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, 1993
-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 59701-9989
(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. [X]
The aggregate market value of the voting stock held by nonaffiliates of the
registrant was $1,494,286,939 at March 17, 1994.
On March 17, 1994, the Company had 52,830,346 shares of common stock
outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
(1) Notice of 1994 Annual Meeting of Shareholders and Proxy Statement,
pages 2-20, 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 conduct a number of diversified, but 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
nonutility operations principally involving the mining and sale of coal and
exploration for, and the development, production, processing and sale of oil
and natural gas. The Company, through its Independent Power Group (IPG)
manages long-term power sales, invests in cogeneration projects, and provides
energy-related support services, including the operation and maintenance of
power plants. See Item 8, 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. The Office of the Corporation
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 area comprises
107,600 square miles or approximately 73% of Montana. Its estimated 1993
population was 723,000 or 90% of the total population of the State. Dominant
factors in Montana's diversified economy are agriculture and livestock, which
constitute Montana's largest industry, tourism and year-round recreation, coal
and metals mining, oil and gas production, and the forest products industry
which embraces the production of pulp and paper, plywood and lumber.
Electric service is provided to 186 communities, the rural areas
surrounding them and Yellowstone National Park, and natural gas service is
provided to 105 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.
The Company's residential and commercial business is substantially free
from direct competition with other utilities. The Utility Division is subject
to, in certain circumstances, increased competition with self-generation for
large industrial loads and with other energy suppliers for large wholesale
loads. Because of the absence of competing transmission pipelines in its
natural gas service territory, the Utility Division is less subject to bypass
by its large industrial and wholesale natural gas customers with respect to
wholesale or transportation service.
Weather is a factor which can significantly affect electric and natural
gas revenues. The Company's sales generally increase as a result of colder
weather with customer demand peaking during the winter months.
REGULATION AND RATES: The Company's public utility business in Montana
is subject to the jurisdiction of the Public Service Commission of
Montana (PSC). The PSC has jurisdiction over the issuance of securities by
the Company. The Federal Energy Regulatory Commission (FERC) also has
jurisdiction over the Company, under the Federal Power Act, as a licensee of
hydroelectric projects and as a public utility 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 June 21, 1993, the Company filed and has since updated general rate
increase requests of $30,900,000 annually for electricity and $9,600,000
annually for natural gas based upon a 12.25% return on common equity. Lower
interest costs from refinancings will reduce the combined amounts by
approximately $3,000,000. A 1% change in the return allowed on common equity
would result in a change of approximately $7,000,000 in annual electric
revenues and a change of approximately $1,800,000 in annual natural gas
revenues. This rate case was filed pursuant to the optional filing rules
adopted by the PSC in February 1992. The optional rules improve the matching
of test year expenses and costs with the time rates are in effect. The
optional rules, as interpreted by the Company, increase the revenue request by
$5,700,000 for the electric utility and $1,000,000 for the gas utility.
Effective October 18, 1993, the PSC approved interim annual increases of
$8,800,000 in electric revenues and $4,000,000 for natural gas revenues. A
final decision on the Company's requests is expected in late April.
In August 1993, the Company filed an Allocated Cost of Service/Rate
Design Application with the PSC which reevaluates the costs and rates for
providing electric service to retail customers. Although the Company's total
revenue requirement would remain the same, the amount of revenue collected
from each customer class would change. Under the Company's proposal, the
share of total revenue collected from the residential and commercial customer
classes would increase by 1% and 8%, respectively, while the share of total
revenue collected from the industrial class would decrease by 10%. A final
decision in this docket is expected in May 1994.
The PSC, in 1991, approved the unbundling of natural gas services,
authorized open access on the Company's transmission and distribution system,
and approved a three-year transition period for customer conversions. On
September 1, 1993, natural gas rates for core residential, commercial and
other full service customers were increased $2,954,000 for the last of three
annual increases to recover costs that had previously been allocated to
noncore customers. This rate change did not affect the Company's earnings.
ELECTRIC OPERATIONS: The maximum demand on the Company's resources in
1993 was 1,445,000 kW on January 11, 1993. Total firm capability of the
Company's electric system for 1993 was 1,601,000 kW. Of this capability,
1,186,000 kW was provided by the Company's generating facilities, and
415,000 kW was provided by firm long-term power purchases and exchange
arrangements. The Company's 1993 reserve margin, as a percentage of maximum
demand, was 11%. Planned increases in peak capability are expected to be met
with a combination of resources including upgrades to hydroelectric and
thermal facilities and both short and long-term purchase contracts. New
electric capacity will be required in the late 1990s to meet load growth and
the expiration of two power purchase contracts totalling approximately
150 megawatts. Pursuant to a Request for Proposal, a variety of projects,
including some proposed by the Company are being evaluated under least cost
planning process. To date, the bid resources that have been acquired include
the extension to 2003 of an existing 50,000 kW exchange contract with the
Idaho Power Company, the purchase of a 15 year 98,000 kW winter season power
purchase starting in November 1996 from Basin Electric Power Cooperative, and
construction has commenced on a 41,000 kW upgrade to MPC's hydroelectric
facility at Thompson Falls. In addition, the Company is continuing to
decrease energy and peak demand by investing in demand-side management
programs.
ITEM 1. BUSINESS (Continued)
During the year ended December 31, 1993, the sources of the Utility
Division electric generation were: hydro, 32%; coal, 40%; and purchased
power, 28%. Improved stream flows in 1993 provided 27% more low-cost
hydroelectric generation than in 1992. Extended plant outages at the Colstrip
plants mostly offset the increased hydrogeneration. The cost of coal burned
has been as follows:
Year Ended December 31
1993 1992 1991
Average cost per million Btu's. . . . . . $ 0.65 $ 0.65 $ 0.66
Average cost per ton (delivered). . . . . 11.16 11.30 11.39
NATURAL GAS OPERATIONS: Natural gas supply requirements in 1993 totaled
22,617 Mmcf, of which 14,680 Mmcf were from Montana and 7,937 Mmcf from
Canada. The Company produced 42% of the Montana natural gas. Its Canadian
subsidiaries produced 71% of the Canadian natural gas.
The Company implemented open access gas transportation on November 1,
1991. As of that date, fifteen large industrial customers and one utility
customer of the Gas Utility were allowed to acquire a portion of their gas
supply requirements directly from gas suppliers. The Gas Utility transports
these gas supplies for these customers. As of September 1993, these customers
were able to acquire 100% of their gas supplies directly from other suppliers.
The total volumes of natural gas transported during 1993 were 17,900 Mmcf. As
a result, the Gas Utility's gas supply requirements declined through 1993 as
noncore customers increasingly acquired their own supplies directly.
Total 1994 natural gas requirements, estimated to be 21,046 Mmcf, are
anticipated to be supplied from existing reserves and purchase contracts.
Approximately 14,433 Mmcf of these requirements are expected to be obtained in
the United States and 6,613 Mmcf from Canada. The Company expects to produce
40% of the Montana natural gas. Its Canadian subsidiaries are expected to
produce 64% of the Canadian natural gas. The 1994 transportation volumes are
anticipated to be 23,500 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, after losses, annually
through October 2006.
ENTECH:
GENERAL: Entech conducts its businesses through various subsidiaries,
all of which, with immaterial exceptions, are wholly-owned. It also owns a
passive investment in a gold mine in Brazil. Its coal and lignite business
is conducted through several subsidiaries. Western Energy Company (Western)
holds leases and rights on coal properties in Montana and Wyoming and operates
the Rosebud Mine. Western's subsidiary, Western SynCoal Company (SynCoal),
and a subsidiary of Northern States Power, each own 50 percent of a patented
coal enhancement process and 50 percent of the Rosebud SynCoal Partnership.
The Partnership owns and operates a coal enchancement process demonstration
plant at the Rosebud Mine. Northwestern Resources Company (Northwestern)
holds leases on coal and lignite properties in Texas and Wyoming and operates
the Jewett Mine. Basin Resources, Inc. (Basin) operates the Golden Eagle
Mine, and North Central Energy Company (North Central) owns and holds leases
on coal properties in Colorado. Horizon Coal Services, Inc. (Horizon) markets
coal and lignite, and holds leases and rights on lignite properties in
Montana, Texas and Alabama. Approximately 93 percent of total annual coal and
lignite production is sold under long-term contracts. Entech's oil and
natural gas business is conducted in the United States through North American
Resources Company and in Canada through both Altana Exploration Company and
Roan Resources, Ltd. Entech's other businesses are conducted by various
subsidiaries, none of which is a significant subsidiary.
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 and the Company's
Corette Plant located at Billings, Montana. These customers purchased
approximately 70 percent of the 1993 production. Most of the remainder of
Rosebud coal is sold to customers located in Michigan, Minnesota, North Dakota
and Wisconsin.
During 1993, Western mined and sold 12,190,651 tons, of which
3,629,994 tons were sold to the Company. Western's Colstrip production is
estimated to be 13,000,000 tons in 1994 and 12,000,000 tons in 1995.
Western has experienced competition from southern Powder River Basin
producers, primarily those in Wyoming, for its Midwestern coal sales, which
represent approximately 26% of total sales. While Western has a per-ton rail
rate advantage to some of the upper Midwest markets, Wyoming producers
generally experience lower stripping ratios, royalty amount and production
taxes. In addition, Western produces coal containing higher, noncompliance
levels of sulfur than southern Powder River Basin Mines.
Northwestern's Jewett Mine is located in central Texas about midway
between Dallas and Houston. 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 during
1993 were 7,907,585 tons. The estimated production for 1994 and 1995 is
7,900,000 and 7,700,000 tons, respectively.
Basin's underground Golden Eagle Mine is located in southern Colorado
near Trinidad. The coal is processed through an on-site wash plant to reduce
the ash content. Total deliveries from the mine, which has a capacity to
produce 2,200,000 tons, were 596,700 tons during 1993. Basin has entered into
a long-term contract to supply up to 1,200,000 tons annually starting July
1994. Basin has several short-term contracts to supply industrial and utility
customers. Basin is also selling coal for test burns by potential customers.
Estimated production for 1994 and 1995 is 1,600,000 and 2,000,000 tons,
respectively. Entech anticipates an increase in demand for Basin's compliance
coal due to the provisions of the Clean Air Act Amendments of 1990.
OIL AND GAS OPERATIONS: Entech's producing oil and natural gas
properties are principally located in the states of Wyoming, Colorado, Kansas,
Oklahoma and Montana, and the Province of Alberta, Canada.
An Entech Oil Division subsidiary has entered into agreements to supply
174 Bcf of natural gas to four cogeneration facilities over periods of 11 to
15 years. Entech has sufficient proven, developed and undeveloped reserves,
and controls related sales of production sufficient to supply all of the
natural gas required by those agreements. For information on another
subsidiary's participation in an investment in these cogeneration projects,
See Item 1 "Independent Power Group."
Natural gas production in both the United States and Canada is currently
sold pursuant to short-term, spot market and long-term contracts. In Canada,
approximately 28 Bcf of the Company's natural gas reserves are dedicated to
long-term contracts expiring at various times through 2005.
Through its subsidiary Entech Altamont, Inc., Entech owns a minority
interest in a joint venture to construct the proposed Altamont pipeline.
Altamont has received FERC approval to construct a 620 mile pipeline running
from the Alberta-Montana border to the Opal area in southwest Wyoming. The
decision to proceed with the construction of this pipeline will depend upon
obtaining the necessary regulatory approval and shipper commitments.
INDEPENDENT POWER GROUP:
GENERAL: The Independent Power Group (IPG) 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 and Light Company under
contracts which are coextensive with the Company's leasehold interest in the
Unit.
The IPG also manages the Company's investment in five operating, natural
gas fired, cogeneration projects located in Texas, New York and the United
Kingdom, one cogeneration project under construction in Washington, and three
projects under development in Washington, Texas and China.
The Company's subsidiary, North American Energy Services Company (North
American), which is included in the IPG, 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.
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, 1993, the Company and its subsidiaries employed
4,089 persons of which 2,364 were utility and Office of the Corporation
employees (including 613 employees at the jointly owned Colstrip Units 1-4),
400 Independent Power Group employees and 1,325 Entech employees.
FOREIGN AND DOMESTIC OPERATIONS:
See Item 2, "Utility Natural Gas Properties," for information on the
Company's Canadian and domestic utility natural gas properties. See Item 2,
"Entech Oil and Natural Gas Properties" for information on Entech's Canadian
and domestic oil and natural gas properties.
EXECUTIVE OFFICERS:
In 1992, D. T. Berube, 60, was elected Chairman of the Board and Chief
Executive Officer. He served as President and Chief Operating Officer,
Entech, Inc., 1988-1991.
In 1991, J. P. Pederson, 51, was elected Vice President and Chief
Financial Officer. He served as Controller - Utility Division 1984-1990
and Vice President Corporate Finance 1990-1991.
In 1993, P. K. Merrell, 41, was elected Vice President and Secretary.
She served as Staff Attorney 1981-1992, Assistant Secretary 1991-1992, and
Secretary 1992-1993.
In 1991, M. E. Zimmerman, 45, was elected Vice President and General
Counsel. He served as Staff Attorney 1986-1989 and General Counsel from 1989-
1991.
In 1990, R. P. Gannon, 49, was elected President and Chief Operating
Officer - Utility Division. He served as Vice President and General Counsel
1984-1989.
In 1993, A. K. Neill, 56, was elected Executive Vice President -
Generation and Transmission. He had previously served as Executive Vice
President - Utility Services since 1987.
In 1993, J. D. Haffey, 48, was elected Vice President - Administration
and Regulatory Affairs. He had previously served as Vice President -
Regulatory Affairs for the Utility Division since 1987.
In 1993, D. A. Johnson, 48, was elected Vice President - Utility
Services. He had previously served as Vice President - Gas Supply and
Transportation for the Utility Division since 1984.
In 1993, C. D. Regan, 57, was elected Vice President - Natural Gas
Supply and Transportation. He had previously served as Vice President -
Energy Services for the Utility Division since 1986.
In 1988, G. A. Thorson, 59, was elected Vice President - Colstrip
Project Division for the Utility Division.
In 1993, W. C. Verbael, 56, was elected Vice President - Accounting,
Finance and Information Systems. He had previously served as Vice President -
Accounting and Finance for the Utility Division since 1984.
In 1993, P. J. Cole, 36, was elected Treasurer for the Utility Division.
He served as Manager, Corporate Financial Planning and Analysis 1986-1992, and
Assistant Treasurer 1992-1993.
In 1990, J. S. Miller, 50, was elected Controller for the Utility
Division. He served as Assistant Controller 1985-1990.
In 1992, J. J. Murphy, 55, 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, and Vice President,
Mining Division, Entech, Inc., 1988-1991.
In 1985, E. M. Senechal, 44, was elected Vice President and Treasurer -
Entech, Inc.
In 1992, R. F. Cromer, 48, was elected President and Chief Operating
Officer - Continental Energy Services, Inc. He served as Vice President and
General Manager, Continental Energy Services 1989-1992.
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 Company of 697,000 kW, and 12 hydroelectric
projects, with total planned net capability of 489,000 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 Company owns 319,000 kW, and (3) the
160,000 kW Corette Plant. All of the Company's 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 the
availability of thermal generation.
In addition to the Company's hydroelectric and thermal resources, it
currently receives power through 21 power contracts totaling 415,000 kW of
firm winter peak capacity. These existing contracts vary in type, size,
seller and ending dates. The Company has one energy contract ending in 1995
for the delivery of power to MPC during the off-peak hours.
Hydroelectric projects are licensed by the FERC under licenses which
expire on varying dates from 1994 to 2035. The Company is in the process of
relicensing its nine dams located on the Missouri and Madison rivers. See
Item 8, "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 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 62 member systems and
4 affiliates in the 14 western states, British Columbia, Alberta and Mexico to
assure reliability of operations and service to their customers; is one of
51 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.
At December 31, 1993, the Company owned and operated 7,074 miles of
transmission lines and 14,880 miles of distribution lines.
NATURAL GAS PROPERTIES: The Company 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 Company's utility natural gas customers are served from its
transmission system which extends through the western two-thirds of Montana.
The Company operates four natural gas storage fields on the system which
enable the Company to store natural gas in excess of system load requirements
during the summer and to deliver natural gas during winter periods of peak
demand.
At December 31, 1993, the Company and its subsidiaries owned and
operated 1,912 miles of natural gas transmission lines and 2,890 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, "Supplementary Information."
In addition to Company-owned reserves, the Company, at December 31,
1993, controlled under purchase contracts, 65,305 Mmcf of proven reserves in
the United States and 37,824 Mmcf in Canada. No significant change has
occurred and no event has taken place since December 31, 1993, that would
materially affect the magnitude of the Company's reserve estimates.
Utility natural gas reserve estimates have not been filed with any other
federal or any foreign governmental agency during the past twelve months.
Certain lease and well data, with respect only to owned wells, are filed with
the Internal Revenue Service for tax purposes.
Total produced, royalty and purchased natural gas volumes in Mmcf during
the last three years were as follows:
United States Canada
Produced Royalty Purchased Produced Royalty Purchased
1991 . . . . 6,294 686 11,258 4,550 1,522 4,944
1992 . . . . 5,724 561 8,713 2,951 916 3,443
1993 . . . . 5,587 539 8,554 3,927 1,186 2,824
The following table presents information as of December 31, 1993,
concerning Company-owned utility natural gas wells and the owned or leased
acreages in which they are located.
United States Canada
Gross productive wells. . . . . . . . . . 591 167
Net productive wells. . . . . . . . . . . 485 156
Gross wells with multiple completions . . 17 10
Net wells with multiple completions . . . 11.8 9.5
Gross producing acres . . . . . . . . . . 452,194 203,672
Net producing acres . . . . . . . . . . . 292,820 180,438
Gross undeveloped acres . . . . . . . . . 76,761 54,240
Net undeveloped acres . . . . . . . . . . 58,292 52,640
These acreages are located primarily in Montana and Alberta, Canada.
The Company anticipates that during 1994 total exploration and
development expenditures (expense and capital) will be approximately
$1,857,000 in the United States and approximately $960,000 in Canada.
The following table presents information on utility natural gas
exploratory and development wells drilled during 1993, 1992 and 1991.
United States Canada
1993 1992 1991 1993 1992 1991
Net productive exploratory
wells. . . . . . . . . . . . - - - - - -
Net dry exploratory wells. . . - - - - - -
Net productive development
wells. . . . . . . . . . . . 12.25 6.38 8.31 3.00 - -
Net dry development wells. . . 2.00 3.00 1.00 1.00 - -
The following table presents average revenues received per Mcf by
customer classification for natural gas from all sources for the years 1993,
1992 and 1991. Revenues per Mcf are computed based on volumes at varying
pressure bases as billed.
Year Ended December 31
Customer Classification 1993 1992 1991
Residential. . . . . . . . . . . . . . . $ 4.35 $ 4.22 $ 3.98
Commercial . . . . . . . . . . . . . . . 4.20 3.91 3.67
Industrial . . . . . . . . . . . . . . . 4.02 3.76 3.19
Other gas utilities. . . . . . . . . . . 3.38 3.33 3.25
The following table presents the average production cost per Mcf for
produced utility natural gas, in U. S. dollars, for the three years 1993, 1992
and 1991.
United States Canada
1991. . . . . . $ 1.18 $ 0.52
1992. . . . . . 1.30 0.78
1993. . . . . . 1.44 0.60
Production cost per unit fluctuated over the three-year period primarily
as a result of expensing fixed costs over varying levels of production
resulting from fluctuations in weather sensitive sales.
ENTECH:
COAL PROPERTIES: Western leases and produces coal in Montana and
Wyoming. Northwestern leases and produces lignite from properties in Texas
and leases coal properties in Wyoming. Basin produces coal, and North Central
owns and leases coal, in Colorado. Horizon leases lignite properties in
Montana, Texas and Alabama. Western SynCoal owns a 50% partnership interest
in a coal enhancement demonstration plant at Colstrip, Montana.
Western has coal mining leases covering approximately 561,000,000 proved
and probable, and recoverable, tons of surface-mineable coal reserves
averaging less than 1.25 pounds of sulfur per million Btu (low-sulfur) at
Colstrip. Approximately 280,000,000 tons of these reserves are committed to
present contracts, including requirements of the Colstrip Units. Western also
has coal mining leases covering approximately 6,000,000 proved and probable,
and recoverable, tons of surface-mineable coal reserves averaging less than
0.6 pounds of sulfur per million Btu (compliance quality) in Wyoming.
Northwestern has lignite mining leases in central Texas at the Jewett
Mine covering approximately 186,000,000 proved and probable, and recoverable,
tons of surface-mineable lignite. Northwestern has contracted to supply the
entire capacity of the Jewett Mine to Houston Lighting and Power Company,
which owns two electric generating units located adjacent to the 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 at Rocky Butte, Wyoming. In January 1993,
Northwestern acquired an adjacent federal lease which contains approximately
56,000,000 proved and probable, and recoverable tons of compliance quality
coal reserves. Northwestern's 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 2003. However, a
challenge to the 1993 federal lease is pending. If this challenge should be
successful, the logical mining unit approved in December 1993 would be
nullified and Northwestern would lose the rights to the federal coal leases
containing approximately 599,000,000 proved and probable, and recoverable tons
of reserves as described above.
North Central owns and leases lands containing approximately
90,000,000 tons of proved and probable, and recoverable, compliance quality
underground-mineable coal reserves near Trinidad, Colorado. Approximately
18,000,000 tons of these reserves are dedicated to a long-term contract.
Horizon has undeveloped mining leases covering lands in three different
states. Properties in eastern Montana contain approximately 31,000,000 proved
and probable, and recoverable, tons of low-sulfur surface-mineable lignite.
Those in southeastern Alabama contain approximately 97,000,000 proved and
probable, and recoverable, tons of surface-mineable lignite (averaging greater
than 1.25 pounds of sulfur per million Btu). Those in central Texas contain
approximately 177,000,000 proved and probable, and recoverable, tons of
surface-mineable lignite.
OIL AND NATURAL GAS PROPERTIES: No significant change has occurred and
no event has taken place since December 31, 1993, 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,
"Supplementary Information to the Consolidated Financial Statements."
All Entech oil and 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 1993, 1992 and
1991.
Year Ended December 31
1993 1992 1991
United United United
States Canada States Canada States Canada
Average sales price:
Per Mcf of natural
gas. . . . . . . . . $ 1.84 $ 1.25 $ 1.50 $ 1.06 $ 1.37 $ 1.23
Per barrel of oil. . . 17.61 14.21 19.15 14.77 20.74 14.56
Per barrel of natural
gas liquids. . . . . 10.98 11.66 10.16 13.42 11.66 15.77
Average production cost:
Per barrel of oil
equivalent . . . . . $ 3.84 $ 3.02 $ 3.52 $ 3.15 $ 4.36 $ 3.63
Natural gas production was converted to barrel of oil equivalents based
on a ratio of six Mcf to one barrel of oil.
Entech's oil, natural gas and natural gas liquids production was sold
under both short and long-term contracts at posted prices or under forward
market arrangements. From 1992 to 1993, Entech's average sale prices changed
due to fluctuations in market prices and currency exchange rates. In the
U.S., Entech's average production cost changed reflecting higher production
taxes per barrel of oil equivalent due to higher revenues received. In
Canada, average production cost decreased because of lower well operating
expenses.
Information on Entech natural gas and oil wells and the owned or leased
acreages in which they are located, as of December 31, 1993, is presented
below.
United
States Canada
Gross productive natural gas wells 400 194
Net productive natural gas wells 205.52 123.71
Gross productive oil wells 250 251
Net productive oil wells 151.86 115.71
Gross producing acres 143,891 192,410
Net producing acres 59,708 95,197
Gross undeveloped acres 235,360 210,405
Net undeveloped acres 112,547 118,731
The wells located in Canada include multiple completions of 12 gross
productive natural gas wells and 10.56 net productive gas wells.
The foregoing acreages are located in the United States and Canada
primarily in the Rocky Mountain states and Alberta.
It is anticipated that during 1994 total exploration, acquisition and
development expenditures (expense and capital) will be approximately
$23,000,000 in the United States and approximately $14,600,000 in Canada.
The following table presents information on Entech oil and natural gas
exploratory and development wells drilled during 1993, 1992 and 1991.
United States Canada
1993 1992 1991 1993 1992 1991
Net productive natural gas
exploratory wells. . . . . 1.25 0.56 1.96 0.87 0.50 0.50
Net productive oil
exploratory wells. . . . . 3.00 -- 1.00 1.04 0.56 --
Net productive natural gas
development wells. . . . . 32.16 20.73 13.45 5.70 1.00 0.95
Net productive oil
development wells. . . . . 4.12 7.00 8.18 6.56 24.65 14.53
Net dry exploratory wells. . 2.79 -- 1.00 5.92 3.14 --
Net dry development wells. . 2.76 4.50 4.08 3.00 3.84 1.99
For information on properties acquired, see Item 8, "Supplementary
Information - Oil and Natural Gas Producing Activities."
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 general and limited partnership interests in or is providing
development funding to the following nonutility generation projects:
Projects in Operation
IPG
Share
of
Rated Rated
Capa- Capa-
Ownership city city Customer
Project Location Interest MW MW Electricity Steam
Encogen One Sweetwater, TX 49.5% 255 126 Texas Util U.S. Gypsum
Electric Co
Tenaska-Paris Paris, TX 10.0% 223 22 Texas Util Campbell
Electric Co Soup Co
Encogen Four Buffalo, NY 49.5% 62 31 Niagara Mohawk American
Power Corp Brass Co
Lockport Lockport, NY 22.3% 168 37 New York State General Motors
Electric &
Gas Corp
Teesside United Kingdom 33.3%* 168* 56 Various U.K. --
customers
* Interest is the contractual right to receive and market 56 megawatts from a
1,725 megawatt natural gas-fired electric generating facility.
Projects Under Construction
IPG
Share
of
Rated Rated
Capa- Capa-
Ownership city city Customer
Project Location Interest MW MW Electricity Steam
Tenaska-Ferndale Ferndale, WA 27.9% 245 68 Puget Sound Tosco Corp
Power & Light
Projects Under Development
Planned
Rated
Capa-
Development city Customer
Project Location Interest MW Electricity Steam
Tenaska-Frederickson Frederickson, WA 31.6% 248 Bonneville None
Power Admn
Tenaska-Brazos Cleburne, TX 31.6% 240 Brazos REA *
China-Henan Henan Province, 12.5% 700 * *
China
*Not determined at this time.
ITEM 3. LEGAL PROCEEDINGS
Refer to Item 7, "Management's Discussion and Analysis of Financial
Condition and Results of Operations."
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
Common Stock Information
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
1993 and 1992. The number of common shareholders on December 31, 1993, was
38,883.
Dividends
Declared
per
1993 High Low Share
1st quarter $ 27.875 $ 25.125 $ 0.395
2nd quarter 27.750 25.500 0.395
3rd quarter 28.125 26.375 0.395
4th quarter 27.500 24.500 0.400
Dividends
Declared
per
1992 High Low Share
1st quarter $ 28.000 $ 24.000 $ 0.385
2nd quarter 26.375 23.625 0.385
3rd quarter 26.625 24.875 0.385
4th quarter 26.625 24.500 0.395
ITEM 6. SELECTED FINANCIAL DATA
The Montana Power Company and Subsidiaries
Balance Sheet Items (000)
1993 1992 1991
Assets:
Utility plant. . . . . . . . . . . . $1,943,428 $1,854,297 $1,774,185
Less accumulated depreciation
and depletion. . . . . . . . . . . 572,141 533,216 495,720
Net Utility Plant . . . . . . . . 1,371,287 1,321,081 1,278,465
Entech property. . . . . . . . . . . 526,692 482,732 464,978
Less accumulated depreciation
and depletion. . . . . . . . . . . 182,129 163,185 144,691
Net Entech Property . . . . . . . 344,563 319,547 320,287
Independent Power Group. . . . . . . 70,198 69,805 66,477
Less accumulated depreciation. . . . 16,822 15,090 11,633
Net Independent Power Group . . . 53,376 54,715 54,844
Total Net Plant and Property. . 1,769,226 1,695,343 1,653,596
Other assets . . . . . . . . . . . . 616,801 590,079 564,450
Total Assets. . . . . . . . . . $2,386,027 $2,285,422 $2,218,046
Liabilities:
Common shareholders' equity. . . . . $ 945,651 $ 902,989 $ 862,601
Unallocated stock held by trustee
for Deferred Savings and ESOP. . . (34,419) (36,098) (37,631)
Preferred stock. . . . . . . . . . . 101,419 51,984 51,984
Long-term debt . . . . . . . . . . . 571,870 581,179 603,266
Other liabilities. . . . . . . . . . 801,506 785,368 737,826
Total Liabilities . . . . . . . $2,386,027 $2,285,422 $2,218,046
ITEM 6. SELECTED FINANCIAL DATA
The Montana Power Company and Subsidiaries
Balance Sheet Items (000)
1990 1989 1988
Assets:
Utility plant. . . . . . . . . . . . $1,712,255 $1,662,887 $1,587,895
Less accumulated depreciation
and depletion. . . . . . . . . . . 468,201 440,944 407,186
Net Utility Plant . . . . . . . . 1,244,054 1,221,943 1,180,709
Entech property. . . . . . . . . . . 403,169 357,088 329,444
Less accumulated depreciation
and depletion. . . . . . . . . . . 124,309 106,702 90,936
Net Entech Property . . . . . . . 278,860 250,386 238,508
Independent Power Group. . . . . . . 66,507 66,000 64,429
Less accumulated depreciation. . . . 10,583 8,790 6,557
Net Independent Power Group . . . 55,924 57,210 57,872
Total Net Plant and Property. . 1,578,838 1,529,539 1,477,089
Other assets . . . . . . . . . . . . 537,686 542,085 575,505
Total Assets. . . . . . . . . . $2,116,524 $2,071,624 $2,052,594
Liabilities:
Common shareholders' equity. . . . . $ 821,521 $ 788,447 $ 768,349
Unallocated stock held by trustee
for Deferred Savings and ESOP. . . (39,031)
Preferred stock. . . . . . . . . . . 51,984 51,984 51,984
Long-term debt . . . . . . . . . . . 599,971 562,610 551,463
Other liabilities. . . . . . . . . . 682,079 668,583 680,798
Total Liabilities . . . . . . . $2,116,524 $2,071,624 $2,052,594
Income Statement Items (000)
1993 1992 1991
Utility operations:
Electric revenues. . . . . . . . . . $ 433,602 $ 406,290 $ 389,476
Natural gas revenues . . . . . . . . 111,288 98,401 108,542
Total Utility Operating Revenues . 544,890 504,691 498,018
Operation expenses . . . . . . . . . 207,362 191,650 178,368
Purchased gas. . . . . . . . . . . . 24,399 22,519 30,603
Fuel for electric generation . . . . 33,338 38,253 35,476
Maintenance. . . . . . . . . . . . . 38,534 34,239 36,321
Depreciation and depletion . . . . . 46,056 43,530 41,443
Taxes--income and other. . . . . . . 89,234 75,636 72,011
Other income . . . . . . . . . . . . (980) (1,972) 171
Interest charges . . . . . . . . . . 46,885 47,733 50,659
Income from Utility Operations . . 60,062 53,103 52,966
Entech operations:
Sales. . . . . . . . . . . . . . . . 410,451 397,129 362,100
Cost of sales. . . . . . . . . . . . 240,701 219,176 190,597
Taxes - other than income taxes. . . 38,933 44,964 40,323
Depreciation and depletion . . . . . 31,653 33,531 30,108
Selling, general and administrative. 38,256 36,050 36,963
Interest . . . . . . . . . . . . . . 2,284 2,144 1,776
Interest income and other - net. . . (5,829) (5,111) (6,642)
Income taxes . . . . . . . . . . . . 17,263 16,178 19,592
Income from Entech Operations. . . 47,190 50,197 49,383
Independent Power Group operations:
Revenues . . . . . . . . . . . . . . 120,255 86,580 59,983
Expenses . . . . . . . . . . . . . . 120,296 82,815 56,617
Income from Independent Power
Group. . . . . . . . . . . . . . (41) 3,765 3,366
Consolidated net income. . . . . . . . 107,211 107,065 105,715
Dividends on preferred stock . . . . . 4,353 3,790 3,790
Net income available for common stock. $ 102,858 $ 103,275 $ 101,925
Net income per share of common stock . $ 1.98 $ 2.02 $ 2.03
Dividends declared per share of
common stock . . . . . . . . . . . . $ 1.585 $ 1.55 $ 1.495
Average shares outstanding (000) . . . 52,040 51,126 50,317
Income Statement Items (000)
1990 1989 1988
Utility operations:
Electric revenues. . . . . . . . . . $ 340,988 $ 343,195 $ 323,850
Natural gas revenues . . . . . . . . 109,350 108,679 96,095
Total Utility Operating Revenues . 450,338 451,874 419,945
Operation expenses . . . . . . . . . 151,360 146,443 139,827
Purchased gas. . . . . . . . . . . . 33,693 36,639 31,345
Fuel for electric generation . . . . 32,314 30,633 30,124
Maintenance. . . . . . . . . . . . . 34,998 31,864 30,134
Depreciation and depletion . . . . . 39,655 40,944 37,624
Taxes--income and other. . . . . . . 63,407 61,862 57,304
Other income . . . . . . . . . . . . (574) (6,755) (3,138)
Interest charges . . . . . . . . . . 47,364 51,529 47,325
Income from Utility Operations . . 48,121 58,715 49,400
Entech operations:
Sales. . . . . . . . . . . . . . . . 319,770 271,909 270,159
Cost of sales. . . . . . . . . . . . 170,980 140,208 135,685
Taxes - other than income taxes. . . 39,217 34,790 42,347
Depreciation and depletion . . . . . 21,839 21,406 19,267
Selling, general and administrative. 23,701 22,604 21,885
Interest . . . . . . . . . . . . . . 1,884 857 3,279
Interest income and other - net. . . (3,387) (6,120) (6,780)
Income taxes . . . . . . . . . . . . 19,023 15,488 18,303
Income from Entech Operations. . . 46,513 42,676 36,173
Independent Power Group operations:
Revenues . . . . . . . . . . . . . . 53,263 51,431 42,749
Expenses . . . . . . . . . . . . . . 52,917 78,411 56,460
Income from Independent Power
Group. . . . . . . . . . . . . . 346 (26,980) (13,711)
Consolidated net income. . . . . . . . 94,980 74,411 71,862
Dividends on preferred stock . . . . . 3,790 3,790 3,790
Net income available for common stock. $ 91,190 $ 70,621 $ 68,072
Net income per share of common stock . $ 1.84 $ 1.45 $ 1.42
Dividends declared per share of
common stock . . . . . . . . . . . . $ 1.435 $ 1.39 $ 1.35
Average shares outstanding (000) . . . 49,657 48,830 47,896
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 1991
through 1993. Also presented are factors which are expected to have an impact
on operating results in the future. This discussion should be read in
conjunction with the Consolidated Statement of Income.
Net Income Per Share of Common Stock:
The Company's consolidated net income increased to $107,211,000 in 1993
compared to $107,065,000 and $105,715,000 in 1992 and 1991, respectively. The
following table shows the sources of consolidated net income on a per share
basis.
1993 1992 1991
Utility Operations $ 1.07 $ 0.97 $ 0.98
Entech 0.91 0.98 0.98
Independent Power Group -- 0.07 0.07
$ 1.98 $ 2.02 $ 2.03
Colder weather and increased hydroelectric generation combined to
increase the earnings of the Utility Division for 1993. The Utility increase
offset reduced earnings of Entech and the Independent Power Group (IPG).
Entech earnings decreased primarily due to reduced coal sales resulting from
an extended outage at a Colstrip generating unit. The IPG earnings decrease
resulted primarily from a decrease in cogeneration project development
revenues.
Consolidated net income for 1992 benefited from the higher earnings of
Entech's Oil Division, lower interest rates and the gain resulting from the
sale of securities held for investment. Net income for the year was also
boosted by increased wholesale sales of electricity. The warm, dry weather
experienced in the Company's service territory during the first half of 1992
caused power supply costs to increase and natural gas sales to decline.
Strong natural gas sales during the fourth quarter resulting from colder
weather and record operating performance by the Utility's coal-fired plants
throughout the year partially offset the adverse effect of weather early in
the year. Losses incurred at a coal mine acquired in June 1991 adversely
impacted consolidated net income during 1992.
Utility Operations:
The following table shows changes from the prior year, in millions of
dollars, in principal categories of utility revenues and the related
percentage changes in volumes sold and prices received:
1993 1992
Electric
General business - revenue $ 9 $ 9
- volume 3% -
- price/kWh - 2%
Other utilities - revenue $ 14 $ 8
- volume 11% 3%
- price/kWh 8% 9%
Natural Gas
General business - revenue $ 14 $ (9)
- volume 11% (17%)
- price/Mcf 6% 9%
Other utilities - revenue $ (5) $ (4)
- volume (53%) (35%)
- price/Mcf 1% 2%
Transportation* - revenue $ 2 $ 3
- volume 19% NM**
- price/Mcf 35% (16%)
*Service commenced November 1, 1991.
**Not Meaningful
Weather can significantly affect electric and natural gas revenues, and
should be considered when determining trends. The Company's sales usually
increase as a result of colder weather, especially in the winter months. As
measured by heating degree days, the weather in 1993 in the Company's service
territory was 17% colder than 1992 and 8% colder than normal. The weather in
1992 was 2% warmer than in 1991 and 8% warmer than normal.
1993 Compared to 1992
Operating Revenues:
Electric revenues from general business customers increased due to a 3%
increase in volumes sold. Weather, which was 17% colder than 1992, and a 2%
increase in the number of customers combined to increase revenues $8,600,000.
Electric revenues from sales to other utilities increased revenues
$14,300,000. Volumes increased 11% and unit prices increased 8%, providing
additional revenues of $7,000,000 and $7,300,000, respectively. The increases
occurred primarily during the first and fourth quarters as a result of
improved regional market conditions during those periods. In spite of reduced
steam generation resulting from outages at a Colstrip generating unit, volumes
sold increased due to a 27% increase in hydroelectric generation for the year
and increased power purchases.
Under a transportation tariff effective November 1, 1991, natural gas
customers who consume more than 60,000 Mcfs annually (noncore customers) may
purchase natural gas from other suppliers and transport that gas on the
Company's transportation and distribution system for a fee. One noncore
customer was no longer required to purchase any natural gas from the Company.
The remaining customers were required to purchase two-thirds of their gas
supplies from the Company until September 1, 1992, and thereafter, one-third
until September 1, 1993, at which time they became free to purchase all of
their gas from other sources. The resulting decline in natural gas sales
revenue has been offset by revenues from transportation fees, lower purchase
gas costs and increased revenues from higher rates charged to core general
business customers.
Natural gas revenues from general business customers increased
$14,500,000. A 19% increase in volumes sold to residential and commercial
customers, primarily a result of 17% colder weather and a 4% increase in the
number of customers, increased revenues $13,900,000. Rate increases resulting
from the transportation phase-in mentioned previously and an interim rate
order effective October 18, 1993, increased revenues $4,100,000. These
increases were partially offset by a $3,500,000 decrease resulting from a 54%
reduction in volumes sold to industrial, government and municipal customers
who switched to transportation.
Natural gas revenues from sales to other utilities also decreased
$4,600,000 due to a 53% decrease in volumes resulting from switches to
transportation service.
Operating Expenses and Taxes:
The following table shows the Company's sources of electricity and power
supply expenses (Operation, Fuel for electric generation, and Maintenance)
for 1993 and 1992.
1993 1992
Sources Megawatt Hours
Hydroelectric. . . . . . . . . . . . . . . 3,560,915 2,793,974
Steam. . . . . . . . . . . . . . . . . . . 4,542,100 5,176,130
Purchases. . . . . . . . . . . . . . . . . 3,186,025 2,833,388
Total Power Supply . . . . . . . . . . . 11,289,040 10,803,492
Expenses Thousands of Dollars
Hydroelectric. . . . . . . . . . . . . . . $ 18,092 $ 17,384
Steam. . . . . . . . . . . . . . . . . . . 57,876 59,563
Purchases. . . . . . . . . . . . . . . . . 96,222 89,748
Total Power Supply Expenses. . . . . . . $ 172,190 $ 166,695
Cents per Kilowatt-Hour. . . . . . . . . 1.525 1.543
The Company's hydroelectric output increased as a result of improved
streamflows, offsetting a decline in generation from the Company's coal-fired
plants. Purchased power volumes were increased to meet higher sales to
general business and wholesale customers.
Increases in purchased power costs were partially offset by a $2,900,000
decrease in the amortization of previously deferred costs. Fuel for electric
generation decreased $4,900,000 as a result of outages at a Colstrip
generating unit. The decrease in fuel was partially offset by a $3,000,000
increase in maintenance of steam plants resulting from scheduled maintenance
and unscheduled repairs due to the previously mentioned outages.
Operations expense not associated with power supply costs increased
$9,600,000 primarily due to a $5,000,000 increase in labor costs, a $2,400,000
increase in transmission costs and expenses of $1,600,000 related to property
damage to homes at Colstrip.
Purchased gas increased $1,900,000 primarily as a result of increased
deferred amortizations which are offset by similar increases in natural gas
revenues through gas cost tracking procedures, and do not affect net income.
The $4,100,000 increase in taxes - other than income taxes is
principally due to increased property taxes resulting from property additions
and higher mill levies.
Interest Charges:
The $1,700,000 decrease in interest on long-term debt is primarily a
result of lower interest rates due to refinancings.
1992 Compared to 1991
Operating Revenues:
Electric revenues from general business customers improved $9,100,000.
A 2% increase in unit prices, primarily the result of a $16,700,000 annual
rate increase effective July 1991, contributed approximately $7,700,000. The
remaining $1,400,000 increase resulted from a slight increase in volumes sold.
Electric revenues from sales to other utilities increased $8,300,000 due
to a 9% increase in price and a 3% increase in volumes sold. Price increases
were caused by reduced hydroelectric generation throughout the Pacific
Northwest, the result of drought conditions that reduced streamflows. Volumes
available for sale increased, in spite of reduced hydroelectric generation at
Company facilities, as a result of a 10% increase in generation at the
Utility's coal-fired plants and purchases.
Natural gas revenues from general business customers decreased
$8,900,000, the result of decreased sales volumes. Specifically, sales
volumes to industrial, government and municipal customers decreased 55%,
principally as the result of the switch of customers to the gas transportation
tariff, reducing revenues $10,300,000. In addition, volumes sold to
residential and commercial customers decreased 5%, reducing revenues
$3,700,000. Increased consumption resulting from a 3% increase in customers
was more than offset by reduced volumes caused by warmer weather. Revenue
decreases resulting from lower sales volumes were partially offset by rate
adjustments, which contributed approximately $5,000,000. These adjustments
consist of $5,900,000 and $2,800,000 annual increases, effective November 1991
and September 1992, respectively, to recover costs that had previously been
allocated to non-core customers, partially offset by a $1,900,000 annual
decrease, effective November 1991, resulting from a gas cost tracking
procedure that annually balances costs collected from customers with the cost
of supplying gas. These rate adjustments do not affect earnings.
Natural gas revenues from other utilities declined $4,400,000 due to a
35% decrease in sales volumes. This decline is largely a result of an
eligible customer switching to the gas transportation tariff.
Operating Expenses and Taxes:
The following table shows the Company's sources of electricity and power
supply expenses (Operation, Fuel for electric generation, and Maintenance) for
1992 and 1991.
1992 1991
Sources Megawatt Hours
Hydroelectric. . . . . . . . . . . . . . . 2,793,974 3,465,626
Steam. . . . . . . . . . . . . . . . . . 5,176,130 4,700,171
Purchases. . . . . . . . . . . . . . . . . 2,833,388 2,281,423
Total Power Supply . . . . . . . . . . . 10,803,492 10,447,220
Expenses Thousands of Dollars
Hydroelectric. . . . . . . . . . . . . . . $ 17,384 $ 16,929
Steam. . . . . . . . . . . . . . . . . . . 59,563 58,866
Purchases. . . . . . . . . . . . . . . . . 89,748 75,283
Total Power Supply Expenses. . . . . . . $ 166,695 $ 151,078
Cents per Kilowatt-Hour. . . . . . . . . 1.543 1.446
The Company's 1992 hydroelectric generation was reduced as a result of
the drought conditions experienced in the Pacific Northwest. Increased power
purchases from other utilities and qualifying facilities offset the hydro
reduction and provided energy for sales to other utilities. In addition,
power purchase costs increased $3,500,000 as a result of the amortization of
costs related to certain 1991 qualifying facility purchases which were
deferred in accordance with regulatory decisions.
Fuel for electric generation was up $2,800,000, largely a result of
increased generation by the Corette Plant in 1992. This plant was
out-of-service from May through August 1991 for maintenance and rehabilitation
work. Maintenance expenses decreased $2,100,000, primarily a result of the
aforementioned work at the Corette Plant in 1991.
Purchased gas expense decreased $8,100,000. The assignment of gas
purchase contracts to the customers who switched to gas transportation
decreased expense approximately $5,600,000. The remainder of the decrease is
largely the result of lower sales due to warmer weather. Since purchased gas
expense decreases are offset by similar changes in natural gas revenues
through gas cost tracking procedures, net income is not affected.
The $3,400,000 increase in taxes - other than income taxes is
principally due to increased property taxes resulting from property additions
and higher mill levies.
Other Income and Expense:
Income taxes applicable to other income decreased $2,100,000, the result
of the recalculation, in 1992, of taxes accrued in 1991.
Interest Charges:
The $2,900,000 decrease in total interest expense is principally the
result of lower interest rates on long and short-term debt.
Entech Operations:
The following table shows year-to-year changes for the previous two
years, in millions of dollars, in the various classifications of revenues of
Entech's businesses with the related percentage changes in volumes sold and
prices received:
1993 1992
Coal -revenue $ (8) $ 5
-volume (7%) -
-price/ton 1% 1%
Oil -revenue $ (5) $ 11
-volume (10%) 61%
-price/bbl (6%) (10%)
Natural Gas -revenue $ 9 $ 5
-volume 16% 24%
-price/Mcf 20% (3%)
Natural Gas
Marketing -revenue $ 23 $ 13
Other Operations -revenue $ (6) $ 1
1993 Compared to 1992
Revenues:
Coal revenues at the Rosebud Mine decreased $21,000,000 due to lower
volumes sold to the Colstrip units as a result of unscheduled outages and from
fewer spot sales to Midwestern customers. This revenue decrease was partially
offset by an increase of $5,800,000 from a combination of brokered coal
revenues and fees related to operating the SynCoal demonstration plant. At
the Jewett Mine, coal revenues increased by $11,400,000 due to higher volumes
sold to the mine-mouth power plants, offset by an $8,000,000 decrease from
lower reimbursable mining expenses. Higher volumes sold to supply coal for
test burns and spot market sales resulted in increased revenues of $4,000,000
at the Golden Eagle Mine. In July 1994, the Golden Eagle Mine will begin
delivering up to 1,200,000 tons of coal per year to a new customer under a
long-term contract.
Entech's coal business faces increasing competition for Midwestern
customers resulting from surplus coal capacity in the southern Powder River
Basin. In 1993, the Rosebud Mine sold approximately 2,000,000 tons of coal
under contracts with two Midwestern customers. One of the contracts with a
Midwestern customer, totaling approximately 1,000,000 tons per year, has a
price reopener at the end of 1994. The other contract, which includes take-
or-pay provisions, also totaling approximately 1,000,000 tons, will expire at
the end of 1995. It is uncertain whether either of these contracts will be
retained. Both customers are expected to purchase the same number of tons
during 1994 as they purchased in 1993, and take-or-pay revenues are expected
to be at the same levels as in 1993.
Oil revenues decreased $5,400,000 primarily from lower volumes sold as a
result of natural declining production and from lower market prices received
in both Canada and the U.S. Natural gas revenues increased $9,200,000
principally from higher market prices received and higher volumes sold as a
result of development drilling in both Canada and the U.S. The increase in
natural gas marketing revenues reflects escalated prices received under three
cogeneration supply contracts and higher volumes sold.
Revenues from Entech's other operations decreased $6,200,000 as a net
result of the sale of the waste management operations in May 1993 offset by
higher telecommunications revenues resulting from expansion of services into
three Northwestern states and increased contractual services provided to
common carriers.
Costs and Expenses:
Cost of sales increased approximately $21,500,000. This amount is
comprised of several items. Natural gas for resale increased $23,100,000 and
costs from increased production of natural gas increased $1,400,000. In
addition, $1,900,000 of the increase resulted from telecommunications
services. These amounts were offset by a $4,500,000 decrease as a result of
the sale of the waste management operations. Taxes other than income taxes
decreased as a result of lower coal revenues at the Rosebud Mine. The
decrease in depreciation and depletion results primarily from lower coal
production at the Rosebud Mine. Selling, general and administrative expense
increased $1,600,000 from the implementation of Statement of Financial
Accounting Standards No. 106, "Employers' Accounting for Postretirement
Benefits Other Than Pensions" and from a non-recurring workers' compensation
refund of $800,000 received in 1992.
Interest income and other-net increased approximately $700,000 from the
net effect of several events. Profits from asset sales increased $2,200,000
and an increase of $3,000,000 was realized because of a 1992 payment to settle
a lawsuit. These increases were offset by a $3,300,000 decrease in joint
ventures income and $1,100,000 less income received from the Brazilian
subsidiary in 1993.
1992 Compared to 1991
Revenues:
Coal revenues at the Rosebud Mine improved $8,300,000 principally due to
higher volumes sold because of improved operating performance by the Colstrip
units and the Company's Corette Plant. Coal revenues decreased at the Jewett
Mine $6,900,000 reflecting lower tonnages sold as a result of scheduled and
unscheduled power plant maintenance offset by a $4,300,000 increase due to
higher reimbursable mining expenses. Coal revenues decreased $600,000 at the
Golden Eagle Mine. The mine was temporarily closed in April 1992 because its
primary customer discontinued buying coal. The mine resumed limited
operations in mid-October 1992 to supply coal for test burn orders. Markets
for coal from this mine are being sought.
The Coal Division faces increasing price competition for Midwestern
customers caused by surplus coal capacity. In 1992, the Rosebud Mine sold
approximately 14,700,000 tons of coal. One Rosebud Mine long-term contract
with a Midwestern customer, totaling approximately 1,000,000 tons per year,
has a price reopener in 1994. Renegotiation of this contract has not yet
begun. Another Rosebud Mine long-term contract with another Midwestern
customer, totaling approximately 1,000,000 tons per year, will expire in 1995.
It is uncertain whether this contract will be renewed.
Oil revenues increased $11,000,000 from higher volumes sold as the
result of development drilling and a 1991 Canadian property acquisition.
Natural gas revenues increased $5,000,000 primarily from higher volumes sold
resulting from development drilling and the property acquisition. The
increased natural gas revenues from higher volumes sold were partially offset
by lower Canadian natural gas prices. Natural gas marketing revenues
increased $13,000,000 from higher volumes sold and escalated prices received
under three cogeneration supply contracts.
In 1992, the Entech Oil Division entered into forward sales and swap
transactions to reduce the effect of fluctuations in oil prices on its
profitability and cash flow. Prospectively, the Division has hedged 700,000
barrels, which represent approximately 40% of its 1993 U.S. and Canadian oil
production, with various financial instruments. This strategy provides price
protection should the Nymex-based price fall below $17.94 per barrel. The
difference between market value and hedged contract prices is recognized in
income when the hedged production is sold.
Revenues from Entech's other operations increased approximately
$1,000,000 resulting from a $4,400,000 increase in telecommunications
operations and a $1,500,000 increase in waste management operations. These
increases were partially offset by a $3,000,000 decrease from real estate
sales and a $2,200,000 decrease from automated system control contracts. Real
estate sales are not expected to make a material contribution to revenues in
future periods due to reduced real estate inventory.
Costs and Expenses:
Cost of sales increased approximately $28,000,000. This amount is
comprised of $10,000,000 of increased cost of purchasing natural gas for
resale, $7,000,000 of increase coal production costs due to increased volumes
and higher maintenance costs at Colstrip, $5,000,000 of increased costs
reflecting a full year operation of the Golden Eagle Mine, which was acquired
mid-1991, and $6,000,000 of increased oil and gas production costs associated
with greater volumes produced. Taxes - other than incomes taxes increased due
to the settlement of a state production tax audit and due to higher revenues
at Colstrip. The majority of these taxes were passed through to customers
under coal contract provisions. The increase in depreciation and depletion
results from increased oil and gas production offset by reduced depletion
rates due to the Canadian acquisition. Increased interest expense resulted
from higher levels of debt outstanding during the period.
Interest income and other-net decreased $1,600,000 because of a
$3,000,000 payment attributable to a lawsuit settlement and $1,000,000 less
income received from the Brazilian subsidiary in 1992. These decreases were
offset by $2,400,000 increased profits from asset sales. Income tax expense
decreased principally due to lower pretax income and additional tax credits.
Independent Power Group Operations:
1993 Compared to 1992
IPG revenues increased $33,700,000. The acquisition of a company that
provides energy-related support services in November 1992 resulted in
increased revenues of $39,300,000. The increase was partially offset by a
$6,000,000 reduction in cogeneration project development fees. Revenues from
electricity sold under long-term contracts remained at 1992 levels.
IPG expenses increased $37,500,000 primarily as a result of a
$38,900,000 increase resulting from the acquisition mentioned above. Expenses
also increased $3,000,000 due to increases in purchased power costs resulting
from outages at a Colstrip generating unit, $1,000,000 due to the accrual of
Colstrip housing damage claims and $3,800,000 resulting from a change in the
amount of amortization of the loss on long-term sales. The increases were
offset by a $3,500,000 reduction in fuel expense resulting from the plant
outages, a $3,000,000 decrease in cogeneration development expenses and a
$2,700,000 decrease in income tax expense.
1992 Compared to 1991
IPG revenues improved $16,800,000. The acquisition of a company that
provides energy-related support services in November 1992 resulted in
increased revenues of $8,200,000. Revenues from electricity sales increased
$4,600,000, caused by higher prices on electricity sold under long-term
contracts. Successful cogeneration project development activities resulted in
additional revenues of $3,900,000.
IPG expenses increased $16,400,000. The acquisition and cogeneration
project development activities mentioned above resulted in additional expenses
of $8,200,000 and $4,600,000, respectively. Expenses increased an additional
$3,600,000 as a result of more scheduled maintenance at a Colstrip generating
unit and higher transmission expenses.
Liquidity and Capital Resources:
Net cash provided by operating activities was $182,437,000 in 1993
compared to $211,081,000 in 1992 and $193,704,000 in 1991. Cash from
operating activities less dividends paid provided 53% of capital expenditures
in 1993, down from 80% in 1992 and 61% in 1991.
The Company's long-term debt as a percentage of capitalization was 36%,
39% and 41% in 1993, 1992 and 1991, 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 and impact its
liquidity. See Item 8, "Note 3 to the Consolidated Financial Statements" for
additional information.
Capital expenditures during the prior three years are as follows:
Years Utility Entech IPG Total
Thousands of Dollars
1991 $ 84,996 $ 88,467 $ 15,220 $ 188,683
1992 96,352 43,982 19,489 159,823
1993 112,178 64,702 4,542 181,422
The following table sets forth the Company's estimated capital
expenditures for the years 1994-1998:
Years Utility Entech IPG Total
Thousands of Dollars
1994 $144,000 $ 46,000 $ 28,000 $ 218,000
1995 160,000 53,000 26,000 239,000
1996 197,000 51,000 31,000 279,000
1997 123,000 68,000 25,000 216,000
1998 134,000 51,000 29,000 214,000
In addition, $90,460,000 of long-term debt will mature during the years
1994-1998. See Item 8, "Note 7 to the Consolidated Financial Statements" for
details on maturities of long-term debt.
For the years 1994-1998, the Company estimates that approximately 51% of
its utility construction program, 100% of Entech capital expenditures and 44%
of IPG investments will be financed from funds generated internally and that
the balance, as well as maturing long-term debt, will be financed through the
incurrence of short and long-term debt and the sales of equity securities, the
timing and amounts of which will depend upon future market conditions. The
Company has adequate sources of external capital to meet its financing needs.
Dividends on common and preferred stock increased to $87,054,000 in 1993
from $83,209,000 in 1992 and $78,114,000 in 1991. The Company paid dividends
of $1.58 per share of outstanding common stock during 1993, up 2.6% from 1992.
The dividend paid January 31, 1994 was increased by the Company's Board of
Directors to 40 cents per share, an increase of 0.5 cents per share from the
previous quarter. This 1.3% increase raises the common stock dividend to an
indicated rate of $1.60 per share on an annual basis.
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, "Notes 7 and 8 to the Consolidated Financial
Statements."
During the first quarter of 1993, the Company sold $50,000,000 of First
Mortgage Bonds and $43,000,000 of Medium-Term Notes, which are secured by
First Mortgage Bonds, with interest rates from 7% to 8.11%. The proceeds were
used to reduce interest expense by refinancing long-term debt maturities and
redeeming, prior to maturity, $60,000,000 of the 8 5/8% series of First
Mortgage Bonds, due 2004.
In 1993, the Company sold $90,205,000 of Pollution Control Revenue
Bonds, 6 1/8% series due 2023. The proceeds of this issue were used to
redeem, prior to maturity, $90,205,000 of Pollution Control Revenue Bonds,
which includes $18,545,000 of the 5.75% series due 2003, $7,000,000 of the
6.3% series due 2007, $39,660,000 of the Adjustable Rate Series due 2014 and
$25,000,000 of the Variable Rate Series due 2014. The Company also sold
$80,000,000 of Pollution Control Revenue Bonds, 5.9% series due 2023, the
proceeds of which were used to redeem, prior to maturity, $80,000,000 of
Pollution Control Revenue Bonds which included $40,000,000 of the 10% series
due 2004 and $40,000,000 of the 10 1/8% series due 2014. See Item No. 8,
"Note 7 to the Consolidated Financial Statements."
In November 1993, the Company sold $50,000,000 of the $6.875 series of
perpetual Preferred Stock, stated value and liquidation value $100. The net
proceeds from the sale were used to repay short-term debt. The stock is
redeemable at the option of the Company, in whole or in part, at any time on
or after November 1, 2003.
On January 19, 1994, the Company sold $5,000,000 of Secured Medium-Term
Notes, 7.25% series due 2024, the proceeds of which were used to repay short-
term debt. The Company also intends to sell additional Secured Medium-Term
Notes within the first half of 1994 for the purpose of retiring Commercial
Paper.
The Company's Mortgage and Deed of Trust contains certain restrictions
upon the issuance of additional First Mortgage Bonds. At December 31, 1993,
after taking into account the sale of $98,000,000 of First Mortgage Bonds and
Secured Medium-Term Notes discussed above, the unfunded net property additions
and retired bonds test, which is the most restrictive test, would have
permitted the issuance of approximately $488,000,000 additional First Mortgage
Bonds. 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, 1993, the Company's ratio of
earnings to fixed charges was 2.86 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 operations, are significantly affected by long-term inflation. Neither
depreciation charges against earnings nor the ratemaking process reflect the
replacement cost of utility plant. However, based on past practices of
regulators, these businesses will be allowed to recover and earn on the actual
cost of investment in the replacement or upgrade of plant. Although prices
for natural gas may fluctuate, earnings 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 contracts and the IPG's long-term operation,
maintenance and power sales contracts provide for the adjustment of prices
either through indices, fixed rate 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.
Postemployment Benefits:
The Financial Accounting Standards Board released SFAS No. 112,
"Employers' Accounting for Postemployment Benefits," in 1992. SFAS No. 112 is
not expected to have a significant effect upon results of operations. See
Item 8, "Note 9 to the Consolidated Financial Statements" for additional
information.
Environmental Issues:
The Company's businesses are subject to, and in substantial compliance
with, existing federal and state environmental regulations. The Company is
committed to careful management and actions which will permit it to continue
to do its part to protect and maintain the environment.
The Clean Air Act Amendments of 1990 should impose no major effects on
the Company's electric generation facilities. The Company's coal-fired
generating plants meet the 1995 Phase I requirements of the Act. Low-sulfur
coal and state-of-the-art scrubbers already result in sulfur dioxide emissions
from the Colstrip units well below the new requirements. Either fuel
switching or the use of allowances, or both, would permit the Corette Plant to
meet the Phase II requirements of the Act in 2000. Despite the expectation
that the Corette Plant may be operated to comply with the Act, air quality
problems in the Billings, Montana area may result in the imposition of
additional emissions restrictions that would require the evaluation of other
options.
Modifications will be required at three units in the late 1990's to meet
the nitrogen oxide emission standards of the Act. However, Phase I rules
implementing the Act have not been published. Nor does the Company know what
requirements may result from Phase II Rules, which also are yet to be
published. Consequently, the capital costs associated with the modifications
to meet the nitrogen oxide standards of the Act have not yet been determined.
However, capital improvements that may be required are expected to be
recovered through rates and therefore, the costs are not expected to have a
material impact on earnings.
In 1988, the United States Environmental Protection Agency advised the
Company that it, along with certain upstream industries, 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 useability 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 $450,000 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. Neither the Company nor, to
the best of the Company's knowledge, any PRP or state or federal agency has
estimated the total cost of the potential clean-up of mining-related
contamination of either its property or other property within the site because
the extent of the contamination has not been established. The Company intends
to deny any responsibility for costs associated with this contamination.
The Company also is a PRP at a second site of soil contamination in
Montana, alleged to have resulted from the salvage of electric transformers by
a third party or parties who obtained the transformers from the Company. The
state agency with jurisdiction over this site has recently determined that the
contamination is contained within the site, that temporary measures taken by
the Company to contain the contamination are effective, and that contamination
has not affected surface water. Costs incurred by the Company are
approximately $500,000. Additional costs are not expected to exceed $350,000.
The Company is a PRP at two sites in the State of Washington where
electric transformers were sent for salvage. At one of the sites, the Company
believes it will qualify as a de minimis settlor. At the second site,
pursuant to the terms of a Consent Decree, the Company is obligated to pay
approximately $350,000.
The Company has accrued the estimated minimum costs associated with
these matters. 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 SUPPLEMENTAL DATA
Page
Management's Responsibility for Financial Statements 40
Report of Independent Accountants 41
Consolidated Financial Statements:
Consolidated Statements of Income for the Years Ended
December 31, 1993, 1992 and 1991 42
Consolidated Balance Sheets as of December 31, 1993 and 1992 43-44
Consolidated Statements of Cash Flows for the Years Ended
December 31, 1993, 1992 and 1991 45
Consolidated Statements of Common Shareholders' Equity for the
Years Ended December 31, 1993, 1992 and 1991 46
Notes to Consolidated Financial Statements 47-74
Supplemental Financial Information (Unaudited) 75-83
Financial Statement Schedules for the Years Ended December 31,
1993, 1992 and 1991:
Schedule V - Property, Plant and Equipment 89-94
Schedule VI - Accumulated Depreciation, Depletion and Amortization
of Property, Plant and Equipment 95-96
Schedule VIII - Valuation and Qualifying Accounts and Reserves 97
Schedule IX - Short-term Borrowings 98
Schedule X - Supplementary Income Statement Information 99
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
Corporation. 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 judgements 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, the Company's independent public accountants,
also considered the systems in connection with its audit. Management has
considered the internal auditors' and Price Waterhouse'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, which
is responsible for conducting its examination in accordance with generally
accepted auditing standards.
Report of Independent Accountants
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,
1993 and 1992, and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 1993, 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 audits 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 9 to the consolidated financial statements, the Company
changed its method of accounting for postretirement benefits other than
pensions.
PRICE WATERHOUSE
Portland, Oregon
February 10, 1994
CONSOLIDATED STATEMENT OF INCOME
The Montana Power Company and Subsidiaries
Year Ended December 31
1993 1992 1991
Thousands of Dollars
UTILITY OPERATIONS:
Operating Revenues:
Electric . . . . . . . . . . . . . . . . . . . $ 433,602$ 406,290$ 389,476
Natural gas. . . . . . . . . . . . . . . . . . 111,288 98,401 108,542
544,890 504,691 498,018
Operating Expenses and Taxes:
Operation. . . . . . . . . . . . . . . . . . . 207,362 191,650 178,368
Purchased gas. . . . . . . . . . . . . . . . . 24,399 22,519 30,603
Fuel for electric generation . . . . . . . . . 33,338 38,253 35,476
Maintenance. . . . . . . . . . . . . . . . . . 38,534 34,239 36,321
Depreciation and depletion . . . . . . . . . . 46,056 43,530 41,443
Taxes - other than income taxes. . . . . . . . 51,729 47,620 44,203
Income taxes (Note 4). . . . . . . . . . . . . 37,505 28,016 27,808
438,923 405,827 394,222
Operating Income . . . . . . . . . . . . . . 105,967 98,864 103,796
Other Income and Expense:
Interest and dividend income and other . . . . 839 1,183 1,107
Income taxes applicable to other (Note 4). . . 141 789 (1,278)
980 1,972 (171)
Interest Charges:
Interest on long-term debt . . . . . . . . . . 44,359 46,014 47,829
Other interest . . . . . . . . . . . . . . . . 2,526 1,719 2,830
46,885 47,733 50,659
Income From Utility Operations . . . . . . . 60,062 53,103 52,966
ENTECH OPERATIONS:
Revenues . . . . . . . . . . . . . . . . . . . . 410,451 397,129 362,100
Costs and Expenses:
Cost of sales. . . . . . . . . . . . . . . . . 240,701 219,176 190,597
Taxes - other than income taxes. . . . . . . . 38,933 44,964 40,323
Depreciation and depletion . . . . . . . . . . 31,653 33,531 30,108
Selling, general and administrative. . . . . . 38,256 36,050 36,963
Interest . . . . . . . . . . . . . . . . . . . 2,284 2,144 1,776
Interest income and other - net. . . . . . . . (5,829)(5,111) (6,642)
Income taxes (Note 4). . . . . . . . . . . . . 17,263 16,178 19,592
363,261 346,932 312,717
Income From Entech Operations. . . . . . . . 47,190 50,197 49,383
INDEPENDENT POWER GROUP OPERATIONS:
Revenues . . . . . . . . . . . . . . . . . . . 120,255 86,580 59,983
Expenses (including interest and income
taxes; see Note 10). . . . . . . . . . . . . 120,296 82,815 56,617
Income from Independent Power Group
Operations . . . . . . . . . . . . . . . . (41) 3,765 3,366
CONSOLIDATED NET INCOME. . . . . . . . . . . . . . 107,211 107,065 105,715
DIVIDENDS ON PREFERRED STOCK . . . . . . . . . . . 4,353 3,790 3,790
NET INCOME AVAILABLE FOR COMMON STOCK. . . . . . . $ 102,858 $ 103,275 $ 101,925
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING (000). 52,040 51,126 50,317
NET INCOME PER SHARE OF COMMON STOCK . . . . . . . $ 1.98 $ 2.02 $ 2.03
The accompanying notes are an integral part of these statements.
CONSOLIDATED BALANCE SHEET
The Montana Power Company and Subsidiaries
ASSETS
December 31
1993 1992
Thousands of Dollars
PLANT AND PROPERTY IN SERVICE:
Utility plant (includes $38,966 and $20,826 plant
under construction):
Electric . . . . . . . . . . . . . . . . . . . . $ 1,514,472 $ 1,450,540
Natural gas. . . . . . . . . . . . . . . . . . . 428,956 403,757
1,943,428 1,854,297
Less - accumulated depreciation and depletion. . . . 572,141 533,216
1,371,287 1,321,081
Entech property (includes $2,446 and $4,930
property under construction) . . . . . . . . . . . 526,692 482,732
Less - accumulated depreciation and depletion. . . . 182,129 163,185
344,563 319,547
Independent Power Group property (includes $84
and $79 property under construction) . . . . . . . 70,198 69,805
Less - accumulated depreciation. . . . . . . . . . . 16,822 15,090
53,376 54,715
1,769,226 1,695,343
MISCELLANEOUS INVESTMENTS (at cost):
Miscellaneous special funds . . . . . . . . . . . 7,811 17,001
Investment in cogeneration projects. . . . . . . . 45,494 44,827
Other. . . . . . . . . . . . . . . . . . . . . . . 51,492 53,647
104,797 115,475
CURRENT ASSETS:
Cash and temporary cash investments. . . . . . . . 11,604 8,879
Accounts receivable. . . . . . . . . . . . . . . . 158,352 142,985
Materials and supplies (principally at
average cost). . . . . . . . . . . . . . . . . . 42,728 41,753
Prepayments and other assets . . . . . . . . . . . 44,425 51,334
257,109 244,951
DEFERRED CHARGES:
Advanced coal royalties. . . . . . . . . . . . . . 20,905 19,035
Costs deferred to future operating periods . . . . 185,151 166,982
Other deferred charges . . . . . . . . . . . . . . 48,839 43,636
254,895 229,653
$ 2,386,027 $ 2,285,422
The accompanying notes are an integral part of these statements.
LIABILITIES
December 31
1993 1992
Thousands of Dollars
CAPITALIZATION:
Common shareholders' equity:
Common stock (120,000,000 shares without par
value authorized; 52,498,896 and 51,548,945
shares issued) . . . . . . . . . . . . . . . . . $ 642,926 $ 618,009
Retained earnings and other shareholders' equity . 302,725 284,980
Unallocated stock held by trustee for Deferred
Savings and Employee Stock Ownership Plan. . . . (34,419) (36,098)
911,232 866,891
Preferred stock. . . . . . . . . . . . . . . . . . . 101,419 51,984
Long-term debt . . . . . . . . . . . . . . . . . . . 571,870 581,179
1,584,521 1,500,054
CURRENT LIABILITIES:
Short-term borrowing . . . . . . . . . . . . . . . . 68,865 63,300
Long-term debt-portion due within one year . . . . . 26,199 37,382
Dividends payable. . . . . . . . . . . . . . . . . . 22,835 21,322
Income taxes . . . . . . . . . . . . . . . . . . . . 4,927 13,282
Other taxes. . . . . . . . . . . . . . . . . . . . . 43,743 41,436
Accounts payable . . . . . . . . . . . . . . . . . . 55,794 48,873
Interest accrued . . . . . . . . . . . . . . . . . . 11,942 15,819
Other current liabilities. . . . . . . . . . . . . . 79,162 83,446
313,467 324,860
DEFERRED CREDITS:
Deferred income taxes. . . . . . . . . . . . . . . . 309,780 288,098
Investment tax credit. . . . . . . . . . . . . . . . 50,476 52,256
Accrued mining reclamation costs . . . . . . . . . . 101,817 91,887
Other deferred credits . . . . . . . . . . . . . . . 25,966 28,267
488,039 460,508
CONTINGENCIES AND COMMITMENTS (Notes 2 and 3)
$ 2,386,027 $ 2,285,422
The accompanying notes are an integral part of these statements.
CONSOLIDATED STATEMENT OF CASH FLOWS
The Montana Power Company and Subsidiaries
Year Ended December 31
1993 1992 1991
Thousands of Dollars
Net Cash Flows From Operating Activities:
Net income . . . . . . . . . . . . . . . . $ 107,211 $ 107,065 $ 105,715
Noncash charges (credits) to net income:
Depreciation and depletion . . . . . . . 80,859 79,049 71,996
Mining reclamation costs expensed. . . . 19,410 21,081 17,069
Amortization of loss on long-term
sales of power . . . . . . . . . . . . (5,251) (9,026) (18,833)
Deferred income taxes. . . . . . . . . . 15,701 (4,082) 4,605
Collection of accrued revenues from
utility rate-moderation plans. . . . . 16,221 28,271
Other-net. . . . . . . . . . . . . . . . 16,507 26,525 25,110
Changes in other assets and liabilities. . (33,099) (11,259) (36,123)
Accounts receivable. . . . . . . . . . . . (15,367) (4,614) 1,432
Materials and supplies . . . . . . . . . . (975) (694) (6,795)
Accounts payable . . . . . . . . . . . . . 6,922 2,387 7,511
Payment of mining reclamation costs. . . . (9,481) (11,572) (6,254)
Net Cash Flows From Operating
Activities . . . . . . . . . . . . . . 182,437 211,081 193,704
Net Cash Flows From Investing Activities:
Miscellaneous special funds. . . . . . . . 9,190 17,303 1,452
Gross additions to property and plant. . . (177,512) (138,778) (167,692)
Investments in other operations. . . . . . (3,910) (21,045) (20,991)
Sales of property. . . . . . . . . . . . . 24,924 12,282 20,077
Additional investments . . . . . . . . . . 4,014 (255) (7,552)
Net Cash Flows From Investing
Activities . . . . . . . . . . . . . . (143,294) (130,493) (174,706)
Net Cash Flows From Financing Activities:
Sales of common stock. . . . . . . . . . . 24,917 21,949 14,944
Issuance of long-term debt . . . . . . . . 294,149 37,862 201,123
Retirement of long-term debt . . . . . . . (316,714) (58,755) (169,058)
Short-term debt. . . . . . . . . . . . . . 5,565 6,000 (6,200)
Notes payable - cogeneration projects. . . (6,716) (210) 14,436
Dividends on common and preferred stock. . (87,054) (83,209) (78,114)
Issuance of preferred stock. . . . . . . . 49,435
Net Cash Flows From Financing
Activities . . . . . . . . . . . . . . (36,418) (76,363) (22,869)
Change in Cash Flows . . . . . . . . . 2,725 4,225 (3,871)
Cash and cash equivalents at beginning
of year. . . . . . . . . . . . . . . . . 8,879 4,654 8,525
Cash and cash equivalents at end of year . $ 11,604 $ 8,879 $ 4,654
Supplemental Disclosures of Cash
Flow Information:
Cash Paid During Year For:
Income taxes . . . . . . . . . . . . . . $ 46,533 $ 39,260 $ 46,226
Interest . . . . . . . . . . . . . . . . 53,541 45,894 57,499
The accompanying notes are an integral part of these statements.
CONSOLIDATED STATEMENT OF COMMON SHAREHOLDERS' EQUITY
The Montana Power Company and Subsidiaries
Year Ended December 31
1993 1992 1991
Thousands of Dollars
Common Stock:
Balance at beginning of year . . . . . . $ 618,009 $ 596,060 $ 581,116
Issuances (949,951; 891,581;
and 699,214 shares). . . . . . . . . . 24,917 21,949 14,944
Balance at end of year . . . . . . . . . 642,926 618,009 596,060
Retained Earnings and Other Shareholders'
Equity:
Balance at beginning of year . . . . . . 284,980 266,541 240,405
Net income . . . . . . . . . . . . . . . 107,211 107,065 105,715
Dividends on common stock ($1.585; $1.55;
and $1.495 per share). . . . . . . . . (82,701) (79,420) (75,345)
Dividends on preferred stock . . . . . . (4,353) (3,790) (3,790)
Other. . . . . . . . . . . . . . . . . . (2,412) (5,416) (444)
Balance at end of year . . . . . . . . . 302,725 284,980 266,541
Unallocated Stock Held by Trustee for
Deferred Savings and Employee Stock
Ownership Plan:
Balance at beginning of year . . . . . . (36,098) (37,631) (39,031)
Distributions. . . . . . . . . . . . . . 1,679 1,533 1,400
Balance at end of year . . . . . . . . . (34,419) (36,098) (37,631)
Total Common Shareholders' Equity at
End of Year. . . . . . . . . . . . . . . $ 911,232 $ 866,891 $ 824,970
The accompanying notes are an integral part of these statements.
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.
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. The
Utility and the IPG purchase coal from Western Energy Company, and sell and
purchase electricity to and from each other. In addition, the Utility sells
electricity and natural gas to the Entech businesses located within the
Utility's service area. Entech sells natural gas to the Utility and to
independent power projects in which the IPG has an ownership interest.
Finally, a subsidiary of the IPG provides maintenance services to the
Utility's power plants, and operation and maintenance services to the
independent power projects mentioned above. Intercompany sales and purchases
between the Utility, Entech, and the IPG are included in the Consolidated
Statement of Income as revenues and expenses. See Note 10 for details.
All other significant intercompany items have been eliminated.
Plant and property:
Additions to and replacement 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, Independent
Power Group 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. The provisions for
utility depreciation and depletion approximated 2.7% for 1993, 1992, and 1991
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, 1993, 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 . . . . . . . . $ 177,340 $ 279,706 $ 56,971
Plant under construction . . . . 218 88 0
Accumulated depreciation . . . . 75,426 77,913 10,063
*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 $35,216,000 and $32,953,000 of the Colstrip Unit 4
share of common production plant and transmission plant that had related
accumulated depreciation of $10,377,000 and $5,258,000, 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.
In 1985, the Public Service Commission of Montana (PSC) and the Federal
Energy Regulatory Commission (FERC) approved annual electric rate increases in
the amounts of $80,400,000 and $7,500,000, respectively, to be collected in
accordance with rate-moderation plans. During 1992 and 1991, cash collected
under these plans exceeded revenues recorded by $12,462,000 and $23,133,000,
respectively. As of October 1992, all deferred revenues under the plans had
been collected.
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 and other costs deferred pursuant
to regulatory decisions which are discussed in the following paragraph of this
note.
Costs deferred to future operating periods:
As a result of the adoption of SFAS No. 109 in 1992, the Company must
recognize a deferred tax liability for certain temporary differences that were
not previously required to be provided. A corresponding asset of $142,123,000
and $137,700,000 has been recorded at December 31, 1993 and 1992, respectively
and is classified as a cost deferred to future operating periods. See the
Income Taxes section of this note for further information on the effects of
the adoption of SFAS No. 109.
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 6.5% for 1993, 7.3% for 1992, and 8.4% for 1991. The Company
capitalized an allowance for borrowed funds used during construction of
$1,372,000, $1,255,000, and $1,181,000 for 1993, 1992, and 1991, respectively.
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. The
difference, if any, between such amounts and the consolidated U.S. income tax
expense is included in utility operations - income taxes applicable to other
income. 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.
In 1992, the Company adopted Statement of Financial Accounting Standards
No. 109, "Accounting for Income Taxes", which required a change to the asset
and liability method of accounting for income taxes. Under this method,
deferred tax assets or liabilities are computed using the tax rates that are
expected to be in effect when the temporary differences reverse. For
regulated companies, the changes in tax rates applied to accumulated deferred
income taxes may not be immediately recognized because of regulatory
practices. For non-regulated companies, the effect on deferred taxes of a
change in tax rates is recognized in income in the period that includes the
enactment date.
The Company elected to report the cumulative effect of the change in the
method of accounting for income taxes as of January 1, 1987. The cumulative
effect of the accounting change was $5,900,000 and was recorded as a reduction
in Common Shareholders' Equity.
Prior to the adoption of SFAS No. 109, deferred income taxes were not
provided for certain Utility Operations' temporary differences pursuant to
regulatory practices. Now the Company must recognize a deferred tax liability
for these temporary differences in the amount of $142,123,000 and $137,700,000
as of December 31, 1993, and 1992, respectively. Because of regulatory
precedent and the Company's intent to request rate recovery of these amounts
in the future, a corresponding asset has been recorded and is classified as a
cost deferred to future operating periods.
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).
Financial instruments:
All of the Company's significant financial instruments were recognized in
the Consolidated Balance Sheet as of December 31, 1993. The value reflected
in the Consolidated Balance Sheet (carrying value) approximates fair value for
the Company's financial assets and current liabilities. Descriptions of the
methods and assumptions used to reach this conclusion are as follows:
Miscellaneous special funds, cash and temporary cash investments, and
current liabilities: These financial instruments have short maturities,
or are invested in financial instruments with short maturities.
Investment in cogeneration projects and other investments: The carrying
value equals cash surrender value, or approximates the present value of
future cash flows, discounted using a market rate of return.
The fair value of the Company's long-term debt, based on quoted market
prices for the same or similar issues or by discounting future cash flows
using interest rates that could be obtained currently, exceeds carrying value
by approximately 6.7%. This is because the average interest rate of the
Company's debt exceeds the rate which could be obtained currently. The
Company refinances the debt that is callable when associated benefits exceed
costs, and when the Company believes it is an opportunistic time to do so.
Reclassifications:
Certain reclassifications have been made to the prior year amounts to
make them comparable to the 1993 presentation. These changes had no impact on
previously reported results of operations or shareholders' equity.
NOTE 2 - Contingencies:
The Company's hydroelectric projects are operated under licenses issued
by the FERC, which expire on varying dates from 1994 to 2035. When a license
expires, it may be reissued to the Company, issued to a new licensee or the
facility may be taken over by the United States. In either of the last two
events, the Company would be entitled to compensation equivalent to its net
investment in the project plus severance damages. In determining net
investment in the project, the licenses provide that there may be deducted the
amount contained in an appropriated retained earnings account, which shall be
accumulated from a portion of the amount earned in excess of a specified
reasonable rate of return after 20 years of operation under the license. At
December 31, 1993, the amount of these appropriated retained earnings relating
to the Company's hydroelectric projects as computed by the Company is
estimated to be $6,238,000. The Board of Directors has appropriated retained
earnings in the same amount for this purpose, thereby restricting their
availability for dividend purposes.
Under a joint 50-year license with the Confederated Salish and Kootenai
Tribes (Tribes), the Company will own and operate the 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.
In 1990, the Company filed with the FERC a plan to mitigate damages to
and manage fish and wildlife habitat impacted by the operation of the Kerr
Hydroelectric Project. The Management and Mitigation Plan (Plan) was prepared
pursuant to the joint license issued by the FERC to the Company and the
Tribes. It consists of a one-time payment by the Company of $15,418,000 and
annual payments of $965,000 allocated between the Tribes and various groups.
The annual payments would be adjusted annually on the basis of the Consumer
Price Index. Additionally, the Secretary of Interior may impose certain
conditions pertaining to fish and wildlife. While the Company cannot predict
when or in what form the Plan finally will be approved, it expects that the
cost of mitigation measures will be recovered through rates and, therefore,
will not have a materially adverse effect on the Company's financial condition
or results of operations.
In November 1992, the Company filed with FERC its application to
relicense nine Madison and Missouri River hydroelectric facilities with
electric generating capacity totaling 292 megawatts. The application, in
preparation since 1989, proposes an additional 74 megawatts of generation.
The total capital investment of relicensing, including physical improvements,
environmental protection, mitigation and enhancement measures, is estimated at
$167,600,000. Additional costs for operational changes, as well as annual
payments for environmental protection, mitigation and enhancement, are
estimated to be about $5,400,000 per year. The Company expects that the
relicensing costs will be recovered through rates and, therefore, will not
have a materially adverse effect on the Company's financial condition or
results of operations.
The owners of homes in two residential developments in Colstrip, Montana,
which were built for the Colstrip Units 3 and 4 Project have made claims
against the Company and the other owners of the Colstrip Units 3 and 4 for
property damages to their homes allegedly caused by soil-related subsidence.
The Company has settled all of these claims. The other Colstrip 3 and 4
owners have denied responsibility for a substantial part of the settlement
costs on the ground that the Company exceeded its authority in settling the
claims. The amount in controversy is not expected to exceed $5,000,000. The
Company is pursuing resolution and it is uncertain whether it will ultimately
pay more than its proportionate share of the settlement costs.
Other property owners in Colstrip also have made claims against the
Company and the other Colstrip Units' owners for property damages allegedly
resulting from soil-related subsidence. The Company has not determined the
magnitude of such alleged damages or the responsibility, if any, of the
Colstrip owners. While the resolution of these claims is uncertain, the
Company believes they will not have a materially adverse effect on the
Company's financial condition or results of operations.
A Rosebud Mine coal supply agreement provides for periodic price
redetermination over the life of the contract. The first date under the
contract that a price redetermination could have occurred was August 1,1991.
Negotiations to redetermine the coal price have been unsuccessful and an
arbitration proceeding has been scheduled to commence in October, 1994.
Through December 31, 1993, 6,923,000 tons, of which 3,466,000 tons were
delivered to the Company, have been delivered and are subject to a
redetermined price. The price change, if any, from this arbitration is not
expected to have a materially adverse effect on the Company's 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
Bonneville Power Administration which expires in 1996. The rate is 4.6 cents
per kWh in the contract year which began in July 1993 and will increase each
subsequent contract year to approximately 4.8 cents per kWh in the final
contract year beginning July 1995. 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, including the capacity charge,
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, including the Basin Electric contract discussed above, 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
1991. . . . . . . $ 15,553 $ 18,422 $ 713
1992. . . . . . . 18,143 12,496 1,938
1993. . . . . . . 18,434 11,633 2,260
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
1994. . . . . . . $ 3,882 $ 12,164 $ 2,976
1995. . . . . . . 4,280 9,560 2,199
1996. . . . . . . 7,576 7,321 2,021
1997. . . . . . . 10,328 6,026 1,664
1998. . . . . . . 10,296 3,308 1,521
Remainder. . . .. 150,085 8,064 8,658
Total . . . . . $ 186,447 $ 46,443 $ 19,039
In 1993, the Company entered into contracts for the construction of a
second powerhouse at the Thompson Falls Hydroelectric Plant. In 1993,
expenditures for the project were $9,000,000, while the total costs for the
next three years are expected to be $51,000,000.
An Entech Coal Division coal lease purchase agreement requires minimum
annual payments beginning in 1991 of $1,125,000 escalated quarterly by the
Gross National Product implicit price deflator. These payments will continue
until the equivalent of $18,750,000, in 1986 dollars, has been paid. At
December 31, 1993, the remaining payments under this agreement were
$14,349,000. A similar agreement requires minimum annual payments of
$1,000,000 through 1995. Under current mine plans, the payments made through
December 1993 should be recovered.
In 1990, a patented coal enhancement process developed by the Entech
Coal Division was selected for funding under the U.S. Department of
Energy (DOE) Clean Coal Technology Program. The Entech Coal Division and a
subsidiary of Northern States Power are partners in a five-year, $69,000,000
coal enhancement demonstration plant at Colstrip, Montana. DOE is funding 50%
and the partners share equally in the remaining 50% of the cost of the
project. The Division's remaining commitment at December 31, 1993, was
$5,100,000.
The Entech Oil Division has agreed to supply 174 Bcf of natural gas to
four cogeneration facilities over 15 years. The Oil Division has sufficient
proven, developed and undeveloped reserves, and controls related sales of
production sufficient to supply all of the remaining natural gas required by
these agreements.
The Entech Oil Division owns a 50% interest in a natural gas marketing
company. Entech has agreed to guarantee the performance by the marketing
company of $4,300,000 in transportation and purchase contracts. The
guaranteed amounts outstanding were $3,400,000 at December 31, 1993.
Rental expense for the prior three years was as follows:
1993 1992 1991
Thousands of Dollars
Colstrip Unit 4. . . . $ 32,226 $ 32,226 $ 32,226
Kerr project . . . . . 11,837 11,486 11,027
Other. . . . . . . . . 11,917 11,985 13,452
$ 55,980 $ 55,697 $ 56,705
In addition, operating expenses include delay rentals paid by the Company
to retain mineral rights before development of leased acreage. Delay rentals
were $1,021,000, $999,000, and $1,000,000 in 1993, 1992, and 1991,
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
$16,113,000 over the remaining term of the 25-year lease.
At December 31, 1993, the Company's future minimum operating lease
payments are as follows:
Thousands of
Year Dollars
1994. . . . . . . . . . . . . . . $ 34,833
1995. . . . . . . . . . . . . . . 34,492
1996. . . . . . . . . . . . . . . 34,362
1997. . . . . . . . . . . . . . . 34,216
1998. . . . . . . . . . . . . . . 34,301
Remainder . . . . . . . . . . . . 393,459
Total . . . . . . . . . . . . $ 565,663
NOTE 4 - Income tax expense:
Income before income taxes for the years ended December 31, 1993, 1992
and 1991 was as follows:
1993 1992 1991
Thousands of Dollars
Utility Operations:
United States..................... $ 94,247 $ 77,752 $ 75,872
Canada............................ 2,340 1,395 5,073
96,587 79,147 80,945
Other Income and Expense:
United States..................... 230 1,497 1,061
Canada............................ 609 (314) 46
839 1,183 1,107
Entech Operations:
United States..................... 58,611 61,409 71,640
Canada............................ 5,842 4,966 (2,665)
64,453 66,375 68,975
Independent Power Group Operations:
United States.................... (548) 5,999 5,082
$ 161,331 $ 152,704 $ 156,109
Income tax expense as shown in the Consolidated Statement of Income
consists of the following components:
1993 1992 1991
Thousands of Dollars
Utility Operations:
Current
United States..................... $ 23,519 $ 24,563 $ 24,104
Canada............................ 1,121 879 2,044
State............................. 4,903 4,999 5,370
Deferred
United States..................... 6,902 (1,593) (2,507)
Canada............................ 80 (191) (262)
State............................. 980 (641) (941)
37,505 28,016 27,808
Other Income and Expense:
Current
United States..................... (2,281) 1,139 655
State............................. (302) 141 181
Deferred
United States..................... 2,410 (1,865) 694
State............................. 32 (204) (252)
(141) (789) 1,278
Entech Operations:
Current
United States..................... 14,090 14,703 18,180
Canada............................ 2,114 2,283 814
State............................. 2,098 3,442 1,905
Deferred
United States..................... (1,619) (3,093) (1,322)
Canada............................ 294 (9) 10
State............................. 286 (1,148) 5
17,263 16,178 19,592
Independent Power Group Operations:
Current
United States..................... (4,289) (2,153) (6,286)
State............................. (3,177) (275) (1,178)
Deferred
United States..................... 5,971 3,905 7,645
State............................. 988 757 1,535
(507) 2,234 1,716
$ 54,120 $ 45,639 $ 50,394
Deferred tax liabilities (assets) are comprised of the following at
December 31:
1993 1992
Thousands of Dollars
Plant Related......................... $ 372,236 $ 353,900
Investment in nonutility generation
projects............................ 16,370 13,904
Other................................. 16,260 11,622
Gross deferred tax liabilities........ 404,866 379,426
Coal reclamation...................... (37,321) (33,005)
Amortization of gain on sale/
leaseback........................... (18,090) (19,295)
Investment Tax Credit Amortization.... (32,801) (33,958)
Other................................. (14,937) (13,409)
Gross deferred tax assets............. (103,149) (99,667)
Net deferred tax liabilities (assets). 301,717 279,759
Current deferred tax assets........... 8,063 8,339
Total noncurrent deferred tax
liabilities(assets)............... $ 309,780 $ 288,098
The change in net deferred 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).............................. $ 21,682
Costs deferred to future operating periods.......... (4,991)
Other............................................... (367)
Deferred Tax Expense.............................. $ 16,324
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:
1993 1992 1991
Thousands of Dollars
Computed "expected" income tax expense.. $ 56,466 $ 51,919 $ 53,077
Adjustments for tax effects of:
Statutory depletion in
coal mining operations............ (3,775) (5,920) (5,972)
General business and nonconventional
fuel tax credits.................. (4,496) (3,723) (2,201)
State income tax, net................ 4,704 3,332 4,890
Reversal of excess of U.S. utility
income tax depreciation over
financial accounting
depreciation on utility plant
additions......................... 2,281 1,987 2,535
Other................................ (1,060) (1,956) (1,935)
Actual income tax expense............... $ 54,120 $ 45,639 $ 50,394
During 1993, the federal income tax rate increased from 34% to 35%. The
following table summarizes the increased income taxes that resulted.
Thousands of Dollars
Utility Operations . . . . . . . . . . . . $ 1,072
Entech Operations. . . . . . . . . . . . . 867
Independent Power Group Operations . . . . 749
$ 2,688
NOTE 5 - Common stock:
At December 31, 1993 and 1992, 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, as well as Montana utility customers, 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 per quarter of common stock.
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 loans are made,
long-term debt and the offset in common shareholders' equity are both reduced.
At December 31, 1993, 482,387 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, 1993:
1993 1992 1991
Thousands of Dollars
Principal allocated.................... $ 2,663 $ 2,683 $ 2,672
Interest incurred...................... 3,275 3,448 3,557
Dividends.............................. (3,028) (2,965) (2,843)
Additional contribution................ 2,310 1,765 1,290
Total Expense..................... $ 5,220 $ 4,931 $ 4,676
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 $758,000, $694,000 and $892,000 for the years
ending December 31, 1993, 1992 and 1991, 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, 1990 436,642 $11.4375 - 20.0625
Granted 372,600 22.125 - 26.50
Exercised (128,930) 11.4375 - 22.125
Cancelled (22,865) 14.25 - 22.125
Outstanding
December 31, 1991 657,447 $11.4375 - 26.50
Granted -
Exercised (116,905) 11.4375 - 22.125
Cancelled (4,457) 11.4375 - 22.125
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
Options Exercisable at
December 31, 1993 412,310
Options were granted at not less than the closing price on the New York
Stock Exchange on the date granted, and generally become exercisable after two
years. Options granted prior to January 1, 1987 must be exercised in the
order granted. All options expire ten years from the date of grant.
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.
In November 1993, the Company sold $50,000,000 of the $6.875 series of
Preferred Stock, stated value and liquidation value $100. The net proceeds
from the sale were used to repay short-term debt. The stock is redeemable at
the option of the Company, in whole or in part, at any time on or after
November 1, 2003.
Preferred stock, as shown in the Consolidated Balance Sheet, 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 the year 2013, after which the redemption price is $100 per share.
NOTE 7 - Long-term debt:
Long-term debt consists of the following:
December 31
1993 1992
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
8 5/8% series, due 2004.................... 60,000
7% series, due 2005........................ 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.................. 43,000
Pollution Control Revenue Bonds:
County of Rosebud, Montana
5 3/4% series, due 2003.................... 18,545
6.3% series, due 2007...................... 7,000
City of Forsyth, Montana
10% series, due 2004....................... 40,000
10 1/8% series, due 2014................... 40,000
Variable rate series, due 2014............. 39,660
Adjustable rate series, due 2014........... 25,000
6 1/8% series, due 2023.................... 90,205
5.9% series, due 2023...................... 80,000
Sinking Fund Debentures:
7 1/2%, due 1998........................... 17,500 18,000
Revolving Credit Agreements:
Entech..................................... 12,000
ESOP Notes Payable, due 2004................... 33,850 35,596
Medium-Term Notes, Series A.................... 67,250 100,000
Long-Term Commercial Paper..................... 20,000 20,000
Other.......................................... 15,144 20,917
Unamortized Discount and Premium.......... (3,880) (3,157)
598,069 618,561
Less: Portion due within one year............. 26,199 37,382
$ 571,870 $ 581,179
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
securing Pollution Control Revenue Bonds, in the aggregate principal amount of
$448,200,000 at December 31, 1993.
In February 1993, the Company sold $50,000,000 of First Mortgage Bonds,
7% series due 2005, and $13,000,000 of Secured Medium-Term Notes, 7.25% series
due 2008. The proceeds of these sales were used to redeem $60,000,000 of
First Mortgage Bonds, 8 5/8% series due 2004.
Secured Medium-Term Notes:
These notes constitute a series of First Mortgage Bonds. On January 26,
1993, the Company sold $22,000,000 of Medium-Term Notes, $15,000,000 of the
8.11% series due 2023 and $7,000,000 of the 7.23% series due 2003. Another
$8,000,000 of the 7.23% series due 2003 was sold on January 28, 1993. The
proceeds of these issues were used to repay Long-Term Commercial Paper and
other long-term bank debt outstanding.
In February 1993, the Company sold $13,000,000 of Secured Medium-Term
Notes, 7.25% series due 2008. As previously mentioned, the proceeds of this
sale were used to redeem $60,000,000 of First Mortgage Bonds, 8 5/8% series
due 2004.
On January 19, 1994, the Company sold $5,000,000 of Secured Medium-Term
Notes, 7.25% series due 2024, the proceeds of which were used to repay short-
term debt incurred to complete the refinancing of the 10% and 10 1/8% series
Pollution Control Revenue Bonds.
Pollution Control Revenue Bonds:
In June 1993, the City of Forsyth, Rosebud County, Montana, sold
$90,205,000 of its 6 1/8% Pollution Control Revenue Refunding Bonds due 2023,
the principal of, and interest on, which the Company is obligated to pay. The
proceeds from the sale of these Bonds were loaned to the Company and used to
redeem, prior to maturity, $18,545,000 of Rosebud County's 5 3/4% Pollution
Control Revenue Bonds due 2003, $7,000,000 of the County's 6.3% Pollution
Control Revenue Bonds due 2007, $39,660,000 of the City of Forsyth's Variable
Rate Pollution Control Revenue Bonds due 2014 and $25,000,000 of the City's
Adjustable Rate Pollution Control Revenue Bonds due 2014, the principal of,
and interest on, all of which the Company was obligated to pay.
On December 30, 1993, the City of Forsyth, Rosebud County, Montana, sold
$80,000,000 of its 5.9% Pollution Control Revenue Refunding Bonds due 2023,
the principal of, and interest on, which the Company is obligated to pay. The
proceeds from the sale of these Bonds were loaned to the Company and used to
redeem, prior to maturity, $40,000,000 of the City of Forsyth's 10% Pollution
Control Revenue Bonds due 2004, $40,000,000 of the City's 10 1/8% Pollution
Control Revenue Bonds due 2014, the principal of, and interest on, all of
which the Company was obligated to pay. Although not redeemed until
January 1, 1994, the 10% and 10 1/8% series were considered to be retired on
December 30, 1993 for financial reporting purposes, since the Company had
placed funds on deposit with the trustee at year end to cover all costs
associated with the redemption of these bonds. Accordingly, the funds held by
the trustee and the bonds do not appear on the December 31, 1993 Consolidated
Balance Sheet.
Revolving Credit Agreements:
The Company has a Revolving Credit and Term Loan Agreement that allows
it to borrow up to $60,000,000, all of which was unused at December 31, 1993.
Under the agreement, borrowings outstanding at October 31, 1995, must be
repaid in eight quarterly installments beginning in January 1996.
Entech has a Revolving Credit and Term Loan Agreement with a group of
banks that allows it to borrow up to $75,000,000, all of which was unused at
December 31, 1993. Under the agreement, borrowings outstanding at
September 30, 1994 must be repaid in eight quarterly installments beginning in
December 1994.
Fixed or variable interest rate options are available under the
facilities, with commitment fees on the unused portions. On December 31,
1992, Entech had outstanding $12,000,000 under these agreements, at a 4%
interest rate.
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 for further information.
Medium-Term Notes, Series A:
At December 31, 1993 and 1992, the Company had outstanding $67,250,000
and $100,000,000 principal amount of Medium-Term Notes, respectively, maturing
from eleven months to 29 years with interest rates varying between 8.57% and
8.90%.
On January 15, 1993, $13,000,000 of Medium-Term Notes, 8.65% series due
1993, matured. The Company retired these notes with the proceeds of short-
term borrowing.
On December 20, 1993, $19,750,000 of Medium-Term Notes, 8.8% series due
1993, matured. The Company retired these notes with the proceeds of long-term
commercial paper.
During the period 1994 through 1998, the Company is required to make the
following maturity and sinking fund payments on long-term debt:
1994 1995 1996 1997 1998
Thousands of Dollars
7 1/2% Sinking Fund
Debentures............... $ 500 $ 500 $ 500 $ 500 $ 15,500
ESOP Notes Payable......... 1,907 2,082 2,274 2,483 2,712
Medium-Term Notes.......... 19,000 10,000 8,750 7,500 2,500
Other...................... 4,792 4,475 4,092 201 192
$ 26,199 $ 17,057 $ 15,616 $ 10,684 $ 20,904
NOTE 8 - Short-term borrowing:
The Company is currently 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, 1993, the Company had lines of credit consisting of
$75,000,000 committed and $65,400,000 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 $135,000,000 of commercial paper
based on the total of its unused committed lines of credit and its revolving
credit agreement and Entech has a $50,000,000 commercial paper facility.
At December 31, 1993 and 1992, the Company's and Entech's short-term
borrowing included the following:
1993 1992
Thousands of Dollars
Notes payable to banks
MPC.......................... $ 43,900 $ 34,300
Entech....................... 8,000 13,000
Commercial paper
MPC.......................... 16,000
Entech....................... 16,965
$ 68,865 $ 63,300
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 1993, pension costs funded were less than SFAS No. 87 pension expense
by $1,887,000 and the difference was recorded as a reduction of unearned
revenue. The amount of utility pension costs funded are included in rates.
In 1992 and 1991, pension costs funded exceeded SFAS No. 87 pension expense by
$969,000 and $48,000, respectively and the differences were recorded as
unearned revenue. At December 31, 1993, the cumulative amount by which
pension costs funded exceed SFAS No. 87 pension expense is $1,362,000.
The assets of the plans consist primarily of corporate stocks, 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:
1993 1992 1991
Thousands of Dollars
Service cost benefits earned during
the period.......................... $ 6,746 $ 5,287 $ 4,875
Interest cost on projected benefit
obligation.......................... 12,077 9,978 9,230
Actual return market value of assets.. (18,701) (12,688) (20,509)
Net amortization and deferral......... 10,891 4,642 14,548
Total net periodic pension and
benefit expense................... $ 11,013 $ 7,219 $ 8,144
The funded status of the pension and benefit plans is as follows:
December 31
1993 1992
Thousands of Dollars
Actuarial present value of accumulated plan
benefits
Vested...................................... $ 120,550 $ 98,618
Nonvested................................... 10,861 8,386
Accumulated benefit obligation.................. 131,411 107,004
Effect of projected future compensation levels.. 62,278 34,931
Projected benefit obligation.................... 193,689 141,935
Plan assets at fair value....................... 150,913 133,291
Plan assets less than projected
benefit obligation............................ (42,776) (8,644)
Unrecognized net (gain) from past
experience different from that assumed and
effects of changes in assumptions............. 16,675 (11,120)
Prior service cost not yet recognized in net
periodic pension expense...................... 14,567 11,445
Unrecognized initial obligation................. 3,703 3,999
Prepaid (Accrued) benefits expense............ $ (7,831) $ (4,320)
The following assumptions were used in the determination of actuarial
present values of the projected benefit obligations:
December 31
1993 1992
Assumed discount rates:
Active service and vested terminations........ 7.00% 7.75%
Retired employees............................. 7.00% 7.75%
Long-term rate of average compensation increase. 4.90%-5.45% 4.50%-5.45%
Long-term rate on plan assets................... 8.50% 8.00%
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, 1992 and 1991 was $1,387,000,
$1,267,000 and $1,187,000, respectively.
The Company adopted Financial Accounting Standards Board (FASB)
Statement of Financial Accounting Standards No. 106, "Employers' Accounting
for Postretirement Benefits Other Than Pensions" (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.
The Company's accumulated postretirement benefit obligation at
January 1, 1994 is estimated to be $34,400,000, with $24,600,000 and
$9,800,000 related to utility and non-utility operations, respectively. The
utility and non-utility amounts are being amortized through charges to
earnings over 20 and 24-year periods, respectively. The incremental increase
in 1993 consolidated expenses due to SFAS No. 106 adoption was $1,600,000, all
of which related to the non-utility operations.
In accordance with an Accounting Order issued by the PSC on November 10,
1992, the Company has recorded as a deferred expense in 1993 the increased
costs of $2,100,000 which resulted from adopting SFAS No. 106 for the Utility
Division. The Company requested recovery of utility SFAS No. 106 costs from
ratepayers in its rate filing on June 21, 1993 and a final rate order is
expected by the end of April 1994. The Company believes that the costs will
be allowed in rates based on previous PSC rate decisions addressing this
issue.
The cost of SFAS No. 106 adoption for the year ended December 31, 1993,
a portion of which has been capitalized, includes the following components:
December 31
1993
Thousands of Dollars
Service cost on benefits earned
during the year. . . . . . . . . . . . $ 1,356
Interest cost on projected benefit
obligation . . . . . . . . . . . . . . 2,296
Amortization of transition obligation . . 1,492
Total postretirement benefit cost . . . . $ 5,144
The funded status of the postretirement benefit plans is as follows:
December 31
1993
Thousands of Dollars
Accumulated benefit obligation:
Fully eligible active employees . . . . . . $ 1,920
Other active employees. . . . . . . . . . . 20,195
Retirees. . . . . . . . . . . . . . . . . . 12,298
Accumulated benefit obligation. . . . . . . 34,413
Plan assets at fair value . . . . . . . . . . 0
Plan assets less than projected
benefit obligation. . . . . . . . . . . . . (34,413)
Unrecognized net transition obligation. . . . 27,519
Unrecognized net loss from past
experience different from that
assumed and effects of changes
in assumptions. . . . . . . . . . . . . . . 3,113
Prepaid (Accrued) benefits expense. . . . . . $ (3,781)
The assumed 1993 health care cost trend rates used to measure the
expected cost of benefits covered by the plans are 9% and 12% for the utility
and non-utility operations, respectively. Both trend rates decrease through
2003 to an ultimate rate of 5.75%. 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 5.75% 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 $34,400,000 to $37,500,000.
In November 1992, the FASB released Statement of Financial Accounting
Standards No. 112, "Employers' Accounting for Postemployment Benefits,"
(SFAS No. 112) effective for fiscal years beginning after December 15, 1993.
The Company adopted SFAS No. 112 with respect to disability related benefits
up to age 65 effective January 1, 1994. This statement requires the accrual
of a liability or loss contingency for the estimated obligation for
postemployment benefits. At December 31, 1993, the Company's postemployment
benefit liability is estimated to be $10,600,000, with $9,300,000 and
$1,300,000 relating to regulated utility and nonregulated operations,
respectively. The utility had recorded a liability and recovered through
rates by year-end approximately $2,400,000 for disability-related benefits.
The incremental increase in 1994 consolidated expenses due to SFAS No. 112
adoption is estimated to be $1,300,000, all of which relates to non-utility
operations.
Effective January 1, 1994, the Company is no longer self-insured for a
significant portion of the disability-related benefits relating to the Utility
Division. The Company will record as a deferred expense in 1994 the
additional postemployment benefit liability of $6,900,000 that was incurred by
the utility but not recognized while self-insured. The Company will charge a
significant portion of this amount to income and will recover it through rates
within 10 years.
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 and exploration for, and the
development, production, processing and sale of oil and natural gas. The
Company, through its Independent Power Group (IPG), manages long-term power
sales, invests in cogeneration projects, and provides energy-related support
services, including the operation and maintenance of power plants.
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. Operating income before income taxes for utility segments
represents operating revenues less total operating expenses and taxes other
than income taxes. Operating income for Entech segments represents total
revenues less all costs and expenses except interest, interest income and
other-net, and income taxes. Depreciation and depletion includes a provision
for abandonment of nonproducing leases, amortization of other deferred charges
and certain depreciation amounts included in operation expense in the
Consolidated Statement of Income. 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 $80,304,000, $83,790,000 and $84,433,000 at
December 31, 1993, 1992 and 1991, respectively.
Operations Information
Year ended December 31, 1993
Thousands of Dollars
Utility industry segments: Electric Natural Gas Consolidated
Operating revenue. . . . . . . . $ 426,812 $ 110,971 $ 537,783
Intersegment sales . . . . . . . 6,790 317 7,107
Total revenue. . . . . . . . . $ 433,602 $ 111,288 $ 544,890
Operating income before
income taxes . . . . . . . . . $ 112,031 $ 31,441 $ 143,472
Income taxes . . . . . . . . . . (37,505)
Operating income . . . . . . . $ 105,967
Depreciation and
depletion. . . . . . . . . . . $ 37,320 $ 8,736
Oil and
Entech industry segments: Coal Natural Gas Other Consolidated
Sales to unrelated
customers. . . . . . . $ 227,268 $ 117,706 $ 24,398 $ 369,372
Intersegment sales to:
Utility. . . . . . . . 29,714 742 700 31,156
Independent Power
Group. . . . . . . . 9,923 9,923
Total revenues . . . . $ 266,905 $ 118,448 $ 25,098 $ 410,451
Operating income before
income taxes . . . . . $ 45,221 $ 14,685 $ 1,002 $ 60,908
Interest . . . . . . . . (2,284)
Interest income and
other-net. . . . . . . 5,829
Income taxes . . . . . . (17,263)
Income from Entech
operations . . . . . . $ 47,190
Depreciation and
depletion. . . . . . . $ 10,102 $ 19,327 $ 2,224
Energy
Independent Power Group Services and
industry segments: Electric Cogeneration Consolidated
Operating revenue. . . . . . . . $ 70,332 $ 44,981 $ 115,313
Intersegment sales . . . . . . . 1,607 3,335 4,942
Total revenues. . . . . . . . . $ 71,939 $ 48,316 $ 120,255
Operating income before
income taxes . . . . . . . . . $ (3,906) $ (4,368) $ (8,274)
Interest . . . . . . . . . . . . (121)
Interest income and
other-net. . . . . . . . . . . 7,847
Income taxes . . . . . . . . . . 507
Income from Independent Power
Group operations . . . . . . . $ (41)
Depreciation . . . . . . . . . . $ 1,916 $ 278
Operations Information
Year ended December 31, 1992
Thousands of Dollars
Utility industry segments: Electric Natural Gas Consolidated
Operating revenue. . . . . . . . $ 402,402 $ 97,805 $ 500,207
Intersegment sales . . . . . . . 3,888 596 4,484
Total revenues. . . . . . . . . $ 406,290 $ 98,401 $ 504,691
Operating income before
income taxes. . . . . . . . . . $ 103,814 $ 23,066 $ 126,880
Income taxes . . . . . . . . . . (28,016)
Operating income. . . . . . . . $ 98,864
Depreciation and
depletion . . . . . . . . . . . $ 35,349 $ 8,181
Oil and
Entech industry segments: Coal Natural Gas Other Consolidated
Sales to unrelated
customers . . . . . . . $ 228,873 $ 90,317 $ 30,560 $ 349,750
Intersegment sales to
Utility . . . . . . . . 32,496 1,020 467 33,983
Independent Power
Group . . . . . . . . 13,396 13,396
Total revenues. . . . . $ 274,765 $ 91,337 $ 31,027 $ 397,129
Operating income before
income taxes. . . . . . $ 48,852 $ 13,285 $ 1,232 $ 63,369
Interest . . . . . . . . (2,144)
Interest income and
other-net . . . . . . . 5,150
Income taxes . . . . . . (16,178)
Income from Entech
operations. . . . . . . $ 50,197
Depreciation and
depletion . . . . . . . $ 11,259 $ 19,607 $ 2,665
Energy
Independent Power Group Services and
industry segments: Electric Cogeneration Consolidated
Operating revenue. . . . . . . . $ 78,896 $ 14,161 $ 93,057
Intersegment sales . . . . . . . 2,492 57 2,549
Total revenues. . . . . . . . . $ 81,388 $ 14,218 $ 95,606
Operating income before
income taxes . . . . . . . . . $ 5,354 $ (1,903) $ 3,451
Interest . . . . . . . . . . . . (31)
Interest income and
other-net. . . . . . . . . . . 2,579
Income taxes . . . . . . . . . . (2,234)
Income from Independent Power
Group operations . . . . . . . $ 3,765
Depreciation . . . . . . . . . . $ 1,883 $ 51
Operations Information
Year ended December 31, 1991
Thousands of Dollars
Utility industry segments: Electric Natural Gas Consolidated
Operating revenue. . . . . . . . $ 385,438 $ 108,477 $ 493,915
Intersegment sales . . . . . . . 4,038 65 4,103
Total revenues. . . . . . . . . $ 389,476 $ 108,542 $ 498,018
Operating income before
income taxes . . . . . . . . . $ 104,628 $ 26,976 $ 131,604
Income taxes . . . . . . . . . . (27,808)
Operating income . . . . . . . $ 103,796
Depreciation and
depletion. . . . . . . . . . . $ 33,312 $ 8,131
Oil and
Entech industry segments: Coal Natural Gas Other Consolidated
Sales to unrelated
customers. . . . . . . $ 225,906 $ 61,961 $ 29,922 $ 317,789
Intersegment sales to
Utility. . . . . . . . 31,300 534 31,834
Independent Power
Group. . . . . . . . 12,477 12,477
Total revenues . . . . $ 269,683 $ 61,961 $ 30,456 $ 362,100
Operating income before
income taxes . . . . . $ 56,988 $ 5,073 $ 1,890 $ 63,951
Interest . . . . . . . . (1,776)
Interest income and
other-net. . . . . . . 6,800
Income taxes . . . . . . (19,592)
Income from Entech
operations . . . . . . $ 49,383
Depreciation and
depletion. . . . . . . $ 12,253 $ 15,197 $ 2,658
Energy
Independent Power Group Services and
industry segments: Electric Cogeneration Consolidated
Operating revenue. . . . . . . . $ 75,276 $ 2,195 $ 77,471
Intersegment sales . . . . . . . 1,345 1,345
Total revenues. . . . . . . . . $ 76,621 $ 2,195 $ 78,816
Operating income before
income taxes . . . . . . . . . $ 4,782 $ (1,358) $ 3,424
Interest . . . . . . . . . . . . (1,081)
Interest income and
other-net. . . . . . . . . . . 2,739
Income taxes . . . . . . . . . . (1,716)
Income from Independent
Power Group operations . . . . $ 3,366
Depreciation . . . . . . . . . . $ 1,835
Assets and Expenditures
Identifiable Assets
December 31
1993 1992 1991
Thousands of Dollars
Industry segments:
Utility
Electric . . . . . . . . . . . . . . . $1,323,760 $1,266,651 $1,248,286
Natural gas. . . . . . . . . . . . . . 352,540 334,834 324,986
Total Utility. . . . . . . . . . . . 1,676,300 1,601,485 1,573,272
Entech
Coal . . . . . . . . . . . . . . . . . 264,991 235,538 242,582
Oil and natural gas. . . . . . . . . . 168,823 161,905 155,006
Other. . . . . . . . . . . . . . . . . 36,300 26,001 25,016
Total Entech . . . . . . . . . . . . 470,114 423,444 422,604
Independent Power Group . . . . . . . . 163,550 164,777 145,370
Total identifiable items . . . . . . 2,309,964 2,189,706 2,141,246
Corporate items . . . . . . . . . . . . 76,063 95,716 76,800
$2,386,027 $2,285,422 $2,218,046
Capital Expenditures
Year Ended December 31
1993 1992 1991
Thousands of Dollars
Industry segments:
Utility
Electric . . . . . . . . . . . . . . . $ 83,308 $ 76,111 $ 67,277
Natural gas. . . . . . . . . . . . . . 28,871 20,233 17,696
Total Utility. . . . . . . . . . . . 112,179 96,344 84,973
Entech
Coal . . . . . . . . . . . . . . . . . 24,123 10,081 32,516
Oil and natural gas. . . . . . . . . . 38,547 29,722 53,435
Other. . . . . . . . . . . . . . . . . 1,875 3,586 1,224
Total Entech . . . . . . . . . . . . 64,545 43,389 87,175
Independent Power Group . . . . . . . . 4,542 19,489 15,220
Total identifiable items . . . . . . 181,266 159,222 187,368
Corporate items . . . . . . . . . . . . 156 601 1,315
$ 181,422 $ 159,823 $ 188,683
SUPPLEMENTARY INFORMATION
OIL AND NATURAL GAS PRODUCING ACTIVITIES
For the years ended December 31, 1993, 1992 and 1991 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:
1993
U.S. CANADA STORAGE
PROVED DEVELOPED AND UNDEVELOPED RESERVES:
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 2,291
Revisions - Price 102 790
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
1992
U.S. CANADA STORAGE
PROVED DEVELOPED AND UNDEVELOPED RESERVES:
UTILITY OPERATIONS:
Natural Gas (Mmcf):
Beginning Balance 87,970 102,609 59,545
Production (5,724) (2,951)
Additions (470)
(Sales) and Purchases of Reserves in Place 266
Revisions - Other 723 1,224
Revisions - Price 29 338
Ending Balance 83,264 101,220 59,075
ENTECH OPERATIONS:
Natural Gas (Mmcf):
Beginning Balance 119,245 36,887
Production (8,758) (6,748)
Additions 6,874 5,288
(Sales) and Purchases of Reserves in Place 2,603 227
Revisions - Other 9,603 2,771
Revisions - Price 3,854 3,195
Ending Balance 133,421 41,620
Natural Gas
Liquids (Bbls):
Beginning Balance 685,600 1,395,400
Production (138,226) (87,997)
Additions 517,581 700
(Sales) and Purchases of Reserves in Place (1,185)
Revisions - Other 6,745 (426,218)
Revisions - Price 26,800
Ending Balance 1,071,700 907,500
Oil (Bbls):
Beginning Balance 3,981,000 3,773,615
Production (590,573) (963,192)
Additions 731,174 1,106,684
(Sales) and Purchases of Reserves in Place 73,934 89,369
Revisions - Other (401,035) 694,224
Revisions - Price 83,400 92,700
Ending Balance 3,877,900 4,793,400
1992
U.S. CANADA
PROVED DEVELOPED RESERVES:
UTILITY OPERATIONS:
Natural Gas (Mmcf):
Ending Balance 82,449 101,220
ENTECH OPERATIONS:
Natural Gas (Mmcf):
Ending Balance 82,596 38,353
Natural Gas Liquids (Bbls):
Ending Balance 1,071,700 895,800
Oil (Bbls):
Ending Balance 3,406,000 4,076,500
1991
U.S. CANADA STORAGE
PROVED DEVELOPED AND UNDEVELOPED RESERVES:
UTILITY OPERATIONS:
Natural Gas (Mmcf):
Beginning Balance 93,658 106,233 59,256
Production (6,294) (4,550)
Additions 289
(Sales) and Purchases of Reserves in Place 235
Revisions - Other 557 22
Revisions - Price (186) 904
Ending Balance 87,970 102,609 59,545
ENTECH OPERATIONS:
Natural Gas (Mmcf):
Beginning Balance 129,075 43,831
Production (7,274) (5,247)
Additions 14,390 301
(Sales) and Purchases of Reserves in Place 1,791 3,552
Revisions - Other (16,553) (4,425)
Revisions - Price (2,184) (1,125)
Ending Balance 119,245 36,887
Natural Gas
Liquids (Bbls):
Beginning Balance 490,999 1,399,131
Production (148,870) (72,468)
Additions
(Sales) and Purchases of Reserves in Place 65,600
Revisions - Other 343,471 (5,563)
Revisions - Price 8,700
Ending Balance 685,600 1,395,400
Oil (Bbls):
Beginning Balance 3,363,000 2,125,938
Production (607,301) (426,624)
Additions 1,140,787 384,991
(Sales) and Purchases of Reserves in Place 157,449 1,541,673
Revisions - Other 164,833 245,009
Revisions - Price (237,768) (97,372)
Ending Balance 3,981,000 3,773,615
1991
U.S. CANADA
PROVED DEVELOPED RESERVES:
UTILITY OPERATIONS:
Natural Gas (Mmcf):
Ending Balance 87,155 102,609
ENTECH OPERATIONS:
Natural Gas (Mmcf):
Ending Balance 55,253 36,294
Natural Gas Liquids (Bbls):
Ending Balance 600,800 1,380,300
Oil (Bbls):
Ending Balance 2,609,200 3,136,115
SUPPLEMENTARY INFORMATION
Oil and Natural Gas Producing Activities (Cont.)
As determined by utility engineers, natural gas reserves were revised
during 1993, 1992 and 1991 due to a change in projected performance or a
change in the Company's ownership interest in specific fields.
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 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.
In 1992, the drilling of 43 development wells and one exploratory well
in Colorado, Wyoming, and Oklahoma, resulted in additions to Entech's oil and
gas reserves in the United States. Price changes also added to the reserves
of existing properties. The Canadian companies participated in 59 development
and two exploratory wells, resulting in the addition of significant oil and
gas reserves. Revisions due to price and improved performance provided a net
increase in oil and gas reserves. Natural gas liquid reserves decreased due
to a downward revision in unit working interest in the recently developed
Shell Caroline area.
In 1991, additions to Entech's United States oil and gas reserves
resulted from the drilling of 32 development wells and two successful
exploratory wells, principally in Colorado, Oklahoma and Wyoming.
Acquisitions of new oil and gas properties added reserves in Colorado, North
Dakota and Wyoming. Price changes and unsuccessful drilling activities
resulted in downward revisions to existing reserves. Additions to oil and gas
reserves in Canada resulted from the drilling of 14 development wells in
Alberta and one exploratory well in British Columbia. Acquisition of a new
oil and gas property, development drilling and favorable production
performance in Alberta reflect upward revisions in reserves. Natural gas
reserves and associated liquids were revised downward as a result of revised
estimates of performance in 26 mature Alberta fields and market price
declines.
The following table presents information for 1993, 1992 and 1991 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.
1993 1992 1991
United United United
States Canada States Canada States Canada
UTILITY OPERATIONS Thousands of Dollars
At December 31:
Capitalized costs relating
to natural gas producing
activities . . . . . . . $ 90,711 $ 35,786 $ 90,416 $ 35,592 $ 89,969 $ 35,962
Accumulated depreciation,
depletion and valuation
allowances . . . . . . . 44,516 18,815 43,003 18,500 41,189 18,213
Net capitalized costs. . $ 46,195 $ 16,971 $ 47,413 $ 17,092 $ 48,780 $ 17,749
For the year ended
December 31:
Costs incurred in natural
gas property acquisition,
exploration and
development activities:
Acquisition of
properties . . . . . $ 46 $ 27 $ 148 $ 7 $ 136 $ 4
Exploration. . . . . . 386 244 361 237 830 244
Development. . . . . . 1,528 496 1,208 329 2,324 464
Costs reflected in results
of operations:
Production costs . . . . 8,060 2,350 7,454 2,289 7,455 2,341
Exploration expenses . . 383 244 361 237 830 244
Development expenses . . 90 59 159 130 46
Depreciation, depletion
and valuation
provisions . . . . . . 2,564 283 2,421 511 3,296 710
The following table presents information for 1993, 1992 and 1991 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:
1993 1992 1991
United United United
States Canada States Canada States Canada
ENTECH OPERATIONS Thousands of Dollars
At December 31:
Capitalized costs relating
to oil and natural gas
producing activities . . $136,949 $ 88,596 $121,119 $ 85,306 $107,771 $ 84,040
Accumulated depreciation,
depletion and valuation
allowances . . . . . . . 36,725 34,426 31,428 28,743 26,301 23,725
Net capitalized costs. $100,224 $ 54,170 $ 89,691 $ 56,563 $ 81,470 $ 60,315
For the year ended
December 31:
Costs incurred in oil and
natural gas property
acquisition, exploration
and development
activities:
Acquisition of
properties . . . . . $ 1,700 $ 2,638 $ 2,629 $ 1,774 $ 7,931 $ 16,567
Exploration. . . . . . 2,838 2,711 1,554 1,839 3,754 2,054
Development. . . . . . 26,279 5,721 15,729 9,183 16,581 9,690
ENTECH OPERATIONS
Results of operations for
oil and natural gas
producing activities:
Revenues . . . . . . . . $ 30,713 $ 23,435 $ 25,739 $ 23,541 $ 24,095 $ 13,361
Production costs . . . . 9,459 7,629 7,685 7,908 8,501 5,511
Exploration expenses . . 2,123 2,184 1,317 1,829 1,704 1,858
Depreciation, depletion
and valuation
provisions . . . . . . 10,386 8,707 9,895 9,515 8,364 6,833
8,745 4,915 6,842 4,289 5,526 (841)
Income tax expenses. . . 978 2,179 687 1,901 2,125 (368)
Results of operations from
producing activities
(excluding corporate
overhead and interest
cost). . . . . . . . . . $ 7,767 $ 2,736 $ 6,155 $ 2,388 $ 3,401 $ (473)
SUPPLEMENTARY INFORMATION
Oil and Natural Gas Producing Activities (Cont.)
Estimated future cash inflows are computed by applying year-end prices
and contract prices, when appropriate, of oil and natural gas to year-end
quantities of proved reserves. Estimated future development and production
costs are determined by estimating the expenditures to be incurred in
developing and producing the proved oil and natural gas reserves at the end of
the year, based on year-end costs. Estimated future income tax expenses are
calculated by applying year-end statutory tax rates to estimated future pretax
net cash flows related to proved oil and natural gas reserves, less the tax
basis of the properties involved. The future income tax expenses give effect
to permanent differences, tax credits and deferred taxes relating to proved
oil and natural gas reserves.
These estimates are furnished and calculated in accordance with
requirements of the Financial Accounting Standards Board and the Securities
and Exchange Commission (SEC). Management believes the usefulness of these
projections is limited because of the unpredictable variances in expenses,
capital forecasts and crude oil and natural gas prices. Estimates of future
net cash flows presented do not represent management's assessment of 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
December 31
1993 1992
United United
States Canada States Canada
Thousands of Dollars
Future cash inflows. . . . . . . . $ 597,493 $ 166,455 $ 539,615 $ 136,833
Future production and
development costs. . . . . . . . 227,093 44,367 221,044 41,632
Future income tax expenses . . . . 106,670 31,003 86,112 17,726
Future net cash flows. . . . . . . 263,730 91,085 232,459 77,475
10% annual discount for
estimated timing
of cash flows. . . . . . . . . . 113,062 22,320 102,408 16,974
Standardized measure of
discounted future net
cash flows . . . . . . . . . . . $ 150,668 $ 68,765 $ 130,051 $ 60,501
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 . . . . . . . . $ (21,254) $ (15,807) $ (18,054) $ (15,633)
Net changes in prices,
development and production
costs. . . . . . . . . . . . . . (4,707) 4,744 18,567 1,600
Extensions, discoveries, and
improved recovery, less
related costs. . . . . . . . . . 45,772 23,655 18,233 11,870
Revisions of previous quantity
estimates. . . . . . . . . . . . (4,521) 2,346 12,323 7,792
Accretion of discount. . . . . . . 15,745 6,470 12,438 5,037
Net change in income taxes . . . . (10,327) (9,016) (8,041) (263)
Other. . . . . . . . . . . . . . . (91) (4,128) (10,441) 3,676
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 1993 and 1992, 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 1993 and 1992
are shown in the tables below. Due to the seasonal nature of the utility
business, the annual amounts are not generated evenly by quarter during the
year.
Quarter ended
Dec. 31, Sept. 30, June 30, Mar. 31,
1993 1993 1993 1993
Utility Operating Revenues . . . . $ 169,018 $ 106,967 $ 100,243 $ 168,662
Utility Operating Income . . . . . 43,491 13,486 8,980 40,010
Income (Loss) from Utility
Operations . . . . . . . . . . . 31,958 1,638 (1,735) 28,201
Entech Revenues. . . . . . . . . . 108,603 111,075 86,200 104,573
Income from Entech Operations. . . 17,557 11,214 6,723 11,696
Independent Power Group Revenues . 29,208 29,361 33,431 28,255
Income (Loss) from Independent . .
Power Group Operations . . . . . 610 (796) (3) 148
Consolidated Net Income. . . . . . 50,125 12,056 4,985 40,045
Net Income Per Share of Common
Stock. . . . . . . . . . . . . . 0.93 0.21 0.08 0.76
Quarter ended
Dec. 31, Sept. 30, June 30, Mar. 31,
1992 1992 1992 1992
Utility Operating Revenues . . . . $ 153,813 $ 105,473 $ 93,426 $ 151,979
Utility Operating Income . . . . . 39,213 15,729 6,669 37,253
Income (Loss) from Utility
Operations . . . . . . . . . . . 28,946 4,201 (5,046) 25,002
Entech Revenues. . . . . . . . . . 107,148 104,064 87,446 98,471
Income from Entech Operations. . . 13,835 11,467 9,512 15,383
Independent Power Group Revenues . 32,591 17,995 17,921 18,073
Income (Loss) from Independent
Power Group Operations . . . . . 1,987 (38) 584 1,232
Consolidated Net Income. . . . . . 44,768 15,630 5,050 41,617
Net Income Per Share of Common
Stock. . . . . . . . . . . . . . 0.85 0.29 0.08 0.80
ITEM 9. DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL PERSONS
See Item 1. Business - "Executive Officers."
Information on Directors is incorporated by reference from the Company's
Notice of 1994 Annual Meeting of Shareholders and Proxy Statement, pages 2-5.
Information on Section 16(a) compliance is incorporated by reference
from the Company's Notice of 1994 Annual Meeting of Shareholders and Proxy
Statement, page 20.
ITEM 11. EXECUTIVE COMPENSATION
Incorporated by reference from Notice of 1994 Annual Meeting of
Shareholders and Proxy Statement, pages 9-12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Incorporated by reference from Notice of 1994 Annual Meeting of
Shareholders and Proxy Statement, pages 5-7.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
(a) Please refer to Item 8, "Financial Statements and Supplementary Data"
for a complete listing of all consolidated financial statements and
financial statement schedules.
(b) The Company filed the following reports on Form 8-K:
Date Subject
None
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 33-42882 4(a)
3(a)(1) Restated Articles of Incorporation
3(a)(2) Amendments to the Restated Articles
of Incorporation
3(b) By-laws, as amended 33-42882 4(b)
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
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(m) 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 1-4566 10(a)(v)
Agreements with Senior 1992
Management Executives Form 10-K
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
THE MONTANA POWER COMPANY AND SUBSIDIARIES
SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT (INCLUDING INTANGIBLES)
Year Ended December 31, 1993
Thousands of Dollars
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
Other
Changes
Balance add
at (deduct) Balance
beginning Additions describe at end
Classification of period at cost Retirements (Note a) of period
Electric:
Intangible (3) $ 3,162 $ 207 $ $ $ 3,369
Production (1) 670,822 8,060 3,528 (2) 675,352
Transmission (1) 287,285 10,092 397 (6) 296,974
Distribution (1) 364,533 33,281 2,781 6 395,039
General (1) 47,010 3,515 1,045 (30) 49,450
Plant held for
future use 4,256 4,256
Electric plant
acquisition
adjustment (3) 3,106 3,106
Total electric
plant 1,380,174 55,155 7,751 (32) 1,427,546
Natural Gas:
Intangible 579 224 9 (6) 788
Field and produc-
tion (1)(2) 183,719 1,923 1,030 373 184,985
Transmission (1) 96,173 6,748 255 9 102,675
Distribution (1) 84,142 11,726 171 (1) 95,696
General (1) 15,958 1,692 525 26 17,151
Plant held for
future use
(Note c) 3,282 41 (260) (372) 3,211
Total natural
gas plant 383,853 22,354 1,730 29 404,506
Common Utility
Plant and Other
(Note b)(1)(3) 69,444 5,172 2,209 3 72,410
THE MONTANA POWER COMPANY AND SUBSIDIARIES
SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT (INCLUDING INTANGIBLES)
Year Ended December 31, 1993
Thousands of Dollars
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
Other
Changes
Balance add
at (deduct) Balance
beginning Additions describe at end
Classification of period at cost Retirements (Note a) of period
Construction Work
in Progress:
Electric $ 19,654 $ 14,744 $ $ $ 34,398
Natural gas 271 3,213 3,484
Common utility
and other 900 184 1,084
Total construction
work in progress 20,825 18,141 38,966
Total utility
plant and other 1,854,296 100,822 11,690 1,943,428
Entech Property
(including intan-
gibles $1,003)
(1)(2)(3) 482,732 69,121 21,527 (3,634) 526,692
Independent Power
Group Property
(including intan-
gibles $21)(1)(3) 69,805 941 548 70,198
Total $2,406,833 $ 170,884 $ 33,765 $ (3,634) $2,540,318
NOTES:
(a) Significant changes in Column E: (1) All changes to utility plant in
service represent transfers between plant accounts;
(2) The change reported for Entech property primarily represents a
translation of beginning and ending foreign property balances at
different exchange rates.
(b) Common utility plant and other includes $994,000 of nonutility property.
(c) Certain amounts retired in 1992 have been allowed to be amortized for
rate purposes. As such, the prior retirements have been reversed.
Methods of depreciation, depletion and amortization:
(1) Straight-line depreciation
(2) Units-of-production depletion
(3) Straight-line amortization
THE MONTANA POWER COMPANY AND SUBSIDIARIES
SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT (INCLUDING INTANGIBLES)
Year Ended December 31, 1992
Thousands of Dollars
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
Other
Changes
Balance add
at (deduct) Balance
beginning Additions describe at end
Classification of period at cost Retirements (Note a) of period
Electric:
Intangible (3) $ 1,357 $ 1,826 $ $ (21) $ 3,162
Production (1) 657,121 16,427 2,797 71 670,822
Transmission (1) 266,248 21,834 797 287,285
Distribution (1) 339,303 27,635 2,399 (6) 364,533
General (1) 42,058 5,984 1,003 (29) 47,010
Plant held for
future use 4,256 4,256
Electric plant
acquisition
adjustment (3) 3,106 3,106
Total electric
plant 1,313,449 73,706 6,996 15 1,380,174
Natural Gas:
Intangible 544 35 579
Field and produc-
tion (1)(2) 180,344 3,445 385 315 183,719
Transmission (1) 93,796 4,216 1,823 (16) 96,173
Distribution (1) 75,506 8,785 156 7 84,142
General (1) 13,372 3,162 538 (38) 15,958
Plant held for
future use 4,587 (287) 713 (305) 3,282
Total natural
gas plant 368,149 19,356 3,615 (37) 383,853
Common Utility
Plant and Other
(Note b)(1)(3) 66,336 3,962 872 18 69,444
THE MONTANA POWER COMPANY AND SUBSIDIARIES
SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT (INCLUDING INTANGIBLES)
Year Ended December 31, 1992
Thousands of Dollars
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
Other
Changes
Balance add
at (deduct) Balance
beginning Additions describe at end
Classification of period at cost Retirements (Note a) of period
Construction Work
in Progress:
Electric 23,641 (3,987) 19,654
Natural gas 1,544 (1,273) 271
Common utility
and other 1,066 (166) 900
Total construction
work in progress 26,251 (5,426) 20,825
Total utility
plant and other 1,774,185 91,598 11,483 (4) 1,854,296
Entech Property
(including intan-
gibles $1,451)
(1)(2)(3) 464,978 42,887 17,430 (7,703) 482,732
Independent Power
Group Property
(including intan-
gibles $20)(1)(3) 66,477 949 (233) 2,146 69,805
Total $2,305,640 $ 135,434 $ 28,680 $ (5,561) $2,406,833
NOTES:
(a) Significant changes in Column E: (1) All changes to utility plant in
service represent transfers between plant accounts;
(2) The change reported for Entech property primarily represents a
translation of beginning and ending foreign property balances at
different exchange rates; (3) The change reported for Independent Power
Group represents plant acquired in the purchase of North American Energy
Services Company on November 1, 1992.
(b) Common utility plant and other includes $1,217,000 of nonutility
property.
Methods of depreciation, depletion and amortization:
(1) Straight-line depreciation
(2) Units-of-production depletion
(3) Straight-line amortization
THE MONTANA POWER COMPANY AND SUBSIDIARIES
SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT (INCLUDING INTANGIBLES)
Year Ended December 31, 1991
Thousands of Dollars
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
Other
Changes
Balance add
at Additions (deduct) Balance
beginning at cost describe at end
Classification of period (Note a) Retirements (Note a) of period
Electric:
Intangible $ 1,321 $ 36 $ $ $ 1,357
Production (1)
(Note c) 650,862 9,113 2,868 14 657,121
Transmission (1) 259,391 7,786 879 (50) 266,248
Distribution (1) 315,987 26,145 2,868 39 339,303
General (1) 38,963 4,005 884 (26) 42,058
Plant held for
future use 4,256 4,256
Electric plant
acquisition
adjustment (3) 3,106 3,106
Total electric
plant 1,273,886 47,085 7,499 (23) 1,313,449
Natural Gas:
Intangible 475 69 544
Field and produc-
tion (1)(2) 180,299 3,571 3,524 (2) 180,344
Transmission (1) 95,268 710 2,192 10 93,796
Distribution (1) 67,487 8,373 354 75,506
General (1) 11,899 1,854 407 26 13,372
Plant held for
future use 5,148 183 744 4,587
Total natural
gas plant 360,576 14,760 7,221 34 368,149
Common Utility
Plant and Other
(Note b)(1)(3) 65,580 6,429 5,683 10 66,336
THE MONTANA POWER COMPANY AND SUBSIDIARIES
SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT (INCLUDING INTANGIBLES)
Year Ended December 31, 1991
Thousands of Dollars
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
Other
Changes
Balance add
at Additions (deduct) Balance
beginning at cost describe at end
Classification of period (Note a) Retirements (Note a) of period
Construction Work
in Progress:
Electric 10,541 13,100 23,641
Natural gas 1,207 337 1,544
Common utility
and other 465 601 1,066
Total construction
work in progress 12,213 14,038 26,251
Total utility
plant and other 1,712,255 82,312 20,403 21 1,774,185
Entech Property
(including intan-
gibles $967)
(1)(2)(3) 403,169 83,580 22,037 266 464,978
Independent Power
Group Property
(including intan-
gibles $3)(1)(3) 66,507 748 765 (13) 66,477
Total $2,181,931 $ 166,640 $ 43,205 $ 274 $2,305,640
NOTES:
(a) Significant changes in Column E: (1) All changes to utility plant
represent transfers between plant accounts; (2) The change reported for
Entech property primarily represents a translation of beginning and
ending foreign property balances at different exchange rates.
(b) Common utility plant and other includes $1,447,000 of nonutility
property.
(c) Certain carrying costs related to Colstrip Unit 3 have been reclassified
from costs deferred to future operating periods.
Methods of depreciation, depletion and amortization:
(1) Straight-line depreciation
(2) Units-of-production depletion
(3) Straight-line amortization
THE MONTANA POWER COMPANY AND SUBSIDIARIES
SCHEDULE VI - ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION OF
PROPERTY, PLANT AND EQUIPMENT
Thousands of Dollars
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
Other
Balance Additions Changes
at charged to add Balance
beginning costs and (deduct) at end
Description of period expenses Retirements (Note a) of period
Year Ended:
December 31, 1993
Accum. deprec.
and depletion:
Utility plant $ 533,216 $ 46,248 $ 11,766 $ 4,443 $ 572,141
Entech property 163,185 31,653 10,008 (2,701) 182,129
Independent
Power Group 15,090 2,200 468 16,822
Total $ 711,491 $ 80,101 $ 22,242 $ 1,742 $ 771,092
December 31, 1992
Accum. deprec.
and depletion:
Utility plant $ 495,720 $ 43,626 $ 10,943 $ 4,813 $ 533,216
Entech property 144,691 33,248 12,291 (2,463) 163,185
Independent
Power Group 11,633 1,939 (240) 1,278 15,090
Total $ 652,044 $ 78,813 $ 22,994 $ 3,628 $ 711,491
December 31, 1991
Accum. deprec.
and depletion:
Utility plant $ 468,201 $ 41,893 $ 19,329 $ 4,955 $ 495,720
Entech property 124,309 28,246 9,593 1,729 144,691
Independent
Power Group 10,583 1,833 783 11,633
Total $ 603,093 $ 71,972 $ 29,705 $ 6,684 $ 652,044
THE MONTANA POWER COMPANY AND SUBSIDIARIES
SCHEDULE VI - ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION OF
PROPERTY, PLANT AND EQUIPMENT
Thousands of Dollars
1993 1992 1991
NOTES:
(a) Comprises the following:
Provision for depreciation of equipment
charged to clearing accounts and
allocated on the basis of the use of
such equipment $ 2,391 $ 2,357 $ 2,291
Other credits from property relocation and
miscellaneous adjustments 2,273 2,658 1,397
Translation adjustment resulting from
translation of beginning and ending
foreign balances and foreign accruals
at different exchange rates (1,390) (2,664) 37
Accumulated depreciation on assets
transferred from Western and NARCO to
Entech 1,601
Accumulated depreciation on assets acquired
in the purchase of North American Energy
Services Company on November 1, 1992 1,277
Insurance proceeds for damages to the
Madison Plant 1,358
Gain on disposal of property 115
Sale of Special Resource Management (1,892)
Valuation adjustment of Momont property 245
Total $ 1,742 $ 3,628 $ 6,684
THE MONTANA POWER COMPANY AND SUBSIDIARIES
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
Thousands of Dollars
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
Balance
at Charged to Charged to Balance
beginning costs and other at close
Description of period expenses accounts Deductions of period
(Note a)
Year Ended:
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
December 31, 1992
Reserves deducted
in balance sheet
from assets to which
they apply:
Doubtful accounts
Utility $ 628 $ 1,361 $ 1,301 $ 688
Entech 387 345 $ 3 206 529
Total $ 1,015 $ 1,706 $ 3 $ 1,507 $ 1,217
December 31, 1991
Reserves deducted
in balance sheet
from assets to which
they apply:
Doubtful accounts
Utility $ 628 $ 1,278 $ 1,278 $ 628
Entech 395 75 83 387
Total $ 1,023 $ 1,353 $ 1,361 $ 1,015
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.
THE MONTANA POWER COMPANY AND SUBSIDIARIES
SCHEDULE IX - SHORT-TERM BORROWINGS (a)
Thousands of Dollars
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
Maximum Average Weighted
Category of Weighted amount amount average
aggregate Balance average outstanding outstanding interest rate
short-term at end interest during the during the during the
borrowings of period rate period period (b) period (b)(c)
Year Ended:
December 31, 1993
Notes payable to
banks
Utility $ 43,900 3.48% $ 57,200 $ 18,639 4.17%
Entech 8,000 3.65% 22,300 11,070 3.74%
Total $ 51,900 3.51% $ 57,200 $ 29,709 4.01%
Commercial Paper
Utility $ 20,000 $ 6,729 3.46%
Entech $ 16,965 3.50% 21,000 12,401 3.38%
Total $ 16,965 3.50% $ 21,000 $ 19,130 3.41%
December 31, 1992
Notes payable to
banks
Utility $ 34,300 3.90% $ 54,000 $ 11,819 5.07%
Entech 13,000 4.15% 19,900 7,156 4.51%
Total $ 47,300 3.97% $ 54,000 $ 18,975 4.86%
Commercial Paper
Utility $ 16,000 4.22% $ 16,000 $ 5,036 4.89%
December 31, 1991
Notes payable to
banks
Utility $ 48,500 5.41% $ 48,500 $ 9,120 7.64%
Entech 8,800 5.79% 14,000 2,609 7.19%
Total $ 57,300 5.46% $ 48,500 $ 11,729 7.54%
Commercial Paper
Utility $ 43,500 $ 7,686 6.99%
NOTES:
(a) For information pertaining to the general terms of each category of aggregate
short-term borrowings, see Note 8 to the Consolidated Financial Statements.
(b) The average amount outstanding during the period is calculated using a daily
weighted average. The weighted average interest rate during the period is
calculated by dividing the interest expense for the year by the average amount
outstanding.
(c) Includes commitment fees for lines of credit.
THE MONTANA POWER COMPANY AND SUBSIDIARIES
SCHEDULE X - SUPPLEMENTARY INCOME STATEMENT INFORMATION
Thousands of Dollars
1993 1992 1991
Charged to costs and expenses:
UTILITY DIVISION:
Maintenance and repairs $ 38,534 $ 34,239 $ 36,321
Amortization of costs deferred
to future operating periods
(Note a) 8,357 13,792 6,750
Taxes and other than income taxes:
Ad valorem $ 40,438 $ 38,221 $ 35,099
Federal and state social security 5,423 5,196 4,879
Other 5,988 4,311 4,317
Total $ 51,849 $ 47,728 $ 44,295
Royalties $ 2,248 $ 2,060 $ 3,111
ENTECH:
Maintenance and repairs $ 31,701 $ 31,811 $ 31,398
Taxes and other than income taxes:
Ad valorem $ 4,832 $ 4,498 $ 3,860
Federal and state social security 4,421 4,531 3,753
Coal gross proceeds 4,492 5,950 5,117
Federal reclamation fee 5,097 5,824 5,787
Severance 14,693 17,866 17,022
Other 9,041 10,040 8,389
Total $ 42,576 $ 48,709 $ 43,928
Royalties $ 33,750 $ 37,256 $ 29,156
INDEPENDENT POWER GROUP:
Maintenance and repairs $ 3,780 $ 4,541 $ 2,791
Taxes and other than income taxes:
Ad valorem $ 3,689 $ 3,465 $ 3,501
Federal and state social security 2,132 520 207
Other 300 346 334
Total $ 6,121 $ 4,331 $ 4,042
Note a: Certain carrying costs in 1991 related to Colstrip Unit No. 3 have been
reclassified to electric production retirements.
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, 1994
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, 1994
(Chief Executive Officer)
/s/ J. P. Pederson Principal Financial
J. P. Pederson and Accounting Officer March 22, 1994
(Vice President and Chief and Director
Financial Officer)
/s/ J. J. Burke Director March 22, 1994
J. J. Burke
/s/ Alan F. Cain Director March 22, 1994
Alan F. Cain
/s/ R. D. Corette Director March 22, 1994
R. D. Corette
/s/Kay Foster Director March 22, 1994
Kay Foster
/s/ Robert P. Gannon Director March 22, 1994
Robert P. Gannon
/s/ Beverly D. Harris Director March 22, 1994
Beverly D. Harris
/s/ Chase T. Hibbard Director March 22, 1994
Chase T. Hibbard
/s/ Daniel P. Lambros Director March 22, 1994
Daniel P. Lambros
/s/ Carl Lehrkind, III Director March 22, 1994
Carl Lehrkind, III
/s/ James P. Lucas Director March 22, 1994
James P. Lucas
/s/ Arthur K. Neill Director March 22, 1994
Arthur K. Neill
/s/ George H. Selover Director March 22, 1994
George H. Selover
/s/ N. E. Vosburg Director March 22, 1994
N. E. Vosburg
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. 33-64922, 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 10, 1994 appearing on page 41 of The Montana Power
Company's Annual Report on Form 10-K for the year ended December 31, 1993.
PRICE WATERHOUSE
Portland, Oregon
March 28, 1994
EXHIBIT INDEX
Exhibit 3(a)(1)
Restated Articles of Incorporation
Exhibit 3(a)(2)
Amendments to the Restated Articles of Incorporation
Exhibit 4(r)
Seventeenth Supplemental Indenture
Exhibit 12
Statement re computation of ratio of earnings to Fixed Charges
Exhibit 21
Subsidiaries of the registrant