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.


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:
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.
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.
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
Projects Under Development
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
Refer to Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations."
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
PART II
ITEM 5.
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.
ITEM 6. SELECTED FINANCIAL DATA
Income Statement Items (000)
ITEM 7.
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.
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.
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.
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.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
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
The accompanying notes are an integral part of these statements.
CONSOLIDATED BALANCE SHEET The Montana Power Company and Subsidiaries ASSETS
CONSOLIDATED STATEMENT OF CASH FLOWS The Montana Power Company and Subsidiaries
CONSOLIDATED STATEMENT OF COMMON SHAREHOLDERS' EQUITY The Montana Power Company and Subsidiaries
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:
*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:
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 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 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
Operations Information
Operations Information
Assets and Expenditures
SUPPLEMENTARY INFORMATION OIL AND NATURAL GAS PRODUCING ACTIVITIES
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.
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:
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
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.
ITEM 9.
ITEM 9. DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10.


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.
ITEM 11. EXECUTIVE COMPENSATION
Incorporated by reference from Notice of 1994 Annual Meeting of Shareholders and Proxy Statement, pages 9-12.
ITEM 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.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
PART IV
ITEM 14.
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
THE MONTANA POWER COMPANY AND SUBSIDIARIES SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT (INCLUDING INTANGIBLES) Year Ended December 31, 1992 Thousands of Dollars
THE MONTANA POWER COMPANY AND SUBSIDIARIES SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT (INCLUDING INTANGIBLES) Year Ended December 31, 1991 Thousands of Dollars
THE MONTANA POWER COMPANY AND SUBSIDIARIES SCHEDULE VI - ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT Thousands of Dollars
THE MONTANA POWER COMPANY AND SUBSIDIARIES SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES Thousands of Dollars
THE MONTANA POWER COMPANY AND SUBSIDIARIES SCHEDULE IX - SHORT-TERM BORROWINGS (a) Thousands of Dollars
THE MONTANA POWER COMPANY AND SUBSIDIARIES SCHEDULE X - SUPPLEMENTARY INCOME STATEMENT INFORMATION Thousands of Dollars
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