Annual Report (Form 10-K), fiscal year 1994

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 and the sale of telecommunication equipment and services. The Company, through its Independent Power Group (IPG) manages long-term power sales, and develops and invests in nonutility power projects and other energy- related businesses. See Item 8, 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 territory comprises 107,600 square miles or approximately 73% of Montana. Within its service territory, 86% of the state's population resides. The Division serves approximately 593,000 residents, or 81% of the population within the service territory. Additionally, energy is provided to cooperatives that serve approximately 72,000 residents. Dominant factors in Montana's diversified economy are agriculture and livestock, which constitute Montana's largest industry, tourism and recreation, coal and metals mining, oil and gas production, and the forest products industry which embraces the production of pulp and paper, plywood and lumber.
Electric service is provided to 191 communities, the rural areas surrounding them and Yellowstone National Park, and natural gas service is provided to 109 communities. Firm electric power is sold at wholesale to two rural electric cooperatives. Natural gas is sold at wholesale or transported to distribution companies in Great Falls, Cut Bank, Shelby, Kevin, Sweetgrass and Sunburst, Montana.
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.
COMPETITIVE ENVIRONMENT: The electric and natural gas industries are currently in a transition to a more competitive market environment. Federal legislation, including the National Energy Policy Act, is intended to promote competition and reduce the level of regulation in the energy supply industry. The Utility Division's electric and natural gas businesses currently are substantially free from direct competition with other suppliers for residential and commercial customers. The Utility Division is subject to, in certain circumstances, increased competition 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.
In February 1995, the Company became a charter member of the Western Regional Transmission Association (WRTA). WRTA is a Regional Transmission Group (RTG), certified by the Federal Energy Regulatory Commission (FERC), formed by its members "to foster the efficient, equitable and reliable use of existing and future transmission facilities and the expeditious and fair resolution of disputes related to transmission access." The Company has also been involved in the formation of another RTG, the Northwest Regional Transmission Association (NRTA). The Company expects that NRTA will be certified by FERC in 1995 and that it will become a member.
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. 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.
The PSC issued an order approving electric and natural gas rate increases for the Company totaling $13,500,000 annually effective April 28, 1994. This order allowed the Company a $7,800,000 annual electric rate increase, down from the interim increase of $8,800,000 and an annual natural gas rate increase of $5,700,000, up from the interim increase of $4,000,000. In its updated application, the Company had requested general rate increases of $37,600,000 annually for electricity and natural gas based upon a 12.25% return on common equity.
The order reduced the Company's authorized return on common equity from 12.1% to 11.0% for both the electric and natural gas utilities. Of the $24,100,000 difference between the requested amount and allowed increases, $11,100,000 is attributable to the lower return on common equity. Another $7,000,000 of the difference is attributable to the disallowance of certain fuel expense on coal sales from the Company's subsidiary, Western Energy Company, to the Utility Division. The remaining differences relate primarily to the denial of the Company's request to begin recovery of previously flowed through tax timing differences and does not affect net income.
On June 17, 1994, the Company filed a complaint requesting the District Court, Butte-Silver Bow County, to set aside that portion of the PSC's decision disallowing the portion of the fuel expense and remand the coal cost issue to the PSC for a redetermination. On December 29, 1994, the District Court ruled that the PSC is entitled to choose the method by which coal costs are determined for inclusion in rates. Legislation was introduced into the 1995 session of the Montana Legislature to require the PSC to use a market price approach for determining the amount of coal costs to be included in rates. On March 17, 1995, the bill was signed into law by the Governor.
In August 1993, the Company filed an allocated cost of service and rate design docket with the PSC requesting that the portion of total electric revenues collected from various customer classifications be changed to more appropriately reflect the cost of providing service to these customers. The filing proposed an 8.16% reduction in average industrial rates, which would be offset by increased revenues collected from other customer classifications. In its final order dated June 17, 1994, the PSC refrained from deciding several contested issues central to the allocation of costs to customer classes. Instead, the PSC strongly encouraged the parties to come together in a collaborative effort to settle, or at least narrow, their differences. That collaborative effort is in progress, and is expected to be completed in time for the results to be used in a new allocated cost of service and rate design filing expected in the fourth quarter of 1995. In the interim, rate designs remain largely unchanged.
On August 22, 1994, the Company filed with the PSC, and has since updated, a request for an increase in annual electric revenues of $24,700,000 representing a 7.4% increase. The request is based upon a 12.75% return on common equity and continues to seek a market price approach for determining the amount of coal costs allowed to be collected in rates. A 1% change in the return allowed on common equity would result in a change of approximately $7,000,000 in annual electric revenues. The Company's interim rate increase request of $16,700,000 was considered by the PSC in November and an interim rate increase of $7,700,000 was granted effective November 28. The interim increase was based on an 11% return on common equity and included a $5,700,000 coal cost disallowance. A proposed settlement between the Company and the Montana Consumer Counsel, which would provide a $13,800,000 annual increase was reached on March 8, 1995. The settlement is now under consideration by the PSC. Final orders are anticipated no later than May 1995.
Natural gas rates changed on December 13, 1994, reflecting a net increase of $4,000,000 in annual revenues. This net increase reflected: 1) The Company's annual deferred gas cost accounting filing. The Company, on an annual basis, is allowed to submit its actual natural gas supply costs and related revenues as a basis for rate adjustments: and 2) The Gas Transportation Adjustment Clause (GTAC) net balance. The GTAC mechanism tracks the difference between estimated interruptible transportation (IT) revenues and the actual IT revenues received. The bulk of the $4,000,000 increase was created by the completion of the deferred gas cost balance and GTAC net balance amortizations from the 12-month tracking period ending in August, 1993, as approved in last year's gas tracking filing in November, 1993, for amortization in the subsequent 12 months. This rate change did not affect the Company's overall net income.
Central Montana Electric Power Cooperative, Inc. (Central) manages the contract for purchases of power from the Utility Division by a group of Montana coops. During 1994, Central purchased 4% of the total energy sold by the Utility Division. On an annual basis the Company prepares and analyzes the cost of service associated with providing this wholesale service to Central. During 1994, the Company prepared a cost of service based on 1993 FERC Form 1 actual data, modified for known and measurable changes. Following presentation of the 1993 data, the Company and Central Montana negotiated a zero rate adjustment for the 1994 rate period and agreed to continue the annual rate review/adjustment process.
ELECTRIC UTILITY OPERATIONS: The maximum demand on the resources in 1994 was 1,468,000 kW on February 7, 1994. Total firm capability of the Utility's electric system for 1994 was 1,601,000 kW. Of this capability, 1,186,000 kW was provided by the Utility's generating facilities, and 415,000 kW was provided by firm Electric Utility power purchases and exchange arrangements. The Electric Utility's 1994 reserve margin, as a percentage of maximum demand, was 9%.
Increases in peak capability will be met with a combination of resources including upgrades to hydroelectric and thermal facilities, both short- and long-term purchase contracts and Demand Side Management. 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 (RFP), a variety of projects, including some proposed by the Company have been evaluated under a 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 the Utility's hydroelectric facility at Thompson Falls. In addition, the Utility is continuing to decrease energy and peak demand by investing in demand-side management programs. In 1994, the Company went out for its second RFP for resources. Evaluation of the responses is ongoing and will be complete during the first half of 1995. The results of this analysis will be part of the Electric Utility's 1995 integrated least cost plan filing with the Montana Public Service Commission. ITEM 1. BUSINESS (Continued)
During the year ended December 31, 1994, the sources of the Utility Division electric supply were: hydro, 27%; coal, 44%; and purchased power, 29%. Hydroelectric generation decreased 16% due to lower stream flows in 1994, partially offset by an 8% increase in steam generation. The cost of coal burned has been as follows:
Year Ended December 31 1994 1993 1992
Average cost per million Btu's. . . . . . $ 0.66 $ 0.65 $ 0.65 Average cost per ton (delivered). . . . . 11.24 11.16 11.30
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 68 member systems and 10 affiliates in the 14 western states, British Columbia, Alberta and Mexico to assure reliability of operations and service to their customers; is one of 64 members of the Western Systems Power Pool, organized to enhance the economics of power production and reliability of service among the western states power systems; and is a party to the Intercompany Pool Agreement for the coordination of load, resource and transmission planning, operations and reserve requirements among eight utilities in Washington, Oregon, Idaho, Montana, Wyoming, Nevada and Utah. The Company participates in an interconnection agreement with The Washington Water Power Company, Idaho Power Company, and PacifiCorp, providing for the sharing of transmission capacity of certain lines on their respective interconnected systems. The Company also operates, in coordination with its own transmission lines and facilities, the transmission lines and facilities which are jointly owned by the utility owners of the four Colstrip generating units. The Company and the Western Area Power Administration have transmission interconnection and agreements which provide for the mutual use of excess capacity of certain lines on each party's system for the transmission of power east of the Continental Divide in Montana and for the firm use of certain of the Company's transmission lines to deliver government power.
NATURAL GAS UTILITY OPERATIONS: Natural gas supply requirements in 1994 totaled 19,594 Mmcf, of which 12,537 Mmcf were from Montana and 7,057 Mmcf from Canada. The Gas Utility produced 40% of the Montana natural gas and its Canadian subsidiaries produced 62% of the Canadian natural gas.
The Company implemented open access gas transportation on November 1, 1991. As of September 1993, substantially all eligible customers were acquiring 100% of their gas supplies directly from other suppliers. The Gas Utility transports gas supplies for these customers. The total volumes of natural gas transported were 23,700 Mmcf, 17,900 Mmcf and 15,100 Mmcf for 1994, 1993 and 1992, respectively.
Total 1995 natural gas requirements, estimated to be 21,600 Mmcf, are anticipated to be supplied from existing reserves and purchase contracts. Approximately 13,100 Mmcf of these requirements are expected to be obtained in the United States and 8,500 Mmcf from Canada. The Gas Utility expects to produce 45% of the Montana natural gas. Its Canadian subsidiaries are expected to produce 60% of the Canadian natural gas. The 1995 transportation volumes are anticipated to be 28,961 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, Inc. (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), owns 75% of a patented coal enhancement process and a subsidiary of Northern States Power owns 25% of this patented coal enhancement process and each own 50% of the Rosebud SynCoal Partnership. The Partnership owns and operates a coal enhancement 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 94% 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 (NARCO) and in Canada through both Altana Exploration Company (Altana) and Roan Resources, Ltd. (Roan). Entech's telecommunication business is conducted through TRI Touch America, Inc. 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. The mine's principal customers are the owners of the four mine-mouth Colstrip units and the Utility Division's Corette Plant located at Billings, Montana. These customers purchased approximately 71% of the 1994 production. Most of the remainder is sold to Midwestern customers located in Michigan, Minnesota, North Dakota and Wisconsin.
During 1994, Western mined and sold 13,717,418 tons, of which 3,787,318 tons were sold to the Company. Western's Colstrip production is estimated to be 12,300,000 tons in 1995 and 10,300,000 tons in 1996. Future production is reduced as a result of the non-renewal of a contract with a Midwestern customer at year-end 1994 and the anticipated non-renewal of contracts with another Midwestern customer and the Corette Plant at year-end 1995. Western has experienced strong competition from southern Powder River Basin producers, primarily those in Wyoming, for its Midwestern coal sales, which represent approximately 23% of Western's total sales. In December 1994, Western lost a contract with a Midwestern customer because of a market price reopener. While Western has a per-ton rail rate advantage to some of the upper Midwest markets, Wyoming producers generally experience lower stripping ratios, royalties 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 1994, a record production year, were 8,627,923 tons. The estimated production for 1995 and 1996 is 8,100,000 and 7,700,000 tons, respectively. Future production is reduced as a result of the two generating units returning to normal levels of demand plus planned maintenance outages.
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 prior to sale. Total deliveries from the mine, which has a current capacity to produce 2,000,000 tons annually, were 1,076,321 tons during 1994. In July 1994, Basin began delivering coal under a long-term contract to supply up to 1,200,000 tons annually to a southeastern utility. A portion of Basin's production supplies short-term sales to industrial and utility customers. The mine experienced unanticipated production problems in both the mining and the wash plant operations during 1994. These production problems are being addressed and management expects resolution of them in 1995. Estimated production for 1995 and 1996 is 1,400,000 and 1,900,000 tons, respectively. For further discussion of Basin's production problems, see Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operation" under "Entech Coal Operations."
OIL AND GAS OPERATIONS: NARCO's producing oil and natural gas properties are principally located in the states of Wyoming, Colorado, Kansas, Oklahoma and Montana. Altana and Roan's properties are principally located in the Province of Alberta, Canada.
NARCO has entered into agreements to supply 138,000 Mmcf of natural gas to four cogeneration facilities over periods of 10 to 16 years with performance guaranteed by Entech. NARCO has sufficient proven, developed and undeveloped reserves to supply all of the remaining natural gas required by those agreements. None of the reserves are dedicated to supply these agreements. 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. Approximately 30,000 Mmcf, or one-third of Altana and Roan's natural gas reserves, are dedicated to long-term contracts expiring at various times through 2005.
Through its subsidiary Entech Altamont, Inc., (a single purpose subsidiary), Entech owns a minority interest in a joint venture to construct the proposed Altamont pipeline. In 1991, Altamont received FERC approval to construct a 620 mile pipeline running from the Alberta-Montana border to Muddy Creek, Wyoming. The decision to proceed with the construction of this pipeline will depend upon obtaining the necessary regulatory approval and shipper commitments.
INDEPENDENT POWER GROUP:
GENERAL: The Independent Power Group (IPG), which consists of Continental Energy Services, Inc. (CES) and Colstrip 4 Lease Management Division, manages sales of the Company's 210 megawatt share of Colstrip Unit 4 generation to the Los Angeles Department of Water and Power and to Puget Sound Power & Light Company (Puget) under contracts which are coextensive with the Company's leasehold interest in the Unit. See Item 3, "Legal Proceedings" for additional information pertaining to the Puget Contract.
Through CES, the IPG has invested in six operating, natural gas fired, independent power projects located in Texas, New York, Washington and the United Kingdom, two independent power projects under construction in Texas and Washington and another under development in China. CES also participates with several partners in several nonutility electric generation development efforts and peak shaving facilities by providing funding and project development expertise. This participation includes domestic as well as foreign projects.
In August 1994, CES sold 50% of its wholly-owned subsidiary, North American Energy Services Company (NAES), which it acquired in November 1992, to Illinova Generating Company. NAES 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, 1994, the Company and its subsidiaries employed 3,686 persons of which 2,290 were utility and Office of the Corporation employees (including 569 employees at the jointly owned Colstrip Units 1-4), 9 Independent Power Group employees and 1,387 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:
Corporate Officers:
In 1992, D. T. Berube, 61, 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, 52, was elected Vice President and Chief Financial Officer. He served as Vice President Corporate Finance 1990-1991.
In 1993, P. K. Merrell, 42, was elected Vice President and Secretary. She served as Staff Attorney 1981-1991, Assistant Secretary 1991-1992, and Secretary 1992-1993.
In 1991, M. E. Zimmerman, 46, was elected Vice President and General Counsel. He served as General Counsel from 1989-1991.
Utility Division Officers:
In 1990, R. P. Gannon, 50, was elected President and Chief Operating Officer - Utility Division.
In 1993, A. K. Neill, 57, 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, 49, 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, 50, 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, 58, 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, 60, was elected Vice President - Colstrip Project Division for the Utility Division.
In 1993, W. C. Verbael, 57, was elected Vice President - Accounting, Finance and Information Services. He had previously served as Vice President - Accounting and Finance for the Utility Division since 1984.
In 1993, P. J. Cole, 37, was elected Treasurer for the Utility Division. He served as Manager, Corporate Financial Planning and Analysis 1986-1992, and as Assistant Treasurer 1992-1993.
In 1990, J. S. Miller, 51, was elected Controller for the Utility Division.
Entech Officers:
In 1992, J. J. Murphy, 56, was elected President and Chief Operating Officer - Entech, Inc. He served as President and Chief Operating Officer, Western Energy and Northwestern Resources Co., 1988-1991.
In 1985, E. M. Senechal, 45, was elected Vice President and Treasurer - Entech, Inc.
Independent Power Group Officer:
In 1992, R. F. Cromer, 49, 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 Utility of 697,000 kW, and 12 hydroelectric projects, with total 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 Utility owns 319,000 kW, and (3) the 160,000 kW Corette Plant. Substantially all of the Utility'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 diverse sources of thermal generation.
In addition to the Utility's hydroelectric and thermal resources, it currently receives power through 21 power contracts totaling 415,000 kW of firm winter peak capacity. These contracts vary in type, size, seller and ending dates. The Utility has one energy contract ending in 1995 for the delivery of up to 10,000 kW of power to the Utility during the off-peak hours.
Hydroelectric projects are licensed by the FERC under licenses which expire on varying dates from 1995 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."
At December 31, 1994, the Utility owned and operated 6,890 miles of transmission lines and 15,073 miles of distribution lines.
NATURAL GAS PROPERTIES: The Utility produces natural gas from fields in Montana and Wyoming and through its subsidiary, Canadian-Montana Gas Company, from fields in southeastern Alberta, Canada. Natural gas is also purchased from independent producers in Montana and Alberta.
All of the Utility's natural gas customers are served from its transmission system which extends through the western two-thirds of Montana. System reliability is enhanced by four natural gas storage fields which enable the Utility to store natural gas in excess of system load requirements during the summer for delivery during winter periods of peak demand.
At December 31, 1994, the Gas Utility and its subsidiaries owned and operated 2,034 miles of natural gas transmission lines and 3,075 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 Data."
In addition to owned reserves, the Utility at December 31, 1994, controlled under purchase contracts, 60,604 Mmcf of proven reserves in the United States and 36,190 Mmcf in Canada. No significant change has occurred and no event has taken place since December 31, 1994, that would materially affect the magnitude of the Utility's reserve estimates.
Utility natural gas reserve estimates have not been filed with any other federal or any foreign governmental agency during the past twelve months. Certain lease and well data, with respect only to owned wells, are filed with the Internal Revenue Service for tax purposes.
Total produced, royalty and purchased natural gas volumes in Mmcf during the last three years were as follows:
United States Canada Produced Royalty Purchased Produced Royalty Purchased
1992 . . . . 5,724 561 8,713 2,951 916 3,443 1993 . . . . 5,587 539 8,554 3,927 1,186 2,824 1994 . . . . 4,742 230 7,565 3,350 998 2,709
The following table presents information as of December 31, 1994, concerning the Utility natural gas wells and the owned or leased acreages in which they are located.
United States Canada
Gross productive wells. . . . . . . . . . 610 173 Net productive wells. . . . . . . . . . . 499 162 Gross wells with multiple completions . . 18 11 Net wells with multiple completions . . . 12.8 10.5
Gross producing acres . . . . . . . . . . 457,145 194,392 Net producing acres . . . . . . . . . . . 296,759 171,798 Gross undeveloped acres . . . . . . . . . 63,344 45,280 Net undeveloped acres . . . . . . . . . . 53,227 44,320
These acreages are located primarily in Montana and Alberta, Canada.
The Company anticipates that during 1995 total exploration and development expenditures (expense and capital) will be approximately $2,114,000 in the United States and approximately $1,735,000 in Canada.
The following table presents information on utility natural gas exploratory and development wells drilled during 1994, 1993 and 1992.
United States Canada 1994 1993 1992 1994 1993 1992
Net productive exploratory wells. . . . . . . . . . . . - - - - - - Net dry exploratory wells. . . - - - - - - Net productive development wells. . . . . . . . . . . . 14.38 12.25 6.38 6.00 3.00 - Net dry development wells. . . 4.00 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 1994, 1993 and 1992. Revenues per Mcf are computed based on volumes at varying pressure bases as billed.
Year Ended December 31 Customer Classification 1994 1993 1992
Residential. . . . . . . . . . . . . . . $ 4.64 $ 4.35 $ 4.22 Commercial . . . . . . . . . . . . . . . 4.43 4.20 3.91 Industrial . . . . . . . . . . . . . . . 4.25 4.02 3.76 Other gas utilities. . . . . . . . . . . 3.72 3.38 3.33
The following table presents the average production cost per Mcf for produced utility natural gas, in U. S. dollars, for the three years 1994, 1993 and 1992.
United States Canada
1992. . . . . . $ 0.84 $ 0.38 1993. . . . . . 0.97 0.36 1994. . . . . . 1.07 0.40
Production cost per unit fluctuated over the three-year period primarily as a result of expensing fixed costs over varying levels of production.
ENTECH:
COAL PROPERTIES: Western leases and produces coal from Montana and Wyoming properties. Northwestern leases and produces lignite from properties in Texas and leases coal properties in Wyoming. Basin produces coal from properties in Colorado that North Central owns and leases. 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 551,000,000 proved and probable, and recoverable tons of surface-minable coal reserves averaging less than 0.9 pounds of sulfur per million Btu (low-sulfur quality) at Colstrip. Approximately 264,000,000 tons of these reserves are committed to present contracts, including requirements of the Colstrip Units.
Northwestern has lignite mining leases in central Texas at the Jewett Mine covering approximately 237,000,000 proved and probable, and recoverable tons of surface-minable lignite reserves. Northwestern has contracted all of these reserves to Houston Lighting and Power Company, which owns two electric generating units located adjacent to the mine.
In 1990, Northwestern acquired surface rights and coal leases which contain approximately 628,000,000 proved and probable, and recoverable tons of surface-minable, coal reserves, averaging less than 0.6 pounds of sulfur per million Btu (compliance quality), 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, surface minable, 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 January 1, 2003. A permit application was submitted to the Wyoming Department of Environmental Quality on November 7, 1994. Northwestern expects to receive a mine permit by the second quarter of 1996. No definite plans for mine development have been made.
North Central owns and leases lands containing approximately 98,600,000 tons of proved and probable, and recoverable, compliance quality underground-minable coal reserves near Trinidad, Colorado. Approximately 32,000,000 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-minable lignite, under lease. Those in southeastern Alabama contain approximately 97,000,000 proved and probable, and recoverable tons of surface-minable 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-minable lignite.
OIL AND NATURAL GAS PROPERTIES: No significant change has occurred and no event has taken place since December 31, 1994, 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 Data."
Entech's oil and natural gas volumes are at a pressure base of 14.73 psia at 60 degrees Fahrenheit.
Entech's oil and natural gas reserve estimates have not been filed with any other federal or any foreign government agency during the past 12 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 1994, 1993 and 1992.
Natural gas production was converted to barrel of oil equivalents based on a ratio of 6 Mcf to 1 barrel of oil.
Entech's oil, natural gas and natural gas liquids production was sold under both short- and long-term contracts at posted prices or under forward market arrangements. From 1993 to 1994, 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 lower production taxes per barrel of oil equivalent due to lower revenues received and lower operating expenses.
Information on Entech's natural gas and oil wells and the owned or leased acreages in which they are located, as of December 31, 1994, is presented below.
United States Canada
Gross productive natural gas wells 379 184 Net productive natural gas wells 232.03 121.31 Gross productive oil wells 247 209 Net productive oil wells 160.56 119.08
Gross producing acres 127,675 191,439 Net producing acres 58,752 96,805 Gross undeveloped acres 260,410 202,764 Net undeveloped acres 126,028 125,288
The wells located in Canada include multiple completions of 12 gross productive natural gas wells and 9.81 net productive gas wells.
The foregoing acreages located in the United States and Canada are primarily in the Rocky Mountain states and Alberta.
It is anticipated that during 1995 total exploration, acquisition and development expenditures (expense and capital) will be approximately $26,895,000 in the United States and approximately $10,814,000 in Canada.
The following table presents information on Entech's oil and natural gas exploratory and development wells drilled during 1994, 1993 and 1992.
For information on properties acquired, see Item 8, "Supplementary Data."
INDEPENDENT POWER GROUP:
The IPG manages the sale of power from the Company's 210 MW Colstrip 4 leased interest and associated common and transmission facilities. The IPG also has ownership or contract rights in a number of nonutility power generation projects:
Projects in Operation:
ITEM 3.

ITEM 3. LEGAL PROCEEDINGS
The Company, through the IPG, sells 94 MW of electricity to Puget Sound Power & Light Company (Puget) under a 25-year agreement which expires in 2010 (the Agreement). On February 27, 1995, Puget notified the Company of its intention to terminate the Agreement, effective the next day, alleging the Company had failed to satisfy a requirement to secure firm contractual rights to transmission paths for the delivery of the electricity.
If Puget establishes its right to terminate the Agreement, the Company would be at risk for the difference between the power purchase price under the Agreement, approximately 4.6 cents/kWh ($29,000,000 in revenue) for the current contract year and escalating annually thereafter, and the prices it might receive from future sales of the electricity. In addition, the Company would be obligated to reimburse Puget approximately $37,000,000 for the amount by which Puget's payments for the electricity have exceeded its projection of avoided costs. This reimbursement obligation would peak at approximately $47,000,000 by the end of 1995 and would be reduced to zero by the end of the Agreement's term in 2010. The Company also may be required to make a non-cash adjustment to its accounting records reducing an asset related to the Agreement by an amount currently estimated to be approximately $20,000,000, pre-tax.
The Company believes that is has performed its obligations under the Agreement and that Puget has no basis for termination. On February 28, 1995, the Company obtained, from a Montana district court, a temporary restraining order enjoining Puget from terminating the Agreement. A hearing has been set for March 15, 1995 to determine whether a preliminary injunction should be issued. The Company also has filed with that court a complaint for a declaratory ruling that it has complied with the Agreement and that Puget has no basis for termination. The Company will seek to enforce the Agreement and to obtain damages for any breach; however, it cannot predict the outcome of this controversy.
Refer to Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations - Environmental Issues" for additional information pertaining to legal proceedings.
Refer to Item 8, "Financial Statements and Supplementary Data - Note 2 to the Consolidated Financial Statements" for additional information pertaining to legal proceedings.
The Company and its subsidiaries are party to various other legal claims, actions and complaints arising in the ordinary course of business. Management does not expect disposition of these matters to have a material adverse effect on the Company's consolidated results of operations.
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 1994 and 1993. The number of common shareholders of record on December 31, 1994, was 40,956.
Dividends Declared per 1994 High Low Share
1st quarter $ 25.875 $ 23.250 $ 0.40 2nd quarter 25.000 22.125 0.40 3rd quarter 24.625 21.750 0.40 4th quarter 24.000 22.250 0.40
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
ITEM 6.

ITEM 6. SELECTED FINANCIAL DATA
ITEM 6. SELECTED FINANCIAL DATA
Income Statement Items (000) 1994 1993 1992
Income Statement Items (000) 1991 1990 1989
ITEM 7.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Results of Operations:
The Company's net income available for common stock increased to $106,365,000 in 1994 compared to $102,858,000 and $103,275,000 in 1993 and 1992, respectively. The following discussion presents significant events or trends which have had an effect on the operations of the Company during the years 1992 through 1994. Also presented are factors which are expected to have an impact on operating results in the future.
Net Income Per Share of Common Stock:
Although net income available for common stock increased $3,507,000, the net income per share increase was moderated by additional outstanding shares. The following table shows the sources of consolidated net income on a per share basis.
1994 1993 1992
Utility Operations $ 0.91 $ 1.07 $ 0.97 Entech 0.90 0.91 0.98 Independent Power Group 0.19 - 0.07
$ 2.00 $ 1.98 $ 2.02
Consolidated net income per share for 1994 increased due to sharply higher Independent Power Group (IPG) earnings resulting from power project development revenues and improved performance by the Colstrip units. Despite higher revenues resulting from rate increases, growth in the number of customers, increased industrial electric loads and improved Colstrip units performance, Utility Division earnings were lower due to less favorable hydroelectric generation and wholesale market conditions, increased property taxes, an increased regulatory disallowance on coal purchases and warmer weather. Entech earnings were comparable to 1993. A 1993 non-recurring gain on the sale of an Entech Oil Division's non-strategic asset and continuing losses at Entech's underground mine in Colorado, where production problems are being addressed, were offset by increased coal sales from mines in Montana and Texas.
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 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 independent power project development revenues.
Utility Operations:
Weather can significantly affect revenues and net income, and should be considered when determining trends. The Company's sales increase as a result of colder weather in the winter months. As measured by heating degree days, the weather in 1994 in the Company's service territory was 13% warmer than 1993 and 6% warmer than normal. The weather in 1993 was 17% colder than 1992 and 8% colder than normal.
Electric Utility:
The following table shows year-to-year changes for the previous two years, in millions of dollars, in the various classifications of electric revenues (excluding intersegment revenues) and the related percentage changes in volumes sold and prices received:
1994 1993
General business - revenue $ 11 $ 9 - volume 3% 3% - price/kWh - -
Other utilities - revenue $ (9) $ 11 - volume (6%) 5% - price/kWh (5%) 10%
Miscellaneous - revenue $ (1) $ 4
1994 Compared to 1993
Income from electric operations decreased $14,500,000 due primarily to the less favorable hydroelectric generation and wholesale market conditions partially offset by higher rates and growth in customers.
Revenues:
Electric sales from general business customers increased $11,500,000 including an increase of $5,800,000 in revenues from industrial customers. Industrial revenues increased due to a 5% increase in volumes sold, primarily the result of additional equipment installed by several customers and demand for irrigation because of dry summer weather. Growth in residential and commercial customers and higher rates also contributed to the increase in revenues. These increases were moderated by volume decreases resulting from the warmer winter weather.
Electric revenues from sales to other utilities decreased $5,100,000 due to a reduction in volumes and $4,300,000 due to a decrease in average price. The decreases resulted from wholesale market conditions returning to near- normal compared with better than average conditions experienced during the first and fourth quarters of 1993.
Miscellaneous electric revenues decreased $1,100,000 primarily due to reduced wheeling revenues resulting from the previously discussed change in wholesale market conditions.
Intersegment revenues decreased $1,600,000 due primarily to lower volumes sold to the IPG.
Expenses:
The following table shows the Company's sources of electricity and power supply expenses (Operation, Fuel for electric generation, and Maintenance) for 1994 and 1993.
1994 1993 Sources Megawatt Hours
Hydroelectric. . . . . . . . . . . . . . . 2,999,396 3,560,915 Steam. . . . . . . . . . . . . . . . . . . 4,909,852 4,542,100 Purchases. . . . . . . . . . . . . . . . . 3,193,522 3,186,025
Total Power Supply . . . . . . . . . . . 11,102,770 11,289,040
Expenses Thousands of Dollars
Hydroelectric. . . . . . . . . . . . . . . $ 18,395 $ 18,092 Steam. . . . . . . . . . . . . . . . . . . 61,385 57,876 Purchases. . . . . . . . . . . . . . . . . 99,147 96,222
Total Power Supply Expenses. . . . . . . $ 178,927 $ 172,190
Cents per Kilowatt-Hour. . . . . . . . . 1.612 1.525
Steam generation and related fuel expense increased as a result of improved performance at the Colstrip units which experienced outages in 1993. Purchased power costs increased as a result of a 3% increase in average price paid. Total power supply cost increased as a result of this price increase and a change in the mix of the Utility's sources of energy. In 1994, a larger portion of power supply was provided by steam generation which is incrementally more expensive than hydroelectric generation.
The increase in selling, general and administrative results primarily from a $1,800,000 increase associated with the recognition of postretirement benefit expense in accordance with SFAS No. 106 commensurate with the approval of rate treatment for this expense by the PSC in April 1994, a $500,000 increase related to insurance for postemployment disability-related benefits and a $600,000 increase due to the costs associated with Colstrip housing damages.
The $3,200,000 increase in taxes - other than income taxes is principally due to increased property taxes resulting from property additions and higher mill levies.
Depreciation and amortization expense increased $1,500,000 as a result of depreciation of additional plant and property in service.
1993 Compared to 1992
Income from electric operations increased $8,000,000 primarily as a result of increased sales to other utilities resulting from better than normal market conditions, increased sales to general business customers due to colder weather and increased hydroelectric generation caused by higher stream flows.
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 $11,400,000. Volumes increased 5% and unit prices increased 10% providing additional revenues of $4,000,000 and $7,400,000, 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.
The $4,300,000 increase in miscellaneous electric revenues resulted primarily from a $2,500,000 increase in wheeling revenues and a $2,300,000 increase due to recording the SFAS No. 87 pension cost funding difference which is explained further in the expense discussion below.
Intersegment revenues increased due to increased sales to the IPG resulting from the reduction in the IPG's steam generation at Colstrip due to the outages.
Expenses:
The following table shows the Company's sources of electricity and power supply expenses (Operation, Fuel for electric generation, and Maintenance) for 1993 and 1992.
1993 1992 Sources Megawatt Hours
Hydroelectric. . . . . . . . . . . . . . . 3,560,915 2,793,974 Steam. . . . . . . . . . . . . . . . . . 4,542,100 5,176,130 Purchases. . . . . . . . . . . . . . . . . 3,186,025 2,833,388
Total Power Supply . . . . . . . . . . . 11,289,040 10,803,492
Expenses Thousands of Dollars
Hydroelectric. . . . . . . . . . . . . . . $ 18,092 $ 17,384 Steam. . . . . . . . . . . . . . . . . . . 57,876 59,563 Purchases. . . . . . . . . . . . . . . . . 96,222 89,748
Total Power Supply Expenses. . . . . . . $ 172,190 $ 166,695
Cents per Kilowatt-Hour. . . . . . . . . 1.525 1.543
The Company's hydroelectric output increased as a result of improved stream flows, 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 outages.
Transmission and distribution expense increased $4,200,000 primarily as a result of increased wheeling expense associated with higher volumes of out- of-state sales and increased maintenance of the transmission and distribution system.
The $4,600,000 increase in selling, general and administrative resulted principally from a $2,600,000 increase in pension costs and expenses of $1,600,000 related to property damages to homes at Colstrip. The Utility recovers pension expense for regulatory purposes on a funding basis. In 1993, pension costs funded were less than SFAS No. 87 pension expense and the difference of $1,900,000 was recorded as miscellaneous operating revenue.
The $2,800,000 increase in taxes - other than income taxes is principally due to increased property taxes resulting from property additions and higher mill levies.
Depreciation and amortization expense increased $2,000,000 as a result of depreciation of additional plant and property in service.
Natural Gas Utility:
The following table shows year-to-year changes for the previous two years, in millions of dollars, in the various classifications of natural gas revenues (excluding intersegment revenues) and the related percentage changes in volumes sold and prices received:
1994 1993 Revenues (other than gas supply cost revenues) Full requirement Customers -revenue $ (3) $ 7 -volume (13%) 4% -price/Mcf 11% 6%
Transportation -revenue $ 3 $ 2 -volume 32% 19% -price/Mcf 26% 35%
Miscellaneous -revenue $ 1 $ 1
1994 Compared to 1993
Income from natural gas operations decreased $1,400,000 primarily due to decreased volumes resulting from warmer weather and increases in expenses other than gas supply costs the effects of which were moderated by higher rates.
Revenues:
Effective September 1, 1993 natural gas customers who consume more than 60,000 Mcfs annually (non full-requirements customers) are no longer required to purchase any portion of their natural gas supply from the Company. All but one eligible customer have chosen to convert their volumes to transportation service only and have secured their own supply. The resulting decline in natural gas revenue has been offset by revenues from transportation fees and lower purchased gas costs.
Natural gas revenues (other than gas supply cost) increased $1,300,000. Growth in the number of residential and commercial customers, higher rates and increased transportation fees contributed $13,200,000. This increase was mostly offset by an approximately $11,800,000 decrease due to warmer weather and the previously discussed switch by eligible customers to transportation service only.
Gas supply cost revenues consist of the amount authorized by the PSC to be collected in rates from full requirement customers to cover the cost of supplying the gas. The $4,900,000 decrease in gas supply cost revenues is the result of reduced volumes sold due to warmer weather and a supply cost rate reduction for overcollections of supply costs in prior years. Gas supply cost revenues and gas supply cost expenses are always equal due to rate and accounting procedures adopted by the PSC in January 1980.
Expenses:
The decrease in gas supply costs results from the reasons mentioned in the gas supply cost revenue discussion.
As presented in the electric expense discussion, the $900,000 increase in selling, general and administrative results primarily from increased costs associated with the recognition of postretirement benefit expense in accordance with SFAS No. 106 and insurance for postemployment disability- related benefits.
Also as previously discussed, the $1,000,000 increase in taxes - other than income taxes is principally due to increased property taxes resulting from property additions and higher mill levies.
1993 Compared to 1992
The $8,600,000 increase in income from natural gas operations results primarily from increased volumes sold to full requirement general business customers due to colder weather and an increase in the number of customers.
Revenues:
Natural gas revenues (other than gas supply cost revenues) increased $10,300,000. Volumes sold to residential and commercial customers increased 19% primarily as a result of 17% colder weather and a 4% increase in the number of customers. The volume increases along with higher rates and increased transportation fees increased revenues approximately $14,600,000. These increases were partially offset by the decrease resulting from a 53% reduction in volumes sold to industrial, government and municipal and other utility customers who switched to transportation service only.
The $2,900,000 increase in gas supply revenues resulted from the increase in volumes delivered to full requirement customers resulting from colder weather and more customers.
Expenses:
The increase in gas supply costs results from the reasons mentioned in the above gas supply cost revenue discussion.
Other production, gathering and exploration expense decreased $2,000,000 due to decreased operation and maintenance costs and the capitalization of future use gas well expenses.
The $1,100,000 increase in selling, general and administrative resulted principally from an increase in labor costs.
The $1,300,000 increase in taxes - other than income taxes is principally due to increased property taxes resulting from property additions and higher mill levies.
Interest Expense and Other Income, and Income Taxes:
The decreases in interest expense from 1992 to 1994 are primarily a result of refinancing of long-term debt at lower interest rates. The average cost of debt was 7.84%, 8.34% and 8.48% for 1994, 1993 and 1992, respectively.
Other (income) deductions - net increased $3,100,000 in 1994 due primarily to a non-recurring increase in investment income.
Income taxes changed due primarily to changes in pre-tax income.
Independent Power Group Operations:
In November 1992, the IPG acquired 100% of North American Energy Services Company (NAES) and their operations were included in the Company's financial statements on a consolidated basis throughout the remainder of 1992 and 1993. In August 1994, the IPG sold a 50% interest in NAES and, as a result of the sale, NAES has been included in the Company's operations on the equity basis of accounting as of January 1, 1994.
1994 Compared to 1993
Income from IPG operations increased $14,300,000 primarily due to increased revenues from independent power project development activity, a gain on the sale of NAES and improved performance by the Colstrip generating units. Earnings from development activities in 1995 are not expected to maintain the 1994 levels.
Revenues:
IPG revenues decreased $43,600,000 due to the accounting change for the IPG's investment in NAES as mentioned above. The decrease was partially offset by increases in independent power project development revenues of $12,600,000, management fees of $500,000 and a $4,900,000 increase in revenues from long-term power sales from the Colstrip units due to a 13% increase in volumes sold.
The decrease in earnings from unconsolidated investments results primarily from lower earnings from operating projects. The decrease in intersegment revenues results primarily from the sale of NAES and the resulting change in accounting.
Expenses:
The NAES sale and corresponding accounting change resulted in decreases of $41,500,000 in operation and maintenance expense and $5,300,000 in selling, general and administrative. Operation and maintenance expense was also impacted by a $2,100,000 decrease in wheeling expense, a $2,100,000 decrease in purchased power costs and a $3,000,000 increase in fuel costs due to increased generation at the Colstrip units. Expenses associated with project development increased by $1,600,000 primarily due to the development of two power projects.
Interest Expense and Other Income:
Other (income) deductions - net increased $3,700,000 due principally to increases in interest income and the gain on the sale of 50% of NAES.
1993 Compared to 1992
Income from IPG operations decreased $5,800,000 primarily due to decreased revenues from independent power project development activity and reduced generation from the Colstrip generating units due to outages.
Revenues:
Total IPG revenues increased $30,400,000. The acquisition of NAES resulted in increased revenues of $39,300,000 and income from investments in independent power projects increased $1,300,000. The increases were partially offset by a $6,000,000 reduction in independent power project development revenues and a $3,800,000 decrease resulting from a change in the amount of amortization of the loss on long-term sales.
A $3,800,000 increase in intersegment revenues resulting from the acquisition mentioned previously was partially offset by a $900,000 decrease in sales from the Colstrip generating units.
Expenses:
IPG operation and maintenance expense increased $30,000,000 primarily as a result of a $34,400,000 increase resulting from the acquisition of NAES mentioned above and a $3,000,000 increase in purchased power costs resulting from outages at a Colstrip generating unit. The increases were offset by a $3,500,000 reduction in fuel expense resulting from the Colstrip outages and a $3,000,000 decrease in independent power project development expenses.
Selling, general and administrative expense rose primarily due to a $4,200,000 increase resulting from the acquisition mentioned previously and a $1,000,000 increase due to the accrual of Colstrip housing damage claims.
Liquidity and Capital Resources:
Net cash provided by operating activities was $203,886,000 in 1994 compared to $185,809,000 in 1993 and $227,988,000 in 1992. Cash from operating activities less dividends paid provided 54% of capital expenditures in 1994, 54% in 1993 and 91% in 1992.
The Company's long-term debt as a percentage of capitalization was 36%, 36% and 39% in 1994, 1993 and 1992, respectively. The Company also has entered into long-term lease arrangements and other long-term contracts for sales and purchases that are not reflected on its balance sheet. See Item 8, "Financial Statements and Supplementary Data - Note 3 to the Consolidated Financial Statements" for additional information.
Capital expenditures during the prior three years are as follows:
Years Utility Entech IPG Total Thousands of Dollars
1992 $ 96,352 $ 44,662 $ 19,489 $ 160,503 1993 112,178 66,832 4,542 183,552 1994 150,903 50,253 6,154 207,310
The following table sets forth the Company's estimated capital expenditures for the years 1995-1999:
Years Utility Entech IPG Total Thousands of Dollars
1995 $128,000 $ 81,000 $ 27,000 $ 236,000 1996 158,000 98,000 31,000 287,000 1997 161,000 78,000 25,000 264,000 1998 134,000 70,000 29,000 233,000 1999 135,000 114,000 26,000 275,000
In addition, $153,677,000 of long-term debt will mature during the years 1995-1999. See Item 8, "Financial Statements and Supplementary Data - Note 7 to the Consolidated Financial Statements" for details on maturities of long- term debt.
For the years 1995-1999, the Company estimates that approximately 61% of its utility construction program, 81% of Entech capital expenditures and 37% of IPG investments will be financed from funds generated internally and that the balance, as well as the repayment of 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 anticipates that it will have adequate sources of external capital to meet its financing needs.
Dividends on common and preferred stock increased to $92,009,000 in 1994 from $85,823,000 in 1993 and $82,343,000 in 1992. The Company paid dividends of $1.60 per share of outstanding common stock during 1994, up 1.27% from 1993. In an effort to move toward the Company's target payout ratio for dividends of 70% of earnings, the Board of Directors voted in December to continue the regular quarterly dividend at 40 cents per share of common stock, $1.60 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, "Financial Statements and Supplementary Data - Notes 7 and 8 to the Consolidated Financial Statements."
In January 1994, the Company sold $5,000,000 of Secured Medium-Term Notes, 7.25% series due 2024. The proceeds were used to repay short-term debt incurred to complete the refinancing of $80,000,000 of the 10% and 10-1/8% series Pollution Control Revenue Bonds in December 1993.
In June 1994, the Company sold $20,000,000 of Secured Medium-Term Notes, 7.2% series due 2000, the proceeds of which were used to retire other long- term debt.
In November 1994, the Company sold $10,000,000 of Secured Medium-Term Notes, 7.6% series due 1997 and $10,000,000 of Secured Medium-Term Notes, 7.85% series due 1998, the proceeds of which were used to retire three series of unsecured Medium-Term Notes, $9,000,000 of the 8.78% series due November 1994, $5,000,000 of the 8.57% series due December 1994 and $5,000,000 of the 8.78% series due December 1994.
The Company's Mortgage and Deed of Trust contains certain restrictions upon the issuance of additional First Mortgage Bonds. At December 31, 1994, the unfunded net property additions and retired bonds test, which is the most restrictive test, would have permitted the issuance of approximately $514,000,000 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, 1994, the Company's ratio of earnings to fixed charges was 3.05 times. Fixed charges include interest, the implicit interest of Unit 4 rentals and one-third of all other rental payments.
Inflation:
Capital intensive businesses, such as the Company's electric and natural gas utility operations, are significantly and adversely affected by long-term inflation as neither depreciation nor the ratemaking process reflect the replacement cost of utility plant. Although prices for natural gas may fluctuate, earnings of the Gas Utility are not impacted because a gas cost tracking procedure annually balances gas costs collected from customers with the costs of supplying gas.
Entech's long-term coal contracts and the IPG's long-term power sales contracts provide for the adjustment of prices either through indices, fixed escalations and/or direct pass-through of costs.
The Company believes that the effects of inflation, at currently anticipated levels, will not significantly affect results of operations.
Environmental Issues:
The Company is committed to do its part to protect and maintain the environment. A management function is in place which monitors compliance and keeps management informed regarding the status of compliance.
The Clean Air Act Amendments of 1990 should have 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. The Company has agreed to a new State Implementation Plan required by the Federal Environmental Protection Agency to reduce sulfur dioxide emissions in Billings, Montana. Under the Plan, the Company will reduce its emissions at the Corette Plant from an average of 7,800 tons in 1987-93 to less than 5,000 tons annually. This reduction is expected to be obtained by changing the Plant's fuel to low-sulphur, compliance coal.
Modifications will be required at three units in the late 1990's to meet the nitrogen oxide emission standards of the Act. Phase II rules implementing the Act are subject to legal appeal, challenging their adoption. The Company, therefore, does not yet know what requirements may result from the Phase II Rules. 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 other parties, is a potentially responsible party (PRP) for the release of certain toxic substances which have come to rest behind the dam at the Company's Milltown Hydroelectric Plant. Because of federal legislation specifically relating to Milltown, the Company believes it has no responsibility for any of the alleged releases. If the Company should have some responsibility, it would have to share, together with other responsible parties, the costs related to the handling of these toxic substances. While these costs have not been determined, the Company believes that any portion which it might bear would not have a significant impact upon its earnings.
The Company, along with others, has been named a PRP with respect to the Silver Bow Creek/Butte Area Superfund Site. The alleged contamination is soil and groundwater contamination, for the most part, associated with decades of copper mining in the area. The PRPs have cooperated to summarize the data that currently exists, to evaluate the 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 $650,000 to investigate its property within the site, collect data, evaluate studies and monitor its property. Costs to clean up this contamination, including sums spent in the studies mentioned above, are not expected to exceed $1,000,000.
Other contamination at the Company's property within the site involves heavy metals and substances which may be attributed to mining and activities of others within the greater area of the site. Consultants employed by the PRPs to compile and analyze previously prepared study data regarding the greater area of this superfund site have made preliminary estimates indicating that clean-up costs could range from $20,000,000 to $60,000,000. While the Company denies any responsibility for costs associated with this contamination, if the Company should have some responsibility, it would have to share a portion of the costs ultimately related to the handling of the contamination.
The Company was also a PRP at another 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 Company completed clean-up work at this site in 1994 and has received acceptance of the clean-up from the state agency with jurisdiction over this site. Costs incurred by the Company were approximately $610,000.
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 is an extremely small contributor and liability will be de minimis. At the second site, pursuant to the terms of a Consent Decree, the Company has paid approximately $360,000. Clean-up at this site is near completion.
Mercury has been used in measurement devices used to measure natural gas production at the Company's properties. The Company has gathered information regarding mercury content in the surrounding wellhead sites and, with the appropriate state agency, is preparing a response strategy. Preliminary estimates indicate the Company may incur costs ranging from $250,000 to $750,000 to clean approximately 120 sites.
A subsidiary of the Company operating oil and gas properties in Canada has notified regulatory authorities with jurisdiction over environmental matters of potential contamination that may have been caused by a leaking condensate tank. Contamination is contained at the site of the plant where the tank was situated and estimated clean-up costs are $250,000 in Canadian dollars. The Company's subsidiary owns 60% of the facility.
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 SUPPLEMENTARY DATA
Page
Management's Responsibility for Financial Statements 50
Report of Independent Accountants 51
Consolidated Financial Statements:
Consolidated Statements of Income for the Years Ended December 31, 1994, 1993 and 1992 52
Consolidated Balance Sheets as of December 31, 1994 and 1993 53-54
Consolidated Statements of Cash Flows for the Years Ended December 31, 1994, 1993 and 1992 55
Consolidated Statements of Common Shareholders' Equity for the Years Ended December 31, 1994, 1993 and 1992 56
Notes to Consolidated Financial Statements 57-83
Supplementary Data (Unaudited) 84-92 Financial Statement Schedules for the Years Ended December 31, 1994, 1993 and 1992:
Schedule VIII - Valuation and Qualifying Accounts and Reserves 97
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 LLP, the Company's independent public accountants, also considered the systems in connection with its audit. Management has considered the internal auditors' and Price Waterhouse LLP's recommendations concerning the systems and has taken cost-effective actions to respond appropriately to these recommendations.
The Board of Directors, acting through an Audit Committee composed entirely of directors who are not employees of the Company, is responsible for determining that management fulfills its responsibilities in the preparation of the financial statements. The Audit Committee recommends, and the Board of Directors appoints, the independent public accountants. The independent accountants and internal auditors are assured of full and free access to the Audit Committee and meet with it to discuss their audit work, the Company's internal controls, financial reporting and other matters. The Committee is also responsible for determining that there is adherence to the Company's Code of Business Conduct (Code). The Code addresses, among other things, potential conflicts of interests and compliance with laws, including those relating to financial disclosure and the confidentiality of proprietary information.
The financial statements have been examined by Price Waterhouse LLP, which is responsible for conducting its examination in accordance with generally accepted auditing standards.
/s/ Daniel T. Berube /s/ J. P. Pederson Daniel T. Berube J. P. Pederson Chairman of the Board and Vice President and Chief Executive Officer Chief Financial Officer
Report of Independent Accountants
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, 1994 and 1993, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1994, 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 2 to the consolidated financial statements, the Company is party to a long-term supply contract price dispute subject to arbitration. The outcome of the arbitration is final and binding on all parties to the contract retroactive to August 1, 1991. The ultimate outcome of the arbitration cannot be determined at present. No provision for any liability that may result upon completion of arbitration has been made in the accompanying consolidated financial statements.
As discussed in Note 9 to the consolidated financial statements, the Company changed its method of accounting for postretirement benefits other than pensions in 1993.
PRICE WATERHOUSE LLP
Portland, Oregon February 10, 1995 CONSOLIDATED STATEMENT OF INCOME The Montana Power Company and Subsidiaries
CONSOLIDATED BALANCE SHEET The Montana Power Company and Subsidiaries ASSETS
CONSOLIDATED STATEMENT OF CASH FLOWS 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. All material intercompany sales and purchases between the Utility, Entech and the IPG have been eliminated from revenues and expenses in the Consolidated Statement of Income. All other significant intercompany items have also been eliminated. See Note 10 for details.
Plant and property:
Additions to and 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 1994, 1993, and 1992 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, 1994, the Company's joint ownership percentage and investment in these Units and transmission facilities were:
Units Transmission 1 & 2 Unit 3 Facilities Thousands of Dollars
Ownership. . . . . . . . . . . . 50% 30% 30%* Plant in service . . . . . . . . 180,725 280,791 50,046 Plant under construction . . . . 248 1,028 6 Accumulated depreciation . . . . 80,576 85,700 10,959
*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 $36,321,000 and $33,024,000 of the Colstrip Unit 4 share of common production plant and transmission plant that had related accumulated depreciation of $11,755,000 and $5,786,000, respectively.
Each joint-owner provides its own financing. The Company's share of direct expenses associated with the operation and maintenance of these joint facilities is included in the corresponding operating expenses in the Consolidated Statement of Income.
Utility revenue and expense recognition:
Operating revenues are recorded on the basis of service rendered. Costs of service are recognized on the accrual basis and charged to expense currently except for natural gas costs deferred pursuant to PSC-approved deferred gas accounting procedures and other costs deferred pursuant to regulatory decisions which are discussed in the following paragraph of this note.
In 1985, the Public Service Commission of Montana (PSC) approved an annual electric rate increase in the amount of $80,400,000 to be collected in accordance with a rate-moderation plan. During 1992, cash collected under this plan exceeded revenues recorded by $12,462,000. As of October 1992, all deferred revenues under the plan had been collected.
Regulatory assets:
In the ratemaking process, tax costs and benefits related to certain temporary differences are recovered in rates on an as paid or "flow-through" basis. Financial Accounting Standards No. 109 "Accounting for Income Taxes," (SFAS No. 109) requires that tax assets and liabilities be reflected on the Balance Sheet on an accrual basis. This timing difference requires the Company to recognize a regulatory asset for taxes accrued but not yet recovered in rates. That regulatory asset was $146,844,000 and $143,447,000 as of December 31, 1994 and 1993 respectively.
Included in other regulatory assets are costs related to the Company's Demand Side Management (DSM) programs in the amounts of $27,521,000 and $17,987,000 for 1994 and 1993, respectively. The amounts are included in the Company's rate base and are being charged to income over a ten-year period. Certain other costs have also been deferred pursuant to PSC orders of which significant amounts will also be charged to income within the next ten years.
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 7.9% for 1994, 6.5% for 1993, and 7.3% for 1992. The Company capitalized an allowance for borrowed funds used during construction of $2,405,000, $1,372,000, and $1,255,000 for 1994, 1993, and 1992, respectively.
Allowance for funds used for conservation expenditures:
The Company has been allowed by the PSC to capitalize, as part of its conservation expenditures, an allowance for the cost of equity and borrowed funds required to finance Demand Side Management expenditures. The rate used to capitalize the allowance is the Company's overall rate of return allowed by the PSC. The Company capitalized an allowance for borrowed funds used to finance DSM expenditures of $635,000, $561,000 and $290,000 for 1994, 1993 and 1992, 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. Deferred income taxes are provided for the temporary differences between the financial reporting basis and the tax basis of the Company's assets and liabilities. For further information on income taxes see "Regulatory Assets" in this note and also Note 4 - "Income Taxes."
Net income per share of common stock:
Net income per share of common stock is computed for each year based upon the weighted average number of common shares outstanding. The effect of options outstanding under the Company's Long-Term Incentive Plan is not significant (see Note 5).
Financial instruments:
In October 1994, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 119, "Disclosure about Derivative Financial Instruments and Fair Value of Financial Instruments," effective for fiscal years ending after December 15, 1994. This statement requires disclosure about derivative financial instruments - futures, forwards, swap and option contracts, and other financial instruments with similar characteristics.
Entech uses derivative financial instruments to manage the price risk associated with its oil and natural gas operations. Entech is authorized to use swaps, collars and options (caps and floors) as approved by a committee of its officers, to hedge up to 75% of its estimated production of oil and natural gas. At December 31, 1994, Entech held no derivative financial instruments.
The Independent Power Group (IPG) has investments in independent power partnerships, some of which have entered into derivative financial instruments to hedge against interest rate exposure on floating rate debt and foreign currency and gas price fluctuations.
Statement of Financial Accounting Standards No. 107, "Disclosure About Fair Value of Financial Instruments," requires disclosure of the fair value of certain financial instruments. The estimated fair value amounts have been determined by the Company using available market information and appropriate valuation methodologies. However, considerable judgement is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that the Company could realize in a current market exchange. The use of different market assumptions and/or estimation methodologies could result in different estimated fair value amounts.
Cash and temporary cash investments, accounts receivable, current assets, short-term borrowings, accounts payable and accrued liabilities are reflected in the financial statements at fair value because of the short-term maturity of these instruments.
The carrying amounts and estimated fair value of the Company's other significant financial instruments at December 31, 1994 are as follows:
Estimated Carrying Fair Amount Value Thousands of Dollars
Assets: Independent Power Investments. . . . . . $ 9,566 $ 5,482 Other Investments. . . . . . . . . . . . 31,690 31,875
Liabilities: Long-Term Debt . . . . . . . . . . . . . $ 585,157 $ 544,639
The following methods and assumptions were used to estimate fair value:
Independent Power Investments - The fair value represents the Company's assessment of the present value of net future cash flows embodied in these investments, discounted to reflect current market rates of return. This represents only those investments accounted for on the cost basis. The investments accounted for on the equity basis are not presented.
Other Investments - The carrying value of most of the investments approximates fair value as the investments have short maturities or the carrying value equals their cash surrender value. Other investments' fair value was estimated based on the discounted value of the future cash flows expected to be received using a rate of return expected on similar current investments.
Long-Term Debt - The fair value was estimated using quoted market rates for the same or similar instruments. Where quotes were not available the fair value was estimated using the Company's year-end incremental borrowing rate.
Reclassifications:
Certain reclassifications have been made to the prior year amounts to make them comparable to the 1994 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 1995 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, 1994, 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 180 megawatt Kerr Hydroelectric project until September 2015. The Tribes may take over the project anytime between 2015 and 2025 on one year's written notice in return for payment equal to the Company's remaining net investment. The Company pays the Tribes an annual rental fee that is adjusted yearly to reflect changes in the Consumer Price Index.
In 1990, the Company filed with the FERC a plan (the Plan), prepared pursuant to the joint license issued by the FERC to the Company and the Tribes, to mitigate damages to, and to manage fish and wildlife habitat impacted by the operation of the Kerr Hydroelectric Project. The Plan provides for a one-time payment by the Company of $15,418,000 and annual payments of $965,000 which would be adjusted annually to reflect the effects of inflation and which are to be allocated between the Tribes and various groups.
As part of its review of the Plan, FERC is preparing a draft environmental impact statement which is expected to suggest modifications to the Plan. In addition, the Department of Interior, pursuant to its authority under the Federal Power Act, has proposed certain conditions, requiring changes in the operation of the project, as well as non-operational measures which would be funded by an initial payment, annual payments based on a calculation of the Project's value as a base-load facility and further capital investments.
While it cannot predict when or in what form the Plan finally will be approved, the Company expects that the cost of mitigation measures will be recovered through rates or from the Tribes if they exercise their right to take over the project and 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 $173,000,000. 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 coal supply agreement for Colstrip Units 1 and 2 between Puget Sound Power & Light Company (Puget) and the Company's Utility Division, as co-owners of the units, and Western Energy Company, as coal supplier, provides for periodic price redeterminations over the life of the contract, commencing in 1991. Negotiations with respect to the 1991 redetermination were unsuccessful and an arbitration proceeding was held in January 1995. A decision is expected in late March 1995. Based upon the positions of the parties, the estimated effect on pretax net income at December 31, 1994 would range from an increase of approximately $4,000,000 to a decrease of approximately $12,000,000 on coal sold to Puget and, in addition, an increase of approximately $2,000,000 to a decrease of $12,000,000 on coal sold to the Company's Utility Division. The Company believes Western presented a convincing position in the arbitration. Further, the Company believes because its electric rates have been adjusted by a coal cost disallowance, they should not be subject to further adjustment. The Company, however, cannot predict the outcome of the arbitration nor any related rate proceeding.
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 4.7 cents per kWh in the contract year which began in July 1994 and will increase 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. Based upon projected deliveries, 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 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 1992. . . . . . . $ 18,143 $ 12,496 $ 1,938 1993. . . . . . . 18,434 11,633 2,260 1994. . . . . . . 19,242 11,072 2,993
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 1995. . . . . . . $ 4,609 $ 9,032 $ 2,411 1996. . . . . . . 8,169 7,001 1,889 1997. . . . . . . 11,143 5,810 1,727 1998. . . . . . . 11,109 2,907 1,598 1999. . . . . . . 10,916 2,450 1,406 Remainder. . . .. 151,979 6,156 6,643 Total . . . . . $ 197,925 $ 33,356 $ 15,674
In 1993, the Company entered into contracts for the construction of a second powerhouse at the Thompson Falls Hydroelectric Plant. Expenditures for the project to date have been $28,300,000, while the total costs for the next two years are expected to be $20,600,000.
An Entech Coal Division coal lease purchase agreement requires minimum annual payments, beginning in 1991 in the amount of $1,125,000 escalated quarterly by the Gross National Product implicit price deflator. The payments will continue until the equivalent of $18,750,000, in 1986 dollars, has been paid. At December 31, 1994, the remaining payments under this agreement were $13,991,000. A similar agreement requires minimum annual payments of $1,000,000 through 1995. Under current mine plans, these payments should be recovered through coal sales.
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 Coal Division and a subsidiary of Northern States Power are partners in a five-year, $69,000,000 coal enhancement demonstration project 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, 1994, was $2,809,000.
The Entech Oil Division has agreed to supply approximately 138,000 Mmcf of natural gas to four cogeneration facilities over 10 to 16 years. The Oil Division has proven, developed and undeveloped reserves sufficient to supply all of the remaining natural gas required by these agreements.
Rental expense for the prior three years was as follows:
1994 1993 1992 Thousands of Dollars
Colstrip Unit 4. . . . $ 32,226 $ 32,226 $ 32,226 Kerr project . . . . . 12,172 11,837 11,486 Other. . . . . . . . . 12,530 11,917 11,985 $ 56,928 $ 55,980 $ 55,697
In addition, operating expenses include delay rentals paid by the Company to retain mineral rights before development of leased acreage. Delay rentals were $1,015,000, $1,021,000, and $999,000 in 1994, 1993, and 1992, 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, 1994, the Company's future minimum operating lease payments are as follows:
Thousands of Year Dollars
1995. . . . . . . . . . . . . . $ 35,265 1996. . . . . . . . . . . . . . 34,317 1997. . . . . . . . . . . . . . 34,022 1998. . . . . . . . . . . . . . 33,831 1999. . . . . . . . . . . . . . 33,781 Remainder . . . . . . . . . . . 356,260 Total . . . . . . . . . . . $ 527,476
NOTE 4 - Income tax expense:
Income before income taxes for the years ended December 31, 1994, 1993 and 1992 was as follows:
1994 1993 1992 Thousands of Dollars
United States. . . . . . . . . . . . . $ 155,978 $ 150,290 $ 143,298
Canada . . . . . . . . . . . . . . . . 9,144 8,791 6,047
Brazil . . . . . . . . . . . . . . . . 3,696 2,250 3,359
$ 168,818 $ 161,331 $ 152,704
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:
1994 1993 1992 Thousands of Dollars
Computed "expected" income tax expense . . $ 59,086 $ 56,466 $ 51,919
Adjustments for tax effects of:
Statutory depletion in coal mining operations . . . . . . . (4,983) (3,775) (5,920) General business and nonconventional fuel tax credits . . . . . . . . . . (5,130) (4,496) (3,723) State income tax, net . . . . . . . . . 4,772 4,704 3,332 Reversal of excess of U.S. utility income tax depreciation over financial accounting depreciation on utility plant additions. . . . . . . . . . . . . . 3,236 2,281 1,987
Other . . . . . . . . . . . . . . . . . (1,755) (1,060) (1,956)
Actual income tax expense. . . . . . . . . $ 55,226 $ 54,120 $ 45,639
Income tax expense as shown in the Consolidated Statement of Income consists of the following components:
1994 1993 1992 Thousands of Dollars
Current
United States. . . . . . . . . . . . $ 38,519 $ 31,039 $ 38,252
Canada . . . . . . . . . . . . . . . 3,093 3,235 3,162
Brazil . . . . . . . . . . . . . . . 1,080
State. . . . . . . . . . . . . . . . 7,742 3,522 8,307
50,434 37,796 49,721
Deferred
United States. . . . . . . . . . . . 4,426 13,664 (2,646)
Canada . . . . . . . . . . . . . . . 850 374 (200)
State. . . . . . . . . . . . . . . . (484) 2,286 (1,236)
4,792 16,324 (4,082)
$ 55,226 $ 54,120 $ 45,639
Deferred tax liabilities (assets) are comprised of the following at December 31: 1994 1993 Thousands of Dollars
Plant Related. . . . . . . . . . . . . . . . . . . $ 379,401 $ 372,236 Investment in nonutility generation projects . . . 21,752 16,370 Other. . . . . . . . . . . . . . . . . . . . . . . 21,309 16,260
Gross deferred tax liabilities . . . . . . . . . . 422,462 404,866
Coal reclamation . . . . . . . . . . . . . . . . . (40,509) (37,321) Amortization of gain on sale/leaseback . . . . . . (17,026) (18,090) Investment tax credit amortization . . . . . . . . (31,665) (32,801) Other. . . . . . . . . . . . . . . . . . . . . . . (20,392) (14,937)
Gross deferred tax assets. . . . . . . . . . . . . (109,592) (103,149) Net deferred tax liabilities (assets). . . . . . . 312,870 301,717
Plus current deferred tax assets-net . . . . . . . 9,965 8,063
Total noncurrent deferred tax liabilities (assets) . . . . . . . . . . . . . . . . . . . . $ 322,835 $ 309,780
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) . . . . . . . . . . . . . . . . $ 13,055 Regulatory assets related to income taxes. . . . . . . (3,397) Current deferred tax asset-net . . . . . . . . . . . . (1,902) Amortization of investment tax credits . . . . . . . . (1,748) Other. . . . . . . . . . . . . . . . . . . . . . . . . (1,216) Deferred tax expense . . . . . . . . . . . . . . . . $ 4,792
NOTE 5 - Common stock:
At December 31, 1994 and 1993, 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, 1994, 610,379 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, 1994:
1994 1993 1992
Thousands of Dollars
Principal allocated.................... $ 2,663 $ 2,663 $ 2,663 Interest incurred...................... 3,114 3,275 3,422 Dividends.............................. (3,046) (3,028) (3,014) Additional contribution................ 2,952 2,310 1,766
Total Expense..................... $ 5,683 $ 5,220 $ 4,837
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 $968,000, $758,000 and $694,000 for the years ending December 31, 1994, 1993 and 1992, 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, 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 Granted 117,100 22.625 - 25.625 Exercised (43,884) 14.25 - 26.50 Cancelled (4,540) 14.25 - 26.50
Outstanding December 31, 1994 480,986 $17.25 - 26.50
Options Exercisable at December 31, 1994 480,986
Options were granted at 100% of the closing price on the New York Stock Exchange on the date granted, and expire ten years from that date. Options granted prior to January 1, 1987 must be exercised in the order granted.
In 1994, 64,235 restricted stock awards were issued to certain Entech employees under the Long-Term Incentive Plan. Upon the achievement of performance and passage of time constraints, restrictions will be lifted and participants will retain, at no cost, the unrestricted shares. As they are earned, the awards are reflected as common stock and compensation expense on the Balance Sheet and Income Statement, respectively.
NOTE 6 - Preferred stock:
The number of authorized shares of preferred stock is 5,000,000. No dividends may be declared or paid on common stock while cumulative dividends have not either been declared and set apart or paid on any of the preferred stock.
Preferred stock, 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. At the annual meeting of shareholders in May 1994, shareholders approved a proposal permitting the redemption of the $2.15 series.
NOTE 7 - Long-term debt:
Long-term debt consists of the following: December 31 1994 1993 Thousands of Dollars First Mortgage Bonds: 7.7% series, due 1999...................... $ 55,000 $ 55,000 7 1/2% series, due 2001.................... 25,000 25,000 7% series, due 2005........................ 50,000 50,000 8 1/4% series, due 2007.................... 55,000 55,000 8.95% series, due 2022..................... 50,000 50,000 Secured Medium-Term Notes.................. 88,000 43,000 Pollution Control Revenue Bonds: City of Forsyth, Montana 6 1/8% series, due 2023.............. 90,205 90,205 5.9% series, due 2023................ 80,000 80,000 Sinking Fund Debentures: 7 1/2%, due 1998........................... 17,000 17,500 ESOP Notes Payable, due 2004................... 31,943 33,850 Unsecured Medium-Term Notes, Series A.......... 48,250 67,250 Long-Term Commercial Paper..................... 20,000 Other.......................................... 19,847 15,144 Unamortized Discount and Premium.......... (4,389) (3,880) 605,856 598,069 Less: Portion due within one year............. 16,980 26,199 $ 588,876 $ 571,870
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 set forth above, in the aggregate principal amount of $493,205,000 at December 31, 1994.
Secured Medium-Term Notes:
At December 31, 1994 and 1993, the Company had outstanding $88,000,000 and $43,000,000 principal amount of Secured Medium-Term Notes, respectively, maturing from 3 to 30 years with interest rates varying between 7.20% and 8.11%.
In January 1994, the Company sold $5,000,000 of Secured Medium-Term Notes, 7.25% series due 2024. The proceeds were used to repay short-term debt incurred to complete the refinancing of $80,000,000 of the 10% and 10-1/8% series Pollution Control Revenue Bonds in December 1993.
In June 1994, the Company sold $20,000,000 of Secured Medium-Term Notes, 7.2% series due 2000, the proceeds of which were used to retire other long- term debt.
In November 1994, the Company sold $10,000,000 of Secured Medium-Term Notes, 7.6% series due 1997 and $10,000,000 of Secured Medium-Term Notes, 7.85% series due 1998, the proceeds of which were used to retire three series of unsecured Medium-Term Notes, $9,000,000 of the 8.78% series due November 1994, $5,000,000 of the 8.57% series due December 1994 and $5,000,000 of the 8.78% series due December 1994.
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.
Unsecured Medium-Term Notes, Series A:
At December 31, 1994 and 1993, the Company had outstanding $48,250,000 and $67,250,000 principal amount of Medium-Term Notes, respectively, maturing from 1 to 28 years with interest rates varying between 8.68% and 8.90%.
During 1994 the following Medium-Term Notes matured; on November 15, 1994, $9,000,000 of the 8.78% series due 1994, on December 15, 1994, $5,000,000 of the 8.57% series due 1994, on December 20, 1994, $5,000,000 of the 8.78% series due 1994. As previously mentioned, the Company retired these notes with the proceeds from the sale of Secured Medium-Term Notes.
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, 1994. 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, 1994. Under the agreement, borrowings outstanding at September 30, 1997 must be repaid at maturity.
Fixed or variable interest rate options are available under the facilities, with commitment fees on the unused portions.
During the period 1995 through 1999, the Company is required to make the following maturity and sinking fund payments on long-term debt:
1995 1996 1997 1998 1999 Thousands of Dollars
7.7% First Mortgage Bonds.. $ 55,000 Secured Medium-Term Notes.. $ 10,000 $ 10,000 7 1/2% Sinking Fund Debentures............... $ 500 $ 500 500 15,500 ESOP Notes Payable......... 2,082 2,274 2,483 2,712 2,961 Unsecured Medium-Term Notes.................... 10,000 8,750 7,500 2,500 2,500 Other...................... 4,398 12,613 303 301 300 $ 16,980 $ 24,137 $ 20,786 $ 31,013 $ 60,761
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, 1994, the Company had lines of credit consisting of $65,000,000 committed and $75,400,000 uncommitted, and Entech had lines of credit consisting of $15,000,000 committed and $25,000,000 uncommitted. There is a commitment fee on the unused portion of some of these facilities which is not significant. The Company has the ability, subject to the previously mentioned PSC limitation, to issue up to $125,000,000 of commercial paper and Entech up to $50,000,000 of commercial paper based on the total of unused committed lines of credit and revolving credit agreements.
At December 31, 1994 and 1993, the Company's and Entech's short-term borrowing included the following:
1994 1993 Thousands of Dollars
Notes payable to banks MPC.......................... $ 90,000 $ 43,900 Entech....................... 14,000 8,000 Commercial paper Entech....................... 9,989 16,965 $ 113,989 $ 68,865
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 1994 and 1993, pension costs funded were less than SFAS No. 87 pension expense by $2,770,000 and $1,887,000, respectively and the difference was recorded as a reduction of unearned revenue. The amount of utility pension costs funded are included in rates. In 1992, pension costs funded exceeded SFAS No. 87 pension expense by $969,000 and the differences were recorded as unearned revenue. At December 31, 1994, the cumulative amount by which SFAS No. 87 pension expense exceeded pension costs funded was $1,408,000.
The assets of the plans consist primarily of domestic and foreign corporate stocks, domestic corporate bonds and U.S. Government securities.
The Company also has an unfunded, nonqualified benefit plan for senior management executives and directors that provides for defined benefit payments upon retirement over the life of the participant or to their beneficiary for a minimum fifteen-year period. Life insurance payable to the Company is carried on plan participants as an investment. Utility nonqualified benefit plan expense is not included in rates.
Net pension and benefit expense includes the following components:
1994 1993 1992 Thousands of Dollars
Service cost benefits earned during the period.......................... $ 8,442 $ 6,746 $ 5,287
Interest cost on projected benefit obligation.......................... 13,430 12,077 9,978
Actual return market value of assets.. (13,051) (18,701) (12,688) Net amortization and deferral......... 3,788 10,891 4,642
Total net periodic pension and benefit expense................... $ 12,609 $ 11,013 $ 7,219
The funded status of the pension and benefit plans is as follows:
December 31 1994 1993 Thousands of Dollars
Actuarial present value of accumulated plan benefits Vested...................................... $ 119,298 $ 120,550 Nonvested................................... 13,066 10,861
Accumulated benefit obligation.................. 132,364 131,411 Effect of projected future compensation levels.. 40,474 62,278
Projected benefit obligation.................... 172,838 193,689 Plan assets at fair value....................... 153,916 150,913
Plan assets less than projected benefit obligation............................ (18,922) (42,776)
Unrecognized net loss (gain) from past experience different from that assumed and effects of changes in assumptions............. (9,402) 16,675 Prior service cost not yet recognized in net periodic pension expense...................... 11,498 14,567 Unrecognized initial obligation................. 3,261 3,703
Prepaid (Accrued) benefits expense............ $ (13,565) $ (7,831)
The following assumptions were used in the determination of actuarial present values of the projected benefit obligations:
December 31 1994 1993
Assumed discount rates: Active service and vested terminations........ 8.25% 7.00% Retired employees............................. 8.25% 7.00%
Long-term rate of average compensation increase. 4.25%-5.20% 4.90%-5.45%
Long-term rate on plan assets................... 8.50% 8.50%
In addition to providing pension benefits, the Company and its subsidiaries provide certain health care and life insurance benefits for eligible retired employees. 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 and 1992 was $1,387,000 and $1,267,000, respectively.
In 1994, the Company established a pre-funding plan for postretirement benefits for utility employees retiring after January 1, 1993. Funding costs for the plan for 1994 were $1,487,000. The assets of the plan consist primarily of domestic and foreign corporate stocks, domestic corporate bonds and U.S. Government securities.
The Company adopted SFAS No. 106 effective January 1, 1993. SFAS No. 106 requires accrual of the expected cost of these postretirement benefits during the employees' years of service rather than when the costs are paid.
In accordance with an Accounting Order issued by the PSC in 1992, the Company recorded as a deferred expense $600,000 and $2,100,000 representing the increased costs in 1994 and 1993, respectively, from adopting SFAS No. 106 for the Utility Division. In its April 28, 1994 Order, the PSC allowed the Company to include in rates the full OPEB cost on the accrual basis provided by SFAS No. 106, including the amortization of the amounts previously deferred under a PSC Accounting Order from January 1, 1993 to April 27, 1994. Consequently, as of April 28, 1994, the Company commenced recognition of these utility postretirement benefits in expense in accordance with SFAS No. 106. The incremental increase in 1994 consolidated expenses due to the utility SFAS No. 106 expense recognition was approximately $1,500,000.
The cost of SFAS No. 106 adoption for the years ended December 31, 1994 and 1993, portions of which have been deferred or capitalized, includes the following components:
December 31 1994 1993 Thousands of Dollars
Service cost on benefits earned during the year. . . . . . . . . . . . . $ 1,455 $ 1,356
Interest cost on projected benefit obligation . . . . . . . . . . . . . . . 2,323 2,296
Actual return market value of assets. . . . (38)
Amortization of transition obligation . . . 1,535 1,492
Total postretirement benefit cost . . . . . $ 5,275 $ 5,144
The funded status of the postretirement benefit plans other than pensions is as follows:
December 31 1994 1993 Thousands of Dollars
Accumulated benefit obligation: Fully eligible active employees . . . . . . $ 2,253 $ 1,920 Other active employees. . . . . . . . . . . 19,857 20,195 Retirees. . . . . . . . . . . . . . . . . . 8,751 12,298 Accumulated benefit obligation. . . . . . . 30,861 34,413 Plan assets at fair value . . . . . . . . . . 1,479 0 Plan assets less than projected benefit obligation. . . . . . . . . . . . . (29,382) (34,413) Unrecognized net transition obligation. . . . 25,560 27,519 Unrecognized net loss (gain) from past experience different from that assumed and effects of changes in assumptions. . . . . . . . . . . . . . . (2,417) 3,113 Prepaid (Accrued) benefits expense. . . . . . $ (6,239) $ (3,781)
The assumed 1994 health care cost trend rates used to measure the expected cost of benefits covered by the plans are 8.75% and 11% for the utility and non-utility operations, respectively. The utility trend rate decreases through 2002 to 6%. The nonutility trend rate decreases through 2004 to 5%. The trend rates are for pre-65 benefits since most of the plans provide a fixed dollar annual benefit for retirees over age 65. One Entech subsidiary's plan used a trend rate of 9% decreasing through 2003 to an ultimate rate of 5% for post-65 benefits. The effect of a 1% increase in each future year's assumed health care cost trend rates increases the service and interest cost from $3,800,000 to $4,200,000 and the accumulated postretirement benefit obligation from $29,400,000 to $32,300,000.
On January 1, 1994, the Company adopted Statement of Financial Accounting Standards No. 112, "Employers' Accounting for Postemployment Benefits," (SFAS No. 112) with respect to disability related benefits up to age 65. SFAS No. 112 requires the accrual of a liability or loss contingency for the estimated obligation for postemployment benefits. At December 31, 1993, the postemployment benefit liability for regulated utility operations was estimated to be $9,300,000, of which $2,400,000 had been accrued and included in rates. The remaining $6,900,000 was recorded in 1994 as a deferred charge and will be expensed and included in rates over the next ten years. The estimated December 31, 1993 postemployment benefit liability of $1,300,000 for non-utility operations has been charged to income in 1994. The Company is no longer self-insured for disability-related benefits resulting from claims occurring after December 31, 1993. Therefore, SFAS No. 112 will not apply to benefits after that date, except workman's compensation claims which are accrued and recovered in rates as previously discussed.
NOTE 10 - Information on industry segments:
The Company's principal business includes regulated utility operations involving the generation, purchase, transmission and distribution of electricity and the production, purchase, transportation and distribution of natural gas. The Company, through Entech, engages in nonutility operations principally involving the mining and sale of coal, exploration for, and the development, production, processing and sale of oil and natural gas and the sale of telecommunication equipment and services. The Company, through its Independent Power Group (IPG), manages long-term power sales, develops and invests in independent power projects, and other energy-related businesses.
Substantially all of the natural gas produced by the Company's Canadian utility operations has been sold to the Company's United States utility operations.
Pre-tax operating income for the Utility, Entech, and IPG segments represents revenues excluding earnings from unconsolidated investments less all costs and expenses except interest and other (income) deductions-net. Immaterial intersegment sales are not disclosed.
Identifiable assets of each industry segment are those assets used in the Company's operations in such industry segments. Corporate assets are principally miscellaneous special funds, cash and temporary cash investments, other investments and unallocable property. The assets of the Company's Canadian operations were $79,337,000, $80,553,000 and $84,202,000 at December 31, 1994, 1993 and 1992, respectively.
Operations Information:
Operations Information:
Operations Information:
SUPPLEMENTARY DATA Oil and Natural Gas Producing Activities (Cont.)
As determined by engineers, utility natural gas reserves were revised during 1994, 1993 and 1992 due to a change in projected performance or a change in the Company's ownership interest in specific fields.
In 1994, Entech's U.S. oil and natural gas reserves increased as a result of the acquisition of oil interests in Kansas and the drilling of 25 development wells and 6 exploratory wells in Colorado, Montana, Oklahoma, and Wyoming. Natural gas liquid reserves decreased due to a lower liquid recovery factor experienced at the Fort Lupton, Colorado, gas processing plant. Higher oil market prices contributed to an upward revision in U.S. reserves. The Canadian companies participated in 21 development wells and 7 exploratory wells. Significant natural gas and natural gas liquid reserves were added as a result of exploratory well discoveries in the Grand Prairie and Saddle Lake areas of Alberta. A development well in the Caroline area in Alberta extended the new pool discovery from 1993. Significant oil reserves were added at Manyberries because of a new pool discovery and development drilling in 1994.
In 1993, Entech's U.S. oil and natural gas reserves increased as a result of the drilling of 55 development wells and 10 exploratory wells in Colorado, North Dakota, Wyoming, Oklahoma and Kansas. Natural gas liquid reserves increased due to the startup of the Fort Lupton, Colorado, gas processing plant in September 1993. Lower oil market prices contributed to downward revisions in U.S. reserves. The Canadian companies participated in 26 development and 13 exploratory wells. Significant gas reserves were added from discoveries in the exploratory wells. Additions in oil reserves were the result of two successful secondary recovery schemes completed in the Manyberries area in Southern Alberta during 1993. Revisions due to price and performance resulted in a net increase in natural gas liquid reserves and a net decrease in oil reserves.
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 Alberta.
The following table presents information for 1994, 1993 and 1992 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 1994, 1993 and 1992 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 DATA Oil and Natural Gas Producing Activities (Cont.)
Estimated future cash flows are computed by applying year-end prices and contract prices, when appropriate, of oil and natural gas to year-end quantities of proved reserves. Estimated future development and production costs are determined by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at the end of the year, based on year-end costs. Estimated future income tax expenses are calculated by applying year-end statutory tax rates to estimated future 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
Quarterly Financial Data
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 1995 Annual Meeting of Shareholders and Proxy Statement, pages 1-3.
ITEM 11.

ITEM 11. EXECUTIVE COMPENSATION
Incorporated by reference from Notice of 1995 Annual Meeting of Shareholders and Proxy Statement, pages 5-8.
ITEM 12.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Incorporated by reference from Notice of 1995 Annual Meeting of Shareholders and Proxy Statement, pages 3-4.
ITEM 13.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Incorporated by reference from Notice of 1995 Annual Meeting of Shareholders and Proxy Statement, page 14.
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 33-56739 3(a) 3(a)(2) Amendments to the Restated Articles of Incorporation 33-56739 3(a) 3(b) By-laws, as amended 33-42882 4(b) 3(b)(1) Amendments to By-laws 4(a) Mortgage and Deed Trust 2-5927 7(e) 4(b) First Supplemental Indenture 2-10834 4(e) 4(c) Second Supplemental Indenture 2-14237 4(d) 4(d) Third Supplemental Indenture 2-27121 2(a)-5 4(e) Fourth Supplemental Indenture 2-36246 2(a)-6 4(f) Fifth Supplemental Indenture 2-39536 2(a)-7 4(g) Sixth Supplemental Indenture 2-49884 2(a)-8(a) 4(h) Seventh Supplemental Indenture 2-52268 2(a)-9 4(i) Eighth Supplemental Indenture 2-53940 2(a)-10 4(j) Ninth Supplemental Indenture 2-55036 2(a)-11 4(k) Tenth Supplemental Indenture 2-63264 2(a)-12 4(l) Eleventh Supplemental Indenture 2-86500 2(a)-13 4(m) Twelfth Supplemental Indenture 33-42882 4(c) 4(n) Thirteenth Supplemental Indenture 33-55816 4(a)-14 4(o) Fourteenth Supplemental Indenture 33-64576 4(c) 4(p) Fifteenth Supplemental Indenture 33-64576 4(d) 4(q) Sixteenth Supplemental Indenture 33-50235 99(a) 4(r) Seventeenth Supplemental Indenture 33-56739 99(a) 4(s) Eighteenth Supplemental Indenture 33-56739 99(b)
Instruments defining the rights of holders of long-term debt which are not required to be filed with the Commission will be furnished to the Commission upon request.
Incorporation by Reference
Previous Previous Exhibit Filing Designation
4(t) Rights Agreement dated as of 33-42882 4(d) June 6, 1989, between The Montana Power Company and First Chicago Trust Company of New York, as Rights Agent
10(a)(i) Benefit Restoration Plan for 33-42882 10(a)(i) Senior Management Executives and Board of Directors
10(a)(ii) Deferred Compensation Plan for 33-42882 10(a)(ii) Non-Employee Directors
Incorporation by Reference
Previous Previous Exhibit Filing Designation
10(a)(iii) Long-Term Incentive Stock 1-4566 10(a)(iii) Ownership Plan 1992 Form 10-K
10(a)(iv) The Montana Power Company 33-28096 4(c) Employee Stock Ownership Plan (Revised)
10(a)(v) Termination Compensation 1-4566 10(a)(v) Agreements with Senior 1992 Management Executives Form 10-K
10(a)(v)(1) Amendments to Termination Compensation Agreements with Senior Management Executives
10(c) Participation Agreements among 33-42882 10(c) United States Trust Company of New York, Burnham Leasing Corporation, and SGE (New York) Associates, Certain Institutions, The Montana Power Company and Bankers Trust Company
12 Statement re computation of ratio of earnings to Fixed Charges
21 Subsidiaries of the registrant
27 Financial Data Schedule
THE MONTANA POWER COMPANY AND SUBSIDIARIES SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES Thousands of Dollars
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E Balance Additions at Charged to Charged to Balance beginning costs and other at close Description of period expenses accounts Deductions of period
(Note a)
Year Ended:
December 31, 1994 Reserves deducted in balance sheet from assets to which they apply: Doubtful accounts Utility $ 748 $ 781 $ $ 721 $ 808 Entech 643 156 (9) 174 616
Total $ 1,391 $ 937 $ (9) $ 895 $ 1,424
December 31, 1993 Reserves deducted in balance sheet from assets to which they apply: Doubtful accounts Utility $ 688 $ 764 $ $ 704 $ 748 Entech 529 391 17 294 643
Total $ 1,217 $ 1,155 $ 17 $ 998 $ 1,391
December 31, 1992 Reserves deducted in balance sheet from assets to which they apply: Doubtful accounts Utility $ 628 $ 1,361 $ $ 1,301 $ 688 Entech 387 345 3 206 529
Total $ 1,015 $ 1,706 $ 3 $ 1,507 $ 1,217
NOTES: (a) Deductions are of the nature for which the reserves were created. In the case of the reserve for doubtful accounts, deductions from this reserve are reduced by recoveries of amounts previously written off. /TABLE
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
THE MONTANA POWER COMPANY
By /s/ Daniel T. Berube Daniel T. Berube (Chairman of the Board)
Date March 21, 1995
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 21, 1995 (Chief Executive Officer)
/s/ J. P. Pederson Principal Financial J. P. Pederson and Accounting Officer March 21, 1995 (Vice President and Chief and Director Financial Officer)
/s/ Alan F. Cain Director March 21, 1995 Alan F. Cain
/s/ R. D. Corette Director March 21, 1995 R. D. Corette
/s/ Kay Foster Director March 21, 1995 Kay Foster
/s/ Robert P. Gannon Director March 21, 1995 Robert P. Gannon
/s/ Beverly D. Harris Director March 21, 1995 Beverly D. Harris
/s/ Chase T. Hibbard Director March 21, 1995 Chase T. Hibbard
/s/ Daniel P. Lambros Director March 21, 1995 Daniel P. Lambros
/s/ Carl Lehrkind, III Director March 21, 1995 Carl Lehrkind, III
/s/ James P. Lucas Director March 21, 1995 James P. Lucas
/s/ Arthur K. Neill Director March 21, 1995 Arthur K. Neill
/s/ George H. Selover Director March 21, 1995 George H. Selover
/s/ N. E. Vosburg Director March 21, 1995 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. 33-56739, 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, 1995 appearing on page 51 of The Montana Power Company's Annual Report on Form 10-K for the year ended December 31, 1994.
PRICE WATERHOUSE LLP
Portland, Oregon March 23, 1995
EXHIBIT INDEX
Exhibit (3)(b)(1) Amendments to By-laws
Exhibit 10(a)(v)(1) Amendments to Termination Compensation Agreements with Senior Management Executives
Exhibit 12 Statement re computation of ratio earnings to Fixed Charges
Exhibit 21 Subsidiaries of the registrant
Exhibit 27 Financial Data Schedule