ITEM 1. BUSINESS
	OVERVIEW: The Montana Power Company (the Company) and its subsidiaries engage in a number of diversified energy and communication related businesses. The Company operates a regulated Utility which generates, purchases, transmits, and distributes electricity and purchases, transports, and distributes natural gas. The Company's Nonutility operations principally conduct telecommunications operations which sell long distance, Internet, and dedicated line services and equipment and design, develop, construct, operate, maintain, and manage a fiber-optic network and digital microwave facilities. Other Nonutility operations include the mining and sale of coal and lignite, and exploration for, and the development, production, processing, and sale of oil and natural gas. The Company also conducts the trading of electricity and the trading and marketing of natural gas. In addition, the Company manages long- term power sales, and develops and invests in independent power projects and other energy-related businesses. The Company was incorporated in 1961 under the laws of the State of Montana as the successor to a corporation formed in 1912. See Part II, Item 8, "Financial Statements and Supplementary Data - Note 12 to the Consolidated Financial Statements" for further information on the Company's business segments.
RECENT DEVELOPMENTS:
? Montana's Electric Industry Restructuring and Customer Choice Act (Electric Act) and Natural Gas Restructuring and Customer Choice Act (Gas Act) became law in May 1997. ? In November 1997, significantly all of the Utility's natural gas production assets were transferred to an unregulated affiliate. The Company also implemented a fixed-price supply contract through 2002 between its unregulated gas supply division and its regulated distribution division to serve the remaining customers who have not chosen other suppliers. ? In July 1998, the Company and the owners of Colstrip Units 3 and 4 generating plants settled coal contract disputes and future coal price reopeners. ? In August 1998, the Company announced it is exiting the electric commodity trading and marketing businesses, but will continue natural gas and natural gas liquids commodity trading and marketing. ? In November 1998, the Company announced an agreement (Agreement) to sell the Company's interest in 12 of its 13 Utility hydroelectric facilities, all four coal-fired thermal generating plants, a Nonutility leasehold interest in Colstrip Unit 4, a power purchase contract with Basin Electric Power Cooperative (Basin) and two power exchange agreements to PP&L Global, Inc. ? In December 1998, a special purpose entity (SPE) wholly owned by the Company issued $62,700,000 of asset-backed transition bonds.
? In December 1998, the Company resolved a dispute with the purchaser of lignite from the Jewett Mine involving the price of lignite and whether other fuels could be substituted for lignite. ? In January 1999, the Company received and recorded $257,000,000 representing prepayment of all amounts due for the remaining initial term of one telecommunications contract.
With the sale of the Company's interest in its electric generating facilities and the exit from the electric trading and marketing business, the Company no longer will be a primarily a vertically integrated electric and natural gas utility. The Company expects to maintain its traditional regulated transmission and distribution utility businesses in Montana, the coal and lignite mines that serve mine-mouth generating plants, the independent power investments and operations and the natural gas exploration, development, production, trading, and marketing. The Company will also continue to invest in new opportunities such as telecommunications.
See Part II, Item 7, "Management's Discussion and Analysis of Financial Conditions and Results of Operations" and Item 8, "Financial Statements and Supplementary Data - Notes 4 and 9 to the Consolidated Financial Statements" for further discussion of recent developments and changes in the Company's operations.
UTILITY OPERATIONS:
	SERVICE AREA AND SALES: The Utility's service territory comprises 107,600 square miles or approximately 73 percent of Montana. It serves approximately 603,000 residents or 80 percent of the population within the service territory. Additionally, energy is provided to cooperatives that serve approximately 76,000 residents. The dominant segments of Montana's economy include agriculture and livestock, which is the largest industry; tourism and recreation; coal and metals mining; oil and natural gas production; and the forest-products industry, including production of pulp and paper, plywood and lumber.
	Electric service is provided to 191 communities, the rural areas surrounding them, and Yellowstone National Park. Firm electric power is sold at wholesale to two rural electric cooperatives and natural gas service is provided to 109 communities.
	ELECTRIC UTILITY: Total firm capability of the Utility's electric system at December 31, 1998 was 1,510,700 kW. Of this capability, the Utility's generating facilities provided 1,157,400 kW, and 353,300 kW was provided by firm Electric Utility power purchase and exchange arrangements. Also refer to Part II, Item 8, "Financial Statements and Supplementary Data - Note 3 to the Consolidated Financial Statements" for further discussion of power purchases.
	The maximum demand on the resources in 1998 was 1,560,000 kW on December 21, 1998. The total firm capability on that date was 1,396,000 kW. Also on that date, the Electric Utility's reserve margin, as a percentage of maximum demand, was 13 percent.
	During the year ended December 31, 1998, the sources of the Utility electric supply were hydro, 37 percent; coal, 45 percent; and purchased power, 18 percent. The cost of coal burned has been as follows:
	 Year Ended December 31 	 1998 	 1997 	 1996
	Average cost per million Btu's		$ 0.59	$ 0.59	$ 0.59
	Average cost per ton (delivered)		 9.99	 9.93	 10.06
	The Company's electric system forms an integral part of the Northwest Power Pool, which consists of the major electric suppliers in the Pacific Northwest region of the United States, in British Columbia, and also in parts of Alberta, Canada. The Company 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. The Company is also a member of the Western Systems Coordinating Council, organized by 84 member systems and 21 affiliates in the 14 western states, British Columbia, Alberta, and Mexico to assure reliability of operations and service to their customers. The Company participates in an interconnection agreement with Avista Corporation, IdaCorp, Inc., 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 that 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.
FERC has announced its intention to conduct a rulemaking during 1999 on FERC's authorities to require transmission owners to participate in regional transmission entities such as independent system operators (ISO) or independent transmission companies, "transcos". The Company will participate in the FERC rulemaking process and is evaluating possible participation in a regional transmission entity.
	Regardless of the timing of the sale of the Company's generating assets and power purchase and exchange contracts, the Company is obligated to continue to provide electric power supply through the transition period to customers in its service territory who have not chosen, or have not had an opportunity to choose to purchase energy from another power supplier. Such service will require the Company to have available a power supply sufficient to meet those customers' electric loads. The Agreement includes transition service agreements under which the Company will purchase electricity to supply customers in its service territory who have not chosen, or have not had an opportunity to choose to purchase energy from another power supplier throughout the transition period. Once the transition period is complete, the Electric Utility may be required to offer electric supply as the supplier of last resort for customers who have not chosen other suppliers. The Company anticipates that any costs related to this electric supply would be recovered through rates charged to such customers. Through December 1998, approximately 50 customers, representing approximately 10 percent of the Utility's pre-choice load has chosen alternate suppliers. See Part II, Item 8, "Financial Statements and Supplementary Data - Note 4 to the Consolidated Financial Statements".
	NATURAL GAS UTILITY: Natural gas supply requirements in 1998 totaled 19,961 Mmcf, of which 7,095 Mmcf were from third party contracts with Montana suppliers and 1,797 Mmcf from third party contracts with Canadian suppliers. A total of 11,069 Mmcf, or approximately 55.4 percent of the natural gas supply requirements for the year, was purchased from an unregulated subsidiary, Montana Power Gas Company (MP Gas). MP Gas has access to reserves in both Montana and Canada.
	Total volumes of natural gas transported were 27,368 Mmcf, 26,020 Mmcf, and 26,969 Mmcf for 1998, 1997, and 1996 respectively. The 1999 transportation volumes are anticipated to be 27,890 Mmcf. The Company filed a core aggregation pilot program (pilot program) in February 1998 with the Montana Public Service Commission (PSC), providing supplier choice for residential and small commercial/industrial customers. The pilot program
provided all of the Utility's core customers with an opportunity to purchase their gas supply from other sources beginning in November 1998. Approximately 6 percent of residential and small commercial/industrial customers have expressed an interest in supplier choice, but no contracts have been signed at this time. The regulated Natural Gas Utility will continue to provide gas transmission, storage, and distribution service to its customers.
	As a result of the natural gas restructuring order effective on November 1, 1997, natural gas customers with annual consumption of 5,000 dekatherms or more are eligible to be served through unbundled gas transportation service. Consequently, the number of customers previously receiving bundled service who have elected unbundled transportation service has increased from 24 to over 232. Substantially all of these customers obtain their supplies directly from other sources.
	Total 1999 natural gas requirements, estimated to be 20,580 Mmcf, are anticipated to be supplied from MP Gas and other purchase contracts. Approximately 30 percent of purchases under contracts with outside suppliers expire each year beginning in 1999 through 2002. As a result of the natural gas restructuring order, these contracts may not be renegotiated to the extent that the Gas Utility has less load due to customer choice.
	REGULATION AND RATES: The Company's public utility business in Montana is subject to the jurisdiction of the PSC. The PSC has jurisdiction over the setting of bundled retail electric and natural gas rates, electric distribution tariffs, gas transportation tariffs, issuance of securities and certain limitations on borrowing by the Company. The Federal Energy Regulatory Commission (FERC) also has jurisdiction over the Company, under the Federal Power Act, as a licensee of hydroelectric projects and as a public utility with respect to wholesale sales of electricity, unbundled transmission of electricity and interstate interruptible transportation of natural gas. The importation of natural gas from Canada requires approval by the Alberta Energy and Utilities Board, the National Energy Board of Canada, and the United States Department of Energy.
Montana's Electric Industry Restructuring and Customer Choice Act and Natural Gas Restructuring and Customer Choice Act providing for customer choice for electric and natural gas supply became law in May 1997.
	Also refer to Part II, Item 7, "Management's Discussion and Analysis of Financial Conditions and Results of Operations - Competitive Environment" and Part II, Item 8, "Financial Statements and Supplementary Data - Note 4 to the Consolidated Financial Statements" for further discussion on changes in utility regulation.
	COMPETITIVE ENVIRONMENT: Refer to Part II, Item 7, "Management's Discussion and Analysis of Financial Conditions and Results of Operations - Competitive Environment".
NONUTILITY OPERATIONS:
	OVERVIEW: The Company's Nonutility operations for coal, oil and natural gas, telecommunications, and independent power operations are principally operated under a holding company, Entech, Inc., a wholly owned subsidiary of the Company. Other Nonutility business is conducted by various subsidiaries, none of which is significant.
	COAL OPERATIONS: Coal operations are operated primarily conducted by Western Energy Company (Western) and Northwestern Resources Co. Western's Rosebud Mine is at Colstrip, Montana, in the northern Powder River Basin, where coal is surface-mined and, after crushing, sold without further preparation. Western's principal customers from this mine are the owners of the four mine-
mouth Colstrip units. These customers accounted for approximately 94 percent of 1998 coal sales volumes. The remainder of Rosebud coal was sold under spot- market sale agreements and contracts in Minnesota, North Dakota, and Montana. During 1998, Western mined and sold 10,499,000 tons, of which 3,547,000 tons were sold to the Company. Western's Rosebud Mine production is estimated to be 10,614,000 tons in 1999 and 10,761,000 tons in 2000.
Northwestern's Jewett Mine, located in central Texas, supplies surface- mined lignite under a long-term lignite sale agreement (LSA) to the two electric generating units, located adjacent to the mine, that are owned by Reliant Energy. Total deliveries in 1998 were 8,831,959 tons. The estimated production for 1999 and 2000 are 8,100,000 and 7,600,000 tons, respectively. After 2001, production is estimated to be approximately 8,000,000 tons annually. During 1998, Northwestern and Reliant Energy, formerly know as Houston Lighting & Power, signed a letter of intent regarding amendments to the LSA. This amendment allows Reliant Energy to blend petroleum coke with the lignite at a 20/80 ratio. The blending is contingent upon the receipt of permits from the Texas Railroad Commission. The total tons under contract did not change. Northwestern will produce the contracted tons over an extended period.
	OIL AND NATURAL GAS OPERATIONS: Oil and natural gas operations are operated primarily under North American Resources Company, MP Gas and Altana Exploration Co., all of which are United States subsidiaries, and Altana Exploration Ltd. and Canadian Montana Gas Company, both Canadian subsidiaries. Natural gas, natural gas liquids, oil commodity trading and marketing, and related energy services are provided by the Company's subsidiary, The Montana Power Trading and Marketing Company (MPT&M). MPT&M competes for former natural gas supply customers of the Company's Utility operations who have exercised choice. Oil and natural gas operations are engaged in exploration, production, gathering, processing, and marketing of oil and natural gas in the United States and Canada. U.S. producing oil and natural gas properties are principally located in the states of Wyoming, Colorado, Oklahoma, and Montana. Canadian properties are principally located in the Province of Alberta, Canada. A subsidiary has entered into agreements to supply 92 Bcf of natural gas to four co-generation facilities over a period of 6 to 12 years for which there is sufficient proven, developed and undeveloped reserves and controls related sales of production sufficient to supply all of the remaining natural gas required by those agreements. None of the reserves are dedicated to supply these agreements.
	Natural gas production in both the United States and Canada is currently sold pursuant to short-term, spot-market and long-term contracts. Approximately 95,981 Mmcf, or 81 percent of Canadian natural gas reserves, are dedicated to long-term contracts expiring at various times through 2005. In addition to serving these contracts, the Company intends to concentrate its efforts on natural gas production in support of the expanding market development objectives.
INDEPENDENT POWER OPERATIONS: Independent power operations develops, acquires, operates, maintains, and manages facilities and resources to provide electricity and other energy-related services.
	Colstrip 4 Lease Management Division sells the Company's 242 MW leased share of Colstrip Unit 4 generation principally to the Los Angeles Department of Water and Power and to Puget Sound Energy, Inc. under contracts with terms coexistent with the lease through December 29, 2010. The leasehold interest and its related assets and liabilities and sales contract obligations are intended to be sold to PP&L Global, Inc. with the regulated electric generating facilities and power purchase contracts.
	Continental Energy Services (CES) develops and invests in independent power projects. During 1998, CES sold its share of the Lockport Project in the state of New York and participated in a power purchase agreement settlement on another project in New York. The plant from this project is currently being dismantled and the partnership will be dissolved in 1999. CES currently holds ownership interests in five operating natural gas-fired projects located in Texas, Washington, and the United Kingdom, one heavy oil-fired project located in Jamaica and two natural gas-fired independent power projects under construction in Pakistan and Grimes County, Texas. CES, through a wholly owned subsidiary, is the managing general partner of a 255 MW project located in Texas. In addition, CES is participating with others in the development of a coal-fired project in India. Refer to Part I, Item 2, "Properties - Independent Power Properties".
	TELECOMMUNICATIONS OPERATIONS: The Company's telecommunications business, Touch America, develops, constructs, operates, and maintains a fiber-optic network and digital microwave facilities. Touch America also provides a full range of wholesale and retail telecommunications services including long-term capacity sales to other telecommunications carriers, long distance, Internet, and dedicated private line services, and equipment sales. Touch America offers telecommunications services in seven states and has staffed offices in Minneapolis, Minnesota; Bismarck, North Dakota; Billings, Bozeman, Helena, Butte, Great Falls, Kalispell, and Missoula, Montana; Boise, Idaho; Spokane and Seattle, Washington; Eugene, Oregon; Casper and Cheyenne, Wyoming; and Denver, Colorado. As Touch America's network expands, it expects to open new offices. The Company has also entered the wireless communications market through the use of its 24 Local Multipoint Distribution Services licenses and its 12 Personal Communications Services licenses.
Currently, Touch America's fiber network extends approximately 10,000 miles from Chicago, Illinois west to Seattle, south to Los Angeles, California, with both a coastal route via Portland, Oregon and Sacramento, California and an inland route via Boise, Salt Lake City, Utah, and Las Vegas, Nevada, and from Denver north through Wyoming and Montana to the Canadian border. At the end of 1998, 6,000 of the 10,000 miles were in service, and by mid-1999, the entire network is expected to be in service.
The Seattle to Los Angeles inland route was accomplished through a joint construction effort among Touch America, Williams Companies, and Enron Corp., known as the FTV partnership. Touch America served as the construction and services manager for the construction project. The segments from Las Vegas to Los Angeles and Seattle to Portland were acquired through a fiber swap. Some of the dark fiber (i.e., unlit fiber with no electronic equipment) on the route has been sold to other telecommunications companies, and some has been exchanged for fiber on other routes. The remaining fibers will be divided between the three partners, and Touch America will operate and maintain its portion.
In other exchange arrangements, Touch America received fiber on a coastal route from Portland through Sacramento to Los Angeles, and it received fiber from Minneapolis/St. Paul, Minnesota through Green Bay, Wisconsin to Chicago. In total, Touch America's current fiber network spans 14 states.
Touch America has plans for expansion that will extend the existing network by some 8,000 miles and give the Company a continental network by the end of 2000. Currently underway is an expansion project that extends from Salt Lake City through Wyoming to Denver and from Denver to Dallas, Texas through Amarillo, Texas. This expansion should be complete by the end of 1999 and will extend Touch America's reach to 16 states.
Touch America's network is comprised of up-to-date fiber technology and includes SL, SMF28, and LEAF fiber. The Company also has installed or is upgrading to Dense Wave Division Multiplexing (DWDM) technology, which greatly increases the capacity of each fiber strand.
	COMPETITIVE ENVIRONMENT: Current production from the Rosebud and Jewett Mines is sold under long-term contracts to mine-mouth customers. Western supplies Colstrip Units 1 through 4 under the terms of contracts obligating the Colstrip Units to purchase all of the fuel required by the plants from Western. Currently, all of the coal requirements for these units are supplied from the Rosebud Mine. The coal supply agreement between the Company and the owners of Colstrip Units 1 and 2 provides for a price re-opener in 2001. The Company and the owners of Colstrip Units 3 and 4, however, entered into an Amended and Restated Coal Supply Agreement dated August 28, 1998, and, among other contract amendments, eliminated future price re-openers for this coal supply agreement. The Company expects to profitably serve both of these contracts over their remaining lives. The Rosebud Mine has production capacity that exceeds the mine-mouth customers' fuel requirements. In the sale of this capacity, it faces competition from Montana and Wyoming Powder River Basin producers located south of the mine. These producers generally experience lower operating costs and the Wyoming coal also has a lower sulfur content than that from Rosebud. The Company, therefore, anticipates only modest contract sales and likely no significant spot market sales for the foreseeable future. The sale of the generation assets does not affect the terms of the coal supply agreements with Colstrip Units 1 through 4.
The Jewett Mine sells its entire production to the two 800 MW Limestone Units owned by Reliant Energy.
Also refer to Part II, Item 7, "Management's Discussion and Analysis of Financial Conditions and Results of Operations - Coal Operations" and Part II, Item 8, "Financial Statements and Supplementary Data - Note 2 to the Consolidated Financial Statements" for further information on the fuel supply agreements.
	The Nonutility oil and natural gas businesses compete with major oil and natural gas companies and other independent and individual producers and operators to acquire property, to develop, produce and market oil, natural gas and natural gas liquids and to contract for equipment and services. The Company believes it has production, development and long-term marketing capabilities, experience in acquiring properties, and the financial resources to enable it to compete effectively.
	Most of CES' current revenues are derived from long-term power supply contracts. Some long-term power supply contracts in the nonutility power industry are under pressure from customers to reconsider pricing. CES' strategy is to work with its partners and customers to attempt to mitigate effects of contracts which may reflect pricing that is higher than current market.
	The telecommunications business competes with major and regional companies to provide long distance, Internet, and private line network services, and telecommunication equipment sales and maintenance. In this competitive and evolving business, the telecommunication unit competes in part by constructing and maintaining a low cost fiber network.
ENVIRONMENT:
	For information on Environment see Part II, Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations - Environmental Issues."
EMPLOYEES:
	At December 31, 1998, the Company and its subsidiaries employed 2,906 persons, including 370 employees at the jointly owned Colstrip Units 1 through 4. Of the 2,906 persons, 1,060 are members of collective bargaining units consisting of 15 unions. Current union contracts will expire at various times during the next three years. It is expected that approximately 500 employees, union and non-union, may be directly affected by the sale of the Company's generating assets and the exit from electric trading and marketing business. See Part II, Item 8, "Financial Statements and Supplementary Data - Note 4 to the Consolidated Financial Statements" for further information regarding the sale.
FOREIGN AND DOMESTIC OPERATIONS:
	Financial information relating to the segment information for foreign and domestic operations and export sales other than the information previously disclosed regarding the Company's Canadian subsidiaries are not considered material.
ITEM 2.
ITEM 2. PROPERTIES
UTILITY OPERATIONS:
	The Company's Mortgage and Deed of Trust (Mortgage) imposes a first mortgage lien on all physical properties owned, exclusive of subsidiary company assets, and certain property and assets specifically excepted. The Company's use of the proceeds from the sale of its Montana generating facilities may be subject to restrictions imposed by the Mortgage.
	ELECTRIC PROPERTIES: The Company's Utility electric system extends through the western two-thirds of Montana. Generating capability is provided by four coal-fired thermal generation units, with total net capability available to the Utility of 683,000 kW, and 12 hydroelectric projects and one storage dam, with total net median water capability of 474,400 kW. See Part II, Item 8, "Financial Statements and Supplementary Data - Note 4 to the Consolidated Financial Statements". The thermal units are (1) Colstrip Unit 3, which has a net capability of 740,000 kW, of which the Company owns 222,000 kW, (2) Colstrip Units 1 and 2, with a combined net capability of 614,000 kW, of which the Utility owns 307,000 kW, and (3) the wholly owned 154,000 kW Corette Plant. Western supplies all of the Colstrip coal requirements under long-term contracts. The Corette Plant is supplied under a short-term contract from a Wyoming mine. Reliability of service is enhanced by the location of hydroelectric generation on two separate watersheds with different precipitation characteristics and by various sources of thermal generation.
	In addition to the Utility's hydroelectric and thermal resources, it currently receives electricity through 18 contracts totaling 353,300 kW of firm winter peak capacity. These contracts vary in type, size, seller, and ending dates. See Part II, Item 8, "Financial Statements and Supplementary Data - Notes 3 and 4 to the Consolidated Financial Statements" for more information concerning commitments and the Company's intended sale of its generation assets.
	Hydroelectric projects are licensed by the FERC under licenses that expire on varying dates through 2035. The Company is in the process of relicensing its nine dams located on the Missouri and Madison rivers. See Part II, Item 8, "Financial Statements and Supplementary Data - Note 2 to the Consolidated Financial Statements".
	At December 31, 1998, the Utility owned and operated 6,855 miles of transmission lines and 15,818 miles of distribution lines.
	The Company's transmission system serves a majority of the state of Montana. The system integrates generation located in both the Columbia River and Missouri River drainages and is directly interconnected with the transmission systems of three investor owned utilities and two federal power marketing agencies. The Company provides nondiscriminatory transmission services pursuant to an open access transmission tariff filed with the FERC.
	The following table represents average revenues received per kWh by customer classification for electricity from all sources for the years 1998, 1997, and 1996.
	 Year Ended December 31 Customer Classification	 1998 	 1997 	 1996
	Residential		$0.066	$0.064	$0.061 	Commercial		0.060	0.059	0.055 	Industrial		0.042	0.041	0.041 	Sales for Resale		0.027	0.019	0.018 	Government and Municipal		0.087	0.085	0.077
	NATURAL GAS PROPERTIES: The Utility currently produces minimal amounts of natural gas from fields in southern Montana and Wyoming to maintain natural gas storage leases and to supply fuel for electric generation. The Utility transferred significantly all of its natural gas production properties in the United States and all of its Canadian natural gas production properties to an unregulated subsidiary on November 1, 1997, as a result of the Company's natural gas restructuring filing with the PSC. The assets, liabilities, equity, and results of operations of the regulated Utility's Canadian subsidiary, Canadian-Montana Gas Company, Limited, have also been included in the unregulated oil and natural gas operations as of that date.
	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, 1998, the Gas Utility and its subsidiaries owned and operated 2,103 miles of natural gas transmission lines and 3,527 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 Part II, Item 8, "Financial Statements and Supplementary Data".
	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
1996		5,055	230	6,749	4,694	950	4,850 1997		3,764	292	8,290	3,402	679	7,132 1998		 - 	 - 	10,741	 - 	 - 	9,440
	The following table presents average revenues received per Mcf by customer classification for natural gas from all sources for the years 1998, 1997, and 1996. Revenues per Mcf are computed based on volumes at varying pressure bases as billed. 		 	 Year Ended December 31 Customer Classification	 1998 	 1997 	 1996
	Residential		$4.77	$4.72	$4.72 	Commercial		4.75	4.53	4.54 	Industrial		4.47	4.30	4.32 	Other gas utilities		4.06	4.04	3.41
NONUTILITY OPERATIONS:
	COAL PROPERTIES: Western leases and produces coal from Montana properties. Northwestern leases and produces lignite from properties in Texas.
Western's subsidiaries, Western SynCoal Company (SynCoal), and SynCoal Inc. own a patented coal enhancement process. SynCoal and SynCoal Inc. own the Rosebud SynCoal Partnership, which owns and operates a coal enhancement process demonstration plant at the Rosebud Mine.
	Western has coal mining leases covering approximately 508,287,000 proved and probable, and recoverable, tons of surface-mineable coal reserves averaging less than 1.6 pounds of sulfur dioxide per million Btu at Colstrip. Approximately 218,328,000 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 153,400,000 proved and probable, and recoverable, tons of surface-mineable lignite reserves. Northwestern has dedicated all of these reserves to Reliant Energy, which owns two electric generating units located adjacent to the mine.
	In addition, Northwestern has proved and probable and recoverable reserves totaling approximately 75,750,000 tons located in central Texas. These reserves are in close proximity to the Jewett Mine.
The Company, through its wholly owned subsidiary, North Central Energy owned approximately 36,000 acres of land in southern Colorado associated with a former coal mining operation. The improvements have been removed or sold and the land has been or is being reclaimed. The Company has sold approximately 31,300 acres and is currently negotiating the sale of the remaining property.
	OIL AND NATURAL GAS PROPERTIES: Information on the Nonutility natural gas and oil wells and the owned or leased acreage in which they are located, as of December 31, 1998, is presented below. 	United 	 States 		 Canada
Gross productive natural gas wells	1,459 	402 Net productive natural gas wells	1,065.40	308.95 Gross productive oil wells	84 	124 Net productive oil wells	83.35	56.73
Gross producing acres	652,580	232,730 Net producing acres	490,544	190,399 Gross undeveloped acres	503,487	304,302 Net undeveloped acres	347,680	234,123
	The wells located in Canada include multiple completions of 21 gross productive natural gas wells or 18.25 net productive gas wells. The U.S. wells listed above include multiple completions of 267 gross productive natural gas wells or 205 net productive natural gas wells, and 2 gross productive oil wells or 2 net productive oil wells.
The foregoing acreage located in the United States and Canada are primarily in the Rocky Mountain States and Alberta.
	During 1999, total exploration, acquisition, and development expenditures (expense and capital) are anticipated to be approximately $34,498,000 in the United States and approximately $20,493,000 in Canada.
	The following table presents information on Nonutility oil and natural gas exploratory and development wells drilled during 1998, 1997, and 1996.
	 United States 	 Canada
	 1998 	 1997 	 1996 	 1998 	 1997 	 1996
Net productive natural gas 	exploratory wells		0.96	1.86	0.33	3.34	4.30	0.55 Net productive oil 	exploratory wells		- 	1.00	- 	- 	- 	2.23 Net productive natural gas 	development wells		53.84	41.50	2.58	73.50	1.30	1.83 Net productive oil 	development wells		- 	2.87	- 	0.98	15.11	9.78 Net dry exploratory wells		1.13	0.34	1.75	0.50	1.13	0.50 Net dry development wells		0.45	0.25	1.81	7.00	- 	0.04
	For information on properties acquired, see Part II, Item 8, "Financial Statements and Supplementary Data".
No significant change has occurred and no event has taken place since December 31, 1998, which would materially affect the estimated quantities of proved reserves. For information pertaining to the net recoverable oil and natural gas reserves, see Part II, Item 8, "Financial Statements and Supplementary Data".
	All Nonutility natural gas volumes are at a pressure base of 14.73 psia at 60 degrees Fahrenheit.
	Nonutility oil and natural gas reserve estimates have not been filed with any other federal or any foreign government agency during the past twelve months. Certain lease information and well data, only with respect to owned wells, is filed with the Internal Revenue Service for tax purposes.
The following table presents information on produced oil and natural gas average sales prices and production costs in U.S. dollars for 1998, 1997, and 1996.
NOTE: Natural gas production was converted to barrel of oil equivalents based on a ratio of 6 Mcf to 1 barrel of oil. 	 Nonutility oil, natural gas, and natural gas liquids production was sold under short-term and long-term contracts at posted prices or under forward market arrangements. From 1997 to 1998, Nonutility average sales prices changed due to fluctuations in the market. Nonutility average production cost in the U.S. decreased as a result of the prior year inclusion of non-recurring environmental and compliance work required on the processing facilities.
During 1997 the oil and gas operations completed two major acquisitions. The Company purchased Vessels Energy's (Vessels) oil and gas assets in Colorado's Denver-Julesburg (D-J) Basin. With the completion of this acquisition late in 1997, annual hydrocarbon production in the D-J Basin increased from 3,800 Mmcf of natural gas to approximately 5,600 Mmcf. The acquisition included more than 565 wells, an 800-mile gas-gathering system, and a natural gas processing and fractionating plant. The plant and gathering system has been integrated with the Company's existing Fort Luption plant.
In 1997, the Company, through a Canadian subsidiary, purchased the stock of Questar Exploration Incorporated. In January 1998, these assets were fully integrated into the Canadian subsidiary. This acquisition is expected to increase hydrocarbon production in Alberta by 6,144 Mmcf and 298,000 barrels of natural gas liquids in 1998.
	INDEPENDENT POWER PROPERTIES: Independent power operations sell power from the Company's 242 MW Colstrip 4 leased interest and associated common and transmission facilities. The leasehold interest and its related assets and liabilities and sales contract obligations are intended to be sold with the regulated electric generating facilities and power purchase contracts.
The Company, through its independent power operations, also partially owns or has contract rights in a number of Nonutility power generation projects.
TELECOMMUNICATIONS PROPERTIES: Touch America has an approximately 10,000-mile fiber-optic network ranging from Chicago west to Seattle, south to Los Angeles, with both a coastal route via Portland and Sacramento and an inland route via Boise, Salt Lake City, and Las Vegas, and from Denver north through Wyoming and Montana to the Canadian border. Approximately 1,200 miles of the network from Denver, Colorado to the Canadian border is held through an indefeasible right of use (IRU) which extends through December 2010 and is subject to two ten year extensions, at Touch America's option. Approximately 2,000 miles of the network from Seattle, to St. Paul, is held through an IRU extending through early 2022. Touch America continues to expand its network capacity. The additional miles of fiber network through a joint construction effort among Touch America, Williams Companies, and Enron Corp. widened Touch America's service territory to 14 states. The Company owns 12 Personal Communication Services (PCS) licenses in 12 marketing areas between Minneapolis, and Seattle, along the route of the fiber-optic network, which presents an opportunity for wireless telephone service in that region. In February 1998, the Company also acquired 24 Local Multipoint Distribution Services (LMDS) licenses, in 24 marketing areas along the Seattle to Minneapolis route and the Montana to Denver route.
Touch America's network is comprised of up-to-date fiber technology and includes LS, SMF28, and LEAF fiber. The Company also has installed or is upgrading to Dense Wave Division Multiplexing (DWDM) technology, which essentially quadruples the capacity of each fiber strand.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
	The Company and North American Resources Company (NARCO), a wholly owned subsidiary of Entech, are defendants in litigation initiated in October, 1995 by Paladin Associates, Inc. (Paladin), a natural gas broker transporting natural gas on the Company's pipeline system. The litigation is pending in the federal district court in Montana. Paladin alleges that the Company, NARCO, and Northridge Petroleum Marketing, a Canadian corporation, violated antitrust law, breached contractual obligations and committed torts for which Paladin is entitled to collect monetary damages as remedies. Paladin is seeking actual damages it estimates to be approximately $10,000,000, which if trebled would be $30,000,000. In addition, it seeks punitive damages regarding its tort claims in an amount the court may determine.
	The Company and NARCO deny Paladin's allegations. Because the alleged wrongful and illegal actions were subject to state and federal regulation, the Company will assert a "state action" defense. Summary judgment motions and motions to limit issues at the trial are pending the Court's determination. Trial is scheduled in January 2000. While it is confident regarding this matter, the Company cannot predict the ultimate outcome.
	Litigation involving Entech's wholly owned subsidiary, Northwestern Resources Company (Northwestern), and TCA Building Company (TCA) regarding the validity of certain lignite leases in the "Donie Block" at the Jewett Mine is pending. TCA initiated a state action against Northwestern in Texas district court in 1995. Among TCA's allegations, were allegations that Northwestern breached an obligation to assist TCA in mining its property; that Northwestern's alleged promises underlying the obligation were tainted by fraud; and, that Northwestern wrongfully interfered with TCA's solicitation of bids to sell lignite. TCA also alleged that Northwestern otherwise wrongfully interfered with a contract and a business opportunity for TCA to sell lignite. TCA sought damages of between $8,000,000 and $13,500,000, in addition to exemplary damages.
	The Texas district court granted Northwestern's motion for summary judgment on all of TCA's claims, except the claim that Northwestern wrongfully interfered with TCA's efforts to solicit bids from mining companies that would mine its lignite. Northwestern plans to file a new motion for summary judgment. If the court denies Northwestern's motion, trial will occur in the fall of 1999. Northwestern is confident regarding its case, however, it cannot predict the ultimate outcome of this matter.
	Refer to Part II, Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations - Environmental Issues" and to Part II, Item 8, "Financial Statements and Supplementary Data - Note 2 to the Consolidated Financial Statements" for further information pertaining to legal proceedings.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
	None.
EXECUTIVE OFFICERS OF THE REGISTRANT
The Montana Power Company Officers:
	In 1998, R. P. Gannon, 54, was elected Chairman of the Board and Chief Executive Officer. He had previously served as Chief Executive Officer and President from 1997 - 1998, and as Chief Operating Officer - Utility Operations from 1992-1996.
	In 1996, J. P. Pederson, 56, was elected Vice President, Chief Financial and Information Officer. He had previously served as Vice President and Chief Financial Officer from 1991-1996.
	In 1996, P. K. Merrell, 46, was elected Vice President, Human Resources and Secretary. She had previously served as Vice President and Secretary from 1993-1996 and as Secretary from 1992-1993.
	In 1991, M. E. Zimmerman, 50, was elected Vice President and General Counsel.
	In 1996, D. S. Smith, 55, was elected Controller. He had previously served as Controller for Entech from 1988-1996.
	In 1996, E. M. Senechal, 49, was elected Treasurer. She had previously served as Vice President and Treasurer for Entech from 1984-1996.
	In 1997, W. S. Dee, 58, was elected Vice President, Marketing. He had previously been employed as a consultant with Leo Burnett, Inc., an advertising agency, from 1993 to 1996.
Energy Services:
	In 1996, J. D. Haffey, 53, was elected Executive Vice President and Chief Operating Officer. He had previously served as Vice President - Administration and Regulatory Affairs from 1993-1996 and as Vice President - Regulatory Affairs for the Utility Division from 1987-1993.
	In 1996, D. A. Johnson, 53, was elected Vice President, Distribution Services. He had previously served as Vice President - Utility Services from 1993-1996 and as Vice President - Gas Supply and Transportation for the Utility Division from 1984-1993.
	In 1996, P. J. Cole, 41, was elected Vice President, Business Development and Regulatory Affairs. He had previously served as Treasurer for the Utility Division from 1993-1996 and as Assistant Treasurer from 1992-1993.
	In 1997, W. A. Pascoe, 42, was elected Vice President, Transmission Services. He had previously served as Assistant Vice President, Transmission Services from May 1996 to April 1997 and as Manager of Transmission and Power Transactions from 1990-1996.
Energy Supply:
	In 1996, R. F. Cromer, 53, was elected Executive Vice President and Chief Operating Officer. He had previously served as President and Chief Operating Officer - Continental Energy Services, Inc. from 1992-1996.
	In 1996, M. C. Enterline, 49, was elected Vice President - Colstrip Project Division for the Energy Supply Division. He had previously served as Vice President, Colstrip Project Division from 1995-1996, as Manager of Business and Change Management from 1994-1995 and as Superintendent of Colstrip Units l and 2 from 1988-1994.
Telecommunications:
	In 1998, M. J. Meldahl, 49, was elected Executive Vice President and Chief Operating Officer. He had previously served as Vice President, Communication Services, and Vice President, Technology Division - Entech from 1988-1996.
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 1998 and 1997. The number of common shareholders of record on December 31, 1998, was 38,790.
				Dividends 				Declared 				 Per 	 1998 	 High 	 Low 	 Share
	1st quarter	$ 36.813	$ 29.063	$ 0.40 	2nd quarter	38.500	33.813	0.40 	3rd quarter	45.250	33.250	0.40 	4th quarter	57.125	41.125	0.40
				Dividends 				Declared 				 Per 	 1997 	 High 	 Low 	 Share
	1st quarter	$ 22.625	$ 21.000	$ 0.40 	2nd quarter	23.312	21.000	0.40 	3rd quarter	26.625	21.000	0.40 	4th quarter	32.250	24.125	0.40
ITEM 7.
ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Safe Harbor for Forward-Looking Statements:
	The Company is including the following cautionary statements to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf, of the Company in this Annual Report on Form 10-K. Forward-looking statements include statements concerning plans, objectives, goals, strategies, future events or performance and underlying assumptions and other statements, which are other than statements of historical facts. Such forward-looking statements may be identified, without limitation, by the use of the words "anticipates", "estimates", "expects", "intends", "believes," and similar expressions. From time to time, the Company or one of its subsidiaries individually may publish or otherwise make available forward- looking statements of this nature. All such forward-looking statements, whether written or oral, and whether made by or on behalf of the Company or its subsidiaries, are expressly qualified by these cautionary statements and any other cautionary statements which may accompany the forward-looking statements. In addition, the Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date hereof.
	Forward-looking statements made by the Company are subject to risks and uncertainties that could cause actual results or events to differ materially from those expressed in, or implied by, the forward-looking statements. These forward-looking statements include, among others, statements concerning the Company's revenue and cost trends, cost recovery, cost-reduction strategies and anticipated outcomes, pricing strategies, planned capital expenditures, financing needs, and availability, changes in the utility industry and the impacts of the year 2000 issue. Investors or other users of the forward- looking statements are cautioned that such statements are not a guarantee of future performance by the Company and that such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in, or implied by, such statements. Some, but not all, of the risks and uncertainties include general economic and weather conditions in the areas in which the Company has operations, competitive factors and the impacts of restructuring in the electric, natural gas and telecommunications industries, sanctity and enforceability of contracts, market prices, environmental laws and policies, federal and state regulatory and legislative actions, drilling successes in oil and natural gas operations, changes in foreign trade and monetary policies, laws and regulations related to foreign operations, tax rates and policies, rates of interest and changes in accounting principles or the application of such principles to the Company.
Results of Operations:
	The following discussion presents significant events or trends which have had an effect on the operations of the Company during the years 1996 through 1998 or which are expected to have an impact on operating results in the future.
Net Income Per Share of Common Stock:
The Company's net income available for common stock increased to $161,930,000 in 1998 compared to $124,942,000 and $111,028,000 in 1997 and 1996, respectively. The following table shows the sources of consolidated net income on a basic per share basis.
		 Year Ended December 31 		 1998 	 1997 	 1996
	Utility Operations	$ 0.94	$ 1.08	$ 1.13 	Nonutility Operations	 2.01	 1.21	 0.90
	Consolidated	$ 2.95	$ 2.29	$ 2.03
1998 Compared to 1997
	Consolidated net income for the year ended December 31, 1998 was $2.95 per share, an increase of 66 cents or 29 percent over 1997 earnings of $2.29 per share.
	The financial performance in 1998 reflects the Nonutility business successes the Company had, which significantly offset the impacts of utility deregulation and very weak oil and gas prices. The independent power and telecommunications businesses provided a significant increase in annual earnings. Besides the impact of deregulation, the Utility operations were adversely affected by weather that was 6 percent warmer than normal.
	Approximately 61 cents of the fourth-quarter earnings resulted from two events. An arbitration panel ruled that the Bonneville Power Administration breached the power purchase agreement with an independent power project at Frederickson, Washington, in which the Company was an investor, resulting in receipt of about $44,000,000. The sale of the Company's interest in the Lockport, New York project netted approximately $14,000,000.
	Increased rates, general business growth, and increased secondary sales resulted in an increase of $17,000,000 in electric revenues, while natural gas revenues decreased by $15,000,000 due mostly to customer choice and warmer weather. Although lower maintenance expenses reduced power-supply costs, the Utility also was affected by charges associated with curtailment of a benefit plan and a writedown of land, which had been held for future generating plant construction.
	Nonutility earnings reflected the independent power transactions mentioned earlier, as well as the settlement in the third quarter with a power purchaser which increased earnings by approximately 16 cents per share.
	Touch America, the Company's telecommunications subsidiary, recorded $11,000,000 in gains from sales of dark fiber on its share of Portland to Los Angeles expansion. Revenues from telecommunications operations increased to nearly $100,000,000 from approximately $48,000,000 last year as a result of a full year's operation of its expanded fiber-optic network linking Seattle and Minneapolis-St. Paul and Denver to Canada, dark fiber sales and increased long- distance revenue.
	Coal tonnage sold increased by 6 percent, but prices were relatively flat and higher revenues were mostly offset by increased operating expenses.
	Oil and gas earnings declined when compared with 1997 primarily due to production constraints and prices well below 1997 levels.
1997 Compared to 1996
	Consolidated net income for the year ended December 31, 1997 was $2.29 per share, an increase of 26 cents over 1996 earnings of $2.03 per share.
Net gains from the sales of non-strategic oil, natural gas and coal properties, and an investment in a Brazilian gold mine contributed significantly to 1997 Nonutility increased earnings. Also, earnings from telecommunications operations increased because the Company began receiving revenues from its expanded fiber-optic network late in the third quarter. Increased earnings from coal operations due to higher sales volumes to Colstrip Units 3 and 4 were more than offset by price reductions resulting primarily from a settlement with Puget Sound Energy (Puget). Earnings from independent power operations decreased primarily due to reduced long-term power sales revenues resulting from the Puget settlement and the absence of a gain recognized in 1996 on the sale of a portion of an asset. Nonutility earnings also benefited from the settlement of a long-standing income tax dispute with the Internal Revenue Service (IRS).
Utility earnings decreased 5 cents per share in 1997 due primarily to weather related reductions in general business revenues and higher power supply costs resulting from increased steam plant maintenance, power purchases from qualifying facilities and the settlement of a power supply contract dispute. These negatives were partially offset by higher rates, customer growth, the expiration in 1996 of two higher-priced power purchase contracts, and the absence of severance costs recorded in the fourth quarter of 1996. The income tax settlement mentioned above also positively impacted the Utility.
RECENT DEVELOPMENTS:
? Montana's Electric Industry Restructuring and Customer Choice Act (Electric Act) and Natural Gas Restructuring and Customer Choice Act (Gas Act) became law in May 1997. ? In November 1997, significantly all of the Utility natural gas production assets were transferred to an unregulated affiliate. A fixed-price supply contract through 2002 between the unregulated gas supply division and the regulated distribution division to serve the remaining customers who have not chosen other suppliers was implemented. ? In July 1998, the Company and the owners of Colstrip Units 3 and 4 generating plants settled coal contract disputes and future coal price reopeners. ? In August 1998, the Company announced it is exiting the electric commodity trading and marketing businesses, but will continue natural gas and natural gas liquids commodity trading and marketing. ? In November 1998, the Company announced that it had entered into an agreement (Agreement) to sell the Company's interest in 12 of its 13 Utility hydroelectric facilities, all four coal-fired thermal generating plants, a Nonutility leasehold interest in Colstrip Unit 4, a power purchase contract with Basin Electric Power Cooperative (Basin) and two power exchange agreements. ? In December 1998, a special purpose entity (SPE) that is a wholly owned subsidiary of the Company issued $62,700,000 of asset-backed securities, known as transition bonds. ? In December 1998, the Company resolved a dispute with the purchaser of lignite from the Jewett Mine involving the price of lignite and whether other fuels could be substituted for lignite. ? In January 1999, the Company received and recorded $257,000,000 representing prepayment of all amounts due for the remaining initial term of one telecommunications contract.
See Item 8, "Financial Statements and Supplementary Data - Notes 4 and 9 to the Consolidated Financial Statements" for further information.
In 1998, the Company received 45 percent of its revenues and 33 percent of its net income from regulated utility operations compared to 55 percent of
revenues and 49 percent of net income in 1997. The Company's diverse unregulated businesses, engaged in coal, oil and natural gas, independent power and telecommunications operations provided 55 percent of revenues and 67 percent of net income in 1998 compared to 45 percent of revenues and 51 percent of net income in 1997.
With the sale of the Company's interest in its electric generating facilities and the exit from the electric trading and marketing business, the Company no longer will be primarily a vertically integrated electric and natural gas utility. The Company expects to maintain its traditional regulated transmission and distribution utility businesses in Montana, the coal and lignite mines that serve mine-mouth generating plants, the independent power investments and operations and the natural gas exploration, development, production, trading, and marketing. The Company will also continue to invest in new opportunities such as telecommunications.
Competitive Environment: Utility Changes
Many state legislatures are considering the introduction of competition in the electric and natural gas businesses. The Company's regulated electric and natural gas businesses are already transitioning to competition in accordance with the Electric Act and the Gas Act, which became law in May 1997. The move to competition provides for customer choice to wholesale and retail customers for energy commodity and related services.
Electric Utility
General - The Electric Act provided for choice of electricity supply for the Company's large industrial customers by July 1, 1998, for pilot programs for residential and small commercial customers beginning November 2, 1998, and for all customers no later than July 1, 2002. Through December 1998, approximately 50 customers, representing approximately 10 percent of the Utility's pre-choice load have chosen alternate suppliers. Transmission and distribution services will remain fully regulated by Federal Energy Regulatory Commission (FERC) and/or the Montana Public Service Commission (PSC). The Electric Act also defines the PSC's role in regulating distribution services, licensing suppliers in the state, and promulgating rules regarding anti- competitive and abusive practices.
Generation and Supply - Proceeds from the sale of the interests in the generating plants, and the Basin and exchange contracts will vary depending upon various factors, and are anticipated to be between $740,000,000 and $988,000,000. These factors include the amount of the Company's related transmission facilities included in the sale and the sales by other parties of their interests in the Colstrip Units.
Based on the Company's current estimate of proceeds and carrying value of the Nonutility assets related to the Colstrip Unit 4 leasehold interest, the Company expects to recognize an immaterial gain on the sale. The leasehold interest is currently accounted for as an operating lease with annual lease payments of approximately $32,000,000 over the remaining term of the lease.
With respect to the sale of the regulated generation assets, the Company first expects to recover the book value of those assets, estimated to be $550,000,000 and the costs of the sale transaction. Proceeds in excess of the book value and transaction costs are expected to reduce the amounts to be collected from ratepayers in the form of competitive transition charges (CTC). Included in the CTC's are the power purchase contracts with qualifying facilities (QF) which could result in above-market costs currently estimated between $300,000,000 and $500,000,000 throughout their duration, the
generation regulatory assets which are currently estimated at $150,000,000 and the above-market generation costs over the transition period, if any. The divestiture of these generating plants and the sale of the contract for purchased power from Basin also will help to largely resolve issues associated with the Company's transition costs in a filing currently before the PSC.
The Company is currently evaluating options for dealing with the QF contracts, which were not included in the sales agreement. Divestiture of these QF contracts could take the form of a buy-down, buy-out or a restructuring of the contract. The lowest cost option with the most favorable terms will be selected in this process. Owners of the QF contracts must, by contract, approve any reassignment of the contract and FERC approval may also be necessary. Since recovery of above-market qualifying facility power- purchase contract costs was specifically provided in the legislation, the Company does not expect the exclusion of these contracts from the sale to have a material impact on results of operations.
The Company is also evaluating potential options with regard to the Milltown Dam, which was not included in the sales agreement. The Company is a Potentially Responsible Party (PRP) for environmental remediation at the Milltown Dam Site, where toxic heavy metals are in the silts resting behind the dam. However, because of federal legislation specifically regarding Milltown, the Company's position is that it has no responsibility for any remediation of the alleged releases under CERCLA.
The generation sale agreement includes transition service agreements under which the Company will purchase electricity to supply customers in its service territory who have not chosen, or have not had an opportunity to choose to purchase energy from another power supplier throughout the transition period. Once the transition period is complete, the Electric Utility may be required to offer electric supply as the supplier of last resort for customers who have not chosen other suppliers. The Company anticipates that any costs related to this electric supply would be recovered through rates charged to those customers.
The regulated generation assets to be sold currently comprise approximately $500,000,000 of the Utility's plant in service upon which it was allowed to earn a return of approximately 9 percent. Actual after-tax rate of return earned on the Company's electric plant in service was approximately 8.5 percent for the year ended December 31, 1998. However, since specific classes of assets cannot be separated in a regulated environment with fully bundled rates charged to customers, the Company cannot accurately estimate the separate results of operations for these generation assets.
The Company is evaluating numerous possible uses for the proceeds realized from the sale. Proceeds could be used to reduce outstanding debt, buy back a number of the Company's outstanding common or preferred shares of stock or proceeds up to the book value of the assets sold may be invested in any of the Company's existing business segments or new ventures. The Company's Mortgage and Deed of Trust imposes a lien on all physical properties including the generation assets and pollution control equipment on some of the thermal generating facilities, therefore, restrictions may exist on the use of proceeds.
Although the sale is subject to the satisfaction of various conditions and the receipt of required regulatory approvals, the Company anticipates this transaction will be completed by the end of 1999.
The Company has several commitments to sell electricity under contracts, which have terms expiring over the next six years. One such contract includes a fixed-price for a portion of the deliveries. When the sale of the Company's generation assets is finalized, and to the extent this contract is not
addressed in the electric restructuring transition process, the Company will be subject to the commodity price risks associated with supplying that portion of the contract. The Company is currently evaluating the potential options related to this contract. However, due to the uncertainties relating to the supply requirements under the contract, the timing of sale of the generation assets and the eventual outcome of the electric restructuring process, the Company is unable at this time to determine the potential future impacts of this contract on the Company's results of operations.
See Item 8, "Financial Statements and Supplementary Data - Notes 3 and 4 to the Consolidated Financial Statements" for further information.
Transmission -- In 1996, the FERC issued Order Nos. 888 and 889 requiring Open-Access Non-Discriminatory Transmission Services by Public and Transmitting Utilities, and stating standards of conduct regarding open access. These orders require public utilities owning transmission lines to file open-access tariffs making transmission service available to all buyers and sellers of wholesale electricity; require utilities to use the tariffs for their own wholesale sales and purchases; and allow utilities to recover wholesale stranded costs, subject to certain conditions.
The Company's FERC open-access transmission tariffs became effective in July 1996. In January 1997, the Company adopted Standards of Conduct and established an Open-Access Same-time Information System (OASIS) to comply with FERC Order No. 889. The Company provides nondiscriminatory transmission services pursuant to this open access transmission tariff filed with the FERC.
FERC has announced its intention to conduct a rulemaking during 1999 on FERC's authority to require transmission owners to participate in regional transmission entities such as an independent system operators (ISO) or independent transmission companies.
Distribution -- Distribution service will continue to be regulated by the PSC and provided by the Company's regulated Distribution operations. The Company anticipates competition for these services from large customers bypassing the Company's system and municipalities as well as on-site or distributed generation.
Wholesale -- The Electric Utility currently provides wholesale service to Central Montana Electric Power Cooperative, Inc. (Central), which manages a contract for purchases of power from the Electric Utility for a group of Montana cooperatives. Central has terminated its contract with the Company, effective June 2000, and will acquire its energy from another supplier. Central's 120 MW load approximates 6 percent of the Company's pre-choice system load.
Natural Gas Utility
General - The changes which are occurring on the Company's natural gas business will have a significant operational impact on the Company as it faces greater competition for resources and for customers. Competitors include privately owned independent natural gas producers and suppliers, and other investor-owned utilities and their unregulated subsidiaries.
Because the Utility's investment in natural gas production properties has been removed from rate base, there will be a corresponding decrease in Utility operating income. When combined with other items in the filing, the November 1997 PSC restructuring order resulted in a net reduction in annual natural gas revenues by $2,800,000, or 2.3 percent, and froze base rates for two years. A non-bypassable Universal System Benefits Charge for public purpose programs was also implemented.
The Company does not anticipate a materially negative impact on earnings due to the reduction in natural gas supply revenues from customers choosing other suppliers, since the decrease is expected to be offset by reduced supply costs, CTC charges, transportation and distribution revenues and transition bond financing savings. However, there can be no assurance that such trends will not have an adverse impact on the Company's Utility natural gas business in the future.
The Gas Act allows utilities to voluntarily offer customers choice of natural gas supply and authorizes the use of transition bonds as a method of financing transition obligations at lower costs. The Gas Act also defines the role the PSC will have in regulating transmission and distribution services, licensing suppliers in the state, and promulgating rules regarding anti- competitive and abusive practices.
Production -- As previously discussed, in 1997, the Company's unregulated Supply Division assumed ownership of significantly all of the natural gas production assets, except delivered gas purchase contracts, which have been retained by the regulated Natural Gas Utility. The difference between book value and the agreed-upon transfer value, and the regulatory assets associated with natural gas production are being recovered over 15 years from transmission and distribution customers as a component of CTC charges. At December 31, 1998, approximately $56,000,000 of CTC charges had not yet been collected from customers.
As a result of the transfer of Utility natural gas production assets discussed previously, the assets, liabilities, equity, and results of operations of the regulated Utility's Canadian subsidiary, Canadian-Montana Gas Company, Limited, have been included in the unregulated oil and natural gas operations as of that date. Production from these transferred properties is now sold in large part back to the Utility distribution operations under a fixed price contract through the transition period ending July 1, 2002. After this transition period, the contract terminates and production will be sold in the competitive market in the unregulated operations.
Transmission, Storage and Distribution -- Transmission, storage, and distribution services will remain regulated, and rates for such services will continue to be subject to approval by the PSC and/or FERC.
UTILITY OPERATIONS:
	Weather affects the demand for electricity and natural gas, especially among residential and commercial customers. Very cold winters increase demand, while mild winter weather reduces demand. The weather's effect is measured using degree-days. A degree-day is the difference between the average daily actual temperature and a baseline temperature of 65 degrees. Heating degree- days result when the average daily actual temperature is less than the baseline. As measured by heating degree-days, the 1998 temperatures for the Company's service territory were 6 percent warmer than 1997 and 6 percent warmer than the historic average. Temperatures in 1997 were 10 percent warmer than 1996 and comparable to the historic average.
Weather, streamflow conditions, and the wholesale power markets in the Northwest and California influence the Company's electric wholesale revenues, power-purchase expenses and output of thermal generation. Regional opportunity purchased-power prices were higher in 1998 than 1997 and consequently, the Company did not displace its thermal generation as it has in prior years. Margins on off-system sales are tightening as competition among suppliers increases.
Accounting for the Effects of Regulation:
	For its regulated operations, the Company follows Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." As a result, the Company has recorded regulatory assets and liabilities that are intended to be recognized in expenses and revenues in future periods. Should any portion of these operations cease to meet the criteria of SFAS No. 71 for various reasons, including changes in regulation or a change in the competitive environment for those operations, the Company would discontinue the application of SFAS No. 71 for that portion of the operations for which the statement no longer applied. If the Company was to discontinue application of SFAS No. 71 for all or a portion of its operations, the regulatory assets and liabilities related to those portions would have to be eliminated from the balance sheet and included in income in the period when the discontinuation occurred unless recovery of those costs was provided through rates charged to those customers in a portion of the business that remains regulated. In conjunction with the ongoing changes in the electric and natural gas industries, the Company will continue to evaluate the applicability of this accounting principle to those businesses.
As a consequence of the issuance by the PSC of the natural gas restructuring order and the related transfer of significantly all of the Utility natural gas production assets to the Company's unregulated operations, the Company's natural gas production assets were removed from SFAS No. 71 accounting in the fourth quarter of 1997. Recovery of the Company's existing natural gas production related regulatory assets and the difference between book value and the agreed-upon transfer value was provided in the PSC order as competitive transition charges (CTC). Accordingly, the CTC's are currently being recovered through rates over a 15-year period. Therefore the discontinuance of SFAS No. 71 for these assets did not have a material impact on the results of operations for 1997.
The timing of the removal of the electric generating assets from SFAS No. 71 is expected to coincide with the conclusion of the sale of the assets, which is anticipated to be completed by the end of 1999. The Company expects a decision on the remaining issues, including the amount of transition costs, once the sale is completed. Recovery of existing regulatory assets related to electric generation, subject to regulatory review, is provided in the electric restructuring legislation. Based upon its anticipated recovery of these regulatory assets, the Company believes that the discontinuation of regulatory accounting for the generation assets will not have a material impact on the Company's financial position or results of operations. See Item 8, "Financial Statements and Supplementary Data - Notes 1 and 4 to the Consolidated Financial Statements".
	Revenues from general business customers increased during the period primarily due to higher rates. As a result of electric deregulation, beginning July 1, 1998, electric trading activity, including buying and selling of electricity in the secondary markets, was conducted as a Nonutility activity. However, sales of electricity generated by the Company, in excess of the needs for core customers, continue to be reflected in "sales to other utilities" in the table above.
	Sales to other utilities increased as a result of an increase in average prices and increased steam generation due to decreased plant maintenance. This increase was despite a decrease in volumes sold due to the transfer of the electric trading activity to Nonutility operations in the third quarter of 1998.
	Other revenues increased as a result of an actuarial pension plan adjustment along with increased secondary sales.
	Power supply expenses decreased primarily due to lower steam maintenance, which was partially offset by increased purchased power costs. Although less power was purchased through electric trading activities as a result of the transfer of this electric trading activity to Nonutility operations, purchased power costs increased due to higher prices.
	Increased selling, general and administrative (SG&A) expenses resulted primarily from increased outsourcing costs and higher benefit charges associated with curtailment of a benefit plan. Partially offsetting the increase was the absence of severance costs in the current year. Depreciation expense increased primarily due to the write-down of land held for future use and software costs in accordance with SFAS No. 121.
Revenues from general business customers increased in 1997 primarily due to higher tariff rates and customer growth. A weather-related reduction in volumes sold moderated this increase. Reduced sales to other utilities resulting from the expiration of a high-priced firm sales contract in the second quarter of 1996 were partially offset by higher prices and greater volumes sold in the wholesale electric market. An actuarial pension plan adjustment decreased other revenues as well as SG&A expenses.
Steam generation expenses were up in 1997 due to additional maintenance costs at the Corette plant. Decreases in purchases and other power supply expenses were mainly related to the expiration of two high-priced firm purchase contracts in the first half of 1996 and reduced opportunity purchase prices. Partially offsetting these decreases were higher qualifying facility rates, the settlement of a supply contract dispute and the absence of a 1996 credit from a third party who delivers energy to the Company's customers. Increased SG&A expenses resulted primarily from increased consulting and computer upgrades, reduced billing to third parties and marketing costs previously classified as other operating expenses. The pension plan adjustment mentioned above and the absence of 1996 permanent employee reduction costs moderated the SG&A expense increase. Depreciation expense increased as a result of greater plant investment and a mid-1996 change in the PSC-approved depreciation rates.
	Natural gas revenues, excluding gas supply cost revenues, decreased in 1998 primarily due to a weather related reduction in volumes sold. Slightly higher tariff rates and customer growth partially moderated the revenue decrease. A decrease in other revenues, due to the November 1997 restructuring of the natural gas utility and an increase in gas cost refunds to the customer, was partially offset by an increase in transportation revenue primarily as a result of a PSC order allowing natural gas customers with annual loads greater than 5,000 dekatherms (Dkt) the right to choose their own supplier effective November 1, 1997.
The restructuring of the natural gas utility also affected its operating results for the period. In November 1997, significantly all of the Company's regulated natural gas production assets were transferred to its Nonutility affiliate, MP Gas. Since that time, operating expenses related to the transferred assets have been included in the Company's Nonutility oil and natural gas operations. The absence of these expenses, which are now recognized in the Nonutility operations, resulted in reduced non-gas supply cost revenues and expenses and other production, gathering and exploration costs.
As a result of the restructuring mentioned above, the Utility has contracted to purchase most of its gas from its Nonutility affiliate. The contract price includes costs associated with the transferred assets and returns on those assets. Gas cost revenues and expenses, which are always equal due to regulated rate and accounting procedures, increased throughout 1998 due to the new purchase contract. Amortizations of prior period under- collections also contributed to the increase.
Higher SG&A expense for the period resulted primarily from increased amortizations of regulatory assets, which are currently being collected in rates, as well as higher outsourcing charges.
Depreciation, depletion, and amortization decreased due to the transfer of the natural gas production properties as discussed above.
Natural gas revenues, excluding gas supply cost revenues, decreased in 1997 primarily due to a weather related reduction in volumes sold. Slightly higher tariff rates and customer growth partially moderated the revenue decrease. An actuarial pension plan adjustment decreased other revenues as well as SG&A expenses. This SG&A adjustment, however, was more than offset by increased consulting and computer upgrades which were moderated by the absence of 1996 permanent employee reduction costs.
Other Income and Expense, Income Taxes and Preferred Dividends:
1998 Compared to 1997
	Interest expense increased in 1998 due to additional long-term borrowing and interest accrued on the Kerr Project mitigation liability as well as interest on a federal income tax audit. This was partially offset by a decrease in short-term borrowing and the absence of interest paid in 1997 in conjunction with a contract settlement. Decreases in other income related to interest income on the 1997 settlement of a dispute with the IRS which was partially offset by the 1997 costs associated with the Flint Creek Dam transfer to Granite County, Montana.
	Income tax expense decreased in 1998 as a result of lower before-tax net income and a reduced effective tax rate.
1997 Compared to 1996
	Interest expense increased in 1997 due to additional borrowing and interest accrued on the Kerr Project mitigation liability, which was recorded in the second quarter of 1997. Increases in other income related to the interest income on the 1997 settlement of a dispute with the IRS and the absence of a 1996 loss on written-off property were partially offset by costs associated with the Flint Creek Dam transfer to Granite County, Montana in the second quarter of 1997.
	Income tax expense declined in 1997 as a result of lower before-tax net income, a reduced effective tax rate, and decreased tax accruals resulting from the settlement of a dispute with the IRS.
	Preferred dividends decreased in 1997 because the Company repurchased and retired 139,200 shares of its $6.875 series and redeemed all outstanding shares of its $2.15 series during the fourth quarter of 1996.
NONUTILITY OPERATIONS:
Coal Operations:
Current production from the Rosebud and Jewett Mines is sold under long- term contracts to mine-mouth customers. In 1998, the Company and the owners of Colstrip Units 3 and 4 generating plants settled coal contract disputes and future coal price reopeners. The resolution provides the Company with a stable earnings platform by eliminating all future price reopeners and an opportunity to enhance revenues through performance incentives, while reducing the plants' delivered coal prices. The Company remains the full requirements fuel supplier for all four Colstrip plants. Until mid-year 2000, the Company will realize a modest profit reduction to account for the gross inequity settlement and the elimination of over collections by the Company in some cost categories. Under the new supply and transportation agreements, the delivered coal price to Units 3 and 4 will be significantly reduced from current price levels in increments beginning July 31, 2000 and 2001. With the pricing structure in effect on those dates, the Company's contribution to consolidated pretax income from the Colstrip 3 and 4 contracts is expected to be reduced by approximately $12,000,000. With the elimination of the price reopeners and the adoption of the new pricing structure, the Company does not anticipate any further adjustments to profitability on these contracts throughout their terms, which run through December 2019. The Company does not expect the sale of its interests in the generating plants to significantly impact the results of operations from the coal sales.
In December 1998, the Company resolved a dispute with the purchaser of lignite from the Jewett Mine. The dispute between the two companies revolved around the price of lignite and whether other fuels could be substituted for lignite. The Company expects that if the market value of fuel stays flat when the agreement is fully implemented after four years, the competitive-pricing structure could result in a reduction of the Company's pretax income of approximately $7,000,000. The Company can mitigate this impact through efficiency and cost-savings measures.
1998 Compared to 1997
	Income from coal operations increased by $3,700,000 primarily due to an increase in the number of tons sold. Revenues from the Rosebud Mine increased $9,500,000 including revenues from a synthetic fuel project. Volumes of coal sold to the Colstrip Units in 1998 was 18 percent higher due to less down time for repairs and scheduled maintenance at the Colstrip generating plants. These increased volumes were partially offset by lower prices resulting from contract dispute settlements with Puget in February 1997 and with the other non-operating owners in August 1998. In addition, the Unit 3 and 4 coal supply and transportation agreements were amended in the third quarter of 1998 resulting in lower prices. As discussed earlier, these changes will result in modest profit reductions until mid-year 2000 with significant price reductions thereafter. Revenues from the Jewett Mine rose $5,500,000 primarily as a result of an increase in reimbursable mining expenses, partially offset by a 4 percent decrease in tons of coal sold.
	Operation and maintenance (O&M) expense increased primarily due to higher volumes at the Rosebud Mine and increased stripping costs at the Jewett Mine. Depreciation, depletion, and amortization decreased primarily as a result of the resolution of matters relating to the former Colorado mining operations in 1995.
1997 Compared to 1996
	Income from coal operations decreased primarily as a result of price decreases and increased production costs and legal expenses. Revenues from
the Rosebud and Jewett mines increased $4,100,000 and $2,500,000, respectively. At the Rosebud Mine, volumes of coal sold to Colstrip Units 3 and 4 increased nearly 37 percent over 1996 which was adversely impacted by plant curtailments resulting from an abundance of low-cost hydroelectric power in the region. This increase was largely offset by price reductions resulting from the Puget settlement and a short-term contract modification on tons sold to the other Colstrip partners along with a decrease in tons sold to Colstrip Units 1 and 2 due to plant maintenance. Volumes of lignite sold at the Jewett Mine increased 8 percent over 1996.
	Operations and maintenance expense increased primarily due to higher volumes of tons sold and increased overburden costs at the Rosebud Mine and higher royalty expense at the Jewett Mine associated with mining more lignite from the customer's leases. Taxes other than income taxes increased as a result of higher revenues and volumes at the Rosebud Mine. Depreciation, depletion, and amortization also increased due to the higher volumes and changes in depreciation estimates.
Oil and Natural Gas Operations:
	The following table shows year-to-year changes for the previous two years, in millions of dollars, in the various classifications of revenues, and the related percentage changes in volumes sold and prices received:
			 1998 	 1997
Oil		-revenue	$ (12)	$ (3) 		-volume	(38)%	 (20)% 		-price/bbl	(38)%	10%
Natural gas	-revenue	$ 78	$ 36 		-volume	103%	1% 		-price/Mcf	(23)%	35%
Miscellaneous	-revenue	$ -	$ 9
1998 Compared to 1997
	Income from oil and natural gas operations decreased primarily due to lower market prices in 1998. In addition to lower prices, revenues from oil operations decreased due to the sale of production properties in conjunction with the Company's increased emphasis on its natural gas operations. Natural gas revenues increased due to the sale of production from the Colorado properties acquired in the second quarter of 1997 and from formerly regulated assets transferred to oil and natural gas operations in the fourth quarter of 1997. In addition, marketing to wholesale customers in California started in the second quarter of 1998. These increases were partially offset by the lower prices in 1998.
	Operation and maintenance expense increased due to the costs of operating the acquired properties and transferred regulated assets. This increase was partially offset by lower prices for purchased gas. These new operations also accounted for the increases in SG&A and depreciation, depletion, and amortization expenses.
1997 Compared to 1996
	Oil and natural gas operations experienced a slight decrease in income primarily due to decreased oil revenues and increased purchased gas costs. Natural gas revenues increased primarily due to higher market prices, primarily in the first and fourth quarters of the year and natural gas liquids revenues
from the Vessels plant acquired in 1997. Oil production decreased for the reasons discussed above. Miscellaneous revenues increased due principally to increases in processing and gathering revenues from the Vessels facilities.
	Operations and maintenance expense increased $41,300,000 primarily due to higher prices and increased volumes of purchased natural gas and additional processing costs at the Vessels plant. Taxes other than income taxes also increased due to the Vessels plant acquisition and higher production taxes.
Independent Power Operations:
1998 Compared to 1997
Income from independent power operations increased in 1998 by $69,800,000. Earnings from unconsolidated investments increased $74,500,000 primarily due to the recognition of the Company's share in a settlement resulting from an arbitration panel's ruling on a power purchase agreement between one of the Company's independent power partnerships and the Bonneville Power Administration. Additionally, a contract settlement between another of its independent power partnerships and the power purchaser, along with the sale of the Lockport, New York project also improved earnings for the year.
Expenses increased $7,800,000 primarily due to a $6,200,000 increase in the amortization of the Company's independent power investments. Power supply expenses increased $2,200,000 resulting from increased generation, which was partially offset by a decrease in project development costs of $1,100,000.
1997 Compared to 1996
	Excluding the 1996 gain on the sale of a portion of an investment, earnings from unconsolidated investments increased $2,000,000 due to continued growth in earnings from existing investments and additional earnings from an investment that became operational in the first quarter of 1997. Offsetting the increase was a $5,700,000 decrease in revenue resulting from a settlement reached with Puget.
	Operating expenses decreased largely from a $1,800,000 reduction in purchase power expense combined with a $1,000,000 decrease in project development expenses. The decrease was offset by a $1,700,000 increase in fuel expense. During 1997, the Colstrip plant generated more energy than in 1996 due to less displacement of thermal generation. Depreciation expense decreased $1,500,000 as a result of decreased amortization of independent power investments due to a change in accounting method.
Telecommunications Operations:
In January 1999, the Company received and recorded $257,000,000 representing prepayment of all amounts due for the remaining initial term of one telecommunications contract. The prepayment will be amortized over the remaining 12-year term of the contract and will result in an annual decrease in telecommunications revenues of approximately $21,600,000 in each year compared to 1998.
1998 Compared to 1997
	Net income from telecommunications operations increased primarily as a result of a full year operation of its expanded fiber-optic network in 1998 as compared to a partial year in 1997. Revenues from telecommunications operations increased primarily due to sales on the Company's Washington to Minnesota and Colorado to Canada fiber-optic network and a higher volume of long-distance minutes sold. Revenues from the fiber-optic network did not begin until late in the third quarter of 1997. The Company also has a one-
third interest in a limited liability company, which made dark fiber sales on a Portland to Los Angeles fiber-optic network currently under construction. These sales account for the $10,500,000 increase in earnings from unconsolidated investments.
	Expenses for 1998 are higher due to the operation of the Washington to Minnesota and Colorado to Canada fiber-optic network mentioned above, increased marketing expenses, and costs related to the increased long-distance service.
1997 Compared to 1996
	Earnings from telecommunications operations increased because the Company began receiving revenues from its expanded fiber-optic network late in the third quarter. A 31 percent increase in long-distance minutes resulted in a $2,500,000 increase in revenues.
	Operations and maintenance, taxes other than income and depreciation increased $2,600,000, $1,900,000 and $1,500,000, respectively, as a result of the operation of the expanded network. Selling, general and administrative expenses increased primarily due to increased marketing efforts and advertising costs.
Other Operations:
	In August 1998, the Company announced it would exit the electric commodity trading and marketing businesses. Due to the high volatility and immaturity of the electric trading market and the Company's decision to sell its generation assets, the Company believes that these activities create unacceptable risks. The Company is in the process of developing its exit strategy, but has remained in the electric trading business to take full advantage of the opportunities to sell excess and buy needed electricity, and fulfill contractual commitments, until the generation assets are sold. The departure from these activities is not expected to have a material impact on the Company's results from operations.
1998 Compared to 1997
	Changes to revenues and expenses in other operations are primarily the result of including the electric trading activities of the Montana Power Trading and Marketing Company (MPT&M) and the Company's shared administrative services functions in this section for 1998. From January through June, MPT&M results reflect the purchase and resale of electricity that did not utilize the Utility's electric system. Beginning in July 1998, all purchases and resale of power in the secondary market are included in other operations.
1997 Compared to 1996
	Revenue and expense increases in other operations relate primarily to the Company's electric trading and marketing activity conducted by MPT&M.
Interest Expense and Other Income, and Income Taxes:
1998 Compared to 1997
	Interest expense increased primarily due to increases in the amount of outstanding borrowings to provide short-term financing for the Company's expansion of its Nonutility operations and higher interest rates.
Other (income) and deductions - net decreased due to the 1997 gains and losses discussed below and the absence of dividend income from the Brazilian gold mine and interest income associated with a 1997 settlement with the IRS.
	The increase in income tax expense resulted from higher pre-tax net income as well as a credit to expense in 1997 associated with a settlement with the IRS.
1997 Compared to 1996
	Interest expense increased primarily due to increases in the amount of outstanding borrowings to provide short-term financing for the Company's expansion of telecommunication and oil and natural gas operations.
	Other income - net increased due to the gains of approximately $23,000,000 on the sales of non-strategic oil and natural gas properties, a $10,300,000 gain on the sale of the investment in the Brazilian gold mine offset by the loss on the sale of non-strategic Wyoming coal properties and the absence of the 1996 gain on the sale of a portion of an independent power investment.
	The increase in income tax expense resulting from higher pre-tax net income was mostly offset by the tax adjustment associated with the settlement with the IRS.
LIQUIDITY AND CAPITAL RESOURCES:
Operating Activities:
Net cash provided by operating activities was $255,677,000 in 1998 compared to $201,091,000 in 1997 and $219,077,000 in 1996. The current year increase of $54,586,000 was due primarily to the settlement resulting from an arbitration panel's ruling on a power purchase agreement between one of the Company's independent power partnerships and the Bonneville Power Administration, a contract settlement between another of its independent power partnerships and the power purchaser and the sale of the Lockport, New York project. In addition, revenues increased from capacity and long-distance sales by the telecommunications operations. These increases were partially offset by an increase in receivables.
Cash from operating activities less dividends paid provided 103 percent of net cash used for investing activities in 1998, 55 percent in 1997 and 64 percent in 1996.
One Touch America customer provided notice to exercise an option allowing prepayment of all amounts due for the remaining initial term of the contract. In January 1999, the Company received and recorded $257,000,000 as deferred revenue. The prepayment will be amortized over the remaining term of the contract. Tax laws require that the prepayment be reported as income in the year received, therefore this will result in a 1999 tax payment of approximately $100,000,000.
Investing Activities:
Net cash used for investing activities was $159,552,000 in 1998 compared to $199,368,000 in 1997 and $193,587,000 in 1996. The current year decrease of $39,816,000 was due primarily to a decrease in capital expenditures, partially offset by a cash flow decrease due primarily to the prior year sale of non-strategic oil and gas properties.
	Capital expenditures during the prior three years and forecasted capital expenditures for 1999 are as follows:
		Forecasted		Actual	 	 1999			1998 		1997 		1996 	Thousands of Dollars
Utility	$	88,000	$	83,323	$ 138,318		$ 105,990 Nonutility		185,000		130,078		 173,368		 65,691 	Total	$	273,000	$	213,401	$ 311,686		$ 171,681
	Of the Utility capital expenditures for 1998, 1997, and 1996, generation accounted for $8,570,000, $74,428,000, and $19,307,000, respectively. Generation is expected to account for $27,500,000 of the 1999 forecasted
Utility expenditures. The majority of the Utility's capital expenditures during 1999 are expected to be spent on refurbishing electric and natural gas transmission lines, extending and maintaining electric and natural gas distribution lines and rehabilitation of steam and hydroelectric projects. The majority of the Nonutility's capital expenditures during 1999 are expected to be spent on the expansion and development of fiber-optic network development and local access phone service in the telecommunications operations, drilling, facilities and production enhancements of natural gas properties, future project investments by the Independent Power Group as well as the implementation of an enterprise resource planning system.
	For 1999, the Company estimates that, by business unit, internally generated funds will average 108 percent of its Utility construction program, exclusive of the proceeds anticipated to be received from the sale of the generation facilities, and 96 percent of Nonutility capital expenditures. Any remaining capital expenditure balances, as well as the repayment of maturing long-term debt, will be financed with short- and long-term debt and with sales of equity securities, the timing and amounts of which will depend upon future market conditions. The Company anticipates that it will have adequate sources of external capital to meet its financing needs.
Financing Activities:
On January 2, 1998, the Company used short-term borrowings to retire $16,000,000 in sinking fund debentures.
	On April 6, 1998, the Company issued $60,000,000 of floating rate Medium-Term Notes, Series B, due April 6 2001, the proceeds of which were used to reduce outstanding debt.
On October 1, 1998, the Company used short-term borrowings to retire $2,500,000 in 8.9 percent series Medium-Term Notes.
On November 9, 1998, the Company used short-term borrowings to retire $10,000,000 in 7.85 percent series Medium-Term Notes.
On November 24, 1998, the Company used short-term borrowings to retire $10,000,000 in 5.9 percent series Medium-Term Notes.
	Dividends paid on common and preferred stock were $91,598,000 in 1998, $91,112,000 in 1997, and $95,284,000 in 1996. During 1998, the regular quarterly dividend level was 40 cents per share of outstanding stock or $1.60 per share on an annual basis. The declaration of future dividends is at the discretion of the Board of Directors.
The Company's Board of Directors has authorized a share repurchase program over the next five years to repurchase up to 10,000,000 shares, or 18 percent, of the Company's outstanding common stock.
As of yearend 1998, the Company had 55,060,520 common shares outstanding. The repurchase of common stock may be made, from time to time, on the open market or in privately negotiated transactions. The number of shares to be purchased and the timing of the purchases will be based on the level of cash balances, general business conditions and other factors, including alternative investment opportunities.
In 1998, the Company established a special purpose entity that is a wholly owned subsidiary, MPC Natural Gas Funding Trust (Trust). In December 1998, the Trust issued $62,700,000 of 6.2 percent asset-backed securities, known as transition bonds. The transition bond proceeds will be used to reduce the Company's outstanding debt and equity. The bonds will be retired from funds collected by the Trust through usage-based charges levied on
natural gas transmission and distribution customers. The retirements will occur at six-month intervals beginning on September 15, 1999, and ending on March 15, 2012. Retirements will be in varying amounts depending on revenues collected from customers. At December 31, 1998, approximately $1,700,000 is classified as due within one year in the Consolidated Balance Sheet.
The Company's consolidated borrowing ability under its Revolving Credit and Term Loan Agreements was $178,300,000, of which $134,000,000 was unused at December 31, 1998. The unused amount excludes $30,000,000 under the Agreements which is currently being used to back a like amount of commercial paper. The Company also has short-term borrowing facilities with commercial banks that provide both committed and uncommitted lines of credit, and the ability to sell commercial paper.
The Company's long-term debt as a percentage of capitalization was 37 percent in 1998, 1997, and 1996. Approximately $96,000,000 of long-term debt will mature during the year 1999. 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.
		While the Company does not expect to issue additional First Mortgage Bonds in 1999, the restrictions upon the issuance of such bonds contained in the Company's Mortgage and Deed of Trust would not preclude it from issuing sufficient First Mortgage Bonds to meet its expected financing requirements for the year. 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.
See Item 8, "Financial Statements and Supplementary Data - Notes 9 and 10 to the Consolidated Financial Statements" for further information on financing activities.
PP&L Global has agreed to purchase the Company's interest in 12 of its 13 hydroelectric facilities, all four coal-fired thermal generating plants and a leasehold interest in Colstrip Unit 4, along with a power purchase contract with Basin and two power exchange agreements. Proceeds from the sale will vary depending upon various factors, and are anticipated to be between $740,000,000 and $988,000,000. The Company is evaluating the potential uses for the proceeds realized from the sale including investing in current businesses, primarily telecommunications, as well as a repurchase of common stock and possible debt repayment. The Company does not expect the generation sale proceeds or the telecommunications prepayment to materially change its consolidated capitalization percentages.
SEC RATIO OF EARNINGS TO FIXED CHARGES:
	For the twelve months ended December 31, 1998, the Company's ratio of earnings to fixed charges was 3.34 times. Fixed charges include interest, the implicit interest of Unit 4 rentals and one-third of all other rental payments.
INFLATION:
	Capital intensive businesses, such as the Company's electric and natural gas utility operations, are significantly and adversely affected by long-term inflation as neither depreciation nor the ratemaking process reflect the replacement cost of utility plant. Although prices for natural gas may fluctuate, earnings of the gas utility operations are not impacted because a gas cost tracking procedure annually balances gas costs collected from customers with the costs of supplying gas. As the Company's utility operations transition to a more competitive environment and considering the intended sale
of the electric generating facilities and power purchase contracts, it is anticipated that the Company will be less capital intensive in the future and therefore, impacted less by inflation.
	The Nonutility's long-term coal and co-generation natural gas supply contracts and long-term power sales contracts provide for the adjustment of prices either through indices, fixed escalations and/or direct pass-through of costs.
	The Company believes that the effects of inflation, at currently anticipated levels, will not materially affect results of operations.
YEAR 2000 COMPLIANCE:
The Year 2000 issue, known as Y2K, relates to the ability of systems, including computer hardware, software, and embedded microprocessors, to properly interpret date information relating to the year 2000. Many existing systems, including some of the Company's systems, use only the last two digits to refer to a year. Therefore, these systems may not properly recognize a year that begins with "20" instead of "19". If not corrected, these systems could fail or create erroneous results.
	The Company has a corporate-wide strategy to address Y2K issues. An Executive Steering Committee was established to coordinate and oversee implementation of the strategy in the business units. The strategy includes a three step process and a contingency plan. The first step involves inventorying critical information technology (IT) systems and non-information (non-IT) systems including third party computer hardware and software, and embedded electronic microprocessors. During the second step, the Company conducts certain analyses to determine the system's Y2K readiness. The third step consists of replacing/repairing and testing the systems to ensure the availability and integrity of the systems. Simultaneous with those three steps, the Company is developing a contingency plan to address unanticipated failure of the systems.
Inventorying of the critical IT systems is complete. This involves computer systems within the Company's main business office, such as accounting systems, human resource systems, materials management systems, and work management systems. Analysis of the inventory is also complete. Of the IT systems inventoried, over 50 percent have already been deemed ready based on testing or representations from the manufacturers. The Company is working to have all of its critical systems Y2K ready by July 1, 1999. Currently, the Company believes that of the systems inventoried, one critical IT system, the Customer Information System, which provides utility customer billing and field operations support, is not Y2K compliant. The Company is pursuing a billing outsourcing solution that is expected to be in place by August 1, 1999. In the event this or any other critical system fails in spite of efforts to be ready, contingency plans are being developed.
Inventorying of critical non-IT systems is 85 percent completed. Analysis of the inventory is 80 percent completed. Approximately 70 percent of the systems that have been inventoried have been deemed Y2K ready based on testing or representations from the manufacturers. The Company is working to have all of its non-IT critical systems Y2K ready by July 1, 1999. Among the Company's critical non-IT systems that will not be ready by that date are the Energy Management System, which provides system control and data acquisition for the Company's electric transmission system, and continuous emission monitoring systems, which monitor stack gas emissions at the Corette and Colstrip Plants. A Y2K solution for the energy management system is expected to be implemented by August 1, 1999, and for the emission monitors by September 1, 1999. Contingency plans are being developed in the event systems fail in spite of the Company's efforts to be ready.
The Year 2000 issue may also impact other entities with which the Company transacts business or with which the Company's electric and natural gas systems are interconnected. Each of the business units has been contacting suppliers, vendors, and key customers to assess their Year 2000 readiness. Currently, the Company has not been advised that Y2K impacts to vendors, customers, or suppliers' systems will significantly impact its operations. In addition, because of the interconnected nature of electric systems, the North American Electric Reliability Council (NERC) is facilitating the preparations of electric systems in North America for operation into the year 2000. As part of its Year 2000 program, NERC monitors the monthly progress of industry efforts to prepare critical systems for the year 2000. NERC has proposed national drills in April and September 1999 to assess industry preparation. The Company plans to participate in such drills.
The Company has not established a formal process to track either external or internal Y2K expenditures. Many of the measures that will mitigate Y2K impacts coincide with normal operations and maintenance, so are not accounted for separately as Y2K expenditures. For example, the capital upgrade to the energy management system which is necessary in any event to provide additional functionality will also result in a Y2K benefit and cost $460,000. An additional $36,000 to test custom software associated with the energy management system and the upgrade software is explicitly accounted for as a Y2K expense. Likewise, the Company is implementing a new method of customer billing which will cost $3,100,000 and although it will address the Y2K issue, in any case, the new method was planned to satisfy deregulation requirements. In addition, the central information services department, estimates that through 1998 it has already spent approximately $1,100,000 to address the Y2K issue and anticipates spending another $1,400,000 in 1999. Although it is not currently possible to estimate the overall cost of required modifications, the Company presently believes that the ultimate cost of this work will not have a material effect on the Company's current financial position, liquidity, or results of operations.
Except as described above, the Company expects all necessary modifications and testing of its critical IT and critical non-IT systems to be completed by July 1, 1999. Also, as previously discussed, contingency plans will be in place. The most reasonably likely worst case Y2K scenario envisioned by the Company is that some customers could experience interruptions in service.
NEW ACCOUNTING PRONOUNCEMENTS:
In June 1998, the Financial Accounting Standards Board (FASB) issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities". SFAS No. 133 requires that all derivative instruments be recorded on an entity's balance sheet at fair value. The statement also expands the definition of a derivative. Changes in the fair value of the derivatives are recognized each period either in current earnings or as a component of comprehensive income, depending on whether the derivative is designated as part of a hedge transaction, and if so, what type of hedge transaction. The statement distinguishes between fair-value hedges, defined as hedges of the Company's assets, liabilities, or firm commitments, and cash-flow hedges, defined as hedges of future cash flows related to a variable rate asset or liability or a forecasted transaction. Recognition of changes in the fair value of a hedge, determined to be a fair-value hedge, will generally be offset in the income statement by the recognition of the change in the fair value of the hedged item. Recognition of changes in the fair value of a cash- flow hedge will be reported as a component of comprehensive income. The gains or losses on the derivative instruments that are reported in comprehensive income will be reclassified into current earnings in the periods in which the earnings are impacted by the variability of the cash flows of the hedged item. The ineffective portion of all hedges will be recognized in current earnings.
	The new statement is effective for all fiscal quarters of all fiscal years beginning after June 15, 1999. The Company has not yet determined the impact that the adoption of the new standard will have on its earnings or financial position.
	During 1998, the Emerging Issues Task Force (EITF) of the FASB released Issue 98-10 (EITF 98-10), "Accounting for Contracts Involved in Energy Trading and Risk Management Activities". EITF 98-10 addresses the accounting for energy contracts and requires that energy contracts entered into under "trading activities" be marked to market with the gains or losses shown net in the income statement. EITF 98-10 is effective for the fiscal years beginning after December 15, 1998. In conjunction with its commodity risk management activities, the Company calculates and evaluates mark to market information for its trading activities on a regular basis. Mark to market analysis for these activities at December 31, 1998 indicates that an immaterial loss would have been required to be recognized in the results of operations had EITF 98- 10 been effective. Based upon a periodic review of the mark to market analysis for these activities, the Company does not expect the adoption of EITF 98-10 to have a material impact on its results of operations.
ENVIRONMENTAL ISSUES:
	The Company is committed to protect, maintain, and enhance the environment in its business operations. The diversity of the Company's businesses subjects it to numerous federal, state and local environmental laws and regulations relating to pollution control and prevention, and environmental remediation. The primary federal environmental laws and regulations affecting the Company are: The Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA); the Resource Conservation and Recovery Act; the Oil Pollution Prevention Act; the Safe Drinking Water Act; the Toxic Substances Control Act; the Federal Insecticide, Fungicide, and Rodenticide Act; the Hazardous Materials Transportation Act; the Emergency Planning and Community Right to Know Act; the Surface Mining Control and Reclamation Act; and the National Environmental Policy Act.
	The Company maintains accruals for its minimum estimated costs associated with reasonably foreseeable potential environmental clean-up costs; it does not expect these costs to materially impact the results of its operations.
	CERCLA, and some of its state counterparts, give rise to loss contingencies for future site remediation because they may require the Company to remove or mitigate the adverse environmental effects resulting from the disposal or release of certain substances at previously owned or present Company sites, or at sites where these substances were disposed. The total amount of costs associated with current site remediation efforts and future remediation is unknown both because (1) the Company may not know of all sites for which it is responsible and (2) it cannot currently predict with any degree of certainty the total costs for those sites it has identified. Current indications are that the known costs will not have a materially adverse effect on the Company or its operations.
	The Company is a Potentially Responsible Party (PRP) at the Silver Bow Creek/Butte Area Superfund Site. A Consent Decree recognizing the Company's "de minimis" contributor status will soon be submitted to the federal court for approval. Upon approval of the Consent Decree, and payment of $100,000, the Company will receive a release from further liability for clean-up costs. . Further, the Consent Decree will provide the Company contribution protection in the event other PRP's claim contribution for clean-up costs they expend. Given the expected approval of the Consent Decree, the substantial financial capability of other PRP's named by the Environmental Protection Agency (EPA),
and the very limited connection between the Company's property ownership and the "mining-related" character of the alleged contamination of the Site, the Company does not feel it has a significant exposure to material liability regarding this overall Site.
	The Company will, however, continue to address alleged soils contamination of the 30 acres of this Site, which it owns. Expected clean-up costs are not material.
	The Company is a PRP at the Milltown Dam Site, where toxic heavy metals are in the silts resting behind the dam. Because of federal legislation specifically regarding Milltown, the Company's position is that it has no responsibility for any of the alleged releases under CERCLA.
The Company has voluntarily cleaned up two sites where it operated manufactured gas plants, spending approximately $675,000. It has inspected and assessed a third site. Periodic ground water monitoring and reporting to the Montana Department of Environmental Quality (MDEQ) is required at the two sites where clean up is completed. The cost of this monitoring is not expected to be material. Discussions with the MDEQ and local regulatory agencies regarding the third site are not complete. Nevertheless, the Company does not expect expenditures at this site to be material.
	The MDEQ has listed the reservoir at the Thompson Falls Dam as a Comprehensive Environmental Cleanup and Responsibility Act (CECRA) site -- the state equivalent of a CERCLA National Priority List site. In 1985 and 1986, researchers found elevated levels of heavy metals in sediments in the reservoir. EPA declared the site a "No Further Action" site under CERCLA. The MDEQ identified the site as a "Low Priority Site" because of low direct contact hazard and the lack of evidence of migration to groundwater supplies. Given the low priority designation for this site, no estimate of costs to address the alleged contamination has been required.
All of the Company's coal-fired units are Phase II Units under Title IV (Acid Rain) of the Clean Air Act Amendments of 1990 (Act) which imposes certain sulfur dioxide and nitrogen oxide requirements. All of the Company's coal-fired plants comply with the sulfur dioxide requirements.
	The nitrogen oxide standard for Phase II Units, effective in the year 2000, is more stringent than the standard imposed upon Phase I Units. However, the Act provides Phase II Units with the option to comply, beginning January 1, 1997, with the Phase I standards and defer, until 2008, compliance with the more stringent Phase II standards. Because the Company has determined that the Colstrip Units could meet the Phase I nitrogen oxide standards by January 1, 1997, it exercised this option for the Colstrip plants. For calendar years 1997 and 1998, the Colstrip plants met the early election standard. The Company did not exercise this option for its Corette Plant. However, in 1997 the Company installed a low nitrogen oxide burner system on the Corette boiler. The cost of the system and installation was approximately $1,000,000. Since the system has been in place, it has performed well within the Phase II standards. The costs associated with any modifications that ultimately may be required to comply with Phase II nitrogen oxide standards have not been determined.
In addition, all of the Company's coal-fired units have now received Operating Permits under Title V (Permitting) of the Act. The permits were effective on January 1, 1998 for Colstrip Units 1 and 2 and January 1, 1999, for Colstrip Units 3 and 4 and the Corette plant. The Corette plant is also operating under a State Implementation Plan, as administered by the MDEQ, for control of sulfur dioxide emissions effective March 1998.
	Surface and ground water impacts resulting from the operation of the Colstrip Project's process water disposal system have been previously documented. Study and mitigation efforts continue in consultation with the MDEQ to address the impacts. Estimated maintenance expenses to monitor and sustain the effectiveness of related groundwater collection systems are $50,000 per year. Estimated capital expenditures for 1999-2001, the scheduled remedy period, are $5,000,000.
	In 1998, the Company employed a consultant to assess environmental conditions at the generation facilities it sold. From the consultant, it obtained estimates of future costs deemed reasonably necessary to address identified issues. Consequently, the Company accrued $7,350,000 in 1998 for its share of the estimated liability.
	The Company's Canadian subsidiaries are involved with ongoing abandonment and remediation of depleted wells and surface facilities in Alberta. The remediation work addresses clean up under the direction of Alberta Environmental and reflects normal activity within the oil and gas industry. Approximately 35 sites are under active reclamation. Clean up of 70 sites has been completed through 1998, of which 31 sites are either awaiting final inspection by Alberta Environmental, or are in the final monitoring of vegetation growth prior to applying for clean-up certification. Since 1995, the Company has spent approximately $800,000 (U.S.$) for clean up of the identified sites. The Company believes that estimated additional expenditures of $980,000 (U.S.$) will be required for clean up of affected sites through the year 2003. The estimate is subject to change, pending acquisitions or divestitures of Canadian properties, which may occur over the five-year period.
	In the purchase of all of the Company's electric generation assets, except Milltown Dam, PP&L Global assumed pre- and post-closing environmental liabilities associated with the purchased assets. The Company retained the following liabilities regarding its interests sold:
? Payment of fines or penalties imposed by regulatory authorities related to pre-closing activity. ? Liability for pre-closing "off-site" activity, such as transportation, disposal, or storage of hazardous material to a site other than the location of a sold generation asset. ? Remediation, if any, of the silts behind the Thompson Falls Dam.
The Company, along with the other sellers of interests in the Colstrip Project, agreed to indemnify PP&L Global from losses arising from pre-closing environmental conditions. The indemnity obligation, however, is limited:
? The indemnity for required remediation of pre-closing conditions, whether known or unknown at the closing, is limited to 50 percent of the loss. (The Company's share of such indemnity obligation at the Colstrip Project is limited to its pro-rata share of 50 percent.) ? The indemnity for required remediation of pre-closing conditions unknown at the time of closing is limited to a two-year period after closing. The indemnity for required remediation of pre-closing conditions known at the time of the closing continues indefinitely. ? The indemnity for required remediation of pre-closing conditions, whether known or unknown, is capped at an amount equal to 10 percent of the purchase price paid for the generation assets.
The Company does not expect this indemnity obligation to materially adversely affect the financial results of its operations.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
RISK MANAGEMENT:
	The Company is exposed to the market risks associated with fluctuations in commodity prices, interest rates, and changes in foreign currency translation. To better manage the risks associated with commodity trading and marketing activities, the Company implemented a comprehensive Energy Risk Management program in 1998. In conjunction with this program, the Company established a Risk Management Committee, which approves the risk-related activities in which the Company participates, the types of instruments that may be used, and recommends to the Company's Audit Committee of the Board of Directors specific limits for trading activity.
TRADING INSTRUMENTS:
Commodity Price Exposure
The Company, primarily through its subsidiaries, is exposed to the effects of market price fluctuations in the price of oil, natural gas, and natural gas liquids, the price of electricity purchased and sold under firm contracts and in the spot market and natural gas transportation costs. Additionally, the Company is exposed to market price fluctuations for instruments related to these products which are marketed and traded. The Company has formal policies regarding the execution, recording, and reporting of products and instruments related to the marketing and trading of electricity, oil, natural gas, and natural gas liquids. The Company uses various financial derivative instruments to manage the price risk associated with its Nonutility producing assets, firm-supply commitments, and natural gas transportation agreements. These financial derivative instruments include swaps and options. See Item 8, "Financial Statements and Supplementary Data - Note 1 to the Consolidated Financial Statements".
In August 1998, the Company announced it would exit the electric commodity trading and marketing businesses. Due to the high volatility and immaturity of the electric trading market and the Company's decision to sell its electric generation assets, the Company believed that these activities created unacceptable risks. Although the Company is in the process of implementing its exit strategy, it has remained in the electric trading business to efficiently sell surplus electricity from its generating plants and buy electricity needed to supply its native Utility load and fulfill contractual commitments. Neither remaining in the electric trading business on a limited basis, nor eventually exiting from this business, is expected to have a material impact on the Company's results from operations.
The Company's value-at-risk for natural gas physical and financial transactions (VaR) is based on J.P. Morgan's RiskMetrics T approach (i.e. variance/co-variance), which uses historical estimates of volatility and correlation and values optionality using delta equivalents. Because actual future changes in markets (prices, volatilities, and correlations) may be inconsistent with historical observations, the Company's VaR may not accurately reflect the potential for future adverse changes in fair values. The Company's VaR is based on a forward 24-month time period and assumes a one-day holding period and a 95 percent confidence level. As of December 31, 1998, the Company's VaR calculation for these natural gas physical and financial transactions was less than $2,000,000. At December 31, 1998, the Company held no financial derivative contracts relating to oil or natural gas liquids.
The Company entered into a financial derivative transaction in conjunction with one of its electric retail sales contracts. The negative mark-to-market valuation of this instrument is recaptured when netted against the positive mark-to-market valuation of a related offsetting physical transaction with another counterparty. The decrease in fair market value of the derivative instrument resulting from a hypothetical 10 percent adverse change in market price is also offset by the increase in the fair market value of the related offsetting physical transaction resulting from this market price change.
Interest Rate Exposure
Currently, the Company does not use derivative financial instruments to hedge against exposure to interest rate fluctuations on variable rate debt. The Company 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. However, at December 31, 1998, the Company believes it would not experience any materially adverse impacts from the risks inherent in these instruments.
Foreign Currency Exposure
	Currently, the Company does not use derivative financial instruments to hedge against exposure to foreign currency exchange rate fluctuations. As a result, at December 31, 1998, the Company has no financial instruments related to foreign currency fluctuations which expose it to such market risks.
OTHER FINANCIAL INSTRUMENTS:
Commodity Price Exposure
At December 31, 1998, the Company's primary commodity risk related to its Nonutility operation's contracts for the purchase or delivery of electricity, natural gas, natural gas liquids, oil, coal, and lignite and the regulated Utility operation's contracts for the purchase or delivery of electricity and natural gas.
Within its regulated Utility operations, the Company has contracts for the purchase or exchange of electricity under contracts with expiration terms ranging from 2001 through 2031. At December 31, 1998, it is estimated that these contracts could result in above-market costs of between $300,000,000 and $500,000,000 throughout their duration. The exchange contracts and one of the purchase contracts are included in the asset sale agreement with PP&L Global and the Company is evaluating options for divestiture of the other contracts. Although a hypothetical 10 percent adverse change in the market price for electricity increases the potential above-market costs by $25,000,000 to $30,000,000, the Company expects to recover the costs associated with these contracts through the sale or through competitive transition charges (CTC's) in the electric restructuring process. Therefore, these contracts are not expected to expose the Company to market risks related to commodity price fluctuations other than from the possibility of a regulatory lag or the disallowance of recovery of those costs. See Item 8, "Financial Statements and Supplementary Data - Note 4 to the Consolidated Financial Statements".
Also within its regulated Utility operations, the Company has contracts for the purchase of fuel for one of its electric generating facilities from a third party as well as contracts for the purchase of natural gas for resale and contracts for the sale of electricity. Although the potential exists for market risk within these contracts, the costs are expected to be recovered through the rate making process and are not expected to expose the Company to market risks related to commodity price fluctuations other than from the possibility of a regulatory lag or the disallowance of recovery of those costs.
In its Nonutility operations, the Company has various electric sales contracts with fixed or variable prices or with cost reimbursement and fee pricing structures with terms expiring from 1999 through 2023. Using mark-to- market analysis and net present value calculations for the duration of the contracts, the Company estimates the fair market value of these contracts is approximately $52,000,000 at December 31, 1998. An analysis of fair value of these contracts resulting from a hypothetical 10 percent adverse change in the market price for the electricity throughout the contracts, which may differ from actual results, indicates a decrease in the December 31, 1998 fair value of approximately $3,000,000.
The Company has a full-lignite requirements supply agreement (LSA) through July 2015 for the delivery of lignite to two mine-mouth electric generating facilities. The contract currently provides for the reimbursement
of certain mining costs as well as management and dedications fees. Under a settlement reached in late 1998, the pricing structure will change in mid-2002 and will be market price driven. The Company expects that if the market price of fuel stays flat when the agreement is fully implemented, the competitive- pricing structure could result in a reduction of the Company's pretax income of approximately $7,000,000. Since transportation costs are a substantial portion of other competitive supplies, the impact that would result from a hypothetical 10 percent adverse change in commodity prices of these competitive fuel supplies is an approximate 2 percent decrease in the price received under the contract. See Item 8, "Financial Statements and Supplementary Data - Note 2 to the Consolidated Financial Statements".
The Company also has full-requirements contracts for the sale of coal to four mine-mouth electric generating plants in Montana partially owned by the Company. The contract for supply to two of these facilities provides for price reopeners to adjust prices to reflect changes in mining costs but is not directly tied to market price changes. Therefore, there is no direct market risk associated with these contracts. The contracts for the other two facilities requires that alternative supplies be continually evaluated by the Company, however, due to the significant transportation costs of alternative supplies, a hypothetical 10 percent decrease in commodity prices of these competitive coal supplies should not impact these contracts.
	At December 31, 1998, the Company had a very limited number of natural gas liquids sales contracts and any market risk associated with these contracts is immaterial.
Interest Rate Exposure
At December 31, 1998, the Company's primary interest rate exposure related to the items defined as other financial instruments under the guidance of SFAS No. 107, "Disclosures about Fair Value of Financial Instruments". These financial instruments principally include the Company's cost basis investments in independent power projects, reclamation fund, other significant investments, mandatory redeemable preferred securities, and long-term debt. Market risk for these financial instruments is estimated as the potential loss in fair value which would result from a hypothetical 10 percent adverse change in interest rates. See Item 8, "Financial Statements and Supplementary Data - Note 1 to the Consolidated Financial Statements".
Based on the method used to estimate fair values for the purposes of SFAS No. 107 analysis, the potential loss in the December 31, 1998 fair value of the independent power projects, reclamation fund, and other significant investments that would result from a hypothetical 10 percent adverse change in interest rates would be immaterial. Based on the method used to estimate fair values for the purposes of SFAS No. 107 analysis, potential loss in the December 31, 1998 fair value of the mandatorily redeemable preferred securities and long-term debt that would result from a hypothetical 10 percent adverse change in interest rates would be approximately $5,300,000 and $15,200,000, respectively.
Foreign Currency Exposure
	The Company's oil and natural gas operations are engaged in exploration, production, gathering, processing, and marketing of oil and natural gas in Canada through Altana Exploration Ltd. and Canadian Montana Gas Company, both Canadian subsidiaries. Both of these subsidiaries use Canadian dollars as their functional currency. The Company also engages in natural gas trading and marketing activities in Canada. However, at December 31, 1998, the Company believes that the market risk associated with a hypothetical 10 percent adverse change in foreign currency translation would be immaterial.
ITEM 8.
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
	AND SUPPLEMENTARY DATA
												 Page
Management's Responsibility for Financial Statements				57
Report of Independent Accountants							58
Consolidated Financial Statements:
	Consolidated Statements of Income for the Years Ended 		59 		December 31, 1998, 1997 and 1996	
	Consolidated Balance Sheets as of December 31, 1998 and 1997	60-61
	Consolidated Statements of Cash Flows for the Years Ended 		62 		December 31, 1998, 1997 and 1996	
	Consolidated Statements of Common Shareholders' Equity for the 	63 		Years Ended December 31, 1998, 1997 and 1996	
	Notes to Consolidated Financial Statements				64-93
Supplementary Data (Unaudited)							94-103
Financial Statement Schedules for the Years Ended December 31, 	1998, 1997 and 1996:	
	Schedule II - Valuation and Qualifying Accounts and Reserves	108
Financial statement schedules not included in this Form 10-K Annual Report have been omitted because they are not applicable or the required information is shown in the Consolidated Financial Statements or notes thereto.
MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS
	The management of The Montana Power Company is responsible for the preparation and integrity of the consolidated financial statements of the Company. These financial statements have been prepared in accordance with generally accepted accounting principles, which are consistently applied, and appropriate in the circumstances. In preparing the financial statements, management makes appropriate estimates and judgments based upon available information. Management also prepared the other financial information in the annual report and is responsible for its accuracy and consistency with the financial statements.
	Management maintains systems of internal accounting control which are adequate to provide reasonable assurance that the financial statements are accurate, in all material respects. The concept of reasonable assurance recognizes that there are inherent limitations in all systems of internal control in that the costs of such systems should not exceed the benefits to be derived. Management believes the Company's systems provide this appropriate balance.
	The Company maintains an internal audit function that independently assesses the effectiveness of the systems and recommends possible improvements. PricewaterhouseCoopers LLP, the Company's independent accountants, also considered the systems in connection with its audit. Management has considered the internal auditors' and PricewaterhouseCoopers 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 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 audited by PricewaterhouseCoopers LLP, which is responsible for conducting its examination in accordance with generally accepted auditing standards.
/s/ Robert P. Gannon		/s/ J. P. Pederson	 R. P. Gannon		J. P. Pederson Chairman of the Board and		Vice President and Chief 	Chief Executive Officer			Financial and Information 			Officer
	Report of Independent Accountants
February 4, 1999
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, 1998 and 1997, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1998, in conformity with generally accepted accounting principles. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with generally accepted auditing standards, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above.
/s/PricewaterhouseCoopers LLP Portland, Oregon
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 - Summary of significant accounting policies:
Basis of accounting:
	The Company's accounting policies conform to generally accepted accounting principles. With respect to utility operations, such policies are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities having jurisdiction.
Use of estimates:
	Preparing financial statements requires the use of estimates. Management makes appropriate estimates and judgments based upon available information. Actual results may differ from accounting estimates as new events occur or additional information is obtained.
Consolidation principles:
	The Consolidated Financial Statements include the accounts of the Company and its subsidiaries, all of which are wholly owned. Significant intercompany balances and transactions have been eliminated. Independent power investments are accounted for using either the cost or equity method depending on the Company's ability to exercise control over the operations of the particular investment.
Plant, property, depreciation and amortization:
	The year-end balances of the major classifications of property, plant, and equipment are detailed in the following table:
			 December 31 			 1998 	 1997 			Thousands of Dollars 	Utility plant: 	Electric: 		Generation (including 		 jointly-owned)		$ 724,483	$ 718,504 		Transmission		373,630	364,638 		Distribution		550,844	520,213 		Other		192,899	216,925 	Natural Gas: 		Production and storage		75,658	70,337 		Transmission		152,804	148,295 		Distribution		146,896	138,676 		Other		 29,633	 38,610 			Total Utility		2,246,847	2,216,198 	Nonutility plant: 	Coal		237,913	241,835 	Oil and natural gas		388,153	363,193 	Technology		113,474	86,617 	Electric generation		76,189	75,585 	Other		 49,252	 14,176 			Total Nonutility		 864,981	 781,406 			Total Plant		$3,111,828	$2,997,604
	 	The cost of additions to and replacement of plant, including an allowance for funds used during construction (AFUDC) of utility plant, is capitalized. The rate used to compute AFUDC is determined in accordance with a formula established by the Federal Energy Regulatory Commission (FERC) and was an average of 8.3 percent for 1998, 8.0 percent for 1997, and 7.2 percent for 1996. Costs of utility depreciable units of property retired plus costs of removal less salvage are charged to accumulated depreciation and no gain or loss is recognized. Gain or loss is recognized upon the sale or other disposition of Nonutility property. Maintenance and repairs of plant and property as well as replacements and renewals of items determined to be less than established units of plant are charged to operating expenses.
With respect to the sale of the regulated generation assets, the Company first expects to recover the book value of those assets and the costs of the sale transaction. Proceeds in excess of the book value and transaction costs are expected to reduce the amounts to be collected from ratepayers in the form of competitive transition charges (CTC).
	Included in the plant classifications are Utility plant under construction in the amounts of $37,966,000 and $39,425,000 for 1998 and 1997, respectively and Nonutility plant under construction in the amounts of $10,990,000 and $17,259,000 for 1998 and 1997, respectively. Also included in the table above are electric generating and transmission assets held for sale with an approximate cost and accumulated depreciation of $901,000,000 and $327,000,000, respectively.
	Provisions for depreciation and depletion are recorded at amounts substantially equivalent to calculations made on straight-line and unit-of- production methods by application of various rates based on useful lives of properties determined from engineering studies. The provisions for Utility
depreciation and depletion approximated 3.0 percent for 1998 and 1997 and 2.9 percent for 1996 of the depreciable and depletable Utility plant at the beginning of the year.
	The Company's Nonutility oil and natural gas operations use the successful efforts method of accounting for exploration and development costs.
Jointly owned electric plant:
	The Company is a joint-owner of Colstrip Units 1, 2, and 3 and of transmission facilities serving these Units. At December 31, 1998, 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		$186,627	$286,200	$45,265 Plant under construction		273	413	-- Accumulated depreciation		101,608	113,371	14,231
	*This is an approximate ownership percentage based on capacity rights on the various segments of the transmission system.
	The Company also owns $42,437,000 and $33,370,000 of the Nonutility Colstrip Unit 4 share of common production plant and transmission plant which is included in Nonutility plant "Electric generation" in the property, plant and equipment table above. Production plant under construction was $406,000. The accumulated depreciation related to Unit 4 production and transmission plant was $18,633,000 and $8,501,000, respectively.
	Each joint-owner provides its own financing. The Company's share of direct expenses associated with the operation and maintenance of these joint facilities is included in the corresponding operating expenses in the Consolidated Statement of Income.
Reclamation fund:
	As a result of a restructured coal supply agreement (CSA) entered into in August 1998, the Company maintains a reclamation fund representing restricted cash necessary to meet its estimated reclamation obligation under the CSA. The funds required for these reclamation obligations will be invested until reclamation is performed. At December 31, 1998, the fund was invested entirely in a money market account. The Company regularly accrues an expense and an offsetting liability associated with its reclamation obligation. The reclamation fund had no effect on the Company's accumulated liability.
Utility and Telecommunication revenue and expense recognition:
	Operating revenues are recorded on the basis of service rendered. In order to match revenues with associated expenses, the Company accrues unbilled revenues for electric, natural gas, and telecommunication services delivered to customers but not yet billed at month-end.
Regulatory assets and liabilities:
	For its regulated operations, the Company follows SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation". Pursuant to this pronouncement, certain expenses and credits, normally reflected in income as incurred, are recognized when included in rates and recovered from or refunded
to the customers. As such, the Company has recorded the following regulatory assets and liabilities that will be recognized in expenses and revenues in future periods when the matching revenues are collected.
	 1998 	 1997 	 Assets 	Liabilities	 Assets 	Liabilities 	Thousands of Dollars
	Income taxes		$119,080			$ 119,643	 	Colstrip Unit 3 		carrying charge			40,325			42,156	 	Conservation programs		33,353		33,965	 	Competitive transition 		charges		56,059		58,983	 	Investment tax credits			$ 33,819		$ 35,182 	Other		 43,308		 9,474		42,344		 8,743 		Subtotal		292,125	43,293	297,091	43,925 	Less: 		Current portions			16,197		5,057		15,615		2,522 		Total		$	275,928	$	 38,236	$	281,476	$	41,403
Income taxes reflect the impacts of temporary differences that will be recovered in rates in future periods. The Montana Public Service Commission (PSC) provided in its August 1985 order a carrying charge and recovery of depreciation that were deferred and are being amortized to income over the remaining 23-year life of Colstrip Unit 3 to compensate the Company for unrecovered costs of its investment for the period the plant was in service from January 10, 1984 to August 29, 1985. Conservation programs represent the Company's Demand Side Management (DSM) programs that are in rate base and are being amortized to income over a ten-year period. The CTC's, which relate to natural gas properties that were removed from regulation on November 1, 1997, are being recovered through rates over 15 years. Investment tax credits and account balances included in Other are either being amortized currently or are those items subject to regulatory confirmation in future regulatory proceedings.
Changes in regulation or changes in the competitive environment could cause recovery of these costs through rates to become uncertain, resulting in the Company not meeting the criteria of SFAS No. 71. If the Company were to discontinue application of SFAS No. 71 for some or all of its operations, the regulatory assets and liabilities related to those portions would have to be eliminated from the balance sheet and included in income in the period when the discontinuation occurred unless recovery of those costs was provided through rates charged to those customers in a portion of the business that remains regulated. In conjunction with the ongoing changes in the electric and natural gas industries, the Company will continue to evaluate the applicability of this accounting principal to those businesses.
As a consequence of the issuance by the PSC of the natural gas restructuring order, the Company's natural gas production assets were removed from SFAS No. 71 accounting in the fourth quarter of 1997. The timing of the removal of the electric generating assets from SFAS No. 71 is expected to coincide with the sale of the Company's interests in the generating facilities. Recovery of the Company's existing regulatory assets related to electric generation is provided in the electric restructuring legislation. For further information on the sale of the Company's interest in the generating facilities see Note 4 - "Deregulation and Asset Divestiture".
Cash and cash equivalents:
	The Company considers all liquid investments with original maturities of three months or less to be cash equivalents.
Storm damage and environmental remediation costs:
	The estimated costs of storm damage and environmental remediation obligations for Utility operations are charged against established, regulator approved operating reserves when such losses are probable and reasonably estimatable. The reserves are adequate to provide for all known obligations and may be increased, if appropriate, by adjusting the annual accrual rate. The reserves' balances at December 31, 1998 and 1997 were approximately $2,000,000 and $2,600,000, respectively, and are included in current liabilities on the Consolidated Balance Sheet.
Income taxes:
	The Company and its U.S. subsidiaries file a consolidated U.S. income tax return. Consolidated U.S. income taxes are allocated to Utility and Nonutility operations as if separate U.S. income tax returns were filed. Deferred income taxes are provided for the temporary differences between the financial reporting basis and the tax basis of the Company's assets and liabilities. For further information on income taxes see "Regulatory assets and liabilities" in this note and also Note 5 - "Income tax expense".
Net income per share of common stock:
	Basic net income per share of common stock is computed for each year based upon the weighted average number of common shares outstanding. In accordance with SFAS No. 128, "Earnings per Share", diluted net income per share of common stock reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock or resulted in the issuance of common stock that shared in the earnings of the Company.
Asset impairment:
	In accordance with SFAS No. 121, "Accounting for the Impairment of Long- Lived Assets and for Long-Lived Assets to be Disposed Of", the Company periodically reviews long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. In 1998, the Company recorded an expense of $1,600,000 in accordance with SFAS No. 121.
Comprehensive income:
SFAS No. 130, "Reporting Comprehensive Income", defines comprehensive income as the change in equity of a business enterprise during a period from transactions and other events and circumstances from non-owner sources. SFAS No. 130 requires that an enterprise report all components of comprehensive income in the period in which they are recognized. These components are net income and other comprehensive income. Net income includes such items as income from continuing operations, discontinued operations, extraordinary items, and cumulative effects of changes in accounting principle. Other comprehensive income includes foreign currency translations, adjustments of minimum pension liability, and unrealized gains and losses on certain investments in debt and equity securities.
For the years ended December 31, 1998, 1997, and 1996, the Company's sole items of other comprehensive income were foreign currency translation adjustments of $7,363,000, $2,181,000, and $18,000, respectively, to retained earnings. There are no current income tax effects resulting from the adjustments. The 1998 adjustment included both the change in the valuation of the assets of the Company's Canadian operations and a change in the rate used to adjust certain Canadian assets. Until November 1, 1997, the plant of the Company's natural gas utility operations, owned by a wholly owned subsidiary, was included in the natural gas utility rate base. As such, the Company
earned a rate of return on these assets stated at their historical costs, converted to U.S. dollars using historical foreign currency exchange rates. When the assets were transferred from the Company's regulated operations to the Nonutility operations, and removed from utility rate base, they were converted to U.S. dollars using current foreign currency exchange rates which resulted in a decrease of approximately $5,100,000 in retained earnings in 1998.
Derivative financial instruments:
The Company has formal policies regarding the execution, recording, and reporting of derivative instruments related to the marketing and trading of electricity, oil, natural gas, and natural gas liquids. The purpose of the policies is to manage a portion of the price risk associated with its Nonutility producing assets, firm-supply commitments, and natural gas transportation agreements. The Company uses derivatives as hedging instruments to achieve earnings targets, reduce earnings volatility, and provide more stabilized cash flows. When fluctuations in natural gas and crude oil market prices result in the Company realizing gains on the derivative instruments into which it has entered, the Company is exposed to credit risk relating to the nonperformance by counterparties of their obligations to make payments under the agreements. Such risk to the Company is mitigated by the fact that the counterparties, or the parent companies of such counterparties, are investment grade financial institutions. The Company does not anticipate any material impact to its financial position, results of operations, or cash flow as a result of nonperformance by counterparties.
To manage a portion of Nonutility price risk, the Company uses a variety of derivative instruments including crude oil and natural gas swap and option agreements to hedge revenue from anticipated production of crude oil and natural gas reserves, supply costs, and transportation commitments to its firm markets. Under swap agreements, the Company receives or makes payments based on the differential between a specified price and a variable price of oil or natural gas when the hedged transaction is settled. The variable price is either a crude oil or natural gas price quoted on the New York Mercantile Exchange or a quoted natural gas price in Inside FERC's Gas Market Report or other recognized industry index. These variable prices are highly correlated with the market prices received by the Company for its natural gas and crude oil production or paid by the Company for commodity purchases. Under option agreements, the Company makes or receives monthly payments at the settlement date based on the differential between the actual price of oil or natural gas and the price established in the agreement depending on whether the Company sells or buys the option. At December 31, 1998, the Company had no hedge agreements on crude oil. The Company had swap and option agreements on approximately 1.3 Bcf of Nonutility natural gas, or 7 percent of its expected production from proved, developed, and producing Nonutility natural gas reserves through October 1999. The Company had swap and option agreements to hedge approximately 4.1 Bcf of Nonutility natural gas, or 20 percent of its expected delivery obligations under long-term natural gas sales contracts through December 1999. In addition, the Company had swap and option agreements to hedge approximately 2.3 Bcf, or 4 percent, of its Nonutility natural gas pipeline transportation obligations under contracts through October 2000.
The Company accounts for derivative transactions through hedge accounting. The Company designates all of its derivatives as fair value hedges. A fair value hedge is based on the following criteria:
? The hedged item is specifically identified as a recognized asset or a firm commitment. ? The hedged item is a single asset or a portfolio of similar assets.
? The hedged item presents an exposure to changes in fair value for the hedged risk that could affect earnings. ? The hedged item is not an asset or liability that is measured at fair value with changes in fair value attributable to the hedged risk reported currently in earnings.
Gains or losses from these derivative instruments are reflected in operating revenues on the Consolidated Statement of Income at the same time as the recognition of the revenue or expense associated with the underlying hedged item. If the Company determines that any portion of the underlying hedged item will not be produced or purchased, the unmatched portion of the instrument is marked-to-market and any gain or loss is recognized in the Consolidated Statement of Income. If the Company terminates a hedging instrument prior to the date of the anticipated natural gas or crude oil production, commodity purchase or transportation commitment, the gain or loss from the agreement is deferred in the Consolidated Balance Sheet at the termination date. At December 31, 1998, the Company had no material deferred gains or losses related to these transactions.
	The Company also has investments in independent power partnerships, some of which have entered into derivative financial instruments to hedge against interest rate exposure on floating rate debt and natural gas price fluctuations. At December 31, 1998, the Company believes it would not experience any materially adverse impacts from the risks inherent in these instruments.
SFAS No. 133, issued by the FASB in 1998, requires that all derivative instruments be recorded on an entity's balance sheet at fair value. The statement also expands the definition of a derivative and requires that changes in the fair value of the derivatives is recognized each period in current earnings or comprehensive income. The gains or losses on the derivative instruments that are reported in comprehensive income will be reclassified into current earnings in the periods in which the earnings are impacted by the variability of the cash flows of the hedged item. The ineffective portion of all hedges will be recognized in current earnings. The new statement is effective for all fiscal quarters of all fiscal years beginning after June 15, 1999. The Company has not yet determined the impact that the adoption of the new standard will have on its earnings or financial position.
Fair value of financial instruments:
			 1998 	 1997	 			Carrying	Fair 	Carrying	Fair 			 Amount 	Value	Amount 	Value 			Thousands of Dollars
Assets: 	Investments in independent 		power projects (cost basis 		 only)		$	 394	$	 1,543	$	5,584	$	9,063 	Reclamation fund		41,542	41,542	47,312	47,312 	Other significant investments		83,102	83,102	34,704	34,704
Liabilities: 	Mandatorily redeemable preferred 		securities		$	65,000	$	 69,160	$	65,000	$	70,850 	Long-term debt(including due 		within one year)		794,621		829,870		734,827	743,713
	The following methods and assumptions were used to estimate fair value:
	Investments in independent power projects - The fair value represents the Company's assessment of the present value of net future cash flows embodied in these investments, discounted to reflect current market rates of return.
	Reclamation fund and other investments - The carrying value of most of the investments approximates fair value as the investments have short maturities or the carrying value equals their cash surrender value. Fair value for the remainder of the investments was estimated based on the discounted value of the future cash flows expected to be received using a rate of return expected on similar current investments.
	Mandatorily redeemable preferred securities and long-term debt - The fair value was estimated using quoted market rates for the same or similar instruments. Where quotes were not available, fair value was estimated by discounting expected future cash flows using year-end incremental borrowing rates.
NOTE 2 - Contingencies:
The Company is required by an order of the Federal Energy Regulatory Commission (FERC) to implement a plan to mitigate the impact of Kerr Project operations on fish, wildlife, and habitat. Implementation will require payments of approximately $135,000,000 between 1985 and 2020, the license term. The net present value of the total payments, assuming a 9.5 percent discount rate, is approximately $57,000,000, an amount the Company recognized as license costs in plant and long-term debt in the Consolidated Balance Sheet in 1997. Included in the $135,000,000 is a payment of approximately $15,600,000 to fund the Fish and Wildlife Implementation Strategy for the 1985 to 1997 period.
	FERC's order is subject to judicial review by the United States Court of Appeals for the District of Columbia Circuit. Pursuant to a related FERC order, the Company is not obligated to pay approximately $15,600,000 to fund the Fish and Wildlife Implementation Strategy for the 1985 to 1997 while the order is subject to judicial review.
In November 1992, the Company applied to FERC to relicense nine Madison and Missouri River hydroelectric projects, a generating capacity of 292 MWs (Project 2188). The Company estimates that the cost of environmental mitigation proposed by FERC's staff in the license proceeding is approximately $162,000,000, net present value. A license order is expected in late 1999 or early 2000.
The Kerr Project and Project 2188 are assets to be sold under the terms of the Agreement for the Company's sale of its generation assets. For further information on the sale of the Company's interest in the generating facilities see Note 4 - "Deregulation and Asset Divestiture". At closing of the sale, PP&L Global will assume the obligation to make payments required to comply with the license conditions. The Company, however, retained the obligation to make (i) the $15,600,000 payment for the Fish and Wildlife Implementation Strategy referred to above and (ii) to the extent not reimbursed by PP&L Global through the capital and maintenance budget to be agreed upon by the Company and PP&L Global, other payments regarding "pre-closing" license compliance expenditures.
Houston Lighting & Power (Reliant Energy), the purchaser of lignite produced by Northwestern Resources Co. (Northwestern), a Company subsidiary, settled litigation regarding the terms of the Lignite Supply Agreement (LSA) between it and Northwestern. The LSA governs the delivery of approximately 9,000,000 tons of lignite per year and is effective until July 29, 2015. Northwestern realizes revenues of approximately $25,000,000 per year from management and dedication fees under LSA terms. Under the terms of the settlement, lignite prices will continue to be set under the pre-settlement LSA pricing terms until June 30, 2002. Reliant Energy will pay from July 1, 2002 through July 30, 2015, the lesser of a re-determined price set to be competitive with Powder River Basin Coal supplies, or the price that would have otherwise been paid under the pre-settlement LSA pricing terms. Reliant Energy and Northwestern are negotiating terms to amend the LSA and implement the settlement.
The Company and its subsidiaries are party to various other legal claims, actions, and complaints arising in the ordinary course of business. Management does not expect disposition of these matters to have a material adverse effect on the Company's consolidated financial position or its consolidated results of operations.
NOTE 3 - Commitments:
Purchase commitments:
In 1994, the Company entered a contract to purchase 98 MWs of seasonal capacity from Basin Electric Power Cooperative (Basin). The rate for the contract year beginning in November 1997 was approximately 3.2 cents per kWh and will increase each subsequent year to approximately 7.4 cents per kWh in the final contract year, which begins in November 2009. This contract is included in the asset sale agreement with PP&L Global for the sale of the Company's interest in the generating facilities. Although not specifically named in the restructuring legislation, costs associated with disposal and reassignment of this contract are also expected to be collectable through the Competitive Transition Charges (CTC).
	The Company also has long-term purchase contracts with certain qualifying facilities (QF's) and natural gas producers. The purchased power contracts provide for capacity payments subject to a facility meeting certain operating standards, and payments based on energy received. The Company currently has 15 QF contracts, with expiration terms ranging from 2003 through 2031. Three contracts account for 96 percent of the 101 MWs of capacity provided by these facilities. These QF contracts were intended to be sold or reassigned in conjunction with the Company's sale of electric generating facilities, however, they were excluded from the asset sale agreement with PP&L Global. Management is evaluating options for dealing with these contracts. In accordance with the restructuring legislation, costs associated with disposal and reassignment of these contracts are also expected to be collected through the CTC.
The Nonutility operations have one natural gas take-or-pay contract that expires in 2006, natural gas transportation contracts that begin expiring in 2000 and two electric firm capacity contracts that expire in mid-2001.
	A Nonutility lignite lease purchase agreement requires minimum annual payments, beginning in 1991 in the amount of $1,125,000 escalated quarterly by the Gross National Product implicit price deflator. The payments will continue until the equivalent of $18,750,000, in 1986 dollars, has been paid. At December 31, 1998, the remaining payments under this agreement were $7,152,000. Under current mine plans, these payments should be recovered through lignite sales.
	Total payments under all of these contracts for the prior three years were as follows:
	 Thousands of Dollars	 	 Utility	 	Nonutility	 Total 		Electric		Natural Gas		
	1996		$	30,751	$	8,100	$	3,245	$	42,096 	1997			44,153		7,554		3,289		54,996 	1998			50,611		2,998		19,809		73,418
	The present value of future minimum payments, at an assumed discount rate of 8 percent, under the above agreements is estimated as follows:
	 Thousands of Dollars	 	 Utility 		Nonutility	 Total 		Electric		Natural Gas		
	1999		$	15,979	$	3,554	$	27,317	$	46,850 	2000			15,113		3,225		25,608		43,946 	2001			14,787		2,767		10,235		27,789 	2002		14,587	2,433	1,820	18,840 2003			14,346		746		1,685		16,777 	Remainder			151,801		1,291		16,338		169,430 		$	226,613	$	14,016	$	83,003	$	323,632
	In 1997, Touch America entered a joint construction effort with Williams Companies and Enron called FTV Communications LLC (FTV) for the purpose of constructing a fiber-optic route from Portland, Oregon to Los Angeles, California. From October 1997 to December 1998, Touch America has loaned FTV $28,500,000 in separate notes of various amounts at fixed rates of interest of approximately 6 percent per annum. These notes are payable on demand, except that any payments depend on the unanimous vote of the members of FTV. Construction of the route will cost in excess of $100,000,000. At December 31, 1998, the Company estimated that remaining construction costs will be less than $10,000,000. Payment of all the notes outstanding is expected upon the completion of construction, which is scheduled to be completed in the second quarter of 1999.
In October 1998, the Company contracted with Northern Telecom, Inc. to upgrade equipment on certain fiber-optic cable networks and install such equipment on recently constructed networks. These projects are expected to be completed in the fourth quarter of 2000 at a cost of $33,900,000, of which $12,000,000 was paid in 1998, and $16,500,000 and $5,400,000 are expected to be paid in 1999 and 2000, respectively.
In December 1998, the Company entered into a contract to implement an enterprise resource planning system (ERP) to better manage its information resources. The system is scheduled for completion in September 2000 at a cost of approximately $40,000,000.
Sales commitments:
	The Nonutility oil and natural gas operations have agreed to supply approximately 92 Bcf of natural gas to four co-generation facilities. These contracts begin expiring in 2005. The Company has sufficient proven, developed, and undeveloped reserves, and controls related sales of production sufficient to supply all of the remaining natural gas required by these contracts.
The Company has several commitments to sell electricity under contracts, which have terms expiring over the next six years. One such contract includes a fixed-price for a portion of the deliveries. When the sale of the Company's generation assets is finalized, and to the extent that this contract is not addressed in the electric restructuring transition process, the Company will be subject to the commodity price risks associated with supplying that portion of the contract. However, due to the uncertainties relating to the supply requirements of the contract, the timing of the sale of the generation assets, and the eventual outcome of the electric restructuring process, the Company cannot determine at this time the potential effects of this contract on the Company's future results of operations.
Lease commitments:
	On December 30, 1985, the Company sold its 30 percent share of Colstrip Unit 4 and is leasing back this share under a net lease. The transaction has been accounted for as an operating lease with annual lease payments of approximately $32,000,000 over the remaining term of the 25-year lease. The unregulated leasehold interest and its related assets and liabilities and contract obligations will be sold as part of the generation sale to PP&L Global and accordingly the lease would be assumed by the buyer. There are no other material minimum operating lease payments. Capitalized leases are not material and are included in other long-term debt.
	Rental expense for the prior three years, including Colstrip Unit 4, was $58,800,000, $56,600,000, and $55,500,000 for 1998, 1997, and 1996 respectively.
Note 4 - Deregulation and asset divestiture:
Natural Gas
Since 1991, the Company's natural gas utility business has been in transition to a competitive environment to provide commodity and related services to wholesale and retail customers. In Montana, the "Natural Gas Restructuring and Customer Choice Act" was signed into law in May 1997 allowing natural gas utilities to open their systems to full customer choice for gas supply.
In response to the Company's restructuring filing, in October 1997, the PSC approved an order (Order) giving additional natural gas customers of the Company the right to choose their own suppliers. The decision allowed approximately 230 smaller industrial and larger commercial customers using 5,000 dekatherms or more of natural gas annually, to have choice beginning in November 1997. The 24 former natural gas supply customers using 60,000 or more dekatherms of natural gas annually, who represented approximately 49 percent of the pre-choice load, have had choice since 1991. The Company's remaining 140,000 customers will have choice no later than July 1, 2002. Pilot programs for natural gas customers began on November 2, 1998. Through December 1998, approximately 232 customers, representing approximately 54 percent of the Utility's pre-choice natural gas supply load have chosen alternate suppliers.
Natural gas transmission, distribution, and storage will remain regulated by the PSC and the Company retains the right to seek rate adjustments related to these services after a two year rate freeze. The Company will also continue to offer regulated supply service at rates set by the PSC for the transition period or such shorter period as determined by the PSC. Following this period, the Company will offer natural gas supply to retail and wholesale customers through its unregulated business segments.
In accordance with the Order, in November 1997, significantly all of the Utility natural gas production assets were transferred to an unregulated affiliate at an agreed-to amount, which was $33,600,000 below the existing book value. This difference between transfer value and the book value and the existing $25,400,000 of regulatory assets related to the natural gas production assets were approved as a Competitive Transition Charge (CTC) to be recovered from transmission and distribution customers in rates over a 15-year period. The transition plan also includes a fixed-price supply contract through 2002 between the unregulated gas supply division and the regulated distribution division to serve the remaining customers who have not chosen other suppliers.
The Order also froze base rates for two years and accepted the continuation of the gas cost tracker and the Gas Transportation Clause (GTAC) procedures.
Electric
Montana's "Electric Industry Restructuring and Customer Choice Act" was also signed into law in May 1997. The legislation provided for choice of electricity supplier for the Company's large customers by July 1, 1998, for pilot programs for residential and small commercial customers by July 1, 1998 and choice for all customers no later than July 1, 2002. Through December 1998, approximately 50 customers, representing approximately 10 percent of the Utility's pre-choice load have chosen alternate suppliers. As with the Utility natural gas business, transmission and distribution services will remain fully regulated by FERC and the PSC and the Company retained the right to seek rate adjustments related to these services.
The legislation provides the collection of CTC's by the Company in order to recover its non-mitigatable transition costs, specifically recovery of above-market qualifying facility power-purchase contract costs and regulatory assets associated with the generation business, and recovery for utility-owned above-market generation costs over the transition period of up to four years. The legislation also established a rate moratorium on electric rates for all customers for two years beginning July 1, 1998, and an electric-energy supply component rate moratorium for an additional two years for smaller customers. The legislation provides that rates cannot be increased under the rate moratorium except under limited circumstances.
As required by the electric legislation, the Company filed a comprehensive transition plan with the PSC in July 1997. The filing contained the Company's transition plan, including the proposed handling and resolution of transition costs, and addressed other issues required by the legislation. Initial hearings on the filing began in April 1998 and the issues involved in the restructuring filing were separated into groups. The PSC rendered a decision in June 1998 on the issues relating to customer choice for the large industrial group and the pilot programs. Pilot programs for electric customers began concurrently with the natural gas pilot program on November 2, 1998. The Company expects a decision on the remaining issues, including the amount of transition costs, the effect of the sale of the generation assets discussed below, and the Uniform Systems Benefits Charge once the details of the sale are final.
On November 2, 1998, the Company announced that it had entered into a definitive Asset Purchase Agreement (the Agreement) with PP&L Global, Inc (PP&L Global), a subsidiary of PP&L Resources, Inc. Under the Agreement, PP&L Global agreed to purchase the Company's interest in 12 of its 13 hydroelectric facilities, all four coal-fired thermal generating plants, and a leasehold interest in Colstrip Unit 4 for a total gross capacity of 1,557 MWs. PP&L Global will also acquire the power purchase contract with Basin and two power exchange agreements. The sale does not include the power purchase contracts with QF's or the 3-MW Milltown Dam near Missoula, Montana.
The sale is subject to the satisfaction of various conditions and the receipt of required regulatory approvals. The transfer of the Company's licenses to operate the hydroelectric facilities is subject to approval by the FERC. Final determination of proceeds and the related transmission facilities to be included in the sale are subject to the sales of two other owners' interests in the Colstrip plants, which must be approved by those owners' state regulatory commissions. The sale of the Company's unregulated leasehold interest in Colstrip Unit 4 is subject to approval by the purchasers of power under two long-term sales agreements related to that unit. Although the Agreement is not contingent upon inclusion of Colstrip Unit 4, such inclusion, or the potential exclusion, will impact the amount of proceeds received as well as the amount of transmission facilities included in the sale. The Company anticipates this transaction will be completed by the end of 1999.
Although the Company has remained in the electric trading business to take full advantage of the opportunities to sell excess and buy needed electricity, and fulfill contractual commitments, the Company will exit the electric commodity trading and marketing business following the sale.
The costs of completion of these potential transactions include legal, accounting, and consulting fees, employee-related costs, asset relocation costs, and other expenses. Total transaction costs may reach $50,000,000 and will reduce the proceeds realized from the sale. There may also be income taxes associated with the transactions.
The Company's Mortgage and Deed of Trust imposes a lien on all physical properties including the generation assets and pollution control equipment on
some of the thermal generating facilities, therefore, restrictions may exist on the use of proceeds.
This divestiture is expected to be a complex process involving many factors. The Company may have little or no direct control over some of these factors; therefore, it can give no assurance as to the successful implementation. If the Company is unsuccessful in implementing the sale of the generation assets or any other elements of the deregulation process, the potential exists for writeoff of regulatory assets and the recording of effects of adverse purchase power contracts. The restructuring legislation does, however, provide for, and management is expecting, full recovery of all regulatory assets and other transition costs.
On March 30, 1998, the Company submitted a filing with the FERC requesting increased rates for bundled wholesale electric service to two rural electric cooperatives. Resolution of this filing is expected before the end of 1999.
As in the natural gas legislation, the issuance of transition bonds was approved to lower transition costs. During the electric transition period, savings related to these financings are available to the Company to offset cost increases that would not be reflected in rates due to the rate moratorium. In addition, under the legislation, if, during the transition period, the earnings of the electric utility fall below a predetermined return on equity, the utility's obligation to flow investment tax credit (ITC) benefits to ratepayers in future years is reduced. Any such ITC reduction in the utility's regulatory obligation provides an economic benefit to the Company and increases income in that year. No such benefit was recognized in the results of operations for 1998.
	The change in net deferred tax liabilities differs from current year deferred tax expense as a result of the following:
				Thousands of 			 Dollars Change in noncurrent deferred tax		$(16,345) Regulatory assets related to income taxes		1,168 Current deferred tax assets-net		(8,216) Amortization of investment tax credits		(1,363) Other		 23 	Deferred tax expense			$(24,733)
NOTE 6 - Common stock:
	The Company has a Shareholder Protection Rights Plan that 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, 2009, unless redeemed earlier or exchanged by the Company.
	The Company's Board of Directors has authorized a share repurchase program over the next five years to repurchase up to 10,000,000 shares, or 18 percent, of the Company's outstanding common stock.
	As of yearend 1998, the Company had 55,060,520 common shares outstanding. The repurchase of common stock may be made, from time to time, on the open market or in privately negotiated transactions. The number of shares to be purchased and the timing of the purchases will be based on the level of cash balances, general business conditions, and other factors, including alternative investment opportunities.
	The Company's Dividend Reinvestment and Stock Purchase Plan permits participants to: (a) acquire additional shares of common stock through the reinvestment of dividends on all or any specified number of common and/or preferred shares registered in their own names, or through optional cash payments of up to $60,000 per year; (b) deposit common and preferred stock certificates into their Plan accounts for safekeeping; and allows for other interested investors (residents of certain states) to make initial purchases of common shares with a minimum of $100 and a maximum of $60,000 per year.
	The Company has a Retirement Savings Plan (Plan) that covers all regular eligible employees. The Company, on behalf of the employee, contributes a matching percentage of the amount contributed to the Plan by the employee. In 1990, the Company borrowed $40,000,000 at an interest rate of 9.2 percent to be repaid in equal annual installments over 15 years. The proceeds of the loan were lent on similar terms to the Plan Trustee, which purchased 1,922,297 shares of Company common stock. The loan, which is reflected as long-term debt, is offset by a similar amount in common shareholders' equity as unallocated stock. Company contributions plus the dividends on the shares held under the Plan are used to meet principal and interest payments on the loan. Shares acquired with loan proceeds are allocated to Plan participants. As principal payments on the loan are made, long-term debt and the offset in common shareholders' equity are both reduced. At December 31, 1998, 1,122,347 shares had been allocated to the participants' accounts. Expense for the Plan is recognized using the Shares Allocated Method, and the pre-tax expense was $4,923,000, $5,194,000 and $6,046,000 for 1998, 1997, and 1996, respectively.
	Under the Long-Term Incentive Plan, options have been issued to Company employees. Options issued to employees are not reflected in balance sheet accounts until exercised, at which time (i) authorized, but unissued shares are issued to the employee, (ii) the capital stock account is credited with the proceeds and (iii) no charges or credits to income are made. Options issued to Nonutility employees under the Key Employee Incentive Stock Option Plan 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. Options were granted at the average of the high and low prices as reported on the New York Stock Exchange composite tape on the date granted, and expire ten years from that date.
	Previously, restricted stock awards of 66,335 shares were issued to certain Nonutility employees under the Long-Term Incentive Plan. Upon the achievement of performance goals and passage of time constraints, restrictions will be lifted and participants will retain, at no cost, the unrestricted shares. As they are earned, the awards are reflected as common stock and compensation expense on the Balance Sheet and Income Statement, respectively. At December 31, 1998, there were 9,285 shares of restricted stock remaining.
	Shares under option at December 31, 1998 are summarized below:
	As permitted by SFAS No. 123, "Accounting for Stock-Based Compensation", the Company has elected to follow Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" (APB 25) and related interpretations in accounting for its employee stock options. Under APB 25, because the exercise price of the Company's employee stock options equals the market price of the underlying stock on the date of grant, no compensation expense is recognized. Disclosure of pro-forma information regarding net income and earnings per share is required by SFAS No. 123. This information has been determined as if the Company had accounted for its employee stock options under the fair value method of that statement. The weighted-average fair value of options granted in 1998 and 1996 was $7.12 and $1.73 per share, respectively. The fair value of each option grant was estimated on the date of grant using the binomial option-pricing model with the following weighted- average assumptions used for grants in 1998 and 1996, respectively: risk-free interest rate of 5.08 percent and 6.87 percent; expected life of 10 and 8.4 years; expected volatility of 19.34 percent and 10.46 percent and a dividend yield of 6.51 percent and 6.83 percent. Had the Company used SFAS No. 123, compensation expense would have increased $795,000, $195,000, and $108,000 for 1998, 1997, and 1996 respectively.
NOTE 7 - Preferred stock:
	The number of authorized shares of preferred stock is 5,000,000. No dividends may be declared or paid on common stock while cumulative dividends have not either been declared and set apart or paid on any of the preferred stock.
	Preferred stock is in three series as detailed in the following table:
	 Stated and 	 Shares Issued 	 Thousands 	Liquidation	 and Outstanding 	 of Dollars Series	 Price* 	 1998 	 1997 	 1998 	 1997 	$6.875	$100	360,800	360,800	$ 36,080	$ 36,080 6.00		100	159,589	159,589	15,959	15,959 4.20		100	60,000	60,000	6,025	6,025 Discount		 	 	 (410)	 (410) 			 580,389	 580,389	$ 57,654	$ 57,654
	*Plus accumulated dividends.
	The preferred stock is redeemable at the option of the Company upon the written consent or affirmative vote of the holders of a majority of the common shares on thirty days notice at $110 per share for the $6.00 series and $103 per share for the $4.20 series, plus accumulated dividends. The $6.875 series is redeemable in whole or in part, at anytime on or after November 1, 2003 for a price beginning at $103.438 per share with annual decrements through October 2013, after which the redemption price is $100 per share.
NOTE 8 - Company obligated mandatorily redeemable preferred securities of subsidiary trust:
	Montana Power Capital I (Trust) was established as a wholly owned business trust of the Company for the purpose of issuing common and preferred securities (Trust Securities) and holding Junior Subordinated Deferrable Interest Debentures (Subordinated Debentures) issued by the Company. At December 31, 1998 and 1997, the Trust held 2,600,000 units of 8.45 percent Cumulative Quarterly Income Preferred Securities, Series A (QUIPS). Holders of the QUIPS are entitled to receive quarterly distributions at an annual rate of 8.45 percent of the liquidation preference value of $25 per security. The sole asset of the Trust is $67,000,000 of Subordinated Debentures, 8.45 percent Series due 2036, issued by the Company. The Trust will use interest payments received on the Subordinated Debentures it holds to make the quarterly cash distributions on the QUIPS.
	The Trust Securities are subject to mandatory redemption upon repayment of the Subordinated Debentures at maturity or redemption. The Company has the option at any time on or after November 6, 2001, to redeem the Subordinated Debentures, in whole or in part. The Company also has the option, upon the occurrence of certain events, to redeem the Subordinated Debentures, in whole but not in part, which would result in the redemption of all the Trust Securities. The Company has the right to terminate the Trust at any time and cause the pro rata distribution of the Subordinated Debentures to the holders of the Trust Securities.
	In addition to the Company's obligations under the Subordinated Debentures, the Company has guaranteed, on a subordinated basis, payment of distributions on the Trust Securities, to the extent the Trust has funds available to pay such distributions and has agreed to pay all of the expenses of the Trust (such additional obligations collectively, the Back-up Undertakings). Considered together with the Subordinated Debentures, the Back-up Undertakings constitute a full and unconditional guarantee by the Company of the Trust's obligations under the QUIPS. The Company is the owner of all the common securities of the Trust, which constitute 3 percent of the aggregate liquidation amount of all the Trust Securities.
NOTE 9 - Long-term debt:
	The Company's Mortgage and Deed of Trust (the Mortgage) imposes a first mortgage lien on all physical properties owned, exclusive of subsidiary company assets, and certain property and assets specifically excepted. The obligations collateralized are First Mortgage Bonds, including those First Mortgage Bonds designated as Secured Medium-Term Notes and those securing Pollution Control Revenue Bonds. The Mortgage may impose some restrictions on the use of proceeds realized from the sale of the electric generating assets and power purchase contracts.
	Long-term debt consists of the following:
	 December 31 	 1998 	 1997 	Thousands of Dollars First Mortgage Bonds: 	7.7% series, due 1999		$	 55,000	$	55,000 	7 1/2% series, due 2001		25,000	25,000 	7% series, due 2005		50,000	50,000 	8 1/4% series, due 2007		55,000	55,000 	8.95% series, due 2022		50,000	50,000 	Secured Medium-Term Notes - 		maturing 1999-2025 7.20%-8.11%		88,000	108,000 	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			15,500 Natural Gas Transition Bonds -6.20%, due 2012		62,700	 ESOP Notes Payable - 9.2%, due 2004		22,392	25,104 Unsecured Medium-Term Notes: 	Series A - maturing 1998-2022 8.68%-8.9%		19,500	22,000 	Series B - maturing 2006-2026 7.07%-7.96%		115,000	55,000 Revolving Credit Agreements		14,241	45,715 Other		71,779	62,269 Unamortized Discount and Premium			(4,196)		(3,966) 	794,621	734,827 Less: Portion due within one year			96,292		81,659 		$	698,329	$	653,168
Both the electric and natural gas legislation authorized the issuance of transition bonds, often referred to as securitization which involves the issuance of a non-recourse debt instrument which is repaid through, and secured by, the recovery of the regulatory assets through a specified component of future revenues, thereby reducing the credit risk of the securities. This specific component of revenues is referred to as a competitive transition charge (CTC). Following the April 1998 natural gas related PSC Financing Order approving issuance of up to $65,000,000 of such bonds, in December 1998, $62,700,000 of bonds, carrying a 6.2 percent interest rate and maturing in March 2013, were issued by a special purpose entity (SPE) which is a wholly owned subsidiary of the Company. At December 31, 1998, approximately $1,700,000 is classified as due within one year in the Consolidated Balance Sheet.
Although the bonds were issued by an SPE and are without recourse to the general credit of the Company, the bonds are shown as debt on the Consolidated Balance Sheet of the Company. Similarly, the right to receive the revenues pledged to secure the bonds is a specific right of the SPE and not the Company. However, as a wholly owned subsidiary of the Company, revenues and expenses of the SPE are shown as revenues and expenses on the Consolidated Statement of Income of the Company. However, due to the regulatory mechanism
for recognizing the operations of the SPE, including the amortization of the regulatory assets, it is not expected to have a material impact on the results of operations of the Company.
In order to ensure that the collections by the SPE are neither more nor less than the amount necessary to pay interest and principal, and the other related issuance costs, the Company is required to file for, and the PSC is required to approve periodic adjustments, or true-ups, to the annual amounts to be collected by the SPE.
In December 1997, Altana Exploration Ltd. (Altana), a wholly owned Canadian subsidiary purchased the stock of a Canadian company, for approximately $26,500,000 in U.S. dollars. Financing for the purchase was provided through an Extendible Revolving Term Credit Agreement between Altana and the Royal Bank of Canada. The maximum amount of credit available under this Agreement is $28,000,000 in Canadian dollars. At December 31, 1998 and 1997, the U.S. dollar amounts outstanding under the agreement were $14,241,000 ($21,796,000 Canadian dollars) and $15,715,000 ($22,459,000 Canadian dollars), respectively. These amounts are included in "Revolving Credit Agreements" in the table above. 	 In April 1997, the Company entered into a $160,000,000 Revolving Credit Agreement for certain of its Nonutility operations. Under terms of the new Agreement, the amount of the facility decreased on March 31, 1998, reducing the borrowing ability to $100,000,000. This Agreement terms on April 4, 2000, and all outstanding borrowings must be repaid on this date. Fixed or variable interest rate options are available under the facility with facility fees or commitment fees on the unused portions.
	In June 1997, in response to FERC's decision regarding the Kerr mitigation plan discussed in Item 8, "Financial Statements and Supplementary Data - Note 2 to the Consolidated Financial Statements", the Company recognized long-term debt of approximately $57,000,000 which is included in "Other" in the table above. Approximately $31,000,000 is classified as due within one year in the Consolidated Balance Sheet at December 31, 1998.
	Debt repayments for the five years ending December 31, 2003, on the long- term debt outstanding at December 31, 1998, amount to: $96,000,000 in 1999; $38,000,000 in 2000; $46,000,000 in 2001; $9,000,000 in 2002; and $25,000,000 in 2003.
NOTE 10 - Short-term borrowing:
	The Company has short-term borrowing facilities with commercial banks that provide both committed, as well as uncommitted lines of credit, and the ability to sell commercial paper. Bank borrowings either bear interest at the lender's floating base rate and may be repaid at any time, or have fixed rates of interest and maturities. Commercial paper has fixed rates of interest and maturities.
	At December 31, 1998, the Company had lines of credit consisting of $110,000,000 committed and $105,000,000 uncommitted. There are facility fees or commitment fees on the committed lines of credit which are not significant. The Company has the ability to issue up to $145,000,000 of commercial paper based on the total of unused committed lines of credit and revolving credit agreements.
	Short-term borrowings and average interest rates were as follows:
	 December 31	 		 1998 	 1997 			 Amount 	Rate	 Amount 	Rate 	Thousands of Dollars
	Notes payable to banks		$ 40,000	5.87%	$ 89,100	6.82% 	Commercial paper			29,820	6.04%		44,858	6.46% 		$ 69,820		$133,958
NOTE 11 - 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.
	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. In December 1998, the Company curtailed the plan and in accordance with SFAS No. 88, "Employers' Accounting for Settlements and Curtailments of Defined Benefit Pension Plans" accrued approximately $4,000,000 of expense.
	In addition to providing pension benefits, the Company and its subsidiaries provide certain health care and life insurance benefits for eligible retired employees. In 1994, the Company established a pre-funding plan for postretirement benefits for Utility employees retiring after January 1, 1993. The assets of the plan consist primarily of domestic and foreign corporate stocks, domestic corporate bonds, and U.S. Government securities. The PSC allows the Company to include in rates all Utility OPEB cost on the accrual basis provided by SFAS No. 106.
	The following tables provide a reconciliation of the changes in the plans' benefit obligations and fair value of assets over the two-year period ending December 31, 1998, and a statement of the funded status as of December 31 of both years:
			 Pension Benefits 		 Other Benefits 			 1998 	 1997 	 1998 	 1997 			 Thousands of Dollars 	Benefit obligation at January 1		$247,903	$221,459	$ 25,153	$ 25,294 	Service cost on benefits earned		8,170	6,595	1,019	803 	Interest cost on projected benefit 		obligation		18,289	16,285	1,864	1,677 	Plan amendments		8,387	325		 	Actuarial (gain)/loss		5,878	12,891	1,909	(1,833) 	Curtailments		(4,303)	137		 	Gross benefits paid		(10,923)	 (9,789)	 (2,269)	 (788) 	Benefit obligation at December 31		$273,401	$247,903	$ 27,676	$ 25,153
	Fair value of plan assets at 		January 1		$259,059	$222,866	$ 8,168	$ 5,740 	Actual return on plan assets		39,765	40,375	1,036	993 	Employer contributions			4,000	1,847	1,908 	Gross benefits paid		 (8,943)	 (8,182)	 (2,269)	 (473) 	Fair value of plan assets 		at December 31		$289,881	$259,059	$ 8,782	$ 8,168
			 Pension Benefits 		 Other Benefits 			 1998 	 1997 	 1998 	 1997 			 Thousands of Dollars 	Funded status at January 1		$ 16,463	$ 11,156	$(18,894)	$(16,984) 	Unrecognized net: 		Actuarial gain		(54,169)	(40,473)	(6,582)	(8,583) 		Prior service cost		12,980	8,691	826	 		Transition obligation		 (337)	 1,905	 16,988	 18,194 	Net amount recognized 		at December 31		$ (25,063)	$(18,721)	$ (7,662)	$ (7,373)
		The following table provides the amounts recognized in the statement of financial position as of December 31 of both years:
			 Pension Benefits 		 Other Benefits 			 1998 	 1997 	 1998 	 1997 			 Thousands of Dollars 	Prepaid benefit cost		$ 4,028	$ 2,403	 	 	Accrued benefit cost		(29,091)	(21,124)	$ (7,662)	$ (7,373) 	Additional minimum liability (net)				(4,618)		 	Intangible asset			4,618		 	Net amount recognized 		at December 31		$(25,063)	$(18,721)	$ (7,662)	$ (7,373)
	The following tables provide the components of net periodic benefit cost for the pension and other postretirement benefit plans, portions of which have been deferred or capitalized, for fiscal years 1998, 1997, and 1996:
	 Pension Benefits 	 1998 	 1997 	 1996 	Thousands of Dollars 	Service cost on benefits earned		$ 8,079	$ 6,625	$ 7,956 	Interest cost on projected benefit 		obligation		18,238	16,316	15,810 	Expected return on plan assets		(22,870)	(19,900)	(16,541) 	Amortization of: 		Transition obligation (asset)		358	383	375 		Prior service cost (credit)		1,468	965	902 		Actuarial (gain) loss		 (1,062)	 (1,474)	 250 	Immediate recognition of DC conversion 		 (142)	 	 	Net periodic benefit cost		 4,069	 2,915	 8,752 	Curtailment (gain) loss		 3,964	 960	 	Net periodic benefit cost after 		curtailments		$	8,033	$	3,875	$	8,752
	 Other Benefits 	 1998 	 1997 	 1996 	Thousands of Dollars 	Service cost on benefits earned		$ 1,020	$ 803	$ 1,074 	Interest cost on projected benefit 		obligation		1,864	1,677	1,768 	Expected return on plan assets		(671)	(459)	(349) 	Amortization of: 		Transition obligation (asset)		1,206	1,185	1,224 		Prior service cost (credit)		69		 		Actuarial (gain) loss		 (346)	 (448)	 (172) 	Net periodic benefit cost		$	3,142	$	2,758	$	3,545
		In 1998, funding for pension costs exceeded SFAS No. 87 pension expense by $1,780,000. In 1997, pension costs exceeded SFAS No. 87 pension expense by $5,441,000, and in 1996, pension costs funded were less than SFAS No. 87 pension expense by $188,000. The differences were deferred for recognition in future periods as funding is reflected in rates. At December 31, 1998, the regulatory liability was $4,125,000.
		The following assumptions were used in the determination of actuarial present values of the projected benefit obligations:
			 Pension Benefits 		 Other Benefits 			 1998 	 1997 	 1998 	 1997
	Weighted average assumptions as 		of December 31 	Discount rate		6.75%	 7.00%	 6.75%	 7.00% 	Expected return on plan assets		9.00%	 9.00%	 9.00%	 9.00% 	Rate of compensation increase		3.97%	 4.89%	 3.75%	 4.50%
		Assumed health care costs trend rates have a significant effect on the amounts reported for the health care plans. A 1 percent change in assumed health care cost trend rates would have the following effects:
	1% Increase		1% Decrease 			Thousands of Dollars 	Effect on total of service and interest 		cost component of net periodic post- 		retirement health care benefit cost		$ 194	$ (182) 	 	Effect on the health care component of 		the accumulated postretirement benefit 		obligation		 1,483	 (1,368)
	The assumed 1999 health care cost trend rates used to measure the expected cost of benefits covered by the plans is 7.50 percent. The trend rate decreases through 2004 to 5 percent.
	In 1995, the Company accrued the estimated expected postretirement benefit obligation for the plan curtailment at its Colorado mining operations as part of the writedown of long-lived assets. As such, these operations are no longer included in the above numbers.
NOTE 12 - Information on industry segments:
	The Company operates a regulated Utility involving the generation, purchase, transmission, and distribution of electricity and the purchase, transportation, and distribution of natural gas. The Company's Nonutility operations principally involve telecommunication operations which sells long distance, Internet, and dedicated line services and equipment and designs, develops, constructs, operates, maintains, and manages a fiber-optic network and digital microwave facilities. Other Nonutility operations include the mining and sale of coal and lignite, exploration for, and the development, production, processing, and sale of oil and natural gas. It also conducts the trading of electricity and trading and marketing of natural gas. In addition, the Company manages long-term power sales, and develops and invests in independent power projects and other energy-related businesses.
	The Company's open-access and reorganization plan for its regulated Natural Gas Utility was approved for implementation by the PSC, effective November 1, 1997. Under the approved plan, significantly all of the regulated Utility's natural gas production assets, including those of its Canadian subsidiary, were transferred to its unregulated oil and natural gas operations as of that date.
	Financial information relating to the segment information for foreign operations is not considered material.
	SUPPLEMENTARY DATA 	OIL AND NATURAL GAS PRODUCING ACTIVITIES
	For the years ended December 31, 1998, 1997, and 1996, net recoverable oil and natural gas reserves, excluding royalty volumes and volumes controlled under purchase contract, of the Utility and Nonutility operations were estimated as follows:
SUPPLEMENTARY DATA Oil and Natural Gas Producing Activities (Cont.)
		As determined by engineers, Utility natural gas reserves were revised during 1997 and 1996 due to changes in projected performance or changes in the Company's ownership interest in specific fields. On November 1, 1997, the PSC approved the deregulation of the Utility's natural gas production properties, the result of which was the transfer of all of the Canadian and significantly all of the U.S. natural gas reserves to the Nonutility operations. Since that date, Utility natural gas reserves have been produced to maintain Utility natural gas storage leases and to supply fuel for electric generation.
	Nonutility U.S. natural gas and natural gas liquid reserves increased in 1998 with the addition of undeveloped reserves in Colorado and successful drilling in Wyoming and Oklahoma. However, the additions were partially offset by downward price revisions of petroleum products. That downward price revision also caused a significant decrease in U.S. oil reserves. The Canadian natural gas reserves increased because of successful exploratory drilling in Southeast Alberta. Oil reserves in Canada decreased due to the sale of an Alberta producing property and downward price revisions. Canadian oil and natural gas reserves were also revised downward to reflect poorer than expected performance in two fields.
	Nonutility U.S. natural gas and natural gas liquid reserves increased in 1997 because of the acquisition of reserves in place, successful drilling in Oklahoma and Wyoming, and the transfer of previously regulated Montana properties. Oil reserves decreased because of the sale of reserves in Kansas. The Canadian natural gas reserves increase is due to the purchase of reserves in place, and transfer of previously regulated Canadian properties to the Nonutility Supply Division. Oil reserves in Canada also decreased because of the sale of some Alberta properties.
	When the Utility owned the reserves that were transferred to the Nonutility on November 1, 1997, petroleum engineers estimated reserves on the basis of Utility business guidelines; that is, mechanical recoverability at reasonable and prudent costs. With deregulation and transfer, petroleum engineers began to estimate reserves on the basis of mechanical recoverability under market price conditions. Estimating reserves on that basis has resulted in downward revisions of Nonutility U.S. and Canadian natural gas reserves in 1997.
	In 1996, the Nonutility U.S. natural gas and oil reserves increased as a result of higher market prices and the acquisition of reserves in place. Natural gas reserves were added through the purchase of interests in 250 wells in northeastern Montana. Oil reserves were added with the purchase of additional interest in an existing Montana field. The Canadian natural gas and oil reserves decreased primarily as a result of downward revisions of engineering estimates for undeveloped reserves.
	The following table presents information for 1998, 1997, and 1996 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 net cost of natural gas in underground storage is 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 1998, 1997, and 1996 on the capitalized costs relating to Nonutility oil and natural gas producing activities, costs incurred in Nonutility oil and natural gas property acquisition, exploration and development activities and results of Nonutility operations for oil and natural gas producing activities:
SUPPLEMENTARY DATA Oil and Natural Gas Producing Activities (Cont.)
	Estimated future cash flows are computed by applying year-end prices and contract prices, when appropriate, of oil and natural gas to year-end quantities of proved reserves. Estimated future development and production costs are determined by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at the end of the year, based on year-end costs. Estimated future income tax expenses are calculated by applying year-end statutory tax rates to estimated future pre-tax net cash flows related to proved oil and natural gas reserves, less the tax basis of the properties involved. The future income tax expenses give effect to permanent differences, tax credits and deferred taxes relating to proved oil and natural gas reserves.
	These estimates are furnished and calculated in accordance with requirements of the Financial Accounting Standards Board and the Securities and Exchange Commission (SEC). Management believes the usefulness of these projections is limited because of the unpredictable variances in expenses, capital forecasts and crude oil and natural gas prices. Estimates of future net cash flows presented do not represent management's assessment of future profitability or future cash flow to the Company. Management's investment and operating decisions are based upon reserve estimates that include proved reserves prescribed by the SEC as well as probable reserves, and upon different price and cost assumptions from those used here.
	Extensions, discoveries, and improved recovery, less related costs, represent the present value of current year reserve additions valued at year-end prices less actual unit production costs for the current year. For the years 1998 and 1997, the amount described as other is primarily the result of changes in the timing of production.
QUARTERLY FINANCIAL DATA
	Operating revenues, operating income, and net income in thousands of dollars and net income per common share for the four quarters of 1998 and 1997 are shown in the tables below. Operating revenues and income include intersegment sales and expenses. Due to the seasonal nature of the utility business, the annual amounts are not generated evenly by quarter during the year.
ITEM 9.
ITEM 9.	DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
	None.
	PART III
ITEM 10.
ITEM 10.	DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
	See Part 1, "Executive Officers of the Registrant."
	Information on The Montana Power Company Directors is incorporated by reference from the Company's Notice of 1999 Annual Meeting of Shareholders and Proxy Statement, pages 5-6.
ITEM 11.
ITEM 11.	EXECUTIVE COMPENSATION
	Incorporated by reference from Notice of 1999 Annual Meeting of Shareholders and Proxy Statement, pages 9-18.
ITEM 12.
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
	Incorporated by reference from Notice of 1999 Annual Meeting of Shareholders and Proxy Statement, pages 7-8.
ITEM 13.
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
	None.
	PART IV
ITEM 14.
ITEM 14.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
(a)	Please refer to Item 8, "Financial Statements and Supplementary Data" for a complete listing of all consolidated financial statements and financial statement schedules.
(b)	The Company filed the following reports on Form 8-K:
	 Date 	 Subject
	October 27, 1998	Item 5. Other Events. Discussion of Third Quarter Net Income.
	Item 7 Exhibits. Consolidated Statements of Income for the Quarters Ended September 30, 1998 and 1997, Nine Months Ended September 30, 1998 and 1997, and for the Twelve Months Ended September 30, 1998 and 1997. Utility Operations Schedule of Revenues and Expenses for the Quarters Ended September 30, 1998 and 1997, Nine Months Ended September 30, 1998 and 1997, and for the Twelve Months Ended September 30, 1998 and 1997. Nonutility Operations Schedule of Revenues and Expenses for the Quarters Ended September 30, 1998 and 1997, Nine Months Ended September 30, 1998 and 1997, and for the Twelve Months Ended September 30, 1998 and 1997.
	November 6, 1998	Item 5. Other Events. Sale of Generation Assets and Stock Repurchase Program.
	December 18, 1998	Item 5. Other Events. Montana Power and Houston Industries settle Coal Dispute.
ITEM 14.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
3.	Exhibits		Incorporation by Reference 				 Previous 			 Previous	 Exhibit 			 Filing 	 Designation
	 2	Asset Purchase Agreement	1-4566		2(a) 							Form 8-K 							Dated 							November 2, 	 3(a)	Restated Articles of Incorporation, 		 as amended	33-56739		3(a) 	 3(a)(1)	Articles of Amendment to the Restated 		 Articles of Incorporation	1-4566		3(a)(1) 	 3(a)(2)	Articles of Amendment to the Restated 		 Articles of Incorporation 	 3(b)	By-laws, as adopted dated August 22, 		 1995	1-4566		3(b) 	 3(b)(1)	Amendment to By-laws dated August 27, 		 1996	1-4566		3(b) 	 3(b)(2)	Amendment to By-laws dated May 12, 		 1997	1-4566		3(b) 	 3(b)(3)	Amendment to By-laws dated December 9, 	 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
	 4(u)	Amendment to Rights Agreement	1-4566	99(a) 		dated March 2, 1999		1999 							Form 8-K 							Dated 							March 2, 1999
	10(a)(i)	Benefit Restoration Plan for 	33-42882	10(a)(i) 		Senior Management Executives	 		and Board of Directors
	10(a)(ii)	Deferred Compensation Plan for	33-42882	10(a)(ii) 		Non-Employee Directors
	10(a)(iii)	Long-Term Incentive Stock	1-4566	10(a)(iii) 		Ownership Plan	1992 			Form 10-K
	10(a)(iv)	The Montana Power Company 	33-28096	 4(c) 		Employee Stock Ownership Plan 		(Revised)
	10(a)(v)	Termination Compensation	1-4566	10(a)(v) 		Agreements with Senior 	1996 		Management Executives	Form 10-K
	10(a)(vi)	Colstrip Unit #3 Wholesale	1-4566	10(a) 		Transmission Service Agreement	Form 8-K 		(Exhibit to the Asset	Dated 		Purchase Agreement	November 2, 1998
	10(a)(vii)	Non-Colstrip Unit #3 Wholesale	1-4566	10(b) 		Transmission Service Agreement		Form 8-K 		(Exhibit to the Asset			Dated 		Purchase Agreement)				November 2,
	10(a)(viii)	Generation Interconnection		1-4566	10(c) 		Agreement (Exhibit G to the			Form 8-K 		Asset Purchase Agreement)			Dated 									November 2,
	10(a)(ix)	Equity Contribution Agreement		1-4566	10(d) 									Form 8-K 									Dated 									November 2,
	10(c)	Participation Agreements among	33-42882	10(c) 		United States Trust Company 	 		of New York, Burnham Leasing 	 		Corporation, and SGE (New York) 		Associates, Certain Institutions, 		The Montana Power Company and 		Bankers Trust Company
	12	Statement Re Computation of Ratio 		of Earnings to Fixed Charges
	21	Subsidiaries of the Registrant
	23	Consent of Independent Accountants
	27	Financial Data Schedule
	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/ Robert P. Gannon	 	Robert P. Gannon 	(Chairman of the Board)
Date: March 23, 1999
	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/ Robert P. Gannon		Principal Executive Robert P. Gannon	 Officer and Director	March 23, 1999 (Chief Executive Officer)
/s/ J. P. Pederson		Principal Financial J. P. Pederson		 and Accounting Officer (Vice President and Chief		 and Director	March 23, 1999 Financial and Information Officer)
/s/ Tucker Hart Adams		Director	March 23, 1999 Tucker Hart Adams
/s/ Alan F. Cain		Director	March 23, 1999 Alan F. Cain
/s/ John G. Connors		Director	March 23, 1999 John G. Connors
/s/ R. D. Corette		Director	March 23, 1999 R. D. Corette
/s/ Kay Foster		Director	March 23, 1999 Kay Foster
/s/ Beverly D. Harris		Director	March 23, 1999 Beverly D. Harris
/s/ John R. Jester		Director 	March 23, 1999 John R. Jester
/s/ Carl Lehrkind, III		Director	March 23, 1999 Carl Lehrkind, III
/s/ N. E. Vosburg		Director	March 23, 1999 N. E. Vosburg
	EXHIBIT INDEX
Exhibit 12 	Statement Re Computation of Ratio Earnings to Fixed Charges	
Exhibit 21 	Subsidiaries of the Registrant	
Exhibit 23 	Consent of Independent Accountants	
Exhibit 27 	Financial Data Schedule	
SIGNATURES (Continued)