UNITED STATES
	SECURITIES AND EXCHANGE COMMISSION
	Washington, D.C. 20549

	FORM 10-K
______________________________________________________________________________
(Mark One)
(X)	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE 
ACT OF 1934 	
For the fiscal year ended December 31, 1998
	-OR-
(  )	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES 
EXCHANGE ACT OF 1934 		

For the transition period from ______________ to _______________.

Commission file number 1-4566

	THE MONTANA POWER COMPANY
	(Exact name of registrant as specified in its charter)

				Montana					81-0170530
		  (State or other jurisdiction		   (IRS Employer
		of incorporation or organization)		Identification No.)

		40 East Broadway, Butte, Montana			59701-9394
		(Address of principal executive offices)		(Zip code)

	Registrant's telephone number, including area code (406) 723-5421

	Securities registered pursuant to Section 12(b) of the Act:

									 Name of each exchange
	       Title of each Class        	  on which registered  
			Common Stock				New York Stock Exchange
									Pacific Stock Exchange

	8.45% Cumulative Quarterly Income	New York Stock Exchange
	  Preferred Securities, Series A
	  of Montana Power Capital I, a
	  subsidiary of The Montana Power
	  Company	

	Securities registered pursuant to Section 12(g) of the Act:

	Preferred Stock
	(Title of Class)

<PAGE>
Indicate by check mark whether the registrant (1) has filed all reports 
required to be filed by section 13 or 15(d) of the Securities Exchange Act of 
1934 during the preceding 12 months (or for such shorter period that the 
registrant was required to file such reports), and (2) has been subject to such 
filing requirements for the past 90 days.  

	Yes  X  No    

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 
of Regulation S-K (Section 229.405 of this chapter) is not contained herein, 
and will not be contained, to the best of registrant's knowledge, in definitive 
proxy or information statements incorporated by reference in Part III of this 
Form 10-K or any amendment to this Form 10-K [  ].  

The aggregate market value of the voting stock held by nonaffiliates of the 
registrant was $3,380,598,127 at March 12, 1999.  

On March 16, 1999, the Company had 55,077,919 shares of common stock 
outstanding.  

	DOCUMENTS INCORPORATED BY REFERENCE

(1)	Notice of 1999 Annual Meeting of Shareholders and Proxy Statement, 
pages 1-44, is incorporated into Part III of this report.  
</PAGE>

<PAGE>
PART I


	This Form 10-K contains forward-looking statements within the meaning of 
Section 21E of the Securities Exchange Act of 1934.  Forward-looking statements 
should be read with the cautionary statements and important factors included in 
this Form 10-K at Part II, Item 7, "Management's Discussion and Analysis of 
Financial Conditions and Results of Operations - Safe Harbor for Forward-
Looking Statements."  Forward-looking statements are all statements other than 
statements of historical fact, including without limitation those that are 
identified by the use of the words "anticipates", "estimates", "expects", 
"intends", "believes", and similar expressions.  


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.  
</PAGE>

<PAGE>
? 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
</PAGE>
<PAGE>
	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 
</PAGE>
<PAGE>
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-
</PAGE>
<PAGE>
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.  


</PAGE>
<PAGE>
	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.  
</PAGE>

<PAGE>
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."  
</PAGE>

<PAGE>
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.  

</PAGE>

<PAGE>
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
</PAGE>
<PAGE>
	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. 
</PAGE>
<PAGE>
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.  
</PAGE>
<PAGE>
	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.  
<TABLE>
<CAPTION>
			            Year Ended December 31            
			     1998     	     1997     	     1996     
			United		United		United
		States	Canada	States	Canada	States	Canada
<S>                                      <C>     <C>     <C>     <C>     <C>     <C>
Average sales price:  
	Per Mcf of natural gas		$ 1.45	$ 1.39	$ 1.94	$ 1.38	$ 1.54	$ 1.10
	Per barrel of oil		12.96	11.36	20.42	18.77	19.74	16.88
	Per barrel of natural gas liquids		9.10	10.12	10.12	15.64	10.56	14.44

Average production cost:
	Per barrel of oil equivalent		$ 3.95	$ 2.95	$ 4.13	$ 3.02	$ 3.94	$ 3.10
</TABLE>
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.  
</PAGE>
<PAGE>
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.  

</PAGE>

<PAGE>
	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.  


<TABLE>
Projects in Operation:  
<CAPTION>
				 IPG
				Share
				 of
			Rated	Rated
	   Location		Capa-	Capa-
	 (Commercial	 Ownership	city	city	          Customer	
    Project     	  Operation)  	or Interest	  MW  	 MW  	 Electricity  	  Thermal   
<S>               <C>             <C>         <C>      \<C> <C>             <C>
Encogen One (a)	Sweetwater, TX	  49.9%	  255	 128	Texas Utilities	U.S. Gypsum
	    (1989)				  Electric Co.
Tenaska-Paris(b)	Paris, TX	  10.0%	  223	  22	Texas Utilities	Campbell
 	    (1989)				  Electric Co.	 Soup Co.
Teesside	United Kingdom	   3.2%(c)	1,725	  56	Various U.K.	    --
	    (1993)				  customers
Tenaska-	Ferndale, WA	  25.1%	  245	  61	Puget Sound	Tosco Corp.
 Ferndale	    (1994)				  Energy

Doctor Bird	Old Harbour,	  17.6%	   74	  13	Jamaica Public	   None
	  Jamaica				  Service
	    (1995)
Tenaska-	Cleburne, TX	  13.4%	  258	  35	Brazos REA	City of 
 Cleburne	    (1997)					 Cleburne
					    
	TOTAL IPG SHARE OF RATED CAPACITY MW			 315



<FN>
(a) CES is the managing partner of this project (through its wholly owned subsidiary 
Enserch Development Corporation One, Inc).  

(b) This co-generation facility has a long-term contract with NARCO (a Nonutility 
subsidiary) to purchase a portion of its natural gas supply.  

(c) Interest is the contractual right to utilize one-third of 168 MWs of capacity to 
produce electricity for sale from a 1,725 MW natural gas-fired electric generating 
facility.  
</FN>
</TABLE>
</PAGE>

<PAGE>
<TABLE>
Projects Under Construction:  
<CAPTION>
				 IPG
				Share
				 of
	    Location		Rated	Rated
	  (Anticipated		Capa-	Capa-
	   Commercial	 Ownership	city	city	         Customer       
  Project   	   Operation)   	or Interest	 MW  	 MW  	 Electricity 	  Thermal  
<S>             <C>               <C>          <C>    <C>    <C>            <C>

Tenaska	Grimes County,	    25%	 830	 208	Power Team, a	None
  Frontier	   Texas				  division of
 (Grimes	  (2000)				  PECO Energy
  County)					  Company

Uch Power	Uch Pakistan	  3.2%	 586	  19	Pakistan Water	None
 Limited	  (1999)				 & Power
					 Department

<CAPTION>
Projects Under Development:

				 IPG
				Share
				 of
			Rated	Rated
		 Devel-	Capa-	Capa-
		 opment  	city	city	           Customer        
   Project    	    Location    	Interest 	 MW  	 MW  	  Electricity   	  Thermal  
<S>             <C>              <C>        <C>    <C>    <C>               <C>
India-	State of Andhra	  (d)	 500	 (d)	State of Andhra	None
  Krishnapatnam	  Pradesh				  Pradesh
<FN>
(d)	The ownership interest, if any, has not been determined.  
</FN>
</TABLE>

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.  
</PAGE>

<PAGE>
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.  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.  

</PAGE>
<PAGE>
	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.  
</PAGE>

<PAGE>
PART II


ITEM 5.	MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER 
MATTERS

	Common Stock Information

	The common stock of the Company is listed on the New York and Pacific 
Stock Exchanges.  The following table presents the high and low sale prices of 
the common stock of the Company as well as dividends declared for the years 
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
</PAGE>

<PAGE>
<TABLE>
<CAPTION>
ITEM 6.	SELECTED FINANCIAL DATA

The Montana Power Company and Subsidiaries

Balance Sheet Items (000)
			   1998  	   1997  	   1996  
<S>                                        <C>         <C>          <C>
Assets:
	Utility plant		$2,246,847	$2,216,198	$2,236,309
	Less accumulated depreciation 
		and depletion		  732,385	  684,960	  705,119
		Net Utility plant		1,514,462	1,531,238	1,531,190
	Nonutility property		864,981	781,406	666,679
	Less accumulated depreciation
		and depletion		  297,933	  260,567	  256,489
		Net Nonutility property		  567,048	  520,839	  410,190
			Total net plant and property		2,081,510	2,052,077	1,941,380
	Other assets		  846,585	  753,819	  756,835
			Total Assets		$2,928,095	$2,805,896	$2,698,215

Liabilities and Shareholders' Equity:
	Common shareholders' equity		$1,112,103	$1,037,534	$  999,657
	Unallocated stock held by trustee
		for retirement savings plan		(23,298)	(25,945)	(28,360)
	Preferred stock		57,654	57,654	57,654
	Mandatorily redeemable preferred
		securities of trust		65,000	65,000	65,000
	Long-term debt		698,329	653,168	633,339
	Other liabilities		1,018,307	1,018,485	  970,925
			Total Liabilities		$2,928,095	$2,805,896	$2,698,215
</TABLE>
</PAGE>

<PAGE>
<TABLE>
<CAPTION>
ITEM  6.  SELECTED FINANCIAL DATA  

The Montana Power Company and Subsidiaries

Balance Sheet Items (000)
			   1995   	   1994   	   1993   
<S>                                         <C>         <C>        <C>
Assets:
	Utility plant		$2,156,959	$2,021,981	$1,891,432
	Less accumulated depreciation 
		and depletion		  663,216	  619,195	  572,141
		Net Utility plant		1,493,743	1,402,786	1,319,291
	Nonutility property		633,079	600,299	596,769
	Less accumulated depreciation 
		and depletion		  252,612	  207,486	  198,951
		Net Nonutility property		  380,467	  392,813	  397,818
			Total net plant and property		1,874,210	1,795,599	1,717,109
	Other assets		  711,881	  717,098	  668,918
			Total Assets		$2,586,091	$2,512,697	$2,386,027

Liabilities and Shareholders' Equity:
	Common shareholders' equity		$  976,043	$  988,100	$  945,651
	Unallocated stock held by trustee
		for retirement savings plan		(30,565)	(32,580)	(34,419)
	Preferred stock		101,416	101,416	101,419
	Mandatorily redeemable preferred
		securities of trust	
	Long-term debt		616,574	588,876	571,870
	Other liabilities		  922,623	  866,885	  801,506
			Total Liabilities		$2,586,091	$2,512,697	$2,386,027
</TABLE>
</PAGE>

<PAGE>
<TABLE>
<CAPTION>
Income Statement Items (000)
				   1998   	   1997   	   1996   

<S>                                        <C>         <C>          <C>
	Revenues		$1,253,724	1,023,597	$  973,208

	Expenses:
		Operations		528,196	420,032	386,775
		Maintenance		81,064	82,702	75,409
		Selling, general and administrative		128,741	116,054	104,535
		Taxes other than income taxes		96,181	92,967	84,400
		Depreciation, depletion and 
			amortization		114,267	95,340	86,403
		Writedowns of long-lived assets		         	         	         
					  948,449	  807,095	  737,522

			Income from operations		305,275	216,502	235,686

	Interest expense and other income:
		Interest		60,851	54,667	48,770
		Distributions on mandatorily
			redeemable preferred securities
			of subsidiary trust		5,492	5,492
		Other income - net		   (4,862)	   (34,159)	   (4,445)
					61,481	26,000	44,325

	Income taxes		  78,174	    61,870	    71,975

	Net income		165,620	128,632	119,386
	Dividends on preferred stock		    3,690	    3,690	    8,358

	Net income available for common stock		$ 161,930	$  124,942	$  111,028

	Basic  earnings per share of common
		stock:
		Utility operations		$     0.94	$     1.08	$     1.13
		Nonutility operations		     2.01	     1.21	    0.90
				$     2.95	$     2.29	$     2.03

	Diluted earnings per share of
		common stock		$     2.94	$     2.28	$     2.03

	Dividends declared per share of 
		common stock		$     1.60	$     1.60	$     1.60

	Average shares outstanding (000)		54,981	54,649	54,634

	Earnings coverage of fixed 
		charges, SEC Method		3.34x	2.94x	3.21x

</TABLE>
</PAGE>

<PAGE>
<TABLE>
<CAPTION>
Income Statement Items (000)
				   1995   	   1994   	   1993   
<S>                                         <C>         <C>         <C>
	Revenues		$  953,224	$1,005,970	$1,024,285

	Expenses:
		Operations		426,425	443,870	485,032
		Maintenance		74,593	81,735	76,256
		Selling, general and administrative		95,212	98,829	95,415
		Taxes other than income taxes		86,599	95,950	89,254
		Depreciation, depletion and 
			amortization		84,635	84,483	80,831
		Writedowns of long-lived assets		   74,297	         	         
					  841,761	  804,867	  826,788

			Income from operations		111,463	201,103	197,497

	Interest expense and other income:
		Interest		43,656	42,817	48,023
		Other income - net		  (10,704)	  (10,532)	  (11,857)
					32,952	32,285	36,166

	Income taxes		   21,574	   55,226	   54,120

	Net income		56,937	113,592	107,211
	Dividends on preferred stock		    7,227	    7,227	    4,353

	Net income available for common stock		$   49,710	$  106,365	$  102,858

	Basic earnings per share of common
		stock:
		Utility operations		$     1.22	$     0.91	$     1.07
		Nonutility operations		    (0.30)	     1.09	     0.91
				$     0.92	$     2.00	$     1.98

	Diluted earnings per share 
		of common stock		$     0.92	$     2.00	$     1.97

	Dividends declared per share of
		common stock		$     1.60	$     1.60	$    1.585

	Average shares outstanding (000)		54,121	53,125	52,040

	Earnings coverage of fixed 
		charges, SEC Method		1.96x	3.05x	2.86x
</TABLE>
</PAGE>

<PAGE>
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.  

</PAGE>
<PAGE>
		      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.  


</PAGE>
<PAGE>
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 

</PAGE>
<PAGE>
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 
</PAGE>
<PAGE>
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 
</PAGE>
<PAGE>
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.  
</PAGE>
<PAGE>
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.  

</PAGE>

<PAGE>
<TABLE>
<CAPTION>
			        UTILITY OPERATIONS
			      Year Ended December 31        
			   1998   	   1997   	   1996   
			       Thousands of Dollars

ELECTRIC UTILITY:
<S>                                                  <C>          <C>          <C>
REVENUES:
	Revenues		$  450,719	$  435,986	$  430,171
	Intersegment revenues		     7,576	     4,685	    5,793
				458,295	440,671	435,964

EXPENSES:
	Power supply		137,415	143,224	138,679
	Transmission and distribution		40,182	38,359	37,255
	Selling, general and administrative		53,017	50,872	47,691
	Taxes other than income taxes	 	46,316	45,540	43,568
	Depreciation and amortization		    56,524	    51,674	   46,648
				   333,454	   329,669	  313,841

	INCOME FROM ELECTRIC OPERATIONS		124,841	111,002	122,123

NATURAL GAS UTILITY:  

REVENUES:
	Revenues (other than gas supply
		cost revenues)		75,112	105,220	107,782
	Gas supply cost revenues		31,940	17,135	20,746
	Intersegment revenues		       727	       588	       649
				107,779	122,943	129,177

EXPENSES:
	Gas supply costs		31,940	17,135	20,746
	Other production, gathering and exploration		2,284	8,572	9,966
	Transmission and distribution		15,556	14,163	14,679
	Selling, general and administrative		20,191	17,889	16,476
	Taxes other than income taxes		14,084	15,251	14,842
	Depreciation, depletion and amortization		     8,705	    11,939	    11,638
				    92,760	    84,949	    88,347

	INCOME FROM GAS OPERATIONS			15,019	37,994	40,830

INTEREST EXPENSE AND OTHER INCOME: 
	Interest		56,357	52,191	46,663
	Distributions on company obligated
		mandatorily redeemable preferred
		securities of subsidiary trust		5,493	5,492	
	Other income - net		    (3,724)	    (7,128)	      (402)
				    58,126	    50,555	    46,261

INCOME BEFORE INCOME TAXES		81,734	98,441	116,692

INCOME TAXES		26,559	35,643	46,687

DIVIDENDS ON PREFERRED STOCK		     3,690	    3,690	    8,358

UTILITY NET INCOME AVAILABLE FOR COMMON STOCK		$   51,485	$   59,108	$   61,647
</TABLE>
</PAGE>

<PAGE>
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".  
</PAGE>

<PAGE>
<TABLE>
<CAPTION>
Electric Utility:  

1998 Compared to 1997


	Revenues and
	 Power Supply Expenses	Volumes	Customers	
	(Thousands of Dollars)	(Thousands of MWh)	(Yearly Average)
		1998	1997			1998	1997			1998	1997	
<S>                  <C>       <C>        <C> <C>     <C>    <C>   <C>     <C>       <C>
Revenues:										

Residential,
	Commercial &
	Government	$280,462	$270,276	4%	4,424	4,342	2%	280,023	275,916	1%
Industrial		108,053	107,038	1%	  2,580	2,580	  0%	  3,508	  3,339	 5%
	General Business		388,515	377,314	3%	  7,004	6,922	1%	283,531	279,255	2%
Sales to Other									
	Utilities		48,111	47,178	2%	1,902	2,663	(29)%	73	84	(13)%
Other		14,093	11,494	23%						
Intersegment		  7,576	  4,685	62%	    125	  149	(16)%	    230	    230	 0%
	Total	$458,295	$440,671	 4%	  9,031	9,734	 (7)%	283,834	279,569	 2%

Power Supply
	Expenses:
Hydroelectric	$ 22,266	$	22,887	(3)%	3,742	4,126	(9)%
Steam 		50,952	57,057	(11)%	4,516	4,290	5%
Purchases
	and Other		 64,197	 63,280	 1%	 2,058	 2,538	(19)%
	Total Power Supply	$137,415	$143,224	(4)%	10,316	10,954	 (6)%
Dollars Per kWh	$  1.332	$  1.308
</TABLE>

	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.  
</PAGE>

<PAGE>
<TABLE>
<CAPTION>
1997 Compared to 1996


	Revenues and
	 Power Supply Expenses	Volumes	Customers	
	(Thousands of Dollars)	(Thousands of MWh)	(Yearly Average)
		1997	1996			1997	1996			1997	1996	

Revenues:										
<S>                  <C>      <C>        <C>   <C>     <C>   <C>   <C>     <C>       <C>
Residential,
	Commercial &
	Government	$270,276	$257,625	5%	4,342	4,414	(2)%	275,916	271,683	2%
Industrial		107,038	108,156	(1)%	2,580	2,580	  0%	  3,339	  3,257	3%
	General Business		377,314	365,781	3%		6,922	6,994	(1)%	279,255	274,940	2%
Sales to Other									
	Utilities		47,178	52,125	(9)%	2,663	2,761	(4)%	84	79	6%
Other		11,494	12,265	(6)%						
Intersegment		  4,685	  5,793	(19)%	  149	   332	(55)%	    230	    230	0%
	Total	$440,671	$435,964	  1%	9,734	10,087	 (3)%	279,569	275,249	2%

Power Supply
	Expenses:
Hydroelectric	$	22,887	$ 19,423		18%	4,126	4,064	2%
Steam 		57,057	47,185	21%	4,290	4,272	0%
Purchases
	and Other		 63,280	 70,209	 (10)%	 2,538	 2,557	 (1)%
	Total Power Supply	$143,224	$136,817	  4%	10,954	10,893	  1%
Dollars Per kWh	$  1.308	$  1.256
</TABLE>


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.  
</PAGE>

<PAGE>
<TABLE>
<CAPTION>
Natural Gas Utility:

1998 Compared to 1997


		Revenues	Volumes	Customers	
	(Thousands of Dollars)	(Thousands of Mmcf)	(Yearly Average)
		1998	1997			1998	1997			1998	1997	

Revenues:										
<S>                  <C>      <C>      <C>    <C>     <C>     <C>  <C>     <C>      <C>

Residential,
	Commercial &
	Government	$ 92,128	$105,246	(12)%	19,355	22,695	(15)%	145,172	141,130	3%
Industrial		  1,380	  2,659	(48)%	   308	   618	(50)%	    394	    399	(1)%
	Subtotal		 93,508	107,905	(13)%	19,663	23,313	(16)%	145,566	141,529	3%
Gas Supply Cost									
	Revenues (GSC)	(31,940)	(17,135)	(86)%	      	      	    	       	       	    
	General Business									
	without GSC	 61,568		90,770	(32)%	19,663	23,313	(16)%	145,566	141,529	3%
Sales to Other									
	Utilities		606	786	(23)%	201	195	3%	3	4	(25)%
Transportation		13,497	9,919	36%	27,785	26,020	7%	23	42	(45)%
Other	   (559)	  3,745	(115)%	      	      	    	       	       	    
	Total	$ 75,112	$105,220	 (29)%	47,649	49,528	 (4)%	145,592	141,575	  3%
</TABLE>


	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.  
</PAGE>

<PAGE>
<TABLE>
<CAPTION>
1997 Compared to 1996


		Revenues	Volumes	Customers	
	(Thousands of Dollars)	(Thousands of Mmcf)	(Yearly Average)
		1997	1996			1997	1996			1997	1996	

Revenues:										
<S>                  <C>      <C>        <C>  <C>    <C>      <C>  <C>     <C>      <C>
Residential,
	Commercial &
	Government	$105,246	$109,795	(4)%	22,695	23,690	(4)%	141,130	137,222	3%
Industrial		  2,659	  2,921	(9)%	   618	   675	(8)%	    399	    421	(5)%
	Subtotal			107,905	112,716	(4)%	23,313	24,365	(4)%	141,529	137,643	3%
Gas Supply Cost									
	Revenues (GSC)	(17,135)	(20,746)	(17)%	      	      	    	       	       	    
	General Business									
	without GSC		90,770	91,970	(1)%	23,313	24,365	(4)%	141,529	137,643	3%
Sales to Other								
	Utilities		786	868	(9)%	195	255	(24)%	4	3	33%
Transportation		9,919	9,582	4%	26,020	26,969	(4)%	42	42	0%
Other		  3,745	  5,362	(30)%	      	      	    	       	       	    
	Total	$105,220	$107,782	 (2)%	49,528	51,589	 (4)%	141,575	137,688	  3%

</TABLE>

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.  

</PAGE>
<PAGE>
	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.  
</PAGE>

<PAGE>
<TABLE>
<CAPTION>
	NONUTILITY OPERATIONS
	       Year Ended December 31       
			   1998   	   1997   	   1996   
			Thousands of Dollars

COAL:
<S>                                                  <C>          <C>          <C>
REVENUES:
	Revenues		$ 177,961	$ 167,623	$ 163,901
	Intersegment revenues		  38,796	  34,164	  31,448
			 216,757	201,787	195,349

EXPENSES:
	Operations and maintenance		132,963	119,085	115,859
	Selling, general and administrative		20,588	21,355	21,373
	Taxes other than income taxes		24,050	23,455	20,883
	Depreciation, depletion and amortization		    6,596	    9,043	    5,653
			  184,197	  172,938	  163,768

	INCOME FROM COAL OPERATIONS		32,560	28,849	31,581

OIL AND NATURAL GAS:  

REVENUES:  
	Revenues:		208,116	163,656	124,532
	Intersegment revenues		   24,597	    3,120	      293
			  232,713	166,776	124,825
EXPENSES:
	Operations and maintenance		176,981	118,266	76,975
	Selling, general and administrative		20,925	10,723	10,152
	Taxes other than income taxes		4,908	4,555	2,931
	Depreciation, depletion and amortization		   22,259	   16,922	   17,080
			  225,073	  150,466	  107,138
	INCOME FROM OIL AND
		NATURAL GAS OPERATIONS		7,640	16,310	17,687

INDEPENDENT POWER:  

REVENUES:
	Revenues		73,707	70,932	75,322
	Earnings from unconsolidated investments		89,525	14,980	21,174
	Intersegment sales		    2,014	    1,820	    1,426
			165,246	87,732	97,922
EXPENSES:
	Operations and maintenance		65,009	63,837	64,274
	Selling, general and administrative		4,746	4,290	5,223
	Taxes other than income taxes		1,767	1,868	1,783
	Depreciation and amortization		    9,005	    2,774	    3,793
			   80,527	   72,769	   75,073

	INCOME FROM INDEPENDENT POWER OPERATIONS		$  84,719	$  14,963	$  22,849
</TABLE>
</PAGE>

<PAGE>
<TABLE>
<CAPTION>
			           NONUTILITY OPERATIONS
			       Year Ended December 31       
			   1998   	   1997   	   1996   
			        Thousands of Dollars

TELECOMMUNICATIONS:
<S>                                                  <C>          <C>         <C>
REVENUES:
	Revenues		$  87,748	$  46,691	$  27,641
	Earnings from unconsolidated investments		10,909	435	
	Intersegment revenues		    1,298	      799	      133
			99,955	47,925	27,774

EXPENSES:
	Operations and maintenance		27,110	22,385	18,316
	Selling, general and administrative		12,172	8,825	5,498
	Taxes other than income taxes		3,623	2,294	392
	Depreciation and amortization	 	    7,090	    2,494	      911
			   49,995	   35,998	   25,117

	INCOME FROM TELECOMMUNICATIONS OPERATIONS.		49,960	11,927	2,657

OTHER OPERATIONS:

REVENUES:
	Revenues		47,988	939	1,939
	Intersegment revenues		    1,913	    5,719	       44
			49,901	6,658	1,983
EXPENSES:
	Operations and maintenance		51,634	3,780	1,207
	Selling, general and administrative		2,211	6,922	2,137
	Taxes other than income taxes		1,431	6	
	Depreciation and amortization		    4,089	      493	      679
			   59,365	   11,201	    4,023

	LOSS FROM OTHER OPERATIONS		(9,464)	(4,543)	(2,040)

INTEREST EXPENSE AND OTHER INCOME:  
	Interest		11,420	6,605	4,829
	Other income - net		   (8,065)	  (31,160)	   (6,764)
			    3,355	  (24,555)	   (1,935)

INCOME BEFORE INCOME TAXES		162,060	92,061	74,669

INCOME TAXES		   51,615	   26,227	   25,288

NONUTILITY NET INCOME AVAILABLE FOR
	COMMON STOCK		$ 110,445	$  65,834	$  49,381
</TABLE>
</PAGE>

<PAGE>
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 
</PAGE>
<PAGE>
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 

</PAGE>
<PAGE>
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-
</PAGE>
<PAGE>
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.  
</PAGE>
<PAGE>
	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.  
</PAGE>

<PAGE>
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 
</PAGE>
<PAGE>
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 
</PAGE>
<PAGE>
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 
</PAGE>
<PAGE>
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.  
</PAGE>
<PAGE>
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.  
</PAGE>
<PAGE>
	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), 
</PAGE>
<PAGE>
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.  


</PAGE>
<PAGE>
	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.  
</PAGE>

<PAGE>
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.  
</PAGE>


<PAGE>
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 
</PAGE>
<PAGE>
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.  
</PAGE>

<PAGE>
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA


	INDEX TO FINANCIAL STATEMENTS
	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.  
</PAGE>

<PAGE>
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 
</PAGE>

<PAGE>
	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
</PAGE>

<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENT OF INCOME
	The Montana Power Company and Subsidiaries


					
				       Year Ended December 31      
				   1998   	   1997   	   1996   
				        Thousands of Dollars 
				(except per share amounts)
<S>                                              <C>            <C>          <C>
REVENUES		$ 1,253,724	$1,023,597	$  973,208

EXPENSES:
	Operations		528,196	420,032	386,775
	Maintenance		81,064	82,702	75,409
	Selling, general and administrative		128,741	116,054	104,535
	Taxes other than income taxes		96,181	92,967	84,400
	Depreciation, depletion and amortization		   114,267	    95,340	    86,403
					   948,449	   807,095	   737,522

		INCOME FROM OPERATIONS		305,275	216,502	235,686

INTEREST EXPENSE AND OTHER INCOME:
	Interest		60,851	54,667	48,770
	Distributions on mandatorily redeemable 
		preferred securities of subsidiary trust		5,492	5,492
	Other income - net		    (4,862)	 (34,159)	   (4,445)
					    61,481	  26,000	   44,325

INCOME TAXES		    78,174	    61,870	    71,975

NET INCOME		   165,620	128,632	119,386
DIVIDENDS ON PREFERRED STOCK		     3,690	     3,690	     8,358

NET INCOME AVAILABLE FOR COMMON STOCK		$  161,930	$  124,942	$  111,028

AVERAGE NUMBER OF COMMON SHARES 
	OUTSTANDING (Basic)		    54,981	54,649	54,634

BASIC EARNINGS PER SHARE OF COMMON STOCK		$    2.95	$     2.29	$     2.03

AVERAGE NUMBER OF COMMON SHARES 
	OUTSTANDING (Diluted)		   55,078	54,700	 54,641

DILUTED EARNINGS PER SHARE OF COMMON STOCK		$    2.94	$     2.28	$     2.03



The accompanying notes are an integral part of these statements.
</TABLE>
</PAGE>

<PAGE>
<TABLE>
<CAPTION>
	CONSOLIDATED BALANCE SHEET
	The Montana Power Company and Subsidiaries
	ASSETS

		December 31     
		1998   		1997   
	Thousands of Dollars

<S>                                                             <C>           <C>
PLANT AND PROPERTY IN SERVICE:
	Utility plant		$2,246,847	$2,216,198
	Less - accumulated depreciation and depletion			732,385		684,960
						1,514,462	1,531,238

	Nonutility property		864,981	781,406
	Less - accumulated depreciation and depletion			297,933		260,567
							567,048		520,839
						2,081,510	2,052,077
MISCELLANEOUS INVESTMENTS:
	Independent power investments		24,268	51,534
	Reclamation fund		41,542	47,312
	Other			84,256		49,555
						150,066	148,401
CURRENT ASSETS:
	Cash and temporary cash investments		10,116	2,770
	Accounts receivable		170,652	126,926
	Notes receivable		29,089	4,061
	Materials and supplies (principally at average cost)		42,292	39,471
	Prepayments and other assets		57,331	49,673
	Deferred income taxes			18,755		10,539
						328,235	233,440

DEFERRED CHARGES:
	Advanced coal royalties		14,312	16,698
	Regulatory assets related to income taxes		121,735	122,903
	Regulatory assets - other		154,193	158,573
	Other deferred charges			78,044		73,804
							368,284		371,978
						$2,928,095	$2,805,896

The accompanying notes are an integral part of these statements.
</TABLE>
</PAGE>

<PAGE>
<TABLE>
<CAPTION>

	LIABILITIES AND SHAREHOLDERS' EQUITY

					       December 31       
					    1998   	    1997    
					   Thousands of Dollars

<S>                                                             <C>         <C>
CAPITALIZATION:
	Common shareholders' equity:
		Common stock (120,000,000 shares without par 
			value authorized; 55,060,520 and 54,728,709
			shares issued)		$	702,511	$	694,561
		Retained earnings and other shareholders' equity		430,309	356,327
		Accumulated other comprehensive income (loss)		(20,717)	(13,354)
		Unallocated stock held by trustee for Retirement
			Savings Plan			(23,298)		(25,945)
					1,088,805	1,011,589

	Preferred stock		57,654	57,654
	Company obligated mandatorily redeemable preferred
		securities of subsidiary trust which holds solely
		company junior subordinated debentures		65,000	65,000
	Long-term debt			698,329		653,168
						1,909,788	1,787,411

CURRENT LIABILITIES:
	Short-term borrowings		69,820	133,958
	Long-term debt-portion due within one year		96,292	81,659
	Dividends payable		22,765	22,684
	Income taxes		24,857	3,803
	Other taxes		51,777	47,818
	Accounts payable		97,197	77,821
	Interest accrued		13,156	13,836
	Other current liabilities			40,087		39,358
						415,951	420,937

DEFERRED CREDITS:
	Deferred income taxes		323,906	340,251
	Investment tax credits		33,819	35,182
	Accrued mining reclamation costs		129,558	131,108
	Other deferred credits			115,073		91,007
							602,356		597,548

CONTINGENCIES AND COMMITMENTS (Notes 2 and 3)
					$2,928,095	$2,805,896

The accompanying notes are an integral part of these statements.  
</TABLE>
</PAGE>

<PAGE>
<TABLE>
<CAPTION>
	CONSOLIDATED STATEMENT OF CASH FLOWS
	The Montana Power Company and Subsidiaries

					       Year Ended December 31       
		   1998   	   1997   	   1996   
	Thousands of Dollars
<S>                                                  <C>           <C>          <C>
NET CASH FLOWS FROM OPERATING ACTIVITIES:
	Net income		$  165,620	$	128,632	$	119,386
	Adjustments to reconcile net income to net 
		cash provided by operating activities:
		Depreciation, depletion and amortization		114,267	94,664	88,744
		Deferred income taxes		(17,958)	10,677	15,430
		Noncash earnings from unconsolidated
			independent power investments		(10,871)	(14,016)	(11,505)
		Reclamation expenses and payments - net		(1,550)	1,230	7,870
		Deferred stripping expenses and
			payments - net		291	(696)	(787)
		Losses (gains) on sales of property and 
			investments		4,669	(33,849)	2,532
		Other - net		32,351	24,145	15,240
		Changes in current assets and liabilities:
			Accounts receivable		(43,726)	21,338	9,686
			Notes receivable		(25,028)	(1,578)	353
			Materials and supplies		(2,821)	(149)	2,872
			Deferred income taxes		(8,216)	556	(2,198)
			Accounts payable		19,376	15,603	(1,702)
			Income taxes payable		21,054	(7,281)	1,146
			Other assets and liabilities			8,219		(38,185)		(27,990)
		Net cash provided by operating activities			255,677		201,091		219,077

NET CASH FLOWS FROM INVESTING ACTIVITIES:
	Capital expenditures		(213,401)	(311,686)	(171,681)
	Reclamation funding		5,770	(4,311)	(43,001)
	Proceeds from property and investments		55,643	135,577	21,991
	Additional investments			(7,564)		(18,948)		(896)
		Net cash used for investing activities			(159,552)		(199,368)		(193,587)

NET CASH FLOWS FROM FINANCING ACTIVITIES:
	Dividends paid		(91,598)	(91,112)	(95,284)
	Sales of common stock		7,421	2,201	798
	Redemption of preferred stock				(44,415)
	Issuance of long-term debt		139,947	103,375	82,890
	Retirement of long-term debt		(80,411)	(71,634)	(22,236)
	Issuance of mandatorily redeemable preferred
		securities			(67)	62,625
	Net change in short-term borrowing			(64,138)		29,256		8,354
		Net cash used for financing activities			(88,779)		(27,981)		(7,268)

CHANGE IN CASH FLOWS		7,346	(26,258)	18,222

CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR			2,770		29,028		10,806

CASH AND CASH EQUIVALENTS, END OF YEAR		$	10,116	$	2,770	$	29,028

SUPPLEMENTAL DISCLOSURES OF CASH FLOW: 
	Cash paid during the year for:
		Income taxes, net of refunds		$	90,663	$	50,797	$	52,470
		Interest		67,777	59,681	49,962

The accompanying notes are an integral part of these statements.
</TABLE>
</PAGE>

<PAGE>
<TABLE>
<CAPTION>
	CONSOLIDATED STATEMENT OF COMMON SHAREHOLDERS' EQUITY
	The Montana Power Company and Subsidiaries

		
		
	
	      Year Ended December 31        
	   1998   	   1997   	   1996   
	Thousands of Dollars

COMMON STOCK:
<S>                                                 <C>           <C>          <C>
	Balance at beginning of year		$  694,561	$ 691,853	$ 691,043
	Issuances (331,811; 97,715; 
		and 16,513 shares)		      7,950	    2,708	      810

	Balance at end of year		   702,511	  694,561	  691,853

RETAINED EARNINGS AND OTHER SHAREHOLDERS' 
	EQUITY:

	Balance at beginning of year		356,327	318,977	296,191
	Net income		165,620	128,632	119,386
	Dividends on common stock ($1.60 
		per share each year)		(88,008)	(87,494)	(87,432)
	Dividends on preferred stock		(3,690)	(3,690)	(8,358)
	Other		        60	      (98)	     (810)

	Balance at end of year		   430,309	  356,327	  318,977

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

	Balance at beginning of year		   (13,354)	   (11,173)	  (11,191)

	Net income		165,620	128,632	119,386
	Foreign currency translation adjustments		    (7,363)	    (2,181)	       18
	Total comprehensive income		158,257	126,451	119,404
	Deduct net income included in comprehensive
		Income.		  (165,620)	  (128,632)	 (119,386)
	Other comprehensive income (loss)		    (7,363)	    (2,181)	       18

	Balance at end of year		  (20,717)	   (13,354)	  (11,173)

UNALLOCATED STOCK HELD BY TRUSTEE FOR
	RETIREMENT SAVINGS:

	Balance at beginning of year		(25,945)	(28,360)	(30,565)
	Distributions		    2,647	    2,415	    2,205

	Balance at end of year		  (23,298)	  (25,945)	  (28,360)

TOTAL COMMON SHAREHOLDERS' EQUITY AT 
	END OF YEAR		$1,088,805	$1,011,589	$ 971,297


The accompanying notes are an integral part of these statements.  
</TABLE>
</PAGE>

<PAGE>
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.  
</PAGE>
<PAGE>
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 

</PAGE>
<PAGE>
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 
</PAGE>
<PAGE>
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.  
</PAGE>
<PAGE>
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 
</PAGE>
<PAGE>
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.  

</PAGE>
<PAGE>
? 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: 

</PAGE>
<PAGE>
	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.  
</PAGE>

<PAGE>
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.  
</PAGE>

<PAGE>
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
</PAGE>

<PAGE>
	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.  
</PAGE>

<PAGE>
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.  

</PAGE>
<PAGE>
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 
</PAGE>
<PAGE>
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.  
</PAGE>

<PAGE>
<TABLE>
<CAPTION>
NOTE 5 - Income tax expense:  

	Income before income taxes was as follows:

	   1998   	   1997   	   1996   
	Thousands of Dollars
<S>                                       <C>          <C>        <C>
United States		$  246,242	$  177,114	$  181,393	
Canada		(2,927)	12,780	7,706	
Other countries		      479	      608	    2,262	
	$  243,794	$  190,502	$  191,361	


	The provision for income taxes differs from the amount of income tax that 
would be expected by applying the applicable U.S. statutory federal income tax 
rate to pretax income as a result of the following differences:  

	   1998   	   1997  	   1996  
	Thousands of Dollars

Computed "expected" income tax expense		$   85,328	$  66,675	$  66,976	
Adjustments for tax effects of:
	Statutory depletion		(4,156)	(2,891)	(2,317)	
	Tax credits		(4,722)	(11,645)	(5,286)	
	State income tax, net		7,393	7,147	5,772	
	Reversal of utility book/tax 
		depreciation		2,784	5,636	4,054	
	Other		  (8,453)	   (3,052)	    2,776	
Actual income tax expense		$   78,174	$  61,870	$  71,975	

	Income tax expense as shown in the Consolidated Statement of Income 
consists of the following components:  

			   1998   	   1997   	   1996   
	Thousands of Dollars

Current:
	United States		$   88,233	$  36,680	$  44,304	
	Canada		1,212	994	3,309	
	Other countries			3,684	445	
	State		   13,462	    9,835	    8,487	
			  102,907	   51,193	   56,545	
Deferred:
	United States		(20,331)	6,491	15,590	
	Canada		(1,851)	2,802	135	
	State		   (2,551)	    1,384	    (295)	
			  (24,733)	   10,677	  15,430	
		$   78,174	$  61,870	$  71,975	
</TABLE>
</PAGE>

<PAGE>
<TABLE>
<CAPTION>
	Deferred tax liabilities (assets) are comprised of the following:

	      December 31     
			   1998   	   1997   
			 Thousands of Dollars
<S>                                                   <C>         <C>
Plant related		$ 403,832	$ 390,776
Investment in Nonutility generation projects		7,132	25,530
Other		   35,344	   41,499
	Gross deferred tax liabilities		  446,308	  457,805

Coal reclamation		(47,487)	(46,820)
Amortization of gain on sale/leaseback		(12,755)	(13,860)
Investment tax credit amortization		(21,833)	(22,862)
Other		  (59,082)	  (44,551)
	Gross deferred tax assets		 (141,157)	 (128,093)
	Net deferred tax liabilities		 305,151	329,712
	Less current deferred tax assets-net		  (18,755)	  (10,539)
Total noncurrent deferred tax liabilities		$ 323,906	$ 340,251
</TABLE>
	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)
</PAGE>

<PAGE>
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.  
</PAGE>
<PAGE>
	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.  
<TABLE>
<CAPTION>
	Option activity is summarized below:  

				       1998       	       1997      	       1996      
					Wtd Avg		Wtd Avg		Wtd Avg
					Exercise		Exercise		Exercise
					  Shares  	 Price 	 Shares 	 Price 	 Shares 	 Price 
<S>                         <C>        <C>      <C>       <C>      <C>      <C>
Outstanding, beginning 
	of year		  540,665	$22.01	694,804	$21.91	569,982	$21.95
		Granted		1,117,329	 49.00	      -	     -	164,400	 21.63
		Exercised		  351,281	 22.51	125,753	21.45	 11,578	 19.04
		Cancelled		   32,666	 26.94	 28,386	22.02	 28,000	 22.31

Outstanding, end of year		1,274,047	$45.42	540,665	$22.01	694,804	$21.91
</TABLE>

	Shares under option at December 31, 1998 are summarized below:  
<TABLE>
<CAPTION>
				      Options Outstanding        	 Options Exercisable 

					Wtd Avg	Wtd Avg			Wtd Avg
					Exercise	Exercise		Exercise
 Exercise Price Range 		  Shares  	 Price 	 Life (yrs) 	 Shares 	 Price 
<S>                       <C>        <C>       <C>            <C>         <C>
$20.06 to $22.63		  180,718	$22.01	6		143,750	$22.10
$36.00 to $38.34		258,000	 37.06	9		-	-
$53.06		  835,329	 53.06	10		      -	     -
	1,274,047	143,750		

</TABLE>
	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.  
</PAGE>

<PAGE>
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.  
</PAGE>

<PAGE>
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.  
</PAGE>

<PAGE>
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 
</PAGE>
<PAGE>
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.  
</PAGE>

<PAGE>
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
</PAGE>

<PAGE>
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
</PAGE>

<PAGE>
			 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
</PAGE>

<PAGE>
	        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.  
</PAGE>

<PAGE>
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.  
</PAGE>

<PAGE>
<TABLE>
<CAPTION>
Operations Information:  
				                   Year Ended                  
				                December 31, 1998               
				               Thousands of Dollars              

UTILITY		 Electric 	Natural Gas
<S>                                                              <C>             <C>
Sales to unaffiliated customers		$  450,719	$  107,052
Intersegment sales		7,576	727
Interest revenue		2,460	311
Interest expense		50,016	11,834
Pre-tax operating income (loss)		124,841	15,019
Earnings (loss) from unconsolidated investments			
Income tax expense		26,388	171
Depreciation, depletion and amortization		56,524	8,705
Capital expenditures		61,334	21,989
Identifiable assets		1,577,583	405,670
<CAPTION>
NONUTILITY				
					  Oil and	Independent
				   Coal*  	Natural Gas	  Power**  
<S>                                                      <C>              <C>             <C>
Sales to unaffiliated customers		$  177,961	$  208,116	$   73,707
Intersegment sales		38,796	24,597	2,014
Interest revenue		2,630	379	4,979
Interest expense		443	1,203	58
Pre-tax operating income		32,560	7,640	(4,806)
Earnings (loss) from unconsolidated investments				89,525
Income tax expense		8,107	(1,007)	32,315
Depreciation, depletion and amortization		6,596	22,259	9,005
Capital expenditures		7,746	53,319	11,329
Identifiable assets		235,438	289,453	120,675
<CAPTION>
NONUTILITY (continued)
					    Tele-
					Communications**	   Other  
<S>                                                         <C>                     <C>
Sales to unaffiliated customers		$   87,748	$   47,987
Intersegment sales			1,298	1,913
Interest revenue			969	1,466
Interest expense			1	9,716
Pre-tax operating income (loss)		39,051	(9,464)
Earnings from unconsolidated investments		10,909	
Income tax expense			19,772	(7,572)
Depreciation, depletion and amortization		7,090	4,088
Capital expenditures		56,181	1,314
Identifiable assets		187,556	69,053

CORPORATE

Interest expense		$     (803)	
Capital expenditures		189
Identifiable assets		42,667
<CAPTION>
RECONCILIATION TO CONSOLIDATED				
				  Segment  		Consolidated
				   Total   	Adjustments***		   Total    
<S>                                                      <C>            <C>                 <C>
Sales to unaffiliated customers		$1,153,290	        	$1,153,290
Intersegment sales		76,921	$  (76,921)	
Interest revenue		13,194	(5,869)	7,325
Interest expense		72,468	(6,125)	66,343
Pre-tax operating income		204,841		204,841
Earnings (loss) from unconsolidated investments		100,434		100,434
Income tax expense		78,174		78,174
Depreciation, depletion and amortization		114,267		114,267
Capital expenditures		213,401		213,401
Identifiable assets		2,928,095		2,928,095
<FN>
*	Sales under one coal contract with Reliant Energy amounted to $110,172,000.  

**	The Telecommunications and Independent Power segments are dependent on a single customer and two customers, 
respectively, the losses of which would have a material adverse effect on the segments.  

***	Identifiable assets excludes intersegment receivables which are eliminated for consolidation.  The 
adjustments include certain eliminations between the business segments.  
</FN>
</TABLE>
</PAGE>

<PAGE>
<TABLE>
<CAPTION>
Operations Information:  
				                   Year Ended                  
				                December 31, 1997               
				               Thousands of Dollars              

UTILITY		 Electric 	Natural Gas
<S>                                                              <C>             <C>
Sales to unaffiliated customers		$  435,986	$  122,355
Intersegment sales		4,685	588
Interest revenue		6,450	1,615
Interest expense		46,257	11,426
Pre-tax operating income (loss)		111,002	37,994
Earnings (loss) from unconsolidated investments			
Income tax expense		24,297	11,347
Depreciation, depletion and amortization		51,674	11,939
Capital expenditures		122,639	15,679
Identifiable assets		1,560,055	390,463
<CAPTION>
NONUTILITY				
					  Oil and	Independent
				   Coal*  	Natural Gas	  Power**  
<S>                                                      <C>             <C>              <C>
Sales to unaffiliated customers		$  169,825	$  163,656	$   70,932
Intersegment sales		34,164	3,120	1,820
Interest revenue		2,095	2,065	3,972
Interest expense		424	106	32
Pre-tax operating income		31,051	16,310	(17)
Earnings (loss) from unconsolidated investments		(2,202)		14,980
Income tax expense		(700)	10,776	6,762
Depreciation, depletion and amortization		9,043	16,922	2,774
Capital expenditures		4,588	140,437	294
Identifiable assets		247,981	290,110	156,282
<CAPTION>
NONUTILITY (continued)
					    Tele-
					Communications	   Other  
<S>                                                         <C>                     <C>
Sales to unaffiliated customers		$   46,691	$      939
Intersegment sales			799	5,719
Interest revenue			143	5,955
Interest expense				6,043
Pre-tax operating income (loss)		11,492	(4,543)
Earnings from unconsolidated investments		435	
Income tax expense			4,824	4,564
Depreciation, depletion and amortization		2,494	494
Capital expenditures		27,902	53
Identifiable assets		101,581	7,987

CORPORATE

Interest expense		        	
Capital expenditures		$      94
Identifiable assets		51,437
<CAPTION>
RECONCILIATION TO CONSOLIDATED				
				  Segment  		Consolidated
				   Total   	Adjustments***		   Total    
<S>                                                      <C>            <C>                 <C>
Sales to unaffiliated customers		$1,010,384	        	$1,010,384
Intersegment sales		50,895	$  (50,895)	
Interest revenue		22,295	(4,271)	18,024
Interest expense		64,288	(4,129)	60,159
Pre-tax operating income		203,289		203,289
Earnings (loss) from unconsolidated investments		13,213		13,213
Income tax expense		61,870		61,870
Depreciation, depletion and amortization		95,340		95,340
Capital expenditures		311,686		311,686
Identifiable assets		2,805,896		2,805,896
<FN>
*	Sales under one coal contract with Reliant Energy amounted to $104,668,000.  

**	The Telecommunications and Independent Power segments are dependent on a single customer and two customers, 
respectively, the losses of which would have a material adverse effect on the segments.  

***	Identifiable assets excludes intersegment receivables which are eliminated for consolidation.  The 
adjustments include certain eliminations between the business segments.
</FN>
</TABLE>
</PAGE>

<PAGE>
<TABLE>
<CAPTION>
Operations Information:  
				                   Year Ended                  
				                December 31, 1996               
				               Thousands of Dollars              

UTILITY		 Electric 	Natural Gas
<S>                                                              <C>             <C>
Sales to unaffiliated customers		$  430,171	$  128,528
Intersegment sales		5,793	649
Interest revenue		2,253	73
Interest expense		46,652	11
Pre-tax operating income (loss)		122,123	40,830
Earnings (loss) from unconsolidated investments			
Income tax expense		33,729	12,958
Depreciation, depletion and amortization		46,648	11,638
Capital expenditures		74,930	31,060
Identifiable assets		1,526,197	421,955
<CAPTION>
NONUTILITY				
					  Oil and	Independent
				   Coal*  	Natural Gas	  Power**  
<S>                                                      <C>             <C>              <C>
Sales to unaffiliated customers		$  166,678	$  124,532	$   75,322
Intersegment sales		31,448	293	1,426
Interest revenue		1,690	530	3,095
Interest expense		404	28	35
Pre-tax operating income		34,358	17,687	1,675
Earnings (loss) from unconsolidated investments		(2,777)		21,174
Income tax expense		7,907	6,936	11,286
Depreciation, depletion and amortization		5,653	17,080	3,793
Capital expenditures		8,386	25,021	3,198
Identifiable assets		268,297	184,512	156,044
<CAPTION>
NONUTILITY (continued)
					    Tele-
					Communications	   Other  
<S>                                                         <C>                     <C>
Sales to unaffiliated customers		$   27,641	$   1,939
Intersegment sales			133	44
Interest revenue			112	1,017
Interest expense			40	4,322
Pre-tax operating income (loss)		2,657	(2,041)
Earnings (loss) from unconsolidated investments			
Income tax expense			960	(1,801)
Depreciation, depletion and amortization		911	680
Capital expenditures		27,902	6
Identifiable assets		52,139	17,954

CORPORATE

Interest expense		         	
Capital expenditures		$    1,178
Identifiable assets		71,117
<CAPTION>
RECONCILIATION TO CONSOLIDATED				
				  Segment  		Consolidated
				   Total   	Adjustments***		   Total    
<S>                                                      <C>            <C>                 <C>
Sales to unaffiliated customers		$  954,811	        	$  954,811
Intersegment sales		39,786	$  (39,786)	
Interest revenue		8,770	(2,771)	5,999
Interest expense		51,492	(2,722)	48,770
Pre-tax operating income		217,289		217,289
Earnings (loss) from unconsolidated investments		18,397		18,397
Income tax expense		71,975		71,975
Depreciation, depletion and amortization		86,403		86,403
Capital expenditures		171,681		171,681
Identifiable assets		2,698,215		2,698,215
<FN>
*	Sales under one coal contract with Reliant Energy amounted to $102,181,000.  

**	The Telecommunications and Independent Power segments are dependent on a single customer and two customers, 
respectively, the losses of which would have a material adverse effect on the segments.  

***	Identifiable assets excludes intersegment receivables which are eliminated for consolidation.  The 
adjustments include certain eliminations between the business segments.  
</FN>
</TABLE>
</PAGE>

<PAGE>
	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:  
<TABLE>
<CAPTION>

					                1998             
				   U.S.   	   CANADA   	STORAGE
PROVED DEVELOPED AND UNDEVELOPED RESERVES:
<S>                                                           <C>             <C>              <C>
UTILITY OPERATIONS:
	Natural Gas (Mmcf):
		Beginning Balance	2,097	0	56,840
		Production	(235)		
		Additions			
		(Sales) and Purchases of Reserves in Place			
		Transfers Out			
		Revisions - Other		
		Revisions - Price				1,469
			Ending Balance		1,862	0	58,309

NONUTILITY OPERATIONS:
	Natural Gas (Mmcf):
		Beginning Balance	191,250	125,135
		Production	(14,099)	(11,216)
		Additions	39,774	41,456
		(Sales) and Purchases of Reserves in Place	1,400	(2,808)
		Transfers In		
		Revisions - Other	(4,635)	(16,001)
		Revisions - Price		(17,640)	     1,573		
			Ending Balance		196,050	138,139		

	Natural Gas
		Liquids (Bbls):
		Beginning Balance	8,246,554	2,542,585
		Production	(218,000)	(325,000)
		Additions	1,321,300	431,000
		(Sales) and Purchases of Reserves in Place		(57,000)
		Revisions - Other	438,943	(667,585)
		Revisions - Price		(1,302,000)	(2,000)	
			Ending Balance	8,486,800	1,922,000	

	Oil (Bbls):
		Beginning Balance	5,025,390	2,700,071
		Production		(242,800)	(258,000)
		Additions	543,300	22,000
		(Sales) and Purchases of Reserves in Place		(540,000)
		Revisions - Other		(874,071)
		Revisions - Price		(2,050,390)	(109,000)	
			Ending Balance	3,275,500	941,000	

				          1998          
				   U.S.   	  CANADA  
PROVED DEVELOPED RESERVES:

UTILITY OPERATIONS:
	Natural Gas (Mmcf):
		Ending Balance	1,862	0

NONUTILITY OPERATIONS:
	Natural Gas (Mmcf):
		Ending Balance	133,578	118,452
	Natural Gas Liquids (Bbls):
		Ending Balance	8,484,116	1,921,728
	Oil (Bbls):
		Ending Balance	3,275,003	941,000
</TABLE>
</PAGE>

<PAGE>
<TABLE>
<CAPTION>
				                1997             
				   U.S.   	   CANADA   	STORAGE
PROVED DEVELOPED AND UNDEVELOPED RESERVES:
<S>                                                           <C>            <C>               <C>
UTILITY OPERATIONS:
	Natural Gas (Mmcf):
		Beginning Balance	71,952	94,445	55,624
		Production	(3,764)	(3,401)	
		Additions			1,216
		(Sales) and Purchases of Reserves in Place	(13,082)		
		Transfers Out	(53,711)	(91,044)	
		Revisions - Other	702	
		Revisions - Price					
			Ending Balance		2,097	0	56,840	

NONUTILITY OPERATIONS:
	Natural Gas (Mmcf):
		Beginning Balance	160,174	53,011
		Production	(11,427)	(6,529)
		Additions	14,920	8,569
		(Sales) and Purchases of Reserves in Place	6,039	5,914
		Transfers In	53,711	91,044
		Revisions - Other	(31,918)	(26,501)
		Revisions - Price		(249)	(373)		
			Ending Balance		191,250	125,135		

	Natural Gas
		Liquids (Bbls):
		Beginning Balance	3,491,100	3,089,300
		Production	(473,139)	(225,715)
		Additions	118,500	184,000
		(Sales) and Purchases of Reserves in Place	2,717,377	582,000
		Revisions - Other	2,392,716	(1,082,000)
		Revisions - Price			(5,000)	
			Ending Balance		8,246,554	2,542,585	

	Oil (Bbls):
		Beginning Balance	6,458,000	3,204,235
		Production		(746,380)	(322,164)
		Additions	339,110	2,445,000
		(Sales) and Purchases of Reserves in Place	(1,145,648)	(2,851,000)
		Revisions - Other	(28,792)	228,000
		Revisions - Price		149,100	(4,000)	
			Ending Balance		5,025,390	2,700,071	

				          1997          
				   U.S.   	  CANADA  
PROVED DEVELOPED RESERVES:

UTILITY OPERATIONS:
	Natural Gas (Mmcf):
		Ending Balance	2,097	0

NONUTILITY OPERATIONS:
	Natural Gas (Mmcf):
		Ending Balance	139,802	104,799
	Natural Gas Liquids (Bbls):
		Ending Balance	8,246,554	2,298,585
	Oil (Bbls):
		Ending Balance	3,474,602	2,079,071
</TABLE>
</PAGE>

<PAGE>
<TABLE>
<CAPTION>
				                1996              
				   U.S.    	   CANADA   	STORAGE
PROVED DEVELOPED AND UNDEVELOPED RESERVES:
<S>                                               <C>         <C>           <C>
UTILITY OPERATIONS:
	Natural Gas (Mmcf):
		Beginning Balance	75,461	103,475	56,745
		Production	(5,055)	(4,694)	
		Additions			(1,121)
		(Sales) and Purchases of Reserves in Place
		Revisions - Other	1,546	(4,336)
		Revisions - Price	         			
			Ending Balance	   71,952	94,445	55,624	

NONUTILITY OPERATIONS:
	Natural Gas (Mmcf):
		Beginning Balance	136,660	62,474
		Production	(8,915)	(6,924)
		Additions	813	1,702
		(Sales) and Purchases of Reserves in Place	19,240	12
		Revisions - Other	(1,098)	(14,847)
		Revisions - Price	    13,474	10,594		
			Ending Balance	   160,174	53,011		

	Natural Gas
		Liquids (Bbls):
		Beginning Balance	3,615,400	3,680,132
		Production	(232,600)	(271,241)
		Additions		17,700
		(Sales) and Purchases of Reserves in Place	(200)	
		Revisions - Other	(43,414)	(440,607)
		Revisions - Price	   151,914	103,316		
			Ending Balance	 3,491,100	3,089,300		

	Oil (Bbls):
		Beginning Balance	5,999,400	4,429,496
		Production		(539,288)	(676,640)
		Additions	19,600	118,814
		(Sales) and Purchases of Reserves in Place	702,347	58,800
		Revisions - Other	(130,360)	(1,027,636)
		Revisions - Price	   406,301	301,401		
			Ending Balance	 6,458,000	3,204,235		

				          1996          
				   U.S.    	  CANADA  
PROVED DEVELOPED RESERVES:

UTILITY OPERATIONS:
	Natural Gas (Mmcf):
		Ending Balance	71,121	94,445

NONUTILITY OPERATIONS:
	Natural Gas (Mmcf):
		Ending Balance	100,067	53,011
	Natural Gas Liquids (Bbls):
		Ending Balance	3,486,700	3,089,300
	Oil (Bbls):
		Ending Balance	6,369,000	3,204,235
</TABLE>
</PAGE>

<PAGE>
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, 
</PAGE>
<PAGE>
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.  
</PAGE>

<PAGE>
<TABLE>
<CAPTION>
				       1998      	       1997      	       1996      
					  U.S.  	 Canada 	  U.S.  	 Canada 	  U.S.  	 Canada 
UTILITY OPERATIONS		       Thousands of Dollars
At December 31:
<S>                           <C>      <C>      <C>      <C>      <C>      <C>
Capitalized costs relating 
	to natural gas producing
	activities		$  2,026	$      0	$  2,023	$      0	$ 87,363	$ 38,551
Accumulated depreciation,
	depletion and valuation
	allowances		   1,853	       0	  1,833	       0	  46,881	  20,102

		Net capitalized costs		$    173	$      0	$    190	$      0	$ 40,482	$ 18,449

For the year ended 
	December 31:  
Costs incurred in natural
	gas property acquisition, 
	exploration and 
	development activities: 
		Acquisition of 
			properties					        	$    474	$     49
		Exploration						$     35	$    168	54	191
		Development		$     (5)	$      0	1	66	501	1,230

Costs reflected in results 
  of operations: 
		Production costs		$     98	$      0	$  3,361	$  1,359	$  4,773	$  1,510
		Exploration expenses		(3)	0	35	168	54	191
		Development expenses				0	66	22	113
		Depreciation, depletion
			and valuation 
		  provisions		     19	       	2,072	686	2,667	711
</TABLE>
</PAGE>

<PAGE>
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:  


<TABLE>
<CAPTION>
				       1998      	       1997      	       1996      
					  U.S.  	 Canada 	  U.S.  	 Canada 	  U.S.  	 Canada 
NONUTILITY OPERATIONS		       Thousands of Dollars
At December 31:
<S>                           <C>      <C>      <C>      <C>      <C>      <C>
Capitalized costs relating
	to oil and natural gas
	producing activities*		$271,047	$109,742	$240,436	$113,165	$182,339	$ 87,529
Accumulated depreciation,
	depletion and valuation 
	allowances*		 60,186	 43,026	 49,167	 46,131	 65,401	 44,770

		Net capitalized costs		$210,861	$ 66,716	$191,269	$ 67,034	$116,938	$ 42,759

For the year ended 
	December 31:

Costs incurred in oil and 
	natural gas property 
	acquisition, exploration
	and development 
	activities:

	Acquisition of 
		properties		$  1,470	$  1,408	$ 85,606	$ 22,762	$  4,667	$  3,722
	Exploration		2,197	1,502	4,589	6,036	1,780	2,157
	Development		32,747	15,287	21,050	8,535	10,651	3,345

Results of operations for 
	oil and natural gas 
	producing activities:

		Revenues		$ 28,366	$ 18,739	$ 34,182	$ 14,821	$ 26,872	$ 19,789
		Production costs		17,029	7,222	10,232	5,041	8,901	6,547
		Exploration expenses		2,158	1,439	3,233	2,905	1,670	1,747
		Depreciation, depletion 
			and valuation 
			provisions		 14,675	  6,779	 12,037	  3,781	 10,019	  6,133
					(5,496)	3,299	8,680	3,094	6,282	5,362

		Income tax expenses		 (3,651)	  1,472	    416	  1,380	    946	  2,393

Results of operations from
	producing activities
	(excluding corporate 
	overhead and interest 
	cost)		$ (1,845)	$  1,827	$  8,264	$  1,714	$  5,336	$  2,969


<FN>
			*U.S. capitalized costs relating to these activities include the costs 
of support equipment and facilities.  Also, U.S. accumulated depreciation, 
depletion, and valuation includes the depreciation associated with such 
equipment and facilities.  The capitalized costs of support equipment and 
facilities were $60,681,000 and $54,295,000, and the associated depreciation 
was $8,676,000 and $5,288,000 for 1998 and 1997, respectively.  
</FN>
</TABLE>
</PAGE>

<PAGE>
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.  
</PAGE>

<PAGE>
<TABLE>
<CAPTION>
	STANDARDIZED MEASURE OF DISCOUNTED FUTURE
	NET CASH FLOWS AND CHANGES THEREIN RELATING TO
	PROVED OIL AND NATURAL GAS RESERVES

		                 December 31                 
		        1998         	         1997         
		   U.S.   	  Canada  	    U.S.   	  Canada  
				  Thousands of Dollars   
<S>                                  <C>         <C>         <C>         <C>
Future cash inflows		$  650,446	$	  273,644	$  876,733	$	  303,780
Future production and  
	development costs		327,784	108,436	467,270	151,201
Future income tax expenses		    56,167	    51,102		94,162		36,253

Future net cash flows		266,495	114,106	315,301	116,326
10% annual discount for 
	estimated timing
	of cash flows		    96,136	    47,155		122,469		35,008

Standardized measure of 
	discounted future net 
	cash flows		$  170,359	$   66,951	$	192,832	$	81,318

	  The following are the principal sources of change in the standardized measure of 
discounted future net cash flows:

Sales and transfers of oil and 
	gas produced, net of 
	production costs		$	(16,236)	$	(11,518)	$	(23,620)	$	(9,780)
Net changes in prices, 
	development and production 
	costs		(57,866)	(13,339)	(30,047)	(12,687)
Extensions, discoveries, and 
	improved recovery, less 
	related costs		25,625	15,424	60,863	42,699
Revisions of previous quantity 
	estimates		(17,259)	(8,916)	(20,953)	(11,929)
Accretion of discount		21,338	8,937	20,503	7,480
Net change in income taxes		 22,793	 (5,061)	25,584	968
Other		(868)	106	1,601	(1,217)
</TABLE>

	Extensions, discoveries, and improved recovery, less related costs, 
represent the present value of current year reserve additions valued at 
year-end prices less actual unit production costs for the current year.  For 
the years 1998 and 1997, the amount described as other is primarily the result 
of changes in the timing of production.  
</PAGE>

<PAGE>
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.  

<TABLE>
<CAPTION>
		                 Quarter Ended                    

			 Dec. 31, 	 Sept. 30, 	 June 30,  	 Mar. 31,
			   1998   	   1998   	   1998   	   1998   
<S>                                  <C>         <C>          <C>           <C>
Utility Operating Revenues		$158,908	$124,805	$123,393	$158,968
Utility Operating Income		37,852	34,002	24,979	43,027
Utility Net Income		16,587	10,930	5,022	18,946

Nonutility Operating Revenues		256,091	197,901	157,779	152,801
Nonutility Operating Income		80,737	38,845	24,996	20,836
Nonutility Net Income		52,891	24,950	16,606	15,998

Consolidated Net Income
	Available for Common Stock		69,478	35,880	21,628	34,944

Basic Earnings Per Share of 
	Common Stock		$   1.26	$   0.65	$   0.40	$   0.64

Diluted Earnings Per Share of
	Common Stock		$   1.26	$   0.65	$   0.39	$   0.64

<CAPTION>
		                 Quarter Ended                    

			 Dec. 31, 	 Sept. 30, 	 June 30,  	 Mar. 31,
			   1997   	   1997   	   1997   	   1997   
<S>                                  <C>         <C>          <C>           <C>
Utility Operating Revenues		$152,498	$120,914	$119,862	$170,340
Utility Operating Income		44,140	22,047	20,925	61,884
Utility Net Income		25,557	3,012	2,543	27,996

Nonutility Operating Revenues		155,610	125,253	105,567	121,589
Nonutility Operating Income		21,095	14,744	10,183	21,484
Nonutility Net Income		24,955	12,306	11,287	17,286

Consolidated Net Income
	Available for Common Stock		50,512	15,318	13,830	45,282

Basic Earnings Per Share of 
	Common Stock		$	0.93	$	0.28	$	0.25	$	0.83

Diluted Earnings Per Share of
	Common Stock		$	0.92	$	0.28	$	0.25	$	0.83
</TABLE>
</PAGE>

<PAGE>
ITEM  9.	DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL 
DISCLOSURE

	None.  

	PART III


ITEM 10.	DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

	See Part 1, "Executive Officers of the Registrant."

	Information on The Montana Power Company Directors is incorporated by 
reference from the Company's Notice of 1999 Annual Meeting of Shareholders and 
Proxy Statement, pages 5-6.  

ITEM 11.	EXECUTIVE COMPENSATION

	Incorporated by reference from Notice of 1999 Annual Meeting of 
Shareholders and Proxy Statement, pages 9-18.  

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.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

	None.  
</PAGE>

<PAGE>
	PART IV

ITEM 14.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.

 (a)	Please refer to Item 8, "Financial Statements and Supplementary Data" for 
a complete listing of all consolidated financial statements and financial 
statement schedules.  


 (b)	The Company filed the following reports on Form 8-K:  

	     Date        	                Subject                     

	October 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.  

</PAGE>

<PAGE>
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,
							1998
	 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,
		  1997
	 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

</PAGE>
<PAGE>
	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 F-1 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 F-2 to the Asset			Dated
		Purchase Agreement)				November 2,
1998

	10(a)(viii)	Generation Interconnection		1-4566	10(c)
		Agreement (Exhibit G to the			Form 8-K
		Asset Purchase Agreement)			Dated
									November 2,
1998

	10(a)(ix)	Equity Contribution Agreement		1-4566	10(d)
									Form 8-K
									Dated
									November 2,
1998

	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
</PAGE>

<PAGE>
<TABLE>
<CAPTION>
THE MONTANA POWER COMPANY AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
Thousands of Dollars

     COLUMN A     	 COLUMN B 	      COLUMN C        	 COLUMN D 	 COLUMN E 
		 	 Balance	      Additions           
			    at	Charged to	Charged to		 Balance
			beginning	costs and	  other		 at close
    Description   	of period 	 expenses 	 accounts 	Deductions	of period 
<S>                   <C>         <C>          <C>         <C>         <C>
						 (Note a)

Year Ended:  

December 31, 1998
Reserves deducted
in balance sheet
from assets to
which they apply:
Doubtful accounts
	Utility	$	984	$	1,749			$	1,689	$	1,044
	Nonutility		827		182	$	(11)		136		862

		Total	$	1,811	$	1,931	$	(11)	$	1,825	$	1,906

December 31, 1997
Reserves deducted
in balance sheet
from assets to
which they apply:
Doubtful accounts
	Utility	$	924	$	2,349			$	2,289	$	984
	Nonutility		636		229	$	6		44		827

		Total	$	1,560	$	2,578	$	6	$	2,333	$	1,811

December 31, 1996
Reserves deducted
in balance sheet
from assets to
which they apply:
Doubtful accounts
	Utility	$	868	$	1,767			$	1,711	$	924
	Nonutility		601		236	$	(37)		164		636

		Total	$	1,469	$	2,003	$	(37)	$	1,875	$	1,560

<FN>
NOTES:  
(a)	Deductions are of the nature for which the reserves were created.  In the 
case of the reserve for doubtful accounts, deductions from this reserve are 
reduced by recoveries of amounts previously written off.  
</FN>
</TABLE>
</PAGE>

<PAGE>
	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


</PAGE>

<PAGE>
/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
</PAGE>

<PAGE>
	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	
</PAGE>


SIGNATURES (Continued)