March 25, 1998



Securities and Exchange Commission
Attn: Mr. Charles Leber
Judiciary Plaza
450 - 5th Street NW
Mail Stop 7-5
Washington, D.C.  20549

RE:  File Number 1-4566


Dear Mr. Leber:

The accounting principles and practices and the method of applying such 
principles and practices reflected in the financial statements included in the 
1997 Annual Report on Form 10-K are consistent with those of preceeding years. 

	Very truly yours,



	/s/ J.P. Pederson
	J. P. Pederson
	Vice President and Chief
	Financial and Information
	Officer

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, 1997
	-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)

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 $1,996,590,783 at March 12, 1998.  

On March 12, 1998, the Company had 54,910,359 shares of common stock 
outstanding.

	DOCUMENTS INCORPORATED BY REFERENCE

(1)	Notice of 1998 Annual Meeting of Shareholders and Proxy Statement, 
pages 1-26, is incorporated into Part III of this report.  


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 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  

	GENERAL - INDUSTRY SEGMENTS:  The Montana Power Company (the Company) and 
its subsidiaries engage in a number of diversified energy and communication 
related businesses.  The Company's principal business is the regulated Utility 
operations 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 the mining and sale of 
coal and lignite, exploration for, and the development, production, processing 
and sale, of oil and natural gas and the sale of telecommunication equipment 
and services.  It  also conducts the trading and marketing of electricity and 
natural gas. In addition, the Company manages long-term power sales, and 
develops and invests in nonutility power projects and other energy-related 
businesses. The Company was incorporated in 1961 under the laws of the State of 
Montana, where its principal business is conducted, as the successor to a New 
Jersey Corporation incorporated in 1912. 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.

	The Company's open-access and reorganization plan for its regulated 
Natural Gas Utility was approved for implementation by the Montana Public 
Service Commission (PSC), effective November 1, 1997.  Under the approved 
plan, almost all of the regulated Utility's natural gas production assets were 
transferred to its unregulated oil and natural gas operations as of that date 
at a value $33,600,000 below the existing book value.  This difference between 
book value and the transfer 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) and will be reflected in rates over a 15-
year period.  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 November 1, 1997.  Production from these transferred 
properties will be sold in the competitive market in the unregulated 
operations.

	In December 1997, the Company announced that it would offer for sale all 
of its Montana electric generating facilities, including 13 dams and four coal-
fired plants of the regulated utility, as well as its unregulated leasehold 
interest in another coal-fired unit, its contracts for purchased power from 
qualifying facilities and Basin Electric Power Cooperative (Basin) and two 
power exchange agreements.  The total book value of the electric generating 
facilities owned by the Company that are being offered for sale is 
approximately $550,000,000 including approximately $10,000,000 of fuel, 
materials and supplies.  Any amount over book value realized from the sale of 
the regulated properties is expected to reduce the amount of transition costs 
to be recovered from ratepayers. Correspondingly, any amount below book value 
realized from the sale of the regulated properties is expected to be recovered 
from ratepayers.  Any gain or loss realized from the disposition of the 
unregulated leasehold interest, and its related assets and liabilities, will be 
reflected in the Consolidated Statement of Income and will not be passed on to 
ratepayers. It is the intention of the Company to proceed with the sale 
process as tentatively scheduled, however, this divestiture is not a 
requirement of the Restructuring Bill as is the case in some other states with 
deregulation legislation and the Company may at any time cease to continue 
this option. The Company anticipates taking bids in mid-1998.  Refer to Part 
II, Item 8, Financial Statements and Supplementary Data, Note 4 to the 
Consolidated Financial Statements.

	In May 1996, the Company was restructured by management into two 
divisions:  Energy Supply and Energy and Communications Services. The Energy 
Supply Division is responsible for coal, oil and natural gas operations, and 
power generation including marketing, brokering and energy business 
development. The Energy and Communications Services Division is responsible for 
the transmission and distribution of electricity and natural gas as well as 
telecommunications and regulated energy management services.

	Pending regulatory approvals pertaining to the Company's restructuring, 
the discussions and financial information which follow are presented in a 
Utility and Nonutility format.

UTILITY OPERATIONS:

	SERVICE AREA AND SALES:  The Utility's service territory comprises 
107,600 square miles or approximately 73% of Montana.  Within its service 
territory, 86% of the state's population resides.  It serves approximately 
603,000  residents, or 80% of the population within the service territory. 
Additionally, energy is provided to cooperatives that serve approximately 
76,000 residents.  Dominant factors in Montana's economy are agriculture and 
livestock, which constitute Montana's largest industry, tourism and recreation, 
coal and metals mining, oil and natural gas production, and the forest products 
industry, which includes the production of pulp and paper, plywood and lumber.  

	Electric service is provided to 191 communities, the rural areas 
surrounding them and Yellowstone National Park, and natural gas service is 
provided to 109 communities.  Firm electric power is sold at wholesale to two 
rural electric cooperatives.  Natural gas is sold at wholesale or transported 
to distribution companies in Great Falls, Cut Bank, Shelby, Kevin, Sweetgrass 
and Sunburst, Montana.  

	COMPETITIVE ENVIRONMENT:  Refer to Part II, Item 7, "Management's 
Discussion and Analysis of Financial Conditions and Results of Operations - 
Competitive Environment."  

	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 retail electric and natural gas rates, 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.  The 
importation of natural gas from Canada requires approval by the Alberta Energy 
Resources Conservation Board, the National Energy Board of Canada and the 
United States Department of Energy.

	The PSC requires the Company to file an Electric Least Cost Resource 
Plan (Plan) biannually.  The Plan identifies the Company's expectations for 
energy and peak requirements, as well as the resources expected to meet those 
requirements, and considers societal and environmental costs in addition to 
actual dollar costs. The Company requested a waiver of the filing requirements 
for a 1997 Plan and proposed to replace the Plan with an alternative planning 
cycle in the form of a Status Report on the 1995 Plan. This alternative 
planning cycle focuses on the implementation of the 1995 Plan, and explores 
electric industry restructuring and the role Integrated Least Cost Planning 
will play in the future.  The waiver was granted and a Plan Status Report was 
filed in March 1997.  This planning process is expected to be modified 
significantly by the intended sale of Montana generation assets and power 
purchase contracts.

	Also refer to Part II, Item 7, "Management's Discussion and Analysis of 
Financial Conditions and Results of Operations - Competitive Environment."  

	ELECTRIC UTILITY: Total firm capability of the Utility's electric system 
at December 31, 1997 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.  The latter 
includes deliveries which began in December 1997 from a 98,000 kW seasonal 
contract that commenced  in  1996. During 1997, two purchase power contracts 
totaling approximately 154,000 kW expired and were not  renewed. 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 1997 was 1,384,000 kW on January 
13, 1997. The total firm capability on that date was 1,452,500 kW. Also on that 
date, the Electric Utility's reserve margin, as a percentage of maximum demand, 
was 5%.

	Regardless of the timing of the sale of the generating assets and power 
purchase 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 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 Company is evaluating options to meet these needs including market 
purchases or a power supply contract with the purchasers of the generating 
facilities. 

	During the year ended December 31, 1997, the sources of the Utility 
Operations electric supply were:  hydro, 40%; coal, 41%; and purchased power, 
19%.  The cost of coal burned has been as follows:

	 Year Ended December 31 
	 1997 	 1996 	 1995 

	Average cost per million Btu's		$ 0.59	$ 0.59	$ 0.56

	Average cost per ton (delivered)		  9.93	 10.06	   9.67

	The Company's electric system forms an integral part of the Northwest 
Power Pool consisting of the major electric suppliers in the United States, 
Pacific Northwest and British Columbia, and 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 The Washington 
Water Power Company, Idaho Power Company, and PacifiCorp, providing for the 
sharing of transmission capacity of certain lines on their respective 
interconnected systems.  The Company also operates, in coordination with its 
own transmission lines and facilities, the transmission lines and facilities 
which are jointly owned by the utility owners of the four Colstrip generating 
units.  The Company and the Western Area Power Administration have transmission 
interconnection and agreements which provide for the mutual use of excess 
capacity of certain lines on each party's system for the transmission of power 
east of the Continental Divide in Montana and for the firm use of certain of 
the Company's transmission lines to deliver government power. Also refer to 
Part II, Item 7, "Management's Discussion and Analysis of Financial Conditions 
and Results of Operations - Competitive Environment" for discussion of the 
Company's participation in the formation of an independent grid operator called 
"IndeGo".

	NATURAL GAS UTILITY:  Natural gas supply requirements in 1997 totaled 
23,242 Mmcf, of which 11,450 Mmcf were from Montana and 9,930 Mmcf from Canada. 
The Gas Utility produced 36% of the Montana natural gas and its Canadian 
subsidiaries produced 41% of the Canadian natural gas through October 31, 1997. 
A total of 1,826 Mmcf, or approximately 8% of the natural gas supply 
requirements for the year, was purchased for the period November 1, 1997 
through December 31, 1997 from an unregulated subsidiary, Montana Power Gas 
Company (MP Gas).

	Total 1998 natural gas requirements, estimated to be 21,729 Mmcf, are 
anticipated to be supplied from MP Gas and other purchase contracts. 
Approximately 30% of purchases under contracts with outside suppliers and the 
Company's unregulated affiliate, MP Gas, expire each year beginning in 1999 
through 2002.  As a result of the natural gas restructuring order, the Company 
anticipates these contracts will be allowed to expire and will not be 
renegotiated.

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 25 to over 175. Substantially all of these customers obtain 
their supplies directly from other sources.

	Total volumes of natural gas transported were 26,020 Mmcf, 26,969 Mmcf 
and 27,325 Mmcf for 1997, 1996 and 1995 respectively. The 1998 transportation 
volumes are anticipated to be 27,700 Mmcf.  Also, the Company anticipates 
filing a core aggregation pilot program (pilot program) in 1998 with the PSC, 
providing supplier choice for residential and small commercial/industrial 
customers. The pilot program will allow up to 500 Mmcf of the Utility's core 
customers to purchase their gas supply from other sources beginning with the 
1998/1999 heating season.  Assuming the pilot program is successful, all 
customers will have supplier choice by 2001.  The regulated Natural Gas Utility 
will continue to provide gas transmission, storage and distribution service to 
its customers. 


NONUTILITY OPERATIONS:

	GENERAL:  The coal and lignite business is conducted through several 
subsidiaries.  Western Energy Company (Western) holds leases and rights on coal 
properties in Montana and operates the Rosebud Mine located in eastern Montana. 
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 located at the Rosebud Mine. Northwestern Resources Co. 
(Northwestern) holds leases on lignite properties in Texas and operates the 
Jewett Mine. 

	The oil and natural gas business is conducted in the United States 
through North American Resources Company (NARCO) and MP Gas, and in Canada 
through Altana Exploration Company (Altana), Roan Resources, Ltd. (Roan) and 
Canadian Montana Gas Company (CMG). As a result of the PSC-approved Natural Gas 
Utility's restructuring filing, almost all of the regulated Natural Gas 
Utility's production assets, including those of CMG, were transferred to the 
unregulated oil and natural gas operations in November 1997. MP Gas was created 
to hold the previously regulated Montana reserves.

	The independent power business, consisting of Colstrip 4 Lease Management 
Division and Continental Energy Services, Inc. (CES), manages long-term power 
sales and develops and invests in nonutility power projects and other energy-
related businesses.  The 222 megawatt leasehold interest in Colstrip Unit 4 and 
its related assets and liabilities are intended to be sold with the regulated 
electric generating facilities and power purchase contracts.

The telecommunication business is conducted through Touch America, Inc. 
Touch America offers four primary services to customers:  equipment, private 
lines, Internet and long distance services. Touch America also markets and 
maintains PBX and key systems, call accounting systems, computer telephone 
interface and voice mail systems.  Its system includes private, dedicated 
communication lines throughout Montana on a digital microwave and the expanded 
3,000 mile fiber optic network from Seattle, Washington to St. Paul, Minnesota 
and from Denver, Colorado to the Canadian Border.  

	Electricity, natural gas and oil commodity trading and marketing and 
related energy services are provided by the Company's new subsidiary, The 
Montana Power Trading and Marketing Company (MPT&MC).  These traditionally 
wholesale activities will be extended to other regions of the country and into 
retail markets as they become deregulated.

	Other Nonutility businesses are conducted by various subsidiaries, none 
of which is a significant subsidiary.

	COMPETITIVE ENVIRONMENT:	 Current production from the Rosebud and Jewett 
Mines is sold under long-term contracts to mine-mouth customers. The Rosebud 
Mine 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 the Rosebud Mine.  The Jewett Mine sells its entire production to 
the two 800 MW Limestone Units owned by Houston Lighting & Power (HL&P). See 
Part II, Item 8, "Financial Statements and Supplementary Data - Note 2 to the 
Consolidated Financial Statements" for further information on this supply 
agreement. The coal supply agreements for the Colstrip Units provide for 
periodic price re-openers. The Company expects to profitably serve these 
contracts over their remaining lives. The Rosebud Mine has production capacity 
that exceeds the mine-mouth customers' fuel requirements. The Rosebud Mine 
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. The 
Company does not anticipate significant spot market sales from the Rosebud 
Mine for the foreseeable future. Western does not anticipate any significant 
contract changes to result from the sale of the Company's generation assets.

The Company and the other owners of the Colstrip units are involved in 
on-going mediation to restructure the relationship of these other owners and 
the Company, as a joint-owner of the plants and fuel supplier. The outcome of 
the restructuring mediation is uncertain.

	The Nonutility oil and natural gas businesses compete with major oil and 
natural gas companies, other independent and individual producers and operators 
to acquire property, to develop, produce and market oil and natural gas and to 
contract for equipment and services. The Company has production, development 
and long-term marketing abilities, 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. 

	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. Despite the intense 
price competition for these products and services, the telecommunication 
business unit competes by maintaining low costs. 

	COAL OPERATIONS:  Western's Rosebud Mine is at Colstrip, Montana, in the 
northern Powder River Basin, where coal is surface-mined and, after crushing, 
sold without further preparation.  Western's principal customers from this mine 
are the owners of the four mine-mouth Colstrip units.  These customers 
accounted for approximately 91% of 1997 coal sales volumes. The remainder of 
Rosebud coal was sold under spot-market sale agreements and contracts in 
Minnesota, North Dakota and Montana.

	During 1997, Western mined and sold 9,127,000 tons, of which 
3,013,000 tons were sold to the Company.  Western's Rosebud Mine production is 
estimated to be 9,818,000 tons in 1998, as a result of expected Colstrip 
Units 3 & 4 increased coal purchases, and 9,868,000 tons in 1999.

	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 
HL&P. Total deliveries in 1997 were 9,187,000 tons.  The estimated production 
for 1998 and 1999 are 8,884,000 and 8,933,000 tons, respectively. After 2000, 
production is estimated to be approximately 9,100,000 tons annually. In 
litigation regarding the agreement, HL&P obtained summary judgment from the 
trial court declaring that the LSA is a requirements contract only for 
lignite. Thus, the trial court concluded HL&P may substitute other fuel for 
lignite at the plant. While Northwestern intends to appeal this judgment, the 
eventual resolution of this matter may affect future deliveries.

	OIL AND NATURAL GAS OPERATIONS:  Oil and natural gas operations are 
engaged in exploration, production, 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 107 Bcf of natural gas to 
four co-generation facilities over a period of 7 to 13 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 
71,360 Mmcf, or 68.1% 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 and maintains, and manages facilities and resources to 
provide electricity and other energy-related services.

	Colstrip 4 Lease Management Division sells the Company's 222 megawatt 
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 a term 
through December 29, 2010.  The leasehold interest and its related assets and 
liabilities and contract obligations are intended to be sold with the regulated 
electric generating facilities and power purchase contracts.

	CES develops and invests in power projects, and currently holds 
ownership interests in seven operating, natural gas fired projects located in 
Texas, New York, Washington and the United Kingdom, one heavy oil-fired 
project located in Jamaica and one gas-fired independent power project under 
construction in Pakistan. 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 and an 800 MW gas-fired project in Texas.

	CES holds a 50% interest in North American Energy Services Company, 
which provides energy-related support services including the operation and 
maintenance of power plants.  

TELECOMMUNICATIONS OPERATIONS:  Touch America provides long distance, 
Internet, private line, and telecommunications equipment sales and services to 
customers in Montana, Idaho, Washington, Oregon, Minnesota, Colorado and 
Wyoming.  Touch America also markets and maintains PBX and key systems, call 
accounting systems, computer telephone interface and voice mail systems.  

	The telecommunications system includes private, dedicated communication 
lines throughout Montana on a digital microwave and fiber network.  Touch 
America has expanded its fiber network, allowing access to markets extending 
from Seattle, Washington to St. Paul, Minnesota and from Denver, Colorado to 
the Canadian Border.  The expanded 3,000 mile fiber optic network was completed 
in mid-1997, offering increased private line service and sales options as well 
as increased long distance service and Internet efficiencies. The fiber optic 
network is being further expanded in 1998 through Touch America's participation 
in FTV Communications LLC (FTV), a limited liability company owned equally by 
Touch America, Inc., FirstPoint Communications, Inc. (a subsidiary of Enron), 
and Vyvx (a subsidiary of Williams Communications Group). FTV will construct 
and own a 1,620-mile fiber optic network route from Portland to Los Angeles 
through Boise, Salt Lake City and Las Vegas. Touch America is the Construction 
Manager for the project. FTV has successfully completed the sale of a portion 
of the fiber on the project during 1997 and has also entered into an exchange 
agreement on a segment of the route between Las Vegas and Los Angeles. The 
project is scheduled to be completed in December 1998.

ENVIRONMENT:

	For information on Environment see Part II, Item 7, "Management's 
Discussion and Analysis of Financial Condition and Results of Operations - 
Environmental Issues."

EMPLOYEES:

	At December 31, 1997, the Company and its subsidiaries employed 
2,903 persons, including 385 employees at the jointly owned Colstrip Units 1-4. 
Of the 2,903 persons, 1,038 are members of collective bargaining units 
consisting of 16 unions. Current union contracts will expire at various times 
during the next 4 years, with 14 contracts expiring in 1998.  The Company 
expects to complete negotiation of the contracts through the normal course of 
business consistent with its successful history of contract renegotiations. It 
is expected that approximately 500 employees, union and non-union, may be 
directly affected by the sale.  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 are not considered material.


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 - 
Note 4 to the Consolidated Financial Statements" for more information 
concerning 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, 1997, the Utility owned and operated 6,889 miles of 
transmission lines and 15,639 miles of distribution lines. 

	The following table represents average revenues received per kWh by 
customer classification for electricity from all sources for the years 1997, 
1996 and 1995.  

	 Year Ended December 31 
Customer Classification	 1997 	 1996 	 1995 

	Residential		$0.064	$0.061	$0.059
	Commercial		0.059	0.055	0.052
	Industrial		0.041	0.041	0.040
	Sales for Resale		0.019	0.018	0.021
	Government and Municipal		0.085	0.077	0.073

	NATURAL GAS PROPERTIES:  The Utility currently produces minimal amounts 
of natural gas from fields in southern Montana and Wyoming. The Utility 
transferred almost 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.  Except where 
noted, the following disclosures are based on activity for the twelve months of 
1997.

	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, 1997, the Gas Utility and its subsidiaries owned and 
operated 2,104  miles of natural gas transmission lines and 3,451 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."

	In addition to owned reserves of 2,396 Mmcf, the Utility at December 31, 
1997, controlled 23,407 Mmcf of proven reserves in the United States and 
2,365 Mmcf in Canada under purchase contracts. The Utility also has a contract 
with the Nonutility oil and gas operations for the delivery of 47,550 Mmcf of 
natural gas over the next five years as the Utility transitions to full 
customer choice in mid-2002.

	During 1997, the Natural Gas Utility sold properties in the United States 
to outside parties, which resulted in reserve revisions of 15,086 Mmcf. The 
Utility also transferred 61,642 Mmcf of United States reserves and 107,870 Mmcf 
of Canadian reserves to the unregulated oil and natural gas operations.

	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

1995		  5,176		632	7,292	4,650	735	3,031
1996		  5,055		230	6,749	4,694	950	4,850
1997		  3,764		292	8,290	3,402	679	7,132

	The following table presents information as of December 31, 1997, 
pertaining to the Utility natural gas wells and the owned or leased properties 
in which they are located.  

		United States	

	Gross productive wells		  11 	
	Net productive wells		  11 	
	Gross wells with multiple completions		   1 	
	Net wells with multiple completions		   1 	

	Gross producing acres		3,545 	
	Net producing acres		3,545 	
	Gross undeveloped acres		  -  	
	Net undeveloped acres		  -  	

	These properties are located in Montana and Wyoming. 

	The following table presents information on Utility natural gas 
development wells drilled during 1997, 1996 and 1995.  No exploratory wells 
were drilled in the periods specified. 

	  United States  	     Canada     
		1997 	1996 	1995 	1997	1996	1995

Net productive development
  wells		- 	2.00	12.81	- 	7.00	4.00
Net dry development wells		- 	 - 	 1.60	- 	- 	4.00

	The following table presents average revenues received per Mcf by 
customer classification for natural gas from all sources for the years 1997, 
1996 and 1995.  Revenues per Mcf are computed based on volumes at varying 
pressure bases as billed.  
		
	 Year Ended December 31 
Customer Classification	 1997 	 1996 	 1995 

	Residential		$4.72	$4.72	$4.74
	Commercial		4.53	  4.54	  4.54
	Industrial		4.30	4.32	  4.33
	Other gas utilities		4.04	3.41	  3.64

	The following table presents the average production cost per Mcf for 
produced utility natural gas, in U. S. dollars, for the three years 1997, 1996 
and 1995.  

		United States	Canada

	1995		$1.10	$0.34
	1996		  0.94	  0.32
	1997 *		0.89	0.40

	* - Average production costs per Mcf for 1997 were computed based on 10 
months of activity since the assets were transferred to the unregulated 
operations on November 1, 1997.

NONUTILITY OPERATIONS:  

	COAL PROPERTIES:  Western leases and produces coal from Montana 
properties. Northwestern leases and produces lignite from properties in Texas. 
Western's subsidiaries, Western SynCoal Company (SynCoal) and Syncoal Inc., own 
a patented coal enhancement process. SynCoal and Syncoal Inc. own the Rosebud 
SynCoal Partnership, which owns and operates a coal enhancement process 
demonstration plant at the Rosebud Mine.

	Western has coal mining leases covering approximately 519,000,000 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 228,000,000 tons of these reserves are committed to present 
contracts, including requirements of the Colstrip Units.

	Northwestern has lignite mining leases in central Texas at the Jewett 
Mine covering approximately 162,200,000 proved and probable, and recoverable, 
tons of surface-mineable lignite reserves.  Northwestern has contracted all of 
these reserves to Houston Lighting and Power Company, which owns two electric 
generating units located adjacent to the mine.

	In addition, Northwestern has proved and probable, and recoverable 
reserves totaling approximately 144,800,000 tons located in central Texas. 
These reserves are in close proximity to the Jewett Mine.

In the fourth quarter of 1997, Horizon Coal Services, Inc. (Horizon) sold 
its non-producing coal property in Wyoming containing approximately 684,000,000 
proved and probable, and recoverable tons of compliance quality coal reserves.

The Company, through its wholly owned subsidiary, Basin Resources Inc. 
owns approximately 36,000 acres of land in southern Colorado associated with a 
former coal mining operation.  The improvements have been removed and the land 
has been reclaimed.  The Company is currently negotiating the sale of this 
property.

	OIL AND NATURAL GAS PROPERTIES: 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 is expected to increase from 3,800 Mmcf of natural gas to 
approximately 7,300 Mmcf, from 146,000 barrels of oil to 296,000 barrels, and 
from 233,000 barrels of natural gas liquids to 1,613,000 barrels. The 
Nonutility U.S. properties include more than 565 wells, operating some 470 of 
them, and include an 800-mile gas-gathering system, which the Company also 
operates. With the Vessels acquisition, the Company also acquired a natural 
gas processing and fractionating plant. The plant and gathering system is 
being integrated with the Company's existing Fort Lupton plant.  This purchase 
allows the Company to enter the gathering and fractionated liquids businesses. 
The Company, through a Canadian subsidiary, purchased the stock of Questar 
Exploration Inc and in January 1998, these assets were merged 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.

	Oil and gas operations also completed the disposition of non-strategic 
oil and natural gas properties in Kansas, Texas, North Dakota, Oklahoma, and 
Alberta, Canada.  The proceeds from these sales were applied to purchase the 
above natural gas acquisitions.

	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 1997, 1996 and 
1995.
<TABLE>
<CAPTION>
			            Year Ended December 31            
			     1997     	     1996     	     1995     
			United		United		United
		States	Canada	States	Canada	States	Canada
<S>                                      <C>     <C>     <C>     <C>      <C>    <C>
Average sales price:  
	Per Mcf of natural gas		$ 1.94	$ 1.38	$ 1.54	$ 1.10	$ 1.21	$ 0.99
	Per barrel of oil		20.42	18.77	19.74	 16.88	 16.55	 15.29
	Per barrel of natural gas liquids		10.12	15.64	  10.56	14.44	  8.17	 11.33

Average production cost:
	Per barrel of oil equivalent		$ 4.13	$ 3.02	$ 3.94	$ 3.10	$ 3.36	$ 2.90
</TABLE>
	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 1996 to 1997, Nonutility average sales prices 
changed due to fluctuations in the market. Nonutility average production cost 
in the U.S. reflects higher lease operating expenses due to non-recurring 
environmental and compliance work required on the newly acquired Vessels 
properties.  As a result of the completion of this non-recurring work in 1997, 
future production costs are expected to decrease.

	Information on the Nonutility natural gas and oil wells and the owned or 
leased acreage in which they are located, as of December 31, 1997, is presented 
below.  
	United
	   States   		  Canada  

Gross productive natural gas wells	1,153   	295   
Net productive natural gas wells	768.15	242.72
Gross productive oil wells	118   	101   
Net productive oil wells	117.00	68.32

Gross producing acres	522,234	265,443
Net producing acres	338,911	185,476
Gross undeveloped acres	355,853	252,868
Net undeveloped acres	206,866	177,108

	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 181 gross productive natural gas 
wells or 131.41 net productive natural gas wells, and 9 gross productive oil 
wells or 9 net productive oil wells. 

The foregoing acreage located in the United States and Canada are 
primarily in the Rocky Mountain states and Alberta. 

	During 1998, total exploration, acquisition and development expenditures 
(expense and capital) are anticipated to be approximately $34,442,000 in the 
United States and approximately $22,423,000 in Canada.

	The following table presents information on Nonutility oil and natural 
gas exploratory and development wells drilled during 1997, 1996 and 1995.


	   United States    	       Canada       

	 1997 	 1996 	 1995 	 1997 	 1996 	 1995 

Net productive natural gas
	exploratory wells		1.86	 0.33	 2.99	4.30	 0.55	 0.50
Net productive oil
	exploratory wells		1.00	 -  	 1.00	 -  	2.23	-  
Net productive natural gas
	development wells		41.50	 2.58	 6.23	1.30	1.83	   -  
Net productive oil
	development wells		2.87	 -  	 1.34	15.11	 9.78	 7.38
Net dry exploratory wells		0.34	 1.75	 2.50	1.13	0.50	 1.69
Net dry development wells		0.25	1.81	4.24	 -  	0.04	 0.50

	For information on properties acquired, see Part II, Item 8, "Financial 
Statements and Supplementary Data."  


	INDEPENDENT POWER PROPERTIES:  Independent power operations sell power 
from the Company's 222 MW Colstrip 4 leased interest and associated common and 
transmission facilities.  The leasehold interest and its related assets and 
liabilities and 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.  The interests in these projects are not being offered for sale with 
the regulated electric generating facilities:  
<TABLE>
<CAPTION>
Projects in Operation:  

				 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 (1)	Sweetwater, TX	  49.9%	  255	 128	Texas Utilities	U.S. Gypsum
	    (1989)				  Electric Co.
Tenaska-Paris(2)	Paris, TX	  10.0%	  223	  22	Texas Utilities	Campbell
 	    (1989)				  Electric Co.	 Soup Co.
Encogen Four	Buffalo, NY	  49.5%	   62	  31	Niagara Mohawk 	Outokumpu
	    (1992)				  Power Corp.	 AmBrass
Lockport(2)	Lockport, NY	  22.3% 	  168	  37	New York State	Harrison
 	    (1993)				  Electric &	 Radiator
					  Gas Corp.
Teesside	United Kingdom	   3.2%(3)	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			 383
<FN>
(1) CES is the managing partner of this project.

(2)	These co-generation facilities have a long-term contract with NARCO (a Nonutility 
subsidiary) to purchase a portion of their natural gas supply.  

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

<TABLE>
<CAPTION>
Projects Under Construction:  

				 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-	Frederickson, WA	    25.3%	 248	  63	Bonneville	None
 Frederickson	     (4)				  Power Admn

Uch Power	Uch Pakistan	     3.2%	 586	  19	Pakistan Water	None
 Limited	  (1998)				 & Power
					 Department
<FN>
(4)	Construction is approximately 50% complete but has been suspended due to a dispute 
with the Bonneville Power Administration.
</FN>
<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	  (5)	 500	 (5)	State of Andhra	None
  Krishnapatnam	  Pradesh				  Pradesh

Tenaska	Grimes County,	    50%	 800	200	Power Team, a	None
  Frontier	  Texas				  division of PECO
 (Grimes					  Energy Company
  County)
<FN>
(5)	The ownership interest, if any, has not been determined.  
</FN>
</TABLE>

TELECOMMUNICATIONS PROPERTIES:  Touch America has a 3,000-mile fiber 
optic network covering a seven state region extending from Seattle, Washington 
to St. Paul, Minnesota and from Denver, Colorado to the Canadian border. 
Approximately 600 miles of the network from Denver, Colorado to Billings, 
Montana 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, 
Washington to St. Paul, Minnesota is held through an IRU extending through 
early 2022.  Touch America continues to expand its network capacity. The 
additional 1,620 miles of fiber network through FTV will widen Touch America's 
service territory to 11 states. In January 1997, the Company acquired 12 PCS 
licenses in 12 marketing areas between Minneapolis, Minnesota and Seattle, 
Washington along the route of the fiber optic network, which presents an 
opportunity for wireless telephone service in that region.

ITEM 3.  LEGAL PROCEEDINGS

	The Company and North American Resources Company (NARCO), a company 
subsidiary, are defendants in litigation filed on October 30, 1995 in the 
United States District Court for the District of Montana by Paladin Associates, 
Inc. (Paladin).  Paladin is a natural gas broker transporting natural gas on 
the Company's pipeline system.  Paladin alleges the Company, NARCO and 
Northridge Petroleum Marketing, a Canadian corporation in which a former member 
of Entech's Board of Directors was a principal, violated antitrust law by, 
among other things, denying Paladin free access to the market for the sale of 
natural gas.  Paladin also alleges various state law claims for breach of 
contractual obligations, interference with business, and negligence arising out 
of the Company's offer of interruptible storage service and interruptible off-
system transportation to third parties.  Damages claimed by Paladin from the 
alleged antitrust violations measure approximately $10,000,000, which would be 
trebled if there is liability. Damages Paladin seeks for the alleged state law 
violations have not been quantified. Trial of this matter is not scheduled, but 
is expected to occur in 1998.  While the outcome of this litigation cannot be 
predicted, the Company is confident of its defenses and will vigorously pursue 
them.

		In 1994, the Company entered into a 15-year agreement to purchase up to 
98 megawatts of capacity from Basin Electric Power Cooperative (Basin) annually 
between November and the following April.  Delivery of power was to begin in 
November 1996.  The Company rescinded the agreement after Basin's refusal to 
provide electricity at the delivery points the Company requested under the 
terms of the agreement. On November 5, 1996, Basin sued the Company in Federal 
District Court in North Dakota seeking specific performance, a stay of the 
litigation, and an order compelling the Company to arbitrate the dispute. On 
March 20, 1997, the court ordered arbitration of all claims and counterclaims, 
except counterclaims against Basin regarding antitrust and wrongful 
interference with business or trade. On December 19, 1997, the arbitrator 
denied the Company's claims, affirming the Company's obligations to purchase 
power under the agreement.  In December 1997, the Company recognized $7,400,000 
as expense representing all amounts that would have been payable under the 
agreement.

	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:  

	On December 31, 1997, D. T. Berube, 64, retired as Chairman of the Board. 
On July 1, 1997 he retired as Chief Executive Officer. 

	On January 1, 1998, R. P. Gannon, 53, was elected Chairman of the Board. 
He was elected Chief Executive Officer on July 1, 1997. He had previously 
served as Vice Chairman of the Board until January 1, 1998, as President since 
January 1, 1990 and as Chief Operating Officer - Utility Operations from 1992-
1996.  

	In 1996, J. P. Pederson, 55, 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, 45, 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, 49,	was elected Vice President and General 
Counsel.

	In 1996, D. S. Smith, 54, was elected Controller.  He had previously 
served as Controller for Entech from 1988-1996.

	In 1996, E. M. Senechal, 48, was elected Treasurer.  She had previously 
served as Vice President and Treasurer for Entech from 1984-1996.  

	In 1997, W. S. Dee, 57, was elected Vice President, Marketing. He had 
previously been employed as policy teacher and consultant with Leo Burnett, 
Inc., an advertising agency, from 1993 to 1996.  He had also served as Chief 
Executive Officer and owner of W. S. Dee - Omega Beverages, a beverage 
manufacturing company, from 1991 to 1992.

Energy and Communications Services Division:  

	In 1996, J. D. Haffey, 52, 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, 52, 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, 40, was elected Vice President, Business Development 
and Regulatory Affairs.  He had previously served as Treasurer for the Utility 
Division from 1993-1996, as Assistant Treasurer from 1992-1993 and as Manager, 
Corporate Financial Planning and Analysis from 1986-1992.

	In 1996, M. J. Meldahl, 48, was elected Vice President, Communication 
Services.  He had previously served as Vice President, Technology Division - 
Entech from 1988-1996.

	In 1997, W. A. Pascoe, 41, 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 Division:  

	In 1996, R. F. Cromer, 52, 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 and as Vice 
President and General Manager, Continental Energy Services from 1989-1992.  

	In 1996, A. K. Neill, 60, was elected Executive Vice President, Energy 
Supply. He had previously served as Executive Vice President - Generation and 
Transmission 1994-1996 and as Executive Vice President - Utility Services from 
1987-1994.  

	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.  

	In 1996, R. P. Madison, 60, was elected Vice President, Oil and Gas 
Operations, Energy Supply Division.  He had previously served as Vice 
President, Entech Oil Division from 1988-1996.  

	In 1996, P. Gatzemeier, 47, was elected Vice President, Coal Operations. 
He had previously served as Vice President, Entech Coal Division from 1992-
1996.  


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 
1997 and 1996.  The number of common shareholders of record on December 31, 
1997, was 41,868.  


				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


				Dividends
				Declared
				   per  
	    1996   	  High  	   Low  	  Share  

	1st quarter	$	23.000	$	21.250	$	0.40
	2nd quarter	22.750	21.000	0.40
	3rd quarter	22.375	20.625	0.40
	4th quarter	22.000	20.750	0.40

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

The Montana Power Company and Subsidiaries

Balance Sheet Items (000)
			   1997  	   1996  	   1995  
<S>                                       <C>  <C>  <C>            <C>
Assets:
	Utility plant		$2,216,198	$2,236,309	$2,156,959
	Less accumulated depreciation 
		and depletion		   684,960	   705,119	   663,216
		Net Utility plant		 1,531,238	 1,531,190	 1,493,743
	Nonutility property		781,406	   666,679	   633,079
	Less accumulated depreciation
		and depletion		   260,567	   256,489	   252,612
		Net Nonutility property		   520,839	   410,190	   380,467
			Total net plant and property		2,052,077	 1,941,380	 1,874,210
	Other assets		   749,619	   756,835	   711,881
			Total Assets		$2,801,696	$2,698,215	$2,586,091

Liabilities:
	Common shareholders' equity		$1,037,534	$  999,657	$  976,043
	Unallocated stock held by trustee
		for retirement savings plan		(25,945)	(28,360)	   (30,565)
	Preferred stock		57,654	57,654	   101,416
	Mandatorily redeemable preferred
		securities of trust		65,000	65,000
	Long-term debt		653,168	633,339	   616,574
	Other liabilities		 1,014,285	   970,925	   922,623
			Total Liabilities		$2,801,696	$2,698,215	$2,586,091
</TABLE>

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

The Montana Power Company and Subsidiaries

Balance Sheet Items (000)
			   1994   	   1993   	   1992   
<S>                                        <C>         <C>         <C>
Assets:
	Utility plant		$2,021,981	$1,891,432	$1,802,987
	Less accumulated depreciation 
		and depletion		   619,195	  572,141	   533,216
		Net Utility plant		 1,402,786	 1,319,291	 1,269,771
	Nonutility property		   600,299	   596,769	   552,537
	Less accumulated depreciation 
		and depletion		   207,486	   198,951	   178,275
		Net Nonutility property		   392,813	   397,818	   374,262
			Total net plant and property		 1,795,599	 1,717,109	 1,644,033
	Other assets		   717,098	   668,918	   641,389
			Total Assets		$2,512,697	$2,386,027	$2,285,422

Liabilities:
	Common shareholders' equity		$  988,100	$  945,651	$  902,989
	Unallocated stock held by trustee
		for retirement savings plan		   (32,580)	(34,419)	(36,098)
	Preferred stock		   101,416	101,419	51,984
	Mandatorily redeemable preferred
		securities of trust	
	Long-term debt		   588,876	   571,870	   581,179
	Other liabilities		   866,885	   801,506	   785,368
			Total Liabilities		$2,512,697	$2,386,027	$2,285,422
</TABLE>

<TABLE>
<CAPTION>
Income Statement Items (000)
				   1997   	   1996   	   1995   
<S>                                       <C>         <C>          <C>
	Revenues		$1,023,597	$  973,208	$  953,224

	Expenses:
		Operations		415,979	   381,550	   420,472
		Maintenance		75,994	68,181	    68,286
		Selling, general and administrative		124,244	113,485	   104,213
		Taxes other than income taxes		96,214	87,903	    89,858
		Depreciation, depletion and 
			amortization		94,664	86,403	    84,635
		Writedowns of long-lived assets (a)		          	          	    74,297
					   807,095	   737,522	   841,761

			Income from operations		216,502	235,686	   111,463

	Interest expense and other income:
		Interest		54,667	48,770	    43,656
		Distributions on mandatorily
			redeemable preferred securities
			of subsidiary trust		5,492
		Other (income) deductions - net		   (34,159)	    (4,445)	   (10,704)
					26,000	44,325	    32,952

	Income taxes		    61,870	    71,975	    21,574

	Net income		128,632	119,386	    56,937
	Dividends on preferred stock		     3,690	     8,358	     7,227

	Net income available for common stock		$  124,942	$  111,028	$   49,710

	Basic  earnings per share of common
		stock:
		Utility operations		$     1.08	$     1.13	$     1.22
		Nonutility operations		      1.21	      0.90	     (0.30)
				$     2.29	$     2.03	$     0.92

	Diluted earnings per share of
		common stock		$     2.28	$     2.03	$     0.92

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

	Average shares outstanding (000)		54,649	54,634	    54,121

	Earnings coverage of fixed 
		charges, SEC Method		2.94x	3.21x	1.96x

<FN>
(a)	Refer to Item 8, "Financial Statements and Supplementary Data - Note 1 to 
the 	Consolidated Financial Statements."
</FN>
</TABLE>

<TABLE>
<CAPTION>
Income Statement Items (000)
				   1994   	   1993   	   1992   
<S>                                        <C>         <C>        <C>
	Revenues		$1,005,970	$1,024,285	$  943,872

	Expenses:
		Operations		   436,610	   476,733	   412,387
		Maintenance		    75,357	    70,029	    70,525
		Selling, general and administrative		   109,217	   106,765	    93,061
		Taxes other than income taxes		    99,200	    92,430	    94,328
		Depreciation, depletion and 
			amortization		    84,483	    80,831	    79,901
		Writedowns of long-lived assets		          	          	          
					   804,867	   826,788	   750,202

			Income from operations		   201,103	   197,497	   193,670

	Interest expense and other income:
		Interest		    42,817	    48,023	    49,166
		Other (income) deductions - net		   (10,532)	   (11,857)	    (8,200)
					    32,285	    36,166	    40,966

	Income taxes		    55,226	    54,120	    45,639

	Net income		   113,592	   107,211	   107,065
	Dividends on preferred stock		     7,227	     4,353	     3,790

	Net income available for common stock		$  106,365	$  102,858	$  103,275

	Basic earnings per share of common
		stock:
		Utility operations		$     0.91	$     1.07	$     0.97
		Nonutility operations		      1.09	      0.91	      1.05
				$     2.00	$     1.98	$     2.02

	Diluted earnings per share 
		of common stock		$     2.00	$     1.97	$     2.02

	Dividends declared per share of
		common stock		$    1.60	$    1.585	$     1.55

	Average shares outstanding (000)		53,125	    52,040	    51,126

	Earnings coverage of fixed 
		charges, SEC Method		3.05x	2.86x	2.74x
</TABLE>


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 impact of restructuring initiatives in the electric and gas 
industry, 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 1995 through 
1997 or which are expected to have an impact on operating results in the 
future.

	In May 1996, the Company was restructured by management into two 
divisions:  Energy Supply and Energy and Communications Services. Pending 
regulatory approvals pertaining to the Company's restructuring, the discussions 
and financial information which follow are presented in a Utility and 
Nonutility format. Refer to Item 8, "Financial Statements and Supplementary 
Data - Note 4 to the Consolidated Financial Statements".  

Net Income Per Share of Common Stock:  

The Company's net income available for common stock increased to 
$124,942,000 in 1997 compared to $111,028,000 and $49,710,000 in 1996 and 1995, 
respectively.  The following table shows the sources of consolidated net income 
on a basic per share basis.  


		 1997 	 1996 	 1995 

	Utility Operations	$ 1.08	$ 1.13	$ 1.22
	Nonutility Operations	 1.21	  0.90	 (0.30)

	Consolidated	$ 2.29	$ 2.03	$ 0.92

	Consolidated net income for the year ended December 31, 1997 was $2.29 
per share, an increase of 26 cents over last year.

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 & 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 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 last year.  The 
income tax settlement mentioned above also positively impacted the Utility.

	Net income for the year ended December 31, 1996 was $2.03 per share, 
compared with 92 cents per share in 1995. Included in 1995 consolidated 
earnings were charges of 90 cents per share resulting from the adoption of a 
new accounting standard, "Accounting for the Impairment of Long-Lived Assets 
and for Long-Lived Assets to Be Disposed Of" (SFAS No. 121), the closing of 
the Golden Eagle Mine and the outcome of a coal arbitration decision.

	Utility earnings for 1996 were positively impacted by higher electric 
and natural gas revenues resulting from increased rates, 12% colder weather 
than 1995, three percent overall customer growth and reduced power-supply 
expenses due to the availability of low-cost regional hydroelectric energy. 
The Utility's natural gas revenues alone increased 12% over 1995. After-tax 
charges of approximately $3,800,000 were recorded in the fourth quarter of 
1996 related to permanent employee reductions and the refinancing of preferred 
stock. These charges are expected to result in future cost savings.

	Nonutility earnings for 1996 increased primarily due to the closure of 
the Golden Eagle Mine, which had sustained operating losses of approximately 
18 cents per share in 1995, and growth in earnings from independent power 
investments throughout 1996, including a gain on the sale of a portion of an 
asset in the fourth quarter of 1996. Partially offsetting these positives were 
reduced coal sales to the Colstrip thermal plants due to the availability of 
low-cost hydroelectric power. Coal volumes also decreased due to the 
expiration of a coal-supply contract with a Midwestern customer at the end of 
1995.

Competitive Environment:

The Company's regulated electric and natural gas businesses are 
transitioning to competition over the next several years in accordance with 
Montana's "Electric Industry Restructuring and Customer Choice Act" and 
Montana's "Natural Gas Restructuring and Customer Choice Act" (Acts or 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.

In 1997, the Company received 55% of its revenues and 49% of its net 
income from regulated utility operations.  Other revenue and net income was 
provided by its diverse unregulated businesses engaged in coal, oil and natural 
gas, independent power and telecommunications operations. A variety of 
transition activities, which are detailed below, will help the Company manage 
change and position itself for a more competitive future.

REGULATED OPERATIONS:

Electric Utility -

General -- The Act provides for choice of electricity supply for the 
Company's large customers by July 1, 1998, for pilot programs for residential 
and small commercial customers beginning July 1, 1998, and for all customers 
no later than July 1, 2002. Generation assets will be removed from regulated 
rate base no later than July 1, 1998. Transmission and distribution services 
will remain fully regulated by FERC and/or the Montana Public Service 
Commission (PSC). The Act 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 Act contemplates that rates cannot be increased under the rate 
moratorium except under limited circumstances. This moratorium begins after a 
2.4% increase, effective January 1, 1998, which will increase revenue 
approximately $9,000,000. The legislation authorizes the use of transition 
bonds, subject to the approval of a financing order by the PSC, as a method of 
financing transition obligations at lower costs. In addition, under the 
legislation, if, during the transition period, the earnings of the Electric 
Utility fall below a 9.5% return on equity, the Utility's obligation to flow 
investment tax credit benefits to ratepayers in future years is reduced.  Any 
such reduction in the Utility's regulatory obligation provides an economic 
benefit to the Company and increases income in that year. The 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.

The legislation requires the payment, through transition charges, of 
proven non-mitigatable transition costs, specifically recovery of above-market 
generation and qualifying facility power-purchase contract costs and regulatory 
assets, and requires for reciprocity between utility companies. 

As required by the Act, the Company filed a comprehensive transition plan 
with the PSC on July 1, 1997. The filing includes the proposed handling and 
resolution of transition costs, and addresses other issues required by the 
legislation. The Company expects the PSC to render a decision in June 1998, 
subject to the provisions of the legislation.

The restructuring activities of the vertically integrated Electric 
Utility are described as follows:

Generation -- The Company announced that it will offer for sale all of 
its Montana electric generating facilities. These generating facilities 
include 13 dams and four coal-fired plants, its contracts for power purchased 
from qualifying facilities and Basin Electric Power Cooperative (Basin), and 
its unregulated leased interest in another coal-fired plant.  

Regardless of the timing of the sale of the generating assets and power 
purchase 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 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 Company is evaluating options to meet these needs including a power supply 
contract with the purchasers of the generating facilities.

The sale of these assets is expected to occur in 1998.  The sale will 
expedite the development of competition in Montana's electric-generation 
market. Proceeds from the divestiture may be used to repurchase debt and equity 
securities, and proceeds up to the book value of the assets sold may be 
invested in growth opportunities related to the Company's current regulated and 
unregulated business lines. 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. The sales decision reflects 
three major beliefs:

(1) Montana Power will be better positioned if it does not own 
generation in a regulatory jurisdiction where it provides 
transmission and distribution services. The reduction of regulatory 
complexities will allow the Company to react quicker to business 
opportunities. 
(2) The size and geographic presence necessary to compete successfully 
in the dynamic, evolving competitive generation market means that 
only the larger companies will have a sustainable competitive 
advantage. Exiting its generation activities in Montana allows the 
Company to focus more on its core strength of customer service. 
(3) Energy prices in the future will be determined by competition and 
may be higher or lower than actual costs of generation.  The risk 
associated with this price competition is better taken by larger 
companies who are concentrating on generation.

The divestiture of these generating plants and the sale of contracts for 
purchased power from independent qualifying facilities and Basin also will help 
to resolve issues associated with the Company's transition costs in the filing 
currently before the PSC.

The electric generation assets will be removed from rate base on July 1, 
1998.  Until the sale is completed, the costs associated with owning and 
operating the assets are expected to continue to be recovered through a cost-
based contract between the Company's regulated operations and its non-
regulated Supply Division. Any gains above the Company's book value realized 
in the sale of the regulated generating facilities and power purchase 
contracts will be utilized to reduce the electric Competitive Transition 
Charge (CTC) amounts to be collected from ratepayers.  Conversely, any losses 
or additional costs to the Company would increase the CTC amounts to be 
collected over the approved transition period. 

Transmission -- On April 24, 1996, the Federal Energy Regulatory 
Commission (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 current 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 to comply 
with FERC Order No. 889.  The Company anticipates updating its FERC tariffs 
with a filing in March 1998.

As part of a group of other Pacific Northwest electric utilities, the 
Company has been studying the formation of an independent grid operator 
(IndeGo) to manage the utilities' high-voltage transmission lines. Work on the 
IndeGo proposal has recently been suspended due to lack of regional consensus.

The Company's transmission system serves a majority of the state of 
Montana with nearly 7,000 miles of lines.  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.

Distribution -- Distribution service will continue to be regulated by 
the PSC and provided by the Company's regulated Distribution Division. 

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 six percent of the Company's system load. 
The Company expects to make an application to FERC for recovery of costs which 
will be stranded by the termination of this contract, subject to the outcome 
of the intended sale of generation assets and power purchase contracts.

Natural Gas Utility --

General -- The restructuring legislation for the Natural Gas Utility 
allows utilities to voluntarily offer customers choice of natural gas supply 
and authorizes the use of transition bonds, subject to the approval of a 
financing order by the PSC, as a method of financing transition obligations at 
lower costs.  The Act 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.

On October 28, 1997, the PSC approved an order giving the Company's 
natural gas customers the right to choose their own suppliers based upon 
stipulation agreements resulting from the Company's July 1996 Restructuring 
Filing.  Customers with annual loads greater than 60,000 dekatherms (Dkt) have 
been eligible to transport natural gas since November 1, 1991.  The October 
order provides for a reduction in this load eligibility level to 5,000 Dkt, 
annually, effective November 1, 1997, equating to approximately 230 smaller 
industrial and larger commercial customers. The order also provides for a pilot 
program for small residential and general service customers to commence by the 
1998 - 1999 heating season and a transition to full customer choice no later 
than mid- 2002.  

	Almost all of the natural gas production assets of the regulated Utility 
were transferred to an unregulated subsidiary on November 1, 1997 at an amount 
agreed-to in the natural gas order 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 CTC and will be recovered from 
transmission and distribution customers in rates over a 15-year period.  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.  Production from these transferred properties will be sold in the 
competitive market in the unregulated operations.

	Natural gas transmission, distribution and storage will remain regulated 
by the PSC, while eligible customers will be allowed to secure their gas 
supply on the open market.

The PSC order reduced annual natural gas revenues by $2,800,000, or 
2.3%, and froze base rates for two years. A non-bypassable Universal System 
Benefits Charge for public purpose programs was also implemented. The Company 
is pursuing the issuance of transition bonds that will refinance the 
transition costs at a lower cost of capital.  The issuance of these bonds is 
expected to result in annual savings of approximately $1,900,000. In November 
1997, the Company filed an application with the PSC seeking authorization to 
issue up to $65,000,000 of transition bonds. 

	On January 5, 1998, Enron Capital & Trade Resources Corp. (Enron) 
requested court review of the PSC's decision regarding the measure of stranded 
costs as well as the level of functional separation of the various segments of 
the Company's natural gas business.  This appeal is pending before the First 
Judicial District Court, Lewis and Clark County. Enron alleges the PSC erred 
when it concluded the assets subject to the CTC are stranded and that their 
value is $60,000,000.

	The Company requested, and expects the district court to provide, 
expedited review and decision making regarding this matter. The Company does 
not expect the PSC to act upon the Company's application for authority to 
issue transition bonds while this appeal is pending at the district court. The 
CTC rates assume the cost of capital associated with the transition bond 
financing, therefore, the Company is not collecting from customers its full 
cost of capital associated with these stranded costs.

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, as the decrease will be offset by reduced supply costs, CTC 
charges, transportation and distribution revenues and transition bond financing 
savings. The PSC order has been appealed by Enron. Consequently, the timing of 
any transition bond issuance is uncertain.  

Production -- As discussed above, the Company's unregulated Supply 
Division assumed ownership of almost all of the natural gas production assets, 
except delivered gas purchase contracts, which have been retained by the 
regulated Natural Gas Utility. The assets were transferred at less than book 
value. The difference between book value and the agreed-upon transfer value, 
and the regulatory assets associated with natural gas production will be 
recovered over 15 years from transmission and distribution customers as a 
component of CTC charges.

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.  

UNREGULATED OPERATIONS:

	General -- In the fourth quarter of 1997, the Company merged MP Energy 
Services, Inc. into MP Energy, Inc. and renamed the entity The Montana Power 
Trading & Marketing Company (MPT&MC).  The new name better describes the 
functions and services that MPT&MC will be providing to customers.  The 
Company has traditionally sold natural gas, electricity, natural gas liquids 
in bulk and other commodities for resale.  The structural changes in the 
energy markets due to deregulation provides the opportunity for the Company to 
extend its traditional wholesale activities to other regions of the nation and 
to expand into retail markets as they become deregulated. The Company will 
focus its activities in the western half of the United States and the upper 
Midwest. MPT&MC targets wholesale and large industrial customers that have 
been granted the right, either by state or federal agencies, to pursue other 
sources for their electricity and natural gas supplies. 

In order to better manage the risks associated with commodity 
production, trading and marketing, the Company retained an outside consultant 
in 1997 to design a comprehensive Energy Risk Management program.  The program 
is being implemented in the first half of 1998.  In addition, the Company also 
established a position, reporting directly to the Company's Chief Financial 
Officer, to oversee the risks in MPT&MC.  Finally, MPT&MC will be implementing 
new systems in 1998 to enable it to more accurately track and manage its 
commodity portfolio. 

	Wholesale -- The Company has a long history of trading in the wholesale 
electric market and also has developed trading, and wholesale and large 
customer expertise in its unregulated natural gas operations. The Company 
believes that this experience allows it to effectively compete in the 
competitive environment.  Currently, the electricity markets are not as 
developed as the natural gas markets.  As the electricity market develops, 
many of the same financial instruments that are used to control risk and 
volatility in the natural gas industry will be used for the electric industry. 
The formation of MPT&MC brings together the Company's expertise in the 
wholesale trading of all energy commodities.  
	
To serve growing markets, MPT&MC secured firm capacity on Pacific Gas 
Transmission's (PGT) interstate pipeline and on Pacific Gas & Electric 
Company's intrastate pipeline. The intrastate capacity provides MPT&MC with 
the ability to offer firm gas deliveries to California customers and PGT 
capacity provides MPT&MC with firm access to Canadian supplies. Trading and 
deliveries to customers will begin in 1998. In addition, MPT&MC will begin 
trading natural gas in the Upper Midwest once an affiliate's firm 
transportation capacity on Northern Border Pipeline is activated. This is 
expected to occur in late 1998. This capacity provides access for the 
Company's low-cost gas from its Bowdoin production on a firm basis to upper 
Midwest markets since this pipeline provides access to several local 
distribution companies in the Chicago area.

Retail -- The Company, through MPT&MC, is actively selling retail 
energy-related products and services in a competitive marketplace.  This 
includes energy commodity supplies, assisting customers with utility rate 
management; managing power contracts; installing energy-efficient equipment; 
and tracking facility energy use, and other services required by customers. 

The Montana Power Group (MPG), an energy supply and management alliance, 
was exclusively endorsed by the California Manufacturers Association (CMA) to 
assist its members with their energy decisions. As a participant in the MPG, 
MPT&MC agreed to offer comprehensive energy services, including energy supply, 
discounted from the power exchange prices, and energy management products and 
services to qualified CMA members. The CMA has agreed to endorse and promote 
such products and services to its members. The membership of the CMA is the 
target market for MPT&MC in California.  The approximate 1,000 members of CMA 
represent an estimated 8,000,000 megawatt hours of electric use annually.  The 
supply program is offered on a limited basis to CMA members capped at 
predetermined volumes.  The program will be subscribed on a first come, first 
serve basis. Once the caps are fully subscribed, MPT&MC will have, at its sole 
discretion, the option to extend the offered supply and services to other CMA 
members. To date, one contract for energy supply and services has been signed 
with a CMA member. MPT&MC is expecting to begin retail deliveries in 
California on April 1, 1998, pending the California market opening on that 
date. At this time, the Company cannot predict the impact of the CMA agreement 
on future earnings, however, due to the limits provided in the agreement, any 
potential negative impacts are not expected to have a material impact on the 
Company's financial position or results of operations. 

MPT&MC is also participating in the Puget Sound Energy customer choice 
pilot program in western Washington.  The Company has one retail industrial 
customer and has been delivering energy under the pilot program since December 
1997.


<TABLE>
<CAPTION>
			        UTILITY OPERATIONS
			      Year Ended December 31        
			   1997   	   1996   	   1995   
			       Thousands of Dollars
<S>                                                  <C>         <C>          <C>
ELECTRIC UTILITY:

REVENUES:
	Revenues		$  435,986	$  430,171	$  421,999
	Intersegment revenues		     4,685	     5,793	     5,813
				440,671	435,964	   427,812

EXPENSES:
	Power supply		142,193	136,817	   148,240
	Transmission and distribution		31,883	30,263	    26,916
	Selling, general and administrative		55,934	53,922	    43,763
	Taxes other than income taxes	 	47,985	46,191	    43,302
	Depreciation and amortization		    51,674	    46,648	    40,675
				   329,669	   313,841	   302,896

	INCOME FROM ELECTRIC OPERATIONS		111,002	122,123	   124,916

NATURAL GAS UTILITY:  

REVENUES:
	Revenues (other than gas supply
		cost revenues)		105,220	107,782	    93,453
	Gas supply cost revenues		17,135	20,746	    21,660
	Intersegment revenues		       588	       649	       852
				122,943	129,177	   115,965

EXPENSES:
	Gas supply costs		17,135	20,746	    21,660
	Other production, gathering and exploration		8,128	9,335	     9,643
	Transmission and distribution		11,353	11,711	    10,934
	Selling, general and administrative		20,342	19,195	    17,671
	Taxes other than income taxes		16,052	15,722	    14,841
	Depreciation, depletion and amortization		    11,939	    11,638	    10,283
				    84,949	    88,347	    85,032

	INCOME FROM GAS OPERATIONS			37,994	40,830	    30,933

INTEREST EXPENSE AND OTHER INCOME: 
	Interest		52,191	46,663	    44,031
	Distributions on company obligated
		mandatorily redeemable preferred
		securities of subsidiary trust		5,492		
	Other (income) deductions - net		    (7,128)	      (402)	    (5,419)
				    50,555	    46,261	    38,612

INCOME BEFORE INCOME TAXES		98,441	116,692	   117,237

INCOME TAXES		   35,643	    46,687	    44,047

DIVIDENDS ON PREFERRED STOCK		    3,690	    8,358	    7,227

UTILITY NET INCOME AVAILABLE FOR COMMON STOCK		$   59,108	$   61,647	$   65,963
</TABLE>

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 1997 temperatures for the 
Company's service territory were 10% warmer than 1996 and comparable to the 
historic average.  Temperatures in 1996 were 12% colder than 1995 and 11% 
colder than 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 than last year and consequently, the 
Company did not curtail its thermal generation as it had during 1996.  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 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 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 has not yet been 
determined.  The Financial Accounting Standards Board's (FASB) Emerging Issues 
Task Force (EITF) met in July 1997 to discuss issues related to removing the 
generation portion of a utility company from SFAS No. 71. Recovery of the 
Company's existing regulatory assets related to the natural gas production 
assets was provided in the PSC order, therefore the discontinuance of SFAS No. 
71 for these assets did not have a material impact on the results of operations 
for 1997.  Recovery of existing regulatory assets related to electric 
generation is provided in the electric restructuring legislation.  Based upon 
the EITF's conclusions regarding regulatory assets and liabilities and the 
Company's anticipated recovery of its regulatory assets, the Company believes 
that the discontinuation of regulatory accounting for these 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."

<TABLE>
<CAPTION>
Electric Utility:  

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

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		49,921	52,125	(4)%	2,663	2,761	(4)%	84	79	6%
Other		8,751	12,265	(29)%						
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	$	21,231	$	19,423	9%	4,126	4,064	2%
Steam 		52,801	47,185	12%	4,290	4,272	0%
Purchases
	and Other		68,161	70,209	(3)%	2,538	2,557	(1)%
	Total Power Supply	$	142,193	$	136,817	4%	10,954	10,893	1%
Cents Per kWh	$	1.298	$	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 selling, general and 
administrative (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.


<TABLE>
<CAPTION>
1996 Compared to 1995


	Revenues and
	 Power Supply Expenses	Volumes	Customers	
	(Thousands of Dollars)	(Thousands of MWh)	(Yearly Average)
		1996	1995			1996	1995			1996	1995	
<S>                 <C>        <C>     <C>     <C>     <C>    <C>  <C>      <C>      <C>
Revenues:

Residential,
	Commercial &
	Government	$	257,625	$	232,676	11%	4,414	4,181	6%	271,683	266,497	2%
Industrial		108,156	120,161	(10)%	2,580	2,974	(13)%	3,257	3,166	3%
	General Business		365,781	352,837	4%		6,994	7,155	(2)%	274,940	269,663	2%
Sales to Other									
	Utilities		52,125	58,623	(11)%	2,761	2,751	0%	79	71	11%
Other		12,265	10,539	16%						
Intersegment		5,793	5,813	0%	332	299	11%	230	234	(2)%
	Total	$	435,964	$	427,812	2%	10,087	10,205	(1)%	275,249	269,968	2%

Power Supply
	Expenses:
Hydroelectric	$	19,423	$	19,291	1%	4,064	3,480	17%
Steam 		47,185	44,010	7%	4,272	4,754	(10)%
Purchases
	and Other		70,209	84,939	(17)%	2,557	2,667	(4)%
	Total Power Supply	$	136,817	$	148,240	(8)%	10,893	10,901	0%
Cents Per kWh	$	1.256	$	1.360

</TABLE>
Revenues from general business customers increased in 1996 due to higher 
tariff rates and greater volumes sold as a result of colder weather and 
customer growth.  These increases were partially offset by reduced revenues 
related to a large industrial customer, who was served under a rate that was 
lower than the tariff rate, closing operations in December 1995.  Sales to 
other utilities declined primarily as a result of the expiration of two firm 
sales contracts, one in late 1995 and the other in early 1996.  This decrease 
was partially offset by increased wholesale volumes, moderated by lower 
regional energy prices.  Other revenues increased due to higher wheeling 
rates.

Excluding a 1995 steam expense reduction of $11,300,000 related to a 
coal arbitration decision, steam expenses decreased in 1996 when higher cost 
thermal generation was displaced as streamflow conditions caused increases in 
Utility and regional low-cost hydroelectric generation.  Shorter maintenance 
periods, improved productivity and permanent employee reductions at the 
Colstrip units also decreased steam expenses.  Purchased power costs declined 
due to the expiration of two high-priced firm purchase contracts in the first 
half of 1996 and a credit from a third party who delivers energy to the 
Company's customers.  This decrease was partially offset by increased 
opportunity purchases and additional payments to qualifying facilities. 
Transmission and distribution expenses were up as a result of several non-
recurring items.  Increases in SG&A expenses were primarily related to 
permanent employee reduction costs, reduced billing to third parties and the 
absence of insurance proceeds received in 1995.  The increase in taxes other 
than income taxes was mainly due to higher property taxes related to property 
additions and increased mill levies.  Depreciation expense increased as a 
result of greater plant investment and a mid-1996 change in the PSC-approved 
depreciation rate.
<TABLE>
<CAPTION>
Natural Gas Utility:

1997 Compared to 1996


		Revenues	Volumes	Customers	
	(Thousands of Dollars)	(Thousands of Mmcf)	(Yearly Average)
		1997	1996			1997	1996			1997	1996	
<S>                 <C>        <C>      <C>   <C>     <C>      <C>  <C>     <C>      <C>
Revenues:

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 selling, general and administrative 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.


<TABLE>
<CAPTION>
1996 Compared to 1995


		Revenues	Volumes	Customers	
	(Thousands of Dollars)	(Thousands of Mmcf)	(Yearly Average)
		1996	1995			1996	1995			1996	1995	
<S>                 <C>        <C>     <C>     <C>     <C>    <C>  <C>      <C>      <C>

Revenues:										

Residential,
	Commercial &
	Government	$109,795		$	98,350	12%	23,690	21,152	12%	137,222	132,518	4%
Industrial		2,921	2,646	10%	675	611	10%	421	412	2%
	Subtotal		112,716	100,996	12%	24,365	21,763	12%	137,643	132,930	4%
Gas Supply Cost									
	Revenues (GSC)		(20,746)	(21,660)	(4)%						
	General Business									
	without GSC		91,970	79,336	16%	24,365	21,763	12%	137,643	132,930	4%
Sales to Other								
	Utilities		868	762	14%	255	209	22%	3	3	0%
Transportation		9,582	8,563	12%	26,969	27,325	(1)%	42	39	8%
Other		5,362	4,792	12%						
	Total		$107,782	$	93,453	15%	51,589	49,297	5%	137,688	132,972	4%
</TABLE>


Natural gas revenues, excluding gas supply cost revenues, increased as a 
result of higher tariff rates and greater volumes sold due to colder weather 
and customer growth.  SG&A expense increased primarily due to permanent 
employee reduction costs.  Depreciation expense increased for the same reasons 
mentioned in the Electric Utility discussion.

Other Income and Expense, and Preferred Dividends:

1997 Compared to 1996

	Interest expense increased in 1997 due to additional borrowing and 
interest accrued on the Kerr Project mitigation liability which was recorded in 
the second quarter of 1997. Increases in other income related to the interest 
income on the 1997 settlement of a dispute with the  IRS and the absence of a 
1996 loss on written-off property were partially offset by costs associated 
with the Flint Creek Dam transfer to Granite County, Montana in the second 
quarter of 1997.

	Income tax expense declined in 1997 as a result of lower before-tax net 
income, a reduced effective tax rate and decreased tax accruals resulting from 
the settlement of a dispute with the IRS.

	Preferred dividends decreased in 1997 because the Company repurchased and 
retired 139,200 shares of its $6.875 series and redeemed all outstanding shares 
of its $2.15 series during the fourth quarter of 1996.

1996 Compared to 1995

	Interest expense increased in 1996 as a result of additional borrowing in 
the fourth quarter.  Other income decreased due to a loss on written-off 
property and the absence of interest income received in 1995 related to a coal 
arbitration decision.  A reduction in capitalized labor added to the interest 
expense increase and partially offset the other income decrease.

	Income taxes increased due to a corresponding increase in before-tax net 
income and a higher 1996 effective tax rate as a result of regulatory 
accounting related to deferred income taxes on depreciation.


<TABLE>
<CAPTION>
	NONUTILITY OPERATIONS
	       Year Ended December 31       
			   1997   	   1996   	   1995   
			Thousands of Dollars
<S>                                                  <C>          <C>         <C>
COAL:

REVENUES:
	Revenues		$ 167,623	$ 163,901	$ 207,451
	Intersegment revenues		   34,164	   31,448	   25,659
			201,787	195,349 	  233,110 

EXPENSES:
	Operations and maintenance		119,086	115,859	  155,149
	Selling, general and administrative		22,030	21,373	   28,211
	Taxes other than income taxes		23,455	20,883	   27,210
	Depreciation, depletion and amortization		8,368	5,653	   11,187
	Writedowns of long-lived assets		         	         	   55,103
			  172,939	  163,768	  276,860

	INCOME (LOSS) FROM COAL OPERATIONS		28,848	31,581	  (43,750)

OIL AND NATURAL GAS:  

REVENUES:
	Revenues:		163,656	124,532	  100,030
	Intersegment revenues		    3,120	      293	      409
			166,776	124,825	  100,439
EXPENSES:
	Operations and maintenance		118,266	76,975	   60,526
	Selling, general and administrative		10,723	10,152	    9,320
	Taxes other than income taxes		4,555	2,931	    2,334
	Depreciation, depletion and amortization		16,922	17,080 	   17,569
	Writedowns of long-lived assets		         	         	   19,194
			  150,466	  107,138	  108,943
	INCOME (LOSS) FROM OIL AND
		NATURAL GAS OPERATIONS		16,310	17,687 	   (8,504)

INDEPENDENT POWER:  

REVENUES:
	Revenues		70,932	75,322 	   79,095 
	Earnings from unconsolidated investments		14,980	21,174 	    2,622 
	Intersegment sales		    1,820	    1,426	      796
			87,732	97,922 	   82,513 
EXPENSES:
	Operations and maintenance		63,837	64,274 	   68,300 
	Selling, general and administrative		4,290	5,223 	    3,557 
	Taxes other than income taxes		1,868	1,783 	    1,831 
	Depreciation and amortization		    2,774	    3,793	    3,176
			   72,769	   75,073	   76,864

	INCOME FROM INDEPENDENT POWER OPERATIONS		$  14,963	$  22,849	$   5,649
</TABLE>

<TABLE>
<CAPTION>
			           NONUTILITY OPERATIONS
			       Year Ended December 31       
			   1997   	   1996   	   1995   
			        Thousands of Dollars
<S>                                                  <C>          <C>          <C>
TELECOMMUNICATIONS:

REVENUES:
	Revenues		$  44,899	$  27,641	$  23,247
	Intersegment revenues		      797	      133	      377
			45,696	27,774 	   23,624 

EXPENSES:
	Operations and maintenance		20,911	18,316	   15,520 
	Selling, general and administrative		7,843	5,498	    4,688 
	Taxes other than income taxes		2,293	392	      343
	Depreciation and amortization	 	    2,455	      911	      803
			   33,502	   25,117	   21,354

	INCOME FROM TELECOMMUNICATIONS OPERATIONS.		12,194	2,657	    2,270

OTHER OPERATIONS:

REVENUES:
	Revenues		2,104	1,201	    2,647 
	Intersegment revenues		    3,924	      782	      699
			6,028	1,983	    3,346 
EXPENSES:
	Operations and maintenance		2,394	1,207	    1,607 
	Selling, general and administrative		7,911	2,137	      849 
	Depreciation and amortization		      532	      679	      942
			   10,837	    4,023	    3,398

	LOSS FROM OTHER OPERATIONS		(4,809)	(2,040)	      (52)

INTEREST EXPENSE AND OTHER INCOME:  
	Interest		6,605	4,829	    4,494
	Other (income) deductions - net		  (31,160)	   (6,764)	  (10,155)
			  (24,555)	   (1,935)	   (5,661)

INCOME (LOSS) BEFORE INCOME TAXES		92,061	74,669	  (38,726)

INCOME TAXES		   26,227	   25,288	  (22,473)

NONUTILITY NET INCOME (LOSS) AVAILABLE FOR
	COMMON STOCK		$  65,834	$  49,381	$ (16,253)
</TABLE>

NONUTILITY OPERATIONS:

Coal Operations:  

1997 Compared to 1996

	Income from coal operations decreased primarily as a result of price 
decreases and increased production costs and legal expenses. Revenues from the 
Rosebud and Jewett mines increased $4,100,000 and $2,500,000, respectively. At 
the Rosebud Mine, volumes of coal sold to Colstrip Units 3 & 4 increased nearly 
37% 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 & 2 due to plant 
maintenance.  Volumes of lignite sold at the Jewett Mine increased 8% 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.

1996 Compared to 1995

	Coal operations for 1995 included charges of approximately $91,000,000 
relating to the closure of the Golden Eagle Mine, the outcome of a coal 
arbitration decision, operating losses at the Golden Eagle Mine prior to 
closure, and the adoption of SFAS No. 121.

	Excluding a non-recurring charge of approximately $20,700,000 recorded in 
1995 as a result of the Colstrip Units 1 & 2 coal arbitration decision, 1996 
revenues, including intersegment revenues, decreased by $58,400,000. Rosebud 
Mine revenues decreased $17,600,000 due to the expiration of a Midwestern 
contract at the end of 1995 and approximately $10,400,000 due primarily to 
decreased short-term coal sales, lower transportation fees and the switching 
of fuel supplier by the Corette Plant for early compliance with air quality 
standards. Rosebud Mine revenues from Colstrip Units 3 & 4 also decreased 
$13,400,000 due to a 22% decline in volumes sold resulting from plant 
curtailments due to the availability of low-cost hydroelectric generation in 
the region. The closure of the Golden Eagle Mine also resulted in a 
$16,400,000 decrease in revenues.

	The closure of the Golden Eagle Mine resulted in a $22,800,000 decrease 
in operation and maintenance, a $4,200,000 decrease in selling, general and 
administrative, a $2,200,000 decrease in taxes other than income taxes and a 
$2,400,000 decrease in depreciation and depletion. Expenses also decreased as 
a result of the loss recorded in 1995 for the closure of the Golden Eagle Mine 
and the adoption of SFAS No. 121. Despite a reduction in 1995 royalty expense 
and production taxes of approximately $7,000,000 resulting from the coal 
arbitration decision, the decrease in volumes sold in 1996 at the Rosebud Mine 
reduced operation and maintenance expenses by $16,500,000, taxes other than 
income taxes by $3,300,000 and depreciation and depletion by $2,300,000. 
Selling, general and administrative expense also decreased $2,600,000 
primarily due to the absence of the outside legal costs incurred in 1995 
related to the coal arbitration proceeding. Taxes other than income taxes for 
the Jewett Mine also decreased $1,000,000 as a result of a refund of Texas 
sales taxes.

	The Golden Eagle Mine, acquired by the Company in 1991, incurred 
significant losses in 1993, 1994 and the first nine months of 1995. With the 
commencement in mid-1994 of deliveries under a long-term contract, losses were 
expected to end.  However, unexpected mining and wash-plant problems caused 
production costs to be higher than expected, and market prices continued to be 
lower than expected. During the course of 1995, management concluded that, in 
view of the outlook for coal prices, production costs could not be reduced 
sufficiently to achieve profitable operations in the foreseeable future. 
Accordingly, the Company terminated the coal sales agreement and ceased 
production at the end of 1995, and wrote down its investment in the mine in 
the fourth quarter of 1995. In 1996, the mine was sealed and most of the 
salvageable plant and equipment was sold. The disposition of these assets was 
charged against the estimated loss provision which was established in 1995. 
See Item 8, "Financial Statements and Supplementary Data - Note 1 to the 
Consolidated Financial Statements" for further discussion of asset impairment.

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:  

			 1997 	 1996  

Oil		-revenue	$  (3)	$   3
		-volume	  (20)%	    2%
		-price/bbl	   10%	   15%

Natural gas and natural
 	gas liquids	-revenue	$  36	$  20
		-volume	    1%	   14%
		-price/Mcf	   35%	   10%

Miscellaneous	-revenue	$   9	$   2	


1997 Compared to 1996

	Oil and natural gas operations experienced a slight decrease in income 
primarily due to decreased oil revenues and increased purchased gas costs. 
Natural gas revenues increased primarily due to higher market prices, primarily 
in the first and fourth quarters of the year and natural gas liquids revenues 
from the Vessels plant acquired in 1997.  Oil production decreased as a result 
of the sale of non-strategic oil properties in accordance with the Company's 
focus on natural gas.  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.

1996 Compared to 1995

	Excluding the 1995 charge of $19,200,000 resulting from the adoption of 
SFAS No. 121, income from oil and natural gas operations improved principally 
as a result of higher prices for both oil and natural gas sold and higher 
volumes of natural gas sold.

	Natural gas revenues for the year increased $11,900,000 due to higher 
market prices and scheduled escalations in the price of gas sold under long-
term co-generation  supply contracts. Natural gas revenues also increased 
$7,400,000, primarily as a result of increased volumes sold in Canada 
resulting from intensified marketing efforts, offset by a five percent 
decrease in gas produced due to natural declining production in Canadian wells 
along with well dispositions. Oil revenues benefited from higher prices in 
both the U.S. and Canada, and increased U.S. production.  Miscellaneous 
revenues increased $1,600,000 primarily as a result of higher volumes and 
higher prices on natural gas processed at the Fort Lupton facility.

	Operating expenses increased primarily due to higher prices paid for 
natural gas in the U.S. and the increase in natural gas volumes purchased for 
resale. The increase was more than offset by a decrease resulting from the 
adoption of SFAS No. 121 recorded in 1995.


Independent Power Operations:  

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.


1996 Compared to 1995

	The 1996 net income from independent power operations increased primarily 
as the result of an $8,700,000 increase in earnings from unconsolidated 
investments due to continued growth in earnings from power investments 
throughout the year. In addition, a gain on the sale of a portion of an 
investment contributed to the increase.   The absence in 1996 of a $1,900,000 
loss on the withdrawal from a power service business in 1995 also contributed 
to the increase.  Partially offsetting the increase was a $2,000,000 decrease 
in long-term power sales revenue resulting from a decrease in volumes sold. 

	Independent power operating and maintenance expenses decreased $4,000,000 
due primarily to a $3,200,000 reduction in power supply costs and a $1,900,000 
decrease in transmission expense.  This decrease was partially offset by a 
$1,300,000 increase in purchase power expense.  Power supply costs decreased as 
a result of the displacement of higher cost thermal generation with lower cost 
hydroelectric generation and the availability of less expensive market energy. 
The decrease in transmission expense was a direct result of the decrease in 
volumes sold under long-term power sales contracts.


Telecommunications Operations:

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 and due to a 31% increase in long-distance minutes sold.

	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.

1996 Compared to 1995

	Earnings from telecommunications operations improved primarily as a 
result of increased long-distance sales and increased equipment sales. 
Long-distance service revenues increased 20% due to a 33% increase in minutes 
sold resulting from increased marketing efforts and expansion into new markets 
in Washington, Idaho and Oregon.  Equipment sales earnings increased as a 
result of completion of projects in these three states as well as Montana.


Other Operations:

1997 Compared to 1996

	Revenue and expense increases in other operations relate primarily to the 
Company's new electric, natural gas and oil marketing company, The Montana 
Power Trading and Marketing Company (MPT&MC).


Other Income and Expense:

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, 
increased earnings from the gold mine and interest income associated with the 
like-kind exchange transaction and the settlement with the IRS.  These 
increases were partially offset by the loss on the sale of non-strategic 
Wyoming coal properties and costs associated with a discontinued SynCoal 
project. 

	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.

1996 Compared to 1995

	The changes in interest expense from 1996 to 1995 were a result of 
increases in the amount of outstanding borrowings and the interest paid 
pursuant to the 1995 coal arbitration decision.

Changes in other income in 1996 and 1995 are primarily the result of a 
non-recurring gain and non-recurring interest income in 1995.


LIQUIDITY AND CAPITAL RESOURCES:  

Operating Activities --

Net cash provided by operating activities was $201,091,000 in 1997 
compared to $219,077,000 in 1996 and $268,890,000 in 1995.  The current year 
decrease of $18,000,000 was due primarily to a decrease in income from 
operations resulting from weather related impacts on the Utility, increased 
power supply costs and decreased revenue from independent power.  This was 
partially offset by increased revenue from the expansion of the fiber optic 
network by the telecommunications operations.

Cash from operating activities less dividends paid provided 58% of net 
cash used for investing activities in 1997, 64% in 1996 and 80% in 1995.

Investing Activities --

	Net cash used for investing activities was $188,808,000 in 1997 compared 
to $194,946,000 in 1996 and $219,740,000 in 1995.  The current year decrease of 
$6,100,000 was due primarily to a cash flow increase of $108,300,000 from the 
sale of non-strategic oil and gas properties in the U.S. and Canada, the sale 
of a Brazilian gold mine investment and a $38,700,000 decrease in cash invested 
into the reclamation fund.  These were mostly offset by an increase in capital 
expenditures of $134,700,000 and an increase in other investments of 
approximately $6,000,000.  Capital expenditures for 1997 were focused on the 
Company's efforts to expand its natural gas operations.  As a result, the 
Company's Nonutility oil and gas operations purchased properties in the Denver 
area and the stock of a small Canadian company for approximately $85,000,000 
and $26,500,000, respectively.  In addition, the Company capitalized 
$57,000,000 for the Kerr Project license and mitigation plan in accordance with 
a 1997 FERC ruling.

	Capital expenditures during the prior three years and forecasted capital 
expenditures for 1998 are as follows:  

		Forecasted		Actual	
	  1998			1997  		1996  		1995  
	Thousands of Dollars
Utility	$	77,000	$ 138,382		$ 107,085		$ 163,238
Nonutility		99,000		 155,390		 51,992		  67,849
	Total	$ 176,000	$ 293,772		$ 159,077		$ 231,087

	Of the Utility capital expenditures for 1997, 1996 and 1995, generation 
accounted for $74,428,000, $19,307,000 and $34,951,000, respectively. 
Generation is expected to account for $8,514,000 of the 1998 forecasted 
Utility expenditures. The majority of the Utility's capital expenditures 
during 1998 are expected to be spent on rehabilitation of steam and 
hydroelectric projects, refurbishing electric and natural gas transmission 
lines, extending and maintaining electric and natural gas distribution lines 
and conservation programs. The majority of the Nonutility's capital 
expenditures during 1998 are expected to be spent on development drilling, 
facilities and production enhancements of natural gas properties along with 
the development of local access phone service and expansion of fiber optic 
network in the telecommunications operations.

	For 1998, the Company estimates that, by business unit, internally 
generated funds will average 87% of its Utility construction program and 64% 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 --

	Dividends paid on common and preferred stock were $91,112,000 in 1997, 
$95,284,000 in 1996, and $93,600,000 in 1995.  During 1997, the regular 
quarterly dividend level of 40 cents per share of outstanding stock or $1.60 
per share on an annual basis was maintained.  The Company's Common Dividend 
Policy states that, over time, dividends should reflect long-term growth in 
corporate earnings and cash flows, as well as a target payout ratio of 70% of 
earnings, provided such dividend levels are sustainable.  The declaration of 
future dividends is at the discretion of the Board of Directors.

	In April 1997, the Company entered into a Revolving Credit Agreement for 
certain of its Nonutility operations.  Including this facility, the Company's 
consolidated borrowing ability under its Revolving Credit and Term Loan 
Agreements (Agreements) is $220,000,000, of which $190,000,000 was unused at 
December 31, 1997.  Under terms of the new agreement, the amount of the 
facility decreases on March 31, 1998, reducing the consolidated borrowing 
ability under the Agreements to $160,000,000.  One agreement terms on 
October 27, 1998 and all outstanding borrowing must be repaid at that time. 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.  See Item 8, "Financial Statements and Supplementary Data - 
Notes 9 and 10 to the Consolidated Financial Statements for further 
information."  

In December 1997, Roan Resources Ltd. (Roan), a wholly owned Canadian 
subsidiary, purchased the stock of a small Canadian company with oil and gas 
properties, for approximately $26,500,000 in U.S. dollars.  Financing for the 
purchase was provided through an Extendible Revolving Term Credit Agreement 
between Roan and the Royal Bank of Canada.  The maximum amount of credit 
available under this Agreement is $37,800,000 in Canadian dollars which was 
reduced to $28,000,000 in Canadian dollars, or $19,627,000 in U.S. dollars, on 
January 8, 1998. At December 31, 1997, the amount outstanding under the 
agreement was $15,715,000 in U.S. dollars.

The Company's long-term debt as a percentage of capitalization was 37%, 
37% and 37% in 1997, 1996 and 1995, respectively.  The Company also has entered 
into long-term lease arrangements and other long-term contracts for sales and 
purchases that are not reflected on its balance sheet.  See Item 8, "Financial 
Statements and Supplementary Data - Note 3 to the Consolidated Financial 
Statements" for additional information.  

In addition, $82,000,000 of long-term debt will mature during the year 
1998.  See Item 8 "Financial Statements and Supplementary Data - Note 9 to the 
Consolidated Financial Statements" for details on maturities of long-term debt.

	The Company's Mortgage and Deed of Trust contains certain restrictions 
upon the issuance of additional First Mortgage Bonds.  The Company anticipates 
that these restrictions would not preclude it from issuing sufficient First 
Mortgage Bonds to meet its bonded debt requirements during 1998, however the 
Company does not expect to issue additional First Mortgage Bonds in 1998. 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.

As discussed in Item 8, "Financial Statements and Supplementary Data - 
Note 4 to the Consolidated Financial Statements", the Company has offered its 
electric generation assets for sale along with its power purchase contracts 
from qualifying facilities and Basin Electric Power Cooperative.  The Company 
is evaluating numerous possible uses for the proceeds realized from the sale 
including reducing outstanding debt, buying back Company common or preferred 
shares of stock or investing in 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.

	A filing requesting authorization to issue up to $65,000,000 in 
transition bonds related to the natural gas transition costs and bond issuance 
costs was made to the PSC in November 1997.  Issuance of similar bonds was 
provided in the electric restructuring legislation, subject to PSC approval. At 
this time, due to the uncertainties related to the electric restructuring 
filing before the PSC and the expected sale of the electric generation assets 
and power purchase contracts, the Company can not determine either the amount 
or the timing of the issuance of transition bonds related to electric 
transition costs.  The Company is evaluating possible uses of proceeds from 
potential natural gas and electric transition bond issuances.


SEC RATIO OF EARNINGS TO FIXED CHARGES:

	For the twelve months ended December 31, 1997, the Company's ratio of 
earnings to fixed charges was 2.94 times.  Fixed charges include interest, the 
implicit interest of Unit 4 rentals and one-third of all other rental payments. 


INFLATION:  

	Capital intensive businesses, such as the Company's electric and natural 
gas utility operations, are significantly and adversely affected by long-term 
inflation as neither depreciation nor the ratemaking process reflect the 
replacement cost of utility plant.  Although prices for natural gas may 
fluctuate, earnings of the gas utility operations are not impacted because a 
gas cost tracking procedure annually balances gas costs collected from 
customers with the costs of supplying gas.  As the Company's utility operations 
transition to a more competitive environment and considering the intended sale 
of the electric generating facilities and power purchase contracts, it is 
anticipated that the Company will be less capital intensive in the future and 
therefore, impacted less by inflation.

	The Nonutility's long-term coal and co-generation natural gas supply 
contracts and long-term power sales contracts provide for the adjustment of 
prices either through indices, fixed escalations and/or direct pass-through of 
costs.  

	The Company believes that the effects of inflation, at currently 
anticipated levels, will not significantly affect results of operations.  


YEAR 2000 COMPLIANCE:

	As the year 2000 approaches, most companies will face a potentially 
serious problem resulting from the possible failure of computer software 
programs and other operational electronic systems to recognize calendar dates 
beyond the year 1999.  This failure could force computers and other electronic 
equipment to shut down or create erroneous results.

The Company is currently addressing this "Year 2000" issue to ensure the 
availability and integrity of its financial systems.  The Company has 
established a project team within its central Information Services Department 
to ensure that all of its information services software and hardware will be 
year 2000 compliant before 2000.  The project team reports on a regular basis 
to the Company's Board of Directors.  At this time, the Company does not 
expect the costs of year 2000 compliance for its information services function 
to have a material impact on its future results of operations.  

The Company is also in the process of identifying the other operational 
systems which have embedded electronic microprocessors that could be affected 
by this issue.  The officers of the various business units have been given the 
responsibility for addressing these operational/process control issues as they 
relate to the year 2000. Although it is not currently possible to estimate the 
overall cost of the 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.

The year 2000 issue may also impact other entities with which the 
Company transacts business or with which the Company's electric and natural 
systems are interconnected.  The Company cannot estimate the potentially 
adverse consequences, if any, which could result from such entities failure to 
adequately address the year 2000 issue.


NEW ACCOUNTING PRONOUNCEMENTS:

	During June 1997, the FASB released SFAS No. 130, "Reporting 
Comprehensive Income".  SFAS No. 130 requires the reporting in the financial 
statements of all items recognized as components of comprehensive income which 
is defined as changes in equity during the period from transactions, events or 
circumstances from non-owner sources.  The statement is effective for fiscal 
years beginning after December 15, 1997.

Also during June 1997, the FASB released SFAS No. 131, "Disclosures 
about Segments of an Enterprise and Related Information".  SFAS No. 131 
requires the disclosure of certain operating information in complete financial 
statements as well as condensed statements for interim periods issued to 
shareholders.  The statement is effective for financial statements for periods 
beginning after December 15, 1997.

The Company is evaluating SFAS No. 130 and SFAS No. 131 at this time to 
determine the effects on the financial statements and related disclosures. 
Although the statements will affect the presentation of the information, they 
are not expected to materially affect the Company's financial position or 
results of operations.


ENVIRONMENTAL ISSUES:

	The Company is committed to do its part to protect, maintain and enhance 
the environment.  The diversity of the Company's business activities 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 Hazardous Materials Transportation 
Act; the Emergency Planning and Community Right to Know Act; the Surface 
Mining Control and Reclamation Act; and the National Environment Policy Act.  

	The Company has established reserves 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.

	Under CERCLA, the Company has been named a potentially responsible 
party (PRP) at the Silver Bow Creek/Butte Area Superfund Site. The PRPs have 
cooperated to identify the extent of groundwater and soil contamination due 
principally to decades of copper mining. The Company has spent $538,000 to 
investigate contamination attributed to its ownership of property. Consultants 
employed by the PRPs have made preliminary estimates indicating that clean-up 
costs could range from $20,000,000 to $60,000,000. While the Company denies 
any responsibility greater than a "diminimis" contributor for costs associated 
with this contamination, if the Company is found to have a greater 
responsibility, it would have to share a portion of the costs ultimately 
related to the handling of the contamination proportionate to its 
contribution.  Other contamination at this site involves petroleum 
hydrocarbons, low level concentrations of polychlorinated biphenyls (PCB's) 
and arsenic. Clean up of this contamination will be accomplished by the 
Company as an issue apart from its involvement with this superfund site at a 
cost which is not expected to be material.

The Thompson Falls Reservoir has been identified by the Montana 
Department of Environmental Quality (MDEQ) as a CECRA site which is the state 
equivalent of a National Priority List site (Superfund).  Elevated levels of 
copper, zinc and possibly arsenic were found in the bottom sediments by 
researchers in 1985-1986.   EPA declared the site a "No Further Action" site 
under CERCLA.  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.  There has been no attempt to quantify the cost to clean up the 
sediments. 

	The Company or its predecessors owned and operated manufactured gas 
plants on three sites, one in each of Helena, Butte and Missoula, Montana. 
Voluntary work to assess and clean up these sites has been undertaken.

	All of the Company's coal-fired units have been designated as 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 had 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 year 1997, 
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. 

	Impacts to groundwater and Armells' Creek have been documented from the 
Colstrip Project's process water disposal system or process water spills. 
Study and mitigation efforts are underway in consultation with the MDEQ to 
address the impacts. Estimated annual expenses to manage this issue are 
estimated to be $50,000.  One-time capital expenditures are estimated to range 
from $100,000 to $4,000,000, depending upon the design ultimately determined 
necessary to remedy the problem. 

	The Company's Canadian subsidiaries are involved in an ongoing cleanup of 
old flare pits, and abandoned wells and production sites. Approximately 50 
sites are under active reclamation. Cleanup of 30 sites has been completed, and 
25 sites are either waiting for final certification from Alberta Environmental, 
or are in the final monitoring of vegetation growth prior to applying for 
cleanup certification.  Since 1995, the Company has spent approximately 
$630,000 (Canadian) for cleanup of the completed sites. Cleanup activity will 
continue for the next five to ten years under the direction of Alberta 
Environmental. Approximately 20 shut-in or abandoned wells do not have any 
appreciable environmental damage, and clean up activity is not expected at 
these sites. 

ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA


	INDEX TO FINANCIAL STATEMENTS
	AND SUPPLEMENTARY DATA

	 Page 

Management's Responsibility for Financial Statements	56

Report of Independent Accountants	57

Consolidated Financial Statements:

	Consolidated Statements of Income for the Years Ended 
		December 31, 1997, 1996 and 1995	58

	Consolidated Balance Sheets as of December 31, 1997 and 1996	59-60

	Consolidated Statements of Cash Flows for the Years Ended 
		December 31, 1997, 1996 and 1995	61

	Consolidated Statements of Common Shareholders' Equity for the 
		Years Ended December 31, 1997, 1996 and 1995	62

	Notes to Consolidated Financial Statements	63-95

Supplementary Data (Unaudited)	96-103

Financial Statement Schedules for the Years Ended December 31, 
	1997, 1996 and 1995:  

	Schedule II - Valuation and Qualifying Accounts and Reserves	109


Financial statement schedules not included in this Form 10-K Annual Report have 
been omitted because they are not applicable or the required information is 
shown in the Consolidated Financial Statements or notes thereto.  


MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS

	The management of The Montana Power Company is responsible for the 
preparation and integrity of the consolidated financial statements of the 
Company.  These financial statements have been prepared in accordance with 
generally accepted accounting principles which are consistently applied, and 
appropriate in the circumstances.  In preparing the financial statements, 
management makes appropriate estimates and judgments based upon available 
information.  Management also prepared the other financial information in the 
annual report and is responsible for its accuracy and consistency with the 
financial statements.  

	Management maintains systems of internal accounting control which are 
adequate to provide reasonable assurance that the financial statements are 
accurate, in all material respects.  The concept of reasonable assurance 
recognizes that there are inherent limitations in all systems of internal 
control in that the costs of such systems should not exceed the benefits to be 
derived.  Management believes the Company's systems provide this appropriate 
balance.  

	The Company maintains an internal audit function that independently 
assesses the effectiveness of the systems and recommends possible improvements. 
Price Waterhouse LLP, the Company's independent accountants, also considered 
the systems in connection with its audit.  Management has considered the 
internal auditors' and Price Waterhouse LLP's recommendations concerning the 
systems and has taken cost-effective actions to respond appropriately to these 
recommendations.  

	The Board of Directors, acting through an Audit Committee composed 
entirely of directors who are not employees of the Company, is responsible for 
determining that management fulfills its responsibilities in the preparation of 
the financial statements.  The Audit Committee recommends, and the Board of 
Directors appoints, the independent 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 Price Waterhouse LLP, which 
is responsible for conducting its examination in accordance with generally 
accepted auditing standards.  






/s/ Robert P. Gannon		/s/ J. P. Pederson	
R. P. Gannon		J. P. Pederson
Chairman of the Board and		Vice President and Chief
	Chief Executive Officer			Financial and Information
			Officer 


	Report of Independent Accountants

February 5, 1998

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, 1997 
and 1996, and the results of their operations and their cash flows for each of 
the three years in the period ended December 31, 1997, 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.  

As discussed in Note 1 to the consolidated financial statements, the Company 
changed its method of accounting for impairments of long-lived assets beginning 
in 1995.  



/s/ PRICE WATERHOUSE LLP
Portland, Oregon


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


					
				       Year Ended December 31       
				   1997   	   1996   	   1995   
				        Thousands of Dollars
<S>                                               <C>           <C>          <C>
REVENUES		$1,023,597	$  973,208	$  953,224

EXPENSES:
	Operations		415,979	381,550	   420,472
	Maintenance		75,994	68,181	    68,286
	Selling, general and administrative		124,244	113,485	   104,213
	Taxes other than income taxes		96,214	87,903	    89,858
	Depreciation, depletion and amortization		94,664	86,403	    84,635
	Writedowns of long-lived assets		          	          	    74,297
					   807,095	   737,522	   841,761

		INCOME FROM OPERATIONS		216,502	235,686	   111,463

INTEREST EXPENSE AND OTHER INCOME:
	Interest		54,667	48,770	    43,656
	Distributions on mandatorily redeemable
		preferred securities of subsidiary
		trust		5,492
	Other (income) deductions - net		   (34,159)	   (4,445)	   (10,704)
					26,000	44,325	    32,952

INCOME TAXES		    61,870	    71,975	    21,574

NET INCOME		128,632	119,386	    56,937
DIVIDENDS ON PREFERRED STOCK		     3,690	     8,358	     7,227

NET INCOME AVAILABLE FOR COMMON STOCK		$  124,942	$  111,028	$   49,710

AVERAGE NUMBER OF COMMON SHARES
	OUTSTANDING (000)		54,649	54,634	    54,121

BASIC EARNINGS PER SHARE OF COMMON STOCK		$     2.29	$     2.03	$     0.92

DILUTED EARNINGS PER SHARE OF COMMON
	STOCK		$     2.28	$     2.03	$     0.92




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

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

		December 31     
		1997   		1996   
	Thousands of Dollars

<S>                                                             < C>          <C>
PLANT AND PROPERTY IN SERVICE:
	Utility plant		$2,216,198	$2,236,309
	Less - accumulated depreciation and depletion			684,960		705,119
						1,531,238	1,531,190

	Nonutility property		781,406	666,679
	Less - accumulated depreciation and depletion			260,567		256,489
							520,839		410,190
						2,052,077	1,941,380
MISCELLANEOUS INVESTMENTS:
	Independent power investments		51,534	53,035
	Reclamation fund		47,312	43,001
	Other			35,619		39,531
						134,465	135,567
CURRENT ASSETS:
	Cash and temporary cash investments		16,706	32,404
	Accounts receivable		126,787	142,347
	Materials and supplies (principally at average cost)		39,471	39,322
	Prepayments and other assets		49,673	49,041
	Deferred income taxes			10,539		11,095
						243,176	274,209

DEFERRED CHARGES:
	Advanced coal royalties		16,698	19,298
	Regulatory assets related to income taxes		122,903	149,150
	Regulatory assets - other		158,573	109,141
	Other deferred charges			73,804		69,470
							371,978		347,059
						$2,801,696	$	2,698,215

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

<TABLE>
<CAPTION>
	LIABILITIES

					       December 31       
					    1997   	    1996    
					   Thousands of Dollars

<S>                                                            <C>          <C>
CAPITALIZATION:
	Common shareholders' equity:
		Common stock (120,000,000 shares without par 
		  value authorized; 54,728,709 and 54,630,994
		  shares issued)		$	694,561	$	691,853
		Retained earnings and other shareholders' equity		342,973	307,804
		Unallocated stock held by trustee for Retirement
		  Savings Plan			(25,945)		(28,360)
					1,011,589	971,297

	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			653,168		633,339
						1,787,411	1,727,290

CURRENT LIABILITIES:
	Short-term borrowings		133,958	104,702
	Long-term debt-portion due within one year		81,659	69,268
	Dividends payable		22,684	22,707
	Income taxes		3,803	11,083
	Other taxes		47,818	41,667
	Accounts payable		77,821	62,218
	Interest accrued		13,836	11,909
	Other current liabilities			35,158		41,155
						416,737	364,709

DEFERRED CREDITS:
	Deferred income taxes		340,251	332,861
	Investment tax credits		35,182	44,467
	Accrued mining reclamation costs		131,108	129,878
	Other deferred credits			91,007		99,010
							597,548		606,216

CONTINGENCIES AND COMMITMENTS (Notes 2 and 3)
					$2,801,696	$2,698,215

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


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

					       Year Ended December 31       
		   1997   	   1996   	   1995   
	Thousands of Dollars
<S>                                                 <C>           <C>         <C>
NET CASH FLOWS FROM OPERATING ACTIVITIES:
	Net income		$	128,632	$	119,386	$	56,937
	Adjustments to reconcile net income to net 
		cash provided by operating activities:
		Depreciation, depletion and amortization		94,664	88,744	86,976
		Writedowns of long-lived assets				74,297
		Deferred income taxes		10,677	15,430	(11,819)
		Noncash earnings from unconsolidated
			independent power investments		(14,016)	(11,505)	(2,314)
		Reclamation expenses and payments - net		1,230	7,870	7,411
		Deferred stripping expenses and
			payments - net		(696)	(787)	1,239
		Losses (gains) on sales of property and 
			investments		(33,849)	2,532	(1,736)
		Other - net		24,145	15,240	10,866
		Changes in current assets and liabilities:
			Accounts receivable		15,560	10,039	7,589
			Materials and supplies		(149)	2,872	5,743
			Accounts payable		15,603	(1,702)	13,132
			Other assets and liabilities			(40,710)		(29,042)		20,569
		Net cash provided by operating activities			201,091		219,077		268,890

NET CASH FLOWS FROM INVESTING ACTIVITIES:
	Capital expenditures		(293,772)	(159,077)	(231,087)
	Reclamation funding		(4,311)	(43,001)	
	Sales of property and investments		117,663	9,387	13,987
	Additional investments			(8,388)		(2,255)		(2,640)
		Net cash used for investing activities			(188,808)		(194,946)		(219,740)

NET CASH FLOWS FROM FINANCING ACTIVITIES:
	Dividends paid		(91,112)	(95,284)	(93,600)
	Sales of common stock		2,201	798	23,465
	Redemption of preferred stock			(44,415)
	Issuance of long-term debt		103,375	82,890	50,758
	Retirement of long-term debt		(71,634)	(22,236)	(18,155)
	Issuance of mandatorily redeemable preferred
		securities		(67)	62,625	
	Net change in short-term borrowing			29,256		8,354		(17,641)
		Net cash used for financing activities			(27,981)		(7,268)		(55,173)

CHANGE IN CASH FLOWS		(15,698)	16,863	(6,023)

CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR			32,404		15,541		21,564

CASH AND CASH EQUIVALENTS, END OF YEAR		$	16,706	$	32,404	$	15,541

SUPPLEMENTAL DISCLOSURES OF CASH FLOW: 
	Cash paid during the year for:
		Income taxes, net of refunds		$	50,797	$	52,470	$	33,087
		Interest		59,681	49,962	46,141

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

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

		
		
	
	        Year Ended December 31        
	   1997   	   1996   	   1995   
	Thousands of Dollars
<S>                                                  <C>          <C>          <C>
COMMON STOCK:
	Balance at beginning of year		$ 691,853	$ 691,043	$ 667,344
	Issuances (97,715; 16,513; 
	  and 1,034,744 shares)		    2,708	      810	   23,699

	Balance at end of year		  694,561	  691,853	  691,043

RETAINED EARNINGS AND OTHER SHAREHOLDERS' 
	EQUITY:

	Balance at beginning of year		307,804	285,000	  320,756
	Net income		128,632	119,386	   56,937
	Dividends on common stock ($1.60
		 per share each year)		(87,494)	(87,432)	  (86,791)
	Dividends on preferred stock		(3,690)	(7,705)	   (7,227)
	Other		   (2,279)	   (1,445)	    1,325

	Balance at end of year		  342,973	  307,804	  285,000

UNALLOCATED STOCK HELD BY TRUSTEE FOR
	RETIREMENT SAVINGS:

	Balance at beginning of year		(28,360)	(30,565)	  (32,580)
	Distributions		    2,415	    2,205	    2,015

	Balance at end of year		  (25,945)	  (28,360)	  (30,565)

TOTAL COMMON SHAREHOLDERS' EQUITY AT 
	END OF YEAR		$1,011,589	$ 971,297	$ 945,478


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


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 - Summary of significant accounting policies:  

Basis of accounting:

	The Company's accounting policies conform to generally accepted 
accounting principles.  With respect to utility operations, such policies are 
in accordance with the accounting requirements and ratemaking practices of the 
regulatory authorities having jurisdiction.  

Use of estimates:

	Preparing financial statements requires the use of estimates. Management 
makes appropriate estimates and judgments based upon available information. 
Actual results may differ from accounting estimates as new events occur or 
additional information is obtained.

Consolidation principles:

	The Consolidated Financial Statements include the accounts of the Company 
and its subsidiaries, all of which are wholly-owned.  Significant intercompany 
balances and transactions have been eliminated. Independent power investments 
are accounted for using either the cost or equity method depending on the 
Company's ability to exercise control over the operations of the particular 
investment.

Plant, property, depreciation and amortization:  

	The cost of additions to and replacement of plant, including an allowance 
for funds used during construction of utility plant (AFUDC), 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 8.0% for 1997, 7.2% for 1996 and 8.1% for 1995. Costs of utility 
depreciable units of property retired plus costs of removal less salvage are 
charged to accumulated depreciation. 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.

	The year-end balances of the major classifications of property, plant and 
equipment are detailed in the following table:

			      December 31       
			   1997   	   1996   
			Thousands of Dollars
	Utility plant:
	Electric:
		Generation (including 
		  jointly-owned)		$  718,504	$  704,057
		Transmission		364,638	352,993
		Distribution		520,213	487,937
		Other		216,925	175,728
	Natural Gas:
		Production and storage		70,337	193,432
		Transmission		148,295	146,072
		Distribution		138,676	128,877
		Other		    38,610	    47,213
			Total Utility		2,216,198	2,236,309
	Nonutility plant:
	Coal		241,835	255,788
	Oil and natural gas		363,193	274,880
	Technology		86,617	48,069
	Electric generation		75,585	75,298
	Other		    14,176	    12,644
			Total Nonutility		   781,406	   666,679
			Total Plant		$2,997,604	$2,902,988

	Included in the plant classifications are Utility plant under 
construction in the amounts of $39,425,000 and $52,125,000 for 1997 and 1996, 
respectively and Nonutility plant under construction in the amounts of 
$17,259,000 and $39,252,000 for 1997 and 1996, respectively.

	The Company's open-access and reorganization plan for the natural gas 
utility was approved for implementation, effective November 1, 1997.  Under 
the approved plan, almost all of the natural gas production assets of the 
Utility, including those of its subsidiary, Canadian Montana Gas, were 
transferred to an unregulated affiliate as of that date. For further 
information, see "Financial Statements and Supplementary Data - Note 4 to the 
Consolidated Financial Statements". 

	Provisions for depreciation and depletion are recorded at amounts 
substantially equivalent to calculations made on straight-line and 
unit-of-production methods by application of various rates based on useful 
lives of properties determined from engineering studies.  The provisions for 
Utility depreciation and depletion approximated 3.0% for 1997, 2.9% for 1996 
and 2.7% for 1995 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, 1997, 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		$	184,943	$	286,122	$	45,229
Plant under construction		507	66	7
Accumulated depreciation		96,206	106,290	13,076

	*This is an approximate ownership percentage based on capacity rights 
on the various segments of the transmission system. 

	The Company also owns $42,251,000 and $33,341,000 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. This plant had related accumulated depreciation of 
$16,727,000 and $7,748,000, 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 1996 coal arbitration decision, the Company established 
a reclamation fund, representing restricted cash equal to a portion of its 
accumulated reclamation liability plus interest.  The fund increases as 
reclamation expenses are collected from customers and all proceeds are invested 
until reclamation is performed.  At December 31, 1997, 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. 
Establishment of the reclamation fund had no effect on the Company's 
accumulated liability.  

Utility 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 and natural gas services delivered to customers but not 
yet billed at month-end.  

Regulatory assets and liabilities:

	For its regulated operations, the Company follows SFAS No. 71, 
"Accounting for the Effects of Certain Types of Regulation."  Pursuant to this 
pronouncement, certain expenses and credits, normally reflected in income as 
incurred, are recognized when included in rates and recovered from or refunded 
to the customers.  As such, the Company has recorded the following regulatory 
assets and liabilities that will be recognized in expenses and revenues in 
future periods when the matching revenues are collected.  

	         1997          	         1996          
	 Assets  	Liabilities	 Assets  	Liabilities
	Thousands of Dollars

	Income taxes		$ 119,643			$ 146,736		
	Colstrip Unit 3 
	  carrying charge			42,156			43,987	
	Conservation programs		33,965		41,372	
	Competitive transition
	  charges		58,983			
	Investment tax credits			$  35,182		$  44,467
	Other		   42,344	    8,743		49,174	   12,206
	    Subtotal		297,091	43,925	281,269	56,673
	Less: 
	  Current portions			15,615		2,522		22,978		3,194
	    Total			$ 281,476		$  41,403	$	258,291	$	53,479

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 competitive transition 
charges, 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 has not yet been 
determined. Recovery of Company's existing regulatory assets related to the 
natural gas production assets was provided in the order and recovery of 
existing regulatory assets related to electric generation is provided in the 
electric restructuring legislation. 

Cash and cash equivalents:

	The Company considers all liquid investments with original maturities of 
three months or less to be cash equivalents.

Storm damage and environmental remediation costs:

	The estimated costs of storm damage and environmental remediation 
obligations for Utility operations are charged against established, regulator 
approved operating reserves when such losses are probable and reasonably 
estimable.  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, 1997 and 1996 were approximately $2,600,000 
and $3,600,000, 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.

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 Statement of Financial Accounting Standards 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.

Change in accounting method:

	At December 31, 1996, the Company, through one of its Nonutility 
subsidiaries, changed its ownership interest in one of its independent power 
investments which had been accounted for on the cost basis method of 
accounting.  As a result of this change, the Company may now exercise 
significant influence over the operations of the investment and therefore has 
elected to change to the equity basis method of accounting for the investment 
at December 31, 1996.  The accounting change did not effect previously reported 
net income or earnings per share.  

Asset impairment:

	Effective October 1, 1995, the Company adopted Statement of Financial 
Accounting Standards No. 121, "Accounting for the Impairment of Long-Lived 
Assets and for Long-Lived Assets to Be Disposed Of" (SFAS No. 121).  Under 
SFAS No. 121, a test is required to determine whether the carrying amount of 
long-lived and certain intangible assets may be recoverable through future 
undiscounted cash flows.  In 1995, the Company recorded a before tax charge 
against income of $74,300,000.  The impairment included a $46,500,000 before 
tax charge to record the writedown of the assets and to recognize the closure 
liabilities of the Company's subsidiary, Basin Resources, Inc. The Company 
performs quarterly reviews for SFAS No. 121 impairments. The Company has had 
no other significant writedowns under SFAS No. 121.

Derivative financial instruments:

The Company has a formal policy regarding the execution, recording, and 
reporting of derivative instruments.  The purpose of the policy is to manage a 
portion of the price risk associated with its Nonutility producing assets and 
firm-supply commitments.  The Company uses derivatives as hedging instruments 
to achieve revenue targets, reduce earnings volatility, and provide stable 
cash flow. When fluctuations in natural gas and crude oil market prices result 
in the Company realizing gains on the price swap agreements into which it has 
entered, the Company is exposed to credit risk relating to the nonperformance 
by counterparties of their obligation 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, collar, 
and cap agreements to hedge revenue from anticipated production of crude oil 
and natural gas reserves and supply costs 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. 
Under collar agreements, the Company makes or receives monthly payments at the 
settlement date when the actual price of oil or natural gas exceeds the 
ceiling or drops below the floor established in the agreement. Under cap 
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 cap established in the agreement depending on whether the Company 
sells or buys a cap.  At December 31, 1997, the Company had no hedge 
agreements on crude oil. The Company had cap and swap agreements on 
approximately 1.7 Bcf of Nonutility natural gas; or 14% of its expected 
production from proved, developed and producing Nonutility natural gas 
reserves through November 1998.  In addition, the Company had swap and collar 
agreements to hedge approximately 1.8 Bcf of Nonutility natural gas, or 19% of 
its expected delivery obligations under long-term natural gas sales contracts 
through September 1998.  

The Company accounts for derivative transactions through hedge 
accounting.  The Company designates all 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 an 
anticipated commitment.
? The hedged item is a single asset or a portfolio of similar assets.
? The hedged item presents an exposure to changes in fair value for the 
hedged risk that could affect earnings.
? The hedged item is not an asset or liability that is measured at fair value 
with changes in fair value attributable to the hedged risk reported 
currently in earnings.

Gains or losses from these price swap agreements are reflected in 
operating revenues on the Consolidated Statement of Income at the time of 
settlement with the other parties.  The Company uses the accrual method to 
record its gains or losses. If the Company terminates a price swap agreement 
prior to the date of the anticipated natural gas or crude oil production, the 
gain or loss from the agreement is deferred in the Consolidated Balance Sheet 
at the termination date.  When the anticipated natural gas or crude oil 
production occurs, the gain or loss from the price swap agreement is 
recognized in the Consolidated Statement of Income.  If the Company determines 
that a portion of its anticipated natural gas or crude oil production will not 
occur, thus creating a matching problem between the price swap agreements and 
the anticipated production, any such unmatched price swap agreements are 
marked-to-market and any unrealized gain or loss is recorded in the 
Consolidated Statement of Income. At December 31, 1997, 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 foreign currency and natural 
gas price fluctuations. At December 31, 1997, the Company believes it would not 
experience any materially adverse impacts from the risks inherent in these 
instruments.

Fair value of financial instruments:

			        1997      	       1996	
			Carrying	Fair 	Carrying	Fair 
			 Amount 	Value	Amount 	Value
			Thousands of Dollars

Assets:  
	Investments in independent
		power projects (cost basis 
		 only)		$	5,584	$	9,063	$	6,090	$	10,300
	Reclamation fund		47,312	47,312	43,001	43,001
	Other significant investments		34,704	34,704	35,449	39,837

Liabilities:
	Mandatorily redeemable preferred
		securities		$	65,000	$	70,850	$	65,000	$	67,600
	Long-term debt(including due 
		within one year)			734,827		743,713	702,607	717,504

	The following methods and assumptions were used to estimate fair value:  

	Investments in independent power projects - The fair value represents the 
Company's assessment of the present value of net future cash flows embodied in 
these investments, discounted to reflect current market rates of return.

	Reclamation fund and other investments - The carrying value of most of 
the investments approximates fair value as the investments have short 
maturities or the carrying value equals their cash surrender value.  Fair value 
for the remainder of the investments was estimated based on the discounted 
value of the future cash flows expected to be received using a rate of return 
expected on similar current investments.  

	Mandatorily redeemable preferred securities and long-term debt - The fair 
value was estimated using quoted market rates for the same or similar 
instruments. Where quotes were not available, fair value was estimated by 
discounting expected future cash flows using year-end incremental borrowing 
rates.


NOTE 2 - Contingencies:  

In July 1985, the Federal Energy Regulatory Commission (FERC) issued to 
the Company a new license for the 180 megawatt Kerr Project (Project) and 
required the subsequent adoption of conditions to mitigate the impact of 
Project operations on fish, wildlife, and habitat.  The Company proposed a 
consensus plan in June 1990 that was agreed to by the Confederated Salish and 
Kootenai Tribes (Tribes) and other state and federal resource agencies.  In 
November 1995, the United States Department of Interior (Department) submitted 
alternative conditions to those stated in the Company's plan.

	On June 25, 1997, FERC approved a mitigation plan, substantially adopting 
the Department's conditions. The mitigation plan calls for payments totaling 
approximately $135,000,000 over the 35-year term of the license. The net 
present value of the total amount, using an assumed discount rate of 9.5%, is 
approximately $57,000,000, which the Company recognized as license costs in 
plant and long-term debt in the Consolidated Balance Sheet during the second 
quarter of 1997.

			The Company, the Tribes and the Department requested rehearing of FERC's 
June 25, 1997 order. The Company asserted that the Department's conditions are 
unreasonable and that FERC should modify them. In the event FERC does not 
modify the mitigation plan it ordered, the Company expects to seek judicial 
review.

		In November 1992, the Company applied to FERC to relicense nine Madison 
and Missouri River hydroelectric projects, with generating capacity of 292 
megawatts. On September 26, 1997, FERC Staff issued its draft environmental 
impact statement, recommending acceptance of most of the measures proposed by 
the Company in its application. FERC Staff recommended adoption of limited 
additional measures.  The Company is analyzing the recommendations to prepare 
comments. Preliminary analysis suggests that the FERC Staff's recommendations 
do not materially change the cost of relicensing and proposed environmental 
mitigation, previously estimated to be approximately $158,000,000 on a net 
present value basis.  The Company expects to receive a license order in late 
1998 or early 1999.  	

	Western Energy Company (Western), a subsidiary of the Company, is a 
party in a dispute concerning the Coal Supply Agreement for Colstrip Units 3 
and 4 with the non-operating owners (NOOs), other than Puget Sound Energy 
(Puget).  Puget withdrew from this dispute as part of a settlement concerning 
a power sales agreement between Puget and the Company. During the spring of 
1996, the Consumer Price Index (CPI) doubled when compared to the CPI level at 
the time that the Coal Supply Agreement was executed.  Under the terms of the 
Coal Supply Agreement, this change in the CPI allows any party to seek a 
modification of the coal price if that party can demonstrate an "unusual 
condition" causing a "gross inequity."  These NOOs are asserting that a number 
of "unusual conditions" have occurred, including (i) the deregulation of 
various aspects of the electric utility industry, (ii) increased scrutiny of 
electric utilities by their public utility commissions, and (iii) changes in 
economic conditions not anticipated at the time of execution of the Coal 
Supply Agreement.  These NOOs claim these "unusual conditions" have created a 
"gross inequity" that must be remedied by a reduction in the coal price. 
Western does not believe that under the terms of the contract any "unusual 
condition" or "gross inequity" has occurred.

Western, the Company and these NOOs are seeking to resolve this dispute 
as part of an on-going mediation to restructure the relationship of the NOOs, 
including Puget, the Company and Western at the Colstrip Project. The outcome 
of this dispute or the restructuring mediation is uncertain. 

Houston Lighting & Power (HL&P), the purchaser of lignite produced by 
Northwestern Resources Co. (Northwestern), a Company subsidiary, filed 
litigation on October 5, 1995 in the District Court of the 157th Judicial 
District, Harris County, Texas, seeking, among other remedies, a declaratory 
judgment that changed conditions required a renegotiation of management and 
dedication fees paid to Northwestern under 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. Under the terms of the LSA, Northwestern realizes approximately 
$25,000,000 per year from these fees.  HL&P alleged Northwestern failed to 
renegotiate these fees in good faith. HL&P sought a reduction exceeding 60% in 
the LSA fees. It alleged that the reduction should be retroactive to 
September 1, 1995. Additionally, HL&P sought a declaration that it may 
substitute other fuels for lignite without violating the LSA.  

Trial concluded in December 1997 with the jury denying all of HL&P's 
claims regarding changed circumstances and Northwestern's alleged obligations 
to negotiate reduced fees. Thus, current pricing under the terms of the LSA is 
unchanged. In a pretrial summary judgment, the trial court concluded other 
fuel may be substituted for lignite at the Limestone Plant. The court has not 
entered judgment and the time for filing appeals has not begun to run. 
Northwestern believes it will maintain a price for lignite that is competitive 
with alternate fuels.

	The Company and its subsidiaries are party to various other legal 
claims, actions and complaints arising in the ordinary course of business. 
Management does not expect disposition of these matters to have a material 
adverse effect on the Company's consolidated financial position or its 
consolidated results of operations.

NOTE 3 - Commitments:

Purchase commitments:

In 1994, the Company entered into a contract to purchase 98 megawatts of 
seasonal capacity from Basin Electric Power Cooperative (Basin).  The rate for 
the contract year beginning in November 1997 will be approximately 3.2 cents 
per kWh and will increase each subsequent year to approximately 6.9 cents per 
kWh in the final contract year, which begins in November 2009.  In conjunction 
with the Company's proposed sale of electric generating facilities, the 
Company also intends to sell or reassign this contract. Although not 
specifically named in the restructuring legislation, costs associated with 
disposal and reassignment of this contract are also expected to be collected 
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 2000 through 2031.  Three 
contracts account for 96% of the 101 MWs of capacity provided by these 
facilities. These QF contracts are also intended to be sold or reassigned in 
conjunction with the Company's proposed sale of electric generating 
facilities. 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 purchased gas contracts provide for take-or-pay payments.  The 
Nonutility oil and natural gas operations have various take-or-pay contracts 
with terms that expire beginning in 1998 and natural gas transportation 
contracts which begin expiring in 2000.  

	Total payments under all of these contracts for the prior three years 
were as follows:

	            Thousands of Dollars	
	       Utility	      	Nonutility	 Total  
		Electric		Natural Gas		

	1995		$	21,830	$	9,873	$	2,980	$	34,683
	1996			30,751		8,100		3,283		42,134
	1997			44,153		7,554		3,532		55,239


	The present value of future minimum payments, at an assumed discount rate 
of 8%, under the above agreements are estimated as follows:  

	            Thousands of Dollars	
	       Utility      		Nonutility	 Total  
		Electric		Natural Gas		

	1998		$	13,935	$	2,590	$	2,826	$	19,351
	1999			13,550		2,206		5,268		21,024
	2000			13,207		1,879		4,845		19,931
	2001			12,864		1,376		2,791		17,031
	2002		12,593	1,172	1,899	15,664
	Remainder			134,894		318		10,370		145,582
		$	201,043	$	9,541	$	27,999	$	238,583

	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, 1997, the remaining payments under this agreement were $7,331,000. 
Under current mine plans, these payments should be recovered through lignite 
sales.  

FTV Communications LLC, a limited liability company owned equally by 
Touch America (a subsidiary of the Company), Williams Communications Group, 
Inc. (a subsidiary of Williams Companies) and FirstPoint Communications, Inc. 
(a subsidiary of Enron) will construct, operate and maintain a 1,620 mile 
fiber-optic cable network linking Portland, Oregon and Los Angeles, 
California.  The project, which is scheduled to be completed in December 1998, 
is expected to cost in excess of $100,000,000.  The Company's investment in 
the project is expected to be funded through existing credit facilities, 
internally generated funds and the sale of fiber to other firms. 

In January 1998, a Nonutility subsidiary of the Company entered into a 
firm natural gas transportation agreement which begins March 1,1998 and expires 
October 31, 2001.  The agreement requires the Company to pay an annual fixed 
charge of $982,000 for capacity, plus a commodity fee for transported volumes.

Sales commitments:

	The Nonutility oil and natural gas operations have agreed to supply 
approximately 107 Bcf of natural gas to four co-generation facilities.  These 
contracts begin expiring in 2005.  Oil operations 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 Montana Power Group (MPG), an energy supply and management alliance, 
was exclusively endorsed by the California Manufacturers Association (CMA) to 
assist its members with their energy decisions. As a participant in the MPG, 
MPT&MC a Nonutility subsidiary of the Company has agreed to offer energy 
supply, discounted from the power exchange prices, and energy management 
products and services to members of the CMA.  The supply program is offered on 
a limited basis and is capped at predetermined volumes.  Once the caps are 
fully subscribed, the Company will have, at its sole discretion, the option to 
extend the offered supply and services to other CMA members.  At December 31, 
1997, one contract had been signed by the Company for electric supply  for the 
next two years. At this time, the Company cannot predict the impact of the CMA 
agreement on future earnings, however, due to the limits provided in the 
agreement, any potential negative impacts are not expected to have a material 
impact on the Company's financial position or results of operations.

The Company is also participating in a pilot program which allows 
participants to supply one-third of the particular customer's electric needs. 
At December 31, 1997, one contract had been signed by the Company under this 
program for  electric supply for the next two years. 

Lease commitments:

	On December 30, 1985, the Company sold its 30% share of Colstrip Unit 4 
and is leasing back this share under a net lease.  The transaction has been 
accounted for as an operating lease with 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 are intended to be sold with the regulated electric generating 
facilities and power purchase contracts. 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 
$56,613,000, $55,500,000 and $55,958,000 for 1997, 1996 and 1995, respectively.


Note 4 - Deregulation and asset divestiture:

Natural Gas

The electric and natural gas utility businesses are in transition to 
competition to provide energy commodity and related services to wholesale and 
retail customers. In Montana, the "Natural Gas Restructuring and Customer 
Choice Act" was passed by the Montana Legislature and signed into law in May 
1997. This legislation allowed for natural gas utilities to open their systems 
to full customer choice for gas supply and authorized the issuance of 
transition bonds to lower transition costs. In response to the Company's July 
1996 open-access and natural gas restructuring filing, in October 1997, the PSC 
approved an order giving the Company's natural gas customers the right to 
choose their own suppliers based upon stipulation agreements agreed-to by the 
Company and many of the contesting parties to the filing. Natural gas 
transmission, distribution and storage will remain regulated by the PSC. The 
decision allows 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 230 customers represent an additional 5% 
of the Company's pre-transportation load that may choose their own supplier. 
Natural gas customers who use 60,000 or more dekatherms of natural gas 
annually, which included 23 industrial customers who represented 49% of the 
Company's pre-transportation load, have had choice since 1991. The Company's 
remaining 140,000 customers will have choice no later than July 1, 2002. A 
pilot program allowing approximately 3,500 residential and small commercial 
customers to choose their own supplier, beginning with the 1998-99 heating 
season, will also be implemented.

Under the approved plan, almost all of the Utility natural gas 
production assets were transferred to an unregulated affiliate at an amount 
agreed-to in the natural gas order 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 CTC and will be recovered from 
transmission and distribution customers in rates over a 15-year period. The 
transition plan also includes a supply contract between the unregulated gas 
supply division and the regulated distribution division through 2002.  This 
contract includes fixed prices and declining volumes for expected reductions 
in regulated loads that will occur as customers choose unregulated suppliers.

A filing requesting authorization to issue up to $65,000,000 in 
transition bonds related to the natural gas transition costs and bond issuance 
costs was made to the PSC in November 1997.  The issuance of transition bonds, 
often referred to as securitization, involves the issuance of a debt instrument 
which is repaid through future revenues of the Utility.  The legislation 
authorizing the financing earmarks these future revenues to bond repayment, 
thereby reducing the credit risk of the securities.  As such, the bonds carry a 
relatively low interest rate and allow the Company to carry higher debt levels 
in relation to equity than would otherwise be desirable.  This higher leverage 
results in a lower cost of capital. The issuance of these bonds is expected to 
result in annual savings of approximately $1,900,000.

On January 5, 1998, Enron requested court review of the PSC's decision 
regarding the measure of stranded costs as well as the level of functional 
separation of the various segments of the Company's natural gas business. This 
appeal is pending before the First Judicial District Court, Lewis and Clark 
County. Enron alleges the PSC erred when it concluded the assets subject to 
the CTC are stranded and that their value is $60,000,000.

	The Company requested, and expects the district court to provide, 
expedited review and decision making regarding this matter. The Company does 
not expect the PSC to act upon the Company's application for authority to 
issue transition bonds while this appeal is pending at the district court. The 
CTC rates assume the cost of capital associated with the transition bond 
financing, therefore, the Company is currently not collecting from customers 
its full cost of capital associated with these stranded costs.

Electric

Montana's "Electric Industry Restructuring and Customer Choice Act", was 
also passed by the Montana Legislature and signed into law by the Governor in 
May 1997.

This legislation provides 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 for all customers no later 
than July 1, 2002. Transmission and distribution services will remain fully 
regulated by FERC and the PSC. Generation assets will be removed from rate 
base no later than July 1, 1998 and costs will be recoverable in utility 
operations through a cost-based contract between the Company's regulated 
operations and its unregulated Supply Division through July 1, 2002 for those 
customers that do not have choice or have not selected a competitive based 
supplier. The Company's Supply Division will compete for customers that have 
choice during and after the transition period is complete. The legislation 
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 in the natural gas legislation, the issuance of 
transition bonds was approved to lower transition costs.  During the 
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 9.5% 
return on equity, the utility's obligation to flow investment tax credit 
benefits to ratepayers in future years is reduced.  Any such reduction in the 
utility's regulatory obligation provides an economic benefit to the Company 
and increases income in that year.

The legislation provides for the recovery of 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 authorizes the use 
of transition bonds, subject to the approval of a financing order by the PSC, 
as a method of financing transition obligations at lower costs. The 
legislation also defines the role the PSC will have in regulating distribution 
services, licensing electricity suppliers in the state, and promulgating rules 
regarding anti-competitive and abusive practices. Finally, the legislation 
provides for reciprocity between utility companies.	

As required by the legislation, the Company filed a comprehensive 
transition plan with the PSC on July 1, 1997. The filing contains the 
Company's transition plan, including the proposed handling and resolution of 
transition costs, and addresses other issues required by the legislation. The 
Company expects the PSC to render a decision before July 1998, subject to the 
above-mentioned legislative guidelines, on the amount of transition costs that 
will be recoverable. The PSC will consider the Company's efforts to mitigate 
transition costs in making its determination.

In a related strategic decision, the Company announced, in December 1997, 
that it will offer for sale all of its electric generating facilities in 
Montana, consisting of 1,217 megawatts of capacity from 13 hydroelectric 
projects and its interests in four coal-fired thermal generating units.  In 
addition, the Company will offer for sale its 222 megawatt leasehold interest 
in Colstrip Unit 4, its power purchase contracts with qualifying facilities and 
Basin Electric Power Cooperative (Basin), and two power exchange agreements.

The total book value of the electric generating facilities owned by the 
Company to be offered is approximately $550,000,000 including approximately 
$10,000,000 of fuel, materials and supplies. The leasehold interest is 
accounted for as an operating lease with annual lease payments of approximately 
$32,000,000 over the remaining term of the lease.

If the Company continued to own the generating facilities, the above-
market generation costs on these facilities for the four-year transition 
period is estimated by the Company to be approximately $160,000,000.  The 
qualifying facility contracts, which the Company was required to enter by the 
Public Utility Regulatory Policy Act of 1978, involve approximately 101 
megawatts of purchased power extending through 2031 and could result in 
$300,000,000 to $500,000,000 in out-of-market costs throughout their duration. 
In testimony from intervenors in the electric restructuring case, the amount 
of out-of-market costs on both the generating assets and the QF, Basin and 
exchange contracts have been disputed.  Disposal of the generation assets and 
the contracts is expected to resolve the disputes. The total amount of 
transition costs will not be determined until the sale process is complete, 
which is expected to occur after the time of the PSC decision on the 
restructuring filing.

Divestiture of these 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.

In the process of selling these generating facilities and power purchase 
contracts, any gains above the Company's book value will be utilized to reduce 
the electric CTC amounts to be collected from ratepayers.  Conversely, any 
losses or additional costs to the Company would increase the CTC amounts to be 
collected over the approved transition period.  Although not specifically 
named in the legislation, costs associated with disposal and reassignment of 
the Basin contract are also expected to be collected through the CTC. Any gain 
or loss realized from the disposition of the unregulated leasehold interest, 
and its related assets and liabilities, will be reflected in the Consolidated 
Statement of Income and will not be passed on to ratepayers.

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 exceed $50,000,000 and will 
reduce the proceeds realized from the sale.  There may also be income taxes 
associated with the transactions.

	Regardless of the timing of the sale of the generating assets and power 
purchase 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 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 Company is evaluating options to meet these needs including market 
purchases or a power supply contract with the purchasers of the generating 
facilities.

The sale process is expected to begin in 1998 with offering memorandums 
being sent to 30 to 50 expected potential buyers.  In April, the Company 
expects to receive non-binding preliminary bids from potential buyers.  The 
top bidders, expected to number less than ten, will be short-listed for 
further negotiations and binding bids.  The winning bidder is expected to be 
selected in mid-summer and financial closing will occur as soon as all 
required legal and regulatory approvals are complete, possibly three months to 
two years after July 1998.  It is the intention of the Company to proceed with 
the sale process as tentatively scheduled, however, this divestiture is not a 
requirement of the restructuring bill as is the case in other states with 
deregulation legislation and the Company may at any time cease to continue 
this option should it appear to not meet its expected benefits to ratepayers 
and shareholders. 

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.

As discussed in Note 1 to the financial statements, the Colstrip 
generating facilities are jointly owned by the Company and others.  The sale 
process of any of the particular plants may also be affected by rights of 
first refusal of any of the partners.  The Company, through one of its wholly 
owned subsidiaries, supplies fuel to the Colstrip facilities.  The sale of 
these facilities is not expected to impact the fuel supply contracts. However, 
the Company and the other owners are currently engaged in discussions intended 
to result in a broad-based restructuring of the contractual arrangements 
between the owners of all of the Colstrip plants and the Company's subsidiary 
as fuel supplier.  It is unknown at this time what impact the potential sale 
may have on these discussions.

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 any 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. 

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

	Income before income taxes was as follows:

	   1997   	   1996   	   1995   
	Thousands of Dollars
<S>                                      <C>          <C>         <C>
United States		$  177,114	$  181,393	$   75,458	
Canada		12,780	7,706	      111	
Other countries		       608	     2,262	     2,942	
	$  190,502	$  191,361	$   78,511	


	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:  

	   1997   	   1996  	   1995  
	Thousands of Dollars

Computed "expected" income tax expense		$  66,675	$  66,976	$  27,479	
Adjustments for tax effects of:
	Statutory depletion		(2,891)	(2,317)	   (6,508)	
	Tax credits		(11,645)	(5,286)	   (5,331)	
	State income tax, net		7,147	5,772	    3,327	
	Reversal of utility book/tax 
	  depreciation		5,636	4,054	    2,552	
	Other		   (3,052)	    2,776	       55	
Actual income tax expense		$  61,870	$  71,975	$  21,574	

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

			   1997   	   1996   	   1995   
	Thousands of Dollars

Current:
	United States		$  36,680	$  44,304	$  25,119	
	Canada		994	3,309	    1,510	 
	Other countries		3,684	445	      548	 
	State		    9,835	    8,487	    6,216	
			   51,193	   56,545	   33,393	
Deferred:
	United States		6,491	15,590	   (8,648)	
	Canada		2,802	135	   (1,124)	
	State		    1,384	     (295)	   (2,047)	
			   10,677	   15,430	  (11,819)	
			$  61,870	$  71,975	$   21,574	
</TABLE>

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

	      December 31     
			   1997   	   1996   
			 Thousands of Dollars
<S>                                                   <C>         <C>
Plant related		$ 390,776	$ 388,973
Investment in Nonutility generation projects		25,530	26,785
Other		   41,499	   33,508
	Gross deferred tax liabilities		  457,805	  449,266

Coal reclamation		(46,820)	(45,252)
Amortization of gain on sale/leaseback		(13,860)	(14,898)
Investment tax credit amortization		(22,862)	(28,895)
Other		  (44,551)	  (38,455)
	Gross deferred tax assets		 (128,093)	 (127,500)
	Net deferred tax liabilities		329,712	321,766
	Less current deferred tax assets-net		  (10,539)	  (11,095)
Total noncurrent deferred tax liabilities		$ 340,251	$ 332,861

	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		$	7,390
Regulatory assets related to income taxes		26,247
Current deferred tax assets-net		556
Amortization of investment tax credits		(7,817)
Transfer of natural gas production balances		(16,677)
Other			978
	Deferred tax expense			$	10,677
</TABLE>


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, 1999, unless redeemed earlier or exchanged by the Company.  

	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% 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, 1997, 994,355 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 $5,194,000, $6,046,000 and 
$5,610,000 for 1997, 1996 and 1995, 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. 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.  Options granted 
prior to January 1, 1987 must be exercised in the order granted.  

	In 1995 and 1994, restricted stock awards of 2,100 and 64,235, 
respectively, were issued to certain Nonutility employees under the Long-Term 
Incentive Plan.  Upon the achievement of performance and passage of time 
constraints, restrictions will be lifted and participants will retain, at no 
cost, the unrestricted shares.  As they are earned, the awards are reflected as 
common stock and compensation expense on the Consolidated Balance Sheet and 
Consolidated Statement of Income, respectively.  At December 31, 1997 there 
were 9,643 shares of restricted stock remaining.  

<TABLE>
<CAPTION>
Option activity is summarized below:  

	      1997      	      1996      	       1995      
<S>                   <C>                <C>                 <C>
Options outstanding
	@ 1/1	694,804	569,982	480,986
	(Price range)	($17.25 - $26.50)	($17.25 - $26.50) 	($17.25 - $26.50)

Options granted		164,400	116,730
	(Price range)		($21.625)    	($21.125 - $22.50)

Options exercised	125,753	11,578	19,034
	(Price range)	($17.25 - $22.625)	($17.25 - $22.125)	($17.25 - $26.50)

Options canceled	27,886	28,000	8,700
	(Price range)	($17.6875 - $22.50)	($22.125 - $22.625)	  ($22.125 - $22.625)

Options outstanding
	@ 12/31	541,165	694,804	569,982
</TABLE>
	There were 436,560 options exercisable at December 31, 1997.

	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 fair value of 
options granted in 1996 and 1995 was $1.93 and $1.60 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 assumptions used for 
grants in 1996 and 1995, respectively: risk-free interest rate of 7.05% and 
5.67%; expected life of ten years for both years; expected volatility of 
10.46% and 10.05% and a dividend yield of 6.83% and 6.33%. Had the Company 
used SFAS No. 123, earnings per share would be unaffected as compensation 
expense would have increased only $195,000, $108,000 and $37,000 for 1997, 
1996 and 1995, respectively.

NOTE 7 - Preferred stock:  

	The number of authorized shares of preferred stock is 5,000,000. No 
dividends may be declared or paid on common stock while cumulative dividends 
have not either been declared and set apart or paid on any of the preferred 
stock.  

	Preferred stock is in four series as detailed in the following table:  
<TABLE>
<CAPTION>
	Stated and
	Liquidation	Shares Issued and Outstanding	    Thousands of Dollars    
Series	   Price*  	  1997   	  1996   	  1995   	  1997 	  1996  	  1995  
<S>                  <C>       <C>       <C>      <C>       <C>       <C>
	$6.875	$100	360,800	360,800	500,000	$ 36,080	$ 36,080	$ 50,000
 6.00	100	159,589	159,589	159,589	15,959	15,959	15,959
 4.20	100	60,000	60,000	60,000	6,025	6,025	6,025
 2.15	25	        	        	1,200,000	        	        	  30,000
Discount		        	        	         	    (410)	    (410)	    (568)
			 580,389	 580,389	1,919,589	$ 57,654	$ 57,654	$101,416
<FN>
	*  Plus accumulated dividends.
</FN>
</TABLE>
	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.

	In October 1996, the Company repurchased and retired 139,200 shares of 
the $6.875 series at prices ranging from $101.50 to $103.00.  In December 1996, 
the Company redeemed all outstanding shares of the $2.15 series at the 
redemption price of $25.25.  The total premium of approximately $650,000 
resulting from these transactions was included in preferred dividends in the 
Consolidated Statement of Income.


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, 1997 and 1996 the Trust held 2,600,000 units of 8.45% 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% of 
the liquidation preference value of $25 per security. The sole asset of the 
Trust is $67,000,000 of Subordinated Debentures, 8.45% 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% of the aggregate 
liquidation amount of all the Trust Securities.

NOTE 9 - Long-term debt:  

	The Company's Mortgage and Deed of Trust (the Mortgage) imposes a first 
mortgage lien on all physical properties owned, exclusive of subsidiary company 
assets, and certain property and assets specifically excepted.  The obligations 
collateralized are First Mortgage Bonds, including those First Mortgage Bonds 
designated as Secured Medium-Term Notes and those securing Pollution Control 
Revenue Bonds. The Mortgage may impose some restrictions on the use of 
proceeds realized from the sale of the electric generating assets and power 
purchase contracts.

	Long-term debt consists of the following:  

	       December 31      
	   1997   	   1996   
	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 1998-2025  5.90%-8.11%		108,000	128,000
	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	16,000
ESOP Notes Payable - 9.2%, due 2004		25,104	27,587
Unsecured Medium-Term Notes:  
	Series A - maturing 1998-2022  8.68%-8.9%		22,000	29,500
	Series B - maturing 2006-2026  7.07%-7.96%		55,000	55,000
Revolving Credit Agreements		45,715	35,000
Other		62,269	10,536
Unamortized Discount and Premium			(3,966)		(4,221)
	734,827	702,607
Less:  Portion due within one year			81,659		69,268
		$	653,168	$	633,339

	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. In August 1997, the Company paid approximately 
$4,200,000 into a fish and wildlife fund reducing the amount owed. 
Approximately, $36,000,000 is classified as due within one year in the 
Consolidated Balance Sheet at December 31, 1997.

In December 1997, Roan Resources Ltd., a wholly owned Canadian subsidiary 
purchased the stock of a small 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 Roan Resources and the Royal Bank of 
Canada.  The maximum amount of credit available under this Agreement is 
$37,800,000 in Canadian dollars which was reduced to $28,000,000 in Canadian 
dollars, or $19,627,000 in U.S. dollars, on January 8, 1998.  At December 31, 
1997, the amount outstanding under the agreement was $15,715,000 in U.S. 
dollars, which is included in "Revolving Credit Agreements" in the table above.

	In April 1997, the Company entered into a Revolving Credit Agreement for 
certain of its Nonutility operations. Including this facility, the Company's 
consolidated borrowing ability under its Revolving Credit and Term Loan 
Agreements (Agreements) is $220,000,000, of which $190,000,000 was unused at 
December 31, 1997.  Under terms of the new agreement, the amount of the 
facility decreases on March 31, 1998, reducing the consolidated borrowing 
ability under the Agreements to $160,000,000. These agreements term on 
October 27, 1998 and April 4, 2000, and all outstanding borrowings must be 
repaid on those dates. Fixed or variable interest rate options are available 
under the facilities with facility fees or commitment fees on the unused 
portions.  

	The sinking fund requirements and maturities for the five years ending 
December 31, 2002, on the long-term debt outstanding at December 31, 1997, 
amount to: $82,000,000 in 1998; $63,000,000 in 1999; $65,000,000 in 2000; 
$30,000,000 in 2001 and $6,000,000 in 2002.


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, 1997, the Company had lines of credit consisting of 
$70,000,000 committed and $85,000,000 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 $165,000,000 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	
		       1997       	       1996       
			 Amount 	Rate	 Amount 	Rate
	Thousands of Dollars

	Notes payable to banks		$	89,100	6.82%	$	70,500	7.17%
	Commercial paper			44,858	6.46%		34,202	5.79%
			$133,958		$104,702

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.  

	In 1997, funding for pension costs exceeded SFAS No. 87 pension expense 
by $5,441,000.  In 1996 and 1995, pension costs funded were less than SFAS 
No. 87 pension expense by $188,000, and $1,501,000, respectively.  The 
differences were deferred for recognition in future periods as funding is 
reflected in rates.  At December 31, 1997, the regulatory liability was 
$2,344,000.  

	The assets of the plans consist primarily of domestic and foreign 
corporate stocks, domestic corporate bonds and U.S. Government securities.  

	The Company also has an unfunded, nonqualified benefit plan for senior 
management executives and directors. Life insurance payable to the Company is 
carried on plan participants as an investment.  The plan costs are not included 
in rates.

	Net pension and benefit expense includes the following components:  

	             December 31	
			   1997  	   1996  	   1995   
			        Thousands of Dollars
	Service cost on benefits earned		$	7,585	$	7,991	$	6,165
	Interest cost on projected benefit 
		obligation		16,370	15,861	   14,524
	Actual return on plan assets		(38,280)	(30,331)	  (13,009)
	Net amortization and deferral			18,185		15,270		1,719
		Net pension and benefit expense		$	3,860	$	8,791	$	9,399


		The funded status of the pension and benefit plans is as follows:  

	    December 31	
	  1997   		  1996   
			Thousands of Dollars
	Actuarial present value of benefit obligation:  
		  Vested		$	180,662	$	152,115
		  Nonvested			21,177		19,029
	Accumulated benefit obligation			201,839		171,144
	Effect of projected future compensation levels			46,902		51,125
	Projected benefit obligation		248,741	222,269
	Plan assets at fair value			259,837		223,686
	Plan assets greater than projected  
	  benefit obligation		11,096	1,417
	Unrecognized net gain		(40,704)	(34,793)
	Unrecognized prior service cost		8,691	10,088
	Unrecognized initial obligation			1,905		2,491
		Accrued benefits expense		$	(19,012)	$	(20,797)


		The following assumptions were used in the determination of actuarial 
present values of the projected benefit obligations:  

			       December 31	
			   1997    	   1996    
	Assumed discount rates		7.00%	7.50%
	Long-term rate of average compensation
	  increase		4.50%-7.50%	4.50%-5.00%
	Long-term rate on plan assets		9.00%	8.50%

	In addition to providing pension benefits, the Company and its 
subsidiaries provide certain health care and life insurance benefits for 
eligible retired employees. 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.

	Postretirement benefit costs for the years ended December 31, 1997, 1996 
and 1995, portions of which have been deferred or capitalized, include the 
following components:  

	           December 31        
	  1997  	  1996  	  1995  
	Thousands of Dollars
	Service cost on benefits earned		$	803	$	1,074	$	1,221
	Interest cost on projected benefit		2,020	2,092	2,482
	Actual return on plan assets		(993)	(876)	(219)
	Net amortizations			1,266		1,577		1,299
		Total postretirement benefit cost		$	3,096	$	3,867	$	4,783

	The funded status of the postretirement benefit plans other than pensions 
is as follows:

	     December 31    
	  1997  	  1996  
	Thousands of Dollars
	Accumulated benefit obligation:
		Fully eligible active employees			$  1,599	$  3,267
		Other active employees		14,796	16,267
		Retirees		  13,859	  10,330
	Accumulated benefit obligation		30,254	29,864
	Plan assets at fair value		   8,168	   5,740
	Plan assets less than projected
	  benefit obligation		(22,086)	(24,124)
	Unrecognized net transition obligation		18,194	20,012
	Unrecognized net gain		  (8,930)	  (8,064)
		Accrued benefits expense		$(12,822)	$(12,176)

	The assumed 1997 health care cost trend rates used to measure the 
expected cost of benefits covered by the plans is 8.50%.  The trend rate 
decreases through 2004 to 5%.  The effect of a 1% increase in each future 
year's assumed health care cost trend rates increases the service and interest 
cost from $2,823,000 to $3,032,000 and the accumulated postretirement benefit 
obligation from $30,000,000 to $32,000,000. 

NOTE 12 - Information on industry segments:  

	The Montana Power Company (the Company) and its subsidiaries engage in a 
number of diversified energy and communication related businesses.  The 
Company's principal business is the regulated Utility operations 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 the mining and sale of coal and 
lignite, exploration for, and the development, production, processing and sale, 
of oil and natural gas, and the sale of telecommunication equipment and 
services.  It  also conducts trading and marketing of electricity and natural 
gas. In addition, the Company manages long-term power sales, and develops and 
invests in Nonutility 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, almost 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.


<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
Pre-tax operating income		111,002	37,994
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
Pre-tax operating income		31,050	16,310	(17)
Earnings (loss) from unconsolidated 
	investments		(2,202)			14,980
Depreciation, depletion and amortization		8,368	16,922		2,774
Capital expenditures		4,588	140,437		(15,140)
Identifiable assets			247,981		290,110		156,282
<CAPTION>
NONUTILITY (continued)
					    Tele-
					Communications**	   Other  
<S>                                                 <C>            <C>
Sales to unaffiliated customers			$	44,464	$	2,104
Intersegment sales				797		3,924
Pre-tax operating income (loss)			11,759	(4,809)
Earnings from unconsolidated 
	investments			435
Depreciation, depletion and amortization			2,455		532
Capital expenditures			25,422	53
Identifiable assets			101,581	7,987
<CAPTION>
CORPORATE
<S>                                                <C>
Capital expenditures		$	94
Identifiable assets		47,237
<FN>
*	Sales under one coal contract with Houston Light and Power Company 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.
</FN>
</TABLE>

<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
Pre-tax operating income		   122,123	    40,830
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
Pre-tax operating income		    34,358	    17,687	    1,675
Earnings (loss) from unconsolidated 
	investments		    (2,777)		   21,174
Depreciation, depletion and amortization		     5,653	    17,080	    3,793
Capital expenditures		     8,386	    25,021	   (9,406)
Identifiable assets		   268,297	   184,512	  156,044
<CAPTION>
NONUTILITY (continued)
					    Tele-
					communications	   Other  
<S>                                                 <C>            <C>
Sales to unaffiliated customers			$   27,575	$    1,201
Intersegment sales			       133	       782
Pre-tax operating income (loss)			     2,591	    (2,040)
Earnings from unconsolidated 
	investments			        66
Depreciation, depletion and amortization		 	       911	       679
Capital expenditures		 	    27,902	         6
Identifiable assets		  	    52,139	    17,954
<CAPTION>
CORPORATE
<S>                                                 <C>
Capital expenditures		$    1,178
Identifiable assets		    71,117
<FN>
*	Sales under one coal contract with Houston Light and Power Company amounted to 
$102,181,000.  

**	The Independent Power segment is dependent on two customers, the losses of which 
would have a material adverse effect on the segment.  
</FN>
</TABLE>

<TABLE>
<CAPTION>
Operations Information:  
				       Year Ended
				    December 31, 1995     
				   Thousands of Dollars

UTILITY		 Electric 	Natural Gas
<S>                                                  <C>           <C>
Sales to unaffiliated customers		$  421,999	$  115,113
Intersegment sales		     5,813	       852
Pre-tax operating income		   124,916	    30,933
Depreciation, depletion and amortization		    40,675	    10,283
Capital expenditures		   127,917	    35,091
Identifiable assets		 1,503,619	   410,267
<CAPTION>
NONUTILITY				
					  Oil and	Independent
				   Coal*  	Natural Gas	   Power**	
<S>                                           <C>          <C>          <C>
Sales to unaffiliated customers		$  210,200	$  100,030	$  79,095
Intersegment sales		    25,659	       409	      796
Writedown of long-lived assets		    55,103	    19,194
Pre-tax operating income (loss)		   (41,001)	    (8,504)	    3,027
Earnings (loss) from unconsolidated 
	investments		    (2,749)		    2,622
Depreciation, depletion and amortization		    11,187	    17,569	    3,176
Capital expenditures		    19,230	    34,780	    4,168
Identifiable assets		   250,132	   177,744	  161,602
<CAPTION>
NONUTILITY (continued)
					    Tele-
					communications	   Other  
<S>                                                 <C>            <C>
Sales to unaffiliated customers			$   23,177	$    2,647
Intersegment sales			       377	       699
Pre-tax operating income (loss)			     2,200	       (52)
Earnings from unconsolidated 
	investments			        70
Depreciation, depletion and amortization		 	       803	       942
Capital expenditures		 	     8,633	        48
Identifiable assets		  	    22,592	    17,032
<CAPTION>
CORPORATE
<S>                                                 <C>
Capital expenditures		$    1,220
Identifiable assets		    43,103
<FN>
*		Sales under one coal contract with Houston Light and Power Company amounted to 
$102,844,000.  

**	The Independent Power segment is dependent on two customers, the losses of which 
would have a material adverse effect on the segment.  
</FN>
</TABLE>

	SUPPLEMENTARY DATA
	OIL AND NATURAL GAS PRODUCING ACTIVITIES

	For the years ended December 31, 1997, 1996 and 1995 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>
					                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>

<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		
<CAPTION>
				          1996          
				   U.S.   	  CANADA  
PROVED DEVELOPED RESERVES:
<S>                                                <C>            <C>
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>

<TABLE>
<CAPTION>
					                1995             
				   U.S.   	   CANADA   	STORAGE 
PROVED DEVELOPED AND UNDEVELOPED RESERVES:
<S>                                               <C>          <C>          <C>
UTILITY OPERATIONS:
	Natural Gas (Mmcf):
		Beginning Balance	   80,562	     96,571	 56,548
		Production	   (5,176)	     (4,651)
		Additions		      2,840	    197
		(Sales) and Purchases of Reserves in Place
		Revisions - Other	       75	      8,715
		Revisions - Price	         			
			Ending Balance	   75,461	103,475	56,745	

NONUTILITY OPERATIONS:
	Natural Gas (Mmcf):
		Beginning Balance	  153,162	     79,283
		Production	   (8,605)	     (6,703)
		Additions	    5,035	      6,528
		(Sales) and Purchases of Reserves in Place	       47	     (8,053)
		Revisions - Other	   (7,426)	     (3,594)
		Revisions - Price	   (5,553)	     (4,987)		
			Ending Balance	  136,660	     62,474		

	Natural Gas
		Liquids (Bbls):
		Beginning Balance	3,110,300	  1,999,500
		Production	 (258,112)	   (183,856)
		Additions	   12,200	    299,300
		(Sales) and Purchases of Reserves in Place		   (141,400)
		Revisions - Other	  929,732	  1,714,808
		Revisions - Price	 (178,720)	(8,220)		
			Ending Balance	3,615,400	  3,680,132		

	Oil (Bbls):
		Beginning Balance	6,079,700	  4,935,000
		Production	   (479,952)	   (601,051)
		Additions	  117,392	     66,400
		(Sales) and Purchases of Reserves in Place	  392,436	    173,392
		Revisions - Other	  (38,862)	    152,418
		Revisions - Price	  (71,314)	   (296,663)		
			Ending Balance	5,999,400	  4,429,496		
<CAPTION>
				          1995          
				   U.S.   	  CANADA  
PROVED DEVELOPED RESERVES:
<S>                                                <C>           <C>
UTILITY OPERATIONS:
	Natural Gas (Mmcf):
		Ending Balance	   74,630	103,475

NONUTILITY OPERATIONS:
	Natural Gas (Mmcf):
		Ending Balance	   78,637	   55,947

	Natural Gas Liquids (Bbls):
		Ending Balance	2,943,900	3,380,832

	Oil (Bbls):
		Ending Balance	4,488,900	3,421,596
</TABLE>



SUPPLEMENTARY DATA
Oil and Natural Gas Producing Activities (Cont.)

		As determined by engineers, Utility natural gas reserves were revised 
during 1997, 1996 and 1995 due to changes in projected performance or changes 
in the Company's ownership interest in specific fields.  

	In 1997, the PSC approved the deregulation of the Utility's natural gas 
production properties.  As a result, all of the Canadian and almost all of the 
U.S. natural gas reserves were transferred to the Nonutility effective November 
1, 1997. 

	Nonutility U.S. natural gas and natural gas liquid reserves increased in 
1997 because of the acquisition of reserves in place (Vessels), 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 (Questar), 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. 

	The Utility reserves that were transferred to the Nonutility in 1997 
were determined by petroleum engineers following Utility business guidelines 
to be those reserves that are mechanically recoverable using reasonable 
production methods. After deregulation and transfer, the same natural gas 
reserve volumes are estimated to be those which are mechanically recoverable 
under market price conditions.  The inclusion of economic limits into the 
estimates has resulted in downward revisions of U.S. and Canadian natural gas 
reserves.

	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 (Bowdoin Field).  Oil reserves were added with the 
purchase of additional interest in an existing Montana field (Reagan).  The 
Canadian natural gas and oil reserves decreased primarily as a result of 
downward revisions of engineering estimates for undeveloped reserves.

	In 1995, the Nonutility U.S. natural gas reserves decreased as a result 
of lower gas market prices and higher liquid recoveries at the Fort Lupton, 
Colorado gas processing plant.  The higher liquid recoveries resulted in an 
increase in natural gas liquid reserves.  Reserve additions through 
participation in the drilling of 29 development wells and five exploratory 
wells in Oklahoma, Colorado and Montana offset Nonutility production.  The 
Canadian companies participated in 18 development wells and 12 exploratory 
wells.  Of these, 17 were oil wells in the Sounding Lake and Manyberries areas 
of Alberta.  

	The following table presents information for 1997, 1996 and 1995 on the 
capitalized costs relating to Utility natural gas producing activities, costs 
incurred in Utility natural gas property acquisition, exploration and 
development activities and certain Utility natural gas production costs 
reflected in results of operations.  As a regulated public utility, the Company 
is authorized to earn a rate of return on its Utility natural gas plant rate 
base. The Company's cost of acquiring Utility natural gas reserves and the net 
cost of natural gas in underground storage are included in the natural gas 
plant which is a part of the Utility rate base.  Due to the commingling of 
produced natural gas with purchased and royalty natural gas for sale to Utility 
customers and application of the ratemaking process to the Utility natural gas 
producing activities, the Company is unable to identify revenues resulting 
solely from Utility natural gas producing activities.  Accordingly, the 
information on revenues, income taxes, results of operations and estimated 
future net cash flows and changes therein relating to proved Utility natural 
gas reserves are not presented for the Company's Utility natural gas producing 
activities.  
<TABLE>
<CAPTION>
				       1997      	       1996      	       1995      
					  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		$  2,023	$      0	$ 87,363	$ 38,551	$ 89,520	$ 37,683
Accumulated depreciation,
	depletion and valuation
	allowances		   1,833	       0	  46,881	  20,102	  50,377	  19,812

		Net capitalized costs		$    190	$      0	$ 40,482	$ 18,449	$ 39,143	$ 17,871

For the year ended 
	December 31:  
Costs incurred in natural
	gas property acquisition, 
	exploration and 
	development activities: 
		Acquisition of 
			properties				$    474	$     49	$     48	$    170
		Exploration		$	35	$	168	54	191	     70	    198
		Development		1	66	501	1,230	  1,753	  1,240

Costs reflected in results 
  of operations: 
		Production costs		$  3,361	$  1,359	$  4,773	$  1,510	$  5,710	$  1,592
		Exploration expenses		35	168	54	191	     70	    198
		Development expenses		0	66	22	113	    165	    416
		Depreciation, depletion
			and valuation 
		  provisions		2,072	686	2,667	711	  2,716	    586
</TABLE>


	The following table presents information for 1997, 1996 and 1995 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>
				       1997      	       1996      	       1995      
					  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		$240,436	$113,165	$182,339	$ 87,529	$171,795	$ 83,457
Accumulated depreciation,
	depletion and valuation 
	allowances		  49,167	  46,131	  65,401	  44,770	  60,329	  39,834

		Net capitalized costs		$191,269	$67,034	$116,938	$ 42,759	$111,466	$ 43,623

For the year ended 
	December 31:

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

	Acquisition of 
	  properties		$85,606	$22,762	$  4,667	$  3,722	$ 13,024	$  4,407
	Exploration		4,589	6,036	1,780	2,157	   4,592	  1,642
	Development		21,050	8,535	10,651	3,345	  11,244	  4,298

Results of operations for 
	oil and natural gas 
	producing activities:

		Revenues		$ 34,182	$ 14,821	$ 26,872	$ 19,789	$ 20,461	$ 19,022
		Production costs		10,232	5,041	8,901	6,547	   7,298	  6,812
		Exploration expenses		3,233	2,905	1,670	1,747	   2,460	  1,517
		Depreciation, depletion 
			and valuation 
			provisions		  12,037	   3,781	  10,019	   6,133	  21,079	  15,371
					8,680	3,094	6,282	5,362	 (10,376)	(4,678)

		Income tax expenses		     416	   1,380	     946	   2,393	  (5,708)	  (2,087)

Results of operations from
	producing activities
	(excluding corporate 
	overhead and interest 
	cost)		$  8,264	$  1,714	$  5,336	$  2,969	$ (4,668)	$ (2,591)
</TABLE>



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.  


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

		                  December 31                 
		         1997         	         1996         
		    U.S.   	  Canada  	    U.S.   	  Canada  
				  Thousands of Dollars   
<S>                                  <C>         <C>         <C>         <C>
Future cash inflows		$	876,733	$	303,780	$	684,709	$	185,988
Future production and  
	development costs		467,270	151,201	261,432	68,921
Future income tax expenses			94,162		36,253		129,091		27,876

Future net cash flows		315,301	116,326	294,186	89,191
10% annual discount for 
	estimated timing
	of cash flows			122,469		35,008		135,285		23,407

Standardized measure of 
	discounted future net 
	cash flows		$	192,832	$	81,318	$	158,901	$	65,784

	  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		$	(23,620)	$	(9,780)	$	(22,466)	$	(13,242)
Net changes in prices, 
	development and production 
	costs		(30,047)	(12,687)	16,095	30,948
Extensions, discoveries, and 
	improved recovery, less 
	related costs		60,863	42,699	19,823	2,597
Revisions of previous quantity 
	estimates		(20,953)	(11,929)	14,012	(11,395)
Accretion of discount		20,503	7,480	16,939	6,150
Net change in income taxes		25,584	968	(14,670)	(4,005)
Other		1,601	(1,217)	(8,765)	(1,758)
</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 1997 and 1996, the amount described as other is primarily the result 
of changes in the timing of production.

QUARTERLY FINANCIAL DATA

	Operating revenues, operating income and net income in thousands of 
dollars and net income per common share for the four quarters of 1997 and 1996 
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,
			  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		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

<CAPTION>
			                 Quarter Ended                    

			 Dec. 31, 	Sept. 30, 	June 30,  	Mar. 31,
			  1996    	  1996    	  1996    	  1996    
<S>                                 <C>          <C>          <C>           <C>
Utility Operating Revenues		$169,257	$115,533	$110,265	$170,086
Utility Operating Income		57,036	22,738	23,899	59,280
Utility Net Income		24,593	3,837	6,016	27,201

Nonutility Operating Revenues		137,437	110,926	94,560	104,930
Nonutility Operating Income		31,719	16,547	8,385	16,083
Nonutility Net Income		19,026	12,585	6,463	11,307

Consolidated Net Income		43,619	16,422	12,479	38,508

Basic Earnings Per Share of 
	Common Stock		$   0.80	$   0.30	$   0.23	$   0.70

Diluted Earnings Per Share of
	Common Stock		$   0.80	$   0.30	   $   0.23	$   0.70
</TABLE>


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 1998 Annual Meeting of Shareholders and 
Proxy Statement, pages 1-3.  

ITEM 11.	EXECUTIVE COMPENSATION

	Incorporated by reference from Notice of 1998 Annual Meeting of 
Shareholders and Proxy Statement, pages 6-12.  

ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

	Incorporated by reference from Notice of 1998 Annual Meeting of 
Shareholders and Proxy Statement, pages 4-5.  

ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

	None.  


	PART IV

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

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


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

	     Date        	                Subject                     

	October 23, 1997	Item 5.  Other Events.  Discussion of Third 
Quarter Net Income.

		Item 7 Exhibits.  Consolidated Statements of 
Income for the Quarters Ended September 30, 
1997 and 1996, Nine Months Ended September 30, 
1997 and 1996, and for the Twelve Months Ended 
September 30, 1997 and 1996.  Utility 
Operations Schedule of Revenues and Expenses 
for the Quarters Ended September 30, 1997 and 
1996, Nine Months Ended September 30, 1997 and 
1996 and for the Twelve Months Ended 
September 30, 1997 and 1996. Nonutility 
Operations Schedule of Revenues and Expenses 
for the Quarters Ended September 30, 1997 and 
1996, Nine Months Ended September 30, 1997 and 
1996 and for the Twelve Months Ended 
September 30, 1997 and 1996.

	December 9, 1997	Item 5.  Other Events.  Montana Power Company 
Offers to Sell its Montana Generation.
 
	December 12, 1997	Item 5.  Other Events.  Texas Jury Finds for 
Northwestern Resources in Coal Dispute.  



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

3.	Exhibits		Incorporation by Reference
				  Previous
			 Previous	   Exhibit
			  Filing  	 Designation 

	 3(a)	Restated Articles of Incorporation,
		  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,
		  1996	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

	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
		Agreements with Senior 
		Management Executives	

	10(c)	Participation Agreements among	33-42882	10(c)
		United States Trust Company 	
		of New York, Burnham Leasing 	
		Corporation, and SGE (New York) 
		Associates, Certain Institutions, 
		The Montana Power Company and 
		Bankers Trust Company

	12	Statement Re Computation of Ratio
		of Earnings to Fixed Charges

	21	Subsidiaries of the Registrant

	23	Consent of Independent Accountants

	27	Financial Data Schedule


<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, 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

December 31, 1995
Reserves deducted
in balance sheet
from assets to
which they apply:
Doubtful accounts
	Utility	$	808	$	1,065			$	1,005	$	868
	Nonutility		616		206	$	62		283		601

		Total	$	1,424	$	1,271	$	62	$	1,288	$	1,469

<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>


	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 25, 1998


	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 25, 1998
(Chief Executive Officer)



/s/ J. P. Pederson		Principal Financial
J. P. Pederson		  and Accounting Officer
(Vice President and Chief		  and Director	March 25, 1998
  Financial and Information
  Officer)



/s/ Tucker Hart Adams		Director	March 25, 1998
Tucker Hart Adams



/s/ Alan F. Cain		Director	March 25, 1998
Alan F. Cain



/s/ John G. Connors		Director	March 25, 1998
John G. Connors



/s/ R. D. Corette		Director	March 25, 1998
R. D. Corette



/s/ Kay Foster		Director	March 25, 1998
Kay Foster



/s/ Beverly D. Harris		Director	March 25, 1998
Beverly D. Harris



/s/ Chase T. Hibbard		Director 	March 25, 1998
Chase T. Hibbard



/s/ John R. Jester		Director 	March 25, 1998
John R. Jester



/s/ Carl Lehrkind, III		Director	March 25, 1998
Carl Lehrkind, III



/s/ Arthur K. Neill		Director	March 25, 1998
Arthur K. Neill



/s/ N. E. Vosburg		Director	March 25, 1998
N. E. Vosburg


	EXHIBIT INDEX


Exhibit 3(b)(3)
	Amendment to By-laws dated December 9, 1997	

Exhibit 12
	Statement Re Computation of Ratio Earnings to Fixed Charges	

Exhibit 21
	Subsidiaries of the Registrant	

Exhibit 23
	Consent of Independent Accountants	

Exhibit 27
	Financial Data Schedule	










SIGNATURES (Continued)