March 26, 1997



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 Gentlemen:

The accounting principles and practices and the method of applying such 
principles and practices relflected in the financial statements included in the 
1996 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, 1996
	-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 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 $1,236,916,381 at March 13, 1997.  

On March 13, 1997, the Company had 54,634,994 shares of common stock 
outstanding.

	DOCUMENTS INCORPORATED BY REFERENCE

(1)	Notice of 1997 Annual Meeting of Shareholders and Proxy Statement, pages 1-
15, 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 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", 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 production, purchase, transportation and distribution of 
natural gas.  The Company's nonutility operations engage in a number of 
diversified operations principally involving the mining and sale of coal and 
exploration for, and the development, production, processing and sale, of oil 
and natural gas and the sale of telecommunication equipment and services.  In 
addition, the Company manages long-term power sales, and develops and invests 
in nonutility power projects and other energy-related businesses.  See Item 8, 
"Financial Statements and Supplementary Data - Note 11 to the Consolidated 
Financial Statements" for further information.  A group of officers and 
employees of the Company constitute the Office of the Corporation, which 
provides strategic direction and policy, approves the allocation of capital and 
provides financial, legal and other services to all of the operating units. The 
Company was incorporated in 1961 under the laws of the State of Montana, where 
its principal business is conducted, as the successor to a New Jersey 
corporation incorporated in 1912.  

	In May 1996, the Company began managing itself as a restructured company 
with 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 wholesale business 
development. The Energy and Communications Services Division is responsible for 
the transmission and distribution of electricity and natural gas as well as 
telecommunications, energy management services and retail business development.

	Pending regulatory decisions and legislation 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 
596,000 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 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 three 
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 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 Montana Public Service Commission (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 filed a motion requesting a waiver of the 
filing requirements for a 1997 Plan and proposing 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 Company is expecting 
approval of the waiver.

	Also refer to Item 7, "Management's Discussion and Analysis of Financial 
Conditions and Results of Operations - Summary of Significant Regulatory 
Matters."  

	ELECTRIC UTILITY:  The maximum demand on the resources in 1996 was 
1,415,000 kW on February 2, 1996.  Total firm capability of the Utility's 
electric system at December 31, 1996 was 1,606,000 kW.  Of this capability, 
1,197,000 kW was provided by the Utility's generating facilities, and 
409,000 kW was provided by firm Electric Utility power purchase and exchange 
arrangements.  The Electric Utility's reserve margin on February 2, 1996, as a 
percentage of maximum demand, was 14%.  Also refer to Item 8, "Financial 
Statements and Supplementary Data - Note 3 to the Consolidated Financial 
Statements" for further discussion of power purchases.

	The Company's future need for electric resources will be to meet winter 
peak requirements.  Future power needs could change depending on wholesale 
wheeling, changes in the number of customers, and changes that retail wheeling 
would cause, if it occurs.  In 1996, two purchase power contracts totaling 
approximately 150,000 kW expired and will not be renewed.  Deliveries under a 
long-term contract with a 450 kW qualifying facility began in October 1996.

	Local-area integrated resource planning (LIRP) uses integrated resource 
planning principles to solve reliability and/or load growth problems for a 
specific area through a balance of resources and/or transmission and 
distribution facilities additions. As a part of the Company's planning process, 
LIRP is being used in the Helena area to determine the least cost solution to a 
transmission reliability problem under certain  line outage conditions. 
Included in this process is an RFP to discover possible solutions that may 
replace or augment known transmission facility alternatives.  The need for 
additional winter peak resource will be addressed annually and any need will be 
met through market purchases. 

	During the year ended December 31, 1996, the sources of the Utility 
Operations electric supply were:  hydro, 38%; coal, 40%; and purchased power, 
22%.  The cost of coal burned has been as follows:
		 
	 Year Ended December 31 
	 1996 	 1995 	 1994 

	Average cost per million Btu's		$ 0.59	$ 0.56	$ 0.66

	Average cost per ton (delivered)		10.06	  9.67	 11.24

	Reduced coal volumes burned due to thermal displacement with low-cost 
hydroelectric power and the switching of fuel suppliers by the Corette Plant 
caused the average cost of coal to increase in 1996 as fixed costs were spread 
over fewer tons. The decline in the 1995 average cost per ton is primarily due 
to the Colstrip Units 1 and 2 Coal Supply Agreement arbitration decision.

	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 also is a party to the Pacific Northwest Coordination Agreement which 
integrates electric and hydroelectric operations of the 18 parties associated 
with generating facilities in the Columbia River Basin; is a member of the 
Western Systems Coordinating Council, organized by 77 member systems and 
20 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 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 1996 totaled 
22,642 Mmcf, of which 12,269 Mmcf were from Montana and 10,373 Mmcf from 
Canada.  The Gas Utility produced 45% of the Montana natural gas and its 
Canadian subsidiaries produced 53% of the Canadian natural gas.  

	The Natural Gas Utility transports gas supplies for all customers meeting 
a 60,000 Mmcf annual transportation threshold.  However, substantially all of 
these customers obtain their supplies directly from other sources.  Total 
volumes of natural gas transported were 27,200 Mmcf, 26,700 Mmcf and 
23,700 Mmcf for 1996, 1995 and 1994, respectively.  

	Total 1997 natural gas requirements, estimated to be 23,123 Mmcf, are 
anticipated to be supplied from existing reserves and purchase contracts. 
Approximately 11,650 Mmcf of these requirements are expected to be obtained in 
the United States and 11,473 Mmcf from Canada.  The Natural Gas Utility expects 
to produce 47% of the Montana natural gas and 48% of the Canadian natural gas. 
The 1997 transportation volumes are anticipated to be 27,889 Mmcf.  The 1997 
estimates do not reflect changes which may occur as a result of the Company's 
natural gas restructuring filing with the PSC.

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 subsidiary, Western SynCoal Company (SynCoal), owns 75% of a 
patented coal enhancement process, a subsidiary of Northern States Power owns 
the rest, and each owns 50% of the Rosebud SynCoal Partnership, which owns and 
operates a coal enhancement process demonstration plant at the Rosebud Mine. 
Northwestern Resources Company (Northwestern) holds leases on lignite 
properties in Texas and operates the Jewett Mine.  Horizon Coal Services, Inc. 
(Horizon) holds leases and rights on coal  properties in Wyoming.  Basin 
Resources, Inc. (Basin) operated the Golden Eagle Mine in Colorado.  In 
December 1995, Basin terminated all coal sales agreements and ceased 
production.  In 1996, the mine was sealed and most of the salvageable plant and 
equipment was sold or is under agreement to be sold. See Item 7, "Management's 
Discussion and Analysis of Financial Condition and Results of Operations - 
Nonutility Operations - Coal Operations - 1996 Compared to 1995 - Expenses" and 
Item 8, "Financial Statements and Supplementary Data - Note 12 to the 
Consolidated Financial Statements."

	The oil and natural gas business is conducted in the United States 
through North American Resources Company (NARCO) and  in Canada through both 
Altana Exploration Company (Altana) and Roan Resources, Ltd. (Roan). 

	The telecommunication business is conducted through Touch America, Inc. 
Touch America offers three primary services to customers:  equipment, private 
lines and long distance services. 

	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.  

	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 and the Jewett Mine sells its entire 
production to the two 800 MW Limestone Units. All of the contracts provide for 
periodic price reopeners. The Company expects to be able 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.  The Company holds significant reserves in 
the Gillette area of Wyoming that are under development.  A decision to commit 
to mine construction will be based on the demand and price outlook for 
production from the area. The Company is also investigating joint development 
and sales alternatives for the property. 

	The Nonutility oil and natural gas business competes in the areas of 
property acquisitions and the development, production and marketing of oil and 
natural gas, as well as contracting for equipment, services, and securing 
personnel, with major oil and natural gas companies, other independent  and 
individual producers and operators.  The Company has production, development 
and long-term marketing abilities, experience in acquiring properties, and the 
financial resources to enable it to compete effectively.

	The telecommunications business competes in the areas of long distance 
and private line services, and telecommunication equipment sales,  with major 
and regional companies where price competition is intense. Telecommunication 
services are provided in the regional marketplace and it competes effectively 
due to a low cost structure.

	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 97% of 1996 coal sales. The remainder of Rosebud 
coal was sold under spot-market sale agreements and contracts in Michigan, 
Minnesota, North Dakota, Wisconsin and Montana.

	During 1996, Western mined and sold 7,828,347 tons, of which 
2,804,034 tons were sold to the Company.  Western's Rosebud Mine production is 
estimated to be 9,250,000 tons in 1997, as a result of expected Colstrip Units 
3 & 4 increased coal purchases, and 9,250,000 tons in 1998.  However, 
preliminary estimates of hydroelectric generating conditions in the Northwest 
indicate higher than normal stream flows which may impact 1997 coal sales 
volumes.  

	Northwestern's Jewett Mine, located in central Texas, supplies lignite 
under a long-term contract to the two electric generating units, located 
adjacent to the mine, that are owned by Houston Lighting and Power Company. 
Total deliveries in 1996, were 8,508,212 tons.  The estimated production for 
1997 and 1998 are 8,700,000 and 8,600,000 tons, respectively. After 1998, 
production is estimated to be approximately 8,500,000 tons annually.

	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.  NARCO's producing oil and natural gas properties are 
principally located in the states of Wyoming, Colorado, Kansas, Oklahoma and 
Montana.  Altana's and Roan's properties are principally located in the 
Province of Alberta, Canada.  NARCO has entered into agreements to supply 
109,800 Mmcf of natural gas to three co-generation  facilities over a period of 
8 to 14 years with performance guaranteed by Entech, Inc., a wholly owned 
subsidiary of the Company.  NARCO has 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 
14,819 Mmcf, or 28% of Altana's and Roan's natural gas reserves,  are dedicated 
to long-term contracts expiring at various times through 2005. In addition to 
serving these contracts, oil and natural gas operations intends to concentrate 
its efforts on natural gas production in support of the expanding market 
development objectives including adding production in target basins.

	In February 1997, NARCO entered into an agreement to purchase Vessels 
Energy's oil and gas assets in Colorado's Denver-Julesburg (D-J) Basin. With 
this acquisition, NARCO's annual hydrocarbon production in the D-J Basin will 
increase from 3,805 Mmcf of natural gas to 7,275 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. NARCO will own more than 565 wells, operating some 470 of 
them, and also will own and operate an 800-mile gas-gathering system.

	INDEPENDENT POWER OPERATIONS:  Independent power operations develops, 
acquires, operates, and manages facilities and resources to provide 
electricity and other energy-related services.

	Colstrip 4 Lease Management Division sells the Company's 210 megawatt 
share of Colstrip Unit 4 generation to the Los Angeles Department of Water and 
Power and to Puget Sound Power & Light Company (Puget) under contracts which 
are coextensive with the term of the Company's leasehold interest in the Unit.

	CES develops and invests in power projects, and currently holds 
ownership interest 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 independent power project under 
construction in Pakistan.  In addition, CES is participating with others in 
the development of a coal-fired project in India and is actively pursuing 
development and investment opportunities in Brazil.

	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 for private power generating companies and 
provides maintenance services for power plants owned and operated by electric 
utilities.

	See Item 8, "Financial Statements and Supplementary Data - Note 2 to the 
Consolidated Financial Statements" for additional information pertaining to 
litigation involving the Puget contract.

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

	The telecommunications system includes private, dedicated communication 
lines throughout Montana on a digital microwave and fiber network.  Touch 
America is currently expanding 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 network is expected to provide 
full service by mid-1997, offering increased private line service and sales 
options as well as increased long distance service efficiencies.  

EMPLOYEES:

	At December 31, 1996, the Company and its subsidiaries employed 
2,949 persons of which 1,925 were utility employees (including 391 employees at 
the jointly owned Colstrip Units 1-4), and 1,024 Nonutility employees.  

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 imposes a first mortgage lien on 
all physical properties owned, exclusive of subsidiary company assets, and 
certain property and assets specifically excepted.

	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 689,000 kW, and 12 hydroelectric projects, with 
total net median water capability of 508,000 kW.  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 160,000 kW 
wholly-owned Corette Plant.  All of the Utility's Colstrip coal requirements 
are supplied by Western Energy Company 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 20 contracts totaling 409,000 kW of firm 
winter peak capacity.  These contracts vary in type, size, seller and ending 
dates.

	Hydroelectric projects are licensed by the FERC under licenses which 
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 
Item 8, "Financial Statements and Supplementary Data - Note 2 to the 
Consolidated Financial Statements."

	At December 31, 1996, the Utility owned and operated 6,194 miles of 
transmission lines and 15,433 miles of distribution lines.  

	The following table represents average revenues received per kWh by 
customer classification for electricity from all sources for the years 1996, 
1995 and 1994.  

	 Year Ended December 31 
Customer Classification	 1996 	 1995 	 1994 

	Residential		$0.061	$0.059	$0.057
	Commercial		0.055	0.052	0.050
	Industrial		0.041	0.040	0.038
	Sales to Other Parties		0.018	0.021	0.025
	Government and Municipal		0.077	0.073	0.070


	NATURAL GAS PROPERTIES:  The Utility produces natural gas from fields in 
Montana and Wyoming and through its subsidiary, Canadian-Montana Gas Company, 
from fields in southeastern Alberta, Canada.

	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, 1996, the Gas Utility and its subsidiaries owned and 
operated 2,103 miles of natural gas transmission lines and  3,322 miles of 
distribution mains.  

	All natural gas volumes are at a pressure base of 14.73 psia at 
60 degrees Fahrenheit, except for those volumes used to compute the average 
revenues by customer classification.  

	For information pertaining to the Company's net recoverable utility 
natural gas reserves, see Item 8, "Financial Statements and Supplementary 
Data."

	In addition to owned reserves, the Utility at December 31, 1996, 
controlled under purchase contracts, 51,388 Mmcf of proven reserves in the 
United States and 26,724 Mmcf in Canada.  No significant change has occurred 
and no event has taken place since December 31, 1996, that would materially 
affect the magnitude of the Utility's reserve estimates.  

	Utility natural gas reserve estimates have not been filed with any other 
federal or any foreign governmental agency during the past twelve months. 
Certain lease and well data, with respect only to owned wells, are filed with 
the Internal Revenue Service for tax purposes.  

	Total produced, royalty and purchased natural gas volumes in Mmcf during 
the last three years were as follows:  

	         United States        	            Canada            
	Produced	Royalty	Purchased	Produced	Royalty	Purchased

1994		  4,724		230	7,565	3,350	998	2,709
1995		  5,176		632	7,292	4,650	735	3,031
1996		  5,055		230	6,749	4,694	950	4,850

	The following table presents information as of December 31, 1996, 
pertaining to the Utility natural gas wells and the owned or leased acreages in 
which they are located.  

		United States	   Canada  

	Gross productive wells		615  	183  
	Net productive wells		502  	172  
	Gross wells with multiple completions		19  	11  
	Net wells with multiple completions		13.8	10.5

	Gross producing acres		360,978	150,236
	Net producing acres		285,205	134,288
	Gross undeveloped acres		20,601	71,040
	Net undeveloped acres		17,035	65,712

	These acreages are located primarily in Montana and Alberta, Canada.  

	The Company anticipates that during 1997 total exploration and 
development expenditures (expense and capital) will be approximately $600,000 
in the United States and approximately $900,000 in Canada.  

	The following table presents information on Utility natural gas 
development wells drilled during 1996, 1995 and 1994.  No exploratory wells 
were drilled in the periods specified 

	  United States  	     Canada     
		1996 	1995 	1994 	1996	1995	1994

Net productive development
  wells		2.00	12.81	12.38	7.00	4.00	6.00
Net dry development wells		- 	 1.60	  4.00	- 	4.00	1.00

	The following table presents average revenues received per Mcf by 
customer classification for natural gas from all sources for the years 1996, 
1995 and 1994.  Revenues per Mcf are computed based on volumes at varying 
pressure bases as billed.  
		
	 Year Ended December 31 
Customer Classification	 1996 	 1995 	 1994 

	Residential		$4.72	$ 4.74	$ 4.64
	Commercial		4.54	  4.54	  4.43
	Industrial		4.32	  4.33	  4.25
	Other gas utilities		3.41	  3.64	  3.72

	The following table presents the average production cost per Mcf for 
produced utility natural gas, in U. S. dollars, for the three years 1996, 1995 
and 1994.  

		United States	Canada

	1994		$ 1.01	$ 0.40
	1995		1.10	  0.34
	1996		  0.92	  0.32

	Changes in operational practices will cause the price per unit to 
fluctuate.

NONUTILITY OPERATIONS:  

	COAL PROPERTIES:  Western leases and produces coal from Montana 
properties. Northwestern leases and produces lignite from properties in Texas. 
Horizon leases coal properties in Wyoming.  Western SynCoal owns a 50% 
partnership interest in a coal enhancement demonstration plant at Colstrip, 
Montana.  Basin produced coal from properties in Colorado that North Central 
owns and leases.  Basin ceased mining operations in December 1995 and the Mine 
was sealed in 1996.

	Western has coal mining leases covering approximately 528,000,000 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 236,000,000 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 171,400,000 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 154,000,000 tons located in central Texas.  These reserves 
are in close proximity to the Jewett Mine.

	Horizon has surface rights and coal leases which contain approximately 
684,000,000 proved and probable, and recoverable tons of compliance quality 
surface-mineable coal reserves in the southern Powder River coal region located 
near Gillette, Wyoming.  A mining permit application was submitted to the 
Wyoming Department of Environmental Quality in November 1994.  Horizon expects 
to receive the mine permit in the fourth quarter of 1997.  Although property 
development is required by 2002, the Company's plans for mine development are 
not definite.  

	OIL AND NATURAL GAS PROPERTIES: In January 1997, Altana sold its interest 
in nine (9) non-strategic oil and gas fields.  The sale represented 5.2 Mmcf 
(10% of Canadian total) of natural gas, and 731,000 barrels (23% of Canadian 
total) of oil.  

	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 1996, 1995 and 
1994.
<TABLE>
<CAPTION>
			            Year Ended December 31            
			     1996     	     1995     	     1994     
			United		United		United
		States	Canada	States	Canada	States	Canada
<S>                                      <C>     <C>     <C>     <C>     <C>     <C>
Average sales price:  
	Per Mcf of natural gas		$ 1.54	$ 1.10	$ 1.21	$ 0.99	$ 1.60	$ 1.48
	Per barrel of oil		 19.74	 16.88	 16.55	 15.29	 14.75	 12.95
	Per barrel of natural gas liquids		 10.56	14.44	  8.17	 11.33	  9.50	  9.99

Average production cost:
	Per barrel of oil equivalent		$ 3.94	$ 3.10	$ 3.36	$ 2.90	$ 3.00	$ 2.93
</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 1995 to 1996, 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 wellwork and 
maintenance in the Bowdoin Field.  Production from this field began in late 
1996.  Production taxes increased due to higher product prices.  

	Information on the Nonutility natural gas and oil wells and the owned or 
leased acreage in which they are located, as of December 31, 1996, is presented 
below.  
	United   
	   States   		  Canada  

Gross productive natural gas wells	642   	151   
Net productive natural gas wells	416.37	100.46
Gross productive oil wells	234   	194   
Net productive oil wells	210.99	107.95

Gross producing acres	194,518	148,942
Net producing acres	134,457	76,775
Gross undeveloped acres	296,785	227,073
Net undeveloped acres	186,098	153,966

	The wells located in Canada include multiple completions of 8 gross 
productive natural gas wells and 6.70 net productive gas wells.  The wells 
listed above include multiple completions of 19 gross productive natural gas 
wells and 9 gross productive oil wells in the United States, and 11 gross 
productive natural gas wells and 1 gross productive well in Canada.  

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

	It is anticipated that during 1997 total exploration, acquisition and 
development expenditures (expense and capital) will be approximately 
$31,762,000 in the United States and approximately $17,708,000 in Canada.  See 
Item 7, "Management's Discussion and Analysis of Financial Conditions and 
Results of Operations - Liquidity and Capital Resources" for further discussion 
of 1997 capital expenditures.

	The following table presents information on Nonutility oil and natural 
gas exploratory and development wells drilled during 1996, 1995 and 1994.


	   United States    	       Canada       

	 1996 	 1995 	 1994 	 1996 	 1995 	 1994 

Net productive natural gas
	exploratory wells		0.33	 2.99	 1.15	0.55	 0.50	 0.87
Net productive oil
	exploratory wells		-  	 1.00	   -  	2.23	   -  	   -  
Net productive natural gas
	development wells		2.58	 6.23	 6.28	1.83	   -  	 1.06
Net productive oil
	development wells		-  	 1.34	 1.29	9.78	 7.38	 8.67
Net dry exploratory wells		1.75	 2.50	 3.44	.50	 1.69	 2.00
Net dry development wells		1.81	4.24	0.59	.04	 0.50	 3.05

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


	TELECOMMUNICATIONS PROPERTIES:  Touch America has a 4,100 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. Touch 
America is beginning to build its network capacity. During 1996, the Company 
acquired 11 PCS licenses in 12 marketing areas between Minneapolis, Minnesota 
and Seattle, Washington which presents an opportunity for wireless telephone 
service in that region.

	INDEPENDENT POWER PROPERTIES:  Independent power operations sell power 
from the Company's 210 MW Colstrip 4 leased interest and associated common and 
transmission facilities.  They also own or have contract rights in a number of 
Nonutility power generation projects:  
<TABLE>
<CAPTION>
Projects in Operation (As of March 12, 1997):  

				 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	Sweetwater, TX	  49.9%	  255	 128	Texas Utility	U.S. Gypsum
	    (1989)				  Electric Co.
Tenaska-Paris(1)	Paris, TX	  10.0%	  223	  22	Texas Utility	Campbell
 	    (1989)				  Electric Co.	 Soup Co.
Encogen Four	Buffalo, NY	  49.5%	   62	  31	Niagara Mohawk 	Outokumpu
	    (1992)				  Power Corp.	 AmBrass
Lockport(1)	Lockport, NY	  22.3% 	  168	  37	New York State	Harrison
 	    (1993)				  Electric &	 Radiator
					  Gas Corp.
Teesside	United Kingdom	   3.2%(2)	1,725	  56	Various U.K.	    --
	    (1993)				  customers
Tenaska-	Ferndale, WA	  25.1%	  245	  61	Puget Sound	Tosco Corp.
 Ferndale	    (1994)				  Power & Light

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 SHARED OF RATED CAPACITY MW			 383
<FN>
(1)	These co-generation facilities have a long-term contract with NARCO (a 
Nonutility subsidiary) to purchase a portion of their natural gas supply.  

(2)	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	    (3)				 Power Admn

Uch Power	Uch Pakistan	     3.2%	 586	  19	Pakistan Water	None
 Limited	  (1998)				 & Power
					 Department

<FN>
(3)	Construction is approximately 50% complete but has been suspended due to a dispute 
with the Bonneville Power Administration.
</FN>
</TABLE>
<TABLE>
<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	  (4)	 500	 (4)	State of Andhra	None
 Krishnapatnam	  Pradesh				  Pradesh
<FN>
(4)	Not determinable at this time.  
</FN>
</TABLE>


ITEM 3.  LEGAL PROCEEDINGS

	Refer to Item 7, "Management's Discussion and Analysis of Financial 
Condition and Results of Operations - Environmental Issues" and to Item 8, 
"Financial Statements and Supplementary Data - Note 2 to the Consolidated 
Financial Statements" for information pertaining to legal proceedings.  


ITEM 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS  

	None.  


EXECUTIVE OFFICERS OF THE REGISTRANT

The Montana Power Company Officers:  

	In 1992, D. T. Berube, 63, was elected Chairman of the Board and Chief 
Executive Officer.

	On January 23, 1996, R. P. Gannon, 52, was elected Vice Chairman of the 
Board and President.  He had previously served as President and Chief Operating 
Officer - Utility Operations from 1990-1996.  

	In 1996, J. P. Pederson, 54, was elected Vice President Chief Financial 
and Information Officer.  He had previously served as Vice President and Chief 
Financial Officer since 1991.

	In 1996, P. K. Merrell, 44, was elected Vice President, Human Resources 
and Secretary.  She had previously served as Vice President and Secretary since 
1993, and Secretary from 1992-1993.  

	In 1991, M. E. Zimmerman, 48,	was elected Vice President and General 
Counsel.

	On May 15, 1996, D. S. Smith, 53, was elected Controller.  He had 
previously served as Controller for Entech from 1988-1996.

	On May 15, 1996, E. M. Senechal, 47, was elected Treasurer.  She had 
previously served as Vice President and Treasurer for Entech from 1984-1996.  


Energy and Communications Services Division:  

	On January 23, 1996, J. D. Haffey, 51, 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, 51, 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, C. D. Regan, 59, was elected Vice President, Transmission 
Services. He had previously served as Vice President - Natural Gas Supply and 
Transportation 1993-1996. and as Vice President - Energy Services for the 
Utility Division from 1991-1993.  

	In 1996, P. J. Cole, 39, was elected Vice President, Business Development 
and Regulatory Affairs.  He had previously served as Treasurer for the Utility 
Division from 1993-1996, Assistant Treasurer from 1992-1993 and Manager, 
Corporate Financial Planning and Analysis from 1986-1992.

	In 1996, M. J. Meldahl, 47, was elected Vice President, Communication 
Services.  He had previously served as Vice President, Technology Division - 
Entech since 1988.


Energy Supply Division:  

	In 1996, R. F. Cromer, 51, 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, 59, 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, 48, was elected Vice President - Colstrip 
Project Division for the Energy Supply Division.  He had previously served as 
Vice President, Colstrip Project Division since 1995 and as Manager of Business 
and Change Management from 1994-1995.  He was Superintendent of Colstrip Units 
l and 2 from 1988-1994.  

	In 1996, R. P. Madison, 59, 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, 46, was elected Vice President, Coal Operations. 
He had previously served as Vice President, Entech Coal Division from 1992-
1996.  

	In 1996, F. L. Rotondi, 36, was elected Vice President, Business 
Development.  He had previously served as Manager of Business Development - 
Entech since 1989.  



	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 
1996 and 1995.  The number of common shareholders of record on December 31, 
1996, was 40,902.  


				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


				Dividends
				Declared
				   per  
	    1995   	  High  	   Low  	  Share  

	1st quarter	$ 24.125	$ 22.500	$  0.40
	2nd quarter	  23.875	  22.250	   0.40
	3rd quarter	  23.375	  21.125	   0.40
	4th quarter	  23.750	  21.500	   0.40



ITEM  6.  SELECTED FINANCIAL DATA  

The Montana Power Company and Subsidiaries

Balance Sheet Items (000)
			   1996  	   1995  	   1994  
Assets:
	Utility plant		$2,281,395	$2,204,386	$2,071,749
	Less accumulated depreciation 
	  and depletion		   705,119	   663,216	   619,195
		Net Utility plant		 1,576,276	 1,541,170	 1,452,554
	Nonutility property		   666,679	   633,079	   600,299
	Less accumulated depreciation
	  and depletion		   256,489	   252,612	   207,486
	 	Net Nonutility property		   410,190	   380,467	   392,813
		  Total net plant and property		 1,986,466	 1,921,637	 1,845,367
	Other assets		   711,749	   664,454	   667,330
		  Total Assets		$2,698,215	$2,586,091	$2,512,697

Liabilities:
	Common shareholders' equity		$  999,657	$  976,043	$  988,100
	Unallocated stock held by trustee
	  for retirement savings plan		(28,360)	   (30,565)	   (32,580)
	Preferred stock		57,654	   101,416	   101,416
	Mandatorily redeemable preferred
	  securities of trust		65,000
	Long-term debt		633,339	   616,574	   588,876
	Other liabilities		   970,925	   922,623	   866,885
		  Total Liabilities		$2,698,215	$2,586,091	$2,512,697



ITEM  6.  SELECTED FINANCIAL DATA  

The Montana Power Company and Subsidiaries

Balance Sheet Items (000)
			   1993   	   1992   	   1991   
Assets:
	Utility plant		$1,943,428	$1,854,297	$1,774,185
	Less accumulated depreciation 
	  and depletion		   572,141	   533,216	   495,720
		Net Utility plant		 1,371,287	 1,321,081	 1,278,465
	Nonutility property		   596,769	   552,537	   531,455
	Less accumulated depreciation 
	  and depletion		   198,951	   178,275	   156,324
	 	Net Nonutility property		   397,818	   374,262	   375,131
		  Total net plant and property		 1,769,105	 1,695,343	 1,653,596
	Other assets		   616,922	   590,079	   564,450
		  Total Assets		$2,386,027	$2,285,422	$2,218,046

Liabilities:
	Common shareholders' equity		$  945,651	$  902,989	$  862,601
	Unallocated stock held by trustee
	  for retirement savings plan		   (34,419)	(36,098)	(37,631)
	Preferred stock		   101,419	51,984	51,984
	Mandatorily redeemable preferred
	  securities of trust	
	Long-term debt		   571,870	   581,179	   603,266
	Other liabilities		   801,506	   785,368	   737,826
		  Total Liabilities		$2,386,027	$2,285,422	$2,218,046



Income Statement Items (000)
				   1996   	   1995   	   1994   

	Revenues		$  973,208	$  953,224	$1,005,970

	Expenses:
		Operations		   383,789	   420,472	   436,610
		Maintenance		65,390	    68,286	    75,357
		Selling, general and administrative		111,144	   101,872	   106,989
		Taxes other than income taxes		87,903	    89,858	    99,200
		Depreciation, depletion and 
			amortization		88,744	    86,976	    86,711
		Writedowns of long-lived assets (a)		          	    74,297	          
					   736,970	   841,761	   804,867

			Income from operations		236,238	   111,463	   201,103

	Interest expense and other income:
		Interest		48,770	    43,656	    42,817
		Other (income) deductions - net		    (3,893)	   (10,704)	   (10,532)
					44,877	    32,952	    32,285

	Income taxes		    71,975	    21,574	    55,226

	Net income		119,386	    56,937	   113,592
	Dividends on preferred stock		     8,358	     7,227	     7,227

	Net income available for common stock		$  111,028	$   49,710	$  106,365

	Net income per share of common stock:
		Utility operations		$     1.13	$     1.22	$     0.91
		Nonutility operations		      0.90	     (0.30)	      1.09
				$     2.03	$     0.92	$     2.00

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

	Average shares outstanding (000)		54,634	    54,121	    53,125


(a)	Refer to Item 8, "Financial Statements and Supplementary Data - Note 12 	
		to the 	Consolidated Financial Statements."



Income Statement Items (000)
				   1993   	   1992   	   1991   

	Revenues		$1,024,285	$  943,872	$  889,254

	Expenses:
		Operations		   476,733	   412,387	   365,597
		Maintenance		    70,029	    70,525	    70,510
		Selling, general and administrative		   104,900	    91,230	    92,126
		Taxes other than income taxes		    92,430	    94,328	    86,428
		Depreciation, depletion and 
			amortization		    82,696	    81,732	    75,782
		Writedowns of long-lived assets		          	          	          
					   826,788	   750,202	   690,443

			Income from operations		   197,497	   193,670	   198,811

	Interest expense and other income:
		Interest		    48,023	    49,166	    52,897
		Other (income) deductions - net		   (11,857)	    (8,200)	   (10,194)
					    36,166	    40,966	    42,703

	Income taxes		    54,120	    45,639	    50,393

	Net income		   107,211	   107,065	   105,715
	Dividends on preferred stock		     4,353	     3,790	     3,790

	Net income available for common stock		$  102,858	$  103,275	$  101,925

	Net income per share of common stock:
		Utility operations		$     1.07	$     0.97	$     0.98
		Nonutility operations		      0.91	      1.05	      1.05
				$     1.98	$     2.02	$     2.03


	Dividends declared per share of
  	common stock		$    1.585	$     1.55	$    1.495


	Average shares outstanding (000)		    52,040	    51,126	    50,317



ITEM  7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
		AND RESULTS OF OPERATIONS

Results of Operations:  

	The following discussion presents significant events or trends which have 
had an effect on the operations of the Company during the years 1994 through 
1996 or which are expected to have an impact on operating results in the 
future.

	In May 1996, the Company began  managing its operations as a restructured 
company with two divisions:  Energy Supply, and Energy and Communications 
Services.  Pending regulatory decisions pertaining to the Company's 
restructuring, the discussions and financial information which follow are 
presented in a Utility and Nonutility format.


Safe Harbor for Forward-Looking Statements:

	The Company is including the following cautionary statements to make 
applicable and take advantage of the safe harbors 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" 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 and changes in the utility industry. 
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.


Net Income Per Share of Common Stock:  

The Company's net income available for common stock increased to 
$111,028,000 in 1996 compared to $49,710,000 and $106,365,000 in 1995 and 1994, 
respectively.  The following table shows the sources of consolidated net income 
on a per share basis.  


		 1996 	 1995 	 1994 

	Utility Operations	$ 1.13	$ 1.22	$ 0.91
	Nonutility Operations	  0.90	 (0.30)	  1.09

		$ 2.03	$ 0.92	$ 2.00

	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.

	The decrease in 1995 consolidated net income was largely due to a 
90-cent-per-share charge related to the writedown of an investment in the 
Golden Eagle Mine in Colorado, the adoption of SFAS No. 121 and the March 1995 
arbitration decision that lowered the price of coal sold to Colstrip Units 1 
and 2.  The lower price, retroactive to July 1991, benefited Utility operations 
by 13 cents per share through lower fuel costs, but reduced Nonutility earnings 
by 18 cents.

	Utility operations also benefited in 1995 from the availability of low-
cost hydroelectric power in the regional energy market, displacing higher cost 
thermal energy. The availability of this low-cost power negatively impacted 
Nonutility earnings due to reduced coal sales to the Colstrip units. The 
expiration of a Midwestern coal contract in 1994 and the absence of independent 
power development fees also contributed to the decline in 1995 Nonutility 
earnings. Increased income from independent power operating projects partially 
offset that decrease. 




<TABLE>
<CAPTION>
			        UTILITY OPERATIONS
			      Year Ended December 31        
			   1996   	   1995   	   1994   
			       Thousands of Dollars
<S>                                                 <C>          <C>          <C>
ELECTRIC UTILITY:

REVENUES:
	Revenues		$  430,171	$  421,999	$  427,686
	Intersegment revenues		     5,793	     5,813	     5,924
				435,964	   427,812	   433,610

EXPENSES:
	Power supply		136,817	   148,240	   178,927
	Transmission and distribution		30,263	    26,916	    27,566
	Selling, general and administrative		52,091	    41,932	    46,134
	Taxes other than income taxes	 	46,191	    43,302	    42,214
	Depreciation and amortization		    48,479	    42,506	    40,699
				   313,841	   302,896	   335,540

	INCOME FROM ELECTRIC OPERATIONS		122,123	   124,916	    98,070

NATURAL GAS UTILITY:  

REVENUES:
	Revenues (other than gas supply
		cost revenues)		107,782	    93,453	    88,914
	Gas supply cost revenues		20,746	    21,660	    18,191
	Intersegment revenues		       649	       852	       917
				129,177	   115,965	   108,022

EXPENSES:
	Gas supply costs		20,746	    21,660	    18,191
	Other production, gathering and exploration		9,335	     9,643	     8,882
	Transmission and distribution		11,711	    10,934	    10,154
	Selling, general and administrative		18,684	    17,161	    17,669
	Taxes other than income taxes		15,722	    14,841	    13,708
	Depreciation, depletion and amortization		    12,149	    10,793	     9,842
				    88,347	    85,032	    78,446

	INCOME FROM GAS OPERATIONS			40,830	    30,933	    29,576

INTEREST EXPENSE AND OTHER INCOME: 
	Interest		46,663	    44,031	    43,013
	Other (income) deductions - net		      (402)	    (5,419)	    (3,947)
				    46,261	    38,612	    39,066

INCOME BEFORE INCOME TAXES		116,692	   117,237	    88,580

INCOME TAXES		    46,687	    44,047	    33,171

UTILITY NET INCOME		$   70,005	$   73,190	$   55,409
</TABLE>



UTILITY OPERATIONS:

	The Company is a winter-peaking utility, which earns most of its revenue 
from retail customers in the first and fourth quarters of the year.  Weather 
can significantly affect revenues and net income, and should be considered when 
analyzing trends.  As measured by heating degree days, a unit measuring the 
extent to which the average daily temperature falls below 65  Fahrenheit, the 
temperatures in 1996 in the Company's service territory were 12% colder than 
1995 and 11% colder than the historic average.  Temperatures in 1995 were six 
percent colder than 1994 and equal to the historic average.  

	The Company's electric wholesale revenues and power purchase expenses are 
influenced by weather, streamflow conditions and the wholesale power market in 
the Northwest and California.  During the year ended December 31, 1996, there 
was a surplus of energy in the region which caused lower wholesale and 
purchased-power prices. February 1997 forecasts for Montana streamflows predict 
water volumes for the April to September period to be about 150% of average. 
Higher than average runoff is also predicted for the Columbia River Basin. The 
resulting hydroelectric generation will put more energy into the market as well 
as displace some thermal generation.

	Since 1994, Utility employment, through targeted and voluntary staff 
reductions, under a severance plan, has been permanently reduced by 
approximately 450 positions.


Competitive Environment:

	The electric and natural gas utility businesses are in transition as 
competition to provide energy commodity and related services to wholesale and 
retail customers intensifies.  The Company has taken a proactive approach to 
these industry changes and has restructured to better align its business 
functions with markets.  Although the Company's principal business is its 
utility operations, it received only 58% of its 1996 revenues and 59% of its 
1996 net income from those operations.  The remaining revenue and net income 
was provided by its diverse Nonutility businesses involved in coal, oil and 
natural gas, independent power and telecommunications operations. The 
Company's hydroelectric and thermal units have low operating costs that should 
allow it to compete effectively with other power generators. Issues remain to 
be addressed, however, in the transition to a competitive power-supply 
marketplace.  These issues focus primarily on the recovery of the Company's 
transition costs relating to certain power-purchase contracts, regulatory 
assets, electric generating facilities and other items.  While the Company 
does not have an unusually large amount of regulatory assets compared to other 
utilities, it does have regulatory assets to be recovered.  The Company, under 
the Public Utility Regulatory Policy Act (PURPA), entered into a number of 
long-term purchase-power contracts from qualifying facilities (QF's) under 
which the prices paid for power are now substantially above market.  While the 
Company's generation assets are low cost nationally, they will have to compete 
with a surplus power-supply market in the Northwest.  (For further information 
pertaining to regulatory assets and QF contracts, see Item 8, "Financial 
Statements and Supplementary Data - Notes 1 and 3 to the Consolidated 
Financial Statements.")  A variety of activities, which are detailed below, 
will help the Company manage change and position itself for the future.

Wholesale --

	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, among other things, 
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 filed open-access transmission tariffs with FERC in November 
1995. To fully conform to FERC Order No. 888 the Company refiled its tariffs 
and separated its transmission and generation functions 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.

	During January 1997, the Company created, with FERC's approval, an 
affiliated power marketing subsidiary, MP Energy. MP Energy is pursuing 
opportunities that emerge as the result of utility industry restructuring. MP 
Energy is focused on new energy markets outside of the Company's traditional 
utility boundaries, primarily in the western half of the United States and the 
upper Midwest. MP Energy targets wholesale and large industrial customers 
which have been granted the right, either by state or federal agencies, to 
pursue other sources for their electricity and natural gas supplies. Any gains 
or losses realized by the purchase and resale of energy in the unregulated 
market will pass to the shareholders. Any gains realized through brokering 
Utility surpluses will benefit general business customers of the regulated 
Utility.

	The Company has joined a group of other Pacific Northwest electric 
utilities in a memorandum of understanding to study the formation of an 
independent grid operator called "IndeGo" for the utilities' high-voltage 
transmission lines. The grid operator would be independent of the utilities, as 
required by FERC. IndeGo, though still in its development stage, is intended to 
ensure the reliability of the regional transmission grid, to provide non-
discriminatory, open-access to electric transmission facilities in compliance 
with recent FERC rulings and to help facilitate the operation of an evolving 
competitive electric power market. The group, which continues to add new 
members, intends to file a proposal with FERC and state regulators during 1997 
and operation is expected to commence during 1999. Through IndeGo, the group of 
utilities expects to increase the efficiency of their transmission systems and 
provide improved access for scheduled electricity transactions in Oregon, 
Washington, Idaho, Montana, Wyoming, Utah, Colorado and northern Nevada.

	The Electric Utility currently competes with other utilities, marketers 
and independent power producers in the wholesale market. 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, provides an example of the growing competition for wholesale 
customers. Central terminated its contract with the Company, effective June 
2000, and is seeking competitive bids to replace the energy. Central's 120 MW 
load accounts for six percent of the Company's system load. The Company and 
other electric suppliers are currently in the process of bidding for the 
cooperatives' power requirements beyond June 2000. The Company plans to make 
an application to FERC for recovery of costs which will be stranded by the 
termination of this contract.

	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 gas operations. The Company believes that the 
combination of these experiences should give it an advantage in the 
competitive environment.

Retail --

	The Electric Utility does not yet face direct competition from other 
electric suppliers in its retail market. During the past ten years, the 
Company has sold approximately 30% of its system load to 16 contract 
industrial customers. These sales and others are expected to be impacted by 
competition in the future. The Company already has instituted Real Time 
Pricing and Time of Use rate offerings in an attempt to bring market-like 
rates to existing customers.

	In open competition with two other utilities, the Company has 
successfully secured a new retail industrial load of approximately 100 MW, 
which will come on line in 1998. The acquisition of this load was dependent 
upon an offer of a market-based rate. This customer's rate has been approved 
by the Montana Public Service Commission (PSC). The Company has applied to the 
PSC for a generic market-based rate offering to allow the Company to compete 
for new loads that arise between now and a PSC-approved transition to retail 
competition for all customers.

	The Company is promoting a transition to retail competition over the 
next several years. The Company has legislative proposals before the current 
session of the Montana Legislature to open up the Utilities' electric and 
natural gas supply functions to full competition by mid-2002.

	The proposed electric legislation provides for a transition to choice 
for all customers; large-customer choice occurring on July 1, 1998 and small 
commercial and residential customer choice occurring no later than July 1, 
2002. Residential and small-commercial pilot programs are expected to be 
provided beginning July 1, 1998. Functional separation of supply, transmission 
and distribution, with no forced divestiture of assets, is proposed. 
Transmission and distribution would remain regulated.  The proposed 
legislation would allow for the recovery of transition costs, specifically 
recovery of above-market QF costs and regulatory assets and a four-year 
recovery period for Utility-owned above-market generation costs. Transition 
bond financings would be used to lower transition costs. The legislation also 
proposes the role the PSC will have in regulating distribution services, 
licensing electricity suppliers in the state, and promulgating rules regarding 
anticompetitive and abusive practices. Finally, the legislation provides for 
reciprocity between utility companies. The ultimate disposition of this 
legislation is uncertain, but some form of retail competition in Montana now 
appears inevitable. 

	The proposed natural gas legislation is similar in form to the electric 
legislation, but unique to natural gas utility service. In parallel with the 
legislative actions proposed by the Company, the Gas Utility filed a formal 
open-access and reorganization plan with the PSC in July 1996. This plan calls 
for the transfer of all producing assets to an unregulated affiliate and the 
retention of regulation for transmission, storage and distribution functions. 
The movement to choice for all customers is proposed to be completed by mid-
2002, starting immediately for all customers with loads in excess of 
5,000 decatherms per year who will have the opportunity to buy their supply 
from their choice of natural gas supplier for the 1997-1998 heating season, 
with smaller users transitioning over the five year period. The procedural 
schedule for this filing has been suspended subject to continuing settlement 
efforts among the parties to the filing. Substantial progress has been made 
toward agreement in several areas. Hearings on the agreed-to items begin in 
late March 1997.  The procedure schedule on the remaining unsettled matters is 
anticipated to begin in early May 1997 after the legislative proposals are 
decided.  

	The Gas Utility has provided open-access to large customers 
(60,000 Mcf's and above) since 1991 and expects to further open the system to 
provide choice to all retail customers and to concentrate on the regulated 
transmission, storage and distribution businesses. The Company is proposing to 
transfer the Utility's existing production assets to an unregulated affiliate. 

	The Company submitted an Electric Utility "informational filing" to the 
PSC in December 1996 that outlines the Company's restructuring plan, the 
movement of generation to full competition, and an estimate of transition 
costs together with the mechanisms for collection of these costs. Depending on 
the outcome of the Montana electric retail open-access legislation, the 
Company will update its December informational filing converting it to a 
formal submission to the PSC that proposes full unbundling of services and 
market-based rates for electric supply.

	The Company has also created a new unregulated energy services 
subsidiary, Montana Energy Services Company, to focus on activities associated 
with the selling of retail energy-related products and services in a 
competitive marketplace. This may include, among other things, assisting 
customers with utility rate management; managing power contracts; installing 
energy-efficient equipment; and tracking facility energy use and costs. This 
subsidiary was created to more clearly separate the more competitive, retail 
markets planned for this company from ongoing regulated Demand Side Management 
activities.


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 addressed in the 
transition process or they would be eliminated from the balance sheet and 
included in income in the period when the discontinuation occurred.  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.  For further information pertaining 
to SFAS No. 71, see Item 8, "Financial Statements and Supplementary Data - 
Note 1 to the Consolidated Financial Statements."


Summary of Significant Regulatory Matters:

	Effective July 1, 1996, the PSC approved a rate plan for the Electric 
Utility, affirming a settlement negotiated with the Montana Consumer Counsel 
and the Large Customer Group, which increased revenues 4.2% or $14,800,000 
annually. This increase includes $5,800,000 which had previously been approved 
on an interim basis, effective March 1, 1996. The plan also includes revenue 
increases of 2.4% or approximately $8,800,000 on January 1, 1997 and 2.4% or 
approximately $9,000,000 on January 1, 1998. The PSC's final order was based 
on an 11% return on common equity.  Actual earnings in excess of 11.4% return 
on common equity will be shared on a 50% basis between ratepayers and 
shareholders.

	The rate order also included the approval of a natural gas revenue 
increase which was designed to increase revenues 5.3% or $6,700,000 annually, 
effective July 1, 1996. This increase includes $3,100,000 which had been 
included in rates on an interim basis, effective March 1, 1996. The increase 
was based on an 11.25% return on common equity.

	In July 1996, the Company filed a natural gas rate case requesting an 
increase in natural gas revenues of $4,800,000 or 3.8% annually to recover 
increased costs of service and to facilitate the Gas Utility's restructuring 
plan. The plan proposes a transportation eligibility threshold lower than the 
current 60,000 Mcf's per year, thereby increasing the number of customers 
eligible to choose their own suppliers. Within five years, all customers would 
have this choice. The plan requests the recovery of all Gas Utility 
investment. Settlement meetings are in progress currently and the Company 
cannot predict when a decision will be rendered.

	On November 21, 1996, the Company filed its annual gas tracking filing 
which resulted in a total annual adjustment decrease of $2,260,000, reflecting 
lower gas costs and other tracking activities offset by the end of 
price-reduction amortizations approved in previous filings.  Rates reflecting 
this filing were effective for service on and after December 1, 1996.  

	As discussed previously in "Competitive Environment", the Company also 
filed an informational electric restructuring plan with the PSC on 
December 20, 1996.  


Electric Utility:  

1996 Compared to 1995

	Excluding the impact of the coal arbitration decision recorded during 
1995, income from electric operations benefited from increased tariffs, colder 
weather, continued customer growth and reduced power supply expenses offset by 
increased selling, general and administrative (SG&A), depreciation and taxes 
other than income tax expenses.


Revenues:

	The following table shows year-to-year changes for the previous two 
years, in millions of dollars, in the various classifications of electric 
revenues, and the related percentage changes in volumes sold and prices 
received:  
	   1996   	   1995   

	General business	- revenue	$    13	$    12
		- volume	    (2)%	     (1)%
		- price/kWh	     6 %	      4 %

	Other utilities	- revenue	$	(6) 	$   (16)
		- volume	     3 %	     (5)%
		- price/kWh	   (12)%	    (17)%

	Miscellaneous	- revenue	$     1		$    (2)

	Total operating revenues increased two percent or $8,100,000. Residential 
and commercial customer revenues were up approximately $24,500,000 or 11%, 
primarily as a result of a six percent increase in volumes sold due to colder 
weather and two percent customer growth, along with increased tariffs. 
Partially offsetting the increase was a decrease of $12,000,000 in revenues 
from the industrial class principally due to a large retail customer closing 
operations in December 1995. The customer was served under an interruptible 
economic retention rate that was lower than the tariff rate.

	Wholesale energy sales declined approximately $6,000,000 over 1995, 
primarily due to the expiration of two firm sales contracts, one in late 1995 
and the other in early 1996. The decrease was partially offset by increased 
non-firm or secondary volumes sold, offset by lower regional energy prices. 

	An increase in miscellaneous revenue resulted primarily from higher 
wheeling rates.

Expenses:

Power Supply:

	The following table shows the Company's sources of electricity and power-
supply expenses (operation, fuel for electric generation and maintenance) for 
1996 and 1995:	

	    1996   	    1995   
Sources	             MWh's           

Hydroelectric		4,064,083	3,479,506
Steam		4,271,701	4,754,489
Purchases and Other		  2,557,460	  2,666,885
  Total Power Supply		 10,893,244	 10,900,880

Expenses	    Thousands of Dollars     

Hydroelectric		$    19,423	$    19,291
Steam		47,185	44,010
Purchases and Other (a)		     70,209	     84,939
  Total Power Supply Expenses		$   136,817	$   148,240
  Cents per Kilowatt-Hour		      1.256	      1.360

 (a)	Includes energy and capacity payments on purchased power contracts.  

	Excluding the impact of the coal arbitration decision that reduced 1995 
steam expenses $11,300,000, power-supply expenses decreased $22,700,000. Better 
streamflow conditions caused increases in Utility and regional low-cost 
hydroelectric generation resulting in displacement of higher cost thermal 
generation. Shorter maintenance periods, improved productivity and permanent 
employee reductions at the Colstrip units also decreased steam expense. 
Purchased power costs declined due to the expiration of two higher priced firm 
contracts and a $3,600,000 credit from a party who delivers energy to the 
Company's customers. The decrease was partially offset by increased purchases 
of lower cost non-firm power and additional payments to independent power 
producers.

Other Expenses:

	Transmission and distribution expense increased as a result of 
non-recurring items. SG&A increased primarily due to approximately $4,100,000 
of expense recorded in the fourth quarter of 1996 related to permanent employee 
reductions. As a result of the reduced payroll costs at the Colstrip plants, 
SG&A costs allocated to the non-operating owners decreased from 1995 causing a 
variance of approximately $1,800,000. Also contributing to the increase was 
approximately $1,200,000 of insurance proceeds received in 1995 that were 
absent from 1996 expenses. The increase in taxes other than income taxes was 
due to increased property taxes resulting from property additions and higher 
mill levies. Depreciation expense increased as a result of greater plant 
investment and a change in the PSC-approved depreciation rate. See Liquidity 
and Capital Resources for further discussion.

1995 Compared to 1994

	Income from electric operations increased significantly over 1994 
primarily the result of reduced power-supply costs, partially offset by a 
decrease in operating revenues. Power-supply costs decreased due to the 
previously discussed coal arbitration decision and reduced purchased-power 
costs resulting from a 16% increase in low-cost hydroelectric generation and 
reduced brokering transactions.

Revenues:

	Revenue from  general business customers increased largely as a result 
of higher tariffs.  Continued customer growth in the residential and 
commercial markets, and colder temperatures resulted in increased sales to 
these customer classes.  Industrial volumes declined, however, due to 
reductions in production by several customers, a 25% decrease in irrigation 
loads due to cooler temperatures and increased precipitation, and the loss of 
a large industrial customer.

	Favorable hydroelectric generating conditions throughout the Northwest 
kept energy prices below their 1994 levels all year, reducing  revenues from 
the off-system sales market. Volumes sold decreased 150,000 MWhs from 1994.

	Miscellaneous revenues decreased primarily as a result of regulatory 
accounting entries.


Expenses:  

Power Supply:

	The following table shows the Company's sources of electricity and power-
supply expenses (operation, fuel for electric generation and maintenance) for 
1995 and 1994:	


	   1995    	   1994    
Sources	             MWh's             

Hydroelectric		  3,479,506	   2,999,396
Steam		  4,754,489	   4,909,852
Purchases and Other		  2,666,885	  3,193,522
  Total Power Supply		 10,900,880	 11,102,770


Expenses			      Thousands of Dollars    

Hydroelectric		$    19,291	$    18,395
Steam		     44,010	     61,385
Purchases and Other (a)		     84,939	     99,147
  Total Power Supply Expenses		$   148,240	$   178,927
  Cents per Kilowatt-Hour		      1.360	      1.612

(a)	Includes energy and capacity payments on purchased power contracts.  

	Power-supply costs decreased $30,700,000 during 1995.  Of this decrease, 
steam generation expenses accounted for $17,400,000, including a $15,200,000 
reduction in fuel costs which resulted primarily from an arbitration decision 
that reduced the price of coal sold by Western Energy Company to Colstrip 
Units 1 and 2 and the Corette Plant.  This price decrease was retroactive to 
July 1991, and 1995 steam expenses included an $11,300,000 credit for coal 
purchased in prior years.  Reduced tonnage and lower prices associated with 
1995 coal purchases accounted for the remaining $3,900,000 reduction in fuel 
costs.  In addition, improved productivity and maintenance practices at the 
Colstrip generating units decreased generation maintenance expense by 
$2,000,000.

	Lower purchased-power expenses, net of demand side management 
amortizations, contributed $14,200,000 to the reduction in power supply costs. 
This reduction was made possible by the increased generation provided by the 
Utility's hydroelectric facilities and reduced volumes sold to other 
utilities.

Other Expenses:

	SG&A expenses decreased primarily due to a reimbursement received in 
1995 from insurers for Colstrip housing repair costs which had been expensed 
in 1994 and lower pension costs. The increase in taxes other than income taxes 
was due to increased property taxes resulting from property additions. 
Depreciation and amortization expense increased as a result of additional plant 
and property in service.


Natural Gas Utility:

1996 Compared to 1995

	Income from natural gas operations increased primarily due to increased 
volumes sold as the result of colder weather, customer growth and higher 
tariffs.

Revenues:

	The following table shows year-to-year changes for the previous two 
years, in millions of dollars, in the full-requirement customer classification 
of natural gas revenues, and the related percentage changes in volumes sold and 
prices received:  

			  1996  	  1995   
	Full-requirement
	  customers	-revenue	$   13	$    4
		-volume	    12 %	     6 %
		-price/Mcf	     4 %	     -


	Natural gas revenues (other than gas supply cost revenues) increased as a 
result of increased volumes sold due to weather 12% colder than 1995, a 3.6% 
increase in the number of residential and commercial customers and higher 
tariff rates.

Expenses:

	SG&A expense increased primarily due to the recording of approximately 
$1,000,000 of expense in the fourth quarter of 1996 related to permanent 
employee reductions. Depreciation expense increased for the same reasons 
mentioned in the Electric Utility discussion.

1995 Compared to 1994

	Income from natural gas operations increased principally due to increased 
volumes sold as a result of colder weather, and residential and commercial 
customer growth.

Revenues:

	Natural gas revenues (other than gas supply costs) increased due to 
customer growth of four percent in the residential and commercial markets and 
temperatures six percent colder than 1994.

	Gas supply cost revenues consist of the amount authorized by the PSC to 
be collected in rates from full-requirement customers to cover the cost of gas 
supplied.  The increase in gas supply cost  revenues is attributed to the 
following factors: increased volumes sold, a refund made in 1994 for over-
collection of prior years' costs and a decrease in price.  Gas supply cost 
revenues and gas supply cost expenses are always equal due to rate and 
accounting procedures. 



Expenses:

	The increase in gas supply costs resulted from the reasons mentioned in 
the foregoing gas supply cost revenue discussion. The increase in taxes other 
than income taxes was due to increased property taxes resulting from higher 
mill levies and property additions.  


Interest Expense and Other Income, and Income Taxes:

	The change in interest expense from 1994 to 1996 is primarily the result 
of refinancing long-term debt at lower interest rates, partially offset by 
increased average borrowings. In addition, there was an increase in 1996 
interest expense due to a decrease in the amount capitalized on construction 
projects. Other income changed in 1996 and 1995 due to separate non-recurring 
events. Income taxes increased due to higher before-tax net income and a higher 
1996 effective tax rate due to regulatory accounting related to deferred income 
taxes on depreciation. 



<TABLE>
<CAPTION>
	
	NONUTILITY OPERATIONS
	       Year Ended December 31       
			   1996   	   1995   	   1994   
			Thousands of Dollars
<S>                                                 <C>          <C>          <C>
COAL:

REVENUES:
	Revenues		$ 163,901	$ 207,451	$ 252,507
	Intersegment revenues		   31,448	   25,659	   42,201
			195,349	   233,110	   294,708

EXPENSES:
	Operations and maintenance		115,859	   155,149	   169,259
	Selling, general and administrative		21,373	    28,211	    29,463
	Taxes other than income taxes		20,883	    27,210	    37,733
	Depreciation, depletion and amortization		5,653	    11,187	    12,649
	Writedowns of long-lived assets		         	   55,103	         
			  163,768	  276,860	  249,104

	INCOME (LOSS) FROM COAL OPERATIONS		31,581	   (43,750)	    45,604

OIL AND NATURAL GAS:  

REVENUES:
	Revenues:		124,553	   100,030	    97,994
	Intersegment revenues		      272	      409	      254
			124,825	   100,439	    98,248
EXPENSES:
	Operations and maintenance		76,975	    60,526	    54,283
	Selling, general and administrative		10,152	     9,320	     8,514
	Taxes other than income taxes		2,931	     2,334	     3,340
	Depreciation, depletion and amortization		17,080	    17,569	    18,464
	Writedowns of long-lived assets		         	   19,194	         
			  107,138	  108,943	   84,601
	INCOME (LOSS) FROM OIL AND
		NATURAL GAS OPERATIONS		17,687	    (8,504)	    13,647

INDEPENDENT POWER:  

REVENUES:
	Revenues		75,322	    79,095	    93,647
	Earnings from unconsolidated investments		21,174	     2,622	     2,080
	Intersegment sales		    1,426	      796	    1,461
			97,922	    82,513	    97,188
EXPENSES:
	Operations and maintenance		64,274	    68,300	    75,080
	Selling, general and administrative		5,223	     3,557	     4,088
	Taxes other than income taxes		1,783	     1,831	     1,916
	Depreciation, depletion and amortization		    3,793	    3,176	    3,112
			   75,073	   76,864	   84,196

	INCOME FROM INDEPENDENT POWER OPERATIONS		$  22,849	$   5,649	$  12,992


			           NONUTILITY OPERATIONS
			       Year Ended December 31       
			   1996   	   1995   	   1994   
			        Thousands of Dollars

TELECOMMUNICATIONS:

REVENUES:
	Revenues		$  27,341	$  23,247	$  20,723
	Intersegment revenues		      433	      377	      138
			27,774	    23,624	    20,861

EXPENSES:
	Operations and maintenance		18,316	    15,520	    14,316
	Selling, general and administrative		5,499	     4,688	     4,240
	Taxes other than income taxes		392	       343	       287
	Depreciation, depletion and amortization	 	      911	      803	      762
			   25,118	   21,354	   19,605

	INCOME FROM TELECOMMUNICATIONS OPERATIONS.		2,656	    2,270	    1,256

OTHER OPERATIONS:

REVENUES:
	Revenues		1,185	     2,647	     3,441
	Intersegment revenues		      782	      699	      649
			1,967	     3,346	     4,090
EXPENSES:
	Operations and maintenance		1,206	     1,607	     2,471
	Selling, general and administrative		1,569	       849	       477
	Depreciation, depletion and amortization		      679	      942	    1,183
			    3,454	    3,398	    4,131

	LOSS FROM OTHER OPERATIONS		(1,487)	       (52)	       (41)

INTEREST EXPENSE AND OTHER INCOME:  
	Interest		4,810	     4,494	     1,447
	Other (income) deductions - net		   (6,193)	  (10,155)	   (8,228)
			   (1,383)	   (5,661)	   (6,781)

INCOME (LOSS) BEFORE INCOME TAXES		74,669	   (38,726)	    80,239

INCOME TAXES		   25,288	  (22,473)	   22,056

NONUTILITY NET INCOME (LOSS)		$  49,381	$ (16,253)	$  58,183

</TABLE


NONUTILITY OPERATIONS:

	On February 21, 1997, the Company and Puget Sound Power & Light Company 
settled all outstanding disputes related to a power-purchase contract and coal-
purchase contracts.  The Company estimates the settlement will reduce future 
consolidated revenues by $11,000,000 to $13,000,000 per year, before 
anticipated efficiency gains.  See Item 8, "Financial Statements and 
Supplementary Data - Note 2 to the Consolidated Financial Statements" for 
further information.  

Coal Operations:  

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 the effects of those 
items, income from coal operations for 1996 decreased as a result of lower 
sales to Colstrip Units 3 and 4, the expiration of a Midwestern contract in 
December 1995 and decreased miscellaneous coal sales.

Revenues:  

	Excluding a non-recurring charge of approximately $20,700,000 recorded in 
1995 as a result of the Colstrip Units 1 and 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 and 4 also decreased 
$13,400,000 due to a 22% decline in volumes sold as a result of these units 
being taken off line during the first and second quarters of 1996 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 increase in Jewett Mine volumes sold was offset by reduced reimbursable 
mining expenses, resulting in a $600,000 revenue decrease.

Expenses:  

	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 Company acquired the Golden Eagle Mine in 1991.  The mine incurred 
after-tax losses of $9,500,000 in the first nine months of 1995, and 
$7,800,000 and $4,300,000 in 1994 and 1993, respectively. 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.  In an effort to solve these problems, $1,100,000 was 
invested in 1994 and an additional $7,100,000 was invested in 1995.  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; most of the salvageable plant and equipment was 
sold or is under agreement to be sold. The disposition of these assets has 
been charged against the estimated loss provision which was established in 
1995.  See Item 8, "Financial Statements and Supplementary Data - Note 12 to 
the Consolidated Financial Statements" for further discussion of asset 
impairment.

1995 Compared to 1994

	The net loss from coal operations resulted from the writedown of the 
investment in the Golden Eagle Mine, the implementation of SFAS No. 121, the 
results of the Colstrip Units 1 and 2 coal arbitration decision, the 
expiration of a Midwestern coal contract and decreased sales to Colstrip Units 
3 and 4 due to the increased availability of low-cost hydroelectric power in 
the region.

Revenues:

	Revenues, including intersegment revenues, decreased primarily at the 
Rosebud Mine.  Revenues from sales to Colstrip Units 1 and 2 and the Company's 
Corette Plant decreased $27,000,000 as a result of the Colstrip Units 1 and 2 
coal arbitration decision in 1995. Of this amount, $20,700,000 resulted from 
sales between July 1991 and December 1994.  Coal volumes sold decreased 
2,200,000 tons from a combination of the expiration of a Midwestern contract 
at the end of 1994 and fewer tons sold to Colstrip Units 3 and 4 due to the 
displacement of generation by lower cost hydroelectric generation. Revenues 
decreased $11,600,000 due to the Midwestern contract expiration at the end of 
1994 and $8,300,000 from Colstrip Units 3 and 4. Revenues decreased $5,000,000 
due to the conclusion of coal brokering agreements in December 1994.  Brokered 
coal was sold at cost.  At the Jewett Mine, revenues increased $1,000,000 as a 
net result of a $3,000,000 increase from reimbursable mining expenses related 
to higher royalty costs and land damage settlement payments, offset by 
$2,000,000 decreased revenues as a result of reduced volumes sold.  Golden 
Eagle Mine revenues decreased $10,700,000 as a result of lower volumes 
available for sale due to production problems and the inclusion of fourth 
quarter revenues in the writedown of the investment in the mine.  

Expenses:

	The decrease in cost of sales includes $13,500,000 decreased mining 
costs at the Rosebud Mine due to lower volumes sold, decreased royalties 
resulting from lower coal revenues, and the expiration of coal brokering 
agreements.  Operating costs at the Golden Eagle Mine decreased $3,400,000 
because the fourth quarter costs were included in the writedown of the 
investment.  The decreased costs at the Rosebud and Golden Eagle Mines were 
partially offset by $3,000,000 increased costs at the Jewett Mine due to the 
reasons mentioned above. Taxes other than income taxes decreased as a result 
of lower Rosebud Mine coal revenues.

	As mentioned in the 1996 discussion, the Company wrote down its 
investment in the Golden Eagle Mine by $46,500,000 before taxes in the fourth 
quarter of 1995.

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:  

			 1996 	 1995  

Oil		-revenue	$   3	$   1
		-volume	    2%	   (8)%
		-price/bbl	   15%	   17 %

Natural gas	-revenue	$  20	$   1
		-volume	   14%	   10 %
		-price/Mcf	   10%	   (8)%

Miscellaneous	-revenue	$   2	    -	


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.

Revenues:

	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.

Expenses:

	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.

1995 Compared to 1994

	The implementation of SFAS No. 121, effective October 1, 1995, is the 
primary cause of the loss from oil and natural gas operations. Lower margins 
on oil and natural gas production were offset in part by increased income from 
natural gas marketing.

Revenues:

	Higher market prices increased oil revenues $1,000,000. However, 
declining field production and property dispositions in Canada decreased oil 
volumes sold. A combination of lower market prices, and lower volumes produced 
and sold in the U.S. and Canada decreased natural gas revenues $9,700,000. The 
lower volumes were principally a result of well shut-ins that occurred due to 
capacity constraints in Canada. Sales of purchased gas increased $10,800,000 
due to higher volumes sold under short-term agreements and higher prices 
received on gas sold under co-generation supply agreements.

Expenses:

	Higher volumes of natural gas purchased for resale increased the cost of 
sales by $5,500,000.  Taxes other than income taxes decreased as a result of 
lower natural gas revenues.


Independent Power Operations:  

1996 Compared to 1995

	Independent power operations net income for 1996 increased primarily from 
continued growth in earnings from power investments throughout the year, 
including a gain on the sale of a portion of an investment in the fourth 
quarter of 1996.  Also contributing to the increase was a decrease in power 
supply costs due to the availability of low-cost hydroelectric generation in 
the region to service power supply obligations.

Revenues:

	Earnings from unconsolidated investments increased $8,700,000 as a result 
of growth in earnings from prior investments coupled with additional 
investments made in late 1995.  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 revenues resulting from a decrease in volumes sold.

Expenses:

	Independent power operations 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 purchased 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.

1995 Compared to 1994

	The 1995 net income from independent power operations decreased primarily 
as a result of fewer development projects reaching successful completion.  Also 
contributing to the 1995 decrease were the absence of the 1994 gain recognized 
on the sale of 50% of North American Energy Services and the 1995 loss on the 
withdrawal from another investment.  Net income benefited from higher earnings 
from unconsolidated investments and decreases in power supply and maintenance 
costs at the Colstrip plant.  

Revenues:

	The decrease in independent power revenues resulted primarily from a 
$12,900,000 decrease in power project development fees, which were not expected 
to meet the levels achieved in 1994.  The increase in earnings from 
unconsolidated investments resulted from higher earnings from independent power 
projects which were offset by the loss on the withdrawal from a power service 
business.

Expenses:

	The independent power operations and maintenance expense decreased 
approximately $7,000,000 due to reduced project development expenses and lower 
power supply and maintenance expenses at the Colstrip plant.  Project 
development expenses decreased approximately $3,000,000 as a correlating result 
of the anticipated decline in successful project development completions. Lower 
fuel, rental and transmission costs, due primarily to reduced generation and 
lower power sales, resulted in a $2,000,000 decrease in power supply costs. 
Operation and maintenance expense also decreased approximately $2,000,000 due 
to improved maintenance practices at the Colstrip plant.  


Telecommunications Operations:

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.

1995 Compared to 1994

	Additional leased network capacity sold to private businesses and a 26% 
increase in minutes sold to long-distance customers increased earnings from 
telecommunications operations.


Other Operations:

1996 Compared to 1995

	Income from other operations decreased primarily due to a decrease in 
distributions from the Company's investment in a Brazilian gold mining 
operation.
Interest Expense and Other Income, and Income Taxes: 

	The changes  in interest expense from 1994 to 1996 were a result of 
increases in the amount of outstanding borrowings and the interest paid 
pursuant to the 1995 coal arbitration decision discussed above. 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:  

	Net cash provided by operating activities was $217,293,000 in 1996 
compared to $268,890,000 in 1995 and $203,886,000 in 1994.  Cash from operating 
activities less dividends paid provided 77% of capital expenditures in 1996, 
76% in 1995 and 54% in 1994.

	The Company's long-term debt as a percentage of capitalization was 37%, 
37% and 36% in 1996, 1995 and 1994, respectively.  The Company also has entered 
into long-term lease arrangements and other long-term contracts for sales and 
purchases that are not reflected on its balance sheet.  See Item 8, "Financial 
Statements and Supplementary Data - Note 3 to the Consolidated Financial 
Statements" for additional information.  

	Capital expenditures during the prior three years were as follows:  

		Utility	Nonutility	  Total  
                     Thousands of Dollars

	1994	$150,903	$ 56,407	$207,310
	1995	 163,238	  67,849	 231,087
	1996	107,085	51,992	159,077


	The following table sets forth the Company's estimated capital 
expenditures for the years 1997-2001:

		Utility	Nonutility	  Total  
                     Thousands of Dollars

	1997	$ 95,000	$129,000(a)	$224,000
	1998	110,000	99,000	209,000
	1999	80,000	78,000	 158,000
	2000	82,000	70,000	 152,000
	2001	102,000	86,000	188,000

(a)	On February 28, 1997, the Company committed to purchase Vessels Energy's 
oil and natural gas assets in Colorado's Denver-Julesburg Basin for 
approximately $85,000,000.  To the extent that 1997 capital expenditures 
are increased, they will be financed internally by oil and natural gas 
operations.  

	The majority of the Utility's capital expenditures during the next five 
years are expected to be spent on environmental mitigation, relicensing and 
rehabilitation of hydroelectric projects, refurbishing electric and natural 
gas transmission lines and extending and maintaining electric and natural gas 
distribution lines. The majority of the Nonutility's capital expenditures 
during the next five years are expected to be spent on replacements, heavy 
equipment purchases, expansion and development of oil and natural gas 
properties and the expansion of the fiber optic network.

	In addition, $238,000,000 of long-term debt will mature during the years 
1997-2001.  See Item 8 "Financial Statements and Supplementary Data - Note 8 to 
the Consolidated Financial Statements" for details on maturities of long-term 
debt.  

	For the years 1997-2001, the Company estimates that, by business unit, 
internally-generated funds will average 98% of its utility construction program 
and 98% 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.  

	Dividends paid on common and preferred stock were $95,284,000 in 1996, 
$93,600,000 in 1995, and $92,009,000 in 1994.  During 1996, 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.

	The Company has Revolving Credit and Term Loan Agreements in the amount 
of $135,000,000.  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 8 and 9 to the Consolidated Financial Statements 
for further information."  

	The Company submitted its latest depreciation study as part of its rate 
request filed with the PSC on September 21, 1995. The PSC approved and included 
in rates the settlement of the depreciation study, effective July 1, 1996. The 
provision for utility depreciation changed from approximately 2.7% of the 
depreciable utility plant to approximately 3.0%, resulting in an increase in 
annual depreciation expense of approximately $5,900,000.

	In November 1996, the Company sold to the public, through a subsidiary 
trust, Montana Power Capital I, $65,000,000 of 8.45% Cumulative Quarterly 
Income Preferred Securities, Series A maturing on December 31, 2036. The 
proceeds from the sale were used to purchase from the Company a like amount of 
its Subordinated Debentures. Approximately $31,000,000 of the proceeds from the 
purchase was used to redeem in December 1996 all 1,200,000 outstanding shares 
of the Company's Preferred Stock, $2.15 Series, at $25.25 per share, plus 
accumulated dividends. The balance of the proceeds was used for general 
corporate purposes including the repurchase and retirement of 139,200 shares of 
the $6.875 Series Preferred Stock.  See Item 8, "Financial Statements and 
Supplementary Data - Note 7 to the Consolidated Financial Statements" for 
further information.  

	In December 1996, the Company received PSC approval to offer from time 
to time up to $150,000,000 of its Unsecured Medium-Term Notes, Series B on 
terms to be determined at the time of the sale. In December 1996, the Company 
sold an aggregate of $55,000,000 of Unsecured Medium-Term Notes.  The amounts, 
interest rates and due dates are: $15,000,000 7.07% series due 2006, 
$5,000,000 7.96% series due 2026 and $35,000,000 7.875% series due 2026.  The 
net proceeds received by the Company from the sale of these notes were used 
for general corporate purposes, including the repayment of long-term and 
short-term borrowings.

	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 will not preclude it from issuing sufficient First 
Mortgage Bonds to meet its bonded debt requirements during the years 1997-2001. 
There are no restrictions upon issuance of short-term debt or preferred stock 
in the Company's Restated Articles of Incorporation, its Mortgage and Deed of 
Trust or its Sinking Fund Debenture Agreement.  


SEC RATIO OF EARNINGS TO FIXED CHARGES:

	For the twelve months ended December 31, 1996, the Company's ratio of 
earnings to fixed charges was 3.21 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.  

	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.  


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 $525,000 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 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 has determined that 
the Colstrip Units can meet the Phase I nitrogen oxide standards by January 1, 
1997, it exercised this option for the Colstrip plants.  The Company did not 
exercise this option for its Corette Plant because, due to improvements in the 
plant's emissions which will not be completed until late in 1997, the level of 
nitrogen oxide emissions at the plant could not be determined before the early 
election deadline. 

	The costs associated with any modifications that ultimately may be 
required to comply with Phase II nitrogen oxide standards have not been 
determined because they have only recently been promulgated.


ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA


	INDEX TO FINANCIAL STATEMENTS
	AND SUPPLEMENTARY DATA

	 Page 

Management's Responsibility for Financial Statements	50

Report of Independent Accountants	51

Consolidated Financial Statements:

	Consolidated Statements of Income for the Years Ended 
		December 31, 1996, 1995 and 1994	52

	Consolidated Balance Sheets as of December 31, 1996 and 1995	53-54

	Consolidated Statements of Cash Flows for the Years Ended 
		December 31, 1996, 1995 and 1994	55

	Consolidated Statements of Common Shareholders' Equity for the 
		Years Ended December 31, 1996, 1995 and 1994	56

	Notes to Consolidated Financial Statements	57-82

Supplementary Data (Unaudited)
Financial Statement Schedules for the Years Ended December 31, 
	1996, 1995 and 1994	83-91

	Schedule II - Valuation and Qualifying Accounts and Reserves	96


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 public accountants, also 
considered the systems in connection with its audit.  Management has considered 
the internal auditors' and Price Waterhouse LLP's recommendations concerning 
the systems and has taken cost-effective actions to respond appropriately to 
these recommendations.  

	The Board of Directors, acting through an Audit Committee composed 
entirely of directors who are not employees of the Company, is responsible for 
determining that management fulfills its responsibilities in the preparation of 
the financial statements.  The Audit Committee recommends, and the Board of 
Directors appoints, the independent public accountants.  The independent 
accountants and internal auditors are assured of full and free access to the 
Audit Committee and meet with it to discuss their audit work, the Company's 
internal controls, financial reporting and other matters.  The Committee is 
also responsible for determining that there is adherence to the Company's Code 
of Business Conduct (Code).  The Code addresses, among other things, potential 
conflicts of interests and compliance with laws, including those relating to 
financial disclosure and the confidentiality of proprietary information.  

	The financial statements have been examined by Price Waterhouse LLP, 
which is responsible for conducting its examination in accordance with 
generally accepted auditing standards.  






                                	                               
Daniel T. Berube	J. P. Pederson
Chairman of the Board and	Vice President and
Chief Executive Officer	Chief Financial and Information
	  Officer 



	Report of Independent Accountants

February 6, 1997, except as to paragraphs 3 and 5 of Note 2, which are as of 
February 21, 1997

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, 1996 
and 1995 and the results of their operations and of their cash flows for each 
of the three years in the period ended December 31, 1996 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 12 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




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


					
				       Year Ended December 31       
				   1996   	   1995   	   1994   
				        Thousands of Dollars
<S>                                               <C>           <C>          <C> 
REVENUES		$  973,208	$  953,224	$1,005,970

EXPENSES:
	Operations		383,789	   420,472	   436,610
	Maintenance		65,390	    68,286	    75,357
	Selling, general and administrative		111,144	   101,872	   106,989
	Taxes other than income taxes		87,903	    89,858	    99,200
	Depreciation, depletion and amortization		88,744	    86,976	    86,711
	Writedowns of long-lived assets		          	    74,297	          
					   736,970	   841,761	   804,867

		INCOME FROM OPERATIONS		236,238	   111,463	   201,103

INTEREST EXPENSE AND OTHER INCOME:
	Interest		48,770	    43,656	    42,817
	Other (income) deductions - net		    (3,893)	   (10,704)	   (10,532)
					44,877	    32,952	    32,285

INCOME TAXES		    71,975	    21,574	    55,226

NET INCOME		119,386	    56,937	   113,592
DIVIDENDS ON PREFERRED STOCK		     8,358	     7,227	     7,227

NET INCOME AVAILABLE FOR COMMON STOCK		$  111,028	$   49,710	$  106,365

AVERAGE NUMBER OF COMMON SHARES
	OUTSTANDING (000)		54,634	    54,121	    53,125

NET INCOME PER SHARE OF COMMON STOCK		$     2.03	$     0.92	$     2.00



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       
	   1996    	   1995    
	Thousands of Dollars

<S>                                                             <C>           <C>
PLANT AND PROPERTY IN SERVICE:
	Utility plant		$2,281,395	$2,204,386
	Less - accumulated depreciation and depletion		   705,119	   663,216
						1,576,276	1,541,170

	Nonutility property		666,679	633,079
	Less - accumulated depreciation and depletion		   256,489	   252,612
						   410,190	   380,467
						1,986,466	1,921,637


MISCELLANEOUS INVESTMENTS (at cost):
	Independent power investments		53,035	57,013
	Reclamation fund		43,001	    
	Other		    39,531	    38,645
						135,567	 95,658
CURRENT ASSETS:
	Cash and temporary cash investments		32,404	15,541
	Accounts receivable		142,347	152,386
	Materials and supplies (principally at average cost)		39,322	42,194
	Prepayments and other assets		    46,408	    46,172
	Deferred income taxes		    11,095	    15,899
						271,576	272,192

DEFERRED CHARGES:
	Advanced coal royalties		19,298	20,175
	Regulatory assets related to income taxes		149,150	148,350
	Regulatory assets - other		66,688	68,637
	Other deferred charges		     69,470	     59,442
						    304,606	    296,604
						$ 2,698,215	$ 2,586,091

The accompanying notes are an integral part of these statements.



	LIABILITIES


					       December 31       
					    1996   	    1995    
					   Thousands of Dollars


CAPITALIZATION:
	Common shareholders' equity:
		Common stock (120,000,000 shares without par 
		  value authorized; 54,630,994 and 54,614,481
		  shares issued)		$  691,853	$  691,043
		Retained earnings and other shareholders' equity		307,804	285,000
		Unallocated stock held by trustee for retirement
		  savings plan		   (28,360)	   (30,565)
					971,297	   945,478

	Preferred stock		57,654	101,416
	Company obligated mandatorily redeemable preferred
	  securities of subsidiary trust which holds solely
	  company junior subordinated debentures		65,000
	Long-term debt		   633,339	   616,574
						1,727,290	1,663,468

CURRENT LIABILITIES:
	Short-term borrowing		104,702	96,348
	Long-term debt-portion due within one year		69,268	24,804
	Dividends payable		22,707	23,668
	Income taxes		11,083	9,937
	Other taxes		41,667	43,302
	Accounts payable		62,218	63,920
	Interest accrued		11,909	12,341
	Other current liabilities		    41,155	    63,488
						364,709	337,808

DEFERRED CREDITS:
	Deferred income taxes		332,861	320,736
	Investment tax credit		44,467	47,001
	Accrued mining reclamation costs		129,878	122,008
	Other deferred credits		    99,010	    95,070
						   606,216	   584,815

CONTINGENCIES AND COMMITMENTS (Notes 2 and 3)


					$2,698,215	$2,586,091


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       
		   1996   	   1995   	   1994   
	Thousands of Dollars
<S>                                                 <C>            <C>         <C>
NET CASH FLOWS FROM OPERATING ACTIVITIES:
	Net income		$  119,386	$  56,937	$ 113,592
	Adjustments to reconcile net income to net 
		cash provided by operating activities:
		Depreciation, depletion and amortization		88,744	86,976	86,711
		Writedowns of long-lived assets			74,297
		Deferred income taxes		15,430	(11,819)	4,792
		Noncash earnings from unconsolidated 
			independent power investments		(11,505)	(2,314)	(169)
		Reclamation expensed and paid - net		7,870	7,411	8,218
		Other - net		25,132	20,105	27,390
		Changes in current assets and liabilities:
			Accounts receivable		10,039	7,589	(1,622)
			Materials and supplies		2,872	5,743	(5,209)
			Accounts payable		(1,702)	13,132	(5,007)
			Other assets and liabilities		   (38,973)	   10,833	  (24,810)
		Net cash provided by operating activities		   217,293	  268,890	  203,886

NET CASH FLOWS FROM INVESTING ACTIVITIES:
	Capital expenditures		(159,077)	  (231,087)	  (207,310)
	Reclamation funding		(43,001)	
	Sales of property		11,171	13,987	27,729
	Additional investments		    (2,255)	   (2,640)	    1,143
		Net cash used for investing activities		  (193,162)	 (219,740)	 (178,438)

NET CASH FLOWS FROM FINANCING ACTIVITIES:
	Dividends paid		(95,284)	   (93,600)	   (92,009)
	Sales of common stock		798	    23,465	    24,380
	Redemption of preferred stock		(46,790)
	Issuance of long-term debt		82,890	    50,758	    52,094
	Retirement of long-term debt		(22,236)	   (18,155)	   (45,078)
	Issuance of mandatorily redeemable preferred
		securities		   65,000		
	Net change in short-term borrowing		     8,354	  (17,641)	   45,125
		Net cash used for financing activities		    (7,268)	  (55,173)	  (15,488)

CHANGE IN CASH FLOWS		    16,863	    (6,023)	     9,960

CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR		    15,541	   21,564	   11,604

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

SUPPLEMENTAL DISCLOSURES OF CASH FLOW: 
	Cash paid during the year for:
		Income taxes		$   55,399	$  32,666	$  45,875
		Interest		49,962	46,141	45,990

The accompanying notes are an integral part of these statements.

</TABLE



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

		
		
	
	        Year Ended December 31        
	   1996   	   1995   	   1994   
	Thousands of Dollars
<S>                                                  <C>          <C>           <C>
COMMON STOCK:

	Balance at beginning of year		$ 691,043	$ 667,344	$ 642,926
	Issuances (16,513; 1,035,744; 
	  and 1,079,841 shares)		      810	   23,699	   24,418

	Balance at end of year		  691,853	  691,043	  667,344 

RETAINED EARNINGS AND OTHER SHAREHOLDERS' 
	EQUITY:

	Balance at beginning of year		285,000	  320,756	  302,725
	Net income		119,386	   56,937	  113,592
	Dividends on common stock ($1.60;
		$1.60; and $1.60 per share)		(87,432)	  (86,791)	  (85,193)
	Dividends on preferred stock		(7,705)	   (7,227)	   (7,227)
	Other		     (1,445)	    1,325	   (3,141)

	Balance at end of year		  307,804	  285,000	  320,756 

UNALLOCATED STOCK HELD BY TRUSTEE FOR
	RETIREMENT SAVINGS:

	Balance at beginning of year		(30,565)	  (32,580)	  (34,419)
	Distributions		    2,205	    2,015	    1,839 

	Balance at end of year		  (28,360)	  (30,565)	  (32,580)

TOTAL COMMON SHAREHOLDERS' EQUITY AT 
	END OF YEAR		$ 971,297	$ 945,478	$ 955,520 


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 FERC and was an average of 7.2% for 1996, 8.1% for 1995 and 
7.9% for 1994. 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       
			   1996   	   1995   
			Thousands of Dollars
	Utility plant:
	Electric:
		Production		$  748,044	$  748,276
		Transmission		352,993	335,338
		Distribution		487,937	456,312
		Other		175,728	172,371
	Natural Gas:
		Production and storage		194,531	197,005
		Transmission		146,072	128,700
		Distribution		128,877	120,152
		Other		    47,213	    46,232
			Total Utility		2,281,395	2,204,386
	Nonutility plant:
	Coal		255,788	266,218
	Oil and natural gas		274,880	261,700
	Technology		48,069	20,164
	Electric production		75,298	72,179
	Other		    12,644	    12,818
			Total Nonutility		   666,679	   633,079
			Total Plant		$2,948,074	$2,837,46


	Included in the plant classifications are Utility plant under 
construction in the amounts of $52,125,000 and $57,095,000 for 1996 and 1995, 
respectively and Nonutility plant under construction in the amounts of 
$39,252,000 and $15,887,000 for 1996 and 1995, respectively.

	Provisions for depreciation and depletion are recorded at amounts 
substantially equivalent to calculations made on straight-line and 
unit-of-production methods by application of various rates based on useful 
lives of properties determined from engineering studies.  The provisions for 
Utility depreciation and depletion approximated 3.0% for 1996 and 2.7% for 1995 
and 1994 of the depreciable and depletable Utility plant at the beginning of 
the year.  

	The Company's Nonutility oil  and natural gas operations uses 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, 1996, 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		$ 183,938	$ 285,388	$  51,170
Plant under construction		      150	    168	        4
Accumulated depreciation		   90,791	   99,191	   12,875

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

	The Company also owns $41,825,000 and $33,237,000 of the Nonutility 
Colstrip Unit 4 share of common production plant and transmission plant that 
had related accumulated depreciation of $14,854,000 and $6,999,000, 
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 the 1996 coal arbitration decision, the Company was 
required to establish a reclamation fund, representing restricted cash equal to 
a portion of their accumulated reclamation liability plus interest.  The fund 
will increase as reclamation expenses are collected from customers and all 
proceeds will be invested until reclamation is performed.  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.  

	         1996          	         1995          
	 Assets  	Liabilities	 Assets  	Liabilities
	Thousands of Dollars

	Income taxes	$ 146,737		$ 147,388	
	Conservation programs	41,372		   40,640
	Other	   48,074	$  12,207	   33,298	$  12,623
	    Subtotal	236,183	12,207	  221,326	   12,623
	Less: 
	  Current portions	   20,345	    3,195	    4,339	    3,675
	    Total	$ 215,838	$   9,012	$ 216,987	$   8,948

	Income taxes reflect the impacts of temporary difference that will be 
recovered in rates in future periods. 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. Items included in Other are 
either being amortized currently or are subject to regulatory confirmation in 
future ratemaking 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 was 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 
addressed in the transition process or they would be eliminated from the 
balance sheet and included in income in the period when the discontinuation 
occurred.

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, 1996 and 1995 were approximately $3,600,000 
and $4,200,000, 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:

	Net income per share of common stock is computed for each year based upon 
the weighted average number of common shares outstanding.  

Derivative financial instruments:

	To manage nonutility price risk, the Company uses a variety of derivative 
financial instruments, including oil and natural gas swap, collar and cap 
agreements, to hedge revenue from anticipated production and sales of oil and 
natural gas.  Under swap agreements, the Company receives or makes payments 
based on the differential between a specified price and the market price of oil 
or natural gas when the hedged transaction is settled.  Under collar 
agreements, the Company makes or receives monthly payments 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 based on the differential between the actual price of 
oil or natural gas and the cap established in the agreement.  At December 31, 
1996, the Company had cap agreements on approximately 164,500 barrels of crude 
oil; 48% of its expected production from proved, developed and producing oil 
reserves through February 1997.  The Company had swap and cap agreements on 
approximately 2.0 Bcf of Nonutility natural gas; 13% of its expected production 
from proved, developed and producing Nonutility reserves through October 1997. 
In addition, the Company had swap and collar agreements to hedge approximately 
3.8 Bcf of Nonutility natural gas; 27% of its expected delivery obligations 
under long-term sales contracts through March 1998. At December 31, 1996, the 
Company had no material gains or losses from 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, 1996, the Company believes it would not 
experience any materially adverse impacts from the risks inherent in these 
instruments.


Fair value of financial instruments:

			        1996      	       1995      
			Carrying	Fair 	Carrying	Fair 
			 Amount 	Value	Amount 	Value
			Thousands of Dollars

Assets:  
	Investments in independent
		power projects (cost basis 
		 only)		$  6,090	$ 10,300	$  7,868	$  2,169
	Reclamation fund		43,001	43,001
	Other significant investments		35,449	39,837	33,558	34,575

Liabilities:
	Mandatorily redeemable preferred
		securities		$ 65,000	$ 67,600
	Long-term debt(including due 
		within one year)		702,607	717,504	$641,378	$672,699

	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.

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.  


NOTE 2 - Contingencies:  

	In 1990, pursuant to a Federal Energy Regulatory Commission (FERC) 
license obligation, the Company proposed a plan to protect fish, wildlife and 
habitat affected by the operation of the 180 megawatt Kerr Project (Project), 
which would cost the Company $15,600,000 initially and, thereafter, $965,000 
annually.  Management's estimate of the initial cost has been capitalized to 
plant.  The United States Department of Interior (Department) has proposed an 
alternative to the plan which the Company estimates would cost approximately 
$35,000,000 initially and, thereafter, $1,300,000 annually.  An Environmental 
Impact Statement prepared by the FERC staff concludes that the Department's 
alternative is preferable, from an environmental perspective, to the Company's 
plan.  In addition to requiring expenditures for environmental mitigation 
which are not included in the Company's plan, the alternative proposed by the 
Department would change the operation of the Project from a peaking to a 
baseload operation.  This matter is pending FERC's decision, which is expected 
in 1997.  The Company can not predict what FERC's decision might be.

	In November 1992, the Company applied to FERC to relicense nine Madison 
and Missouri River hydroelectric projects, with generating capacity of 292 
megawatts.  The net present value of relicensing and environmental mitigation 
is estimated to be approximately $158,000,000. The FERC staff is expected to 
issue a draft environmental impact statement in mid-1997.  The Company expects 
to receive a license order in late 1998 or early 1999.  The majority of the 
cost is capital for physical improvements, which is not expected to be spent 
before 2006.

	In March 1995, the Company sued Puget Sound Power & Light Company 
(Puget) in the United States District Court for the District of Montana 
seeking a determination that the Company was in compliance with an agreement 
to sell Puget 94 megawatts of power annually to the year 2010.  This action 
arose out of an allegation by Puget that the Company breached the agreement by 
failing to provide firm contractual rights to a transmission path for the 
power, thereby entitling Puget to terminate the agreement.  On February 21, 
1997 the Company and Puget settled this litigation.  The litigation has been 
dismissed with prejudice.  In the settlement, the Company agreed to reduce 
prices for power purchased under the terms of the agreement and to amend other 
provisions to grant Puget access to an additional 3 MW of capacity and to 
eliminate restrictions limiting Puget's right to take energy to a 75% capacity 
factor.  The Company and Puget agreed that the General Transmission Agreement 
between Puget and the Bonneville Power Administration provides firm 
contractual rights to transmission paths sufficient to fulfill the Company's 
obligations under the Agreement through the end of the contract.  In addition, 
Western Energy Company (Western), a subsidiary of the Company, agreed to 
reduce the price of coal to Puget for Colstrip Units 1,2,3 and 4.  The Company 
estimates the settlement will reduce future consolidated revenues between 
approximately $11,000,000 and $13,000,000 per year.  This settlement had no 
effect on the Company's consolidated financial position or consolidated 
results of operation for the year ended December 31, 1996.

	In 1994, the Company entered into an agreement to purchase 98 megawatts 
of capacity during the winter months from Basin Electric Power Cooperative 
(Basin), delivery of which was to begin in November 1996.  The purchase 
obligation under the agreement was from November 1, 1996 to April 30, 2012. 
Under the terms of the agreement, the Company would have purchased seasonal 
power between November and April of each year at a cost estimated to be 
approximately $11,200,000 in 1997 and escalating annually, pursuant to the 
contract. On October 31, 1996, the Company notified Basin of the Company's 
rescission of the agreement as a consequence of Basin's refusal to provide 
electricity at the delivery points the Company had requested under the terms 
of the agreement without imposing unacceptable precedent conditions.  On 
November 5, 1996, Basin sued the Company in the Federal District Court for the 
Southwestern District of North Dakota seeking specific performance, a stay of 
the litigation and an order compelling the Company to arbitrate the dispute. 
On January 6, 1997, the Company answered Basin's complaint stating numerous 
counterclaims.  The outcome of this litigation can not be predicted at this 
time.  As of December 31, 1996, the Company did not pay approximately 
$2,000,000 that otherwise would have been payable under the terms of the 
agreement.

	Western is seeking to resolve a Coal Supply Agreement (CSA) dispute with 
the non-operating owners (NOOs) of Colstrip Units 3 and 4, other than Puget. 
In the settlement of the litigation regarding the power sales agreement 
described above, Puget withdrew from this dispute. The doubling of the 
Consumers Price Index, which occurred in 1996, triggered a right to assert a 
Gross Inequity claim.  The NOOs claim that the combination of electric utility 
industry restructuring and economic and other changes, which have occurred 
since the CSA was entered into, has created a Gross Inequity.  Thus, according 
to the NOOs, a reduction of the coal price is necessary to remedy the Gross 
Inequity and assure the competitive posture of Colstrip Units 3 and 4. Western 
disputes that a Gross Inequity has occurred and is discussing this matter with 
the NOOs.  The outcome, however, can not be predicted at this time.

	Houston Lighting & Power (HL&P), the purchaser of lignite produced by 
Northwestern Resources Company (Northwestern), a subsidiary of the Company, 
has filed litigation in the District Court of the 157th Judicial District, 
Harris County, Texas, seeking a declaratory judgment that changed conditions 
require a renegotiation of management and dedication fees paid to Northwestern 
under the terms of the Lignite Sales Agreement (LSA) between it and 
Northwestern.  The LSA governs the delivery of approximately 8,000,000 tons 
per year and is effective until July 29, 2015.  Northwestern realizes 
approximately $25,000,000 per year from the management and dedication fees 
under the terms of the agreement.  HL&P alleges Northwestern failed to 
renegotiate these fees in good faith as HL&P alleges the agreement requires. 
As its remedy, HL&P seeks to terminate the LSA or, alternatively, asks the 
court to set reasonable fees.  HL&P appears to be seeking an approximate 60% 
reduction in these fees and alleges that the reduction should be retroactive 
to September 1, 1995.  Additionally, HL&P is seeking a declaration that it may 
substitute other fuels for lignite without violating the LSA.  If HL&P does 
not have this right, it further seeks a declaration that the absence of this 
right constitutes a gross inequity which entitles HL&P to have the court 
reform the LSA to provide the right to substitute fuels.  Finally, HL&P 
alleges that the parties were mutually mistaken regarding the quantity and the 
quality of lignite dedicated to the LSA and, consequently, the original 
bargain has been so altered that either no agreement was made or the agreement 
should be reformed.

	Northwestern disputes HL&P's claims and does not believe the Texas 
district court has jurisdiction to make the declarations HL&P is seeking.  The 
court will order mediation.  If settlement is not achieved, trial is expected 
in 1997.  The outcome of mediation and litigation are uncertain.

	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:

	The Company has long-term purchase contracts with certain 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 17 QF contracts, 
with expiration terms ranging from 1997 through 2031. Three contracts account 
for 97% of the 1,179 MWs of capacity provided by these facilities.  The 
purchased gas contracts provide for take-or-pay payments.  The Nonutility oil 
and natural gas operations have various natural gas transportation contracts 
with terms that expire beginning in 1998.

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

	            Thousands of Dollars             
	       Utility      	Nonutility	 Total  
		Electric	Natural Gas		

	1994		$ 19,242	$ 11,072	$  3,298	$ 33,612
	1995		21,830	9,873	3,020	34,723
	1996		30,751	8,100	3,334	42,185

	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		

	1997		$  7,292	$  6,853	$  3,000	$ 17,145
	1998		7,085	3,321	3,785	14,191
	1999		6,700	2,816	3,486	13,002
	2000		6,352	2,457	3,227	12,036
	2001		6,004	1,915	1,819	9,738
	Remainder		  83,542	   2,718	  10,582	  96,842
		$116,975	$ 20,080	$ 25,899	$162,954

	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, 1996, the remaining payments under this agreement were $8,600,000. 
Under current mine plans, these payments should be recovered through lignite 
sales.  

	The Nonutility oil and natural gas operations have agreed to supply 
approximately 110 Bcf of natural gas to three co-generation facilities through 
mid-2011.  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 Company has also entered into various contracts for the completion of 
its fiber optic network expansion. The Company is committed to spend 
approximately $21,000,000 in 1997.

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. 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 
$55,500,000, $55,958,000 and $56,928,000 for 1996, 1995 and 1994, respectively.


NOTE 4 - Income tax expense:  

	Income before income taxes was as follows:

	   1996   	   1995   	   1994   
	Thousands of Dollars

United States		$  181,393	$   75,458	$  155,978
Canada		7,706	      111	     9,144
Other countries		     2,262	     2,942	     3,696
	$  191,361	$   78,511	$  168,818


	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:  

	   1996   	   1995  	   1994  
	Thousands of Dollars

Computed "expected" income tax expense		$  66,976	$  27,479	$  59,086
Adjustments for tax effects of:
	Statutory depletion		(2,317)	   (6,508)	   (4,983)
	Tax credits		(5,286)	   (5,331)	   (5,130)
	State income tax, net		5,772	    3,327	    4,772
	Reversal of utility book/tax 
	  depreciation		4,054	    2,552	    3,236
	Other		    2,776	       55	   (1,755)
Actual income tax expense		$  71,975	$  21,574	$  55,226

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

			   1996   	   1995   	   1994   
	Thousands of Dollars

Current:
	United States		$  44,304	$  25,119	$  38,519
	Canada		3,309	    1,510	     3,093
	Other countries		445	      548	     1,080
	State		    8,487	    6,216	    7,742
			   56,545	   33,393	   50,434
Deferred:
	United States		15,590	   (8,648)	     4,426
	Canada		135	   (1,124)	       850
	State		     (295)	   (2,047)	     (484)
			   15,430	  (11,819)	     4,792
			$  71,975	$   21,574	$   55,226



	Deferred tax liabilities (assets) are comprised of the following:

	      December 31     
			   1996   	   1995   
			 Thousands of Dollars

Plant related		$ 388,973	$ 377,741
Investment in Nonutility generation projects		26,785	   23,896
Other		   33,509	   25,724
	Gross deferred tax liabilities		  449,267	  427,361

Coal reclamation		(45,252)	  (42,438)
Amortization of gain on sale/leaseback		(14,898)	  (15,962)
Investment tax credit amortization		(28,895)	  (30,542)
Other		  (38,455)	  (33,582)
	Gross deferred tax assets		 (127,500)	 (122,524)
	Net deferred tax liabilities		321,767	  304,837
	Plus current deferred tax assets-net		   11,094	   15,899
Total noncurrent deferred tax liabilities		$ 332,861	$ 320,736

	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		$  12,125
Regulatory assets related to income taxes		(800)
Current deferred tax assets-net		4,805
Amortization of investment tax credits		(2,534)
Other		    1,834
	Deferred tax expense			$  15,430



NOTE 5 - Common stock:  

	The Company has a Shareholder Protection Rights Plan which provides one 
preferred share purchase right (Right) on each outstanding common share of the 
Company.  Each Right entitles the registered holder, upon the occurrence of 
certain events, to purchase from the Company one one-hundredth of a share of 
Participating Preferred Shares, A Series, without par value.  If it should 
become exercisable, each Right would have economic terms similar to one share 
of common stock of the Company.  The Rights trade with the underlying shares 
and will, except under certain circumstances described in the Plan, expire on 
June 6, 1999, unless 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, 1996, 866,363 shares had been allocated to the 
participants' accounts. Expense for the Plan is recognized using the Shares 
Allocated Method, and was $6,046,000, $5,610,000 and $5,683,000 for 1996, 1995 
and 1994, respectively.  

	Under the Long-Term Incentive Plan, options have been issued to Company 
employees.  Options issued to Utility employees are not reflected in balance 
sheet accounts until exercised, at which time (i) authorized, but unissued 
shares are issued to the employee, (ii) the capital stock account is credited 
with the proceeds and (iii) no charges or credits to income are made.  Options 
issued to Nonutility employees are not reflected in balance sheet accounts. 
Rather, upon exercise, outstanding shares are purchased at current market 
prices and compensation expense is charged with the excess of the market price 
over the option price.  

Option activity is summarized below:  

	      1996      	      1995      	       1994      
Options outstanding	569,982	480,986	412,310
	(Price range)	($17.25 - $26.50) 	($17.25 - $26.50)	($14.25 - $26.50)

Options granted	164,400	116,730	117,100
	(Price range)	($21.625)    	($21.125 - $22.50)	  ($22.625 - $25.625)

Options exercised	11,578	19,034	43,884
	(Price range)	($17.25 - $22.125)	($17.25 - $26.50)	($14.25 - $26.50)

Options canceled	28,000	8,700	4,540
	(Price range)	($22.125 - $22.625)	  ($22.125 - $22.625)	($14.25 - $26.50)

	There were 421,051 options exercisable at December 31, 1996.

	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 Balance Sheet and Income 
Statement, respectively.  At December 31, 1996 there were 29,564 shares of 
restricted stock remaining.  

	The Financial Accounting Standards Board has issued Statement of 
Financial Accounting Standards No. 123 "Accounting for Stock-Based 
Compensation" (SFAS No. 123), which is effective for years beginning after 
December 15, 1995.  SFAS No. 123 encourages, but does not require, companies to 
recognize compensation expense for grants of common stock, stock options, and 
other equity instruments to employees based upon the fair value of the 
instruments when issued.  The Company applies APB Opinion 25 and related 
Interpretations in accounting for its plan.  Accordingly, no compensation cost 
has been recognized for the options granted under the Long-Term Incentive Plan. 
Had the Company used the fair value method in accordance with SFAS No. 123, 
compensation expense would have increased $108,000 and $37,000 for 1996 and 
1995, respectively.  



NOTE 6 - Preferred stock:  

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

	Preferred stock is in four series as detailed in the following table:  

	Stated and
	Liquidation	Shares Issued and Outstanding	    Thousands of Dollars    
Series	   Price*  	  1996   	  1995   	  1994   	  1996  	  1995  	  1994  
	$6.875	$100	360,800	500,000	500,000	$ 36,080	$ 50,000	$ 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	1,200,000	        	  30,000	  30,000
			 580,389	1,919,589	1,919,589	$ 58,064	$101,984	$101,984

	*  Plus accumulated dividends.
	
	The preferred stock is redeemable at the option of the Company upon the 
written consent or affirmative vote of the holders of a majority of the common 
shares on thirty days notice at $110 per share for the $6.00 series and 
$103 per share for the $4.20 series, plus accumulated dividends.  The $6.875 
series is redeemable in whole or in part, at anytime on or after November 1, 
2003 for a price beginning at $103.438 per share with annual decrements through 
October 2013, after which the redemption price is $100 per share.

	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 has been included in preferred dividends in 
the Consolidated Income Statement.



NOTE 7 - 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, 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 8 - Long-term debt:  

	The Company's Mortgage and Deed of Trust imposes a first mortgage lien on 
all physical properties owned, exclusive of subsidiary company assets, and 
certain property and assets specifically excepted.  The obligations 
collateralized are First Mortgage Bonds, including those First Mortgage Bonds 
designated as Secured Medium-Term Notes and those securing Pollution Control 
Revenue Bonds.

	Long-term debt consists of the following:  

	       December 31      
	   1996   	   1995   
	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 1997-2025  5.75%-8.11%		128,000	   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		16,000	    16,500
ESOP Notes Payable - 9.2%, due 2004		27,587	    29,861
Unsecured Medium-Term Notes:  
	Series A - maturing 1997-2022  8.68%-8.9%		29,500	38,250
	Series B - maturing 2006-2026  7.07%-7.96%		55,000
Revolving Credit Agreements		35,000	    10,000
Other		10,536	    17,696
Unamortized Discount and Premium		   (4,221)	   (4,134)
	702,607	   641,378
Less:  Portion due within one year		    69,268	    24,804
	$  633,339	$  616,574

Revolving Credit Agreements:  

	The Company has two Revolving Credit Agreements that allow it to borrow 
up to a combined total of $135,000,000, of which $100,000,000 was unused at 
December 31, 1996.  One agreement requires that borrowings outstanding at 
October 27, 1998 must be repaid at that time.  The other agreement states that 
borrowings outstanding at September 30, 1997 must be repaid at that time. Fixed 
or variable interest rate options are available under the facilities with 
commitment fees on the unused portions.  

	The sinking fund requirements and maturities for the five years ending 
December 31, 2001, on the long-term debt outstanding at December 31, 1996, 
amount to: $69,000,000 in 1997; $45,000,000 in 1998; $61,000,000 in 1999; 
$34,000,000 in 2000 and $29,000,000 in 2001.



NOTE 9 - 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, 1996, the Company had lines of credit consisting of 
$100,000,000 committed and $95,400,000 uncommitted. There is a commitment fee 
on the unused portion of some of these facilities which is not significant. The 
Company  has the ability to issue up to $175,000,000 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              
		       1996       	       1995       
			 Amount 	Rate	 Amount 	Rate
	Thousands of Dollars

	Notes payable to banks		$ 70,500	7.17%	$ 78,400	6.18%
	Commercial paper		  34,202	5.79%	  17,948	6.33%
		$104,702		$ 96,348


NOTE 10 - 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 1996, 1995 and 1994, pension costs funded were less than SFAS No. 87 
pension expense by $188,000, $1,501,000 and $2,770,000, respectively and the 
difference was recorded as a deferred charge which will be recovered in rates. 
At December 31, 1996, the regulatory asset was $3,097,000.  

	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            
			   1996  	   1995  	   1994   
			        Thousands of Dollars
	Service cost on benefits earned		$   7,991	$   6,165	$    8,442
	Interest cost on projected benefit 
		obligation		15,861	   14,524	    13,430
	Actual return on plan assets		(30,331)	  (13,009)	   (13,051)
	Net amortization and deferral		   15,270	    1,719	     3,788
		Net pension and benefit expense		$   8,791	$   9,399	$   12,609
<TABLE>
<CAPTION>
		The funded status of the pension and benefit plans is as follows:  

	     December 31     
	  1996   	  1995   
			Thousands of Dollars
<S>                                                      <C>         <C>
	Actuarial present value of benefit obligation:  
		  Vested		$ 152,115	$ 149,122
		  Nonvested		   19,029	   17,768
	Accumulated benefit obligation		171,144	  166,890
	Effect of projected future compensation levels		   51,125	   53,340
	Projected benefit obligation		222,269	  220,230
	Plan assets at fair value		  223,686	  196,427
	Plan assets less than projected  
	  benefit obligation		1,417	(23,803)
	Unrecognized net gain		(34,793)	(7,082)
	Unrecognized prior service cost		10,088	   10,466
	Unrecognized initial obligation		    2,491	    2,874
		Accrued benefits expense		$ (20,797)	$ (17,545)
</TABLE>


<TABLE>
<CAPTION>
			The following assumptions were used in the determination of actuarial 
present values of the projected benefit obligations:  
			      December 31      
			   1996    	    1995   
<S>                                                      <C>         <C>
	Assumed discount rates		7.50%	7.00%
	Long-term rate of average compensation increase		4.50%-5.00%	4.00%-4.90%
	Long-term rate on plan assets		8.50%	8.50%
</TABLE>
	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, 1996, 1995 
and 1994, portions of which have been deferred or capitalized, includes the 
following components:  

	          December 31        
	  1996  	  1995  	  1994  
	Thousands of Dollars
	Service cost on benefits earned		$  1,074	$  1,221	$  1,455
	Interest cost on projected benefit		2,092	   2,482	2,323
	Actual return on plan assets		(876)	    (219)	(38)
	Net amortizations		   1,577	   1,299	   1,535
		Total postretirement benefit cost		$  3,867	$  4,783	$  5,275

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

	     December 31    
	  1996  	  1995  
	Thousands of Dollars
	Accumulated benefit obligation:
		Fully eligible active employees		$  3,267	$  1,939
		Other active employees		16,267	  22,856
		Retirees		  10,330	  11,909
	Accumulated benefit obligation		29,864	  36,704
	Plan assets at fair value		   5,740	   3,714
	Plan assets less than projected
	  benefit obligation		(24,124)	(32,990)
	Unrecognized net transition obligation		20,012	  24,728
	Unrecognized net gain		  (8,064)	     542
		Accrued benefits expense		$(12,176)	$ (7,720)

	The assumed 1996 health care cost trend rates used to measure the 
expected cost of benefits covered by the plans are 8.25% and 9% for the Utility 
and Nonutility operations, respectively.  The trend rates decrease through 2004 
to 5%. One Nonutility subsidiary's plan used a trend rate of 9% decreasing 
through 2003 to an ultimate rate of 5% for post-65 benefits.  The effect of a 
1% increase in each future year's assumed health care cost trend rates 
increases the service and interest cost from $3,200,000 to $3,500,000 and the 
accumulated postretirement benefit obligation from $29,900,000 to $32,100,000. 

	At December 31, 1993, the unrecorded postemployment benefit liability for 
regulated Utility operations was estimated to be $6,900,000.  The amount was 
recorded in 1994 as a deferred charge and will be expensed and included in 
rates over the next ten years.  The estimated December 31, 1993 postemployment 
benefit liability of $1,300,000 for Nonutility operations was charged to income 
in 1994.  The Company is no longer self-insured for disability-related benefits 
resulting from claims occurring after December 31, 1993.  Therefore, SFAS 
No. 112 will not apply to benefits after that date, except workman's 
compensation claims which are accrued and recovered in rates.



NOTE 11 - Information on industry segments:  

	The Company and its subsidiaries conduct a number of diversified, but 
related businesses. The Company's principal business is its Montana electric 
and natural gas utility operation.  This activity includes  utility operations 
involved in the generation, purchase, transmission and distribution of 
electricity, and the production, purchase, transportation and distribution of 
natural gas. The Company's  nonutility businesses are involved principally in 
the mining and sale of coal, exploration for, and the development, production, 
processing and sale of oil and natural gas; the sale of telecommunication 
equipment, internet, long distance and dedicated services; and independent 
power activities that include the sales of power under long-term contracts, and 
the development of and investment in nonutility power projects and other 
energy-related businesses.

	The Company's assets and operations are located principally in the United 
States.  The assets of the Company's Canadian operations were $77,266,000 , 
$77,282,000 and $79,337,000 at December 31, 1996, 1995 and 1994, respectively. 
Substantially all of the natural gas produced by the Company's Canadian utility 
operations has been sold to the Company's United States utility operations.



<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		    48,479	    12,149
Capital expenditures		    74,930	    31,060
Identifiable assets		 1,526,197	   421,955
<CAPTION>
NONUTILITY				Independent
					  Oil and	   Power
				   Coal*  	Natural Gas	Investments
<S>                                           <C>          <C>          <C>
Sales to unaffiliated customers		$  166,678	$  124,553	$  75,322
Intersegment sales		    31,448	       272	    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			$   27,275	$    1,185
Intersegment sales			       443	       782
Pre-tax operating income (loss)			     2,590	    (1,487)
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.  
</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		    42,506	    10,793
Capital expenditures		   127,917	    35,091
Identifiable assets		 1,503,619	   410,267
<CAPTION>
NONUTILITY				Independent
					  Oil and	   Power
				   Coal*  	Natural Gas	Investments
<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		    55,102	    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.  
</FN>
</TABLE>


<TABLE>
<CAPTION>
Operations Information:  
				       Year Ended
				    December 31, 1994     
				   Thousands of Dollars

UTILITY		 Electric 	Natural Gas
<S>                                                 <C>            <C>
Sales to unaffiliated customers		$  427,686	$  107,105
Intersegment sales		     5,924	       917
Pre-tax operating income		    98,070	    29,576
Depreciation, depletion and amortization		    40,699	     9,842
Capital expenditures		   108,933	    41,969
Identifiable assets		 1,430,516	   368,320
<CAPTION>
NONUTILITY				Independent
					  Oil and	   Power
				   Coal*  	Natural Gas	Investments
<S>                                           <S>          <C>          <C>
Sales to unaffiliated customers		$  255,247	$   97,994	$  93,647
Intersegment sales		    42,201	       254	    1,461
Pre-tax operating income		    48,344	    13,647	   10,912
Earnings (loss) from unconsolidated 
	investments		    (2,740)		    2,080
Depreciation, depletion and amortization		    12,649	    18,464	    3,112
Capital expenditures		    16,115	    32,417	    6,154
Identifiable assets		   291,224	   179,261	  159,138
<CAPTION>
NONUTILITY (continued)
					    Tele-
					communications	   Other  
<S>                                             <C>                <C>
Sales to unaffiliated customers			$   20,655	$    3,441
Intersegment sales			       138	       649
Pre-tax operating income (loss)			     1,188	       (41)
Earnings from unconsolidated 
	investments			        68
Depreciation, depletion and amortization		 	       762	     1,183
Capital expenditures		 	       449	        43
Identifiable assets		  	    14,319	    19,450
<CAPTION>
CORPORATE
<S>                                                 <C>
Capital expenditures		$    1,231
Identifiable assets		    50,469

<FN>
*	Sales under one coal contract with Houston Light and Power Company amounted to 
$101,845,000.  
</FN>
</TABLE>


NOTE 12 - 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. which owned and 
operated the Golden Eagle Mine in Colorado.  In addition, the Nonutility coal 
operations recorded impairment charges of approximately $8,600,000 before tax 
for certain non-producing leaseholds and other investments and the Nonutility 
oil operations recorded an impairment charge of $19,200,000 before tax.  



	SUPPLEMENTARY DATA
	OIL AND NATURAL GAS PRODUCING ACTIVITIES
<TABLE>
<CAPTION>
	For the years ended December 31, 1996, 1995 and 1994 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:  

					                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>
<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>


<TABLE>
<CAPTION>
					                1994             
				   U.S.   	   CANADA   	STORAGE 
<S>                                               <C>         <C>           <C>

PROVED DEVELOPED AND UNDEVELOPED RESERVES:

UTILITY OPERATIONS:
	Natural Gas (Mmcf):
		Beginning Balance	   80,070	     98,871	 56,318
		Production	   (4,742)	(3,350)
		Additions	       87	        570	    230
		(Sales) and Purchases of Reserves in Place
		Revisions - Other	    5,147	        480
		Revisions - Price	         			
			Ending Balance	   80,562	     96,571 	 56,548	

NONUTILITY OPERATIONS:
	Natural Gas (Mmcf):
		Beginning Balance	  140,923	     59,071
		Production	   (9,444)	     (7,785)
		Additions	    4,683	13,830	
		(Sales) and Purchases of Reserves in Place	    2,250	      5,866
		Revisions - Other	   14,385	      4,987
		Revisions - Price	      365	3,314		
			Ending Balance	  153,162	79,283		

	Natural Gas
		Liquids (Bbls):
		Beginning Balance	3,682,700	  1,508,100
		Production	 (376,650)	(172,600)
		Additions	  103,300	    365,300
		(Sales) and Purchases of Reserves in Place	 (116,298)	     81,184
		Revisions - Other	 (199,552)	 217,216
		Revisions - Price	   16,800	300		
			Ending Balance	3,110,300	1,999,500		

	Oil (Bbls):
		Beginning Balance	6,238,700	  4,511,600
		Production	 (440,040)	   (709,248)
		Additions	   77,800	  1,497,400
		(Sales) and Purchases of Reserves in Place	  821,276	   (215,042)
		Revisions - Other	 (740,736)	   (135,310)
		Revisions - Price	  122,700	(14,400)		
			Ending Balance	6,079,700	  4,935,000		
<CAPTION>
				         1994         
				   U.S.   	  CANADA  
PROVED DEVELOPED RESERVES:
<S>                                               <C>        <C>
UTILITY OPERATIONS:
	Natural Gas (Mmcf):
		Ending Balance	   79,731	     96,571

NONUTILITY OPERATIONS:
	Natural Gas (Mmcf):
		Ending Balance	   89,305	     65,454

	Natural Gas Liquids (Bbls):
		Ending Balance	2,588,700	  1,634,200

	Oil (Bbls):
		Ending Balance	3,194,600	  3,437,600
</TABLE


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

	As determined by engineers, Utility natural gas reserves were revised 
during 1996, 1995 and 1994 due to a change in projected performance or a change 
in the Company's ownership interest in specific fields.  

	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 the 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.  

	In 1994, the Nonutility U.S. oil and natural gas reserves increased as a 
result of the acquisition of oil interests in Kansas and the drilling of 25 
development wells and six exploratory wells in Colorado, Montana, Oklahoma and 
Wyoming.  Natural gas liquid reserves decreased due to a lower liquid recovery 
factor experienced at the Fort Lupton, Colorado gas processing plant.  Higher 
oil market prices contributed to an upward revision in U.S. reserves.  The 
Canadian companies participated in 21 development wells and seven exploratory 
wells.  Significant natural gas and natural gas liquid reserves were added as a 
result of exploratory well discoveries in the Grand Prairie and Saddle Lake 
areas of Alberta.  A development well in the Caroline area in Alberta extended 
the new pool discovery from 1993.  Significant oil reserves were added at 
Manyberries because of a new pool discovery and development drilling in 1994.



	The following table presents information for 1996, 1995 and 1994 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>
<TABLE>
<CAPTION>
				       1996      	       1995      	       1994      
					  U.S.  	 Canada 	  U.S.  	 Canada 	  U.S.  	 Canada 
					       Thousands of Dollars
<S>                           <C>      <C>      <C>      <C>      <C>      <C>
UTILITY OPERATIONS
At December 31:
Capitalized costs relating 
	to natural gas producing
	activities		$ 87,363	$ 38,551	$ 89,520	$ 37,683	$ 95,713	$ 36,904
Accumulated depreciation,
	depletion and valuation
	allowances		  46,881	  20,102	  50,377	  19,812	  48,913	  19,386

		Net capitalized costs		$ 40,482	$ 18,449	$ 39,143	$ 17,871	$ 46,800	$ 17,518

For the year ended 
	December 31:  
Costs incurred in natural
	gas property acquisition, 
	exploration and 
	development activities: 
		Acquisition of 
			properties		$    474	$     49	$     48	$    170	$    414	$    259	
		Exploration		54	191	     70	    198	     358	     231	
		Development		501	1,230	  1,753	  1,240	   5,158	   1,203	

Costs reflected in results 
  of operations: 
		Production costs		$  4,773	$  1,510	$  5,710	$  1,592	$  4,795	$  1,348	
		Exploration expenses		54	191	     70	    198	     128	     231	
		Development expenses		22	113	    165	    416	     165	     197	
		Depreciation, depletion
			and valuation 
		  provisions		2,667	711	  2,716	    586	   2,607	     487	

</TABLE




</TABLE>
<TABLE>
<CAPTION>
	The following table presents information for 1996, 1995 and 1994 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:



				       1996      	       1995      	       1994      
					  U.S.  	 Canada 	  U.S.  	 Canada 	  U.S.  	 Canada 
					       Thousands of Dollars
<S>                           <C>      <C>      <C>      <C>      <C>      <C>
NONUTILITY OPERATIONS
At December 31:

Capitalized costs relating
	to oil and natural gas
	producing activities		$182,339	$ 87,529	$171,795	$ 83,457	$145,639	$ 78,667
Accumulated depreciation,
	depletion and valuation 
	allowances		  65,401	  44,770	  60,329	  39,834	  39,534	  27,247

		Net capitalized costs		$116,938	$ 42,759	$111,466	$ 43,623	$106,105	$ 51,420

For the year ended 
	December 31:

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

	Acquisition of 
	  properties		$  4,667	$  3,722	$ 13,024	$  4,407	$  8,134	$  5,866
	Exploration		1,780	2,157	   4,592	  1,642	   2,513	   1,924
	Development		10,651	3,345	  11,244	  4,298	  11,514	   4,068

Results of operations for 
	oil and natural gas 
	producing activities:

		Revenues		$ 26,872	$ 19,789	$ 20,461	$ 19,022	$ 25,319	$ 22,542
		Production costs		8,901	6,547	   7,298	  6,812	   7,261	7,404
		Exploration expenses		1,670	1,747	   2,460	  1,517	   1,610	1,426
		Depreciation, depletion 
			and valuation 
			provisions		 10,019	  6,133	  21,079	 15,371	 10,533	  7,669
					6,282	5,362	 (10,376)		(4,678)	   5,915	6,043

		Income tax expenses		    946	  2,393	 (5,708)	  (2,087)		     25	  2,679

Results of operations from
	producing activities
	(excluding corporate 
	overhead and interest 
	cost)		$  5,336	$  2,969	$ (4,668)	$ (2,591)	$  5,890	$  3,364
</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                 
		         1996         	         1995         
		    U.S.   	  Canada  	    U.S.   	  Canada  
				  Thousands of Dollars   
<S>                                 <C>         <C>         <C>         <C>
Future cash inflows		$  684,709	$  185,988	$  523,563	$  148,140
Future production and  
	development costs		261,432	68,921	197,073	    57,455
Future income tax expenses		   129,091	    27,876	    89,726	    18,033

Future net cash flows		294,186	89,191	    236,764	    72,652
10% annual discount for 
	estimated timing
	of cash flows		   135,285	    23,407	    98,831	    16,163

Standardized measure of 
	discounted future net 
	cash flows		$  158,901	$   65,784	$  137,933	$   56,489

	  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		$  (22,466)	$  (13,242)	$  (33,013)	$  (24,585)
Net changes in prices, 
	development and production 
	costs		16,095	30,948	   (24,122)	    (7,886)
Extensions, discoveries, and 
	improved recovery, less 
	related costs		19,823	2,597	     8,100	     1,728
Revisions of previous quantity 
	estimates		14,012	(11,395)	   (12,950)	     4,860
Accretion of discount		16,939	6,150	    20,816	     7,483
Net change in income taxes		(14,670)	(4,005)	    10,948	     6,315
Other		(8,765)	(1,758)	     2,403	     5,074

</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 1996 and 1995, 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 1996 and 1995 
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>
<TABLE>
<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		57,029	22,749	23,895	59,280
Utility Net Income		27,530	5,644	7,823	29,008

Nonutility Operating Revenues		137,421	110,926	94,560	104,930
Nonutility Operating Income		32,271	16,547	8,385	16,083
Nonutility Net Income		19,026	12,585	6,463	11,307

Consolidated Net Income		46,556	18,229	14,286	40,315

Net Income Per Share of Common
  Stock		$   0.80	$   0.30	$   0.23	$   0.70
<CAPTION>

			                 Quarter Ended                    

			 Dec. 31, 	Sept. 30, 	June 30,  	Mar. 31,
			  1995    	  1995    	  1995    	  1995    
<S>                                 <C>          <C>          <C>          <C>
Utility Operating Revenues		$165,280	$110,248	$108,144	$160,105
Utility Operating Income		61,213	19,218	16,084	59,334
Utility Net Income		32,204	6,251	3,768	30,967

Nonutility Operating Revenues		116,995	117,255	103,891	104,891
Nonutility Operating
  Income (Loss)		(59,267)	10,149	3,060	1,671
Nonutility Net Income (Loss)		(33,320)	9,900	3,802	3,365

Consolidated Net Income (Loss)		(1,116)	16,151	7,570	34,332

Net Income (Loss) Per Share of 
	Common Stock		$  (0.05)	$   0.25	$   0.11	$   0.61

</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 1997 Annual Meeting of Shareholders and 
Proxy Statement, pages 1-3.  

ITEM 11.	EXECUTIVE COMPENSATION

	Incorporated by reference from Notice of 1997 Annual Meeting of 
Shareholders and Proxy Statement, pages 6-8.  

ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

	Incorporated by reference from Notice of 1997 Annual Meeting of 
Shareholders and Proxy Statement, pages 4-5.  

ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

	Incorporated by reference from Notice of 1997 Annual Meeting of 
Shareholders and Proxy Statement, page 14.  



	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 22, 1996	Item 5.  Other Events.  Discussion of Third 
Quarter Net Income.

		Item 7 Exhibits.  Consolidated Statements of 
Income for the Quarters Ended September 30, 
1996 and 1995, Nine Months Ended September 30, 
1996 and 1995, and for the Twelve Months Ended 
September 30, 1996 and 1995. Utility 
Operations Schedule of Revenues and Expenses 
for the Quarters Ended September 30, 1996 and 
1995, Nine Months Ended September 30, 1996 and 
1995 and for the Twelve Months Ended 
September 30, 1996 and 1995. Nonutility 
Operations Schedule of Revenues and Expenses 
for the Quarters Ended September 30, 1996 and 
1995, Nine Months Ended September 30, 1996 and 
1995 and for the Twelve Months Ended 
September 30, 1996 and 1995.

	December 11, 1996	Item 5.  Other Events.  MPC's Board Announces 
Succession Plan.  

	February 21, 1997	Item 5.  Other Events.  Montana Power Company 
and Puget Sound Power and Light Resolve a 
Pending Litigation Matter.  

	February 28, 1997	Item 2.  Acquisition or Disposition of 
Assets.  Montana Power Company, through its 
subsidiary, North American Resources Co., 
announced its commitment to purchase Vessels 
Energy's oil and gas assets in Colorado's 
Denver-Julesburg Basin.



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
	 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



THE MONTANA POWER COMPANY AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
Thousands of Dollars

</TABLE>
<TABLE>
<CAPTION>
     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, 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

December 31, 1994
Reserves deducted
in balance sheet
from assets to 
which they apply:
Doubtful accounts
	Utility	$    748	$    781		$     721	$     808
	Nonutility	     643	     156	$     (9)	      174	      616

		Total	$  1,391	$    937	$     (9)	$     895	$   1,424
	

<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/ Daniel T. Berube                 
   Daniel T. Berube 
   (Chairman of the Board)



Date: March 26, 1997


	Pursuant to the requirements of the Securities Exchange Act of 1934, this 
report has been signed below by the following persons on behalf of the 
registrant and in the capacities and on the dates indicated.  

           Signature          	          Title          	     Date     



/s/ Daniel T. Berube           	Principal Executive
Daniel T. Berube	  Officer and Director	March 26, 1997
(Chief Executive Officer)



/s/ J. P. Pederson             	Principal Financial
J. P. Pederson	  and Accounting Officer	March 26, 1997
(Vice President and Chief	  and Director
  Financial and Information
  Officer)



/s/ Tucker Hart Adams          	Director	March 26, 1997
Tucker Hart Adams



/s/ Alan F. Cain               	Director	March 26, 1997
Alan F. Cain



/s/ R. D. Corette              	Director	March 26, 1997
R. D. Corette



/s/ Robert P. Gannon           	Director 	March 26, 1997
Robert P. Gannon



/s/ Kay Foster                	Director 	March 26, 1997
Kay Foster



/s/ Beverly D. Harris         	Director	March 26, 1997
Beverly D. Harris



/s/ Chase T. Hibbard           	Director 	March 26, 1997
Chase T. Hibbard



/s/ John R. Jester            	Director 	March 26, 1997
John R. Jester



/s/ Daniel P. Lambros          	Director 	March 26, 1997
Daniel P. Lambros



/s/ Carl Lehrkind, III         	Director	March 26, 1997
Carl Lehrkind, III



/s/ James P. Lucas             	Director 	March 26, 1997
James P. Lucas



/s/ Arthur K. Neill            	Director	March 26, 1997
Arthur K. Neill



/s/ N. E. Vosburg              	Director	March 26, 1997
N. E. Vosburg



	EXHIBIT INDEX


Exhibit 3(a)(2)
	Articles of Amendment to the Restated Articles of 
	  Incorporation	100-101

Exhibit 3(b)(1)
	Amendment to By-laws dated August 27, 1996	102-104

Exhibit 10(a)(v)
	Termination Compensation Agreements with Senior Management
	  Executives	105-114

Exhibit 12
	Statement Re Computation of Ratio Earnings to Fixed Charges	115

Exhibit 21
	Subsidiaries of the Registrant	116-118

Exhibit 23
	Consent of Independent Accountants	119

Exhibit 27
	Financial Data Schedule	120






-1-


-15-


-27-


-51-


-81-


	-97-




SIGNATURES (Continued)




-99-







</TABLE>