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 	(FEE REQUIRED)
For the fiscal year ended December 31, 1995
	-OR-
(  )	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES 
EXCHANGE ACT OF 1934 		(NO FEE REQUIRED)

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

	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. 

	Yes  X  No    


The aggregate market value of the voting stock held by nonaffiliates of the 
registrant was $1,277,206,731 at March 18, 1996.  

On March 18, 1996, the Company had 54,632,075 shares of common stock 
outstanding.

	DOCUMENTS INCORPORATED BY REFERENCE

(1)	Notice of 1996 Annual Meeting of Shareholders and Proxy Statement, 
pages 1- 17, is incorporated into Part III of this report.  



PART I

ITEM 1.  BUSINESS  

	GENERAL - INDUSTRY SEGMENTS:  The Montana Power Company (the Company) and 
its subsidiaries engage in a number of diversified and energy related 
businesses.  The Company's principal business, which is conducted through its 
Utility Division, includes regulated utility operations involving the 
generation, purchase, transmission and distribution of electricity and the 
production, purchase, transportation and distribution of natural gas.  The 
Company, through its wholly-owned subsidiary, Entech, Inc. (Entech), engages in 
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.  The Company, through its Independent Power Group (IPG) manages long-
term power sales, and develops and invests in nonutility power projects and 
other energy-related businesses.  See Item 8, "Financial Statements and 
Supplementary Data - Note 10 to the Consolidated Financial Statements" for 
further information.  A group of officers and employees of the Company 
constitute the Office of the Corporation, 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.  

UTILITY DIVISION:

	SERVICE AREA AND SALES:  The Utility Division's service territory 
comprises 107,600 square miles or approximately 73% of Montana.  Within its 
service territory, 86% of the state's population resides.  The Division serves 
approximately 606,000 residents, or 81% of the population within the service 
territory.  Additionally, energy is provided to cooperatives that serve 
approximately 72,000 residents.  Dominant factors in Montana's diversified 
economy are agriculture and livestock, which constitute Montana's largest 
industry, tourism and recreation, coal and metals mining, oil and gas 
production, and the forest products industry which includes the production of 
pulp and paper, plywood and lumber.  

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

	COMPETITIVE ENVIRONMENT:  The electric and natural gas utility 
businesses are in transition to a competitive market.

	Recent federal legislation has opened the Utility Division's electric 
wholesale business to competition from other suppliers. While its retail 
business is now free from competition, the Montana Public Service Commission 
(PSC) has initiated consideration of a transition to retail competition.  The 
Company is preparing for such competition.

	The Utility Division offers its large customers the option of purchasing 
their own natural gas supplies, which the Division will transport to these 
customers.  While its other natural gas customers do not have this choice, the 
Company is preparing for its extension to all customers.

	Competition in both the electric and natural gas utility businesses has 
been heightened in the Northwest by an abundance of low cost electric and 
natural gas supplies, which the Company expects to continue through the end of 
the century.

	In March  1995, the Federal Energy Regulatory Commission (FERC) issued a 
Notice of Proposed Rulemaking (NOPR) on Open-Access Non-Discriminatory 
Transmission Services by Public and Transmitting Utilities and  on Recovery of 
Stranded Costs.  The NOPR would require utilities to file non-discriminatory 
tariffs available to all wholesale buyers and sellers of electricity, require 
utilities to use those tariffs for their own wholesale sales and purchases, 
and allow utilities to recover stranded costs.  A final rule is expected in 
1996.  The Company has filed open-access transmission tariffs with FERC and 
applied for authorization to create an affiliated power marketing subsidiary.

	Central Montana Electric Power Cooperative, Inc.  (Central), which 
manages a contract for purchases of power from the Utility Division by a group 
of Montana cooperatives, provides an example of the growing competition for 
wholesale customers.  Central has given notice of termination, effective in 
June 2000, of this contract, which, during 1995, accounted for 4% of the 
electric energy sold by the Utility Division.  The Utility Division and other 
electric suppliers are in the process of bidding for the cooperatives' power 
requirements beyond June 2000.  The Company is planning to request  FERC to 
authorize recovery of costs which will be stranded by the termination of this 
contract.  The Company cannot predict the extent of stranded cost recovery.

	Among other steps the Company has taken to position itself to meet 
competition, it has joined two regional transmission groups, the Western 
Regional Transmission Association, currently comprised of 63 members; and the 
Northwest Regional Transmission Association, currently comprised of 18 
members.  These groups, whose memberships include transmission owning 
utilities, transmission dependent utilities, non-utility generators, and 
others, were formed to take advantage of the benefits that might arise through 
joint transmission planning and operation and regional transmission tariff and 
pricing developments.  

	The PSC has initiated an inquiry into the restructuring of the electric 
industry in Montana.  The Company is participating in these proceedings and 
plans to file an electric restructuring case with the PSC in the fall of 1996.

	The Company has been ordered by the PSC to file a consolidated natural 
gas structural and cost allocation case in July 1996.  This filing will 
address such issues as transportation thresholds, stranded costs, utility gas 
production costs and rates charged to various customer classes.  The Company 
anticipates that all customers should and will be able to choose a natural gas 
supplier after a transition period.

	These changes in the utility and energy industries have prompted the 
Company to re-evaluate the basic structure of its operations to meet the 
challenges ahead.  The Company is realigning its businesses into two 
divisions.  An energy supply division will be responsible for coal, oil and 
natural gas, and power generation including marketing, brokering and wholesale 
business development.  An energy services and communications division will 
engage in the transmission and distribution of electricity and gas as well as 
telecommunications, energy management services and retail business 
development.  The Company believes this structure will accommodate its 
businesses, yet be flexible enough to fit anticipated federal and state 
mandates.  The new structure is being put in place in 1996 and contemplates a 
five to ten year transition period before open-access will be available to all 
customers.  At the end of the transition period, generation and gas supply 
would be fully deregulated.

	REGULATION AND RATES:  The Company's public utility business in Montana 
is subject to the jurisdiction of the PSC.  The PSC has jurisdiction over the 
issuance of securities by the Company.  FERC also has jurisdiction over the 
Company, under the Federal Power Act, as a licensee of hydroelectric projects 
and as a public utility engaged in interstate commerce.  The importation of 
natural gas from Canada requires approval by the Alberta Energy Resources 
Conservation Board, the National Energy Board of Canada and the United States 
Department of Energy  

	On April 25, 1995, the PSC approved an electric rate increase of 
$13,900,000, on an annual basis, effective May 1, 1995.  This increase affirmed 
a settlement with intervenors and included $7,700,000 which had been authorized 
on November 28, 1994 on an interim basis.  The final order did not identify an 
allowed rate of return.

	On September 21, 1995, the Company filed a request with the PSC to 
increase both electric and natural gas rates.  The Company also offered a 
preferred three-year 'alternative' rate plan.  The filing, as adjusted, 
requests an additional $27,500,000 (7.80%) for electric revenues and $9,200,000 
(7.34%) for natural gas revenues, based upon a 12.0% return on equity. 
Requested interim increases were $11,000,000 for electricity and $4,400,000 for 
natural gas.  On February 14, 1996, the PSC granted interim increases of 
$5,800,000 for electricity and $3,100,000 for natural gas, effective March 1, 
1996.  

	The 'alternative' plan would establish rates for the next three years 
thus eliminating conventional filings until 1998.  The 'alternative' plan 
includes predetermined rate adjustments.  The plan is intended to allow the 
Utility to maintain financial integrity while providing time for parties 
usually involved in rate proceedings, including the Company, the PSC and 
intervenors, to deal with issues related to changes in the utility industry.  

	The 'alternative' plan's three year rate increases, as adjusted, would 
provide the following additional electric and natural gas revenues:  

	    Three Year Plan   	  Electric  	Natural Gas

	Effective July 1996	$19,600,000	$ 7,700,000
	Effective January 1997	 10,400,000	  3,800,000
	Effective January 1998	 10,700,000	  4,100,000


	Hearings on the rate filing are scheduled to begin in April 1996 and a 
decision is expected in June.  

	On December 15, 1995 the Company filed with the PSC its annual gas cost 
tracking application, reflecting a net decrease of $5,100,000 in annual natural 
gas revenues in response to reduced operating costs.  This rate change will not 
affect the Company's overall net income.  

	In 1995, the Company and Central negotiated a $960,000 annual rate 
increase adjustment for the 1995 rate period and agreed to continue an annual 
rate review/adjustment process.

	ELECTRIC UTILITY OPERATIONS:  The maximum demand on the resources in 1995 
was 1,350,000 kW on February 13, 1995.  Total firm capability of the Utility's 
electric system for 1995 was 1,703,000 kW (including resources added in late 
1995).  Of this capability, 1,227,000 kW was provided by the Utility's 
generating facilities, and 476,000 kW was provided by firm Electric Utility 
power purchase and exchange arrangements.  The Electric Utility's reserve 
margin on February 13, 1995, as a percentage of maximum demand, was 19%.  

	The Company's future need for electric resources is to meet winter peak 
requirements.  Future power needs could change depending on wholesale wheeling 
customer gains or losses, and changes that retail wheeling would cause, if it 
occurs.  In 1995, the electric utility's resource capability was increased by 
the Thompson Falls 41,000 kW hydroelectric upgrade and a 57,000 kW power 
purchase from Billings Generation Inc.  The Billings Generation Inc. purchase 
is being acquired under a PURPA Qualifying Facility (QF) contract.  In 1996, 
two purchase power contracts totaling approximately 150,000 kW will terminate.  

	As part of its planning activities, the Company biannually prepares an 
Electric Least Cost Resource Plan (Plan), which is filed with the PSC.  The 
document identifies the Company's expectations for load and energy requirements 
as well as the resources expected to meet those requirements.  The plan, which 
is prepared with input from low income, large user and environmental groups, 
considers societal and environmental costs in addition to actual dollar costs. 
The plan is referred to as "dynamic" indicating that it is responsive to 
change.  A comparison of the 1993 plan to the 1995 plan demonstrates the 
changes taking place as a result of competition.  The comparative costs of 
specific resources have changed drastically in two years with wholesale 
purchases becoming a cheaper resource.  The plan has been modified to rely more 
heavily on purchases to meet peak demand.  As a result, future demand side 
management expenditures have been reduced and expansion of Company owned 
generating facilities has been postponed.  



ITEM 1.  BUSINESS (Continued)

	During the year ended December 31, 1995, the sources of the Utility 
Division electric supply were:  hydro, 32%; coal, 44%; and purchased power, 
24%.  The cost of coal burned has been as follows:

	  Year Ended December 31 
	  1995  	 1994  	 1993 

	Average cost per million Btu's		$ 0.56	$ 0.66 	$ 0.65 
	Average cost per ton (delivered)		  9.67	 11.24 	 11.16 

	The average cost of coal declined in 1995 due to the Colstrip Units 1 
and 2 Coal Supply Agreement arbitration decision and reduced generation at the 
incrementally more expensive Colstrip Unit 3. See Item 8, "Financial 
Statements and Supplementary Data - Note 2 to the Consolidated Financial 
Statements."

	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 74 member systems and 
11 affiliates in the 14 western states, British Columbia, Alberta and Mexico to 
assure reliability of operations and service to their customers; is one of 
97 members of the Western Systems Power Pool, organized to enhance the 
economics of power production and reliability of service among the western 
states power systems; and is a party to the Intercompany Pool Agreement for the 
coordination of load, resource and transmission planning, operations and 
reserve requirements among eight utilities in Washington, Oregon, Idaho, 
Montana, Wyoming, Nevada and Utah.  The Company participates in an 
interconnection agreement with The Washington Water Power Company, Idaho Power 
Company, and PacifiCorp, providing for the sharing of transmission capacity of 
certain lines on their respective interconnected systems.  The Company also 
operates, in coordination with its own transmission lines and facilities, the 
transmission lines and facilities which are jointly owned by the utility owners 
of the four Colstrip generating units.  The Company and the Western Area Power 
Administration have transmission interconnection and agreements which provide 
for the mutual use of excess capacity of certain lines on each party's system 
for the transmission of power east of the Continental Divide in Montana and for 
the firm use of certain of the Company's transmission lines to deliver 
government power.  

	NATURAL GAS UTILITY OPERATIONS:  Natural gas supply requirements in 1995 
totaled 21,173 Mmcf, of which 12,792 Mmcf were from Montana and 8,381 Mmcf from 
Canada.  The Gas Utility produced 43% of the Montana natural gas and its 
Canadian subsidiaries produced 64% of the Canadian natural gas.  

	The Company implemented open-access gas transportation on November 1, 
1991.  As of September 1993, substantially all eligible customers were 
acquiring 100% of their gas supplies directly from other suppliers.  The Gas 
Utility transports gas supplies for these customers.  The total volumes of 
natural gas transported were 26,700 Mmcf, 23,700 Mmcf and 17,900 Mmcf for 1995, 
1994 and 1993, respectively.  

	Total 1996 natural gas requirements, estimated to be 21,870 Mmcf, are 
anticipated to be supplied from existing reserves and purchase contracts. 
Approximately 12,563 Mmcf of these requirements are expected to be obtained in 
the United States and 9,307 Mmcf from Canada.  The Gas Utility expects to 
produce 45% of the Montana natural gas and 53% of the Canadian natural gas. The 
1996 transportation volumes are anticipated to be 26,800 Mmcf.  

	Exportation of natural gas from Canada is controlled by the Canadian 
provincial and federal governments.  The Company has a long-term export license 
which entitles it to export up to 10,000 Mmcf annually through October 2006.  

ENTECH:

	GENERAL:  Entech conducts its businesses through various subsidiaries. It 
also owns a passive investment in a gold mine in Brazil.

	Entech's 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. 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) markets coal, and 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.  See Item 7, 
"Management's Discussion and Analysis of Financial Condition and Results of 
Operations - Entech Operations - Coal Operations - 1995 Compared to 1994 - 
Expenses" and Item 8, "Financial Statements and Supplementary Data - Note 11 to 
the Consolidated Financial Statements."

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

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

	Entech's other businesses are conducted by various subsidiaries, none of 
which is a significant subsidiary.

	COMPETITIVE ENVIRONMENT:	 The Rosebud Mine faces competition from the 
Montana and Wyoming Powder River Basin producers. The Montana and Wyoming 
producers generally experience lower stripping ratios, royalties and 
production taxes. Additionally, the Wyoming coal is a lower sulfur coal. The 
Midwestern coal contracts that expired were not extended due to the extremely 
low prices of competing coals. The Rosebud Mine does have a stable future due 
to the long-term contracts to supply the mine-mouth Colstrip units. The Jewett 
Mine sells its entire production under an exclusive supply contract to the two 
750 megawatt Limestone Units.  In 1996, substantially all of the Company's 
coal and lignite production is expected to be sold under long-term exclusive 
supply contracts.

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

	The Telecommunications Division 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.  The 
Telecommunication Division provides services in the regional marketplace and 
has made economic investments which allow it to compete effectively.

	COAL OPERATIONS:  Western's Rosebud Mine is at Colstrip, Montana, in the 
northern Powder River Basin, where coal is surface-mined and, after crushing, 
sold without further preparation, principally for use by electric utilities in 
steam-electric generating plants.  Western's principal customers from this mine 
are the owners of the four mine-mouth Colstrip units, the SynCoal plant, and 
the Utility Division's Corette Plant located in Billings, Montana.  These 
customers accounted for approximately 79% of 1995 coal sales. The remainder of 
Rosebud coal was sold under spot-market sale agreements and contracts in 
Michigan, Minnesota, North Dakota, Wisconsin and Montana.  The Midwestern 
contracts made up 18% of 1995 coal sales of which one representing 9% expired 
and was not renewed at the end of 1995.

	During 1995, Western mined and sold 11,493,179 tons, of which 3,462,483 
tons were sold to the Company.  Western's Rosebud Mine production is estimated 
to be 8,000,000 tons in 1996, as a result of the Colstrip Units 3 & 4 reduced 
coal purchases, and 10,325,000 tons in 1997.  Coal production in 1996 is 
expected to be lower due to the availability of hydroelectric generation in the 
Pacific Northwest, expiration of a Midwestern customer contract at the end of 
1995 and reduced sales to the Corette Plant.

	Northwestern's Jewett Mine is located between Dallas and Houston, Texas. 
Northwestern supplies lignite under a long-term contract to the two electric 
generating units, located adjacent to the mine, that are owned by Houston 
Lighting and Power Company.  Total deliveries in 1995, were 8,268,149 tons. The 
estimated production for 1996 and 1997 are 8,200,000 and 8,400,000 tons, 
respectively. After 1997, production is estimated to be approximately 8,500,000 
tons annually.

	Basin's underground Golden Eagle Mine is located near Trinidad, Colorado. 
Total deliveries from the mine were 872,043 tons during 1995.  As discussed 
above under "General", Basin ceased production in December 1995.



	OIL AND GAS OPERATIONS:  The Oil and Gas Division is 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 
126,000 Mmcf of natural gas to four co-generation facilities over a period of 9 
to 15 years with performance guaranteed by Entech.  NARCO has sufficient 
proven, developed and undeveloped reserves to supply all of the remaining 
natural gas required by those agreements.  None of the reserves are dedicated 
to supply these agreements.

	Natural gas production in both the United States and Canada is currently 
sold pursuant to short-term, spot-market and long-term contracts. Approximately 
18,960 Mmcf, or 30.3% of Altana's and Roan's natural gas reserves,  are 
dedicated to long-term contracts expiring at various times through 2005.

	Through a subsidiary, Entech owns a minority interest in a joint venture 
to construct the proposed Altamont pipeline.  In 1991, Altamont received FERC 
approval to construct a 620 mile pipeline running from the Alberta-Montana 
border to Muddy Creek, Wyoming.  The decision to proceed with the construction 
of this pipeline will depend upon obtaining the necessary regulatory approval 
and shipper commitments by July 1996 unless approval is extended.

	TELECOMMUNICATIONS:  Touch America's network provides long distance and 
private line sales and services to customers in Montana, Idaho, Washington and 
Oregon.  The telecommunications system includes private, dedicated 
communication lines throughout Montana on a digital microwave and fiber 
network.  Touch America is currently in the process of installing a fiber optic 
cable in Montana, Wyoming and Colorado that is expected to be in service in 
early 1997. This cable will connect to other carriers to provide interstate and 
international communications.

	Touch America sells, installs and maintains telephone equipment in the 
states of Montana, Idaho, Washington, Oregon and Wyoming.  Touch America 
markets and maintains PBX and key systems, call accounting systems and voice 
mail systems.

	Touch America provides telecommunication services to over 
12,000 customers.



INDEPENDENT POWER GROUP:

	GENERAL:  The Independent Power Group (IPG), which consists of 
Continental Energy Services, Inc. (CES) and Colstrip 4 Lease Management 
Division, manages sales of the Company's 210 megawatt share of Colstrip Unit 4 
generation to the Los Angeles Department of Water and Power and to Puget Sound 
Power & Light Company (Puget) under contracts which are coextensive with the 
Company's leasehold interest in the Unit.

	Through CES, the IPG has invested in six operating, natural gas fired, 
independent power projects located in Texas, New York, Washington and the 
United Kingdom, one heavy oil-fired project in Jamaica, and one independent 
power project under construction in Texas.  In addition to other project 
acquisition and development activities, CES is participating with others in the 
development of a coal-fired project in India.  In early 1996, the IPG elected 
to withdraw from the development of a coal-fired project in China.  

	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 and an arbitration involving the 
termination of a contract for power from a plant under construction at 
Frederickson, Washington.  

ENVIRONMENT:  

	The information required in this section is contained in Item 7, 
"Management's Discussion and Analysis of Financial Condition and Results of 
Operations" under "Environmental Issues."  

EMPLOYEES:

	At December 31, 1995, the Company and its subsidiaries employed 
3,278 persons of which 2,112 were utility and Office of the Corporation 
employees (including 511 employees at the jointly owned Colstrip Units 1-4), 
9 Independent Power Group employees and 1,157 Entech 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 DIVISION:

	ELECTRIC PROPERTIES:  The Company's Utility Division electric system 
extends through the western two-thirds of Montana.  Generating capability is 
provided by four coal-fired thermal generation units, with total net capability 
available to the Utility of 697,000 kW, and 12 hydroelectric projects, with 
total net capability of 530,000 kW.  The thermal units are (1) Colstrip Unit 3, 
which has a net capability of 727,000 kW, of which the Company owns 218,000 kW, 
(2) Colstrip Units 1 and 2, with a combined net capability of 638,000 kW, of 
which the Utility owns 319,000 kW, and (3) the 160,000 kW wholly-owned Corette 
Plant.  All of the Utility's Colstrip coal requirements are supplied by Western 
Energy Company under long-term contracts.  Reliability of service is enhanced 
by the location of hydroelectric generation on two separate watersheds with 
different precipitation characteristics and by various sources of thermal 
generation.  

	In addition to the Utility's hydroelectric and thermal resources, it 
currently receives power through 22 power contracts totaling 476,000 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, 1995, the Utility owns and operates 6,911 miles of 
transmission lines and 15,255 miles of distribution lines.  

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

	All of the Utility's natural gas customers are served from its 
transmission system which extends through the western two-thirds of Montana. 
System reliability is enhanced by four natural gas storage fields which enable 
the Utility to store natural gas in excess of system load requirements during 
the summer for delivery during winter periods of peak demand.  

	At December 31, 1995, the Gas Utility and its subsidiaries owns and 
operates 2,070 miles of natural gas transmission lines and 3,219 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, 1995, 
controlled under purchase contracts, 60,116 Mmcf of proven reserves in the 
United States and 27,999 Mmcf in Canada.  No significant change has occurred 
and no event has taken place since December 31, 1995, 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:  
<TABLE>
<CAPTION>
	         United States        	            Canada            
	Produced	Royalty	Purchased	Produced	Royalty	Purchased
<S>            <C>         <C>       <C>          <C>        <C>         <C>
1993		  5,587	   539	  8,554	 3,927	 1,186	  2,824
1994		  4,724	   230	  7,565	 3,350	   998	  2,709
1995		  5,176	   632	  7,292	 4,650	   735	  3,031
</TABLE>
	The following table presents information as of December 31, 1995, 
concerning the Utility natural gas wells and the owned or leased acreages in 
which they are located.  

		United States	   Canada  

	Gross productive wells		       616	      177
	Net productive wells		       503	      166  
	Gross wells with multiple completions		        19	       11 
	Net wells with multiple completions		        13.8	       10.5

	Gross producing acres		   387,149	  154,716
	Net producing acres		   294,756	  137,808
	Gross undeveloped acres		    32,776	   79,360
	Net undeveloped acres		    27,313	   72,752

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

	The Company anticipates that during 1996 total exploration and 
development expenditures (expense and capital) will be approximately $1,300,000 
in the United States and approximately $1,700,000 in Canada.  

	The following table presents information on utility natural gas 
exploratory and development wells drilled during 1995, 1994 and 1993.   

		   United States   	     Canada     
		1995 	1994 	1993 	1995	1994	1993

Net productive exploratory
  wells		  -	   -	   -	  -	  -	  -
Net dry exploratory wells		  -	   -	   -	  -	  -	  -
Net productive development
  wells		14.81	 14.38	 12.25	4.00	6.00	  -
Net dry development wells		 1.60	  4.00	  2.00	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 1995, 
1994 and 1993.  Revenues per Mcf are computed based on volumes at varying 
pressure bases as billed.  

			 Year Ended December 31 
	Customer Classification		 1995 	 1994 	 1993 

	Residential		$ 4.74	$ 4.64	$ 4.35
	Commercial		  4.54	  4.43	  4.20
	Industrial		  4.33	  4.25	  4.02
	Other gas utilities		  3.64	  3.72	  3.38

	The following table presents the average production cost per Mcf for 
produced utility natural gas, in U. S. dollars, for the three years 1995, 1994 
and 1993.  

			United States	Canada

	1993		$    0.89	$ 0.36
	1994		     1.01	  0.40
	1995		     1.10	  0.34

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

ENTECH:  

	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 on December 29, 1995. 
Management is attempting to sell these reserves.  

	Western has coal mining leases covering approximately 536,000,000 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 200,000,000 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 223,000,000 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.

	In 1990, Northwestern acquired surface rights and coal leases which 
contain approximately 628,000,000 proved and probable, and recoverable, tons of 
compliance quality surface-mineable coal reserves in the southern Powder River 
coal region located near Gillette,  Wyoming.  In January 1993, an adjacent 
federal lease was acquired which contains approximately 56,000,000 proved and 
probable, and recoverable tons of compliance quality coal reserves.  The coal 
reserves average less than 0.6 pounds of sulfur per million BTU (compliance 
quality).  The application with the Department of Interior to combine these 
leases into one logical mining unit, which was granted in December 1993, 
requires the property to be developed by 2002.  A permit application was 
submitted to the Wyoming Department of Environmental Quality in November 1994. 
The leases were transferred to Horizon in the fourth quarter 1995.  Horizon 
expects to receive the mine permit by the third quarter of 1996.  No definite 
plans for mine development have been made.  

	Horizon's undeveloped mining leases in southeastern Alabama and central 
Texas were released at the end of 1995.

	OIL AND NATURAL GAS PROPERTIES:  No significant change has occurred and 
no event has taken place since December 31, 1995, which would materially affect 
the estimated quantities of proved reserves.  For information pertaining to net 
recoverable Entech oil and natural gas reserves, see Item 8, "Financial 
Statements and Supplementary Data."  

	All Entech natural gas volumes are at a pressure base of 14.73 psia at 
60 degrees Fahrenheit.

	Entech 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 1995, 1994 and 
1993.
<TABLE>
<CAPTION>
			            Year Ended December 31            
			     1995     	     1994     	     1993     
			United		United		United
			States	Canada	States	Canada	States	Canada
<S>                                      <C>     <C>     <C>     <C>     <C>     <C>
Average sales price:  
	Per Mcf of natural gas		$ 1.21	$ 0.99	$ 1.60	$ 1.48	$ 1.84	$ 1.25
	Per barrel of oil		 16.55	 15.29	 14.75	 12.95	 17.61	 14.21
	Per barrel of natural gas liquids		  8.17	 11.33	  9.50	  9.99	 10.98	 11.66
</TABLE>
Average production cost:
	Per barrel of oil equivalent		$ 3.36	$ 2.90	$ 3.00	$ 2.93	$ 3.84  $ 3.02

	Natural gas production was converted to barrel of oil equivalents based 
on a ratio of 6 Mcf to 1 barrel of oil.

	Entech's oil, natural gas and natural gas liquids production was sold 
under short-term and long-term contracts at posted prices or under forward 
market arrangements.  From 1994 to 1995, Entech's average sales prices changed 
due to fluctuations in the market.  Entech's average production cost in the 
U.S. reflects higher lease operating expenses due to declining production in 
older fields and startup waterflood injection costs.  Increased production from 
this waterflood is expected in late 1996. 

	Information on Entech natural gas and oil wells and the owned or leased 
acreage in which they are located, as of December 31, 1995, is presented below.

	    United
	    States   	  Canada  

Gross productive natural gas wells	474		134
Net productive natural gas wells	299.53	 83.65
Gross productive oil wells	253		181
Net productive oil wells	184.29	 96.49

Gross producing acres	209,505	152,453
Net producing acres		 80,332	75,359
Gross undeveloped acres		264,212	240,567
Net undeveloped acres		146,011	162,639

	The wells located in Canada include multiple completions of 8 gross 
productive natural gas wells and 6.70 net productive gas wells.

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

	It is anticipated that during 1996 total exploration, acquisition and 
development expenditures (expense and capital) will be approximately 
$19,532,000 in the United States and approximately $11,780,000 in Canada.  



	The following table presents information on Entech oil and natural gas 
exploratory and development wells drilled during 1995, 1994 and 1993.
<TABLE>
<CAPTION>
		    United States    	        Canada        
		 1995 	 1994 	 1993 	 1995 	 1994 	 1993  
<S>                                 <C>    <C>    <C>     <C>     <C>    <C>
Net productive natural gas
	exploratory wells		 2.99	 1.15	 1.25	 0.50	 0.87	 0.87
Net productive oil
	exploratory wells		 1.00	   -	 3.00	   -	   -	 1.04
Net productive natural gas
	development wells		 6.23	 6.28	32.16	   -	 1.06	 5.70
Net productive oil
	development wells		 1.34	 1.29	 4.12	 7.38	 8.67	 6.56
Net dry exploratory wells		 2.50	 3.44	 2.79	 1.69	 2.00	 5.92
Net dry development wells		 4.24	 0.59	 2.76	 0.50	 3.05	 3.00
</TABLE>
	For information on properties acquired, see Item 8, "Financial Statements 
and Supplementary Data."  



INDEPENDENT POWER GROUP:

	The IPG manages the sale of power from the Company's 210 MW Colstrip 4 
leased interest and associated common and transmission facilities.  The IPG 
also has ownership or contract rights in a number of nonutility power 
generation projects:  
<TABLE>
<CAPTION>
Projects in Operation:  
				 IPG
				Share
				 of
			Rated	Rated
	   Location		Capa-	Capa-
	 (Commercial	 Ownership	city	city	           Customer          
    Project     	  Operation)  	or Interest	  MW  	 MW  	 Electricity  	  Thermal   
<S>               <C>               <C>       <C>      <C>  <C>             <C>
Encogen One	Sweetwater, TX	  49.5%	  255	 126	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
Jamaica Barge	Old Harbour,	  17.6%	   74	  13	Jamaica Public	   None
	  Jamaica				  Service
	    (1995)

(1)	These co-generation facilities have a long-term contract with NARCO (an Entech 
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.  
</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

Tenaska-	Cleburne, TX	    25.0%	 258	  65	Brazos REA	Distilled
 Cleburne	    (1997)					  Water Plant

(3)	Construction is 50% complete but has been suspended due to a dispute with the 
Bonneville Power Administration (BPA).  See Item 8, "Financial Statements and 
Supplementary Data - Note 2 to the Consolidated Financial Statements".
</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>
India-	State of Andhra	  (4)	 500	 (4)	State of Andhra	None
 Krishnapatnam	  Pradesh				  Pradesh

(4)	Not determinable at this time.  
</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

Corporate Officers:  

	In 1992, D. T. Berube, 62, was elected Chairman of the Board and Chief 
Executive Officer.  He served as President and Chief Operating Officer, Entech, 
Inc., 1988-1991.  

	On January 23, 1996, R. P. Gannon, 51, was elected Vice Chairman and 
President.  He has been President since 1990.  He was Chief Operating Officer - 
Utility Division from 1990-1996.  

	In 1991, J. P. Pederson, 53, was elected Vice President and Chief 
Financial Officer.  He served as Vice President Corporate Finance 1990-1991.  

	In 1993, P. K. Merrell, 43, was elected Vice President and Secretary. She 
served as Staff Attorney 1981-1991, Assistant Secretary 1991-1992, and 
Secretary 1992-1993.  

	In 1991, M. E. Zimmerman, 47,	was elected Vice President and General 
Counsel.  He served as General Counsel from 1989-1991.  


Utility Division Officers:  

	On January 23, 1996, J. D. Haffey, 50, 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 1994, A. K. Neill, 58, was elected Executive Vice President - 
Generation and Transmission.  He had previously served as Executive Vice 
President - Utility Services from 1987-1994.  

	In 1993, D. A. Johnson, 51, was elected Vice President - Utility 
Services.  He had previously served as Vice President - Gas Supply and 
Transportation for the Utility Division from 1984-1993.  

	In 1993, C. D. Regan, 59, was elected Vice President - Natural Gas Supply 
and Transportation.  He had previously served as Vice President - Energy 
Services for the Utility Division from 1986-1993.  

	On July 17, 1995, M. C. Enterline, 47, was elected Vice President - 
Colstrip Project Division for the Utility Division.  He had previously served 
as Manager of Business and Change Management from 1994-1995 and was 
Superintendent of Colstrip Units l and 2 from 1988-1994.  

	In 1993, W. C. Verbael, 58, was elected Vice President - Accounting, 
Finance and Information Services.  He had previously served as Vice President - 
Accounting and Finance for the Utility Division from 1984-1993.  

	In 1993, P. J. Cole, 38, was elected Treasurer for the Utility Division. 
He served as Manager, Corporate Financial Planning and Analysis 1986-1992, and 
as Assistant Treasurer 1992-1993.  

	In 1990, J. S. Miller, 52, was elected Controller for the Utility 
Division.  


Entech Officers:  

	In 1992, J. J. Murphy, 57, was elected President and Chief Operating 
Officer - Entech, Inc.  He served as President and Chief Operating Officer, 
Western Energy and Northwestern Resources Co., 1988-1991.  

	In 1985, E. M. Senechal, 46, was elected Vice President and Treasurer - 
Entech, Inc.  


Independent Power Group Officer:  

	In 1992, R. F. Cromer, 50, was elected President and Chief Operating 
Officer - Continental Energy Services, Inc.  He served as Vice President and 
General Manager, Continental Energy Services  1989-1992.  



	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 
1995 and 1994.  The number of common shareholders of record on December 31, 
1995, was 42,441. 

				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


				Dividends
				Declared
				   per	  
	    1994    	  High  	   Low  	  Share    

	1st quarter	$ 25.875	$ 23.250	$  0.40
	2nd quarter	  25.000 	  22.125	   0.40
	3rd quarter	  24.625 	  21.750	   0.40
	4th quarter	  24.000 	  22.250	   0.40



ITEM  6.  SELECTED FINANCIAL DATA  

The Montana Power Company and Subsidiaries

Balance Sheet Items (000)
			   1995   	   1994   	   1993   
Assets:
	Utility plant		$2,205,564	$2,071,749	$1,943,428	
	Less accumulated depreciation 
	  and depletion		   663,215	   619,195	   572,141	
		Net Utility plant		 1,542,349	 1,452,554	 1,371,287	
	Entech property		   559,722	   530,167	   526,692	
	Less accumulated depreciation
	  and depletion		   232,947	   189,926	   182,129	
	 	Net Entech property		   326,775	   340,241	   344,563	
	Independent Power Group property		    72,179	    70,132	    70,077 	
	Less accumulated depreciation		    19,666	    17,560	    16,822	
		Net Independent Power Group		    52,513	    52,572	    53,255	
		  Total net plant and property		 1,921,637	 1,845,367	 1,769,105 	
	Other assets		   664,454	   667,330	   616,922	
		  Total Assets		$2,586,091	$2,512,697	$2,386,027	

Liabilities:
	Common shareholders' equity		$  976,043	$  988,100	$  945,651	
	Unallocated stock held by Trustee
	  for Deferred Savings and ESOP		   (30,565)	   (32,580)	   (34,419)	
	Preferred stock		   101,416	   101,416	   101,419	
	Long-term debt		   616,574	   588,876	   571,870	
	Other liabilities		   922,623	   866,885	   801,506	
		  Total Liabilities		$2,586,091	$2,512,697	$2,386,027	



ITEM  6.  SELECTED FINANCIAL DATA  

The Montana Power Company and Subsidiaries

Balance Sheet Items (000)
			   1992   	   1991   	   1990   
Assets:
	Utility plant		$1,854,297	$1,774,185	$1,712,255
	Less accumulated depreciation 
	  and depletion		   533,216	   495,720	   468,201
		Net Utility plant		 1,321,081	 1,278,465	 1,244,054
	Entech property		   482,732	   464,978	   403,169
	Less accumulated depreciation 
	  and depletion		   163,185	   144,691	   124,309
	 	Net Entech property		   319,547	   320,287	   278,860
	Independent Power Group property		    69,805	    66,477	    66,507
	Less accumulated depreciation		    15,090	    11,633	    10,583
		Net Independent Power Group		    54,715	    54,844	    55,924
		  Total net plant and property		 1,695,343	 1,653,596	 1,578,838
	Other assets		   590,079	   564,450	   537,686
		  Total Assets		$2,285,422	$2,218,046	$2,116,524

Liabilities:
	Common shareholders' equity		$  902,989	$  862,601	$  821,521
	Unallocated stock held by Trustee
	  for Deferred Savings and ESOP		   (36,098)	   (37,631)	   (39,031)
	Preferred stock		    51,984	    51,984	    51,984
	Long-term debt		   581,179	   603,266	   599,971
	Other liabilities		   785,368	   737,826	   682,079
		  Total Liabilities		$2,285,422	$2,218,046	$2,116,524



Income Statement Items (000)
				   1995   	   1994   	   1993   

	Revenues		$  953,539	$1,005,970	$1,024,285

	Expenses:
		Operations		   424,443	   440,472	   480,382
		Maintenance		    68,286	    75,357	    70,029
		Selling, general and administrative		    98,327	   103,127	   101,251
		Taxes other than income taxes		    89,858	    99,200	    92,430
		Depreciation, depletion and 
			amortization		    86,976	    86,711	    82,696
		Writedowns of long-lived assets (a)		    74,297	          	          
					   842,187	   804,867	   826,788

			Income from operations		   111,352	   201,103	   197,497

	Interest expense and other income:
		Interest		    43,788	    42,817	    48,023	
		Other (income) deductions - net		   (10,947)	   (10,532)	   (11,857)	
					    32,841	    32,285	    36,166	

	Income taxes		    21,574	    55,226	    54,120	

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

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

	Net income per share of common stock:
		Utility operations		$     1.22	$     0.91	$     1.07	
		Entech operations		     (0.38)	      0.90	      0.91	
		Independent Power Group operations		      0.08	      0.19	       -  	
				$     0.92	$     2.00	$     1.98	

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

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


(a)	Refer to Item 8, "Financial Statements and Supplementary Data - Note 11 	
		to the 	Consolidated Financial Statements."



Income Statement Items (000)
				   1992   	   1991   	   1990   

	Revenues		$  943,872	$  889,254	$  795,528	

	Expenses:
		Operations		   416,072	   368,797	   322,010	
		Maintenance		    70,525	    70,510	    66,634	
		Selling, general and administrative		    87,545	    88,926	    78,188	
		Taxes other than income taxes		    94,328	    86,428	    82,418	
		Depreciation, depletion and 
			amortization		    81,732	    75,782	    65,790	
		Writedowns of long-lived assets		          	          	          
					   750,202	   690,443	   615,040 	

			Income from operations		   193,670	   198,811	   180,488 	

	Interest expense and other income:
		Interest		    49,166	    52,897	    53,537	
		Other (income) deductions - net		    (8,200)	   (10,194)	    (8,235)	
					    40,966	    42,703	    45,302	

	Income taxes		    45,639	    50,393	    40,206	

	Net income		   107,065	   105,715	    94,980	
	Dividends on preferred stock		     3,790	     3,790	     3,790 	

	Net income available for common stock		$  103,275	$  101,925	$   91,190 	

	Net income per share of common stock:
		Utility operations		$     0.97	$     0.98	$     0.89	
		Entech operations		      0.98	      0.98	      0.94	
		Independent Power Group operations		      0.07	      0.07	      0.01	
				$     2.02	$     2.03	$     1.84 	


	Dividends declared per share of 
  	common stock		$     1.55	$    1.495	$    1.435 	

	Average shares outstanding (000)		    51,126	    50,317	    49,657 	



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 1993 through 
1995. Also presented are factors which are expected to have an impact on 
operating results in the future.

Net Income Per Share of Common Stock:  

The Company's net income available for common stock decreased to 
$49,710,000 in 1995 compared to $106,365,000 and $102,858,000 in 1994 and 1993, 
respectively.  The following table shows the sources of consolidated net income 
on a per share basis.  


		 1995 	 1994 	 1993 

	Utility Operations	$ 1.22	$ 0.91	$ 1.07
	Entech	 (0.38) 	  0.90	  0.91
	Independent Power Group	  0.08	  0.19	     -

		$ 0.92	$ 2.00	$ 1.98



	The decrease in 1995 consolidated net income was largely due to the 
writedown of an investment in an underground mine in Colorado and the adoption 
of a new financial accounting standard "Accounting for the Impairment of Long-
Lived Assets and for Long-Lived Assets to be Disposed Of" (SFAS No. 121).  The 
impairments, recorded as of October 1, 1995, resulted in an after tax charge to 
income of approximately $46,000,000 or 85 cents per share.  The after tax 
writedown of the investment in the underground coal mine was $29,000,000 and of 
certain other non-regulated coal, oil and gas properties was $17,000,000.  For 
further information concerning the mine closure see "Entech Operations - Coal 
Operations - 1995 Compared to 1994 - Expenses."  

	Net income for 1995 was also adversely impacted by 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 Entech's earnings 
by 18 cents. The lower contract price will reduce pre-tax consolidated net 
income approximately $3,500,000 per year.

	Utility operations benefited from a 16% increase in low-cost 
hydroelectric generation in 1995.  Favorable hydroelectric conditions increased 
the availability of low-cost power in the regional energy market, displacing 
higher cost thermal energy.  These conditions and the arbitration decision 
increased Utility earnings.  Entech's earnings for the year also declined as 
the result of reduced coal volumes sold due to the displacement of generation 
at the Colstrip units by low-cost hydroelectric power and the expiration of a 
Midwestern coal contract in 1994.  

	The hydroelectric conditions that displaced thermal generation and 
reduced Entech's 1995 earnings are expected to continue into 1996.

	The Independent Power Group's earnings were lower in 1995, reflecting the 
absence of development revenues. Increased income from operating projects 
partially offset this expected decrease.  

	Consolidated net income per share for 1994 increased due to higher 
Independent Power Group earnings resulting from power project development 
revenues and improved performance by the Colstrip units.  Despite higher 
revenues from rate increases, customer growth, increased industrial electric 
loads and the Colstrip units' improved performance, the Utility Division 
earnings were lower due to less favorable hydroelectric generation and 
wholesale energy market conditions.  Also contributing to the decrease in 
earnings were increased property taxes, a regulatory disallowance on coal 
purchases and warmer weather.  Entech earnings were comparable to 1993.  A 1993 
non-recurring gain on the sale of an Entech Oil Division non-strategic asset 
and losses at the underground mine in Colorado were offset by increased coal 
sales from Montana and Texas mines.  



<TABLE>
<CAPTION>

			        UTILITY OPERATIONS
			      Year Ended December 31        
			   1995   	   1994   	   1993   
			       Thousands of Dollars
<S>                                                  <C>         <C>          <C>
ELECTRIC UTILITY:

REVENUES
	Revenues		$  422,019	$  427,686	$  426,746
	Intersegment revenues		     5,793	     5,924	     7,532
			   427,812	   433,610	   434,278

EXPENSES
	Power supply		   148,240	   178,927	   172,190
	Transmission and distribution		    26,916	    27,566	    28,109
	Selling, general and administrative		    41,932	    46,134	    43,284
	Taxes other than income taxes	 	    43,302	    42,214	    39,014
	Depreciation and amortization		    42,506	    40,699	    39,151
				   302,896	   335,540	   321,748

	INCOME FROM ELECTRIC OPERATIONS		   124,916	    98,070	   112,530

NATURAL GAS UTILITY:  

REVENUES
	Revenues (other than gas supply
		cost revenues)		    93,460	    88,914	    87,634
	Gas supply cost revenues		    21,660	    18,191	    23,062
	Intersegment revenues		       862	       917	       778
				   115,982	   108,022	   111,474

EXPENSES
	Gas supply costs		    21,660	    18,191	    23,062
	Other production, gathering and exploration		     9,662	     8,882	     9,331
	Transmission and distribution		    10,932	    10,154	     9,256
	Selling, general and administrative		    17,161	    17,669	    17,162
	Taxes other than income taxes		    14,841	    13,708	    12,715
	Depreciation, depletion and amortization		    10,793	     9,842	     9,006
				    85,049	    78,446	    80,532

	INCOME FROM GAS OPERATIONS		    30,933	    29,576	    30,942

INTEREST EXPENSE AND OTHER INCOME: 
	Interest		    44,029	    43,013	    46,885
	Other (income) deductions - net		    (5,417)	    (3,947)	      (839)
				    38,612	    39,066	    46,046

INCOME BEFORE INCOME TAXES		   117,237	    88,580	    97,426

INCOME TAXES		    44,047	    33,171	    37,364

UTILITY NET INCOME		$   73,190	$   55,409	$   60,062
</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, the temperatures in 1995 
in the Company's service territory were equal to the historic average and 
6% colder than 1994.  Temperatures in 1994 were 13% warmer than 1993 and 
6% warmer than normal.  

	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, 1995, there 
was a surplus of energy in the region which caused lower wholesale and 
purchased power prices.  The Company believes that the wholesale power market 
in 1996 will be as weak if not weaker than 1995.

	During the fourth quarter of 1995, Rhone-Poulenc Basic Chemicals 
(Rhone), one of the Company's largest retail electric customers, announced its 
decision to cease operating its Montana plant.  Rhone was receiving power 
under a contract that was scheduled to end in June 1996.  The termination had 
been anticipated in the Company's resource plan for the last few years.

	Advanced Silicon Materials, Inc. has selected Montana as the site for a 
new silicon processing plant.  The Company will provide electricity to this 
plant commencing in 1998.  The load for the new plant is expected to exceed 
the load lost due to Rhone's shutdown.  The negotiated rate for this customer 
reflects competitive market conditions prevalent in the Northwest.

	The Company is facing increased competition for its large industrial and 
wholesale customers who are beginning to consider other sources for their 
energy needs.  To respond to this competition, the Company is realigning its 
businesses into two divisions.  An energy supply division will be responsible 
for coal, oil and natural gas, and power generation including marketing, 
brokering and wholesale business development.  An energy services and 
communications division will engage in the transmission and distribution of 
electricity and gas as well as telecommunications, energy management services 
and retail business development.  The Company believes this structure will 
accommodate its businesses, yet be flexible enough to fit anticipated federal 
and state mandates.  The new structure is being put in place in 1996 and 
contemplates a five to ten year transition period before open-access will be 
available to all customers.  At the end of the transition period, power 
generation and natural gas supply would be fully deregulated.

Summary of Significant Regulatory Matters:

	On April 25, 1995, the PSC approved an electric increase of $13,900,000, 
on an annual basis, effective May 1, 1995.  This increase affirmed a settlement 
with intervenors and included $7,700,000 which had been previously authorized 
on an interim basis.

	On September 21, 1995, the Company filed a request with the PSC to 
increase both electric and natural gas rates.  The Company also offered a 
preferred three-year `alternative' rate plan.  The filing, as adjusted, 
requests an additional $27,500,000 (7.80%) for electric revenues and $9,200,000 
(7.34%) for natural gas revenues, based upon a 12.0% return on equity. 
Requested interim increases were $11,100,000 for electricity and $4,400,000 for 
natural gas. On February 14, 1996, the PSC granted interim increases of 
$5,800,000 for electricity and $3,100,000 for natural gas, effective March 1, 
1996.  

	The 'alternative' plan would establish rates for the next three years 
thus eliminating conventional filings until 1998.  This plan is intended to 
allow the Utility to maintain financial integrity while providing time for 
parties usually involved in rate proceedings, including the Company, the PSC 
and intervenors, to deal with issues related to changes in the utility 
industry.

Electric Utility:  

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

			   1995   	   1994   

	General business	- revenue	$    12  	$    11
		- volume	     (1)% 	      3 %
		- price/kWh	      4 %	      -

	Other utilities	- revenue	$   (16)   	$    (9)
		- volume	     (5)% 	     (6)%
		- price/kWh	    (17)%   	     (5)%

	Miscellaneous	- revenue	$    (2)	$    (1)

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 
the large industrial customer discussed previously.

	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:  

	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		       Megawatt Hours          

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		     84,939	      99,147

  Total Power Supply Expenses		$   148,240	$    178,927

  Cents per Kilowatt-Hour		      1.360	       1.612


	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&2 and the Corette Plant.  This price decrease was retroactive to July 
1991, and current period expenses include 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.

	Selling, general and administrative 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 is due to increased 
property taxes resulting from property additions.

	Depreciation and amortization expense increased as a result of additional 
plant and property in service.



1994 Compared to 1993

	Income from electric operations decreased due primarily to the less 
favorable hydroelectric generation and wholesale market conditions partially 
offset by higher rates and growth in customers.  

Revenues:

	Electric sales from general business customers increased $11,500,000 
including an increase of $5,800,000 in revenues from industrial customers. 
Industrial revenues increased due to a 5% increase in volumes sold, primarily 
the result of additional equipment installed by several customers and demand 
for irrigation because of dry summer weather.  Growth in residential and 
commercial customers and higher rates also contributed to the increase in 
revenues.  These increases were moderated by volume decreases resulting from 
the warmer winter weather.  

	Electric revenues from sales to other utilities decreased $5,100,000 due 
to a reduction in volumes and $4,300,000 due to a decrease in average price. 
The decreases resulted from wholesale market conditions returning to near-
normal compared with better than average conditions experienced during the 
first and fourth quarters of 1993.  

	Miscellaneous electric revenues decreased primarily due to reduced 
wheeling revenues resulting from the previously discussed change in wholesale 
market conditions.  

	Intersegment revenues decreased primarily due to lower volumes sold to 
the IPG.  

Expenses:

	The following table shows the Company's sources of electricity and power 
supply expenses (operation, fuel for electric generation, and maintenance) for 
1994 and 1993.  

		   1994    		    1993   
Sources		        Megawatt Hours        

Hydroelectric		  2,999,396	  3,560,915
Steam	  	  4,909,852	  4,542,100
Purchases and Other		  3,193,522	  3,186,025

  Total Power Supply		 11,102,770	 11,289,040

Expenses		     Thousands of Dollars    

Hydroelectric		$    18,395	$    18,092
Steam		     61,385	     57,876
Purchases and Other		     99,147	     96,222

  Total Power Supply Expenses		$   178,927	$   172,190

  Cents per Kilowatt-Hour		      1.612	      1.525



	Steam generation and related fuel expense increased as a result of 
improved performance at the Colstrip units which experienced outages in 1993. 
Purchased power costs increased as a result of a 3% increase in average price 
paid.  Total power supply cost increased as a result of this price increase and 
a change in the mix of the Utility's sources of energy.  In 1994, a larger 
portion of power supply was provided by steam generation which is incrementally 
more expensive than hydroelectric generation.  

	The increase in selling, general and administrative results primarily 
from a $1,800,000 increase associated with the recognition of postretirement 
benefit expense in accordance with SFAS No. 106 commensurate with the approval 
of rate treatment for this expense by the PSC in April 1994, a $500,000 
increase related to insurance for postemployment disability-related benefits 
and a $600,000 increase due to the costs associated with Colstrip housing 
damages.  

	The increase in taxes other than income taxes is principally due to 
increased property taxes resulting from property additions and higher mill 
levies.  

	Depreciation and amortization expense increased as a result of 
depreciation of additional plant and property in service.  


Natural Gas Utility:

	The following table shows year-to-year changes for the previous two 
years, in millions of dollars, in the various classifications of natural gas 
revenues (excluding intersegment revenues) and the related percentage changes 
in volumes sold and prices received:  

			  1995  	  1994   
Revenues (other than gas
	  supply cost revenues)
  Full requirement
	  customers	-revenue	$    4	$   (3)
		-volume	     6 %	   (13)%
		-price/Mcf	     -	   (11)%

	Transportation	-revenue	$    -	$    3
		-volume	    16 %	    33 %
		-price/Mcf	     3 %	    (3)%

	Miscellaneous	-revenue	$    -	$    1

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 4% in the residential and commercial markets and 
temperatures 6% 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. 

	Interruptible transportation revenues are fixed by the most recent rate 
case.  Amounts in excess of, or lower than, amounts considered in the rate 
case, are deferred for treatment in a future rate filing.  Transportation 
volumes fluctuate with customer demand.

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 is due to increased 
property taxes resulting from higher mill levies and property additions.  

1994 Compared to 1993

	Income from natural gas operations decreased primarily due to decreased 
volumes resulting from warmer weather and increases in expenses other than gas 
supply costs, the effects of which were moderated by higher rates. 

Revenues:

	Effective September 1, 1993 natural gas customers who consume more than 
60,000 Mcfs annually (non full-requirements customers) are no longer required 
to purchase any portion of their natural gas supply from the Company.  All 
eligible customers have chosen to convert their volumes to transportation 
service only and have secured their own supply.  The resulting decline in 
natural gas revenue has been offset by revenues from transportation fees and 
lower purchased gas costs.  

	Natural gas revenues (other than gas supply costs) increased $1,300,000. 
Growth in the number of residential and commercial customers, higher rates and 
increased transportation fees contributed $13,200,000.  This increase was 
mostly offset by an approximately $11,800,000 decrease due to warmer weather 
and the previously discussed switch by eligible customers to transportation 
service only.  

	Gas supply cost revenues consist of the amount authorized by the PSC to 
be collected in rates from full requirement customers to cover the cost of 
supplying the gas.  The decrease in gas supply cost revenues is the result of 
reduced volumes sold due to warmer weather and a supply cost rate reduction for 
overcollections of supply costs in prior years.  Gas supply cost revenues and 
gas supply cost expenses are always equal due to rate and accounting 
procedures.  

Expenses:  

	The decrease in gas supply costs results from the reasons mentioned in 
the gas supply cost revenue discussion.  

	The increase in taxes other than income taxes is principally due to 
increased property taxes resulting from property additions and higher mill 
levies.

Interest Expense and Other Income, and Income Taxes:

	The change in interest expense from 1993 to 1995 is primarily the result 
of refinancing long-term debt at lower interest rates partially offset by 
increased average borrowings.

	Other income increased in 1995 and 1994 due to separate non-recurring 
events.

	Income taxes changed due primarily to changes in pre-tax income.



<TABLE>
<CAPTION>
			             ENTECH OPERATIONS
			       Year Ended December 31       
			   1995   	   1994   	   1993   
			        Thousands of Dollars
COAL OPERATIONS:
<S>                                                  <C>          <C>          <C>
REVENUES
	Revenues		$  207,517	$  252,507	$  225,155
	Intersegment revenues		    25,659	    42,201	    39,637
			   233,176	   294,708	   264,792

EXPENSES
	Cost of sales		   155,329	   169,259	   152,300
	Selling, general and administrative		    28,211	    29,463	    24,988
	Taxes other than income taxes		    27,210	    37,733	    34,221
	Depreciation, depletion and amortization	 	    11,187	    12,649	    10,193
	Writedowns of long-lived assets		    55,102	          	          
				   277,039	   249,104	   221,702

	INCOME (LOSS) FROM COAL OPERATIONS		   (43,863)	    45,604	    43,090

OIL AND NATURAL GAS OPERATIONS:  

REVENUES
	Revenues		   100,198	    97,994	   114,431
	Intersegment revenues		       241	       254	       741
				   100,439	    98,248	   115,172
EXPENSES
	Cost of sales		    60,526	    54,283	    71,311
	Selling, general and administrative		     9,320	     8,514	     8,549
	Taxes other than income taxes		     2,334	     3,340	     4,239
	Depreciation, depletion and amortization		    17,569	    18,464	    19,327
	Writedowns of long-lived assets		    19,194	          	          
				   108,943	    84,601	   103,426

	INCOME (LOSS) FROM OIL AND NATURAL 
		GAS OPERATIONS		    (8,504)	    13,647	    11,746

OTHER OPERATIONS:  

REVENUES
	Revenues		    26,308	    24,164	    24,252
	Intersegment revenues		       662	       787	       700
				    26,970	    24,951	    24,952
EXPENSES
	Cost of sales		    17,127	    16,787	    17,090
	Selling, general and administrative		     5,537	     4,717	     4,719
	Taxes other than income taxes		       343	       287	       473
	Depreciation, depletion and amortization		     1,745	     1,945	     2,133
				    24,752	    23,736	    24,415

	INCOME FROM OTHER OPERATIONS		     2,218	     1,215	       537

INTEREST EXPENSE AND OTHER INCOME:
	Interest		     4,596	     1,425	     2,284
	Other (income) deductions-net		    (6,978)	    (3,517)	   (11,364)
			   	    (2,382)	    (2,092)	    (9,080)

INCOME (LOSS) BEFORE INCOME TAXES		   (47,767)	    62,558	    64,453

INCOME TAXES		   (27,248)	    14,670	    17,263

ENTECH NET INCOME (LOSS)		$  (20,519)	$   47,888	$   47,190
</TABLE>


ENTECH OPERATIONS:

Coal Operations:  

1995 Compared to 1994

	The net loss from coal operations resulted from the writedown of 
Entech's investment in Basin, the implementation of SFAS No. 121, the results 
of the Colstrip Units 1 & 2 arbitration decision, the expiration of a 
Midwestern coal contract and decreased sales to Colstrip Units 3 & 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 & 2 and the Company's 
Corette Plant decreased $27,000,000 as a result of the Colstrip Units 1 & 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 & 4 due to the 
displacement of generation by lower cost hydroelectric generation. Revenues 
decreased $11,600,000 due to the Midwestern contract expiration and $8,300,000 
from Colstrip Units 3 & 4. Revenues decreased $5,000,000 due to the conclusion 
of coal brokering agreements in December 1994.  Brokered coal was sold at 
cost. A second Midwestern contract that expired in December was not renewed, 
and in 1996, revenues and volumes will be reduced by approximately $16,000,000 
and 1,100,000 tons, respectively.  At the Jewett Mine, revenues increased 
$1,000,000 as a net result of $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.

	Operating expenses at the Rosebud Mine in 1996 will decrease by 
approximately $9,000,000 due to the loss of the second Midwestern contract.

	Entech 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, Basin terminated the coal sales 
agreement and ceased production at the end of 1995. The Mine will be 
permanently closed at the end of the first quarter 1996 unless a viable buyer 
is identified.  To date, efforts to sell the Mine have been unsuccessful.  In 
the fourth quarter of 1995, Entech wrote down its investment in the Mine by 
$46,500,000 before taxes.  See Item 8, "Financial Statements and Supplementary 
Data - Note 11 to the Consolidated Financial Statements" for further 
discussion of asset impairment.

1994 Compared to 1993

	Income from coal operations increased $2,500,000 as a result of increased 
coal volumes sold.

Revenues:  

	Overall coal revenues, including intersegment revenues, increased 
$30,000,000 over 1993 due to a 13% increase in volumes sold.  Prices per ton 
were substantially unchanged.  Coal revenues increased $14,200,000 at the 
Rosebud Mine due to increased volumes sold to the Colstrip units as compared to 
1993 which were lower due to unplanned outages, and increased volumes sold to 
the SynCoal demonstration plant.  At the Jewett Mine, coal revenues increased 
$3,300,000 due to increased volumes delivered to the mine-mouth plant. 
Increased revenues of $12,900,000 at the Golden Eagle Mine resulted from 
increased volumes sold to supply coal for a long-term supply contract and for 
spot market sales.  In July, the Mine began delivering coal under a long-term 
contract to supply up to 1,200,000 tons of coal annually to a southeastern 
utility.  

Expenses:  

	Cost of sales increased $15,000,000 at the Golden Eagle Mine due to 
increased volumes sold and higher costs per ton including those related to 
unanticipated production problems in both the mining and the wash plant 
operations.  Also, cost of sales increased $2,000,000 at the Rosebud Mine as a 
result of increased volumes sold.  Selling, general and administrative expenses 
increased $4,500,000 from legal fees incurred relating to coal contract price 
arbitration and leasehold interest litigation, from the implementation of an 
accounting pronouncement pertaining to postemployment benefits and from the use 
of outside consultants.  Taxes other than income taxes increased $3,500,000 due 
to increased coal revenues.  Depreciation and depletion increased $2,400,000 
principally due to increased volumes sold and increased investment in the 
operation at the Golden Eagle Mine.  

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 
(excluding intersegment revenues) and the related percentage changes in volumes 
sold and prices received:  

			  1995 	 1994  

Oil	-revenue	$   1	$   (7)
		-volume	   (8)%	   (19)%
		-price/bbl	   17 %	   (11)%

Natural gas	-revenue	$ (10)	$    -
		-volume	   (8)%	     7 %
		-price/Mcf	  (23)%	    (4)%

Natural gas marketing	-revenue	$  11	$   (9)
		-volume	   27 %	   (13)%
		-price/Mcf	   (2)%	   (11)%

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 because 
of low market prices.  Revenues from natural gas marketing 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.

1994 Compared to 1993

	Income from oil and natural gas operations increased $1,900,000 due to 
higher profit margins realized on the natural gas marketing activity.  

Revenues:  

	Oil revenues decreased $7,000,000 from both lower volumes sold due to 
natural declining production and lower market prices received.  Natural gas 
revenues in Canada increased $3,500,000 from higher volumes sold as a result of 
1993 development drilling and from higher market prices received.  However, 
natural gas revenues in the U.S. decreased $3,900,000 from lower market prices 
received.  Natural gas marketing revenues decreased $12,000,000 due to the 
expiration of a short-term supply contract in 1993.  The operating revenue 
decrease was partially offset by the absence of losses of $3,200,000 as a 
result of a marketing joint venture that was sold in December 1993.  

Expenses:

	Cost of sales decreased $17,000,000.  This amount is comprised of 
$14,700,000 decreased costs of natural gas purchased for resale because of 
lower spot market prices and decreased natural gas marketing volumes sold in 
the U.S., and $2,300,000 decreased operating costs resulting from the sale of a 
non-strategic asset in the fourth quarter of 1993.  The decrease of $900,000 in 
taxes other than income taxes reflects lower revenues.  

Other Operations:

1995 Compared to 1994

	Income from other operations increased from telecommunications 
operations and land sales.

Revenues:

	Additional leased network capacity sold to private businesses and a 26% 
increase in minutes sold to long-distance customers increased revenues from 
Entech's other operations by $2,500,000.  Additionally, revenues from land 
sales increased $400,000.  The increased revenues from telecommunications and 
real estate were partially offset by $900,000 decreased revenues due to the 
1995 completion of automated control systems contracts.

1994 Compared to 1993

	Income from other operations increased $700,000 due to expanded 
telecommunications services.  

Revenues:  

	Revenues from Entech's other operations decreased $3,500,000 because of 
the sale of the waste management operations in May 1993.  This decrease was 
offset by $3,000,000 increased revenues from telecommunications operations due 
to increased services provided to common carriers and expanded operations in 
three western states, and by $500,000 increased revenues from land sales.  

Expenses:

	The operating expenses of Entech's other operations decreased $3,600,000 
due to the sale of the waste management operations mentioned above.  This 
decrease was offset by $2,900,000 increased costs of telecommunications 
operations and land sales.

Interest Expense and Other Income, and Income Taxes:  

1995 Compared to 1994

	The increase in interest expense was a result of $2,000,000 non-
recurring interest paid to the Utility Division pursuant to the arbitration 
decision discussed above and increased borrowings.  Other income increased 
approximately $3,500,000 due to Oil Division property sales and non-recurring 
interest income.

	Lower pre-tax net income from operations decreased income taxes 
$41,900,000.

1994 Compared to 1993

	The decrease in interest expense is due to lower levels of outstanding 
debt.  The $7,800,000 decrease in other income resulted from the 1993 sales of 
a non-strategic asset and the waste management operations.  

	Income taxes decreased $3,700,000 due to income tax credits utilized and 
lower pre-tax net income.  



<TABLE>
<CAPTION>
				 INDEPENDENT POWER GROUP OPERATIONS
				       Year Ended December 31       
				   1995   	   1994   	   1993   
				        Thousands of Dollars
<S>                                                  <C>         <C>           <C>
REVENUES:
	Revenues		$   79,095	$   93,647	$  119,189
	Earnings from unconsolidated investments		     2,622	     2,080	     3,117
	Intersegment revenues		       796	     1,461	     5,528
			    82,513	    97,188	   127,834

EXPENSES:
	Operation and maintenance		    68,300	    75,080	   114,923
	Selling, general and administrative		     3,557	     4,088	     9,605
	Taxes other than income taxes		     1,831	     1,916	     1,767
	Depreciation and amortization	 	     3,176	     3,112	     2,887
				    76,864	    84,196	   129,182

	INCOME (LOSS) FROM OPERATIONS		     5,649	    12,992	    (1,348)

INTEREST EXPENSE AND OTHER INCOME:
	Interest		        21	        22	       211
	Other (income) deductions - net		    (3,413)	    (4,711)	    (1,011)
				    (3,392)	    (4,689)	      (800)

INCOME (LOSS) BEFORE INCOME TAXES		     9,041	    17,681	      (548)

INCOME TAXES		     4,775	     7,386	      (507)

IPG NET INCOME (LOSS)		$    4,266	$   10,295	$      (41)
</TABLE>



INDEPENDENT POWER GROUP OPERATIONS:  

	In November 1992, the IPG acquired 100% of North American Energy Services 
Company (NAES) and their operations were included in the Company's financial 
statements on a consolidated basis in 1993.  In August 1994, the IPG sold a 50% 
interest in  NAES and, as a result of the sale, NAES has been included in the 
Company's operations on the equity basis of accounting as of January 1, 1994.  

1995 Compared to 1994

	The 1995 net income of IPG decreased primarily as a result of the 
anticipated decline in the number of 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 NAES and the 1995 loss on the 
withdrawal from another investment.  IPG 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 IPG 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 IPG 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.  

Interest Expense and Other Income:

	Other income decreased primarily as a result of the absence in 1995 of 
the gain on the sale of 50% of NAES in 1994, which was partially offset by an 
increase in interest income.  

1994 Compared to 1993

	Income from IPG operations increased $14,300,000 primarily due to 
increased revenues from independent power project development activity, a gain 
on the sale of NAES and improved performance by the Colstrip generating plant.

Revenues:

	IPG revenues decreased $43,600,000 due to the accounting change for the 
IPG's investment in NAES as mentioned above.  The decrease was partially offset 
by increases in independent power project development revenues of $12,600,000, 
management fees of $500,000 and a $4,900,000 increase in revenues from long-
term power sales from the Colstrip plant due to a 13% increase in volumes sold. 

	The decrease in earnings from unconsolidated investments resulted 
primarily from lower earnings from operating projects.  The decrease in 
intersegment revenues resulted primarily from the sale of NAES and the 
resulting change in accounting.  

Expenses:

	The NAES sale and corresponding accounting change resulted in decreases 
of $41,500,000 in operation and maintenance expense and $5,300,000 in selling, 
general and administrative.  Operation and maintenance expense was also 
impacted by a $2,100,000 decrease in wheeling expense, a $2,100,000 decrease in 
purchased power costs and a $3,000,000 increase in fuel costs due to increased 
generation at the Colstrip units.  Expenses associated with project development 
increased by $1,600,000 primarily due to the development of two power projects. 

Interest Expense and Other Income:

	Other income increased $3,700,000 due principally to increases in 
interest income and the gain on the sale of 50% of NAES.  



LIQUIDITY AND CAPITAL RESOURCES:  

	Net cash provided by operating activities was $268,890,000 in 1995 
compared to $203,886,000 in 1994 and $185,809,000 in 1993.  Cash from operating 
activities less dividends paid provided 76% of capital expenditures in 1995, 
54% in 1994 and 54% in 1993.

	The Company's long-term debt as a percentage of capitalization was 37%, 
36% and 36% in 1995, 1994 and 1993, 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:  

	Years	Utility 	 Entech 	   IPG  	  Total  
	Thousands of Dollars

	1993	$112,178	$ 66,832	$  4,542	$ 183,552
	1994	 150,903	  50,253	   6,154	  207,310
	1995	 163,238	  63,681	   4,168	  231,087



	The following table sets forth the Company's estimated capital 
expenditures for the years 1996-2000 (Projections have been adjusted from 1994 
reporting to reflect changes in the Company's electric resource plan, lower 
spending for gas transmission projects, and overall reductions in the 
construction budget):  


	Years	Utility 	 Entech 	   IPG  	  Total   
	Thousands of Dollars

	1996	$117,000	$ 56,000	$ 28,000	$ 201,000
	1997	 108,000	  48,000	  27,000	  183,000
	1998	  73,000	  50,000	  26,000	  149,000
	1999	  76,000	  53,000	  26,000	  155,000
	2000	  71,000	  54,000	  26,000	  151,000

	In addition, $203,000,000 of long-term debt will mature during the years 
1996-2000.  See Item 8 "Financial Statements and Supplementary Data - Note 7 to 
the Consolidated Financial Statements" for details on maturities of long-term 
debt.  

	For the years 1996-2000, the Company estimates that, by business unit, 
internally-generated funds will average 103% of its utility construction 
program, 106% of Entech's capital expenditures and 29% of IPG investments.  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 $93,600,000 in 1995, 
$92,009,000 in 1994 and $85,822,000 in 1993.  During 1995, 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.  While the declaration 
of future dividends is at the discretion of the Board of Directors, the Company 
does not anticipate that the 1995 writedown of a coal mining investment and the 
adoption of SFAS No. 121 will affect the common stock dividend.  

	The Company and Entech have Revolving Credit and Term Loan Agreements in 
the amount of $60,000,000 and $75,000,000, respectively.  These businesses also 
have short-term borrowing facilities with commercial banks that provide both 
committed and uncommitted lines of credit, and the ability to sell commercial 
paper.  See Item 8, "Financial Statements and Supplementary Data - Notes 7 
and 8 to the Consolidated Financial Statements for further information."  

	In April 1995, the Company sold $20,000,000 of Secured Medium-Term Notes, 
7.33% series due 2025.  The proceeds were used to finance construction and to 
repay short-term debt.  In November 1995, the Company sold $20,000,000 of 
Secured Medium-Term Notes, $10,000,000 of a 5.75% series due 1997 and 
$10,000,000 of a 5.9% series due 1998.  The proceeds were used to finance 
construction and to retire $10,000,000 of Unsecured Medium-Term Notes, 8.87% 
series due 1995.

	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 1996-2000. 
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, 1995, the Company's ratio of 
earnings to fixed charges was 1.96 times.  Excluding the effects of the 
implementation of SFAS No. 121 and the writedown of a coal mining investment, 
discussed in Note 11 to the Consolidated Financial Statements, the ratio of 
earnings to fixed charges would have been 2.84 times.  Fixed charges include 
interest, the implicit interest of Unit 4 rentals and one-third of all other 
rental payments.  



INFLATION:  

	Capital intensive businesses, such as the Company's electric and natural 
gas utility operations, are significantly and adversely affected by long-term 
inflation as neither depreciation nor the ratemaking process reflect the 
replacement cost of utility plant.  Although prices for natural gas may 
fluctuate, earnings of the Gas Utility are not impacted because a gas cost 
tracking procedure annually balances gas costs collected from customers with 
the costs of supplying gas.  

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

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

STOCK BASED COMPENSATION:

	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. See Item 8, "Financial Statements and Supplementary Data - 
Note 5 to the Consolidated Financial Statements" for further discussion of the 
accounting standard.

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 almost all federal, state and local environmental laws and regulations 
relating to pollution control and prevention and environmental remediation. The 
primary 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.  To comply with 
these laws and to maintain compliance requires a significant commitment of 
resources and a comprehensive planning effort.  

	Some of these environmental laws and regulations, primarily CERCLA and 
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 past or present Company sites or at sites where these substances 
were disposed.  The Company currently participates in several such remediation 
efforts and may, in the future, be involved in additional site remediation 
activities.  The total amount of costs associated with future sites remediation 
is unknown both because (1) the Company may not know of all sites for which it 
has all or some responsibility and (2) for those sites which the Company does 
have responsibility, it does not have enough information to estimate future 
costs with reasonable certainty.  However, as the Company gains information 
regarding its obligations and in accordance with accounting guidelines, it will 
continually refine and update its estimates of future costs associated with 
site remediation.  

	The Clean Air Act Amendments of 1990 (Act) should have no major effects 
on the Company's electric generation facilities.  All units have been 
designated as Phase II Units under Title IV (Acid Rain) of the 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 intends to exercise this option.  

	The Company will not exercise this option for its Corette Plant because, 
due to improvements in the plant's emissions which will not be completed until 
1997, the level of nitrogen oxide emissions at the plant cannot be determined 
with the precision necessary to make this election.  

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

	In 1988, the United States Environmental Protection Agency advised the 
Company that it, along with certain other parties, is a potentially responsible 
party (PRP) for the release of certain toxic substances which have come to rest 
behind the dam at the Company's Milltown Hydroelectric Plant.  Because of 
federal legislation specifically relating to Milltown, the Company believes it 
has no responsibility for any of the alleged releases.  If the Company should 
have some responsibility, it would have to share, together with other 
responsible parties, the costs related to the handling of these toxic 
substances.  While these costs have not been determined, the Company believes 
that any portion which it might bear would not have a significant impact upon 
its earnings.  

	The Company, along with others, has been named a PRP with respect to the 
Silver Bow Creek/Butte Area Superfund Site.  The alleged contamination is soil 
and groundwater contamination, for the most part, associated with decades of 
copper mining in the area.  The PRPs have cooperated to summarize the data that 
currently exists, to evaluate the usability of this existing data and to 
determine additional data needs.  Studies to determine the extent of the 
alleged contamination, and a proposal for removal or remediation of the alleged 
contamination are not complete.  

	Regarding this superfund site, the Company has focused on its property 
ownership and alleged contamination that may be attributed to that ownership. 
It has spent approximately $500,000 to investigate its property within the 
site, collect data, evaluate studies and monitor its property.  Costs to clean 
up this contamination, including sums spent in the studies mentioned above, are 
not expected to exceed $1,000,000.  

	Other contamination at the Company's property within the site involves 
heavy metals and substances which may be attributed to mining and activities of 
others within the greater area of the site.  Consultants employed by the PRPs 
to compile and analyze previously prepared study data regarding the greater 
area of this superfund site have made preliminary estimates indicating that 
clean-up costs could range from $20,000,000 to $60,000,000.  While the Company 
denies any responsibility for costs associated with this contamination, if the 
Company should have some responsibility, it would have to share a portion of 
the costs ultimately related to the handling of the contamination.  

	The Company or its predecessors owned and operated manufactured gas 
plants on three sites.  To gather information necessary to learn about the 
nature of contamination at one of these sites, the Company voluntarily began 
work in 1995.  The assessment accomplished to date indicates that the cost of 
cleanup may range from $1,100,000 to $2,200,000.  The Company has not yet taken 
extensive action to characterize the potential for pollution at the other two 
sites.

	The Company has accrued the estimated minimum costs associated with the 
matters discussed above.  The Company does not expect these costs to materially 
impact the results of its operations.  



ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA


	INDEX TO FINANCIAL STATEMENTS
	AND SUPPLEMENTARY DATA

	 Page 

Management's Responsibility for Financial Statements	52 

Report of Independent Accountants	53 

Consolidated Financial Statements:

	Consolidated Statements of Income for the Years Ended 
		December 31, 1995, 1994 and 1993	54 

	Consolidated Balance Sheets as of December 31, 1995 and 1994	55-56

	Consolidated Statements of Cash Flows for the Years Ended 
		December 31, 1995, 1994 and 1993	57 

	Consolidated Statements of Common Shareholders' Equity for the 
		Years Ended December 31, 1995, 1994 and 1993	58 

	Notes to Consolidated Financial Statements	59-86

Supplementary Data (Unaudited)
Financial Statement Schedules for the Years Ended December 31, 
	1995, 1994 and 1993	87-95

	Schedule II - Valuation and Qualifying Accounts and Reserves	100 


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.  






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



	Report of Independent Accountants

February 9, 1996

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, 1995 
and 1994, and the results of their operations and of their cash flows for each 
of the three years in the period ended December 31, 1995, 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 11 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



CONSOLIDATED STATEMENT OF INCOME
	The Montana Power Company and Subsidiaries
<TABLE>
<CAPTION>
					       Year Ended December 31       
					   1995   	   1994   	   1993   
					        Thousands of Dollars
<S>                                                <C>          <C>          <C>
REVENUES		$  953,539	$1,005,970	$1,024,285

EXPENSES:
	Operations		   424,443	   440,472	   480,382
	Maintenance		    68,286	    75,357	    70,029
	Selling, general and administrative		    98,327	   103,127	   101,251
	Taxes other than income taxes		    89,858	    99,200	    92,430
	Depreciation, depletion and amortization		    86,976	    86,711	    82,696
	Writedowns of long-lived assets		    74,297	          	          
					   842,187	   804,867	   826,788

		INCOME FROM OPERATIONS		   111,352	   201,103	   197,497

INTEREST EXPENSE AND OTHER INCOME:
	Interest		    43,788	    42,817	    48,023
	Other (income) deductions - net		   (10,947)	   (10,532)	   (11,857)
					    32,841	    32,285	    36,166

INCOME TAXES		    21,574	    55,226	    54,120

NET INCOME		    56,937	   113,592	   107,211
DIVIDENDS ON PREFERRED STOCK		     7,227	     7,227	     4,353

NET INCOME AVAILABLE FOR COMMON STOCK		$   49,710	$  106,365	$  102,858

AVERAGE NUMBER OF COMMON SHARES
	OUTSTANDING (000)		    54,121	    53,125	    52,040

NET INCOME PER SHARE OF COMMON STOCK		$     0.92	$     2.00	$     1.98



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


	CONSOLIDATED BALANCE SHEET
	The Montana Power Company and Subsidiaries
	ASSETS
<TABLE>
<CAPTION>
	       December 31,      
	   1995    	   1994    
	Thousands of Dollars

<S>                                                             <C>           <C>
PLANT AND PROPERTY IN SERVICE:
	Utility plant (includes $57,095 and $79,510 plant 
		under construction):
			Electric		$1,713,133	  $1,608,615
			Natural gas		   492,431	     463,134
						2,205,564	2,071,749
	Less - accumulated depreciation and depletion		   663,215	     619,195
						1,542,349	1,452,554
	Entech property (includes $12,716 and $3,030
		property under construction)		559,722	530,167
	Less - accumulated depreciation and depletion		   232,947	     189,926
						326,775	340,241

	Independent Power Group property (includes $3,171
		and $671 property under construction)		72,179	70,132
	Less - accumulated depreciation		    19,666	      17,560
						    52,513	      52,572
						1,921,637	1,845,367

	MISCELLANEOUS INVESTMENTS (at cost):
		Independent power investments		57,013	54,518
		Other		    46,966	      49,713
						103,979	104,231
	CURRENT ASSETS:
		Cash and temporary cash investments		15,541	21,564
		Accounts receivable		152,386	159,975
		Materials and supplies (principally at 
			average cost)		42,194	47,937
		Prepayments and other assets		    62,071	      65,154
						272,192	294,630
	DEFERRED CHARGES:
		Advanced coal royalties		20,175	22,939
		Regulatory assets related to income taxes		148,350	146,844
		Regulatory assets - other		68,637	49,880
		Other deferred charges		    51,121	      48,806
						   288,283	     268,469
						$2,586,091	  $2,512,697

The accompanying notes are an integral part of these statements.



	LIABILITIES


					       December 31       
					    1995   	    1994    
					   Thousands of Dollars


CAPITALIZATION:
	Common shareholders' equity:
		Common stock (120,000,000 shares without par 
		  value authorized; 54,614,481 and 53,578,737
		  shares issued)		$  691,043	  $  667,344
		Retained earnings and other shareholders' equity		285,000	     320,756
		Unallocated stock held by trustee for Deferred 
		  Savings and Employee Stock Ownership Plan		   (30,565)	     (32,580)
						   945,478	     955,520

	Preferred stock		101,416	     101,416
	Long-term debt		   616,574	     588,876
						1,663,468	   1,645,812

CURRENT LIABILITIES:
	Short-term borrowing		96,348	     113,989
	Long-term debt-portion due within one year		24,804	      16,980
	Dividends payable		23,668	      23,249
	Income taxes		9,937	       9,210
	Other taxes		43,302	      46,521
	Accounts payable		63,920	      50,788
	Interest accrued		12,341	      11,785
	Other current liabilities		    63,488	      40,546
						337,808	     313,068

DEFERRED CREDITS:
	Deferred income taxes		320,736	     322,835
	Investment tax credit		47,001	      48,729
	Accrued mining reclamation costs		122,008	     110,035
	Other deferred credits		    95,070	      72,218
						   584,815	     553,817

CONTINGENCIES AND COMMITMENTS (Notes 2 and 3)


							$2,586,091	  $2,512,697


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



	CONSOLIDATED STATEMENT OF CASH FLOWS
	The Montana Power Company and Subsidiaries
<TABLE>
<CAPTION>
						       Year Ended December 31       
						   1995    	   1994    	   1993   
							Thousands of Dollars       
<S>                                                  <C>          <C>          <C>
NET CASH FLOWS FROM OPERATING ACTIVITIES:
	Net income		$   56,937	$  113,592	$ 107,211
	Noncash charges (credits) to net income:
		Depreciation, depletion and amortization		    86,976	    86,711	   82,696
		Writedowns of long-lived assets		    74,297
		Mining reclamation costs expensed		    15,970	    19,527	   19,410
		Amortization of loss on long-term
			sales of power		    (3,264)	    (4,226)	   (5,251)
		Deferred income taxes		   (11,819)	     4,792	   16,324
		Other-net		    21,055	    31,447	   16,176
	Accounts receivable		     7,589	    (1,622)	  (15,367)
	Materials and supplies		     5,743	    (5,209)	     (975)
	Accounts payable		    13,132	    (5,007)	    6,922
	Payment of mining reclamation costs		    (8,559)	   (11,309)	   (9,481)
	Changes in other assets and liabilities		    10,833	   (24,810)	  (31,856)

		Net Cash Flows From Operating 
			Activities		   268,890	   203,886	  185,809

NET CASH FLOWS FROM INVESTING ACTIVITIES:
	Gross additions to property and plant		  (213,440)	  (187,213)	 (166,050)
	Investments in other operations		    (3,953)	    (6,344)	   (6,161)
	Sales of property		    13,987	    27,729	   24,924
	Additional investments		   (16,334)	   (12,610)	   (7,327)

		Net Cash Flows From Investing 
			Activities		  (219,740)	  (178,438)	 (154,614)

NET CASH FLOWS FROM FINANCING ACTIVITIES:
	Sales of common stock		    23,465	    24,380	   24,917
	Issuance of long-term debt		    50,758	    52,094	  294,149
	Retirement of long-term debt		   (18,155)	   (45,078)	 (316,714)
	Short-term debt		   (17,641)	    45,125	    5,565
	Dividends on common and preferred stock		   (93,600)	   (92,009)	  (85,822)
	Issuance of preferred stock		          	          	   49,435

		Net Cash Flows From Financing 
			Activities		   (55,173)	   (15,488)	  (28,470)

			Change in Cash Flows		    (6,023)	     9,960	    2,725

	Cash and cash equivalents at beginning 
		of year		    21,564	    11,604	    8,879

	Cash and cash equivalents at end of year		$   15,541	$   21,564	$  11,604


SUPPLEMENTAL DISCLOSURES OF CASH 
	FLOW INFORMATION: 

	Cash Paid During Year For:
		Income taxes		$   32,666	$   45,875	$  46,533
		Interest		    46,141	    45,990	   53,541

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


	CONSOLIDATED STATEMENT OF COMMON SHAREHOLDERS' EQUITY
	The Montana Power Company and Subsidiaries
<TABLE>
<CAPTION>
						        Year Ended December 31        
						   1995   	   1994   	   1993   
					               Thousands of Dollars
<S>                                                    <C>           <C>         <C>
COMMON STOCK:

	Balance at beginning of year		$ 667,344	$ 642,926	$ 618,009
	Issuances (1,035,744; 1,079,841; 
		and 949,951 shares)		   23,699	   24,418	   24,917

	Balance at end of year		  691,043	  667,344 	  642,926

RETAINED EARNINGS AND OTHER SHAREHOLDERS' 
	EQUITY:

	Balance at beginning of year		320,756	  302,725	  284,980
	Net income		56,937	  113,592	  107,211
	Dividends on common stock ($1.60;
		$1.60; and $1.585 per share)		(86,791)	  (85,193)	  (82,701)
	Dividends on preferred stock		(7,227)	   (7,227)	   (4,353)
	Other		    1,325	   (3,141)	   (2,412)

	Balance at end of year		  285,000	  320,756 	  302,725

UNALLOCATED STOCK HELD BY TRUSTEE FOR  
	DEFERRED SAVINGS AND EMPLOYEE STOCK 
	OWNERSHIP PLAN:

	Balance at beginning of year		(32,580)	  (34,419)	  (36,098)
	Distributions		    2,015	    1,839 	    1,679

	Balance at end of year		  (30,565)	  (32,580)	  (34,419)

TOTAL COMMON SHAREHOLDERS' EQUITY AT 
	END OF YEAR		$ 945,478	$ 955,520 	$ 911,232


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



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 - Summary of significant accounting policies:  

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

	Preparing financial statements requires the use of estimates.  Future 
events and their effects cannot be perceived with certainty; estimating, 
therefore, requires the exercise of judgment.  Management makes appropriate 
estimates and judgments based upon available information.  Accounting estimates 
may change as new events occur, additional information is obtained or more 
experience is acquired.  Actual results may differ from accounting estimates.  

Principles of consolidation:  

	The Consolidated Financial Statements include the accounts of the Company 
and its subsidiaries, all of which are wholly-owned.  The Independent Power 
Group (IPG) includes the Company's Colstrip Unit 4 operations.  All material 
intercompany sales and purchases between the Utility, Entech and the IPG have 
been eliminated from revenues and expenses in the Consolidated Statement of 
Income.  All other significant intercompany items have also been eliminated. 
See Note 10 for details.  

Plant and property:  

	Additions to and replacements of plant and property are recorded at 
original cost, which includes material, labor, overhead and contracted 
services.  Cost includes interest capitalized and, with respect to Utility 
plant, also includes an allowance for funds used during construction.  Gas in 
underground storage is included in natural gas Utility plant.  Maintenance and 
repairs of plant and property, and replacements and renewals of items 
determined to be smaller than established units of plant, are charged to 
operating expenses.  The cost of units of Utility plant retired or otherwise 
disposed of, adjusted for removal costs and salvage, is charged to the 
accumulated provision for depreciation and depletion, and the cost of related 
replacements and renewals is added to Utility plant.  Gain or loss is 
recognized upon the sale or other disposition of Entech property, IPG property 
and Utility land.  

	Provisions for depreciation and depletion are recorded at amounts 
substantially equivalent to calculations made on straight-line and 
unit-of-production methods by application of various rates based on useful 
lives of properties determined from engineering studies. For 1995, 1994 and 
1993, the provisions for utility depreciation and depletion approximated 2.7% 
of the depreciable and depletable utility plant at the beginning of the year.  

	The Company and its subsidiaries have adopted two methods of accounting 
for oil and gas exploration and development costs.  Entech's Oil Division uses 
the successful efforts method.  The regulated natural gas utility capitalizes 
all costs associated with the successful development of a natural gas well and 
expenses those costs incurred on an unsuccessful well.  

	The Company is a joint-owner of Colstrip Units 1, 2 and 3 and of 
transmission facilities serving these Units.  At December 31, 1995, 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		$ 182,380	$ 284,017	$  51,147
Plant under construction		      235	    1,648	        9
Accumulated depreciation		   85,572	   93,022	   11,847

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

	The Company also owns $35,739,000 and $33,151,000 of the Colstrip Unit 4 
share of common production plant and transmission plant that had related 
accumulated depreciation of $13,311,000 and $6,315,000, respectively.

	Each joint-owner provides its own financing.  The Company's share of 
direct expenses associated with the operation and maintenance of these joint 
facilities is included in the corresponding operating expenses in the 
Consolidated Statement of Income.  

Utility revenue and expense recognition:  

	Operating revenues are recorded on the basis of service rendered.  Costs 
of service are recognized on the accrual basis and charged to expense currently 
except for natural gas costs deferred pursuant to PSC-approved deferred gas 
accounting procedures. 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:

	As a rate regulated utility, the Company follows SFAS No. 71, "Accounting 
for the Effects of Certain Types of Regulation."  Pursuant to the 
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.  

		         1995          	         1994          
		 Assets  	Liabilities	 Assets  	Liabilities
			 Thousands of Dollars 

	Income taxes	$ 147,388		$ 145,623	
	Conservation programs	   40,640		   31,214
	Other	   33,298	$   12,623	   24,173	$   10,330
	    Subtotal	  221,326	    12,623	  201,010	    10,330
	Less: 
	  Current portions	    4,339	     3,675	    4,286	       426
	    Total	$ 216,987	$    8,948	$ 196,724	$    9,904



	Income taxes represent the expected future tax consequences that will 
result from the reversal of temporary differences between the recorded book 
basis and the tax basis of assets and liabilities.  These amounts reverse in 
future periods when the taxes are paid and reflected in rates.  

	Conservation programs represent the Company's Demand Side Management 
(DSM) programs that are in rate base and are being charged 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. 
Historically, all costs of this nature that are determined to have been 
reasonable and prudently incurred have been recoverable through rates and the 
Company believes these costs will be afforded similar treatment.  

	In order to defer incurred costs under SFAS No. 71, a regulated entity 
must be regulated in a manner which allows recovery of costs and rates so 
established can be charged to and collected from customers.  Certain events 
could cause the Company to not meet the criteria of SFAS No. 71.  These include 
a change in the method of regulation, a change in the competitive environment 
where the Company may be forced to establish rates which are insufficient to 
recover incurred costs or any other event that could cause the recovery of 
costs through rates to become uncertain.  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 be eliminated from the 
balance sheet and included in income in the period when the discontinuation 
occurred.  The financial effects of such an occurrence could be significant.  

Cash and cash equivalents:

	For the purposes of these financial statements, the Company considers all 
liquid investments with original maturities of three months or less to be cash 
equivalents.

Allowance for funds used during construction:  

	The Company capitalizes, as a part of the cost of utility plant, an 
allowance for the cost of equity and borrowed funds required to finance 
construction work in progress.  The rate used to compute the allowance is 
determined in accordance with a formula established by the FERC and was an 
average of 8.1% for 1995, 7.9% for 1994 and 6.5% for 1993.  The Company 
capitalized an allowance for borrowed funds used during construction of 
$4,250,000, $2,402,000 and $1,372,000 for 1995, 1994 and 1993, respectively.

Allowance for funds used for conservation expenditures:  

	The Company has been allowed by the PSC to capitalize, as part of its 
conservation expenditures, an allowance for the cost of equity and borrowed 
funds required to finance DSM expenditures.  The rate used to capitalize the 
allowance is the Company's overall rate of return allowed by the PSC.  The 
Company capitalized an allowance for borrowed funds used to finance DSM 
expenditures of $872,000, $635,000 and $561,000 for 1995, 1994 and 1993, 
respectively.  

Environmental remediation costs:  

	The estimated costs of environmental remediation obligations for the 
Utility Division are charged against established, regulator approved operating 
reserves when such losses are probable and reasonably estimable.  Consequently, 
the Company does not experience large fluctuations in environmental costs from 
year to year.  The reserves are adequate to provide for all known obligations 
and may be increased, if appropriate, by adjusting the annual accrual rate. The 
annual accruals are recovered through rates.  

Employee termination benefits:

	The Company has performed a strategic analysis of certain business 
functions, to determine what is needed in those areas to meet changing 
conditions in the utility industry.  Study teams developed methods to be more 
efficient and changes are being implemented in the Utility's organizational 
structure.  The changes, which began in 1994, are anticipated to be largely 
completed in 1997.  The following table shows the total number of employees 
terminated and estimated to be terminated and the associated termination costs 
by operations:

		Number of 	Regulated 	Colstrip Unit 4
	Year	Employees	 Operations 	  Operations  

	1994	59	$ 2,460,577
	1995	121	3,445,348	$     104,908
	1996	88	2,450,515	226,000
	1997	 97	  2,236,352	      212,000
	  Total	365	$10,592,792	$     542,908

	For the regulated operations, the Company has accrued an estimated 
$8,100,000 of severance benefits for years 1995 through 1997.  Offsetting these 
benefit costs are savings realized through 1995 of $1,700,000.  The 1994 costs 
were charged to income through operating and selling, general and 
administrative expenses.  The net cost of the program since 1995 is being 
deferred as authorized by an accounting order from the PSC and is not reflected 
in income.  The Company believes this cost will be recovered through rates.  

	Total termination costs for 1995 through 1997 for Colstrip Unit 4 
operations have been charged against income through operating expenses.  

Income taxes:

	The Company and its U.S. subsidiaries file a consolidated U.S. income tax 
return.  Consolidated U.S. income taxes are allocated to Utility, Entech and 
IPG operations as if separate U.S. income tax returns were filed.  Deferred 
income taxes are provided for the temporary differences between the financial 
reporting basis and the tax basis of the Company's assets and liabilities.  For 
further information on income taxes see "Regulatory assets and liabilities" in 
this note and also Note 4 - Income taxes.

Net income per share of common stock:

	Net income per share of common stock is computed for each year based upon 
the weighted average number of common shares outstanding.  The effect of 
options outstanding under the Company's Long-Term Incentive Plan is not 
significant (see Note 5 - Common stock).

Financial instruments:

	In October 1994, the Financial Accounting Standards Board (FASB) issued 
Statement of Financial Accounting Standards No. 119, "Disclosure about 
Derivative Financial Instruments and Fair Value of Financial Instruments," 
effective for fiscal years ending after December 15, 1994.  This statement 
requires disclosure about derivative financial instruments - futures, forwards, 
swap and option contracts, and other financial instruments with similar 
characteristics.  

	To manage price risk, Entech uses oil and natural gas swap agreements and 
oil collar agreements to hedge revenue from anticipated production and sales of 
oil and natural gas.  Under swap agreements, Entech receives or makes payments 
based on the differential between a specified price and the market price of oil 
or natural gas when the hedged production is sold.  Under collar agreements, 
Entech makes or receives monthly payments when the actual price of oil exceeds 
the ceiling or drops below the floor established in the agreement.  At 
December 31, 1995, Entech had swap agreements to hedge approximately 
400,000 barrels of oil, or 44%, of its expected production through November 
1996, and for approximately 806,000 Mmcf of natural gas, or 22%, of its 
expected production through March 1996.  In addition, Entech had swap 
agreements to hedge approximately 2,675,000 Mmcf of natural gas, or 23%, of its 
delivery obligations under long-term natural gas sales contracts through 
February 1997.  At December 31, 1995, the Company had no material deferred 
gains or losses from these transactions.

	The IPG has investments in independent power partnerships, some of which 
have entered into derivative financial instruments  to hedge against interest 
rate exposure on floating rate debt and foreign currency and gas price 
fluctuations.  At December 31, 1995, the Company believes it would not 
experience any materially adverse impacts from the risks inherent in these 
instruments.  

	Statement of Financial Accounting Standards No. 107, "Disclosure about 
Fair Value of Financial Instruments," requires disclosure of the fair value of 
certain financial instruments.  The estimated fair value amounts have been 
determined by the Company using available market information and appropriate 
valuation methodologies.  However, considerable judgment is required in 
interpreting market data to develop the estimates of fair value.  Accordingly, 
the estimates presented herein are not necessarily indicative of the amounts 
that could be realized in a current market exchange.  The use of different 
market assumptions and/or estimation methodologies could result in different 
estimated fair value amounts.  

	Cash and temporary cash investments, accounts receivable, current assets, 
short-term borrowings, accounts payable and accrued liabilities are reflected 
in the financial statements at fair value because of the short-term maturity of 
these instruments.  



	The carrying amounts and estimated fair value of the Company's other 
significant financial instruments were as follows:  

			1995	1994
			Carrying	Fair 	Carrying	Fair 
			 Amount 	Value	Amount 	Value
				  Thousands of Dollars

Assets:  
	Independent power investments		$ 7,868	$ 2,169	$ 9,566	$ 5,482
	Other investments		33,558	34,575	31,690	31,875

Liabilities:
	Long-term debt		$616,574	$656,476	$588,876	$548,358

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

	Independent power investments - The fair value represents the Company's 
assessment of the present value of net future cash flows embodied in these 
investments, discounted to reflect current market rates of return.  This 
represents only those investments accounted for on the cost basis.  The 
investments accounted for on the equity basis are not presented.  

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

	Long-term debt - The fair value was estimated using quoted market rates 
for the same or similar instruments.  Where quotes were not available the fair 
value was estimated using the Company's year-end incremental borrowing rate.  

Reclassifications:  

	Certain reclassifications have been made to the prior year amounts to 
make them comparable to the 1995 presentation.  These changes had no impact on 
previously reported results of operations or shareholders' equity.  



NOTE 2 - Contingencies:  

	In 1990, pursuant to a FERC license obligation, the Company proposed a 
plan to protect fish and wildlife habitat affected by the operation of the Kerr 
hydroelectric project, which would cost the Company $15,500,000 initially and, 
thereafter, $1,000,000 annually.  FERC and the Department of the Interior have 
proposed alternatives which would cost $48,000,000 initially  and, thereafter, 
$1,300,000 annually and would require baseload as opposed to load following 
operation.

	In November 1992, the Company applied to FERC to relicense nine Madison 
and Missouri River hydroelectric projects, with generating capacity of 
292 megawatts.  The total cost of relicensing, including physical improvements, 
is estimated at $151,000,000.  In addition, operating changes associated with 
environmental protection are expected to decrease project capability by 
26 megawatts.

	The Company has brought an action against Puget Sound Power & Light 
Company (Puget) in the Federal District Court for the Western District of 
Montana seeking a determination that the Company is 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 had breached the 
agreement by failing to provide a firm transmission path for the power, thereby 
entitling Puget to terminate the agreement.  The Company and Puget have agreed 
that, should it be determined that Puget is entitled to terminate the 
agreement, the Company would reimburse Puget for the excess, if any, of the 
cost of power purchased under the agreement after February 1995, over the cost 
which Puget may demonstrate it would have paid for such power elsewhere.  Also, 
the Company would be obligated to reimburse Puget for the amount (estimated at 
$40,000,000, excluding interest, by which Puget's payments through February 
1995 have exceeded its projected avoided cost.  In addition, the Company's 
future revenues would be reduced by the difference, if any, between sales at 
prices under the agreement, approximately $30,000,000 per year, and prices it 
might receive from alternative sales.  In accordance with SFAS No. 121, the 
Company could be required to writedown assets related to the agreement by 
approximately $24,000,000, before taxes.  The Company believes that Puget's 
intention is to reduce its purchase power costs.  The price of power under the 
agreement is in excess of current market rates.  While confident of its 
position, the Company cannot be certain of the decisions in the proceedings, 
which are not expected to conclude before the fourth quarter of 1996.  

	In March 1995, an arbitration decision resolved a  pricing dispute 
between Western Energy Company (Western), a subsidiary of the Company, and 
Puget regarding the Colstrip Units 1 and 2 Coal Supply Agreement which is 
between Puget and the Company's Utility Division, as co-owners of the units, 
and Western, as coal supplier. Excluding production taxes and royalties, the 
contract price was reduced, effective July 1991, by approximately $1.20 per 
ton.  As a result, the Company's 1995 consolidated pre-tax income decreased 
approximately $6,000,000. Cash flow was not materially affected because Puget 
had  paid less than invoiced amounts for coal delivered after April 1992.  In 
addition, Western refunded approximately $11,700,000, including interest, with 
respect to coal sold to the Company's Utility Division since July 1991.  This 
refund did not affect either consolidated income or cash flow.  On an annual 
basis, the new contract price is estimated to result in a pre-tax reduction of 
consolidated income of approximately $3,500,000 per year.

	Western is also a party in an arbitration initiated by the non-operating 
owners of the Colstrip Units 3 and 4 (i.e., Puget, Washington Water Power 
Company, Portland General Electric Company and PacifiCorp -- collectively, the 
"Buyers") to resolve a variety of disputes arising under the contracts with 
Western for the supply and transportation of coal for these Units.  The 
principal issues are the amounts of and prices for coal that the Buyers are 
obligated to purchase in excess of 600,000 tons monthly, 6,000,000 tons yearly 
and 170,000,000 tons over the contract life, Western's obligation to mine in a 
manner dictated by the Buyers, and Western's obligation to place reclamation 
funds received in a trust account.  The Buyers are seeking prospective relief 
regarding the volumes and the amount to be paid for any volumes that exceed the 
above-stated amounts.  Damages sought by the Buyers regarding Western's alleged 
failure to have mined in accordance with their proposed mine plan and the 
refund of certain transportation charges are approximately $7,000,000.  And, 
the amount Western would be obligated to place in the trust account would be 
approximately $36,000,000, including interest.  A decision of the arbitrator is 
expected in the second quarter of 1996.  While confident of Western's 
positions, the Company cannot be certain of the outcome of the arbitration.

	Continental Energy Services, Inc., a wholly-owned subsidiary of the 
Company, is a general partner in a partnership (the Partnership) formed to 
construct and own a 248 megawatt Tenaska power plant at Frederickson, 
Washington.  The Partnership contracted in 1994 to sell the output of this 
plant to the Bonneville Power Administration (BPA) over a 20-year period.  In 
May of 1995, BPA informed the Partnership that it would not purchase the power. 
BPA alleged that decreases in demand for power and increasing constraints in 
protection of endangered species have frustrated its purposes for entering into 
the power purchase contract and, consequently, have excused it from 
performance.  The Partnership halted construction of the plant and has sued BPA 
seeking damages, including lost future profits.  This matter has been referred 
to binding arbitration by the United States Court of Federal Claims.  The 
Company does not believe this dispute will adversely affect its financial 
performance.

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



NOTE 3 - Commitments:

	The Company purchases approximately 600 million kWh annually under an 
Exchange Agreement with the Washington Public Power Supply System and the BPA 
which expires in 1996.  The rate is 4.9 cents per kWh.  In 1993, the Company 
entered into a contract to purchase 98 megawatts of seasonal capacity from 
Basin Electric Power Cooperative beginning in 1996. The rate will be 
approximately 3.3 cents per kWh in the contract year beginning in November 1996 
and will increase each subsequent year to approximately 7.1 cents per kWh in 
the final contract year which begins in November 2009.  

	The Company also has long-term purchase contracts with certain 
independent power producers and natural gas producers.  The purchased power 
contracts provide for capacity payments subject to a facility meeting certain 
operating standards, and payments based on energy received.  The purchased gas 
contracts provide for take-or-pay payments.  The Entech Oil Division has 
various natural gas transportation contracts with terms that expire beginning 
in 1998.

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

			          Thousands of Dollars       

	       Years      	 Electric	Natural Gas	 Entech 
	1993		$  18,434	$    11,633	$  2,460
	1994		   19,242	     11,072	   3,302
	1995		   21,830	      9,873	   3,023

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

			          Thousands of Dollars       

	       Years      	 Electric	Natural Gas	 Entech  
	1996		$   8,829	  $  7,393	$  2,954
	1997		   12,035	     6,346	   2,420
	1998		   11,999	     3,075	   2,873
	1999		   11,791	     2,607	   3,188
	2000		   11,606	     2,275	   2,951
	Remainder		  152,223	     4,289	  11,587
	  Total		$ 208,483	  $ 25,985	$ 25,973


	Under a joint 50-year license with the Confederated Salish and Kootenai 
Tribes (Tribes), the Company will own and operate the 180 megawatt Kerr 
hydroelectric project until September 2015.  The Tribes may take over the 
project anytime between 2015 and 2025 on one year's written notice in return 
for payment equal to the Company's remaining net investment.  The Company pays 
the Tribes an annual rental fee that is adjusted yearly to reflect changes in 
the Consumer Price Index.  

	An Entech Coal Division coal lease purchase agreement requires minimum 
annual payments, beginning in 1991 in the amount of $1,125,000 escalated 
quarterly by the Gross National Product implicit price deflator.  The payments 
will continue until the equivalent of $18,750,000, in 1986 dollars, has been 
paid.  At December 31, 1995, the remaining payments under this agreement were 
$11,791,000.  Under current mine plans, these payments should be recovered 
through coal sales.  

	The Entech Oil Division has agreed to supply approximately 126,000 Mmcf 
of natural gas to four co-generation facilities through mid-2011.  The Oil 
Division has proven, developed and undeveloped reserves sufficient to supply 
all of the remaining natural gas required by these agreements.

	Rental expense for the prior three years was as follows:  

	   1995   	   1994   	   1993   
	         Thousands of Dollars

Colstrip Unit 4			$   31,680	$   32,226	$   32,226
Kerr project			    12,498	    12,172	    11,837
Other			    11,780	    12,530	    11,917
		$   55,958	$   56,928	$   55,980

	In addition, operating expenses include delay rentals paid by the Company 
to retain mineral rights before development of leased acreage.  Delay rentals 
were $2,960,000, $1,015,000 and $1,021,000 in 1995, 1994 and 1993, 
respectively.

Leases:

	The Company classifies leases as operating or capitalized leases. 
Capitalized leases are not material and are included in other long-term debt. 
On December 30, 1985, the Company sold its 30% share of Colstrip Unit 4 and is 
leasing back this share under a net lease.  The transaction has been accounted 
for as an operating lease with semiannual lease payments of approximately 
$16,000,000 over the remaining term of the 25-year lease.

	At December 31, 1995, the Company's future minimum operating lease 
payments were as follows:

				Thousands of
	Year		   Dollars  

	1996		$     33,430
	1997		      32,971
	1998		      32,769
	1999		      32,757
	2000		      32,542
	Remainder		     322,064
		Total		$    486,533



NOTE 4 - Income tax expense:  

	Income before income taxes for the years ended December 31, 1995, 1994 
and 1993 was as follows:

		   1995   	   1994   	   1993   
		        Thousands of Dollars 

United States		$   75,458	$  155,978	$  150,290

Canada		       111	     9,144	     8,791

Brazil		     2,942	     3,696	     2,250

		$   78,511	$  168,818	$  161,331


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

				   1995  	   1994  	   1993  
			         Thousands of Dollars

Computed "expected" income tax expense		$  27,479	$  59,086	$  56,466

Adjustments for tax effects of:

	Statutory depletion in
		coal mining operations		   (6,508)	   (4,983)	   (3,775)
	General business and nonconventional
		fuel tax credits		   (5,331)	   (5,130)	   (4,496)
	State income tax, net		    3,327	    4,772	    4,704
	Reversal of excess of U.S. Utility
		income tax depreciation over
		financial accounting 
		depreciation on utility plant
		additions		    2,552	    3,236	    2,281

	Other		       55	   (1,755)	   (1,060)

Actual income tax expense		$  21,574	$  55,226	$  54,120



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

			   1995   	   1994   	   1993   
			         Thousands of Dollars

Current

	United States		$   25,119	$   38,519 	$   31,039

	Canada		     1,510	     3,093	     3,235

	Brazil		       548	     1,080

	State		     6,216	     7,742	     3,522

			    33,393	    50,434	    37,796

Deferred

	United States		    (8,648)	     4,426	    13,664

	Canada		    (1,124)	       850	       374

	State		    (2,047)	      (484)	     2,286

			   (11,819)	     4,792	    16,324

			$   21,574	$   55,226	$   54,120

	Deferred tax liabilities (assets) are comprised of the following at 
December 31:  
			   1995   	   1994   
			 Thousands of Dollars

Plant related		$  377,741	$  379,401
Investment in nonutility generation projects		    23,896	    21,752
Other		    25,724	    21,309

	Gross deferred tax liabilities		   427,361	   422,462

Coal reclamation		   (42,438)	   (40,509)
Amortization of gain on sale/leaseback		   (15,962)	   (17,026)
Investment tax credit amortization		   (30,542)	   (31,665)
Other		   (33,582)	   (20,392)

	Gross deferred tax assets		  (122,524)	  (109,592)
	Net deferred tax liabilities (assets)		   304,837	   312,870

	Plus current deferred tax assets-net		    15,899	     9,965

Total noncurrent deferred tax liabilities
  (assets)		$  320,736	$  322,835	



	The change in net deferred tax liabilities differs from current year 
deferred tax expense as a result of the following:

				Thousands of
			   Dollars  
	Increase (decrease) in total noncurrent deferred tax
	  liabilities (assets)		$  (2,099)
	Regulatory assets related to income taxes		   (1,506)
	Current deferred tax assets-net		   (5,934)
	Amortization of investment tax credits		   (1,728)
	Other		     (552)
		Deferred tax expense		$ (11,819)



NOTE 5 - Common stock:  

	At December 31, 1995 and 1994, the Company had 120,000,000 shares of 
authorized common stock.  The Company has a Shareholder Protection Rights Plan 
which provides one preferred share purchase right (Right) on each outstanding 
common share of the Company.  Each Right entitles the registered holder, upon 
the occurrence of certain events, to purchase from the Company one 
one-hundredth of a share of Participating Preferred Shares, A Series, without 
par value.  If it should become exercisable, each Right would have economic 
terms similar to one share of common stock of the Company.  The Rights trade 
with the underlying shares and will, except under certain circumstances 
described in the Plan, expire on June 6, 1999, unless earlier redeemed or 
exchanged by the Company.  

	The Company's Dividend Reinvestment and Stock Purchase Plan allows owners 
of common and preferred stock, employees, Montana utility customers and certain 
others to reinvest the dividends paid on their common and preferred stock to 
purchase shares of common stock.  Participants in the plan may also elect to 
invest by purchasing up to $15,000 of common stock per quarter.  Beginning in 
1996, shares issued under these plans will be purchased in the open market.  

	The Company has a Deferred Savings and Employee Stock Ownership 
Plan (Plan) that covers all regular eligible employees.  The Company, on behalf 
of the employee, contributes a percentage of the amount contributed to the Plan 
by the employee.  In 1990, the Company borrowed $40,000,000 at an interest rate 
of 9.2% to be repaid in equal annual installments over 15 years.  The proceeds 
of the loan were lent on similar terms to the Plan Trustee, which purchased 
1,922,297 shares of Company common stock.  The loan, which is reflected as 
long-term debt, is offset by a similar amount in common shareholders' equity as 
unallocated stock.  Company contributions plus the dividends on the shares held 
under the Plan are used to meet principal and interest payments on the loan. 
Shares acquired with loan proceeds are allocated to Plan participants.  As 
principal payments on the loan are made, long-term debt and the offset in 
common shareholders' equity are both reduced.  At December 31, 1995, 
738,371 shares had been allocated to the participants' accounts.  

	Expense for the Plan is recognized using the Shares Allocated Method, and 
consists of the following for the three years ended December 31:  
  
		  1995  	  1994  	  1993   
		     Thousands of Dollars

	Principal allocated....................	$  2,663	$  2,663	$  2,663
	Interest incurred......................	   2,939	   3,114	   3,275
	Dividends..............................	  (3,033)	  (3,046)	  (3,028)
	Additional contribution................	   3,041	   2,952	   2,310

	     Total expense.....................	$  5,610	$  5,683	$  5,220

	The Company's amount of Plan costs funded, which currently is less than 
the aforementioned expense amounts, is included in utility rates.  Accordingly, 
the difference of $746,000, $968,000 and $758,000 for the years ending 
December 31, 1995, 1994 and 1993, respectively, were recorded as a reduction of 
Plan expense.  

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

	Option activity is summarized below:  

				  Number	 Option Price
				Of Shares	   Per Share  

	Outstanding
		December 31, 1992	   536,085	$14.25   -  26.50
			Granted	       -	
			Exercised	  (118,243)	 14.25   -  26.50
			Cancelled	    (5,532)	 14.25   -  26.50

	Outstanding
		December 31, 1993	   412,310	$14.25   -  26.50
			Granted	   117,100	 22.625  -  25.625
			Exercised	   (43,884)	 14.25   -  26.50
			Cancelled	    (4,540)	 14.25   -  26.50

	Outstanding
		December 31, 1994	   480,986	$17.25   -  26.50
			Granted	   116,730	 21.125  -  22.50
			Exercised	   (19,034)	 17.25   -  26.50
			Cancelled	    (8,700)	 22.125  -  22.625

	Outstanding
		December 31, 1995	   569,982	$17.25   -  26.50

	Options Exercisable at
		December 31, 1995	   569,982

	Options were granted at 100% of the closing price on the New York Stock 
Exchange on the date granted, and expire ten years from that date.  Options 
granted prior to January 1, 1987 must be exercised in the order granted.  

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

	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.  Companies electing not to recognize compensation 
expense are required to disclose what net income and earnings per share would 
have been if the expense were recognized.  While the Company does on occasion 
issue equity instruments to its key employees, the total value is not material. 
At this time, the Company expects to elect the disclosure option of SFAS No. 
123 rather than recognition of compensation expense.  


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:  

		  Shares	   Amount   
		Issued and	Thousands of
	Series	Outstanding	   Dollars  

	$6.875	    500,000	 $   50,000 
	 6.00	    159,589	     15,959
	 4.20	     60,000	      6,025
	 2.15	  1,200,000	     30,000
		  1,919,589	 $  101,984

	The stated value and liquidation price of preferred shares is $100 for 
the $6.875 series, the $6.00 series and the $4.20 series and $25 for the 
$2.15 series, plus accumulated dividends.  The preferred stock is redeemable at 
the option of the Company upon the written consent or affirmative vote of the 
holders of a majority of the common shares on thirty days notice at $110 per 
share for the $6.00 series, $103 per share for the $4.20 series and $25.25 per 
share for the $2.15 series, plus accumulated dividends.  The $6.875 series is 
redeemable in whole or in part, at anytime on or after November 1, 2003 for a 
price beginning at $103.438 per share with annual decrements through October 
2013, after which the redemption price is $100 per share.  At the annual 
meeting of shareholders in May 1994, shareholders approved a proposal 
permitting the redemption of the $2.15 series.  



NOTE 7 - Long-term debt:  

	Long-term debt consists of the following:  
						       December 31      
						   1995   	   1994   
					  	  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		   128,000	    88,000
		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		    16,500	    17,000
ESOP Notes Payable, due 2004		    29,861	    31,943
Unsecured Medium-Term Notes, Series A		    38,250	    48,250
Revolving Credit Agreements - Entech		    10,000	
Other		    17,696	    19,847
Unamortized Discount and Premium		    (4,134)	    (4,389)
		   641,378	   605,856
Less:  Portion due within one year		    24,804	    16,980
		$  616,574	$  588,876

First Mortgage Bonds:

	The Company's Mortgage and Deed of Trust imposes a first mortgage lien on 
all physical properties owned, exclusive of subsidiary company assets, and 
certain property and assets specifically excepted.  The obligations 
collateralized are First Mortgage Bonds, including those First Mortgage Bonds 
designated as Secured Medium-Term Notes and those securing Pollution Control 
Revenue Bonds set forth above, in the aggregate principal amount of 
$533,205,000 at December 31, 1995.  

	At December 31, 1995 and 1994, the Company had outstanding $128,000,000 
and $88,000,000 principal amount of Secured Medium-Term Notes, respectively, 
maturing from 2 to 30 years with interest rates varying between 5.75% and 
8.11%.  

	In April 1995, the Company sold $20,000,000 of Secured Medium-Term Notes, 
7.33% series due 2025.  The proceeds of which were used to finance construction 
and repay short-term debt.  In November 1995, the Company sold  $20,000,000 of 
Secured Medium-Term Notes, $10,000,000 of a 5.75% series due 1997 and 
$10,000,000 of a 5.9% series due 1998.  The proceeds were used to finance 
construction and retire $10,000,000 of Unsecured Medium-Term Notes, 8.87% 
series due 1995.



ESOP Notes Payable:  

	In 1990, the Company borrowed $40,000,000 at an interest rate of 9.2% in 
a 15-year loan to be repaid in equal annual installments.  The proceeds of the 
loan were used to purchase shares of the Company's stock to pre-fund a portion 
of the Company's matching requirements under the Deferred Savings and Employee 
Stock Ownership Plan.  See Note 5 - Common stock for further information.  

Unsecured Medium-Term Notes, Series A:

	At December 31, 1995 and 1994, the Company had outstanding $38,250,000 
and $48,250,000 principal amount of Unsecured Medium-Term Notes, respectively, 
maturing from 1 to 27 years with interest rates varying between 8.68% and 
8.90%.  

Revolving Credit Agreements:  

	The Company has a Revolving Credit Agreement that allows it to borrow up 
to $60,000,000, all of which was unused at December 31, 1995.  Under the 
agreement, borrowings outstanding at October 27, 1998, must be repaid at that 
time.

	Entech has a Revolving Credit and Term Loan Agreement with a group of 
banks that allows it to borrow up to $75,000,000, of which $65,000,000 was 
unused at December 31, 1995.  Under the agreement, borrowings outstanding at 
September 30, 1997 must be repaid at that time.  After recording the 
SFAS No. 121 adjustment, the fourth quarter coverage ratio did not meet the 
requirements of the Agreement.  The Company requested and expects to receive a 
waiver from the banks with respect to the coverage ratio for the fourth 
quarter.  

	Fixed or variable interest rate options are available under the 
facilities, with commitment fees on the unused portions.  

	During the period 1996 through 2000, the Company is required to make the 
following maturity and sinking fund payments on long-term debt:

		  1996  	  1997  	  1998  	  1999  	  2000  
			    Thousands of Dollars

7.7% First Mortgage Bonds..				$ 55,000
Secured Medium-Term Notes..		$ 20,000	$ 20,000		$ 20,000
7 1/2% Sinking Fund
	Debentures...............	$    500	     500	  15,500	
Revolving Credit
  Agreement - Entech.......		  10,000
ESOP Notes Payable.........	   2,274	   2,483     2,712     2,961	   3,234
Unsecured Medium-Term 
  Notes....................	   8,750	   7,500	   2,500	   2,500	  10,000
Other......................	  13,280	     969	   1,030	     636	     672
		$ 24,804	$ 41,452	$ 41,742	$ 61,097	$ 33,906



NOTE 8 - Short-term borrowing:  

	The Company is authorized by the PSC to incur short-term debt not to 
exceed $150,000,000.  The Company and Entech have short-term borrowing 
facilities with commercial banks that provide both committed, as well as 
uncommitted lines of credit, and the ability to sell commercial paper.  Bank 
borrowings either bear interest at the lender's floating base rate and may be 
repaid at any time, or have fixed rates of interest and maturities.  Commercial 
paper has fixed rates of interest and maturities.   

	At December 31, 1995, the Company had lines of credit consisting of 
$65,000,000 committed and $70,400,000 uncommitted, and Entech had lines of 
credit consisting of $15,000,000 committed and $20,000,000 uncommitted.  There 
is a commitment fee on the unused portion of some of these facilities which is 
not significant.  The Company has the ability, subject to the previously 
mentioned PSC limitation, to issue up to $125,000,000 of commercial paper and 
Entech up to $50,000,000 of commercial paper based on the total of unused 
committed lines of credit and revolving credit agreements.  

	At December 31, 1995 and 1994, the Company's and Entech's short-term 
borrowing included the following:  

		   1995   	   1994   
		  Thousands of Dollars

	Notes payable to banks
	  MPC..........................	$   53,000	$   90,000
	  Entech.......................	    25,400	    14,000
	Commercial paper
	  Entech.......................	    17,948	     9,989
		$   96,348	$  113,989



NOTE 9 - Retirement plans:  

	The Company maintains trusteed, noncontributory retirement plans covering 
substantially all employees.  Retirement benefits are based on salary, years of 
service and social security integration levels.  

	In 1995, 1994 and 1993, pension costs funded were less than SFAS No. 87 
pension expense by $1,501,000, $2,770,000 and $1,887,000, respectively and the 
difference was recorded as a deferred charge.  The amount of Utility pension 
costs funded are included in rates.  At December 31, 1995, the cumulative 
amount by which SFAS No. 87 pension expense exceeded pension costs funded was 
$2,909,000. 

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

	The Company also has an unfunded, nonqualified benefit plan for senior 
management executives and directors that provides for defined benefit payments 
upon retirement over the life of the participant or to their beneficiary for a 
minimum fifteen-year period.  Life insurance payable to the Company is carried 
on plan participants as an investment.  Utility nonqualified benefit plan 
expense is not included in rates.  

	Net pension and benefit expense includes the following components:  

			   1995  	   1994  	   1993   
			       Thousands of Dollars

	Service cost benefits earned during 
		the period..........................	$   6,204	$   8,442	$    6,746
	Interest cost on projected benefit 
		obligation..........................	   14,594	   13,430	    12,077
	Actual return market value of assets..	  (13,090)	  (13,051)	   (18,701)
	Net amortization and deferral.........	    1,718	    3,788	    10,891

		Total net periodic pension and 
		  benefit expense...................	$   9,426	$  12,609	$   11,013



	The funded status of the pension and benefit plans is as follows:  
<TABLE>
<CAPTION>
			     December 31     
			  1995   	  1994   
			Thousands of Dollars
<S>                                                      <C>         <C>
	Actuarial present value of accumulated plan
		benefits:  
		  Vested......................................	$ 149,787	$ 119,298
		  Nonvested...................................	   17,799	   13,066

	Accumulated benefit obligation..................	  167,586	  132,364
	Effect of projected future compensation levels..	   53,514	   40,474

	Projected benefit obligation....................	  221,100	  172,838
	Plan assets at fair value.......................	  197,389	  153,916

	Plan assets less than projected  
	  benefit obligation............................	  (23,711)	  (18,922)

	Unrecognized net loss (gain) from past 
		experience different from that assumed and 
		effects of changes in assumptions.............	   (7,137)	   (9,402)
	Prior service cost not yet recognized in net
		periodic pension expense......................	   10,466	   11,498
	Unrecognized initial obligation.................	    2,852	    3,261

		Prepaid (Accrued) benefits expense............	$ (17,530)	$ (13,565)

</TABLE>
	The following assumptions were used in the determination of actuarial 
present values of the projected benefit obligations:  
<TABLE>
<CAPTION>
			      December 31      
			   1995    	    1994   
<S>                                                      <C>         <C>
	Assumed discount rates:  
		Active service and vested terminations........	      7.00%	      8.25%
		Retired employees.............................	      7.00%	      8.25%

	Long-term rate of average compensation increase.	4.00%-4.90%	4.25%-5.20%

	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.  Until 1993, the cost of retiree health care and 
life insurance benefits was recognized as expense on a pay-as-you-go (cash) 
basis.  The cost of these benefits in 1993 was $1,387,000.

	In 1994, the Company established a pre-funding plan for postretirement 
benefits for Utility employees retiring after January 1, 1993.  Funding costs 
for the plan for 1995 and 1994 were $2,077,000 and $1,487,000, respectively. 
The assets of the plan consist primarily of domestic and foreign corporate 
stocks, domestic corporate bonds and U.S. Government securities.  

	The Company adopted SFAS No. 106 effective January 1, 1993.  SFAS No. 106 
requires accrual of the expected cost of these postretirement benefits during 
the employees' years of service rather than when the costs are paid.

	In accordance with an Accounting Order issued by the PSC in 1992, the 
Company recorded as a deferred expense $600,000 and $2,100,000 representing the 
increased costs in 1994 and 1993, respectively, from adopting SFAS No. 106 for 
the Utility Division.  In its April 28, 1994 Order, the PSC allowed the Company 
to include in rates the full OPEB cost on the accrual basis provided by SFAS 
No. 106, including the amortization of the amounts previously deferred under a 
PSC Accounting Order from January 1, 1993 to April 27, 1994.  Consequently, as 
of April 28, 1994, the Company commenced recognition of these Utility 
postretirement benefits in expense in accordance with SFAS No. 106.  The 
incremental increase in 1994 consolidated expenses due to the Utility SFAS 
No. 106 expense recognition was approximately $1,500,000.  

	The cost of SFAS No. 106 adoption for the years ended December 31, 1995 
and 1994, portions of which have been deferred or capitalized, includes the 
following components:  

				     December 31     
				  1995     	  1994    
				Thousands of Dollars

	Service cost on benefits earned
		during the year		$  1,221	$  1,455

	Interest cost on projected benefit
		obligation		   2,482	   2,323

	Actual return market value of assets		    (219)	     (38)

	Net amortizations		   1,299	   1,535

	Total postretirement benefit cost		$  4,783	$  5,275



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

				    December 31     
		 		  1995  	  1994  
				Thousands of Dollars

	Accumulated benefit obligation:
		Fully eligible active employees		$  1,939	$  2,253
		Other active employees		  22,856	  19,857
		Retirees		  11,909	   8,751
		Accumulated benefit obligation		  36,704	  30,861
	Plan assets at fair value		   3,714	   1,479
	Plan assets less than projected
		benefit obligation		 (32,990)	 (29,382)
	Unrecognized net transition obligation		  24,728	  25,560
	Unrecognized net loss (gain) from past
	  experience different from that
	  assumed and effects of changes
	  in assumptions		     542	  (2,417)
	Prepaid (accrued) benefits expense		$ (7,720)	$ (6,239)

	In 1995, the Company accrued the estimated expected postretirement 
benefit obligation for the plan curtailment at Basin Resources, Inc. during 
1996 as part of the writedown of long-lived assets (see Note 11 - Asset 
impairment).  

	The assumed 1995 health care cost trend rates used to measure the 
expected cost of benefits covered by the plans are 8.50% and 10% for the 
utility and non-utility operations, respectively.  The trend rates decrease 
through 2004 to 5%.  The trend rates are for pre-65 benefits since most of the 
plans provide a fixed dollar annual benefit for retirees over age 65.  One 
Entech subsidiary's plan used a trend rate of 9% decreasing through 2003 to an 
ultimate rate of 5% for post-65 benefits.  The effect of a 1% increase in each 
future year's assumed health care cost trend rates increases the service and 
interest cost from $3,700,000 to $4,100,000 and the accumulated postretirement 
benefit obligation from $24,700,000 to $28,000,000.

	On January 1, 1994, the Company adopted Statement of Financial Accounting 
Standards No. 112, "Employers' Accounting for Postemployment Benefits," (SFAS 
No. 112) with respect to disability related benefits up to age 65.  SFAS 
No. 112 requires the accrual of a liability or loss contingency for the 
estimated obligation for postemployment benefits.  At December 31, 1993, the 
postemployment benefit liability for regulated utility operations was estimated 
to be $9,300,000, of which $2,400,000 had been accrued and included in rates. 
The remaining $6,900,000 was recorded in 1994 as a deferred charge and will be 
expensed and included in rates over the next ten years.  The estimated 
December 31, 1993 postemployment benefit liability of $1,300,000 for non-
utility operations 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 as previously discussed.  



NOTE 10 - Information on industry segments:  

	The Company's principal business includes regulated utility operations 
involving the generation, purchase, transmission and distribution of 
electricity and the production, purchase, transportation and distribution of 
natural gas.  The Company, through Entech, engages in nonutility operations 
principally involving the mining and sale of coal, exploration for, and the 
development, production, processing and sale of oil and natural gas and the 
sale of telecommunication equipment and services.  The Company, through IPG, 
manages long-term power sales, develops and invests in independent power 
projects and other energy-related businesses.  

	Substantially all of the natural gas produced by the Company's Canadian 
utility operations has been sold to the Company's United States utility 
operations.  

	Pre-tax operating income for the Utility, Entech and IPG segments 
represents revenues excluding earnings from unconsolidated investments less all 
costs and expenses except interest and other (income) deductions-net. 
Immaterial intersegment sales are not disclosed.  

	Identifiable assets of each industry segment are those assets used in the 
Company's operations in such industry segments.  Corporate assets are 
principally miscellaneous special funds, cash and temporary cash investments, 
other investments and unallocable property.  The assets of the Company's 
Canadian operations were $77,282,000, $79,337,000 and $80,553,000 at 
December 31, 1995, 1994 and 1993, respectively.  



Operations Information:  
<TABLE>
<CAPTION>
				       Year Ended
				    December 31, 1995     
				   Thousands of Dollars
<S>                                                 <C>            <C>
UTILITY		 Electric 	Natural Gas

Sales to unaffiliated customers		$  422,019	$  115,120
Intersegment sales		     5,793	       862
Pre-tax operating income		   124,916	    30,933
Earnings from unconsolidated investments		
Depreciation, depletion and amortization		    42,506	    10,793
Capital expenditures		   127,917	    35,091
Identifiable assets		 1,503,619	   410,267

<CAPTION>
					  Oil and
ENTECH		   Coal*  	Natural Gas	   Other   
<S>                                           <C>          <C>          <C>
Sales to unaffiliated customers		$  210,377	$  100,198	$  26,238
Intersegment sales		    25,659	       241	      662
Writedown of long-lived assets		    55,102	    19,194	    
Pre-tax operating income (loss)		   (41,003)	    (8,504)	    2,148
Earnings (loss) from unconsolidated 
	investments		    (2,860)	    	       70
Depreciation, depletion and amortization		    11,187	    17,569	    1,745
Capital expenditures		    19,230	    34,780	    8,681
Identifiable assets		   250,132	   177,744	   39,624

<CAPTION>
INDEPENDENT POWER GROUP 
<S>                                                 <C>
Sales to unaffiliated customers		$   79,095
Intersegment sales		       796
Pre-tax operating income		     3,027
Earnings from unconsolidated investments		     2,622
Depreciation, depletion and amortization		     3,176
Capital expenditures		     4,168
Identifiable assets		   161,602

<CAPTION>
CORPORATE
<S>                                                 <C>
Sales to unaffiliated customers		
Intersegment sales		
Pre-tax operating income		
Earnings from unconsolidated investments		
Depreciation, depletion and amortization	
Capital expenditures		$    1,220
Identifiable assets		    43,103


*	Sales under one coal contract with Houston Light and Power Company amounted to 
$102,844,000.  
</TABLE>


Operations Information:  
<TABLE>
<CAPTION>
				       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
Earnings from unconsolidated investments	
Depreciation, depletion and amortization		    40,699	     9,842
Capital expenditures		   108,933	    41,969
Identifiable assets		 1,430,516	   368,320

<CAPTION>
					  Oil and
ENTECH		   Coal*  	Natural Gas	   Other  
<S>                                           <C>          <C>          <C>
Sales to unaffiliated customers		$  255,247	$   97,994	$   24,096
Intersegment sales		    42,201	       254	       787
Pre-tax operating income		    48,344	    13,647	     1,147
Earnings (loss) from unconsolidated 
	investments		    (2,740)		        68
Depreciation, depletion and amortization		    12,649	    18,464	     1,945
Capital expenditures		    16,115	    32,417	       492
Identifiable assets		   291,224	   179,261	    33,769

<CAPTION>
INDEPENDENT POWER GROUP 
<S>                                                 <C>
Sales to unaffiliated customers		$   93,647
Intersegment sales		     1,461
Pre-tax operating income		    10,912
Earnings from unconsolidated investments		     2,080
Depreciation, depletion and amortization		     3,112
Capital expenditures		     6,154
Identifiable assets		   159,138

<CAPTION>
CORPORATE
<S>                                                 <C>
Sales to unaffiliated customers		
Intersegment sales		
Pre-tax operating income		
Earnings from unconsolidated investments		
Depreciation, depletion and amortization	
Capital expenditures		$    1,231
Identifiable assets		    50,469


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


Operations Information:
<TABLE>
<CAPTION>
				       Year Ended
				    December 31, 1993     
				   Thousands of Dollars
 
UTILITY		 Electric 	Natural Gas
<S>                                                 <C>            <C>
Sales to unaffiliated customers		$  426,746	$  110,696
Intersegment sales		     7,532	       778
Pre-tax operating income		   112,530	    30,942 
Earnings from unconsolidated investments	
Depreciation, depletion and amortization		    39,151	     9,006
Capital expenditures		    83,308	    28,871
Identifiable assets		 1,338,560	   359,223

<CAPTION>
					  Oil and
ENTECH		   Coal*  	Natural Gas	   Other  
<S>                                           <C>          <C>          <C>
Sales to unaffiliated customers		$  227,285	$  117,659	$   24,429
Intersegment sales		    39,637	       741	       700
Pre-tax operating income		    45,220	    14,974	       714
Loss from unconsolidated investments		    (2,130)	    (3,228)	      (177)
Depreciation, depletion and amortization		    10,193	    19,327	     2,133
Capital expenditures		    26,253	    38,547	     1,875
Identifiable assets		   276,158	   169,310	    36,374

<CAPTION>
INDEPENDENT POWER GROUP
<S>                                                 <C>
Sales to unaffiliated customers		$  119,189
Intersegment sales		     5,528
Pre-tax operating loss		    (4,465)
Earnings from unconsolidated investments		     3,117
Depreciation, depletion and amortization		     2,887
Capital expenditures		     4,542
Identifiable assets		   163,550

<CAPTION>
CORPORATE
<S>                                                 <C>
Sales to unaffiliated customers		
Intersegment sales		
Pre-tax operating income		
Earnings from unconsolidated investments		
Depreciation, depletion and amortization	
Capital expenditures		$      156
Identifiable assets		    42,852


*	Sales under one coal contract with Houston Light and Power Company amounted to 
$98,569,000.  
</TABLE>



NOTE 11 - 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, an impairment test is required to determine whether the carrying 
amount of long-lived and certain intangible assets may be recoverable through 
future undiscounted cash flows.  Based upon tests performed as prescribed by 
SFAS No. 121, the Company recorded a before tax charge against income of 
$74,300,000.

	The impairment includes a $46,500,000 before tax charge to record the 
writedown of the assets and to recognize the closure liabilities of Entech's 
subsidiary, Basin Resources, Inc. (Basin), which owns and operated the Golden 
Eagle Mine in Colorado. Basin has been unable to operate without losses 
because of operating problems and a market where prices continue to be low. On 
December 29, 1995, Basin announced that all coal sales agreements had been 
terminated, that underground production would cease immediately, and that the 
Mine would be permanently closed by March 31, 1996, unless a viable buyer is 
identified.  To date, efforts to sell the Mine have been unsuccessful.  In 
addition to the Basin impairment, Entech's Coal Division recorded impairment 
charges of approximately $8,600,000 before tax for certain non-producing 
leaseholds and other investments.  Based upon  management's evaluation, these 
assets were not expected to generate sufficient undiscounted cash flows to 
cover their carrying values.

	Entech's Oil Division properties were also affected by the adoption of 
SFAS No. 121.  The Oil Division recorded an impairment charge of $19,200,000 
before tax.  Based upon updated reserve studies and tests performed under SFAS 
No. 121, the expected undiscounted cash flows from reserves in certain fields 
were not sufficient to recover the carrying value of those properties.

	Expected depreciation and depletion reductions in 1996 will be 
approximately $2,000,000 after taxes.




	SUPPLEMENTARY DATA
	OIL AND NATURAL GAS PRODUCING ACTIVITIES
<TABLE>
<CAPTION>
	For the years ended December 31, 1995, 1994 and 1993 net recoverable oil and 
natural gas reserves, excluding royalty volumes and volumes controlled under purchase 
contract, of the Utility and Entech operations were estimated as follows:  

					    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

ENTECH 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          

				        1995           
				   U.S.   	   CANADA  
PROVED DEVELOPED RESERVES:

UTILITY OPERATIONS:
	Natural Gas (Mmcf):
		Ending Balance	   74,630	  103,475

ENTECH 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 
PROVED DEVELOPED AND UNDEVELOPED RESERVES:
<S>                                               <C>         <C>           <C>
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 

ENTECH 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  	       

				        1994           
				   U.S.   	   CANADA    
PROVED DEVELOPED RESERVES:

UTILITY OPERATIONS:
	Natural Gas (Mmcf):
		Ending Balance	   79,731	     96,571

ENTECH 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>



<TABLE>
<CAPTION>
					   1993    
				   U.S.   	   CANADA   	STORAGE  
PROVED DEVELOPED AND UNDEVELOPED RESERVES:
<S>                                                  <C>        <C>         <C>
UTILITY OPERATIONS:
	Natural Gas (Mmcf):
		Beginning Balance	   83,264 	  101,220	 59,075
		Production	   (5,587)	   (3,927)
		Additions		      788 	 (2,757)
		(Sales) and Purchases of Reserves in Place 
		Revisions - Other	    2,393 	      790 	       
		Revisions - Price	                      	      	
			Ending Balance	   80,070	   98,871	 56,318 

ENTECH OPERATIONS:
	Natural Gas (Mmcf):
		Beginning Balance	  133,421 	   41,620 
		Production	  (10,740)	   (6,735)
		Additions	   24,414 	   17,758 
		(Sales) and Purchases of Reserves in Place	     (130)	    1,024 
		Revisions - Other	   (4,937)	      (74)
		Revisions - Price	   (1,105)	    5,478 	        
			Ending Balance	  140,923 	   59,071          

	Natural Gas
		Liquids (Bbls):
		Beginning Balance	1,071,700 	  907,500 
		Production	 (143,059)	 (134,509)
		Additions	  597,100 	  452,766 
		(Sales) and Purchases of Reserves in Place	 (861,059)	   (8,353)
		Revisions - Other	3,030,018 	  236,058 
		Revisions - Price	  (12,000)	   54,638         
			Ending Balance	3,682,700 	1,508,100         

	Oil (Bbls):
		Beginning Balance	3,877,900 	4,793,400 	
		Production	 (528,408)	 (917,992)
		Additions	3,157,100 	1,208,328 
		(Sales) and Purchases of Reserves in Place	   55,811 	 (115,014)
		Revisions - Other	 (127,288)	 (373,231)
		Revisions - Price	 (196,415)	  (83,891)       
			Ending Balance	6,238,700 	4,511,600        

				        1993 
				   U.S.   	   CANADA    
PROVED DEVELOPED RESERVES:

UTILITY OPERATIONS:
	Natural Gas (Mmcf):
		Ending Balance	   79,239 	     98,871 

ENTECH OPERATIONS:
	Natural Gas (Mmcf):
		Ending Balance	   89,372 	     51,437 

	Natural Gas Liquids (Bbls):
		Ending Balance	3,088,600 	  1,314,300 

	Oil (Bbls):
		Ending Balance	3,190,000 	  4,265,400 
</TABLE>



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

	As determined by engineers, Utility natural gas reserves were revised 
during 1995, 1994 and 1993 due to a change in projected performance or a change 
in the Company's ownership interest in specific fields.  

	In 1995, Entech's 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 Entech's 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, Entech's U.S. oil and natural gas reserves increased as a result 
of the acquisition of oil interests in Kansas and the drilling of 25 
development wells and 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.

	In 1993, Entech's U.S. oil and natural gas reserves increased as a result 
of the drilling of 55 development wells and 10 exploratory wells in Colorado, 
North Dakota, Wyoming, Oklahoma and Kansas.  Natural gas liquid reserves 
increased due to the startup of the Fort Lupton, Colorado gas processing plant 
in September 1993.  Lower oil market prices contributed to downward revisions 
in U.S. reserves.  The Canadian companies participated in 26 development and 13 
exploratory wells.  Significant gas reserves were added from discoveries in the 
exploratory wells.  Additions in oil reserves were the result of two successful 
secondary recovery schemes completed in the Manyberries area in Southern 
Alberta during 1993.  Revisions due to price and performance resulted in a net 
increase in natural gas liquid reserves and a net decrease in oil reserves.  



	The following table presents information for 1995, 1994 and 1993 on the 
capitalized costs relating to utility natural gas producing activities, costs 
incurred in utility natural gas property acquisition, exploration and 
development activities and certain utility natural gas production costs 
reflected in results of operations.  As a regulated public utility, the Company 
is authorized to earn a rate of return on its utility natural gas plant rate 
base. The Company's cost of acquiring utility natural gas reserves and the net 
cost of natural gas in underground storage are included in the natural gas 
plant which is a part of the utility rate base.  Due to the commingling of 
produced natural gas with purchased and royalty natural gas for sale to utility 
customers and application of the ratemaking process to the utility natural gas 
producing activities, the Company is unable to identify revenues resulting 
solely from utility natural gas producing activities.  Accordingly, the 
information on revenues, income taxes, results of operations and estimated 
future net cash flows and changes therein relating to proved utility natural 
gas reserves are not presented for the Company's utility natural gas producing 
activities.  
<TABLE>
<CAPTION>
				       1995      	       1994      	       1993     
					  U.S.  	 Canada 	  U.S.  	 Canada 	  U.S.  	 Canada 
UTILITY OPERATIONS		       Thousands of Dollars
<S>                           <C>      <C>      <C>      <C>      <C>      <C>
At December 31:
Capitalized costs relating 
	to natural gas producing
	activities		$ 89,520	$ 37,683	$ 95,713	$ 36,904	$ 90,711	$ 35,786
Accumulated depreciation,
	depletion and valuation
	allowances		  50,377	  19,812	  48,913	  19,386	  44,516	  18,815

		Net capitalized costs		$ 39,143	$ 17,871	$ 46,800	$ 17,518	$ 46,195	$ 16,971

For the year ended 
	December 31:  
Costs incurred in natural
	gas property acquisition, 
	exploration and 
	development activities: 
		Acquisition of 
			properties		$    48	$   170	$    414	$    259	$     46	$     27
		Exploration		     70	    198	     358	     231	     386	     244
		Development		  1,753	  1,240	   5,158	   1,203	   1,528	     496

Costs reflected in results 
  of operations: 
		Production costs		$ 5,710	$ 1,592	$  4,795	$  1,348	$  4,958	$  1,391
		Exploration expenses		     70	    198	     128	     231	     148	     244
		Development expenses		    165	    416	     165	     197	      90	      59
		Depreciation, depletion
			and valuation 
		  provisions		  2,716	    586	   2,607	     487	   2,564	     283
</TABLE>


	The following table presents information for 1995, 1994 and 1993 on the 
capitalized costs relating to Entech oil and natural gas producing activities, 
costs incurred in Entech oil and natural gas property acquisition, exploration 
and development activities and results of Entech operations for oil and natural 
gas producing activities:
<TABLE>
<CAPTION>
				       1995      	       1994      	       1993      
					  U.S.  	 Canada 	  U.S.  	 Canada 	  U.S.  	 Canada 
ENTECH OPERATIONS		       Thousands of Dollars
At December 31:
<S>                           <C>      <C>      <C>      <C>      <C>      <C>
Capitalized costs relating
	to oil and natural gas
	producing activities		$171,795	$83,457	$145,639	$ 78,667	$136,949	$ 88,596
Accumulated depreciation,
	depletion and valuation 
	allowances		  60,329	 39,834	  39,534	  27,247	  36,725	  34,426

		Net capitalized costs		$111,466	$43,623	$106,105	$ 51,420	$100,224	$ 54,170

For the year ended 
	December 31:

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

		Acquisition of 
		  properties		$ 13,024	$ 4,407	$  8,134	$  5,866	$  1,700	$  2,638
		Exploration		   4,592	  1,642	   2,513	   1,924	   2,838	   2,711
		Development		  11,244	  4,298	  11,514	   4,068	  26,279	   5,721

Results of operations for 
	oil and natural gas 
	producing activities:

		Revenues		$ 20,461	$19,022	$ 25,319	$ 22,542	$ 30,713	$ 23,435
		Production costs		   7,298	  6,812	   7,261	   7,404	   9,459	   7,629
		Exploration expenses		   2,460	  1,517	   1,610	   1,426	   2,123	   2,184
		Depreciation, depletion 
			and valuation 
			provisions		  21,079	 15,371	  10,533	   7,669	  10,386	   8,707
					 (10,376)	 (4,678)	   5,915	   6,043	   8,745	   4,915

		Income tax expenses		  (5,708)	 (2,087)	      25	   2,679	     978	   2,179

Results of operations from
	producing activities
	(excluding corporate 
	overhead and interest 
	cost)		$ (4,668)	$(2,591)	$  5,890	$  3,364	$  7,767	$  2,736
</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.  



	STANDARDIZED MEASURE OF DISCOUNTED FUTURE
	NET CASH FLOWS AND CHANGES THEREIN RELATING TO
	PROVED OIL AND NATURAL GAS RESERVES
<TABLE>
<CAPTION>
			                    December 31                   
		             1995                    1994         
			   U.S.     	    Canada  	    U.S.    	    Canada  
				    Thousands of Dollars   
<S>                                 <C>          <C>          <C>          <C>
Future cash inflows		$   523,563	$  148,140	$   603,543	$  185,877
Future production and  
	development costs		    197,073	    57,455	    200,004	    69,043
Future income tax expenses		     89,726	    18,033	    114,953	    29,952

Future net cash flows		    236,764	    72,652	    288,586	    86,882
10% annual discount for 
	estimated timing
	of cash flows		     98,831	    16,163	    122,835	    23,382

Standardized measure of 
	discounted future net 
	cash flows		$   137,933	$   56,489	$   165,751	$   63,500

	  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 (a)		$  (33,013)	$  (24,585)	$   (33,342)	$ (19,556)
Net changes in prices, 
	development and production 
	costs		   (24,122)	    (7,886)	      1,939	  (15,010)
Extensions, discoveries, and 
	improved recovery, less 
	related costs		     8,100	     1,728	     13,454	   18,687
Revisions of previous quantity 
	estimates		   (12,950)	     4,860	     12,868	    3,449
Accretion of discount		    20,816	     7,483	     18,839	    8,198
Net change in income taxes		    10,948	     6,315	     (4,683)	    1,895
Other (a)		     2,403	     5,074	      6,008	   (2,928)

(a)	Certain reclassifications have been made to the prior year amounts to make them 
comparable to the 1995 presentation.  
</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 1995 and 1994, 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 1995 and 1994 
are shown in the tables below.  Operating revenues and income include 
intersegment sales and expenses.  Due to the seasonal nature of the utility 
business, the annual amounts are not generated evenly by quarter during the 
year.
<TABLE>
<CAPTION>
			                 Quarter Ended                    

			 Dec. 31, 	Sept. 30, 	June 30,  	Mar. 31,
			  1995    	  1995    	  1995    	  1995    
<S>                                <C>          <C>          <C>           <C>
Utility Operating Revenues		$ 165,281	$ 110,254	$ 108,150	$ 160,109
Utility Operating Income		61,213	19,218		16,084	59,334
Utility Net Income		32,204	6,251		3,768	30,967

Entech Operating Revenues		95,880	95,601		85,754	83,350
Entech Operating Income (Loss)		(60,429)	8,172		2,628	(520)
Entech Net Income (Loss)		(33,547)	8,216		3,143	1,669

IPG Operating Revenues		21,244	21,616		18,113	21,540
IPG Operating Income		1,113	1,940		406	2,190
IPG Net Income		226	1,685		659	1,696

Consolidated Net Income (Loss)		(1,117)	16,152		7,570	34,332

Net Income (Loss) Per Share of 
	Common Stock		(0.05)	0.26		0.11	0.60


			                  Quarter Ended                   

			 Dec. 31, 	Sept. 30, 	June 30,  	Mar. 31,
			  1994   	  1994   	  1994   	  1994    

Utility Operating Revenues		$ 166,711	$ 110,394	$ 104,315	$ 160,212
Utility Operating Income		   55,546	    8,670	   10,728	   52,702
Utility Net Income		   27,843	      130	    1,162	   26,274

Entech Operating Revenues		  109,503	  107,796	   91,379	  109,229
Entech Operating Income		   15,715	   15,574	   12,141	   17,036
Entech Net Income		   13,896	   12,393	    9,772	   11,827

IPG Operating Revenues		   27,070	   27,404	   20,740	   21,974
IPG Operating Income (Loss)		    6,555	    5,573	     (905)	    1,769
IPG Net Income (Loss)		    3,686	    5,758	     (225)	    1,076

Consolidated Net Income		   45,425	   18,281	   10,709	   39,177

Net Income Per Share of Common 
	Stock		     0.82	     0.31	     0.17	     0.70
</TABLE>



ITEM  9.	DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL 
DISCLOSURE

	None.  

	PART III


ITEM 10.	DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

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

	Information on The Montana Power Company Directors is incorporated by 
reference from the Company's Notice of 1996 Annual Meeting of Shareholders and 
Proxy Statement, pages 1-3.  

ITEM 11.	EXECUTIVE COMPENSATION

	Incorporated by reference from Notice of 1996 Annual Meeting of 
Shareholders and Proxy Statement, pages 6-15.  

ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

	Incorporated by reference from Notice of 1996 Annual Meeting of 
Shareholders and Proxy Statement, pages 4-5.  

ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

	Incorporated by reference from Notice of 1996 Annual Meeting of 
Shareholders and Proxy Statement, page 15.  



	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 24, 1995	Item 5 Other Events.  Discussion of Third 
Quarter Net Income.

		Item 7 Exhibits.  Consolidated Statements of 
Income for the Quarters Ended September 30, 
1995 and 1994, Nine Months Ended September 30, 
1995 and 1994, and for the Twelve Months Ended 
September 30, 1995 and 1994. Utility 
Operations Schedule of Revenues and Expenses 
for the Quarters Ended September 30, 1995 and 
1994, Nine Months Ended September 30, 1995 and 
1994 and for the Twelve Months Ended 
September 30, 1995 and 1994. Entech 
Operations Schedule of Revenues and Expenses 
for the Quarters Ended September 30, 1995 and 
1994, Nine Months Ended September 30, 1995 and 
1994 and for the Twelve Months Ended 
September 30, 1995 and 1994. Independent 
Power Group Operations Schedule of Revenues 
and Expenses for the Quarters Ended 
September 30, 1995 and 1994, Nine Months 
Ended September 30, 1995 and 1994 and for the 
Twelve Months Ended September 30, 1995 and 
1994.  



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
	 3(b)	By-laws, as adopted
	 4(a)	Mortgage and Deed Trust	2-5927		7(e)
	 4(b)	First Supplemental Indenture	2-10834		4(e)
	 4(c)	Second Supplemental Indenture	2-14237		4(d)
	 4(d)	Third Supplemental Indenture	2-27121		2(a)-5
	 4(e)	Fourth Supplemental Indenture	2-36246		2(a)-6
	 4(f)	Fifth Supplemental Indenture	2-39536		2(a)-7
	 4(g)	Sixth Supplemental Indenture	2-49884		2(a)-8(a)
	 4(h)	Seventh Supplemental Indenture	2-52268		2(a)-9
	 4(i)	Eighth Supplemental Indenture	2-53940		2(a)-10
	 4(j)	Ninth Supplemental Indenture	2-55036		2(a)-11
	 4(k)	Tenth Supplemental Indenture	2-63264		2(a)-12
	 4(l)	Eleventh Supplemental Indenture	2-86500		2(a)-13
	 4(m)	Twelfth Supplemental Indenture	33-42882		4(c)
	 4(n)	Thirteenth Supplemental Indenture	33-55816		4(a)-14
	 4(o)	Fourteenth Supplemental Indenture	33-64576		4(c)
	 4(p)	Fifteenth Supplemental Indenture	33-64576		4(d)
	 4(q)	Sixteenth Supplemental Indenture	33-50235		99(a)
	 4(r)	Seventeenth Supplemental Indenture	33-56739	  99(a)
	 4(s)	Eighteenth Supplemental Indenture	33-56739	  99(b)


		Instruments defining the rights of holders of long-term debt 
which are not required to be filed with the Commission will be 
furnished to the Commission upon request.  

			Incorporation by Reference 
				 Previous
			 Previous	  Exhibit
			  Filing  	Designation

	 4(t)	Rights Agreement dated as of 	33-42882	4(d)
		June 6, 1989, between The 	
		Montana Power Company and First
		Chicago Trust Company of New  
		York, as Rights Agent

	10(a)(i)	Benefit Restoration Plan for 	33-42882	10(a)(i)
		Senior Management Executives	
		and Board of Directors

	10(a)(ii)	Deferred Compensation Plan for	33-42882	10(a)(ii)
		Non-Employee Directors



			Incorporation by Reference

				  Previous
			 Previous	   Exhibit
			  Filing  	Designation

	10(a)(iii)	Long-Term Incentive Stock	1-4566	10(a)(iii)
		Ownership Plan	1992
			Form 10-K

	10(a)(iv)	The Montana Power Company 	33-28096	 4(c)
		Employee Stock Ownership Plan 
		(Revised)

	10(a)(v)	Termination Compensation
		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>
<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, 1995
Reserves deducted
in balance sheet
from assets to
which they apply:
Doubtful accounts
	Utility	$      808	$    1,065		$    1,005	$      868
	Entech	       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
	Entech	       643	       156	$       (9)	       174	       616

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

December 31, 1993
Reserves deducted
in balance sheet
from assets to 
which they apply:
Doubtful accounts
	Utility	$      688	$      764		$      704	$      748
	Entech	       529	       391	$       17	       294	       643

		Total	$    1,217	$    1,155	$       17	$      998	$    1,391
	


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



	SIGNATURES


	Pursuant to the requirements of Section 13 or 15(d) of the Securities 
Exchange Act of 1934, the registrant has duly caused this report to be signed 
on its behalf by the undersigned, thereunto duly authorized.  

THE MONTANA POWER COMPANY




By /s/ Daniel T. Berube       
   Daniel T. Berube 
   (Chairman of the Board)



Date:  March 22, 1996


	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 22, 1996
(Chief Executive Officer)



/s/ J. P. Pederson            	Principal Financial
J. P. Pederson	  and Accounting Officer	March 22, 1996
(Vice President and Chief	  and Director
  Financial Officer)



/s/ 		        	Director	March 22, 1996
Tucker Hart Adams



/s/ Alan F. Cain              	Director	March 22, 1996
Alan F. Cain



/s/ R. D. Corette             	Director	March 22, 1996
R. D. Corette



/s/ Robert P. Gannon          	Director 	March 22, 1996
Robert P. Gannon



/s/ Kay Foster               	Director 	March 22, 1996
Kay Foster



/s/ Beverly D. Harris         	Director	March 22, 1996
Beverly D. Harris



/s/ Chase T. Hibbard          	Director 	March 22, 1996
Chase T. Hibbard



/s/ John R. Jester            	Director 	March 22, 1996
John R. Jester



/s/ Daniel P. Lambros         	Director 	March 22, 1996
Daniel P. Lambros



/s/ Carl Lehrkind, III        	Director	March 22, 1996
Carl Lehrkind, III



/s/ James P. Lucas            	Director 	March 22, 1996
James P. Lucas



/s/ Arthur K. Neill           	Director	March 22, 1996
Arthur K. Neill



/s/ George H. Selover         	Director 	March 22, 1996
George H. Selover



/s/ N. E. Vosburg             	Director	March 22, 1996
N. E. Vosburg



	EXHIBIT INDEX


Exhibit 3(a)(1)
	Articles of Amendment to the Restated Articles of Incorporation

Exhibit 3(b)
	By-laws, as adopted

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

Exhibit 12
	Statement Re Computation of Ratio Earnings to Fixed Charges

Exhibit 21
	Subsidiaries of the Registrant

Exhibit 23
	Consent of Independent Accountants

Exhibit 27
	Financial Data Schedule


 



 

 

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