UNITED STATES 	SECURITIES AND EXCHANGE COMMISSION 	Washington, D.C. 20549 	FORM 10-Q 	________________________________________ (Mark One) (X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended March 31, 1998 	-- OR -- ( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from ______________ to _______________ 	________________________________________ 	Commission file number 1-4566 	THE MONTANA POWER COMPANY 	(Exact name of registrant as specified in its charter) 		 Montana						 81-0170530 	(State or other jurisdiction				 (IRS Employer 		of incorporation)					 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 	________________________________________________________ 	(Former name, former address and former fiscal year, 	if changed since last report.) 	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 the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. 	On May 6, 1998, the Company had 54,969,841 shares of common stock outstanding. 	PART I 	FINANCIAL STATEMENTS 	THE MONTANA POWER COMPANY AND SUBSIDIARIES 	CONSOLIDATED STATEMENT OF INCOME 					For Three Months Ended	 				March 31,	March 31, 					1998			1997	 					Thousands of Dollars	 REVENUES		$	294,102	$	281,370 EXPENSES: 	Operations		128,479	103,784 	Maintenance		19,782	19,275 	Selling, general and administrative		29,367	27,806 	Taxes other than income taxes		25,525	25,094 	Depreciation, depletion and amortization			27,086		22,042 					230,239		198,001 INCOME FROM OPERATIONS		63,863	83,369 INTEREST EXPENSE AND OTHER INCOME: 	Interest		14,504	12,563 	Distributions on mandatorily redeemable preferred 		securities of subsidiary trust			1,373		1,373 	Other (income) deductions-net			(1,729)		(4,817) 				14,148	9,119 	 INCOME TAXES			13,848		28,045 NET INCOME		35,867	46,205 DIVIDENDS ON PREFERRED STOCK			923		923 NET INCOME AVAILABLE FOR COMMON STOCK		$	34,944	$	45,282 AVERAGE NUMBER OF COMMON SHARES OUTSTANDING (000)		54,875	54,634 BASIC EARNINGS PER SHARE OF COMMON STOCK		$	0.64	$	0.83 FULLY DILUTED EARNINGS PER SHARE OF COMMON STOCK		$	0.64	$	0.83 The accompanying notes are an integral part of these statements. THE MONTANA POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEET 	A S S E T S 				March 31,	December 31, 					1998			1997	 					Thousands of Dollars	 PLANT AND PROPERTY IN SERVICE: 		UTILITY PLANT (includes $40,924 and $39,425 			plant under construction) 			Electric		$	1,806,539	$	1,820,280 			Natural gas			384,940		395,918 					2,191,479	2,216,198 		Less - accumulated depreciation and depletion			683,252		684,960 				1,508,227	1,531,238 	NONUTILITY PROPERTY (includes $26,023 and $17,259 		property under construction)	822,377	781,406 	Less - accumulated depreciation and depletion			286,059		260,567 					536,318		520,839 				2,044,545	2,052,077 MISCELLANEOUS INVESTMENTS (at cost): 	Independent power investments		44,455	51,534 	Reclamation fund		47,903	47,312 	Other			37,577		35,619 				129,935	134,465 CURRENT ASSETS: 	Cash and temporary cash investments		25,805	16,706 	Accounts receivable		154,113	126,787 	Materials and supplies (principally at average cost)		40,944	39,471 	Prepayments and other assets		59,250	49,673 	Deferred income taxes			10,587		10,539 				290,699	243,176 DEFERRED CHARGES: 	Advanced coal royalties		17,204	16,698 	Regulatory assets related to income taxes		125,515	122,903 	Regulatory assets - other		150,892	158,573 	Other deferred charges			75,761		73,804 					369,372		371,978 				$	2,834,551	$	2,801,696 The accompanying notes are an integral part of these statements. THE MONTANA POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEET L I A B I L I T I E S 				March 31,	December 31, 					1998			1997	 					Thousands of Dollars	 CAPITALIZATION: 		Common shareholders' equity: 			Common stock (120,000,000 shares 				authorized; 54,921,409 and 				54,728,709 shares issued)		$	698,852	$	694,561 			Retained earnings and other shareholders' equity		352,201	342,973 			Unallocated stock held by trustee for retirement 				savings plan			(25,305)		(25,945) 					1,025,748	1,011,589 		Preferred stock		57,654	57,654 		Company obligated mandatorily redeemable preferred 			securities of subsidiary trust, which holds solely, 			company junior subordinated debentures		65,000	65,000 	Long-term debt			670,516		653,168 				1,818,918	1,787,411 CURRENT LIABILITIES: 	Short-term borrowing		101,482	133,958 	Long-term debt - portion due within one year		63,798	81,659 	Dividends payable		22,730	22,684 	Income taxes		23,242	3,803 	Other taxes		66,334	47,818 	Accounts payable		63,341	77,821 	Interest accrued		15,150	13,836 	Accrued lease payments		7,920 	Other current liabilities			53,492		35,158 				417,489	416,737 DEFERRED CREDITS: 	Deferred income taxes		341,007	340,251 	Investment tax credit		34,786	35,182 	Accrued mining reclamation costs		132,624	131,108 	Other deferred credits			89,727		91,007 					598,144		597,548 CONTINGENCIES AND COMMITMENTS (Notes 2 and 5) 				$	2,834,551	$	2,801,696 The accompanying notes are an integral part of these statements. THE MONTANA POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENT OF CASH FLOWS 					For Three Months Ended	 				March 31,	March 31, 					1998			1997	 					Thousands of Dollars	 NET CASH FLOWS FROM OPERATING ACTIVITIES: 	Net income		$	35,867	$	46,205 	Adjustments to reconcile net income to net cash 		provided by operating activities: 		Depreciation, depletion and amortization		27,086	22,042 		Deferred income taxes		(2,218)	5,152 		Noncash earnings from unconsolidated 			independent power investments.		(1,425)	(2,860) 		Reclamation expensed and paid - net		1,516	2,292 		Deferred stripping expenses and payments - net		48	(887) 		Gains on sales of property		(135)	(4,131) 		Other - net		5,119	5,097 		Changes in other assets and liabilities: 			Accounts receivable		(27,326)	20,432 			Materials and supplies		(1,473)	(591) 			Accounts payable		(14,480)	(5,928) 			Accrued lease payments		7,920	7,920 			Other assets and liabilities			50,564		41,200 		Net cash provided by operating activities			81,063		135,943 NET CASH FLOWS FROM INVESTING ACTIVITIES: 	Capital expenditures		(20,620)	(28,391) 	Reclamation funding		(591)	(1,892) 	Sales of property		2,811	15,442 	Additional investments			(1,958)		(898) 		Net cash used by investing activities			(20,358)		(15,739) NET CASH FLOWS FROM FINANCING ACTIVITIES: 	Dividends paid		(22,847)	(22,775) 	Sales of common stock		4,294	61 	Issuance of long-term debt		2,743	(170) 	Retirement of long-term debt		(3,320)	(44,615) 	Issuance of mandatorily redeemable preferred 		securities of subsidiary trust			(65) 	Net change in short-term borrowing			(32,476)		(59,440) 		Net cash used by financing activities			(51,606)		(127,004) CHANGE IN CASH FLOWS		9,099	(6,800) CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD			16,706		32,404 CASH AND CASH EQUIVALENTS, END OF PERIOD		$	25,805	$	25,604 SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION: 	Cash Paid During Three Months For: 		Income taxes, net of refunds		$ 12,074	$	16,497 		Interest		14,742	9,597 The accompanying notes are an integral part of these statements. </TABLE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 	The accompanying financial statements of the Company for the interim periods ended March 31, 1998 and 1997 are unaudited but, in the opinion of management, reflect all adjustments, consisting only of normal recurring accruals, necessary for a fair statement of the results of operations for those interim periods. The results of operations for the interim periods are not necessarily indicative of the results to be expected for the full year. These financial statements do not contain the detail or footnote disclosure concerning accounting policies and other matters which would be included in full fiscal year financial statements; therefore, they should be read in conjunction with the Company's audited financial statements included in the Company's Annual Report on Form 10-K for the year ended December 31, 1997. 	Certain reclassifications have been made to the prior year amounts to make them comparable to the 1998 presentation. These changes had no impact on previously reported results of operations or shareholders' equity. NOTE 1 -- DEREGULATION AND ASSET DIVESTITURE, AND OTHER REGULATORY MATTERS: The electric and natural gas utility businesses are in transition to competition to provide energy commodity and related services to wholesale and retail customers. In Montana, electric and natural gas restructuring and customer choice legislation was passed by the Montana Legislature and signed into law in 1997. Both the electric and natural gas legislation authorized the issuance of transition bonds, often referred to as securitization. The issuance of transition bonds involves the issuance of a debt instrument which is repaid through, and secured by, a specified component of future revenues, thereby reducing the credit risk of the securities. Although the bonds are expected to be shown as debt on the Consolidated Balance Sheet of the Company, the bonds will be issued by a special purpose entity and will be without recourse to the general credit of the Company. Similarly, the right to receive the revenues pledged to secure the bonds is a specific right of the special purpose entity and not the Company. However, as a wholly owned subsidiary of the Company, revenues of the special purpose entity are expected to be shown as revenues on the Consolidated Statement of Income of the Company. This right to receive revenues will have been transferred to the special purpose entity issuing the bonds and will not be the property of the Company. As a result of such features, the bonds carry a relatively low interest rate and allow the Company, on a consolidated basis, to carry higher debt levels in relation to equity than would otherwise be desirable. A filing requesting authorization to issue up to $65,000,000 in transition bonds related to the natural gas transition costs and bond issuance costs was made to the PSC in November 1997. In April 1998, the PSC approved the issuance of up to $65,000,000 of transition bonds and the Company expects the issuance of approximately $60,000,000 of bonds to occur in the third quarter of this year. On January 5, 1998, Enron Capital & Trade Resources Corp. (Enron) requested court review of the Montana Public Service Commission's (PSC) decision regarding the measure of natural gas transition costs as well as the level of functional separation of the various segments of the Company's natural gas business. This appeal was resolved by settlement in April 1998. 	The legislation provides for choice of electricity supplier for the Company's large customers by July 1, 1998, for pilot programs for residential and small commercial customers by July 1, 1998 and for all customers no later than July 1, 2002. As required by the electric legislation, the Company filed a comprehensive transition plan with the PSC on July 1, 1997. The filing contains the Company's transition plan, including the proposed handling and resolution of transition costs, and addresses other issues required by the legislation. Initial hearings on the filing began April 26, 1998 and the issues involved in the restructuring filing have been separated into three groups. The Company expects the PSC to render a decision on the issues surrounding customer choice for the large industrial group and the pilot programs before July 1998. The Company expects a decision on the remaining issues, including the amount of transition costs, the effect of the sale of the generation assets and the Uniform Systems Benefits Charge, later this year. The PSC will consider the Company's efforts to mitigate transition costs in making its determination. In December 1997, the Company announced that it would offer for sale all of its electric generating facilities in Montana, consisting of 1,157.4 megawatts of capacity from 13 hydroelectric projects and its interests in four coal-fired thermal generating units. In addition, the Company offered for sale its 222 megawatt leasehold interest in Colstrip Unit 4, its power purchase contracts with qualifying facilities and Basin Electric Power Cooperative (Basin), and two power exchange agreements. The sale process began in 1998 with offering memorandums being sent to 30 to 50 potential buyers. In June, the Company expects to receive non- binding preliminary bids from potential buyers. The top bidders, expected to number less than ten, will be short-listed for further negotiations and binding bids. The winning bidder is expected to be selected in mid- to late summer and financial closing will occur as soon as all required legal and regulatory approvals are complete, possibly three months to two years after selection of the winning bidder. The Company intends to proceed with the sale process as tentatively scheduled, however, this divestiture is not a requirement of the restructuring bill as is the case in other states with deregulation legislation and the Company may at any time cease to continue this option. 	Responses to the restructuring legislation and the Company's decision to offer for sale its generations assets include two calls for a special legislative session to amend or repeal the electric restructuring legislation and two proposed ballot issue initiatives. One of the proposed ballot issue initiatives would seek from voters in the November 1998 general election repeal of the electric restructuring legislation. The second would seek approval of law to require the condemnation of the Company's water rights associated with its hydroelectric plants. The first call for a special legislative session was unsuccessful. Such efforts are in the preliminary stages and the Company is unable to predict the outcome of such efforts or any other efforts to modify or repeal the legislation. 	As a result of a three-year rate plan approved by the PSC in 1996, electric rates increased 2.5%, or approximately $9,000,000, effective January 1, 1998. NOTE 2 - CONTINGENCIES: 	 In July 1985, the Federal Energy Regulatory Commission (FERC) issued to the Company a new license for the 180 megawatt Kerr Project (Project) and required the subsequent adoption of conditions to mitigate the impact of Project operations on fish, wildlife and habitat. The Company proposed a consensus plan in June 1990 that was agreed to by the Confederated Salish and Kootenai Tribes (Tribes) and other state and federal resource agencies. In November 1995, the United States Department of Interior (Department) submitted alternative conditions to those stated in the Company's plan. 	On June 25, 1997, FERC approved a mitigation plan, substantially adopting the Department's conditions. The mitigation plan calls for payments totaling approximately $135,000,000 over the 35-year term of the license. The net present value of the total amount, using an assumed discount rate of 9.5%, is approximately $57,000,000, which the Company recognized as license costs in plant and long-term debt in the Consolidated Balance Sheet during the second quarter of 1997. The Company, the Tribes and the Department requested rehearing of FERC's June 25, 1997 order. The Company asserted that the Department's conditions are unreasonable and that FERC should modify them. In the event FERC does not modify the mitigation plan it ordered, the Company expects to seek judicial review. In November 1992, the Company applied to FERC to relicense nine Madison and Missouri River hydroelectric projects, with generating capacity of 292 megawatts. On September 26, 1997, FERC Staff issued its draft environmental impact statement, recommending acceptance of most of the measures proposed by the Company in its application. FERC Staff recommended adoption of limited additional measures. The Company has analyzed the recommendations and submitted comments. The analysis indicates that the FERC Staff's recommendations do not materially change the cost of relicensing and proposed environmental mitigation, previously estimated to be approximately $162,000,000 on a net present value basis. The Company expects to receive a license order in late 1999 or early 2000. 	Western Energy Company (Western), a subsidiary of the Company, is a party in a dispute concerning the Coal Supply Agreement for Colstrip Units 3 and 4 with the non-operating owners (NOOs), other than Puget Sound Energy (Puget). Puget withdrew from this dispute as part of a settlement concerning a power sales agreement between Puget and the Company. During the spring of 1996, the Consumer Price Index (CPI) doubled when compared to the CPI level at the time that the Coal Supply Agreement was executed. Under the terms of the Coal Supply Agreement, this change in the CPI allows any party to seek a modification of the coal price if that party can demonstrate an "unusual condition" causing a "gross inequity." These NOOs are asserting that a number of "unusual conditions" have occurred, including (i) the deregulation of various aspects of the electric utility industry, (ii) increased scrutiny of electric utilities by their public utility commissions, and (iii) changes in economic conditions not anticipated at the time of execution of the Coal Supply Agreement. These NOOs claim these "unusual conditions" have created a "gross inequity" that must be remedied by a reduction in the coal price. Western does not believe that under the terms of the contract any "unusual condition" or "gross inequity" has occurred. Western, the Company and these NOOs are seeking to resolve this dispute as part of an on-going mediation to restructure the relationship of the NOOs, including Puget, the Company and Western at the Colstrip Project. The outcome of this dispute or the restructuring mediation is uncertain. Houston Lighting & Power (HL&P), the purchaser of lignite produced by Northwestern Resources Co. (Northwestern), a Company subsidiary, filed litigation on October 5, 1995 in the District Court of the 157th Judicial District, Harris County, Texas, seeking, among other remedies, a declaratory judgment that changed conditions required a renegotiation of management and dedication fees paid to Northwestern under the terms of the Lignite Supply Agreement (LSA) between it and Northwestern. The LSA governs the delivery of approximately 9,000,000 tons of lignite per year and is effective until July 29, 2015. Under the terms of the LSA, Northwestern realizes approximately $25,000,000 per year from these fees. HL&P alleged Northwestern failed to renegotiate these fees in good faith. HL&P sought a reduction exceeding 60% in the LSA fees. It alleged that the reduction should be retroactive to September 1, 1995. Additionally, HL&P sought a declaration that it may substitute other fuels for lignite without violating the LSA. Trial concluded in December 1997 with the jury denying all of HL&P's claims regarding changed circumstances and Northwestern's alleged obligations to negotiate reduced fees. Thus, current pricing under the terms of the LSA is unchanged. In a pretrial summary judgment, the trial court concluded other fuel may be substituted for lignite at the Limestone Plant. Northwestern intends to appeal this summary judgment. Northwestern believes it will maintain a price for lignite that is competitive with alternate fuels. 	The Company and its subsidiaries are party to various other legal claims, actions and complaints arising in the ordinary course of business. Management does not expect disposition of these matters to have a material adverse effect on the Company's consolidated financial position or its consolidated results of operations. NOTE 3 - DERIVATIVE FINANCIAL INSTRUMENTS: The Company has a formal policy regarding the execution, recording and reporting of derivative instruments. The purpose of the policy is to manage a portion of the price risk associated with its Nonutility producing assets, firm-supply commitments and natural gas transportation agreements. The Company uses derivatives as hedging instruments to achieve earnings targets, reduce earnings volatility and provide more stablized cash flows. When fluctuations in natural gas and crude oil market prices result in the Company realizing gains on the derivative instruments into which it has entered, the Company is exposed to credit risk relating to the nonperformance by counterparties of their obligation to make payments under the agreements. Such risk to the Company is mitigated by the fact that the counterparties, or the parent companies of such counterparties, are investment grade financial institutions. The Company does not anticipate any material impact to its financial position, results of operations or cash flow as a result of nonperformance by counterparties. To manage a portion of Nonutility price risk, the Company uses a variety of derivative instruments including crude oil and natural gas swap and option agreements to hedge revenue from anticipated production of crude oil and natural gas reserves, supply costs and transportation commitments to its firm markets. Under swap agreements, the Company receives or makes payments based on the differential between a specified price and a variable price of oil or natural gas when the hedged transaction is settled. The variable price is either a crude oil or natural gas price quoted on the New York Mercantile Exchange or a quoted natural gas price in Inside FERC's Gas Market Report or other recognized industry index. These variable prices are highly correlated with the market prices received by the Company for its natural gas and crude oil production or paid by the Company for commodity purchases. Under option agreements, the Company makes or receives monthly payments at the settlement date based on the differential between the actual price of oil or natural gas and the price established in the agreement depending on whether the Company sells or buys the option. At March 31, 1998, the Company had no hedge agreements on crude oil. The Company had swap and option agreements on approximately 0.46 Bcf of Nonutility natural gas, or 5% of its expected production from proved, developed and producing Nonutility natural gas reserves through October 1998. The Company had swap and option agreements to hedge approximately 3.4 Bcf of Nonutility natural gas, or 26% of its expected delivery obligations under long-term natural gas sales contracts through March 1999. In addition, the Company had swap and option agreements to hedge approximately 1.8 Bcf, or 4%, of its Nonutility natural gas pipeline transportation obligations under contracts through October 1999. The Company accounts for derivative transactions through hedge accounting. The Company designates all its derivatives as fair value hedges. A fair value hedge is based on the following criteria: ? The hedged item is specifically identified as a recognized asset or a firm commitment. ? The hedged item is a single asset or a portfolio of similar assets. ? The hedged item presents an exposure to changes in fair value for the hedged risk that could affect earnings. ? The hedged item is not an asset or liability that is measured at fair value with changes in fair value attributable to the hedged risk reported currently in earnings. Gains or losses from these derivative instruments are reflected in operating revenues on the Consolidated Statement of Income at the same time as the recognition of the revenue or expense associated with the underlying hedged item. If the Company determines that any portion of the underlying hedged item will not be produced or purchased, the unmatched portion of the instrument is marked-to-market and any gain or loss is recognized in the Consolidated Statement of Income. If the Company terminates a hedging instrument prior to the date of the anticipated natural gas or crude oil production, commodity purchase or transportation commitment, the gain or loss from the agreement is deferred in the Consolidated Balance Sheet at the termination date. At March 31, 1998, the Company had no material deferred gains or losses related to these transactions. 	The Company also has investments in independent power partnerships, some of which have entered into derivative financial instruments to hedge against interest rate exposure on floating rate debt and foreign currency and natural gas price fluctuations. At March 31, 1998, the Company believes it would not experience any materially adverse impacts from the risks inherent in these instruments. NOTE 4 - COMPANY OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY TRUST: 	Montana Power Capital I (Trust) was established as a wholly owned business trust of the Company for the purpose of issuing common and preferred securities (Trust Securities) and holding Junior Subordinated Deferrable Interest Debentures (Subordinated Debentures) issued by the Company. The Trust has issued 2,600,000 units of 8.45% Cumulative Quarterly Income Preferred Securities, Series A (QUIPS). Holders of the QUIPS are entitled to receive quarterly distributions at an annual rate of 8.45% of the liquidation preference value of $25 per security. The sole asset of the Trust is $67,000,000 of Subordinated Debentures, 8.45% Series due 2036, issued by the Company. The Trust will use interest payments received on the Subordinated Debentures it holds to make the quarterly cash distributions on the QUIPS. NOTE 5 - COMMITMENTS: The Montana Power Group (MPG), an energy supply and management alliance, was exclusively endorsed by the California Manufacturers Association (CMA) to assist its members with their energy decisions. As a participant in the MPG, Montana Power Trading and Marketing Company (MPT&M), a Nonutility subsidiary of the Company has agreed to offer energy supply, discounted from the power exchange prices, and energy management products and services to members of the CMA. The supply program is offered on a limited basis and is capped at predetermined volumes. Once the caps are fully subscribed, the Company will have, at its sole discretion, the option to extend the offered supply and services to other CMA members. At March 31, 1998, three contracts had been signed by the Company for electric supply for the next two years with service beginning April 1, 1998. At this time, the Company cannot predict the impact of the CMA agreement on future earnings, however, due to the limits provided in the agreement, any potential negative impacts are not expected to have a material impact on the Company's financial position or results of operations. NOTE 6 - LONG-TERM DEBT On January 2, 1998, the Company used short term borrowings to retire $16,000,000 in sinking fund debentures. 	On April 6, 1998, the Company issued $60,000,000 of floating rate Medium Term Notes, Series B, due April 6 2001, the proceeds of which were used to reduce outstanding debt. NOTE 7 - COMPREHENSIVE INCOME 	During June 1997, the Financial Accounting Standards Board (FASB) released SFAS No. 130, "Reporting Comprehensive Income". SFAS No. 130 requires the reporting in the financial statements of all items recognized as components of comprehensive income which is defined as changes in equity during the period from transactions, events or circumstances from non-owner sources. The statement is effective for fiscal years beginning after December 15, 1997. During the three-month periods ended March 31, 1998 and 1997, the Company's components included adjustments of $3,900,000 and $771,000, respectively, to retained earnings for the foreign currency translation adjustments. The 1998 adjustment results not only from the change in the valuation of the assets of the Company's Canadian operations, but also a change in the rate used to adjust certain Canadian assets. Until November 1, 1997, the plant of the Company's natural gas utility operations, owned by a wholly owned subsidiary, were included in natural gas utility rate base. As such, the Company earned a rate of return on these assets stated at their historical costs, converted to U.S. dollars using historical foreign currency exchange rates. When the assets were transferred from the Company's regulated operations to the unregulated operations, and removed from utility rate base, they were converted to U.S. dollars using current foreign currency exchange rates which resulted in a decrease of approximately $5,100,000 in retained earnings in 1998. ITEM 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 	This discussion should be read in conjunction with the management's discussion included in the Company's Annual Report on Form 10-K for the year ended December 31, 1997. Safe Harbor for Forward-Looking Statements: 	The Company is including the following cautionary statements to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of, the Company in this Quarterly Report on Form 10-Q. Forward-looking statements include statements concerning plans, objectives, goals, strategies, future events or performance and underlying assumptions and other statements which are other than statements of historical facts. Such forward-looking statements may be identified, without limitation, by the use of the words "anticipates", "estimates", "expects", "intends", "believes" and similar expressions. From time to time, the Company or one of its subsidiaries individually may publish or otherwise make available forward-looking statements of this nature. All such forward-looking statements, whether written or oral, and whether made by, or on behalf of, the Company or its subsidiaries, are expressly qualified by these cautionary statements and any other cautionary statements which may accompany the forward-looking statements. In addition, the Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date hereof. 	Forward-looking statements made by the Company are subject to risks and uncertainties that could cause actual results or events to differ materially from those expressed in, or implied by, the forward-looking statements. These forward-looking statements include, among others, statements concerning the Company's revenue and cost trends, cost recovery, cost-reduction strategies and anticipated outcomes, pricing strategies, planned capital expenditures, financing needs, and availability and changes in the utility industry. Investors or other users of the forward-looking statements are cautioned that such statements are not a guarantee of future performance by the Company and that such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in, or implied by, such statements. Some, but not all, of the risks and uncertainties include general economic and weather conditions in the areas in which the Company has operations, competitive factors and the impact of restructuring initiatives in the electric and natural gas industry, market prices, environmental laws and policies, federal and state regulatory and legislative actions, drilling successes in oil and natural gas operations, changes in foreign trade and monetary policies, laws and regulations related to foreign operations, tax rates and policies, rates of interest and changes in accounting principles or the application of such principles to the Company. Results of Operations: 	The following discussion presents significant events or trends that have had an effect on the operations of the Company or which are expected to have an impact on operating results in the future. For the Quarters Ended March 31, 1998 and 1997: Net Income Per Share of Common Stock: The Montana Power Company had consolidated net income of $0.64 per share for the quarter ended March 31, 1998, compared to first-quarter earnings of $0.83 per share a year earlier. For the quarter, Utility earnings were 34 cents a share compared to 52 cents in the first quarter of 1997. Nonutility earnings were 30 cents a share compared to 31 cents a year earlier. The Utility was adversely affected by winter's El Nino weather patterns, which had a compound effect in the Company's Montana service territory. First, winter weather in the primary heating months of January and February was 9 percent warmer than normal, reducing the natural gas utility's earnings by 4 cents per share. And because normal winter moisture was pushed further south, there was a significant reduction in hydro-electric generation capability. 	 The combination of reduced hydro output and commencement of a long-term seasonal power-purchase agreement reduced the electric utility's performance by 9 cents per share. A timing difference on natural gas utility restructuring costs reduced net income by 4 cents a share. The earnings improvements by Touch America nearly offset the impact of an $8.2 million (15 cents per share) decrease in Nonutility income resulting primarily from reduced volumes and prices for oil and natural gas as well as 5 cents from a non-recurring asset sale. 	For comparative purposes, the following table shows the breakdown of consolidated net income per share by principal business segment. 	Quarter Ended 	March 31,	March 31, 		1998		1997	 	Utility Operations	$	0.34	$	0.52 	Nonutility Operations		0.30		0.31 		Consolidated	$	0.64	$	0.83 UTILITY OPERATIONS 					For Three Months Ended	 				March 31,	March 31, 					1998			1997	 					Thousands of Dollars	 ELECTRIC UTILITY: REVENUES: 	Revenues		$	116,798	$	122,008 	Intersegment revenues			996		1,337 				117,794	123,345 EXPENSES: 	Power supply		39,967	35,845 	Transmission and distribution		8,584	9,317 	Selling, general and administrative		13,316	13,510 	Taxes other than income taxes		12,097	12,829 	Depreciation and amortization			13,185		12,756 					87,149		84,257 	INCOME FROM ELECTRIC OPERATIONS		30,645	39,088 NATURAL GAS UTILITY: REVENUES: 	Revenues (other than gas supply cost revenues)		26,666	40,228 	Gas supply cost revenues		14,378	6,852 	Intersegment revenues			130		233 				41,174	47,313 EXPENSES: 	Gas supply costs		14,378	6,852 	Other production, gathering and exploration		645	2,533 	Transmission and distribution		3,635	3,487 	Selling, general and administrative		4,558	4,263 	Taxes other than income taxes		3,372	4,254 	Depreciation, depletion and amortization			2,204		3,128 					28,792		24,517 	INCOME FROM NATURAL GAS OPERATIONS		12,382	22,796 INTEREST EXPENSE AND OTHER INCOME: 	Interest		13,445	12,138 	Distributions on mandatorily redeemable preferred 		securities of subsidiary trust			1,373		1,373 	Other (income) deductions - net			(116)		(755) 					14,702		12,756 INCOME BEFORE INCOME TAXES		28,325	49,128 INCOME TAXES			8,456		20,209 DIVIDENDS ON PREFERRED STOCK			923		923 UTILITY NET INCOME AVAILABLE FOR COMMON STOCK		$	18,946	$	27,996 UTILITY OPERATIONS: 	Weather affects the demand for electricity and natural gas, especially among residential and commercial customers. Very cold winters increase demand, while mild weather reduces demand. The weather's effect is measured using degree-days. A degree-day is the difference between the average daily actual temperature and a baseline temperature of 65 degrees. Heating degree-days result when the average daily actual temperature is less than the baseline. As measured by heating degree days, the temperatures for the first quarter of 1998 in the Company's service territory were 5% warmer than 1997 and 6% warmer than the historic average. In addition, winter weather for the primary heating months of January and February was 9% warmer than normal. 	See Note 1 - Deregulation and Asset Divestiture, and Other Regulatory Matters in the Notes to the Consolidated Financial Statements for a description of the transition in the electric and natural gas utility business to competition. 	For its regulated operations, the Company follows SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." Pursuant to this pronouncement, certain expenses and credits, normally reflected in income as incurred, are recognized when included in rates and recovered from or refunded to the customers. Changes in regulation or changes in the competitive environment could result in the Company not meeting the criteria of SFAS No. 71. If the Company were to discontinue application of SFAS No. 71 for some or all of its operations, the regulatory assets and liabilities related to those portions would have to be eliminated from the balance sheet and included in income in the period when the discontinuation occurred unless recovery of those costs was provided through rates charged to those customers in a portion of the business that remains regulated. In conjunction with the ongoing changes in the electric industry, the Company will continue to evaluate the applicability of this accounting principle to that business. Based upon the Company's anticipated recovery of its regulatory assets in accordance with the electric restructuring legislation, the Company believes that the discontinuation of regulatory accounting for these generation assets will not have a material impact on the Company's financial position or results of operations. 	The Company has existing long-term contracts for the purchase and sale of electricity that have fixed price components. To the extent that these contracts are not addressed in the restructuring docket, the Company would become subject to the commodity price risks associated with meeting these obligations. Electric Utility: 	Revenues and 	 Power Supply Expenses	Volumes	Customers	 	(Thousands of Dollars)	(Thousands of MWh)	(Quarterly Average) 		3/31/98	3/31/97		3/31/98	3/31/97	3/31/98	3/31/97 Revenues:										 Residential, 	Commercial and 	Government	$	74,488	$ 76,008	(2)%	1,131	1,168	(3)%	279,473	275,342	2 % Industrial		28,567	26,320	9 %	656	603	9 %	2,340	2,334	0 % 	General Business	103,055	102,328	1 %	1,787	1,771	1 %	281,813	277,676	1 % Sales to Other									 	Utilities	9,335	15,973	(42)%	437	898	(51)%	84	84	0 % Other	4,408	3,707	19 %				 Intersegment		996	1,337	(26)%	21	46	(54)%	231	228	1 % 	Total		$117,794	$123,345	(5)%	2,245	2,715	(17)%	282,128	277,988	1 % Power Supply 	Expenses: Hydroelectric	$	5,664	$	5,385	5 %	818	1,083	(24)% Steam 	11,708	12,280	(5)%	1,022	1,040	(2)% Purchases 	and Other		22,595	18,180	24 %	795	847	(6)% 	Total Power Supply	$	39,967	$	35,845	11 %	2,635	2,970	(11)% Cents Per kWh		$1.517	$1.207 Revenues from general business customers increased slightly in the first quarter of 1998 as a result of increased rates and customer growth. Warmer weather for the period partially offset these increases. Decreased hydroelectric generation resulting from reduced winter moisture as well as scheduled maintenance and other generator repairs at the Corette thermal plant resulted in decreased sales to other utilities. The Corette plant was off- line from December 1997 through mid-April 1998 and is expected to be taken off-line for further maintenance from mid-May through mid-June 1998. The combination of reduced electric generation and the commencement of a long-term seasonal power-purchase agreement in January 1998 resulted in increased purchase power costs. Higher qualifying facility rates also contributed to the increase. Natural Gas Utility: 		Revenues	Volumes	Customers	 	(Thousands of Dollars)	(Thousands of Mmcf)	(Quarterly Average) 		3/31/98	3/31/97		3/31/98	3/31/97	3/31/98	3/31/97 Revenues:										 Residential, 	Commercial and 	Government	$ 35,880	$ 41,681	(14)%	8,115	9,380	(13)%	145,243	141,197	3 % Industrial		642	1,020	(37)%	151	238	(37)%	399	426	(6)% 	Subtotal		36,522	42,701	(14)%	8,266	9,618	(14)%	145,642	141,623	3 % Gas Supply Cost						 	Revenues (GSC)		(14,378)	(6,852)	(110)%						 	General Business						 	without GSC	22,144	35,849	(38)%	8,266	9,618	(14)%	145,642	141,623	3 % Sales to Other						 	Utilities	250	353	(29)%	94	114	(18)%	3	3	0 % Transportation	3,102	2,545	22 %	6,953	7,607	(9)%	21	33	(36)% Other		1,170	1,481	(21)%						 	Total		$	26,666	$ 40,228	(34)%	15,313	17,339	(12)%	145,666	141,659	3 % Sales volume decreases due to warmer winter weather, partially offset by customer growth, resulted in decreased revenues in the first quarter of 1998. The restructuring of the natural gas utility also affected its operating results for the period. In November 1997, almost all of the Company's regulated natural gas production assets were transferred to its Nonutility affiliate, MP Gas. Since that time, operating expenses related to the transferred assets have been included in the Company's Nonutility oil and natural gas operations. The absence of these expenses in the Utility's natural gas operations resulted in reduced non-gas supply cost revenues and expenses in the first quarter of 1998. Timing differences between reductions in non-gas supply cost accruals and corresponding reductions in consumption-based revenues caused a decrease in operating income. 	As part of the restructuring mentioned above, the Utility is no longer producing most of its natural gas, but has contracted to purchase gas from its Nonutility affiliate. The contract price includes costs associated with the transferred assets and returns on those assets. Gas cost revenues and expenses, which are always equal due to regulated rate and accounting procedures, increased in the first quarter of 1998 due to the new purchase contract. Amortizations of prior period under-collections also contributed to the increase. Other Income and Expense: 	Increases in interest expense in the first quarter of 1998 due to increased short-term borrowing and the mid-1997 recognition of the Kerr Project mitigation liability were partially offset by decreases related to retirements of long-term debt in the first and fourth quarters of 1998 and 1997, respectively. 	Income taxes decreased in the first quarter of 1998 due to lower before- tax net income and a reduced effective tax rate. NONUTILTY OPERATIONS 					For Three Months Ended	 				March 31,	March 31, 					1998			1997	 					Thousands of Dollars	 COAL: REVENUES: 	Revenues		$	43,426	$	42,371 	Intersegment revenues			10,198		8,079 				53,624	50,450 EXPENSES: 	Operations and maintenance			31,765	29,708 	Selling, general and administrative			5,052	4,939 	Taxes other than income taxes			6,689	5,819 	Depreciation, depletion and amortization			2,736		1,166 						46,242		41,632 		INCOME FROM COAL OPERATIONS		7,382	8,818 OIL AND NATURAL GAS: REVENUES: 	Revenues		23,546	42,356 	Intersegment revenues			4,746		106 						28,292	42,462 EXPENSES: 	Operations and maintenance		16,514	24,469 	Selling, general and administrative		3,483	2,250 	Taxes other than income taxes		1,351	1,560 	Depreciation, depletion and amortization			5,377		4,300 							26,725		32,579 	INCOME FROM OIL AND NATURAL GAS OPERATIONS		1,567	9,883 INDEPENDENT POWER: REVENUES: 	Revenues		18,576	17,198 	Earnings from unconsolidated investments		1,553	3,025 	Intersegment revenues			569		817 						20,698	21,040 EXPENSES: 	Operations and maintenance		18,673	15,904 	Selling, general and administrative		974	1,089 	Taxes other than income taxes		466	495 	Depreciation, depletion and amortization			919		305 							21,032		17,793 	INCOME (LOSS) FROM INDEPENDENT POWER OPERATIONS		$	(334)	$	3,247 NONUTILITY OPERATIONS (continued) 					For Three Months Ended	 				March 31,	March 31, 					1998			1997	 					Thousands of Dollars	 TELECOMMUNICATIONS: REVENUES: 	Revenues		$	20,382	$	6,981 	Earnings from unconsolidated investments		2,080	23 	Intersegment revenues			251		181 						22,713	7,185 EXPENSES: 	Operations and maintenance		5,947	4,835 	Selling, general and administrative		2,207	1,635 	Taxes other than income taxes		1,245	136 	Depreciation, depletion and amortization			1,532		254 						10,931		6,860 	INCOME FROM TELECOMMUNICATIONS OPERATIONS		11,782	325 OTHER OPERATIONS: REVENUES: 	Revenues		26,616	252 	Intersegment revenues			345		290 						26,961	542 EXPENSES: 	Operations and maintenance		24,103	218 	Selling, general and administrative		982	980 	Taxes other than income taxes		304 	Depreciation, depletion and amortization			1,133		133 					26,522		1,331 	INCOME (LOSS) FROM OTHER OPERATIONS		439	(789) INTEREST EXPENSE AND OTHER INCOME: 	Interest		2,229	1,112 	Other (income) deductions - net			(2,783)		(4,750) 						(554)		(3,638) INCOME BEFORE INCOME TAXES		21,390	25,122 INCOME TAXES			5,392		7,836 NONUTILITY NET INCOME AVAILABLE FOR COMMON STOCK		$	15,998	$	17,286 		This table was included as an exhibit to a Current Report on Form 8-K, dated April 23, 1998, filed with the Securities and Exchange Commission. The information has been revised from that included in such Form 8-K to eliminate the material intersegment sales and expenses which are not arm's length transactions. These revisions had no effect on the previously reported consolidated net income or the income from operations of any of the segments. NONUTILITY OPERATIONS: Coal Operations: Income from coal operations decreased compared to a year ago first quarter. Revenues from the Rosebud Mine increased $3,500,000. Volume of coal sold to the Colstrip Units in 1998 increased 29% which was partially offset by a price reduction resulting from the settlement of a dispute with Puget and a short-term contract modification with certain other Colstrip partners. Revenues from the Jewett mine decreased $1,000,000 as a result of a 22% decrease in volumes of lignite sold due to generating plants being shut down for repairs. 	Operation and maintenance expense, taxes other than income taxes and depreciation, depletion and amortization increased primarily due to increased volumes at the Rosebud mine and increased stripping costs at the Jewett mine. Oil and Natural Gas Operations: 	The following table shows changes from the previous year, in millions of dollars, in the various classifications of revenue and the related percentage changes in volumes sold and prices received: 	Oil 	-revenue	$ (5) 		-volume	 (45)% 		-price/bbl	 (37)% 	Natural gas	-revenue	$ (11) 		-volume	 (17)% 		-price/Mcf	 (19)% 	Miscellaneous		$ 2 	Income from oil and natural gas operations decreased due to lower market prices in the first quarter of 1998 and accounting changes in the Company. Revenues from oil operations decreased from lower prices and due to the sale of production properties in conjunction with the Company's increased emphasis on its natural gas operations. Natural gas revenues decreased due to lower prices and a change in the accounting for the natural gas marketing activities from oil and gas operations to Montana Power Trading and Marketing Company (MPT&M), which is included in other operations. Effective January 1, 1998, with the exception of gas sold to supply long-term contracts to co-generators, substantially all market purchases of natural gas and their subsequent resale are now recorded on the books of MPT&M. These decreases in revenue were partially offset by the sale of production from the Vessels properties acquired in the second quarter of 1997 and from formerly regulated gas production assets transferred to oil and natural gas operations in the fourth quarter of 1997. Miscellaneous revenues increased primarily as a result of increased processing and gathering revenues. 	Operation and maintenance expense decreased due to lower gas purchase costs resulting from the accounting change for marketing activities discussed above. This decrease was partially offset by expenses of operating the Vessels properties and transferred regulated assets. These new operations also accounted for the increases in selling, general and administrative and depreciation, depletion and amortization expenses. Independent Power Operations: 	Net income from independent power operations for the first quarter 1998 decreased primarily as a result of a $2,800,000 increase in operations and maintenance expense. Increased project development costs of $2,300,000 due to a new domestic investment opportunity combined with higher power supply expense of $970,000 contributed to the increase. Slightly offsetting the increase was a decrease in purchase power expense of $570,000. During the first quarter of 1998, the Colstrip plant generated more energy than in the first quarter of 1997 due to increased long-term power sales volumes and a stronger market. 	Earnings from unconsolidated investments decreased $1,700,000 due to costs associated with refinancing an existing project. The decrease was offset by a $1,460,000 increase in revenues from long-term power sales resulting from an increase in volumes sold. Telecommunications Operations: 	Revenues from telecommunications operations increased primarily due to revenues on its Washington to Minnesota, Colorado to Canada fiber optic network and a 36% higher volume of long-distance minutes sold. Revenues from the additional fiber optic network did not begin until the third quarter of 1997. Telecommunications operations has a one-third interest in a limited liability company which made sales in the first quarter on a Portland to Los Angeles fiber optic network currently under construction. These sales account for the $2,000,000 increase in earnings from unconsolidated investment. 	Expenses for the first quarter were higher due to the operation of the Washington to Minnesota, Colorado to Canada fiber optic network mentioned above. Other Operations: Revenues and expenses in other operations include primarily the activities of MPT&M. In addition to the natural gas marketing activities discussed in oil and gas operations above, MPT&M is also recording on its books the purchase and resale of any electricity which does not utilize the Utility's electric system. Natural gas revenues were approximately $25,000,000 and the corresponding gas purchase expense was approximately $22,000,000. Interest Expense and Other Income: 	Interest expense increased primarily due to increases in the amount of outstanding borrowings to provide short-term financing for the Company's expansion of telecommunications and oil and natural gas operations. Other (income) and deductions - net decreased due to a $4,200,000 gain realized on dispositions of oil and natural gas properties in the first quarter of 1997. This gain was partially offset by increased costs associated with a discontinued project. LIQUIDITY AND CAPITAL RESOURCES: Operating Activities -- Net cash provided by operating activities was $81,063,000 during the period compared to $135,943,000 in the first quarter 1997. The current year decrease of $54,880,000 was due primarily to decreased Utility revenues during December 1997 and January and February of 1998 compared to the same period last year and construction costs incurred which will be reimbursed in future periods. Investing Activities -- 	Net cash used for investing activities was $20,358,000 during the period compared to $15,739,000 in the first quarter 1997. The current year increase of $4,619,000 was due primarily to the decrease in property sales in 1998, partially offset by a decrease in capital expenditures. 	Forecasted capital expenditures for 1998 are as follows: 			Forecasted	 			1998 		Thousands of Dollars 	Utility		$	77,000	 	Nonutility		174,000	 	Total	$	251,000	 Financing Activities -- On January 2, 1998, the Company used short term borrowings to retire $16,000,000 in sinking fund debentures. 	On April 6, 1998, the Company issued $60,000,000 of floating rate Medium Term Notes, Series B, due April 6 2001, the proceeds of which were used to reduce outstanding debt. The Company's consolidated borrowing ability under its Revolving Credit and Term Loan Agreements was $160,000,000, of which $65,000,000 was unused at March 31, 1998. SEC RATIO OF EARNINGS TO FIXED CHARGES: 	For the twelve months ended March 31, 1998, the Company's ratio of earnings to fixed charges was 2.71 times. Fixed charges include interest, distributions on preferred securities of a subsidiary trust, the implicit interest of the Colstrip Unit 4 rentals and one-third of all other rental payments. NEW ACCOUNTING PRONOUNCEMENT: 	During February 1998, the FASB issued SFAS No. 132, "Employers' Disclosures about Pensions and Other Postretirement Benefits". SFAS No. 132 revises employers' disclosures about pension and other postretirement plans currently provided under the provisions of SFAS Nos. 87, 88 and 106. Although the statement will affect the presentation of the information, it does not change the measurement or recognition of those plans, and therefore it will not affect the Company's financial position or results of operations. The statement is effective for fiscal years beginning after December 15, 1997. 	 PART II OTHER INFORMATION ITEM 1.	Legal Proceedings Houston Power & Light Lignite Sales Agreement Dispute Refer to Part 1, "Notes to the Consolidated Financial Statements - Note 2" for additional information pertaining to legal proceedings. ITEM 6.	Exhibits and Reports on Form 8-K: 	(a)	Exhibits 	Exhibit 12		Computation of ratio of earnings to fixed charges for the twelve months ended March 31, 1998. 	Exhibit 27			Financial data schedule 	(b)	Reports on Form 8-K 		DATE			SUBJECT	 	January 27,1998		Item 5 Other Events. Discussion of Fourth 			Quarter Net Income. 			Item 7 Exhibits. Preliminary Consolidated Statements of Income for the Quarters Ended December 31, 1997 and 1996 and for the Years Ended December 31, 1997 and 1996. Preliminary Utility Operations Schedule of Revenues and Expenses for the Quarters Ended December 31, 1997 and 1996 and for the Years Ended December 31, 1997 and 1996. Preliminary Nonutility Operations Schedule of Revenues and Expenses for the Quarters Ended December 31, 1997 and 1996 and for the Years Ended December 31, 1997 and 1996. SIGNATURES 	Pursuant to the requirements 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	 		(Registrant) 	By	/s/ J. P. Pederson	 		J. P. Pederson Vice President and Chief Financial and Information Officer Dated: May 14, 1998