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, 2000 - -- 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) 497-3000 ________________________________________________________ (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 9, 2000, the Company had 105,572,301 shares of common stock outstanding. PART I ITEM 1 - FINANCIAL STATEMENTS THE MONTANA POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENT OF INCOME For Three Months Ended March 31, March 31, 2000 1999 (Thousands of Dollars) REVENUES $ 364,864 $ 321,768 EXPENSES: Operations 206,693 153,560 Maintenance 17,276 19,630 Selling, general, and administrative 36,928 33,143 Taxes other than income taxes 26,331 25,768 Depreciation, depletion, and amortization 25,105 27,754 312,333 259,855 INCOME FROM OPERATIONS 52,531 61,913 INTEREST EXPENSE AND OTHER INCOME: Interest 11,390 13,629 Distributions on mandatorily redeemable Preferred securities of subsidiary trusts 1,373 1,373 Other (income) deductions - net (8,343) (3,869) 4,420 11,133 INCOME TAXES 16,832 16,956 NET INCOME 31,279 33,824 DIVIDENDS ON PREFERRED STOCK 923 923 NET INCOME AVAILABLE FOR COMMON STOCK $ 30,356 $ 32,901 AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - BASIC (000) 105,552 110,146 BASIC EARNINGS PER SHARE OF COMMON STOCK $ 0.29 $ 0.30 AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - DILUTED (000) 107,041 110,799 DILUTED EARNINGS PER SHARE OF COMMON STOCK $ 0.28 $ 0.30 <FN> The accompanying notes are an integral part of these financial statements. THE MONTANA POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEET A S S E T S March 31, December 31, 2000 1999 (Thousands of Dollars) PLANT AND PROPERTY IN SERVICE: UTILITY PLANT (includes $5,950 and $3,782 Plant under construction) Electric $ 1,054,545 $ 1,050,344 Natural gas 413,546 416,383 1,468,091 1,466,727 Less - accumulated depreciation and depletion 475,726 464,653 992,365 1,002,074 NONUTILITY PROPERTY (includes $125,329 and $134,817 Property under construction) 1,112,941 1,051,997 Less - accumulated depreciation and depletion 395,435 349,045 717,506 702,952 1,709,871 1,705,026 MISCELLANEOUS INVESTMENTS: Independent power investments 22,658 23,460 Reclamation fund 44,037 43,460 Other 95,673 93,231 162,368 160,151 CURRENT ASSETS: Cash and cash equivalents 417,218 554,407 Temporary investments 32,677 40,417 Accounts receivable, net of allowance for doubtful accounts 190,042 182,248 Materials and supplies (principally at average cost) 36,772 37,928 Prepayments and other assets 75,554 53,733 Deferred income taxes 19,017 18,303 771,280 887,036 DEFERRED CHARGES: Advanced coal royalties 12,280 12,506 Regulatory assets related to income taxes 60,539 60,538 Regulatory assets - other 149,302 150,486 Other deferred charges 42,554 73,000 264,675 296,530 $ 2,908,194 $3,048,743 <FN> The accompanying notes are an integral part of these financial 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, 2000 1999 (Thousands of Dollars) CAPITALIZATION: Common shareholders' equity: Common stock (240,000,000 shares without par value authorized; 110,241,951 and 110,218,973 shares issued) $ 703,153 $ 702,773 Treasury stock (4,682,100 shares authorized, issued, and repurchased by the Company) (144,872) (144,872) Unallocated stock held by trustee for Retirement Savings Plan (19,573) (20,401) Retained earnings and other shareholders' equity 500,596 488,975 Accumulated other comprehensive loss (18,547) (17,659) 1,020,757 1,008,816 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 601,236 618,512 1,744,647 1,749,982 CURRENT LIABILITIES: Long-term debt - portion due within one year 39,854 58,955 Dividends payable 18,908 22,746 Income taxes 40,918 152,739 Other taxes 72,319 54,630 Accounts payable 129,826 115,654 Interest accrued 11,702 11,597 Other current liabilities 96,316 92,277 409,843 508,598 DEFERRED CREDITS: Deferred income taxes 18,755 8,847 Investment tax credits 13,211 13,330 Accrued mining reclamation costs 136,326 135,075 Deferred revenue 266,198 311,751 Net proceeds from the generation sale 216,545 219,726 Other deferred credits 102,669 101,434 753,704 790,163 CONTINGENCIES AND COMMITMENTS (Notes 2 and 5) $ 2,908,194 $ 3,048,743 <FN> The accompanying notes are an integral part of these financial statements. THE MONTANA POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENT OF CASH FLOWS For Three Months Ended March 31, March 31, 2000 1999 (Thousands of Dollars) NET CASH FLOWS FROM OPERATING ACTIVITIES: Net Income $ 31,279 $ 33,824 Adjustments to reconcile net income to net cash Provided by operating activities: Depreciation, depletion, and amortization 25,105 27,754 Deferred income taxes 9,075 (16,954) Noncash earnings from unconsolidated investments (5,050) (6,533) Other - net 6,492 3,963 Changes in assets and liabilities: Accounts and notes receivable (7,794) 26,492 Generation asset sale - net proceeds (3,181) - - Accounts payable 14,172 (15,246) Income taxes payable (111,821) 22,501 Deferred revenue and other (45,553) 251,850 Other assets and liabilities - net 42,476 18,147 Net cash provided by (used for) operating activities (44,800) 345,798 NET CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures (37,208) (23,764) Proceeds from sales of property and investments 2,638 6,536 Additional investments 277 (843) Net cash used for investing activities (34,293) (18,071) NET CASH FLOWS FROM FINANCING ACTIVITIES: Dividends paid (22,035) (22,947) Sales of common stock 377 321 Issuance of long-term debt 16,044 31,048 Retirement of long-term debt (52,482) (56,699) Net change in short-term borrowing - - (69,820) Net cash used for financing activities (58,096) (118,097) CHANGE IN CASH FLOWS (137,189) 209,630 CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD 554,407 10,116 CASH AND CASH EQUIVALENTS, END OF PERIOD $ 417,218 $ 219,746 SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION: Cash paid during three months for: Income taxes, net refunds $ 144,295 $ 113 Interest 12,383 14,971 <FN> The accompanying notes are an integral part of these financial statements. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The accompanying consolidated financial statements of The Montana Power Company for the interim periods ended March 31, 2000 and 1999 are unaudited. In the opinion of management, the accompanying consolidated financial statements reflect all normally recurring accruals necessary for a fair statement of the results of operations for those interim periods. Results of operations for the interim periods are not necessarily indicative of the results to be expected for the full year, and these financial statements do not contain the detail or footnote disclosure concerning accounting policies and other matters that would be included in full fiscal year financial statements. Therefore, these statements should be read in conjunction with our audited financial statements included in our Annual Report on Form 10-K for the year ended December 31, 1999. In prior years, to facilitate the timely preparation of the consolidated financial statements, we consolidated the accounts of certain operations for fiscal years ending in November. The consolidated financial statements for the quarter ended March 31, 2000, eliminate the one-month lag in reporting for these operations. The results of operations of December 1999 for these entities, which would have previously been reported in results of the first quarter of 2000, have been recorded as an adjustment to beginning retained earnings as of January 1, 2000. This adjustment increased retained earnings by approximately $1,500,000. We have made reclassifications to certain prior-year amounts to make them comparable to the 2000 presentation. These changes had no significant effect on previously reported results of operations or shareholders' equity. NOTE 1 - DEREGULATION, REGULATORY MATTERS, SALE OF ELECTRIC GENERATING ASSETS, AND PROPOSED DIVESTITURE OF ENERGY BUSINESSES Deregulation The electric and natural gas utility businesses are in transition to a competitive market in which commodity energy products and related services are sold directly to wholesale and retail customers. Montana's Electric Industry Restructuring and Customer Choice Act (Electric Act), passed in 1997, provides that all customers will be able to choose their electric supplier by July 1, 2002. Montana's Natural Gas Utility Restructuring and Customer Choice Act (Natural Gas Act), also passed in 1997, provides that a utility may voluntarily offer its customers choice of natural gas suppliers and provide open access. Since natural gas restructuring is voluntary, no deadline for choice exists. Electric Through March 31, 2000, approximately 1,200 electric customers representing more than 1,800 accounts crossing all customer classifications - or approximately 27 percent of our pre-choice electric load - have moved to competitive supply since the inception of customer choice on July 1, 1998. Residential customers were eligible to move to choice during the fourth quarter of 1999. However, the majority of the load associated with our pre- choice electric customers who moved to other suppliers was industrial and large commercial customers. As required by the Electric Act, we filed a comprehensive transition plan with the Montana Public Service Commission (PSC) in July 1997. On July 1, 1999, we filed a case with the PSC to resolve the Tier II issues under the filing. Tier II issues address the recovery and treatment of the Qualifying Facility (QF) power-purchase contract costs, which are above-market costs; regulatory assets associated with the electric generating business; and a review of our electric generating assets sale, including the treatment of sales proceeds above book value of the assets. We will update our Tier II filing as a result of the closing of the sale of our electric generating assets, but we do not expect an order from the PSC until late 2000. In implementing our comprehensive transition plan, we initiated litigation in Montana District Court in Butte to seek reversal of a PSC decision regarding our ability to use tracking mechanisms to ensure fair and accurate recovery of above-market QF costs and certain other transition costs. In an order issued as part of its consideration of the transition plan, the PSC concluded that the Electric Act does not provide for tracking mechanisms and that transition costs must be mitigated and determined as a final matter in the transition filing. In the litigation, we also sought court clarification on whether the Electric Act authorized a rate freeze or a rate cap during the transition period that ends July 1, 2002. The PSC concluded that the Electric Act authorized a rate cap, but we disagreed with this interpretation. In May 2000, the district court heard oral arguments and issued an order. The court ruled in our favor on the first issue, emphasizing that the PSC must allow us to incorporate tracking mechanisms in our transition plan proposal and that an unconstitutional taking from either shareholders or customers would result if tracking mechanisms were not used. The court agreed with the PSC on the second issue, ruling that the Electric Act authorized a rate cap. We cannot predict whether the PSC will appeal the court's decision, and we have not yet determined whether we will appeal. Natural Gas Through March 31, 2000, approximately 240 natural gas customers with annual consumption of 5,000 dekatherms or more - 52 percent of our pre-choice natural gas supply load - have chosen alternate suppliers since the transition to a competitive natural gas environment began in 1991. Regulatory Matters Electric/Federal Energy Regulatory Commission (FERC) On March 30, 1998, we filed a request with the FERC to increase our open access transmission rates and the rates for bundled wholesale electric service to two rural electric cooperatives. FERC approved an interim increase in rates charged for transmission service, pending final approval in 2000. In January 1999, we reached a rate settlement with one of the cooperatives who moved to another supplier in December 1999. In March 1999, we reached a separate settlement with the other cooperative. We agreed to assist the cooperative in moving to choice when its full-service wholesale contract expires in exchange for its agreement to withdraw the rate-reduction complaint. This cooperative will move to another supplier in June 2000. Through a filing made with FERC in April 2000, we are seeking recovery of approximately $23,800,000 in transition costs associated with serving both of the wholesale electric cooperatives. We do not expect a FERC decision on this filing, which corresponds with our transition-costs recovery proceedings with the PSC in Montana, until 2001. Electric/PSC Montana's Electric Act established a rate freeze for all electric customers, meaning that transmission and distribution rates cannot be changed until July 1, 2000. In January 2000, as a result of the sale of our electric generating assets and sales proceeds in excess of the book value of the assets sold, we filed a voluntary rate reduction with the PSC for approximately $16,700,000 annually. This reduction became effective February 2, 2000. We expect to submit a combined electric and natural gas filing with the PSC, requesting increased rates, in the third quarter of 2000. Natural Gas/PSC On August 12, 1999, we filed a natural gas rate case with the PSC requesting increased annual revenues of $15,400,000, with a proposed interim increase of $11,500,000. The filing represented our first transmission and distribution gas filing since Montana's Natural Gas Act was passed. An interim increase of $7,600,000 became effective on December 10, 1999. A final PSC order that became effective on April 1, 2000, approved an additional increase of $2,800,000. As discussed above, we expect to submit a combined filing with the PSC in the third quarter of 2000 seeking increased natural gas and electric rates. Sale of Electric Generating Assets The sale of our electric generating assets in December 1999 to PPL Montana, LLC negatively affected the utility's net income for first quarter 2000. Utility revenues decreased because of discontinued off-system revenues related to the electric generating assets sold. Although the sale of the assets resulted in lower property taxes for the first quarter 2000, increased power-supply expenses offset these decreases. Power-supply expenses increased, despite decreases in fuel expenses. We no longer purchase fuel to operate the generating plants because we now purchase most of the power to serve our core customers pursuant to buyback contracts with PPL Montana. The maximum price that we pay for power in the buyback contracts, $22.25/MWh, represents our net fully allocated costs of service in current rates, replacing operations and maintenance expense, depreciation expense, and return on investment. In the sale of these assets, we generally retained all pre-closing obligations, and PPL Montana generally assumed all post-closing obligations. However, with respect to environmental liabilities, PPL Montana assumed all pre-closing (subject to certain indemnification provisions) and post-closing environmental liabilities associated with the purchased assets, with certain exceptions for pre-closing liabilities. We agreed to indemnify PPL Montana, on a limited basis, from losses arising from required remediation of pre-closing environmental conditions, whether known or unknown at the closing. During the first quarter of 2000, PPL Montana did not deliver any claim notices to us with respect to this indemnity obligation. We do not expect this indemnity obligation to have a material adverse effect on our consolidated financial position, results of operations, or cash flows. Proposed Divestiture of Energy Businesses On March 28, 2000, we announced our intent to separate our telcommunications business from our energy businesses through stock sale(s) of our energy businesses. When we complete the sale(s), expected to take six to twelve months from the end of the first quarter, Touch America, Inc. will remain as the entity through which we will continue to conduct our telecommunications business. We intend to invest the proceeds received from the sale of our energy businesses into Touch America. NOTE 2 - CONTINGENCIES Kerr Project A FERC order that preceded our sale of the Kerr Project to PPL Montana required us to implement a plan to mitigate the effect of the Kerr Project operations on fish, wildlife, and habitat. To implement this plan, we were required to make payments of approximately $135,000,000 between 1985 and 2020, the term during which we would have been the licensee. The net present value of the total payments, assuming a 9.5 percent annual discount rate, was approximately $57,000,000, an amount we recognized as license costs in plant and long-term debt on the Consolidated Balance Sheet in 1997. In the sale of the Kerr Project, PPL Montana assumed the obligation to make post-closing license compliance payments. In December 1998 and January 1999, we asked the United States Court of Appeals for the District of Columbia Circuit to review FERC's orders and the United States Department of Interior's conditions contained in them. On September 17, 1999, the court granted the motion of the parties and intervenors to hold up the appeal pending settlement efforts. In December 1999, we, along with PPL Montana, the United States Department of the Interior, the Confederated Salish and Kootenai Tribes (the Tribes), and Trout Unlimited, in a court-ordered mediation, agreed in principle to settle this litigation. A Statement of Agreement containing the principles for settlement of the disputes underlying the appeals was developed in December 1999. It provides that its terms are binding against all parties, with the understanding that the signatory parties will jointly draft additional documents as necessary to establish the terms of the settlement in detail. The parties have drafted these documents, and we have paid our settlement payment of approximately $24,000,000 under the Statement of Agreement into an escrow account. If FERC approves, in a final non-appealable order, the settlement terms as reflected in proposed license amendments discussed below, we will dismiss the petitions in the court of appeals, and the escrow agent will release the payments to the Tribes. In addition, we will transfer to the Tribes 669 acres of land we own on the Flathead Indian Reservation. If FERC does not approve the proposed license amendments in the form agreed to by the parties, or if, as a result of the appeal of a FERC order, that order is not final after a specified period, the money will be returned to us, and the litigation will resume. The settlement, subject to the conditions described above, substantially reduces our obligation to pay for fish, wildlife, and habitat mitigation assigned to the pre-closing period in the sale of the Kerr Project. In April 2000, PPL Montana and the Tribes, as co-licensees, filed proposed license amendments with FERC to effect the settlement described above. We supported these proposed license amendments. FERC is reviewing the filing, but we do not expect a decision until late 2000 or early 2001. Miscellaneous We and our subsidiaries are parties to various other legal claims, actions and complaints arising in the ordinary course of business. We do not expect the conclusion of any of these matters to have a material adverse effect on our consolidated financial position, results of operations, or cash flows. NOTE 3 - DERIVATIVE FINANCIAL INSTRUMENTS Derivative Financial Instruments Used We use derivative financial instruments to reduce earnings volatility and stabilize cash flows by hedging some of the price risk associated with our nonutility energy commodity-producing assets, contractual commitments for firm supply, and natural gas transportation agreements. We also use derivative financial instruments in speculative transactions to seek enhanced profitability based on expected market movements, as discussed below in "Speculative Transactions." In all cases, financial swap and option agreements constitute the principal kinds of derivative financial instruments used for these purposes. Swap Agreements Under a typical swap agreement, we make or receive payments based on the difference between a specified fixed price and a variable price of crude oil or natural gas at the time of settlement. The variable price is either a crude oil or natural gas price quoted on the New York Mercantile Exchange or a natural gas price quoted in Inside FERC's Gas Market Report or other recognized industry index. Option Agreements Under a typical option agreement, we make or receive monthly payments based on the difference between the actual price of crude oil or natural gas at settlement and the price established in a private agreement at the time of execution. Making or receiving payments is dependent on whether we buy (own or hold) or sell (write or issue) the option. Buying options involves paying a premium - the price of the option - and selling options involves receiving a premium. When we use options, we defer all premiums paid or received and recognize the applicable expenses or revenues monthly throughout the option term. As of March 31, 2000, our deferred revenues due to option premiums were approximately $1,500,000. Hedged Transactions Hedged transactions are those in which we have a position (either current or anticipated) in an underlying commodity or derivative of that commodity that exposes us to risk if the price of the underlying item adversely changes. We enter into these transactions primarily to reduce earnings volatility and stabilize cash flows. We recognize gains or losses from these derivative financial instruments in the Consolidated Statement of Income at the same time that we recognize the revenues or expenses associated with the underlying hedged item; until then, we do not reflect these gains or losses in our financial statements. At March 31, 2000, we had unrecognized gains of approximately $1,700,000 related to these transactions. As of March 31, 2000, we had not terminated any significant hedging instrument before the date of the anticipated commodity production, commodity purchase or sale, or natural gas transportation commitment. At March 31, 2000, we had swap and option agreements on approximately: ? 1,460,000 barrels, or 58 percent, of our estimated nonutility crude oil and natural gas liquids production through March 2002; ? 15 Bcf, or 42 percent, of our expected delivery obligations under long-term natural gas sales contracts through October 2001; and ? 0.15 Bcf, or 1 percent, of our natural gas production through December 2000. In addition, at March 31, 2000, we had sold swap and option agreements to hedge approximately 27 Bcf of our nonutility natural gas pipeline transportation obligations under contracts through December 2001, and we had purchased swap and option agreements to hedge approximately 33 Bcf of these obligations. Speculative Transactions We also enter into derivative financial transactions in which we have no underlying price risk exposure nor any interest in making or taking delivery of crude oil or natural gas commodities. We seek, by these speculative transactions, to profit from the market movements of the prices of these commodities. In accordance with Emerging Issues Task Force Issue No. 98-10, we mark to market all of our speculative transactions and recognize any corresponding gain or loss in the Consolidated Statement of Income. During the first quarter 2000, we recorded pretax losses of approximately $600,000 related to these transactions. NOTE 4 - COMPANY OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY TRUST We established Montana Power Capital I (Trust) as a wholly owned business trust to issue common and preferred securities and hold Junior Subordinated Deferrable Interest Debentures (Subordinated Debentures) that we issue. The Trust has issued 2,600,000 units of 8.45 percent Cumulative Quarterly Income Preferred Securities, Series A (QUIPS). Holders of the QUIPS are entitled to receive quarterly distributions at an annual rate of 8.45 percent of the liquidation preference value of $25 per security. The sole asset of the Trust is $67,000,000 of our Subordinated Debentures, 8.45 percent Series due 2036. The Trust will use interest payments received on the Subordinated Debentures that it holds to make the quarterly cash distributions on the QUIPS. NOTE 5 - COMMITMENTS Touch America's Commitments Construction Projects Before 2000, Touch America contracted with Northern Telecom, Inc. (Nortel) to furnish and install optical electronic equipment on certain fiber-optic networks. We expect Nortel to complete these installations in the fourth quarter of 2000 at a cost of $51,800,000, of which we have paid $28,300,000. The remaining $23,500,000 is scheduled for payment in 2000 as various segments of the fiber-optic network under construction, discussed below, are completed. Touch America continues to enter into arrangements with Nortel for installations of Nortel's optical electronic equipment on Touch America's network, including installations related to Touch America's acquisition from Qwest Communications International Inc. (Qwest) discussed below under "Investments and Acquisitions." Joint Ventures In accordance with the agreements governing the following relationships, Touch America is committed to contribute capital at various times. In May 2000, Touch America and Sierra Pacific Communications, a subsidiary of Sierra Pacific Resources, formed a 50-50 joint venture named Sierra Touch America LLC to construct a fiber-optic network between Sacramento and Salt Lake City. This network will make up 750 miles of the 4,300-mile build-out that Touch America is constructing in tandem with its construction of a fiber-optic network for AT&T. Sierra Touch America will begin construction of the Sacramento-Salt Lake City route immediately and expects to complete the route in mid-2001 at an estimated cost of $100,000,000. Touch America's portion of this estimated cost (directly and through its interest in the joint venture) will be approximately $83,000,000, of which it expects to recover approximately 50 percent from AT&T and other third parties. The terms of the joint venture agreement give Sierra Touch America a partial interest in the metropolitan fiber networks that Sierra Pacific Resources operates in Reno and Las Vegas. In June 1999, Touch America and Iowa Network Services, Inc. (INS) formed Iowa Telecommunications Services, Inc. (ITS) to purchase from a third party domestic access lines connected to telephone exchanges in Iowa. However, because the emerging organizational and capital structure of ITS does not fit Touch America's growth strategy, Touch America exited from its equity position in ITS in April 2000. Under the terms of the exit agreement: ? Touch America sold its 31 percent interest in ITS to INS, and INS released Touch America from all of ITS' obligations; ? Upon the closing of the third-party purchase transaction, expected to occur in mid-2000, INS will reimburse Touch America approximately $8,000,000 for Touch America's cash outlays to ITS; and ? Touch America will not withdraw its $14,000,000 letter of credit from ITS until the closing of the third-party purchase transaction. In January 2000, Touch America and AEP Communications LLC, a subsidiary of American Electric Power, formed a 50-50 joint venture named America Fiber Touch LLC (AFT) to connect national and regional fiber-optic networks. The venture's first project is to construct a 330-mile fiber-optic route between St. Louis, Missouri, and Plano, Illinois, which makes up the Midwest route of the 4,300 mile build-out for AT&T. This Midwest route is scheduled for completion in December 2000, at an estimated cost of $25,000,000, of which Touch America's portion is $12,500,000. Exchanges and Leases In March 2000, Touch America and Williams Communications, Inc. agreed to an exchange of dark fiber to expand both companies' fiber-optic networks. Touch America receives approximately 1,050 route miles of dark fiber and cash from Williams, in exchange for approximately 1,200 route miles of Touch America's dark fiber (from Denver to Dallas through Colorado Springs). This exchange will expand Touch America's network from Minneapolis to Denver through Des Moines, Iowa and Topeka, Kansas. Both routes are currently operational. In January 2000, Touch America and PF.Net, a privately held telecommunications company, agreed to a cross lease of fiber and conduit to expand both companies' fiber-optic networks. Touch America will receive approximately 5,900 route miles of fiber and conduit from PF.Net for 4,400 route miles of Touch America's fiber and conduit and a cash payment of $48,500,000 for the difference in route miles. Touch America has made an initial payment of $4,850,000 and will pay the remainder as segments of the routes under construction are completed. Segments are scheduled for completion at various times in 2000 and 2001. Investments and Acquisitions In January 2000, Touch America signed an agreement to purchase, from Century Tel Inc., 400 route miles of fiber-optic network linking Chicago and Detroit. Touch America will pay approximately $10,000,000 for the rights to these route miles, which it expects to be in service by late 2000. Touch America has made an initial payment of $2,000,000 and will make the remaining payments as construction is completed. In January 2000, Touch America signed a purchase agreement with Minnesota PCS, LP (MPCS) to acquire a 25 percent interest in MPCS' wireless telephone business, which owns PCS licenses in North Dakota, South Dakota, Minnesota, and Wisconsin. In accordance with the agreement, Touch America made an initial equity investment of $2,700,000 in MPCS and, over the years 2000-2001, will loan MPCS $12,000,000 in interest-bearing notes payable on October 1, 2002, of which a total of $6,000,000 had been loaned in early May 2000. In addition, Touch America will guarantee payment of $7,000,000 in loans owned by MPCS through the year 2007. The guarantees are callable only upon MPCS' default. In March 2000, Touch America signed an agreement with Qwest to acquire for approximately $193,000,000, subject to certain adjustments, Qwest's wholesale, private-line, long-distance, and other telecommunications services in US WEST's 14-state region, which covers 250,000 customer accounts for voice, data, and video services. By this agreement, Touch America will also acquire a fiber-optic network of 1,800 route miles and associated optronics and switches. If the Qwest acquisition is closed, we estimate that related capital expenditures will be an additional $100,000,000. The network will connect to Touch America's fiber-optic network, and Touch America will offer employment to approximately 120 of Qwest's sales agents in the region. We expect this acquisition to close in mid-2000, subject to the satisfaction of various conditions and the receipt of required regulatory approvals. NOTE 6 - LONG-TERM DEBT On January 3, 2000, we made a payment of approximately $10,200,000 for our share of the costs associated with the Kerr mitigation plan (Plan). This amount represented our final liability for costs under the Plan through the December 17, 1999, sale date of the electric generating assets. Two issues of Medium-Term Notes (MTNs) were retired prior to maturity in January of 2000. On January 13, 2000, we retired $5,000,000 of 7.25 percent Series A Secured MTNs due January 19, 2024. On January 14, 2000, we retired $7,000,000 of 8.68 percent Series A Unsecured MTNs due February 7, 2022. We retired at maturity $10,000,000 of 8.80 percent Series A Unsecured MTNs on February 22, 2000. On April 13, 2000, we retired prior to maturity $25,000,000 of our 7.5 percent First Mortgage Bonds (Bonds) due April 1, 2001. On April 25, 2000, we offered to purchase any or all of the following series of our outstanding debt: 8.95 percent Bonds due February 1, 2022; 7.33 percent Secured MTNs due April 15, 2025; 8.11 percent Secured MTNs due January 25, 2023; 7.00 percent Bonds due March 1, 2005; and 8.25 percent Bonds due February 1, 2007. The total amount outstanding for these issues was $190,000,000 as of March 31, 2000. Prices for the redemption will be set on May 18, 2000, and the offer to purchase expires on May 23, 2000. Proceeds received from the sale of the electric generating assets have been or will be used to make all of the retirements discussed above. In April 1997, we entered into a $160,000,000 Revolving Credit Agreement for some of our nonutility operations. Under the terms of the Revolving Credit Agreement, the amount of the facility decreased on March 31, 1998, reducing the borrowing ability to $100,000,000, all of which was unused at March 31, 2000. This agreement terminated on April 4, 2000, with no amount outstanding. NOTE 7 - COMPREHENSIVE INCOME The Financial Accounting Standards Board defines comprehensive income as all changes to the equity of a business enterprise during a period, except for those resulting from transactions with owners. For example, dividend distributions are excepted. Comprehensive income consists of net income and other comprehensive income. Net income includes such items as income from continuing operations, discontinued operations, extraordinary items, and cumulative effects of changes in accounting principles. Other comprehensive income includes foreign currency translations, adjustments of minimum pension liability, and unrealized gains and losses on certain investments in debt and equity securities. For the three months ended March 31, 2000 and 1999, our only item of other comprehensive income was foreign currency translation adjustments of the assets and liabilities of our foreign subsidiaries. These adjustments resulted in decreases to retained earnings of $888,000 in the first quarter of 2000, and increases to retained earnings of $665,000 in the first quarter of 1999. No current income tax effects resulted from the adjustments, nor do we expect there will be any net income effects until we sell a foreign subsidiary. NOTE 8 - INFORMATION ON INDUSTRY SEGMENTS: Our utility operations purchase, transmit, and distribute electricity and natural gas. With the sale of our electric generating assets other than Milltown Dam, we no longer are primarily engaged in regulated electric generation. In our nonutility businesses, our telecommunications operation designs, develops, constructs, operates, maintains, and manages a fiber-optic network and wireless facilities; it also sells long-distance, Internet, and private-line services and equipment. In other nonutility operations, we mine and sell coal and lignite; manage long-term power sales, and develop and invest in independent power projects and other energy-related businesses; and explore for, develop, produce, process, and sell crude oil and natural gas. We also trade crude oil, natural gas, and natural gas liquids. Identifiable assets of each industry segment are principally those assets used in our operation of those industry segments. Corporate assets are principally cash and cash equivalents and temporary investments. We consider segment information for foreign operations immaterial. Operations Information: Three Months Ended March 31, 2000 (Thousands of Dollars) UTILITY Electric Natural Gas Sales to unaffiliated customers $ 101,491 $ 44,794 Earnings from unconsolidated investments - - - - Intersegment sales 1,570 203 Pretax operating income (loss) 12,271 12,052 Capital expenditures 5,607 (3,035)(a) Identifiable assets 997,301 403,220 NONUTILITY Tele- Communications Coal(b) Independent Power(c) Sales to unaffiliated customers $ 24,126 $ 57,281 $ 17,749 Earnings from unconsolidated investments 602 - - 5,700 Intersegment sales 308 3,938 200 Pretax operating income (loss) 7,074 8,007 4,659 Capital expenditures 16,930 1,790 61 Identifiable assets 372,719 238,800 45,383 NONUTILITY (continued) Oil and Natural Gas Other Sales to unaffiliated customers $ 105,415 $ 7,706 Earnings from unconsolidated investments - - - - Intersegment sales 5,365 1,524 Pretax operating income (loss) 8,950 (482) Capital expenditures 8,996 1,926 Identifiable assets 306,256 30,780 CORPORATE Capital expenditures $ 4,933 Identifiable assets 513,735 RECONCILIATION TO CONSOLIDATED Segment Total Adjustments(d) Consolidated Total Sales to unaffiliated customers $ 358,562 - - $ 358,562 Earnings from unconsolidated investments 6,302 - - 6,302 Intersegment sales 13,108 $ (13,108) - - Pretax operating income (loss) 52,531 - - 52,531 Capital expenditures 37,208 - - 37,208 Identifiable assets 2,908,194 - - 2,908,194 <FN> (a) Decreased capital expenditures resulted from reduced levels of natural gas in underground storage. (b) The loss of revenues pursuant to one contract with a single customer would have a material adverse effect on the segment. (c) The loss of revenues pursuant to contracts with two customers would have a material adverse effect on the segment. (d) The amounts indicated include certain eliminations between the business segments. </TABLE Operations Information (continued): Three Months Ended March 31, 1999 (Thousands of Dollars) UTILITY Electric Natural Gas Sales to unaffiliated customers $ 116,534 $ 40,345 Earnings from unconsolidated investments - - - - Intersegment sales 3,690 199 Pretax operating income (loss) 29,674 10,140 Capital expenditures 8,024 - - Identifiable assets 1,575,186 392,195 NONUTILITY Tele- Communications Coal(a) Independent Power(b) Sales to unaffiliated customers $ 19,775 $ 43,438 $ 18,234 Earnings from unconsolidated investments 1,423 - - 5,333 Intersegment sales 228 9,904 238 Pretax operating income (loss) 6,743 7,746 6,001 Capital expenditures 5,540 1,634 246 Identifiable assets 196,310 236,726 110,028 NONUTILITY (continued) Oil and Natural Gas Other Sales to unaffiliated customers $ 68,809 $ 7,877 Earnings from unconsolidated investments - - - - Intersegment sales 4,400 441 Pretax operating income (loss) 3,441 (1,832) Capital expenditures 10,314 13 Identifiable assets 296,810 64,252 CORPORATE Capital expenditures $ 408 Identifiable assets 244,552 RECONCILIATION TO CONSOLIDATED Segment Total Adjustments(c) Consolidated Total Sales to unaffiliated customers $ 315,012 - - $ 315,012 Earnings from unconsolidated investments 6,756 - - 6,756 Intersegment sales 19,100 $ (19,100) - - Pretax operating income (loss) 61,913 - - 61,913 Capital expenditures 26,179 (2,415) 23,764 Identifiable assets 3,116,059 - - 3,116,059 <FN> (a) The loss of revenues pursuant to one contract with a single customer would have a material adverse effect on the segment. (b) The loss of revenues pursuant to contracts with two customers would have a material adverse effect on the segment. (c) The amounts indicated include certain eliminations between the business segments. NOTE 9 - COMMON STOCK STOCK SPLIT On June 22, 1999, the Board of Directors approved a two-for-one split of our outstanding common stock. As a result of the split, which was effective August 6, 1999, for all shareholders of record on July 16, 1999, 55,099,015 outstanding shares of common stock were converted to 110,198,030 outstanding shares of common stock. We have retroactively applied the split to all periods presented. SHARE REPURCHASE PROGRAM In 1998, the Board of Directors authorized a share-repurchase program over the next five years to repurchase up to 20,000,000 shares (approximately 18 percent of our then outstanding common stock) on the open market or in privately negotiated transactions. As of May 9, 2000, we had 105,572,301 common shares outstanding. The number of shares to be purchased and the timing of the purchases will be based on the level of cash balances, general business conditions, and other factors, including alternative investment opportunities. Subsequent to this authorization, we entered into a Forward Equity Acquisition Transaction (FEAT) program with a bank that committed to purchase shares on our behalf. Under the terms of the program, the amount owed to the bank and the number of shares held by the bank cannot exceed certain limits. In March 2000, these limits were amended and now are $125,000,000 and 2,500,000 shares. The expiration date of the program is October 31, 2000. Until that date, when all transactions must be settled, we can elect to fully or partially settle either on a full physical (cash) or a net share basis. A full physical settlement would be the purchase of shares from the bank for cash at the bank's average purchase price plus interest costs less dividends. A net share settlement would be the exchange of shares between the parties so that the bank receives shares with value equivalent to its original purchase price plus interest costs less dividends. Only at the time that the transactions are settled can our capital or outstanding stock be affected, and settlement has no effect on results of operations. In December 1999, when the limits described above were $200,000,000 and 8,000,000 shares, we used proceeds from the sale of our generation assets to acquire 4,682,100 shares of our stock under the FEAT program. The purchase of these shares averaged approximately $30.94 per share and ranged from $27.05 per share to $33.52 per share for a total cost of $144,872,000. We have reflected the shares purchased as treasury stock on the Consolidated Balance Sheet. No additional shares have been acquired under the program in 2000. ITEM 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Please read the following discussion in conjunction with the statements included in our Annual Report on Form 10-K for the year ended December 31, 1999 at Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations." Warnings About Forward-Looking Statements This Quarterly Report on Form 10-Q may contain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. Forward-looking statements are qualified by and should be read together with the cautionary statements and important factors included in our Annual Report on Form 10-K for the year ended December 31, 1999. See Part I, "Warnings About Forward-Looking Statements." We are 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 us, or on our behalf, in this 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 statements other than those of historical fact. Forward-looking statements may be identified, without limitation, by the use of the words "anticipates," "estimates," "expects," "intends," "believes," and similar expressions. We disclaim any obligation to update any forward-looking statements to reflect events or circumstances after the date that we file this Form 10-Q. Forward-looking statements that we make 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 our 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 and telecommunication industries and other industries in which we operate. Investors or other readers of the forward-looking statements are cautioned that these statements are not a guarantee of future performance and that the forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in, or implied by, the statements. Some, but not all, of the risks and uncertainties include: ? General economic and weather conditions in the areas in which we have operations; ? Competitive factors and the effects of restructuring in the electric, natural gas, and telecommunications industries; ? Sanctity and enforceability of contracts; ? Market prices; ? Environmental laws and policies and 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 and interest rates; and ? Changes in accounting principles or the application of such principles. Strategy We are focused on growing Touch America's revenues and earnings as demonstrated by the expansion of our fiber-optic network, which we expect to span more than 26,000 miles by the end of 2001. In pursuing this strategy, we will continue to investigate different approaches, including asset purchases and sales, the issuance of securities, and other transactions that may materially affect our results of operations, liquidity, and capital resources. For a discussion of how we intend to use proceeds from the sale(s) of our energy businesses, see the "Proposed Divestiture of Energy Businesses" section of Note 1, "Deregulation, Regulatory Matters, Sale of Electric Generating Assets, and Proposed Divestiture of Energy Businesses." Results of Operations The following discussion describes significant events or trends that have had an effect on our operations or which we expect to have an effect on our future operating results. We have adjusted all 1999 earnings-per-share information to reflect the two-for-one stock split effective August 6, 1999. Quarter Ended March 31, 2000 and 1999: Net Income Per Share of Common Stock (Basic) First quarter earnings were $0.29 per share, $0.01 less than first quarter 1999. Utility earnings were $0.08, compared with $0.12 last year. Nonutility earnings were $0.21, up $0.03 from the $0.18 figure of a year earlier. Because we have not yet reinvested all of the proceeds from the generation sale, we were negatively affected by the marginal difference between the returns received on the temporary investment of these funds versus what we would expect to earn as we reinvest the funds. Our repurchase last December of approximately 4,700,000 shares of common stock and our continued retirement of long-term debt mitigated these effects. Utility Operating Income ? Income from electric utility operations decreased approximately $17,400,000, or 59 percent, compared with the first quarter of 1999 because of the effects of the fourth quarter 1999 sale of our electric generating assets, customers continuing to choose other commodity suppliers, and the voluntary rate reduction that became effective on February 2, 2000. ? Income from our natural gas utility operations increased approximately $1,900,000, or 19 percent, during the period mainly because of an interim increase in rates that became effective on December 10, 1999. Nonutility Operating Income ? Income from our telecommunications operations increased approximately $300,000 compared with the first quarter of 1999 principally as a result of increased private-line and long-distance revenues. ? Income from our coal operations increased approximately $300,000 during the period because of higher revenues, mainly due to an increase in tons sold and average revenue per ton at Western Energy's Rosebud Mine because of the absence in 2000 of a $2,700,000 refund that Western Energy paid to a customer in the first quarter of 1999. ? Income from our independent power operations decreased approximately $1,300,000 during the period. While Continental Energy Services continues to benefit from improved operations at generating projects in which it holds interests, its Colstrip 4 Lease Management Division, which sells the leased share of Colstrip Unit 4 generation, had lower income compared with first quarter 1999 because of the effects of a restructured contract with the Los Angeles Department of Water and Power (LADWP) and higher operations and maintenance expenses associated with Colstrip Unit 4. ? Oil and natural gas operating income increased approximately $5,500,000 during the period, resulting from increased sales volumes and significantly higher commodity prices. For comparative purposes, the following table shows consolidated basic net income per share by principal business segment. Quarter Ended March 31, 2000 March 31, 1999 Utility operations $ 0.08 $ 0.12 Nonutility operations 0.21 0.18 Consolidated $ 0.29 $ 0.30 UTILITY OPERATIONS For Three Months Ended March 31, March 31, 2000 1999 (Thousands of Dollars) ELECTRIC UTILITY: REVENUES: Revenues $ 101,491 $ 116,534 Intersegment revenues 1,570 3,690 103,061 120,224 EXPENSES: Power supply 48,149 38,687 Transmission and distribution 9,057 11,677 Selling, general, and administrative 14,702 13,753 Taxes other than income taxes 9,725 12,754 Depreciation and amortization 9,157 13,679 90,790 90,550 INCOME FROM ELECTRIC OPERATIONS 12,271 29,674 NATURAL GAS UTILITY: REVENUES: Revenues (other than gas supply cost revenues) 29,467 26,293 Gas supply cost revenues 15,327 14,052 Intersegment revenues 203 199 44,997 40,544 EXPENSES: Gas supply costs 15,327 14,052 Other production, gathering, and exploration 750 793 Transmission and distribution 3,623 3,636 Selling, general, and administrative 7,145 5,755 Taxes other than income taxes 3,732 3,817 Depreciation, depletion, and amortization 2,368 2,351 32,945 30,404 INCOME FROM NATURAL GAS OPERATIONS 12,052 10,140 INTEREST EXPENSE AND OTHER INCOME: Interest 13,034 14,438 Distributions on mandatorily redeemable Preferred securities of subsidiary trusts 1,373 1,373 Other (income) deductions - net (6,589) (1,284) 7,818 14,527 INCOME BEFORE INCOME TAXES 16,505 25,287 INCOME TAXES 7,514 10,674 DIVIDENDS ON PREFERRED STOCK 923 923 UTILITY NET INCOME AVAILABLE FOR COMMON STOCK $ 8,068 $ 13,690 </TABLE UTILITY OPERATIONS Electric Utility The following table categorizes revenues and volumes into General Business Revenues, Sales To Other Utilities, Other, and Intersegment. It also shows Bundled Revenues and Distribution Only Revenues separately for General Business Revenues. While we no longer supply the electricity for customers who have chosen other commodity suppliers, we continue to earn transmission and distribution revenues for moving their electricity across our transmission and distribution lines. We reflect transmission revenues as Other Revenues and distribution revenues as Distribution Only Revenues. We expect these revenues to continue to increase as additional customers move to choice. For customers who have not chosen other suppliers, Bundled Revenues reflect fully bundled rates for supplying, transmitting, and distributing electricity. We expect these revenues to continue to decrease as additional customers move to choice. Revenues and Power Supply Expenses Volumes (Thousands of Dollars) (Thousands of MWh) 3/31/00 3/31/99 3/31/00 3/31/99 REVENUES: GENERAL BUSINESS BUNDLED REVENUES: Residential $ 36,063 $ 36,135 - - 542 531 2% Small commercial, small industrial, and government and municipal 37,541 41,533 (10%) 602 644 (7%) Large commercial, large Industrial 9,788 12,294 (20%) 261 447 (42%) Irrigation and street lighting 2,423 2,496 (3%) 14 15 (7%) Total 85,815 92,458 (7%) 1,419 1,637 (13%) GENERAL BUSINESS DISTRIBUTION ONLY REVENUES: Residential 56 - - - - 2 - - - - Small commercial, small industrial, and government and municipal 1,022 227 350% 60 11 445% Large commercial, large Industrial 1,745 2,640 (34%) 479 225 113% Total 2,823 2,867 (2%) 541 236 129% TOTAL GENERAL BUSINESS REVENUES 88,638 95,325 (7%) 1,960 1,873 5% SALES TO OTHER UTILITIES 5,252 16,443 (68%) 154 878 (82%) OTHER 7,601 4,766 59% INTERSEGMENT 1,570 3,690 (57%) - - 34 - - TOTAL $103,061 $120,224 (14%) 2,114 2,785 (24%) POWER SUPPLY EXPENSES: Hydroelectric - - 5,460 - - - - 870 - - Steam - - 12,986 - - 221 1,269 (83%) Purchased power and other 48,149 20,241 138% 1,671 551 203% Total $ 48,149 $ 38,687 24% 1,892 2,690 (30%) Dollars per MWh $ 25.45 $ 14.38 </TABLE General Business Revenues General Business Revenues decreased mainly from customers continuing to choose different suppliers and a voluntary rate reduction filed with the PSC, effective February 2, 2000. An increase in prices to recover the cost of public-purpose programs in accordance with the Electric Act partially offset these decreases. Sales to Other Utilities With the sale of substantially all of our generating assets, we no longer sell energy in the secondary markets. The elimination of these sales resulted in a decrease in revenues from Sales to Other Utilities. Other Other revenues increased mainly from transmitting energy for PPL Montana and customers who chose other suppliers. Prior to the generation sale, the energy transmitted for PPL Montana was the same energy generated by us and sold by MPT&M in the secondary markets, with MPT&M using our lines to transmit the energy across our service territory. The transmission of this energy was reflected as intersegment revenues in the table above. We reflect transmission revenues from customers who are not supplied by us as Other Revenues. Consequently, revenues from transmitting energy for PPL Montana and customers who chose other suppliers are reflected as Other Revenues in the table above. We report transmission revenues from customers who have not chosen other suppliers as General Business Revenues. Intersegment Intersegment revenues decreased principally because the absence of sales in the secondary markets eliminated the need for MPT&M to transmit energy across our lines. As discussed above, revenues from transmitting energy for PPL Montana partially offset this decrease. Expenses Power-supply expenses increased, despite decreased fuel expenses because we no longer purchase fuel to operate the generating plants, mainly because of increased purchased power costs required to supply electric energy to our core customers. Prior to the generation sale, we supplied these customers with electric energy primarily from our generation plants. As discussed above, we now purchase most of the power to serve our core customers at a price of approximately $22.25/MWh. This price represents our net fully allocated costs of service in current rates, replacing operations and maintenance expense, depreciation expense, and return on investment. Transmission and distribution expenses decreased primarily because, as discussed above, we are no longer selling energy in the secondary markets. As a result, we did not incur the costs associated with using other utilities' lines outside our service territory to transmit this energy. Selling, general, and administrative (SG&A) expenses increased approximately $950,000. The following items contributed to changes in administrative expenses: ? An increase of approximately $2,500,000 relating to energy efficiency and public-purpose programs in compliance with the Universal System Benefits Charge requirements of the Electric Act. In accordance with the Electric Act, we collect the costs associated with the energy efficiency and public-purpose programs through a separate component of rates; ? Costs of approximately $800,000 incurred to train staff and to adapt business processes to implement our new Enterprise Customer-Care information system (E-CIS); ? Reduced pension expense of approximately $900,000 because of the generation sale, which resulted in the transfer of 474 employees to PPL Montana; ? A decrease of approximately $900,000 in conservation program expenses; and ? A decrease in other miscellaneous administrative costs of approximately $550,000. Decreased taxes other than income taxes and depreciation expense represent a decrease in property taxes and plant related to the generation assets sold. Natural Gas Utility The following table categorizes revenues and volumes into General Business Revenues, Sales to Other Utilities, Transportation, and Other. Revenues Volumes* (Thousands of Dollars) (Thousands of Dkt) 3/31/00 3/31/99 3/31/00 3/31/99 REVENUES: Residential $ 26,852 $ 23,989 12% 4,772 11,505 (59%) Small commercial, small industrial, and government and municipal 13,130 11,326 16% 2,355 6,006 (61%) General business revenues 39,982 35,315 13% 7,127 17,511 (59%) Less: Gas supply cost Revenues (GSC) 15,327 14,052 9% - - - - - - General business revenues Without GSC 24,655 21,263 16% 7,127 17,511 (59%) Sales to other utilities 297 288 3% 106 101 5% Transportation 4,329 4,192 3% 7,253 7,024 3% Other 186 550 (66%) - - - - - - Total $ 29,467 $ 26,293 12% 14,486 24,636 (41%) <FN> *With the implementation of our E-CIS, we now report natural gas revenues in dekatherms (Dkt). A Dkt measures the heat used and is the basis of how we bill our customers. Revenues All of our former Large Industrial and Large Commercial customers have now chosen other commodity suppliers. While we no longer supply the natural gas for those customers, we still earn transportation revenues from moving their natural gas through our pipelines. We reflect these revenues as Transportation revenues in the table. General Business Revenues increased in the first quarter of 2000 primarily due to an increase in rates, customer growth, and a weather-related increase in volumes sold. For information on our natural gas rate case with the PSC, see Note 1, "Deregulation, Regulatory Matters, Sale of Electric Generating Assets, and Proposed Divestiture of Energy Businesses." Expenses SG&A expenses increased mainly because of costs for implementing the E- CIS system and for incentive compensation accruals. Utility Interest Expense and Other Income Retirement of long-term debt in 1999 and early 2000 and the absence of accruals in 2000 related to the Kerr Project mitigation liability account for the majority of the decrease of approximately $1,400,000 in interest expense. Other Income - Net increased approximately $5,300,000 primarily because of interest income earned on the higher cash balances held in 2000 compared to 1999. NONUTILITY OPERATIONS For Three Months Ended March 31, March 31, 2000 1999 (Thousands of Dollars) TELECOMMUNICATIONS: REVENUES: Revenues $ 24,126 $ 19,775 Earnings from unconsolidated investments 602 1,423 Intersegment revenues 308 228 25,036 21,426 EXPENSES: Operations and maintenance 9,558 8,446 Selling, general, and administrative 3,962 2,782 Taxes other than income taxes 2,068 1,040 Depreciation and amortization 2,374 2,415 17,962 14,683 INCOME FROM TELECOMMUNICATIONS OPERATIONS 7,074 6,743 COAL: REVENUES: Revenues 57,281 43,438 Intersegment revenues 3,938 9,904 61,219 53,342 EXPENSES: Operations and maintenance 37,838 32,332 Selling, general, and administrative 5,357 5,022 Taxes other than income taxes 8,004 6,357 Depreciation, depletion, and amortization 2,013 1,885 53,212 45,596 INCOME FROM COAL OPERATIONS 8,007 7,746 INDEPENDENT POWER: REVENUES: Revenues 17,749 18,234 Earnings from unconsolidated investments 5,700 5,333 Intersegment revenues 200 238 23,649 23,805 EXPENSES: Operations and maintenance 16,440 15,734 Selling, general, and administrative 1,044 830 Taxes other than income taxes 636 463 Depreciation and amortization 870 777 18,990 17,804 INCOME FROM INDEPENDENT POWER OPERATIONS $ 4,659 $ 6,001 </TABLE NONUTILITY OPERATIONS (CONTINUED) For Three Months Ended March 31, March 31, 2000 1999 (Thousands of Dollars) OIL AND NATURAL GAS: REVENUES: Revenues $ 105,415 $ 68,809 Intersegment revenues 5,365 4,400 110,780 73,209 EXPENSES: Operations and maintenance 87,888 58,951 Selling, general, and administrative 5,219 4,228 Taxes other than income taxes 2,000 1,024 Depreciation, depletion, and amortization 6,723 5,565 101,830 69,768 INCOME FROM OIL AND NATURAL GAS OPERATIONS 8,950 3,441 OTHER OPERATIONS: REVENUES: Revenues 7,706 7,876 Intersegment revenues 1,524 441 9,230 8,317 EXPENSES: Operations and maintenance 8,170 7,431 Selling, general, and administrative (224) 1,324 Taxes other than income taxes 166 313 Depreciation and amortization 1,600 1,081 9,712 10,149 LOSS FROM OTHER OPERATIONS (482) (1,832) INTEREST EXPENSE AND OTHER INCOME: Interest 773 2,104 Other income - net (4,171) (5,497) (3,398) (3,393) INCOME BEFORE INCOME TAXES 31,606 25,492 INCOME TAXES 9,318 6,281 NONUTILITY NET INCOME AVAILABLE FOR COMMON STOCK $ 22,288 $ 19,211 NONUTILITY OPERATIONS Telecommunications Operations Revenues from telecommunications operations increased approximately $4,400,000. This increase principally consists of the effects of the following elements: ? Increased private-line revenues of approximately $3,400,000 as a result of an increase in customer growth. ? Increased long-distance revenues, including Internet revenues, of approximately $800,000 as a result of more minutes sold and more long-distance and Internet customers. ? Decreased equipment-service sales of approximately $1,000,000, primarily because of 1999 equipment upgrades to address Year 2000 concerns and 1999 sales to a school district. ? Increased revenues of approximately $500,000 earned by Tetragenics Company, which designs and manufactures electronic monitoring, control, and data acquisition hardware and software for electric and communications systems. The following table shows changes from the previous year, in millions of dollars, in long-distance revenues (excluding Internet revenues) and the related percentage changes in minutes sold, price per minute, and customer growth: For The Three Months Ended March 31, March 31, 2000 1999 Revenues $ - $ 1 Minutes sold 9% 41% Price per minute (1%) (7%) Customer growth 21% 45% Earnings from unconsolidated investments were approximately $800,000 lower compared with the same period in 1999. Dark-fiber revenues, primarily from the FTV Communications LLC joint venture, were approximately $1,100,000 lower than in 1999. This decrease was somewhat offset by approximately $300,000 in net earnings from various joint ventures in which Touch America owns interests. After adjusting private-line revenues for the accounting effects of the $257,000,000 prepayment received in January 1999 and after excluding the dark- fiber sales included in earnings from unconsolidated investments, Touch America's operating revenues for the first three months of 2000 increased more than 20 percent as compared to the first three months of 1999. With the same adjustments above, Touch America's operating income for the first three months of 2000 increased more than 40 percent as compared to the first three months of 1999. Operations and maintenance expense increased approximately $1,100,000, attributable chiefly to higher cost of sales for Tetragenics. SG&A expenses increased approximately $1,200,000 as a result of a combination of expenses associated with outside consultants, salaries, costs relating to joint ventures, increased marketing efforts, and Touch America's share of expenses for our new Enterprise Resource Planning (ERP) information system. Taxes other than income taxes increased approximately $1,000,000 as a result of increased property taxes, resulting from expansion of Touch America's fiber- optic network. Depreciation and amortization expense remained relatively flat because the absence in 2000 of amortization expense associated with Personal Communication Services (PCS) licenses owned by Touch America, which Touch America transferred in late 1999 to its TW Wireless joint venture, offset increases associated with expansion of the fiber-optic network. As discussed in the "Touch America's Commitments" section of Note 5 under "Investments and Acquisitions," Touch America signed a purchase agreement with Qwest in March 2000. We expect this acquisition will close in mid-2000 and that it will increase Touch America's revenues in 2001 by approximately $300,000,000. For a discussion of Touch America's forecasted capital expenditures for 2000, see the "Investing Activities" section of "Liquidity and Capital Resources." Coal Operations Income from coal operations increased approximately $300,000 when compared with the first quarter of 1999. Revenues from Western Energy's Rosebud mine increased $7,600,000. Volume of coal sold to the Colstrip Units increased by approximately 8 percent and average revenue per ton was approximately 16 percent higher. The average revenue per ton increase was largely the result of a one-time $2,700,000 refund in the first quarter of 1999 to a customer for final pit reclamation funds previously collected. The customer has agreed to be responsible for a portion of all final pit reclamation expenses in the future. Sales to a midwest utility under a new contract also contributed to the improved revenues. Revenues from Northwestern Resource's Jewett mine increased $300,000 as a 3 percent increase in price more than offset a 2 percent decrease in tons sold. Operations and maintenance expense increased approximately $5,500,000 from higher royalties, reclamation costs, equipment rentals, and diesel fuel costs. A one-time reversal of reclamation expenses in the first quarter of 1999 associated with the refund discussed above contributed to this increase. Taxes other than income taxes also increased as a result of the increased revenues at the Rosebud Mine. Independent Power Operations Income from our independent power operations decreased approximately $1,300,000. Revenues decreased approximately $500,000 mainly because of the effects of a December 1999 agreement with LADWP. Continental Energy Services' Colstrip 4 Lease Management Division sells the leased share of Colstrip Unit 4 generation, and the December agreement terminated an existing power-supply contract and established a new contract expiring in December 2010. As a result of this transaction, we received approximately $106,000,000 from LADWP in December 1999. Earnings from unconsolidated investments increased approximately $400,000. This was attributable mainly to improved operations in generating projects in which Continental Energy Services holds equity interests - particularly Encogen One in Texas and Ferndale in Washington state. Operations and maintenance expense increased approximately $700,000 principally because of an increase in expenses associated with Colstrip Unit 4 operations. SG&A expenses increased approximately $200,000 mainly as a result of Continental Energy's share of expenses associated with the ERP information system. 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 $ 2 - -volume 2% - -price/bbl 165% Natural gas - -revenue $ 27 - -volume 1% - -price/Mcf 41% Natural gas liquids - -revenue $ 7 - -volume 41% - -price/bbl 75% Miscellaneous $ 2 Income from oil and natural gas operations increased approximately $5,500,000 due primarily to higher commodity prices and increased natural gas liquids trading and marketing activities in the first quarter of 2000 compared with 1999. Oil and natural gas revenues increased because of significant increases in prices along with slightly higher sales volumes. Revenues from natural gas liquids operations were higher because of both a sizable increase in prices and increased trading and marketing activities. Operations and maintenance expense increased mainly because of higher purchased gas costs and royalties caused by the higher prices discussed above. Taxes other than income nearly doubled compared to the prior year because of the higher value of the oil, natural gas, and natural gas liquids produced from our reserves. Depreciation, depletion, and amortization increased mainly because depletion rates applied to production from our Canadian properties were higher in the first quarter of 2000 compared to 1999. Nonutility Interest Expense and Other Income Reduced needs for short-term cash resulted in the decrease in interest expense of approximately $1,300,000. Other Income - Net decreased approximately $1,300,000 because the funds available for investments in the first quarter of 2000 were less than the funds available in the first quarter of 1999. LIQUIDITY AND CAPITAL RESOURCES Operating Activities Net cash used for operating activities was $44,800,000 for the three months ended March 31, 2000, compared with net cash provided by operations of $345,798,000 in the first three months of 1999. The current-year decrease of $390,598,000 was attributable mainly to the $257,000,000 prepayment received in January 1999 from a Touch America customer. We are recognizing the prepayment in revenues over the remaining eleven-year term of the agreement. The decrease in cash provided by operating activities also was attributable to income taxes paid during the first quarter of 2000 as a result of the following items: (1) the telecommunications prepayment discussed above, (2) the $106,000,000 received in December 1999 from LADWP relating to a power- supply agreement, and (3) the gain from the December 1999 sale of our electric generating assets. Investing Activities Net cash used for investing activities was $34,293,000 for the three months ended March 31, 2000, compared with $18,071,000 in the first three months of 1999. The current-year increase of $16,222,000 was attributable mainly to an increase in capital expenditures and a decrease in proceeds from sales of property and investments in 2000. Touch America's forecasted capital expenditures for 2000, including those required for the Qwest acquisition, are approximately $700,000,000. If the Qwest acquisition is closed, Touch America does not expect the purchase price and related capital expenditures to exceed $300,000,000. Financing Activities Net cash used for financing activities was $58,096,000 for the three months ended March 31, 2000, compared with $118,097,000 in the first three months of 1999. On January 3, 2000, we made a payment of approximately $10,200,000 for our share of the costs associated with the Kerr mitigation plan (Plan). This amount represented our final liability for costs under the Plan through the December 17, 1999, sale date of the electric generating assets. Two issues of Medium-Term Notes (MTNs) were retired prior to maturity in January of 2000. On January 13, 2000, we retired $5,000,000 of 7.25 percent Series A Secured MTNs due January 19, 2024. On January 14, 2000, we retired $7,000,000 of 8.68 percent Series A Unsecured MTNs due February 7, 2022. We retired at maturity $10,000,000 of 8.80 percent Series A Unsecured MTNs on February 22, 2000. On April 13, 2000, we retired prior to maturity $25,000,000 of our 7.5 percent First Mortgage Bonds (Bonds) due April 1, 2001. On April 25, 2000, we offered to purchase any or all of the following series of our outstanding debt: 8.95 percent Bonds due February 1, 2022; 7.33 percent Secured MTNs due April 15, 2025; 8.11 percent Secured MTNs due January 25, 2023; 7.00 percent Bonds due March 1, 2005; and 8.25 percent Bonds due February 1, 2007. The total amount outstanding for these issues was $190,000,000 as of March 31, 2000. Prices for the redemption will be set on May 18, 2000, and the offer to purchase expires on May 23, 2000. Proceeds received from the sale of the electric generating assets have been or will be used to make all of the retirements discussed above. Our consolidated borrowing ability under our Revolving Credit and Term Loan Agreements was $179,264,000, of which $165,670,000 was unused at March 31, 2000. On April 4, 2000, our Revolving Credit Agreement for some of our nonutility operations terminated with no amounts outstanding. This reduced our consolidated borrowing ability by $100,000,000. We also have short-term borrowing facilities with commercial banks that provide committed and uncommitted lines of credit and the ability to sell commercial paper. The Board of Directors periodically reviews our dividend policy to ensure that our dividend payout and dividend rate are appropriate given our business plan, strategy, and outlook. Our common stock dividend rate is dependent on our results of operations, financial position, anticipated future uses of cash, and other factors. In assessing the dividend policy, the Board of Directors also evaluates the effect of the sale of our generation assets and the continued growth of, and investment in, Touch America. As discussed more fully in Note 1, "Deregulation, Regulatory Matters, Sale of Electric Generating Assets, and Proposed Divestiture of Energy Businesses," on March 28, 2000, we announced our intent to separate our telecommunications business from our energy businesses through stock sale(s) of our energy businesses, with Touch America remaining as the entity through which we will continue to conduct our telecommunications business. The Board of Directors will continue to assess and adjust our dividend policy in light of these and other developments. For information regarding our authorization to repurchase common stock, refer to Note 9, "Common Stock." SEC RATIO OF EARNINGS TO FIXED CHARGES For the twelve months ended March 31, 2000, our ratio of earnings to fixed charges was 3.36 times. Fixed charges include interest, distributions on preferred securities of a subsidiary trust, the implicit interest of the Colstrip Unit No. 4 rentals, and one-third of all other rental payments. YEAR 2000 COMPLIANCE We did not have any significant disruptions as a result of the calendar rollover from 1999 to 2000 or the "leap year" rollover. NEW ACCOUNTING PRONOUNCEMENTS New requirements associated with the accounting for derivative instruments and hedging and trading activities will affect MPT&M and ultimately may affect Touch America. Statement of Financial Accounting Standards Nos. 133 and 137 In June 1998, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133 requires that all derivative instruments be recorded on an entity's balance sheet at fair value. The statement also expands the definition of a derivative. In July 1999, the FASB issued SFAS No. 137, "Accounting for Derivative Instruments and Hedging Activities: Deferral of the Effective Date of FASB Statement No. 133." SFAS No. 137 delays for one year the effective date of SFAS No. 133. This delay means that we are not required to adopt SFAS No. 133 until January 1, 2001. We expect to complete the sale(s) of our unregulated energy businesses, including MPT&M, before January 1, 2001. While we have begun a review of our commodity purchase and sale agreements to evaluate exposure to potential embedded derivatives, we do not expect the adoption of SFAS No. 137 to have a material effect on our consolidated financial position, results of operations, or cash flows. ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Our energy commodity-producing, trading, and marketing activities and other investments and agreements expose us to the market risks associated with fluctuations in commodity prices, interest rates, and changes in foreign currency translation rates. Trading Instruments Because we do not use derivative financial instruments to hedge against exposure to fluctuations in interest rates or foreign currency exchange rates, commodity price risk represents the primary market risk to which our non- regulated energy-commodity producing, trading, and marketing operations are exposed. We discuss the derivative financial instruments that we use to manage this risk in Note 3, "Derivative Financial Instruments." Electricity In June 1998, prior to our August 1998 decision to exit the electric trading and marketing businesses, MPT&M entered into a derivative financial transaction, called a "swap," in conjunction with one of our electric retail sales contracts. That swap allows us to receive the difference between a fixed price and market-index price for electricity. We net the difference against the cost of purchasing electricity to serve the retail sales contract. Crude Oil, Natural Gas, and Natural Gas Liquids We have commodity risk-management policies and practices to govern the execution, recording, and reporting of derivative financial instruments and physical transactions associated with the trading and marketing activity of crude oil, natural gas, and natural gas liquids engaged in by MPT&M. These policies and practices require MPT&M to identify, quantify, and report commodity risks and to hold regular Risk Management Committee meetings. Our Audit Committee established a value-at-risk (VaR) limit to manage our exposure to potential losses from trading activity. MPT&M must report to that committee the number of times it exceeds the established limit. MPT&M's VaR limit, including forecasts of affiliate-owned production, is $2,000,000. MPT&M's VaR calculation indicates how much MPT&M could lose from its trading transactions under certain assumptions. Because actual future changes in markets - prices, volatilities, and correlations - may be inconsistent with historical observations, MPT&M's VaR may not accurately reflect the potential for future adverse changes in fair values. At March 31, 2000, MPT&M's VaR calculation for physical and financial crude oil, natural gas, and natural gas liquids transactions, including forecasts of affiliate-owned production, was approximately $1,500,000. From January 1, 2000, through the end of the first quarter, MPT&M reported daily adverse changes in fair values in excess of its $2,000,000 VaR limit on three occasions. From April 1, 2000, through May 8, 2000, MPT&M reported one such occasion. Other-Than-Trading Agreements We are exposed to commodity price risks through our utility and nonutility operations. Our utility has entered into purchase, sale, and transportation contracts for electric energy and natural gas. One of these contracts obligates us to sell electric energy to an industrial customer at terms that include a fixed price for a portion of the power delivered and an index-based price for another portion through December 2002. For 2003 and 2004, we sell all power to the customer at an index-based price. Since the sale of our electric generating assets, we have been supplying our customer with power purchased through an index-based contract that remains effective through July 2001. Our industrial customer has given us usage estimates that do not exceed the amount of power that we are committed to purchase. Because the price of power under the index-based purchase contract could exceed the fixed price in our sales contract, we are subject to commodity price risk. Due to uncertainties relating to the supply requirements of the contract and uncertainties surrounding various arrangements that would allow us to serve the contractual demand, we cannot determine at this time the effects that this contract ultimately may have on our consolidated financial position, results of operation, or cash flows. MPT&M has entered into arrangements to mitigate the commodity price risk inherent in this contract, and we continue to examine our options and take steps to mitigate the commodity price risk resulting from this contract. Our nonutility has entered into similar kinds of purchase, sale, and transportation contracts for coal, lignite, natural gas, crude oil, and natural gas liquids. Since December 31, 1999, there has been no material change in these other instruments or the corresponding commodity price risk associated with these instruments. Our primary interest rate exposure with respect to other-than-trading instruments relates to items that SFAS No. 107, "Disclosures about Fair Value of Financial Instruments," defines as "financial instruments," which are instruments readily convertible to cash. Since December 31, 1999, there has been no material change in these instruments or the corresponding interest rate risk associated with these instruments. Our primary foreign currency exposure results from (1) our Canadian subsidiaries - Altana Exploration Company and Altana Exploration Ltd. - exploring for, producing, gathering, processing, transporting, and marketing crude oil and natural gas in Canada, and (2) MPT&M trading and marketing natural gas in Canada. (Effective January 1, 2000, we combined all of the assets, liabilities, and undertakings of our Canadian subsidiaries, Altana Exploration Ltd. and Canadian-Montana Gas Company Limited, with Altana Exploration Ltd. surviving.) Since December 31, 1999, there has been no material change in these activities or the corresponding foreign currency risk associated with these activities. PART II OTHER INFORMATION ITEM 1. Legal Proceedings Kerr Project For information regarding the Kerr Project fish, wildlife and habitat mitigation plan, refer to Note 2, "Contingencies." Paladin Associates, Inc. On May 4, 2000, the United States District Court for the District of Montana granted motions for summary judgment submitted by us and North American Resources Company (NARCo), a subsidiary of our subsidiary, Entech, Inc., challenging Paladin's antitrust claims on the grounds that they lacked merit as a matter of law. The court dismissed Paladin's antitrust claims. The court also ordered that Paladin's pending state claims (alleging breach of contractual obligation and torts on the part of NARCo and us) be dismissed without prejudice to the right of Paladin to prosecute those claims in state court. We cannot predict whether Paladin will appeal the court's order regarding the antitrust claims or whether it will pursue these claims in state court. TCA Building Company On April 26, 2000, TCA appealed the summary judgment entered against it in Texas district court. The counterclaims asserted by our subsidiary, Entech, Inc., and its subsidiary, Northwestern Resources Co., against TCA have been abated pending the resolution of the appeal. We cannot predict when this matter will ultimately be resolved. 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, 2000 Exhibit 18 Letter of preferability on change of accounting principle Exhibit 27 Financial data schedule (b) Reports on Form 8-K Filed During the Quarter Ended March 31, 2000. DATE SUBJECT January 25, 2000 Item 5. Other Events. Discussion of Fourth Quarter 1999 Net Income. Item 7. Exhibits. Preliminary Consolidated Statements of Income for the Quarters Ended December 31, 1999 and 1998 and for the Twelve Months Ended December 31, 1999 and 1998. Preliminary Utility Operations Statements of Income for the Quarters Ended December 31, 1999 and 1998 and for the Twelve Months Ended December 31, 1999 and 1998. Preliminary Nonutility Operations Statements of Income for the Quarters Ended December 31, 1999 and 1998 and for the Twelve Months Ended December 31, 1999 and 1998. 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 Chairman and Chief Financial Officer Dated: May 15, 2000 EXHIBIT INDEX Exhibit 12 Computation of ratio of earnings to fixed charges for the twelve months ended March 31, 2000 Exhibit 18 Letter of preferability on change of accounting principle Exhibit 27 Financial data schedule - -5- - -13- - -26- - -35- - -36- - -39-