(Mark One)

(X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2000

-- OR --

( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

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 November 8, 2000, the Company had 105,665,479 shares of common stock outstanding.

The accompanying consolidated financial statements of The Montana Power Company for the interim periods ended September 30, 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.

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.

On March 28, 2000, we announced our decision to separate our telecommunications business from our energy businesses through stock sales of our energy businesses. When we complete the sales, which we expect to close before the end of the first quarter 2001, Touch America, Inc. will remain as the entity through which we will continue to conduct our telecommunications business. We intend to invest the net proceeds received from the sales of our energy businesses - approximately $1,300,000,000 before taxes - into Touch America.

On August 25, 2000, our wholly owned subsidiary, Entech, Inc., and Altana Exploration Company, Entech's wholly owned subsidiary, entered into a Stock and Asset Purchase Agreement with PanCanadian Petroleum Limited, a Canadian corporation (PanCanadian Petroleum), and one of PanCanadian Petroleum's wholly owned subsidiaries, PanCanadian Energy, Inc., a Delaware corporation (PanCanadian Energy). Pursuant to the Stock and Asset Purchase Agreement, PanCanadian Petroleum agreed to purchase from us all of the stock and assets of our Canadian oil and natural gas businesses, and PanCanadian Energy agreed to purchase from us all of the stock of our United States oil and natural gas businesses. The transaction closed on October 31, 2000, with a purchase price of US$475,000,000, subject to certain adjustments. Based on the net book value of our oil and natural gas businesses, we expect to record a gain on the sale of these properties. For information on the accounting treatment applied to these operations, see Note 2, "Discontinued Operations."

On September 15, 2000, Entech entered into a Stock Purchase Agreement with Westmoreland Coal Company, a Delaware corporation (Westmoreland), pursuant to which Westmoreland agreed to purchase the companies comprising our coal businesses. The purchase price is $138,000,000, subject to certain adjustments, and we expect the transaction to close in the first quarter 2001. For information on the accounting treatment applied to these operations, see Note 2, "Discontinued Operations."

On September 19, 2000, Entech entered into a Stock Purchase Agreement with BBI Power Corporation, a Delaware corporation, pursuant to which BBI Power agreed to purchase the stock of Continental Energy Services, Inc., our independent power business. The purchase price is $84,500,000, subject to certain adjustments. We expect the transaction to close by year-end 2000, subject to customary closing and other conditions.

On September 29, 2000, we, together with our affiliate, Touch America Holdings, Inc., a Delaware corporation, entered into a Unit Purchase Agreement with NorthWestern Corporation, a Delaware corporation (NorthWestern), pursuant to which NorthWestern agreed, as discussed below, to purchase our affiliate, The Montana Power LLC, a Montana limited liability company. The Montana Power LLC will hold - among other assets, liabilities, and commitments - our electric and natural gas utility businesses. The consideration is $1,090,000,000, comprised of cash of $602,000,000 and NorthWestern's assumption of $488,000,000 of our debt.

Prior to closing the transaction, we will seek to restructure our organization so that The Montana Power Company will be merged into The Montana Power LLC. NorthWestern will then acquire all of the outstanding membership interests in Montana Power LLC from Touch America Holdings, Inc. For additional information on Touch America Holdings, Inc., see Note 3, "Upcoming Special Meeting of Shareholders."

The transaction is targeted to close at approximately the end of the first quarter 2001. The closing is subject to the approval of our shareholders, regulatory approvals from the Montana Public Service Commission (PSC) and the Federal Energy Regulatory Commission (FERC), and other customary conditions, including any necessary antitrust determinations.

As a result of the definitive agreements entered into with respect to our oil and natural gas and coal operations, we applied discontinued operations accounting to these operations effective September 1, 2000. Accordingly, we have separately reported net income after income taxes from oil and natural gas and coal operations in income from discontinued operations for all periods presented to reflect the reclassification of our oil and natural gas and coal operations as discontinued operations. With respect to our consolidated balance sheet at September 30, 2000, we have netted assets and liabilities of oil and natural gas and coal operations in "investment in discontinued segments." We have reported cash flows of oil and natural gas and coal operations as "net cash provided by discontinued operations," "net cash used for discontinued investing activities," and "net cash provided by (used for) discontinued financing activities" for all periods presented.

As discussed in Note 3, "Upcoming Special Meeting of Shareholders," our proposed restructuring and sale of all of the outstanding membership interests in The Montana Power LLC are subject to shareholder approval. As a result, we have not yet implemented discontinued operations accounting for our utility operations. Because Colstrip Unit 4 has historically been reported as part of the independent power group segment with Continental Energy Services, Inc., that entire segment will not be afforded discontinued operations accounting treatment until we receive the shareholder approval required for our restructuring and the sale of our remaining utility businesses. Consequently, Continental Energy's results of operations are reported under continuing operations.

Our Board of Directors has approved our proposed restructuring creating a new holding company, Touch America Holdings, Inc., which will hold what is today our telecommunications business. Immediately following this restructuring, Touch America Holdings, Inc. will own all of the outstanding membership interests in The Montana Power LLC and will sell these interests to NorthWestern. Upon completion of this restructuring and sale, Touch America Holdings, Inc. will own all of the assets of Touch America, Inc., which will be our telecommunications operating business.

Shareholder approval is required to divest The Montana Power LLC and to become, through this restructuring, a telecommunications company. We have targeted the end of the first quarter 2001 to hold a special meeting of shareholders to approve these transactions.

If the restructuring and sale are completed, our shareholders will receive one share of Touch America Holdings' common stock for each share of our current common stock, and one share of Touch America Holdings' preferred stock for each share of our then-outstanding preferred stock.

On June 30, 2000, in accordance with a previously executed stock purchase agreement, we acquired from Qwest Communications International Inc. (Qwest) wholesale, private-line, long-distance, and other telecommunications services in U S WEST's fourteen-state region associated with Qwest's interLATA businesses for approximately $206,000,000, subject to certain adjustments. We estimate that Touch America's related capital expenditures, mainly to install optronics on new routes, will be an additional $70,000,000. The fourteen-state region covers approximately 250,000 customer accounts for voice, data, and video services. Touch America also acquired a fiber-optic network of 1,800 route miles and associated optronics and switches that will connect to Touch America's existing fiber-optic network. As a result of the acquisition, Touch America acquired 173 of Qwest's former sales and sales-support personnel in the fourteen-state region.

Our September 30, 2000 consolidated balance sheet includes approximately $60,000,000 of net nonutility plant and approximately $146,000,000 of intangible assets related to the Qwest acquisition. An independent third party is presently appraising the value of the properties acquired. When this appraisal is complete, which is expected to occur in the fourth quarter 2000, we will adjust our allocation of the purchase price among the various balance sheet classifications, if necessary.

For more information on the Qwest acquisition, see the audited historical and unaudited pro forma financial information contained in our Form 8-K/A filed with the Securities and Exchange Commission (SEC) on September 15, 2000.

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 1997 Electric Utility Industry Restructuring and Customer Choice Act (Electric Act) provides that all customers will be able to choose their electric supplier by July 1, 2002. In October 2000, the PSC issued a Request for Comments on Extension of Transition Period, with comments due in November 2000. Due to the lack of a competitive market for the supply of electric energy in Montana, the PSC is proposing to extend the transition period two years, or until July 1, 2004. If the transition period is extended, the electric utility would be required to supply electric energy for the additional two-year period.

Montana's 1997 Natural Gas Utility Restructuring and Customer Choice Act (Natural Gas Act) 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.

Through September 30, 2000, approximately 1,250 electric customers representing more than 2,000 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 became eligible to move to choice during the fourth quarter of 1998. However, the majority of the load associated with our pre-choice electric customers that moved to other suppliers was industrial and large commercial customers. In 2000, commercial accounts associated with specific trade organizations have been the most active in moving to competitive choice.

As required by the Electric Act, we filed a comprehensive transition plan with the PSC in July 1997. On July 1, 1999, we filed a case with the PSC to resolve the remaining 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 the book value of the assets.

In implementing our comprehensive transition plan, we initiated litigation in Montana District Court in Butte to address our ability to use tracking mechanisms to ensure fair and accurate recovery of above-market QF costs and certain other transition costs. We also sought court clarification on whether the Electric Act authorized a rate moratorium or a rate cap during the transition period that ends July 1, 2002.

The district court issued an order in May 2000. The court ruled that the PSC must allow us to incorporate tracking mechanisms in our transition plan proposal. The court also ruled that the Electric Act authorized a rate cap. The PSC appealed to the Montana Supreme Court the court's decision regarding tracking mechanisms, and we did not appeal its decision regarding the rate moratorium. The parties completed briefing of the tracking-mechanisms issue in October 2000 and are awaiting a decision from the Montana Supreme Court, which has requested amicus briefs and will schedule oral argument.

After the district court case, we updated our Tier II filing to reflect the closing of the sale of our electric generating assets. The PSC has suspended the procedural schedule and, therefore, we do not expect an order from the PSC until the third or fourth quarter of 2001.

Natural Gas

Through September 30, 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.

Electric/FERC

On March 30, 1998, we submitted a cost-of-service filing with the FERC to increase our open access transmission rates and the rates for bundled wholesale electric service to two rural electric cooperatives. Effective November 1, 1998, FERC approved an interim increase in rates charged for transmission service. In May 2000, we received final approval from FERC.

In January 1999, we reached a rate settlement with one of the cooperatives that selected another supplier in December 1999. In March 1999, we reached a separate settlement with the other cooperative, agreeing to assist the cooperative's selection of another supplier when its full-service wholesale contract expired in exchange for its agreement to withdraw its rate-reduction complaint. This cooperative moved to another supplier in June 2000.

Through a stranded-costs filing 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.

In January 2000, as a result of the sale of our electric generating assets and sales proceeds exceeding 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.

On August 11, 2000, we filed a combined rate case with the PSC, seeking increased electric and natural gas rates. We requested increased annual electric transmission and distribution revenues of approximately $38,500,000, with a proposed interim annual increase of approximately $24,900,000. We expect a decision from the PSC regarding our interim request during the fourth quarter of 2000 and a final order in April 2001.

On August 25, 2000, we filed a request for increased rates to recover approximately $9,200,000 of higher power-supply costs relating to certain QF costs on an interim basis, pending final determination of QF transition costs. In a work session with the PSC on October 25, 2000, the PSC denied our request. We intend to clarify our request and ask the PSC to reconsider its decision.

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. An interim increase of $7,600,000 became effective on December 10, 1999, and a final PSC order that became effective on April 1, 2000 approved an additional increase of $2,800,000.

As discussed above, we submitted a combined filing with the PSC on August 11, 2000, seeking increased natural gas and electric rates. We requested increased annual natural gas revenues of approximately $12,000,000, with a proposed interim annual increase of approximately $6,000,000. We expect a decision from the PSC regarding our interim request during the fourth quarter of 2000 and a final order in April 2001.

As expected, the sale of our electric generating assets in December 1999 reduced the utility's net income for third quarter 2000. Utility revenues decreased because of discontinued off-system revenues related to the electric generating assets sold. Before the sale, revenues covered the costs of operating the generating plants, taxes and interest, and earned a return on our shareholders' investment. Since the sale, we continue to bill for energy supply, but now these revenues cover the costs of purchased power to serve our core customers. While revenues from our core customers were not affected by the sale, we now pay the profit component of revenues to the purchaser of the assets as part of purchased power expenses. Prior to the sale, this component represented the return on our shareholders' investment. As we now purchase most of the power to serve our core customers pursuant to buyback contracts, we reflect these costs in operating expenses as power supply expenses. 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, property tax expense, depreciation expense, and return on investment associated with the electric generating assets.

In the sale of these assets, we generally retained all pre-closing obligations, and the purchaser generally assumed all post-closing obligations. However, with respect to environmental liabilities, the purchaser assumed all pre-closing (with certain limited exceptions) and post-closing environmental liabilities associated with the purchased assets.

While the purchaser assumed pre-closing environmental liabilities, we agreed to indemnify the purchaser, on a limited basis, from losses arising from required remediation of pre-closing environmental conditions, whether known or unknown at the closing. During the third quarter 2000, we received no claim notices related 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.

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 our electric generating assets. For further information regarding the Plan, see Note 13, "Contingencies."

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 April 25, 2000. On May 24, 2000, we retired $182,700,000 of this amount, as follows:

• $48,500,000 of 8.95 percent Bonds due February 1, 2022;
• $20,000,000 of 7.33 percent Secured Series A MTNs due April 15, 2025;
• $15,000,000 of 8.11 percent Secured Series A MTNs due January 25, 2023;
• $44,600,000 of 7.00 percent Bonds due March 1, 2005; and
• $54,600,000 of 8.25 percent Bonds due February 1, 2007.

In addition, we retired at maturity $20,000,000 of 7.20 percent Series A Secured MTNs on June 1, 2000.

These debt retirements were made from the proceeds received from the sale of the electric generating assets.

As part of the Tier II rate filing discussed in Note 5, "Deregulation, Regulatory Matters, and Sale of Electric Generating Assets," we indicated our intention to retire approximately $266,000,000 of debt. The expenses associated with the debt retirements were estimated at approximately $20,000,000. With all retirements of MTNs and Bonds discussed above, the actual amount of debt retired (including the retirement in 1999 of $15,000,000 of 7.875 percent Series B Unsecured MTNs due December 23, 2026) was slightly less than $265,000,000 and the associated expenses were approximately $9,300,000.

On April 4, 2000, a $100,000,000 Revolving Credit Agreement associated with some of our nonutility operations terminated, with no amount outstanding.

During the first nine months of 2000, Altana Exploration Ltd., our wholly owned Canadian subsidiary at that time, made net payments of approximately $7,400,000 in United States dollars (approximately $10,800,000 Canadian dollars) pursuant to its revolving line of credit. The outstanding balance under the agreement at September 30, 2000 is approximately $9,600,000 United States dollars (approximately $14,500,000 Canadian dollars). We sold our oil and natural gas businesses, including Altana Exploration Ltd., on October 31, 2000.

At September 30, 2000, we had notes payable to banks for $80,000,000 at an average annual interest rate of approximately 7.46 percent. On November 8, 2000, we converted these notes, along with an additional $20,000,000 borrowed after the end of the third quarter, to borrowings under the term loan provisions of our Senior Secured Credit Facility discussed in Note 7, "Short-term Borrowing."

At September 30, 2000, we had committed lines of credit consisting of $340,000,000 and uncommitted lines of $70,000,000. Facility or commitment fees on the committed lines of credit are not significant. We have the ability to issue up to $95,000,000 of commercial paper based on the total amount of unused committed lines of credit and revolving credit agreements.

At September 30, 2000, we had outstanding notes payable to banks of $108,500,000 at an average annual interest rate of approximately 7.46 percent. We paid off $100,000,000 of these outstanding notes on November 6, 2000 from proceeds of the sale of our oil and natural gas businesses.

On November 8, 2000, we replaced a $200,000,000 90-Day Credit Agreement with a $400,000,000 5-year Senior Secured Credit Facility for use in our telecommunications operations. The loan facility consists of a $200,000,000 term loan and $200,000,000 revolver, either of which we may use for short- or long-term borrowing. Under this facility, interest is assessed against outstanding balances at a variable rate based on Touch America's credit rating and LIBOR, and annual commitment fees are based on the amount of loans outstanding.

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.

In 1998, our 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 November 8, 2000, we had 105,665,479 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 August 1, 2001. 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.

From August 1, 2000, through November 8, 2000, the bank had acquired for us 1,933,900 shares of our stock under the FEAT program. The average price, including commissions, was approximately $30.96 per share, with prices ranging from $27.26 per share to $33.53 per share, for a total cost of approximately $59,900,000.

If we had fully settled with the bank on November 8, 2000, when the market price of our stock closed at approximately $26.50 per share, the settlement cost would have been approximately $59,900,000 (approximately 1,933,900 shares times average cost of approximately $30.96 per share). A net-share settlement on that date would have increased our outstanding shares of common stock by approximately 326,000 shares ($59,900,000 total cost divided by $26.50 per share market price, less approximately 1,933,900 shares purchased).

For a discussion of Emerging Issues Task Force (EITF) Issue No. 00-19, "Determination of Whether Share Settlement is Within the Control of the Issuer for Purposes of Applying Issue No. 96-13, 'Accounting for Derivative Financial Instruments Indexed to, and Potentially Settled in, a Company's Own Stock,'" see Note 16, "New Accounting Pronouncements."

We compute basic net income per share of common stock for each year based upon the weighted average number of common shares outstanding. In accordance with Statement of Financial Accounting Standards (SFAS) No. 128, "Earnings per Share," diluted net income per share of common stock reflects the potential dilution that would occur if securities or other contracts, mainly options, to issue common stock were exercised or converted into common stock or resulted in the issuance of common stock that shared in our earnings.

For comparative purposes, the following table shows consolidated basic net income per share.

Comprehensive income consists of net income and other comprehensive income. For the nine months ended September 30, 2000 and September 30, 1999, comprehensive income was approximately $18,839,000 and $21,429,000, respectively. For the nine months ended September 30, 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 $3,167,000 in 2000 and increases of $2,096,000 in 1999. We will reclassify the other comprehensive income of our foreign subsidiaries to a translation loss of approximately $12,123,000 (net of taxes) upon realization of the gain from the sale of our oil and natural gas businesses in the fourth quarter 2000.

We used 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. As discussed in Note 1, "October 31, 2000 Divestiture of Oil and Natural Gas Businesses and Pending Divestiture of Remaining Energy Businesses," we sold all of the stock of our oil and natural gas businesses on October 31, 2000 and, therefore, no longer use derivative financial instruments except as discussed below.

By drilling wells and adding compression at our Cobb storage reservoir, we could sell natural gas that had been held in reserve to provide firm storage deliverability to our customers. We therefore contracted to sell, from October 2000 through March 2001, 1,760,000 dekatherms from that reservoir at a monthly market index price. To reduce our exposure to fluctuations of the market index price, we entered into a swap agreement with a counterparty that effectively converts that index price to a fixed price for 903,000 dekatherms associated with these sales from December 2000 through February 2001. In accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation," we defer recognition of gains or losses resulting from the swap until the PSC approves the inclusion of these items in future rate schedules.

In June 1998, prior to our August 1998 decision to exit the electric trading and marketing businesses, The Montana Power Trading & Marketing Company (MPT&M) entered into a derivative financial transaction, called a " swap," in conjunction with one of our electric retail sales contracts. On October 30, 2000, we entered into an additional swap transaction. For further information regarding the swap transactions, see Note 13, "Contingencies," under " Long-term Power Supply Agreements."

A FERC order that preceded our sale of the Kerr Project 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, the purchaser of our electric generating assets 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 the purchaser of our generating assets, 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 provided that its terms were binding against all parties, with the understanding that the signatory parties would jointly draft additional documents as necessary to establish the terms of the settlement in detail. In April 2000, the parties submitted these documents, which we supported, to FERC, and we have paid our settlement payment of approximately $24,000,000 under the Statement of Agreement into an escrow account. If FERC approves these documents in a final non-appealable order, 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.

FERC is reviewing the April 2000 filing, but we do not expect a decision until late 2000 or early 2001.

In accordance with Statement of Financial Accounting Standards No. 5, "Accounting for Contingencies," we recorded a $10,000,000 provision in the third quarter 2000 for future pretax losses relating to long-term power supply agreements. An ongoing power supply agreement with one industrial customer exposes us to most of the expected loss. That agreement obligates us to deliver to that customer one half of its electric energy at a fixed price and the remainder at an index-based price with a cap. When the agreement expires at the end of 2002, the customer has an option to extend the agreement through 2004. If the customer exercises this option, however, only index-based prices with no cap would apply during the extension period.

Since the sale of our electric generating assets, we have been supplying our customers with electric energy purchased through an index-based contract. The volume of electric energy that we are committed to purchase under this index-based contract exceeds our customers' usage estimates.

In June 1998, we entered into a derivative financial transaction, called a "swap", with the industrial customer whose contract exposes us to most of our risk, so that the customer could effectively purchase all of its electricity from us at a fixed rate. At the same time, we entered into a separate fixed-price purchase and related index-based sale of equivalent volumes with other counterparties to hedge that swap and eliminate our exposure to fluctuating market prices. Both the purchase and sale agreements with the other counterparties remain effective through May 2001. During the third quarter of this year, however, our industrial customer increased its electric energy consumption, and wholesale electric prices increased substantially. The combination of these two events rendered the swap and related physical offset less effective.

Specifically, the average monthly purchases of electric energy by the industrial customer whose contract exposes us to most of our risk increased more than 30 percent during the third quarter 2000 compared to the second quarter 2000. Average monthly wholesale electric prices in the Pacific Northwest, based on the Mid-Columbia price index, more than doubled during the third quarter 2000 compared to the second quarter 2000. Because of these two events, the expenses of supplying our customers with electric energy during the third quarter 2000 exceeded the associated revenues earned from these customers and the swap and physical offset by approximately $9,000,000. By contrast, for the entire six months ended June 30, 2000, the expenses incurred to supply these customers exceeded the associated revenues earned from these customers and the swap and physical offset by approximately $2,000,000.

Usage estimates provided by these customers and wholesale electric prices calculated from forward price projections and broker quotes indicate that the costs of supplying electric energy to these customers are expected to continue to result in losses, until the expected closing of the sale of our utility businesses to NorthWestern Corporation in the first half of 2001, although we cannot predict the amount of losses because they are dependent on customer usage. Thus, on October 30, 2000, we entered into a five-month agreement with a counterparty to swap the market-index price at which we purchase electricity for those customers with the fixed price at which we sell it to them. As long as these customers do not materially change their estimated electric usage, this swap will allow us to fix the total cost of supplying their electric energy and thus mitigate the possibility of incurring more loss than the $10,000,000 provision.

We expect to continue to seek other opportunities to mitigate the commodity price risk associated with our power supply agreements.

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.

Touch America has 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 2000 at a cost of approximately $43,800,000, of which we have paid approximately $18,700,000 in 2000. The remaining amount is scheduled for payment before the end of 2000 as various segments of the fiber-optic network under construction, discussed below, are completed. Touch America also entered into an arrangement with Nortel for an estimated $70,000,000 of installations of Nortel's optical electronic equipment related to Touch America's acquisition of properties from Qwest, discussed below under " Investments and Acquisitions," and in Note 4, "Acquisition of Properties from Qwest." At September 30, 2000 Touch America had expanded approximately $33,000,000 of the estimated $70,000,000 installation cost.

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 has begun construction of the Sacramento-Salt Lake City route and expects to complete the route in mid-2001 at an estimated cost of $100,000,000. Touch America will purchase two-thirds of the network and sell it to AT&T and another third party. The joint venture, Sierra Touch America, will therefore retain ownership of one-third of the project, of which each partner will have an equal share. By mid-October 2000, Touch America and Sierra Pacific Communications each contributed approximately $2,600,000 to the joint venture, and Touch America paid approximately $10,000,000 in construction expenditures to the joint venture. The terms of the joint venture agreement give Sierra Touch America a partial interest in the metropolitan fiber networks that Sierra Pacific Communications operates in Reno and Las Vegas.

In January 2000, Touch America and AEP Communications, LLC, a subsidiary of American Electric Power Company, formed a 50-50 joint venture, named American Fiber Touch, LLC, to construct a fiber-optic network between Plano, Illinois and Saint Louis, Missouri. This network will make up 296 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. American Fiber Touch has begun construction of the Plano-St. Louis route and expects to complete the route in the first quarter of 2001 at an estimated cost of $36,000,000. Touch America's portion of this estimated cost will be approximately 50 percent of this amount. The agreement also requires that Touch America advance $6,450,000 to meet the costs associated with construction. By mid-October 2000, Touch America had advanced $3,750,000 for construction costs.

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 organizational and capital structure of ITS did 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 its share of the ITS obligations;
• Upon the closing of the third-party purchase transaction, which occurred on June 30, 2000, INS reimbursed Touch America approximately $7,600,000 for Touch America's cash outlays to ITS, with interest on the funds extended; and
• Touch America withdrew its $14,000,000 letter of credit from ITS upon the closing of the third-party purchase transaction.

In July 2000, Touch America entered into two separate agreements for the use of duct along a route from Minneapolis to Chicago. This route makes up 500 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. One agreement with Adesta Communications, Inc. gives Touch America an exclusive, indefeasible and non-cancelable right to use up to 6 ducts along routes totaling approximately 151 miles within metropolitan Chicago for 24 years, with an option to renew for an additional 20 years at then-existing market rates. Touch America agreed to pay $16,000,000 for these rights, of which $4,000,000 was paid in August 2000. Annual maintenance fees are expected to be approximately $200,000.

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 Personal Communication Services (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 agreed to loan MPCS up to $12,000,000 in interest-bearing notes payable on October 1, 2002, of which the full $12,000,000 had been loaned as of August 2000. In addition, Touch America has guaranteed payment of $7,400,000 in loans owed by MPCS through the year 2007.

Our continuing telecommunications operations design, develop, construct, operate, maintain, and manage a fiber-optic network and wireless facilities; it also sells long-distance, Internet, and private-line services and equipment. Our continuing utility operations purchase, transmit, and distribute electricity and natural gas, and the Colstrip Unit 4 division manages long-term power supply agreements. Continental Energy develops and invests in independent power project and other energy-related businesses. In our discontinued operations, we mine and sell coal and lignite; and explore for, develop, produce, process, and sell crude oil and natural gas and trade crude oil, natural gas, and natural gas liquids. We closed our sale of discontinued oil and natural gas operations on October 31, 2000.

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.

In December 1999, the SEC issued Staff Accounting Bulletin (SAB) No. 101, "Revenue Recognition in Financial Statements." In June 2000, the SEC issued SAB No. 101B, "Second Amendment: Revenue Recognition in Financial Statements", which delays the implementation date of SAB No. 101 until no later than the fourth quarter 2000 for companies with fiscal years beginning after December 15, 1999. As it relates to our companies, SAB No. 101 mainly affects Touch America. SAB No. 101 represents the SEC's summarized interpretations of the application of generally accepted accounting principles to revenue recognition by establishing criteria as to when the SEC considers revenue realized or realizable and earned. We are evaluating SAB No. 101, but we do not expect the adoption of SAB No. 101 to have a material effect on our consolidated financial position, results of operations, or cash flows.

In July 2000, the Financial Accounting Standards Board (FASB) issued EITF Issue No. 00-19, "Determination of Whether Share Settlement is Within the Control of the Issuer for Purposes of Applying Issue No. 96-13, 'Accounting for Derivative Financial Instruments Indexed to, and Potentially Settled in, a Company's Own Stock.'" We are evaluating EITF Issue No. 00-19, but we do not expect the adoption of EITF Issue No. 00-19 to have a material effect on our consolidated financial position, results of operations, or cash flows.

In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133 expands the definition of a derivative and requires that all derivative instruments be recorded on an entity's balance sheet at fair value. 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, meaning that we are not required to adopt SFAS No. 133 until January 1, 2001. In June 2000, the FASB issued SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities," which amends some accounting and reporting standards of SFAS No. 133, but not the January 2001 effective date. We are continuing to evaluate how SFAS No. 138 will affect us.

As discussed in Note 1, "October 31, 2000 Divestiture of Oil and Natural Gas Businesses and Pending Divestiture of Remaining Energy Businesses," we expect to complete the sale of Continental Energy at approximately year-end 2000 and are targeting the end of the first quarter 2001 to complete the sale of our coal business and the restructuring and sale of our utility businesses. We sold our oil and natural gas businesses - including MPT&M - on October 31, 2000. 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, as amended by SFAS No. 138, to have a material effect on our consolidated financial position, results of operations, or cash flows.

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."

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 strategy, revenue and cost trends, cost recovery, cost-reduction strategies and anticipated outcomes, pricing strategies, hedging arrangements, 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;
• Customer usage;
• 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.

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.

On October 24, 2000, in conjunction with the pending divestiture of our energy businesses and our transition to a telecommunications enterprise under Touch America, our Board of Directors decided to eliminate ongoing dividend payments on common stock effective the first quarter 2001. The dividend payment on common stock approved by the Board of Directors in the third quarter 2000 will be paid as scheduled in the fourth quarter 2000.

We expect to expand Touch America's business, leveraging off of the fiber network and selling a broad array of communications products and services primarily focused on wholesale and commercial markets. We expect Touch America to focus its efforts initially in the western United States, but to expand nationally as the network is completed. For a discussion of how we intend to use net proceeds from the sales of our energy businesses, see the "Pending Divestiture of Remaining Energy Businesses" section of Note 1, "October 31, 2000 Divestiture of Oil and Natural Gas Businesses and Pending Divestiture of Remaining Energy Businesses."

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.

Year-to-date earnings were $0.85 per share, $0.07 per share more than year-to-date 1999 earnings of $0.78 per share, an increase of 9 percent. Earnings from continuing telecommunications, utility, Continental Energy, and other operations were $0.35 per share, compared with $0.44 per share last year, a decrease of 20 percent. Earnings from discontinued coal and oil and natural gas operations were $0.50 per share, up 47 percent from the $0.34 per share figure of a year earlier.

Income from Continuing Operations

• Income from our telecommunications operations increased approximately $8,500,000 due to higher revenues resulting from customer growth, primarily attributable to the June 30, 2000 acquisition from Qwest.

• Income from electric utility operations decreased approximately $79,900,000 compared with the nine months ended September 30, 1999, mainly because of the effects of the fourth quarter 1999 sale of our electric generating assets, unplanned outages at our Colstrip Unit 4 plant, and the loss provision that we recorded relating to the long-term power supply agreements discussed in Note 13, "Contingencies," under "Long-term Power Supply Agreements."

• Income from natural gas utility operations decreased approximately $700,000 during the period mainly because increases in rates that became effective on December 10, 1999 and April 1, 2000 were more than offset by increased transmission and distribution and selling, general, and administrative (SG&A) expenses.

• Income from Continental Energy's operations increased approximately $34,100,000 during the period principally because of Continental Energy's pretax gain of approximately $34,300,000 recognized in the second quarter 2000 relating to the sale of its equity interest in the Brazos project.

• Income from our discontinued coal and oil and natural gas operations increased approximately $16,200,000 mainly because of significantly higher commodity prices in the oil and natural gas business.

For comparative purposes, the following table shows consolidated basic net income per share.

For the nine months ended September 30, 2000, income from our telecommunications operations increased approximately $8,500,000 compared with the nine months ended September 30, 1999, mainly due to increased revenues on Touch America's broadband, high-speed fiber-optic and wireless network. The increases are chiefly attributable to the June 30, 2000 acquisition from Qwest of rights and properties associated with Qwest's wholesale, private-line, long-distance, and other t elecommunications services in U S WEST's fourteen-state region related to Qwest's interLATA businesses (collectively, the Qwest Businesses).

Revenues: Revenues increased on Touch America's broadband, high-speed fiber-optic and wireless network for the nine months ended 2000 compared to the same period in 1999. The increases are primarily attributable to the June 30, 2000 acquisition of the Qwest Businesses and the following areas:

• Year-to-date increases in network-service revenues (wholesale and dedicated business line segments) of approximately $78,000,000;

• Year-to-date increases in retail sales revenues (commercial and consumer long-distance) of approximately $32,400,000; and

• Year-to-date increases in revenues of approximately $6,200,000 associated with infrastructure investments for a PCS joint venture for which Touch America provided equipment and engineering and construction services.

Earnings from unconsolidated investments were approximately $10,900,000 lower compared with the same period in 1999. This decrease was the result of Touch America's anticipated losses of approximately $1,900,000 related to its equity investment in the Minnesota PCS, LP joint venture, losses of approximately $1,200,000 related to Touch America's equity investment in the TW Wireless, LLC joint venture, and lower income from dark-fiber transactions of approximately $8,500,000, primarily resulting from the FTV Communications LLC joint venture.

Expenses: Operations and maintenance expenses increased approximately $57,200,000 and SG&A expenses increased approximately $30,800,000, attributable chiefly to customer growth, increased expenses and salaries as we expand Touch America's infrastructure, and increased marketing efforts. Taxes other than income taxes increased approximately $2,000,000 as a result of increased property taxes, representing expansion of Touch America's fiber-optic network, partially offset by revised property tax assessed values for 2000. Depreciation and amortization expense increased approximately $5,900,000 mainly because network expansion and the acquisition of the Qwest Businesses increased depreciable plant in service.

In accordance with Statement of Financial Accounting Standards No. 5, "Accounting for Contingencies," we recorded a $10,000,000 provision in the third quarter 2000 for future pretax losses relating to long-term power supply agreements. For additional information on this loss provision, see Note 13, "Contingencies," under "Long-term Power Supply Agreements."

February 2000 Voluntary Rate Reduction

In January 2000, as a result of the proceeds from the sale of our electric generating assets exceeding book value, we filed a rate reduction request with the PSC for approximately $16,700,000 annually. This rate reduction, which was voluntary pending a final determination by the PSC of our Tier II issues, became effective on February 2, 2000. For additional information on the Tier II filing, see Note 5, "Deregulation, Regulatory Matters, and Sale of Electric Generating Assets," and Note 4, "Deregulation and Regulatory Matters," of our 1999 Annual Report on Form 10-K.

December 1999 Sale of Electric Generating Assets

With the sale of our electric generating assets, we reduced our utility net plant by approximately $497,000,000. Because the Company no longer earns an equity rate of return on those assets, we experienced a decline in utility earnings, as expected. For additional information on the effects of the generation sale, see Note 5, "Deregulation, Regulatory Matters, and Sale of Electric Generating Assets."

Unplanned Outages at Colstrip Unit 4

Colstrip Unit 4 experienced unplanned outages for approximately 45 days during the end of the third quarter and the beginning of the fourth quarter. As a result, we were required to purchase power to supply a long-term contract dedicated to Colstrip Unit 4 in the secondary market at prices inflated by drought, unplanned plant outages, and unseasonably high temperatures. This increased our purchased power costs by approximately $5,100,000 during the nine months ended September 30, 2000 compared to the same period in 1999.

Operating Results

Income from electric utility operations decreased approximately $79,900,000, or 96 percent compared to 1999, primarily because of the effects of the sale of our electric generating assets, unplanned outages at our Colstrip Unit 4 plant, and the loss provision that we recorded relating to the long-term power supply agreements, as discussed above.

Revenues: Revenues decreased for the nine months ended approximately $28,000,000 primarily because of decreased general business revenues, resulting from the voluntary rate reduction discussed above and a weather-related decrease in volumes sold. The effects of the generation sale, including decreased revenues from the absence of sales to other utilities and the associated intersegment transmission revenue from our MPT&M affiliate also contributed to the decrease in revenues. Transmission revenues from PPL Montana and an increase in revenue collected to recover the cost of public-purpose programs in accordance with the Electric Act partially offset the decreased revenues.

Expenses: Overall expenses increased approximately $51,900,000 because of the effects of the following items, most of which, as discussed, were attributable to the generation sale, unplanned outages at our Colstrip Unit 4 plant, and the provision for future losses of $10,000,000 relating to the long-term power supply agreements:

• Power-supply expenses increased approximately $74,200,000 for the electric utility and approximately $2,900,000 for the Colstrip Unit 4 Lease Management Division.

• Power-supply expenses for the electric utility increased mainly because of increased purchased power costs required to supply electric energy to our core customers, along with a higher average price for wholesale power under a purchase contract that we use mainly to supply our industrial customer, as discussed in Note 13, "Contingencies," under "Long-term Power Supply Agreements." A decrease in purchased power resulting from customers choosing other suppliers partially offset this increase. As discussed above, the overall increase in purchased power costs attributable to the generation sale is recoverable in rates.

• Power-supply expenses for the Colstrip Unit 4 Lease Management Division increased mainly because of unplanned outages at our Colstrip Unit 4 plant, as discussed above. As a result, we were required to purchase power, an increase of approximately $5,100,000, to supply a long-term contract dedicated to Colstrip Unit 4 in the secondary market at relatively high prices. A related decrease in transmission expense, approximately $2,200,000, partially offset the increased purchase power costs.

• Transmission and distribution wheeling expenses decreased approximately $8,400,000 primarily because, as discussed above, we are no longer selling surplus generation 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.

• SG&A expenses decreased approximately $5,900,000 mainly due to a decrease in regulatory amortizations and pension expense resulting from the generation sale, decreased costs relating to the Energy Resource Planning information system and the Enterprise Customer-Care information system, and decreased costs relating to the Automatic Meter Reading system. An increase in costs relating to energy efficiency and public-purpose programs in compliance with the Universal System Benefits Charge requirements of the Electric Act partially offset these decreases. 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;

• Taxes other than income taxes and depreciation expense decreased approximately $20,900,000 as a result of the sale of most of our generation plant.

• Provision for future losses relating to long-term contracts increased $10,000,000 as a result of the loss that we recorded in the third quarter 2000 primarily associated with the power supply agreement with an industrial customer.

Regulatory: For information on regulatory matters affecting the electric utility, see Note 5, "Deregulation, Regulatory Matters, and Sale of Electric Generating Assets," under "Regulatory Matters, Electric/PSC."

Natural Gas Utility

Income from operations decreased approximately $700,000, or 10 percent, for the nine-months ended September 30, 2000, compared to the same period in 1999.

Revenues: Revenues increased approximately $6,200,000 mainly because of increases in rates that became effective on December 10, 1999 and April 1, 2000. A weather-related decrease in volumes sold partially offset this increase.

Expenses: Expenses increased approximately $7,000,000 mainly because increased incentive-compensation accruals and miscellaneous administrative items increased SG&A expenses.

Regulatory: For information on regulatory matters affecting the natural gas utility, see Note 5, "Deregulation, Regulatory Matters, and Sale of Electric Generating Assets," under "Regulatory Matters, Natural Gas/PSC."

Income from Continental Energy's operations increased approximately $34,100,000 compared with the nine months ended September 30, 1999 principally because of Continental Energy's pretax gain of approximately $34,300,000 recognized in the second quarter 2000 relating to the sale of Continental Energy's interest in the Brazos project. Continental Energy also experienced improved operating efficiencies at generating plants in which it owns equity interests.

Income from other operations decreased approximately $5,200,000 compared to 1999. Revenues and operation and maintenance expenses decreased primarily because, in the second quarter of 2000, MPT&M transferred all contracts related to the electric utility's supply contract with a large industrial customer to the utility, retroactive to January 1, 2000. Revenues and expenses associated with these contracts included revenues from sales in the secondary markets, expenses for purchased power, and gains associated with a derivative financial instrument entered into to mitigate our commodity price risk. For more information about the industrial-supply contract, see Footnote 3, "Commitments," of our 1999 Annual Report on Form 10-K, under "Sales Commitments," and Item 7A of our Annual Report on Form 10-K, "Quantitative and Qualitative Disclosures About Market Risk," under the "Utility" section of the "Other-Than-Trading Instruments" discussion. SG&A expenses increased mainly because of the acquisition of One Call Locators in January of 2000 and because we have reclassified all general corporate overhead expenses associated with, but not directly attributable to, the discontinued coal and oil and natural gas operations into other operations.

Interest expense decreased approximately $11,200,000 with the net retirement of long-term debt in 1999 and early 2000 and the decrease in the interest expense related to the Kerr Project mitigation liability, which was reduced with our sale of generation assets. Other income - net increased approximately $8,900,000 primarily because of interest income earned on the higher cash balances held in 2000 compared to 1999.

Discontinued Coal and Oil and Natural Gas Operations

As stated in Note 2, "Discontinued Operations," effective September 1, 2000, we accounted for our coal operations and our oil and natural gas operations as discontinued operations. Income from these discontinued operations, net of income taxes, increased approximately $16,200,000, or 43 percent compared to 1999.

Income from our discontinued coal operations decreased mainly because of decreased revenues resulting from lower prices due to contract amendments, negotiated in 1998 and taking effect in mid-2000, relating to the coal supply agreement between Western Energy and the owners of Colstrip Units 3 and 4 and lower sales volumes because of scheduled maintenance and unplanned outages in Colstrip and planned maintenance at the generating plants in Texas.

Income from our discontinued oil and natural gas operations increased mainly because higher commodity prices increased revenues.

We reported consolidated basic net income of $0.23 per share in the third quarter, a decrease of 12 percent when compared with third quarter 1999 consolidated basic net income of $0.26 per share. Earnings from continuing telecommunications, utility, Continental Energy, and other operations for the third quarter 2000 decreased from earnings of $0.11 per share to $0.00 per share mainly because decreased utility earnings more than offset increased telecommunications earnings. Earnings from discontinued operations for the third quarter 2000 were $0.23 per share, an increase of $0.08 per share compared with third quarter 1999 earnings of $0.15 per share.

Income from our continuing telecommunications increased approximately $10,400,000, and income from our continuing electric and natural gas utility operations decreased a total of approximately $39,100,000, principally for the reasons mentioned above in the nine-months-ended discussion. Continental Energy's income from continuing operations remained relatively stable.

Income from our discontinued coal and oil and natural gas operations increased approximately $8,100,000 mainly because of the reasons mentioned above in the nine-months-ended discussion.

Income from our telecommunications operations increased approximately $10,400,000. Higher revenues primarily resulted from customer growth, as discussed below.

Revenues: Revenues increased on Touch America's broadband, high-speed fiber-optic and wireless network for the third quarter 2000 compared to the same period in 1999. The increases are primarily attributable to the acquisition of the Qwest Businesses and growth in the following areas:

• Retail sales revenues (commercial and consumer long-distance) of approximately $37,700,000, compared to approximately $6,300,000 for the third quarter 1999; and

• Increased revenues of approximately $2,100,000 associated with infrastructure investments for a PCS joint venture for which Touch America provided equipment and engineering and construction services.

Earnings from unconsolidated telecommunications investments were approximately $8,600,000 lower compared with the same period in 1999, primarily because of anticipated losses of approximately $1,000,000 related to Touch America's equity interest in the Minnesota PCS, LP joint venture and losses of approximately $1,300,000 related to Touch America's equity interest in the TW Wireless, LLC joint venture. We expect the Minnesota PCS venture to continue to incur losses through 2003 as it expands its network and increases its marketing efforts, and we estimate Touch America's share of these anticipated losses to be an additional $400,000 per month for the remainder of 2000. We expect Touch America's share of the TW Wireless venture's anticipated losses in the fourth quarter of 2000 to be approximately $2,000,000. Earnings from dark-fiber transactions, primarily from the FTV Communications LLC joint venture, were approximately $6,300,000 lower than in 1999 as a result of the substantial completion of FTV's network during the second quarter of 1999.

Expenses: Operations and maintenance expenses increased approximately $50,600,000 and SG&A expenses increased approximately $27,800,000, attributable chiefly to the combination of expenses mentioned above in the nine months ended discussion. Taxes other than income taxes increased approximately $1,100,000, representing increased property taxes as a result of the expansion of Touch America's fiber-optic network. Depreciation and amortization expense increased approximately $4,900,000, representing increased plant in service resulting mainly from the continuing expansion of our fiber network and the acquisition of the Qwest Businesses.

Income from electric utility operations for the third quarter decreased approximately $38,000,000, or 155 percent, compared with income from operations for the third quarter 1999. Third quarter 2000 income from natural gas utility operations, when compared with the same period in 1999, decreased approximately $1,000,000, or 26 percent.

Revenues: Revenues during the third quarter decreased approximately $800,000. Increased general business revenues and transmission revenues from PPL Montana were more than offset by the effects of the generation sale, including decreased revenues from the absence of sales to other utilities and the associated intersegment transmission revenue from our MPT&M affiliate.

Expenses: Overall expenses increased approximately $37,300,000 mainly as the result of the items mentioned above in the discussion of the nine months ended September 30, 2000. These items were primarily attributable to the generation sale, unplanned outages at our Colstrip Unit 4 plant, and the provision for future losses of $10,000,000 relating to the long-term power supply agreements.

Revenues and Expenses: Revenues increased approximately $2,100,000 principally from an increase in rates that became effective on December 10, 1999 and April 1, 2000. Operating expenses increased approximately $3,100,000 mainly for the reasons discussed in the results of the nine months ended September 30, 2000.

Income from Continental Energy's operations increased approximately $1,200,000 compared with the third quarter 1999 mainly because of improved operating efficiencies at generating plants in which Continental Energy owns interests.

Income from other operations decreased approximately $2,000,000. Revenues and expenses changed for the same reasons discussed in the nine-months-ended section above.

Interest expense decreased and Other deductions (income) - net increased primarily due to the reasons mentioned above in the nine-months-ended discussion.