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

For the quarterly period ended June 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 August 7, 2000, the Company had 105,630,296 shares of common stock outstanding.

The accompanying consolidated financial statements of The Montana Power Company for the interim periods ended June 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.

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. 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 June 30, 2000, approximately 1,200 electric customers representing more than 1,750 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 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, and most of the activity in the second quarter 2000 was from residential and small 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 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 the court's decision regarding tracking mechanisms, and we declined to appeal its decision regarding the rate moratorium.

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 2001.

Natural Gas

Through June 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/Federal Energy Regulatory Commission (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. 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 that moved to another supplier in December 1999. In March 1999, we reached a separate settlement with the other cooperative, agreeing to assist the cooperative's move to choice 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.

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 second 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.

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 three 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 second 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 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, expected to take six to twelve months from the end of the first quarter 2000, 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 sale of our energy businesses into Touch America.

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 provides that its terms are 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. The parties have submitted these documents 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, 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, the purchaser of our generating assets 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.

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.

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.

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.

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 June 30, 2000, we paid more in option premiums than we received, resulting in deferred expenses of approximately $800,000.

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. In April and May 2000, we terminated hedging instruments associated with ongoing natural gas sales and transportation contracts and are recognizing total gains of approximately $15,000,000 over the original periods covered by the hedging instruments (May 2000 through December 2000 for a portion of the gain and July 2000 through December 2000 for a portion of the gain). During the second quarter 2000, we recognized as income approximately $1,400,000 of the total gain.

At June 30, 2000, we had swap and option agreements on approximately:

• 1,278,000 barrels, or 42 percent, of our estimated nonutility crude oil and natural gas liquids production through March 2002;
• 21 Bcf, or 66 percent, of our expected delivery obligations under long-term natural gas sales contracts through October 2001; and
• 0.12 Bcf, or 4 percent, of our natural gas production through December 2000.

In addition, at June 30, 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.

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. As of June 30, 2000, we had unrealized mark-to-market losses of approximately $2,200,000 related to these speculative transactions.

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.

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 continues to enter into arrangements with Nortel for installations of Nortel's optical electronic equipment on Touch America's network, including an estimated $75,000,000 of installations related to Touch America's acquisition from Qwest Communications International Inc. (Qwest) discussed below under "Investments and Acquisitions," and in Note 10, "Acquisition of Properties from Qwest."

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's portion of this estimated cost will be approximately $83,000,000, of which it expects to recover approximately 50 percent from AT&T and other third parties. In July 2000, Touch America and Sierra Pacific Communications each contributed approximately $1,400,000 to the joint venture, and Touch America paid approximately $5,700,000 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 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, 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 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 $7,000,000 in loans owed by MPCS through the year 2007.

In March 2000, Touch America signed an agreement with Qwest to acquire Qwest's wholesale, private-line, long-distance, and other telecommunications services in US WEST's 14-state region. Touch America and Qwest closed this transaction on June 30, 2000. For more information on Touch America's acquisition, see Note 10, "Acquisition of Properties from Qwest."

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. For further information regarding the Plan, see Note 2, "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 1, "Deregulation, Regulatory Matters, Sale of Electric Generating Assets, and Proposed Divestiture of Energy Businesses," 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.

Altana Exploration Ltd., our wholly owned Canadian subsidiary, made payments of approximately $10,400,000 in United States dollars (approximately $15,300,000 Canadian dollars) during the first six months of 2000 pursuant to its revolving line of credit, resulting in a balance outstanding at June 30, 2000 of approximately $6,700,000 United States dollars (approximately $10,000,000 Canadian dollars).

For the six months ended June 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 $1,789,000 in 2000, and increases to retained earnings of $2,262,000 in 1999. No current income tax effects resulted from the adjustments, nor do we expect there to be any net income effects until we sell a foreign subsidiary. For the six months ended June 30, 2000, comprehensive income was approximately $65,907,000, as compared to comprehensive income of approximately $61,335,000 for the six months ended June 30, 1999.

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.

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.

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 August 7, 2000, we had 105,630,296 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.

No additional shares were acquired under the program from January 1, 2000 through July 31, 2000. From August 1, 2000, through August 9, 2000, the bank had acquired for us 610,000 shares of our stock under the FEAT program. The average price, including commissions, was approximately $30.51 per share, with prices ranging from $29.78 per share to $31.67 per share, for a total cost of approximately $18,600,000.

On June 30, 2000, in accordance with a previously executed stock purchase agreement, we acquired Qwest's wholesale, private-line, long-distance, and other telecommunications services in US 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 $75,000,000. 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 employed 173 of Qwest's former marketing representatives in the fourteen-state region.

The sources of funds for this transaction were a combination of approximately $147,000,000 in internal funds and approximately $59,000,000 in short-term borrowings from various external sources.

Our June 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. Because the transaction closed on June 30, our Consolidated Statements of Income do not include any depreciation or amortization expense associated with the properties acquired. An independent third party is presently appraising the value of the properties acquired. When this appraisal is complete, we will adjust our allocation of the purchase price among the various balance sheet classifications, if necessary.

As a result of the Qwest acquisition, we will file audited historical and unaudited pro forma financial information with the Securities and Exchange Commission (SEC) on or before September 15, 2000.

At June 30, 2000, we had committed lines of credit consisting of $190,000,000 and uncommitted lines of $90,000,000. Facility/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 June 30, 2000, we had notes payable to banks for $65,000,000 at an average annual interest rate of approximately 7.4 percent.

On June 29, 2000, we developed a $200,000,000 90-Day Credit Agreement for use in our telecommunications operations. This agreement expires on September 26, 2000.

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 to issue common stock were exercised or converted into common stock or resulted in the issuance of common stock that shared in our earnings.

In June 2000, the SEC issued Staff Accounting Bulleting (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. We do not expect the adoption of SAB No. 101 to have a material effect on our consolidated financial position or results of operations.

SFAS Nos. 133, 137, and 138

In June 1998, the Financial Accounting Standards Board (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 presently evaluating how SFAS No. 138 may affect us.

We expect to complete the sales of our energy businesses within six to twelve months from the end of the first quarter 2000, and we expect to sell our unregulated oil and natural gas 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, 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 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.

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.

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 "Proposed Divestiture of Energy Businesses" section of Note 1, "Deregulation, Regulatory Matters, Sale of Electric Generating Assets, and Proposed Divestiture of 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. We have adjusted all 1999 share and earnings-per-share information to reflect the two-for-one stock split effective August 6, 1999.

Year-to-date earnings were $0.62 per share, $0.10 per share more than year-to-date 1999 earnings of $0.52 per share, an increase of 19 percent. Utility earnings were $0.06 per share, compared with $0.18 per share last year, a decrease of 67 percent. Nonutility earnings were $0.56 per share, up $0.22 per share, or 65 percent, from the $0.34 per share figure of a year earlier.

Utility Operating Income

• Income from electric utility operations decreased approximately $38,200,000 compared with the six months ended June 30, 1999, mainly because of the effects of the fourth quarter 1999 sale of our electric generating assets and the voluntary rate reduction that became effective on February 2, 2000.
• Income from our natural gas utility operations increased approximately $300,000 during the period mainly because of increases in rates that became effective on December 10, 1999 and April 1, 2000.

• Income from our telecommunications operations decreased approximately $1,900,000 compared with the first six months of 1999, principally as a result of decreased earnings from unconsolidated investments and increased operating expenses.
• Income from our coal operations decreased approximately $4,000,000 during the period principally because of lower revenues - resulting from a decrease in tons sold as a result of scheduled maintenance and unplanned outages at the generating plants in Colstrip, Montana and scheduled maintenance at the generating plants in Jewett, Texas - and higher reclamation, maintenance, and diesel fuel costs.
• Income from our independent power operations increased approximately $29,300,000 during the period. On June 30, 2000, Continental Energy Services sold its equity interest in a partnership that owned the Brazos project in Cleburne, Texas. As a result of this transaction, Continental Energy recorded a pretax gain of approximately $34,300,000.
• Oil and natural gas operating income increased approximately $11,800,000 during the period, resulting from significantly higher commodity prices.

For comparative purposes, the following table shows consolidated basic net income per share by principal business segment.

Prior to 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 to purchase power to serve our core customers. These costs no longer fluctuate based on actual operating results, but are fixed based on an allocated cost-of-service price. While revenues from sales to our core customers were not affected by the sale, we now pay the profit component of revenues - which previously represented the return on our shareholders' investment - as part of purchased power expenses. Buyback contracts allow us to purchase power necessary to serve our core customers through the transition period ending in 2002. The price 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. We reflect the costs of purchased power under the buyback contracts in operating expenses as power supply expenses.

As discussed above in the "Regulatory Matters" section of Note 1, "Deregulation, Regulatory Matters, Sale of Electric Generating Assets, and Proposed Divestiture of Energy Businesses we filed a request for a rate increase with the PSC in August 2000. In January 2000, as a result of proceeds from the sale of our electric generating assets exceeding the book value of those assets, 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 4, "Deregulation and Regulatory Matters," of our 1999 Annual Report on Form 10-K.

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 Other 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.

Income from electric utility operations decreased approximately $38,200,000, or 68 percent compared to the six months ended June 30, 1999, primarily because of the effects of the sale of our electric generating assets and the voluntary rate reduction discussed above.

Revenues: Revenues decreased approximately $23,500,000 compared with year-to-date 1999, primarily due to the effects of the following items:

• General Business: These revenues decreased approximately $13,500,000, mainly from the voluntary rate reduction discussed above, customers continuing to choose other suppliers, and a weather-related reduction in volumes sold resulting from weather 10 percent warmer than normal and 3 percent warmer than in 1999. An increase in general business prices to recover the cost of public-purpose programs in accordance with the Universal System Benefits Charge requirements of the Electric Act mitigated the effects of decreased revenues. The effect on earnings of the volume decreases from warmer weather and customer choice were partially offset by corresponding decreases in purchased power costs.
• Sales to Other Utilities: These revenues decreased approximately $8,600,000 because, with the sale of our generating assets, we no longer sell surplus generation in the secondary markets. However, our affiliate, The Montana Power Trading & Marketing Company (MPT&M), transferred to the utility an index-based purchase contract that we have been using to supply power to a large industrial customer since the sale of our generating assets. We have been selling all power purchased under the index-based contract not used by our industrial customer in the secondary market at significantly higher prices.
• Other: These revenues increased approximately $3,200,000 mainly from transmitting energy for PPL Montana and customers who chose other suppliers. We reflect transmission revenues from customers who are not supplied by us as Other revenues in the table above. Prior to the generation sale, the energy transmitted for PPL Montana was 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 report transmission revenues from customers who have not chosen other suppliers as General Business revenues.
• Intersegment: These revenues decreased approximately $4,600,000 principally because MPT&M no longer engages in secondary-market sales requiring the use of our lines to transmit surplus generation. As discussed above, an increase in Other revenues from transmitting energy for PPL Montana partially offset this decrease.

Expenses: Power-supply expenses increased; transmission and distribution expenses decreased; selling, general, and administrative (SG&A) expenses decreased; taxes other than income taxes decreased; and depreciation and amortization expenses decreased for the six months ended June 30, 2000, when compared with the six months ended June 30, 1999. These expenses changed because of the effects of the following items, most of which, as discussed, were attributable to the generation sale:

• Power-supply expenses increased approximately $36,300,000, 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 the index-based purchase contract mentioned above. The increase was partially offset by a decrease in purchased power resulting from warmer weather and customers choosing other suppliers. As discussed above, the increase in purchased power costs attributable to the generation sale is recoverable in rates.
• Transmission and distribution wheeling expenses decreased approximately $3,000,000 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 $3,400,000 mainly due to a decrease in regulatory amortizations and pension expense, both related to the generation sale. Increased energy-efficiency and public-purpose program costs in compliance with 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 a total of approximately $15,200,000 as a result of the sale of most of our generation plant.

Regulatory: For more information on our August 2000 filing with the PSC, in which we are seeking increased annual electric revenues, see Note 1, "Deregulation, Regulatory Matters, Sale of Electric Generating Assets, and Proposed Divestiture of Energy Businesses," under "Regulatory Matters."

Natural Gas Utility

The following table categorizes revenues and volumes into General Business Revenues, Sales to Other Utilities, Transportation, and Other.

Income from natural gas operations increased approximately $300,000, or 3 percent, when compared with the six months ended June 30, 1999.

Revenues: Revenues increased approximately $4,100,000, principally due to increased General Business revenues resulting from increased rates and customer growth. Weather-related decreases in volumes sold reduced the effects of the increase. All of our former Large Industrial and Large Commercial customers have chosen other commodity suppliers and, 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 above.

Expenses: Operating expenses - consisting of gas supply costs; other production, gathering, and exploration expenses; transmission and distribution expenses; and SG&A expenses - increased approximately $4,100,000 chiefly because of increased SG&A expenses resulting mainly from increased incentive-compensation accruals and miscellaneous administrative items. Taxes other than income taxes decreased approximately $400,000 principally due to our June 2000 settlement of a property tax dispute with the Montana Department of Revenue. As a result of this settlement, we reduced property tax expense by approximately $500,000.

Regulatory: In August 1999, we filed a natural gas rate case with the PSC that resulted in an interim increase of $7,600,000 effective on December 10, 1999, and an additional increase of $2,800,000 that became effective on April 1, 2000. For more information on our August 2000 filing with the PSC, in which we are seeking increased annual natural gas revenues, see Note 1, "Deregulation, Regulatory Matters, Sale of Electric Generating Assets, and Proposed Divestiture of Energy Businesses," under "Regulatory Matters."

Interest expense decreased approximately $5,700,000 with the net retirement of long-term debt in late 1999 and early 2000 and the decrease in interest expense related to the Kerr Project mitigation liability, which was reduced with our sale of the generation assets. Other Income - Net increased approximately $9,300,000 primarily because of interest income earned on the higher cash balances held in 2000 compared to 1999.