SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
(X) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
for the fiscal year ended December 31, 2000 -OR-
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
for the transition period from ______________ to _______________.
Commission File Number1-4566
THE MONTANA POWER COMPANY
(Exact name of registrant as specified in its charter)
MONTANA | 81-0170530 | ||
(State or other jurisdiction of incorporation or organization) | (IRS Employer Identification No.) | ||
40 East Broadway, Butte, Montana | 59701-9394 | ||
(Address of principal executive offices) | (Zip code) | ||
Registrant's telephone number, including area code(406) 497-3000 | |||
Exhibit Index is found on page 120. | |||
Securities registered pursuant to Section 12(b) of the Act: | |||
Title of each Class | Name of each exchange on which registered | ||
Common Stock | New York Stock Exchange | ||
Pacific Exchange, Inc. | |||
8.45% Cumulative Quarterly Income Preferred Securities, Series A of Montana Power Capital I, a subsidiary of The Montana Power Company | New York Stock Exchange | ||
Securities registered pursuant to Section 12(g) of the Act: | |||
Title of Class | |||
Preferred Stock | |||
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 ___ | |||
The aggregate market value of the voting stock held by nonaffiliates of the Company was $1,684,658,670 at March 16, 2001. | |||
On March 16, 2001, the Company had 103,760,218 shares of common stock outstanding. | |||
DOCUMENTS INCORPORATED BY REFERENCE | |||
None. | |||
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (Section 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K []. | |||
PART I
When we use the terms "Registrant," "Company," "Montana Power," "we," "us," or "our" in this Form 10-K, we mean The Montana Power Company, a Montana corporation, and its wholly owned subsidiaries.
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 Annual Report on Form 10-K. 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 Annual Report on Form 10-K.
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 strategyand planned transition to a telecommunications company, including the sales of our energy businesses, 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 telecommunications 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:
ITEM 1. BUSINESS
GENERAL
The Montana Power Company was incorporated in 1961 under the laws of the state of Montana as the successor to a corporation formed in 1912 through the merger of four regional electric companies. As of the beginning of 2000, we operated or invested in businesses in North America, Europe, and Asia, providing telecommunications and energy products and services.
In recent years, the strongest growth of our business has centered around Touch America, Inc., our telecommunications subsidiary. Touch America's fiber optic network in the United States spanned approximately 18,000 miles at the end of 2000. Touch America plans to expand that network to 26,000 miles by the end of 2001.
We regularly assess our business units and evaluate opportunities to create, develop, and maximize the value of our diverse businesses. Given the tremendous growth in the telecommunications industry generally, and Touch America specifically, our Board of Directors began considering restructuring our business to focus on the telecommunications business. On March 28, 2000, our Board of Directors announced that we would begin the process of divesting our multiple energy businesses, separating them from Touch America.
The decision to divest the energy businesses was based on a belief that the divestiture would allow a focus on Touch America's fast-growing telecommunications business, while enabling the energy companies to grow and add value under new ownership. Our Board of Directors concluded that our structure, which had been created to be responsive to the demands of a regulated utility business, could not continue to meet the demands and ensure the success of the different energy and telecommunications businesses.
Consequently, we retained Goldman, Sachs & Co. to assist us in the sale of our oil and natural gas businesses, coal businesses, independent power production business, and utility business. Goldman, Sachs also assisted us in the restructuring plan of our Company from an energy-related business to Touch America Holdings, Inc. (Touch America Holdings), a telecommunications business with a simple corporate structure more appropriate to a national telecommunications holding company. Based on the restructuring plan, Montana Power is to merge with and into The Montana Power L.L.C., a Montana limited liability company and wholly owned subsidiary of Touch America Holdings. Pursuant to the merger agreement, shareholders of Montana Power are to become shareholders of Touch America Holdings. Immediately following the merger, The Montana Power L.L.C. - constituting Montana Power's utility business - is to be sold to NorthWestern Corporation, a South Dakota-based energy and communications company. As a result of these transactions, Touch America Holdings will become the owner of the telecommunications operating businesses of Touch America.
Shareholder approval is required for us to become, through these proposed transactions, solely a telecommunications company. We plan to schedule a special meeting in the second or third quarter 2001 for our shareholders to consider and vote on these matters.
We entered into a competitive bid process to determine all qualified buyers for the various businesses that we have sold or are in the process of selling. In identifying buyers, our Board of Directors has been particularly focused on achieving strong prices from reputable companies known for integrity, community involvement, and fair treatment of employees. We subsequently entered into agreements with third parties to divest ourselves of the oil and natural gas businesses, the coal businesses, the independent power production business, and the utility business.
Touch America expects to use the cash proceeds from the sale of the oil and natural gas businesses, the coal businesses, the independent power production business, and the utility business to take advantage of opportunities in the telecommunications business. We expect these gross cash proceeds, before income taxes and transaction costs, to total approximately $1,300,000,000.
For additional information on how pursuing these strategies may affect our liquidity and capital resources, see Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A), "Liquidity and Capital Resources." ;
Sale of Oil and Natural Gas Businesses
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 (PanCanadian Petroleum) and one of PanCanadian Petroleum's wholly owned subsidiaries, PanCanadian Energy, Inc. (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 all of the stock of our United States oil and natural gas businesses.
The sale of the oil and natural gas businesses closed on October 31, 2000, with a purchase price of US$475,000,000, subject to post-closing adjustments. In the fourth quarter 2000, we recorded a gain from the sale of these properties of approximately $62,000,000, net of income taxes and a regulatory liability of approximately $32,500,000. We have agreed to share this regulatory liability with our natural gas utility ratepayers as a result of gas stipulation agreements addressing the removal of natural gas production properties from regulation.
For accounting purposes, we have separately reported "net income after income taxes" from oil and natural gas operations in "income from discontinued operations" for all periods presented to reflect the reclassification of these operations as discontinued. With the sale of our oil and natural gas operations on October 31, 2000, our Consolidated Balance Sheet at December 31, 2000 reflects no financial position related to these operations. We have reported cash flows of oil and natural gas operations as "net cash provided by (used for) discontinued operations" - whether associated with operating, investing, or financing activities. For additional information on the accounting treatment afforded our former oil and natural gas operations, see Note 2, "Decision to Sell Energy Businesses."
Pending Sale of Coal Businesses
On September 15, 2000, Entech entered into a Stock Purchase Agreement with Westmoreland Coal Company (Westmoreland) pursuant to which Westmoreland agreed to purchase the companies comprising our coal businesses. The purchase price is $138,000,000, subject to customary closing adjustments. We expect this transaction to close at approximately the beginning of the second quarter 2001.
For accounting purposes, we have separately reported net income after income taxes from coal operations in income from discontinued coal operations for all periods presented to reflect the reclassification of these operations as discontinued. With respect to our Consolidated Balance Sheet at December 31, 2000, we have netted assets and liabilities of coal operations in "Current assets," under "Investment in discontinued coal operations." We have reported cash flows of coal operations as "net cash provided by (used for) discontinued operations" - whether associated with operating, investing, or financing activities. For additional information on the accounting treatment afforded our coal operations, see Note 2, "Decision to Sell Energy Businesses."
Sale of Independent Power Production Business/Continental Energy
On September 19, 2000, Entech entered into a Stock Purchase Agreement with privately held BBI Power Corporation pursuant to which BBI agreed to purchase the stock of Continental Energy Services, Inc. (Continental Energy), our independent power production business. In January 2001, BBI assigned its right to purchase Continental Energy to BBI's wholly owned subsidiary, CES Acquisition Corp.
The sale of Continental Energy closed on February 21, 2001, with a purchase price of $84,500,000, subject to post-closing adjustments. Based on the net book value of Continental Energy, we expect to record a gain in the first quarter 2001 of approximately $33,000,000, net of income taxes.
Our proposed restructuring and sale of all of our electric and natural gas utility business are subject to shareholder approval. Our Colstrip Unit 4 Lease Management Division, which leases 30 percent of Colstrip Unit 4 generation, historically has been reported as part of the Independent Power operations with Continental Energy. That entire segment has not been afforded discontinued operations accounting treatment because we have not yet received the required shareholder approval. Consequently, while we sold Continental Energy in February 2001, we have reported Continental Energy's results of operations, financial position, and cash flows under continuing operations for all periods presented. For additional information on the status of the sales of our energy businesses, including the applicable accounting treatment, see Note 2, "Decision to Sell Energy Businesses."
Pending Sale of The Montana Power L.L.C./Utility Business
On September 29, 2000, we entered into a Unit Purchase Agreement with NorthWestern pursuant to which NorthWestern agreed to purchase The Montana Power L.L.C., which will hold - among other assets, liabilities, commitments, and contingencies - our electric (including Colstrip Unit 4) and natural gas utility business. The consideration will be approximately $1,090,000,000, comprised of cash of $602,000,000 and NorthWestern's assumption of up to $488,000,000 of our debt.
This transaction is to close approximately three months after our proxy statement/prospectus is filed and becomes effective. It is subject to the approval of our shareholders and the Montana Public Service Commission (PSC). In February 2001, the Federal Energy Regulatory Commission (FERC) approved this pending sale. This transaction also is subject to other customary closing conditions.
Because our proposed restructuring and sale of all of our electric and natural gas utility business are subject to shareholder approval, we have not yet implemented discontinued operations accounting treatment for our utility operations. We have included the results of operations, financial position, and cash flows of Colstrip Unit 4 as part of our electric utility operations for all periods presented.
For additional information on the status of the sales of our energy businesses, including our electric and natural gas utility business and the applicable accounting treatment, see Note 2, "Decision to Sell Energy Businesses."
In accordance with our October 31, 1998 Asset Purchase Agreement with PPL Montana, as amended June 29, 1999 and October 29, 1999, we expect to sell our portion of the 500-kilovolt transmission system associated with Colstrip Units 1, 2, and 3 to PPL Montana for $97,100,000. This transaction is expected to close in 2001. The after-tax proceeds that we expect to receive as a result of this transaction will remain with The Montana Power L.L.C., and we expect the gain resulting from the transaction to be addressed in the regulatory process.
On March 15, 2001, the PSC issued a Notice of Commission Action and Opportunity to Comment, stating the PSC's belief that it not only has continuing jurisdiction over our utility that provides fully regulated services to our customers, but also over the electric generating assets that we sold to PPL Montana in December 1999. In its Notice, the PSC stated that our closing of the sale of the electric generating assets to PPL Montana did not preclude the PSC from determining cost-based prices for customers during the extended transition period ending June 30, 2004. In a work session on March 28, 2001, the PSC formally adopted its statement affirming its authority to make determinations regarding the generation assets during the extended transition period, while fostering the financial integrity of our utility.
In addition, the Montana Legislature is currently considering various energy-related proposals to maintain low energy prices. Several of these proposals address who should supply electric energy and what this energy should cost Montana consumers.
We cannot predict the ultimate outcome of these matters or their potential effect on our consolidated financial position, results of operations, or cash flows. For additional information on the PSC's December 21, 2000 decision to extend our obligation to supply remaining customers from July 1, 2002 through June 30, 2004, see Note 5, "Deregulation, Regulatory Matters, and 1999 Sale of Electric Generating Assets," in the "Deregulation" section.
In conjunction with the pending divestiture of the energy businesses and our transition to a telecommunications enterprise, our Board of Directors voted in October 2000 to eliminate the dividend payment on our common stock effective the first quarter 2001. The final quarterly dividend on our common stock was $0.20 per share, payable on November 1, 2000. The Board's decision did not affect dividends on preferred stock. For the foreseeable future, Touch America Holdings does not expect to pay dividends on common stock.
Telecommunications OPERATIONS
Through Touch America, we develop, own, and operate a high-speed fiber optic network spanning 28 states and approximately 18,000 route miles. We also provide wireless services mainly through Personal Communication Services (PCS) and Local Multi-Point Distribution Services (LMDS). On our fiber optic and wireless network, we offer high-speed voice, data, video, and Internet services. We also provide colocation services, lease dark fiber and conduit rights on our network, and offer construction management oversight services for installation of fiber networks. Currently, we serve more than 300,000 customer accounts, including all of the major domestic telecommunications carriers.
As a telecommunications transport services company, our goal is to be the premier provider of advanced, integrated communications solutions for businesses. We strive to:
Our objective is to complete construction of the lowest cost and highest quality fiber optic network in North America and to provide the highest quality voice, data, and video transport services at competitive prices. For information regarding the challenges that we face in accomplishing these goals and objectives, see the "Competitive Environment" section of this "Telecommunications Operations" discussion.
As part of our strategy, on June 30, 2000, we acquired from Qwest Communications International Inc. (Qwest) 250,000 customer accounts. These customers purchase wholesale, private line, long-distance, and other telecommunications services in the former U S WEST fourteen-state region. We also acquired approximately 1,800 route miles of fiber optic network and associated electronics and switches to connect to our then-existing fiber optic network, and 173 sales and sales-support personnel in the fourteen-state region. This acquisition resulted in annual telecommunications revenues that increased by nearly four times, from $86,000,000 in 1999 to $323,000,000 in 2000, and customer accounts that increased by six times, from approximately 50,000 to more than 300,000. These additional customers included national business accounts, wholesale (reseller) customers, medium to large business customers, and small business and residential customers.
Network Expansion
We are continuing to expand our fiber optic network, which is expected to help us achieve our objective of becoming the premier provider of telecommunications transport services. At the end of 2001, we expect our network to consist of approximately 26,000 route miles, spanning 40 states and the District of Columbia and reaching more than 125 major cities.
In October 1999, we entered into a cost-sharing arrangement with AT&T to build a high-speed, long haul, fiber optic network that will span more than 4,300 miles and provide for additional expansion opportunities. The network includes new routes from Minneapolis to Chicago; from St. Louis, Missouri to Plano, Illinois; from Sacramento to Salt Lake City; from Salt Lake City to Denver; and from Denver through Nebraska and Iowa to Chicago. We are installing six conduits on the 4,300-mile route - three for AT&T and three for us. We expect various third parties, including AT&T, to cover approximately 50 percent of our estimated $488,000,000 total project cost.
In January 2000, we entered into a fiber optic and conduit agreement with Velocita (formerly known as PF.Net) under which we will lease approximately 5,900 route miles from them and they will lease approximately 4,400 miles of fiber from us. Prior to commencement of the lease, we will prepay $48,500,000 for the difference in route miles. This agreement will expand our network coverage from Los Angeles to San Diego, Phoenix, El Paso, Dallas, Austin, San Antonio, Houston, New Orleans, Jacksonville, Orlando, Greensboro, Washington D.C., New York City, Tulsa, Kansas City, and St. Louis. The segments of the network included in this agreement are under construction and we expect them to be completed in 2001.
For more information on our alliances, acquisitions, and investments, see Note 14, "Commitments," in the "Telecommunications" section.
Network Design
Important characteristics of our current network are:
In addition, our network is designed to ensure reliability by automatically rerouting traffic to prevent interruptions. This is accomplished through Sonet ring technology and one-for-one design. A Sonet ring is used to instantaneously reroute traffic in the opposite direction on the ring in the event of a fiber cut or other service interruption. The "one-for-one" design ensures reliability because it requires one extra lit fiber for every lit fiber carrying traffic. In the event of an interruption on the traffic-carrying fiber, traffic is immediately switched to the extra lit fiber.
By combining the market-leading technology of Cisco Systems Inc. with our advanced OC-192 technology, we offer powerful new IP generation network applications for customers from small businesses to national accounts and network solution providers.
Products and Services
We market the following products and services:
The telecommunications industry is highly competitive, particularly with respect to price, traffic volumes, and revenue growth. Many of our competitors currently own, and others are constructing, nationwide fiber optic networks. In addition, numerous local and regional long-distance networks exist.
We seek to differentiate ourselves from our competitors in several ways:
Our continued success depends on completion of our planned restructuring and our ability to increase our share of the telecommunications services market by providing high-quality services at competitive prices. Though we believe we currently are positioned favorably to compete as a telecommunications business, declines or concerns about imminent declines in general domestic economic health or other factors could affect our future success. In addition, our continued success depends, in part, on our ability to anticipate and adapt in a timely and cost-effective manner to technological changes.
Specifically, we face the following challenges:
Technological Advances
The development of new, technologically advanced products and services is a complex and uncertain process requiring constant innovation and the ability to anticipate technological and market trends. We continually strive to maintain a low-cost fiber optic network while staying abreast of applicable technological advances.
Business Support Systems
We need effective business support systems to provision, install, and deliver services to our customers, and to bill them in a timely manner for these services. Developing effective business support systems is a complicated undertaking requiring significant resources and expertise as well as support from third-party vendors. We are in the process of implementing a new provisioning, order-entry, and billing system, which we anticipate completing in mid-2001. We must continually update this system to provide an excellent level of customer service. We have also expanded our network operating center that monitors the network and provides full-time customer service.
Strategic Alliances and Acquisitions
We enter into strategic alliances and acquire businesses and technologies to secure long-term, high-capacity traffic on our network, and to enhance our service offerings.We continue to look at alliances and acquisitions that will enable us to extend our network, to provide timely and cost-effective "last mile" services, and to reduce our off-network carrier charges (charges we incur when other carriers must carry our traffic).
Utility operations
We operate a regulated electric and natural gas transmission and distribution utility. Our service territory covers approximately 107,600 square miles, or approximately 73 percent of Montana. Dominant industries operating within our service territory are manufacturing of wood, petroleum, and metal products; metal and coal mining; agriculture; and tourism and recreation. We serve approximately 446,000 customers, or 80 percent of the population within our service territory. For information about how weather affects our utility operations, see MD&A, "Utility Operations."
In addition, through our unregulated Colstrip Unit 4 Lease Management Division, we sell electric energy from our Colstrip Unit 4 operation.
We expect to close the sale of our electric and natural gas utility business approximately three months after the proxy statement/prospectus is filed and becomes effective. The closing of the sale of The Montana Power L.L.C. to NorthWestern will complete our exit from the regulated transmission and distribution utility business, as liabilities and obligations of utility operations will accompany these operations to NorthWestern. For further information on the status of the sales of our energy businesses, see Note 2, "Decision to Sell Energy Businesses."
Our regulated electric utility, which consists principally of electric transmission and distribution systems, delivers electric energy to 191 communities and their surrounding rural areas throughout Montana.
On December 17, 1999, we sold substantially all of our electric generating assets for approximately $758,600,000. We used the sale proceeds to repurchase shares of our common stock, retire long-term debt, and expand Touch America. For additional information on the 1999 sale, its accounting and regulatory implications and our use of sale proceeds, see Note 5, "Deregulation, Regulatory Matters, and 1999 Sale of Electric Generating Assets," and MD&A, "Liquidity and Capital Resources."
Electric Transmission System
Our electric transmission system delivers power to wholesale and retail customers and is interconnected with Bonneville Power Administration (BPA) and Avista Corporation to the west; Idaho Power Company and PacifiCorp to the south; and Western Area Power Administration and PacifiCorp to the east and southeast. We are a member of the Northwest Power Pool and the Western Systems Coordinating Council. These organizations promote reliability of the electric power system, coordinate power system planning, and facilitate a regional transmission planning process.
In April 1996, FERC issued Order No. 888 and Order No. 889 requiring utilities to allow open use of their transmission systems by other utilities and power marketers. Since then, a number of companies have purchased transmission service from us to transmit power across our system under terms, conditions, and rates defined in our FERC open access transmission tariff (OATT), which became effective in July 1996. With electric restructuring, we now provide retail transmission service under both our PSC rate tariffs for customers still receiving "bundled" service and under the OATT for "choice" customers.
On December 20, 1999, FERC issued Order No. 2000, its most recent order regarding Regional Transmission Organizations (RTOs). An RTO is an organization that attempts to capture efficiencies created by combining individually operated transmission systems into a single operation, focusing on operational and strategic transmission issues. Pursuant to Order No. 2000, utilities that own, operate, or control interstate transmission facilities were required to file a proposal with FERC by October 15, 2000, describing the utilities' efforts to participate in an RTO expected to be operational by December 15, 2001. We have been involved in RTO West, made up of BPA and eight utilities in the Northwest. RTO West submitted its initial filing with FERC in October 2000 and expects to file a second proposal during the summer 2001.
Together with five of the utilities involved in RTO West, we are investigating the feasibility of an Independent Transmission Company, called Transconnect, under which the participating companies would transfer their transmission systems to Transconnect in exchange for an appropriate passive ownership interest in Transconnect. Transconnect then would own the combined system as a for-profit entity. In line with FERC Order No. 2000, Transconnect would relinquish the operation of its system to the RTO. We made an initial filing with FERC in October 2000 describing Transconnect and requesting approval of its corporate governance and formation documents.
In 2001, we expect to sell our portion of the 500-kilovolt transmission system associated with Colstrip Units 1, 2, and 3 for $97,100,000. After-tax proceeds that we receive from this sale will remain with The Montana Power L.L.C., and the gain resulting from the sale will be addressed in the regulatory process.
Electric Supply Obligations
Montana's Electric Industry Restructuring and Customer Choice Act (Electric Act) provided our large industrial customers with choice of commodity supply beginning July 1, 1998; pilot supply programs for our residential and small commercial customers beginning November 2, 1998; and choice of supply for all of our customers no later than July 1, 2002. For additional information on Montana's Electric Act and the regulatory environment in which our electric utility operates, see Note 5, "Deregulation, Regulatory Matters, and 1999 Sale of Electric Generating Assets."
Under the Electric Act, we are obligated to continue to supply electric energy to customers in our service territory that have not chosen, or have not had an opportunity to choose, other power suppliers through the transition period. This obligation requires us to have a sufficient power supply to meet these customers' electric loads. Our sales agreement with PPL Montana includes buyback contracts pursuant to which we purchase electric energy from PPL Montana to supply our remaining customers. The buyback contracts are effective through June 30, 2002.
On December 21, 2000, the PSC extended our obligation to supply remaining customers from July 1, 2002 through June 30, 2004. We will act as an intermediary for our customers, purchasing energy in the market and supplying this energy to our customers. The possibility exists that, through legislative action, this obligation may be extended through June 30, 2007. We are working with the Montana Legislature and the PSC to fully recover the default supply costs. For additional information on the effects of deregulation, see Note 5, "Deregulation, Regulatory Matters, and 1999 Sale of Electric Generating Assets."
Through our unregulated Colstrip Unit 4 Lease Management Division, we sell our leased share of Colstrip Unit 4 generation, representing approximately 222 MWh at full load, principally to Duke Energy Trading & Marketing and to Puget Sound Energy under agreements expiring December 20, 2010.
Our regulated natural gas utility purchases, transports, distributes, and stores natural gas. We deliver natural gas to 109 communities throughout Montana.
Natural Gas Requirements
Natural gas-supply requirements in 2000 totaled 18,771 thousands of dekatherms (MDkt), of which 8,267 MDkt were purchased under third-party contracts with Montana suppliers and 1,046 MDkt were purchased under contracts with Canadian suppliers. We purchased a total of 9,458 MDkt, or approximately 50 percent of the natural gas-supply requirements for the year, from our unregulated former affiliates. We estimate that our natural gas requirements for 2001 will be approximately 19,966 MDkt.
Natural Gas Resources
We fulfill our natural gas market requirements through third-party purchase contracts for natural gas delivered within the state of Montana. Approximately 36 percent of our supply requirements are covered under long-term contracts and approximately 40 percent of our supply requirements are covered by one-year contracts, with the balance secured through short-term contracts. Approximately 75 percent of our contractual commitments are priced at current market levels and the remainder are fixed-price contracts. We anticipate that our contracts for natural gas-supply will meet our requirements for 2001.
Gas Transportation
We transported natural gas volumes of 22,953 MDkt in 2000, 24,426 MDkt in 1999, and 27,516 MDkt in 1998. We expect transportation volumes to decrease in 2001 to approximately 21,750 MDkt, due primarily to reduced demand by large industrial, on-system transportation customers. We also anticipate demand for off-system transportation to be weaker in 2001 because on-system demand is projected to be stronger than previous years for storage refill, reducing the amount of on-system gas in the summer that needs to be transported to off-system markets. In addition, because of no price differential between Canada and the Rocky Mountain Region, customers are not incented to transfer natural gas across our system to be sold for a more attractive price in either location.
With the exception of Colstrip Unit 4, either the PSC or FERC approves the rates charged for our electric and natural gas transmission and distribution services. For additional information on the regulatory environment in which our electric and natural gas utility operates, see Note 5, "Deregulation, Regulatory Matters, and 1999 Sale of Electric Generating Assets."
continental energy operations
Through Continental Energy, our former independent power operation previously developed, invested in, and operated independent power projects. For additional information on the February 21, 2001 sale of Continental Energy, see Note 2, "Decision to Sell Energy Businesses."
Coal operations
At our Rosebud Mine in Colstrip, Montana, in the northern Powder River Basin, Western Energy Company (Western Energy) surface-mines coal and, after crushing, sells it without further preparation. Rosebud Mine's primary customers are the owners of the four mine-mouth units in Colstrip, making up approximately 84 percent of Western Energy's 2000 coal sales volumes. During 2000, Western Energy mined and sold 10,405,000 tons, of which 1,355,000 tons were affiliated sales. We estimate production will be approximately 10,850,000 tons in 2001 and 11,500,000 tons in 2002.
Northwestern Resources Company's Jewett Mine, located in central Texas, supplies surface-mined lignite under a long-term lignite sale agreement (LSA) to the two electric generating units located adjacent to the mine. Reliant Energy owns these electric generating units. Northwestern Resources sold 8,165,810 tons in 2000. We estimate Northwestern Resources' production for 2001 will be approximately 8,300,000 tons and approximately 8,000,000 tons annually thereafter.
We expect to close the sale of our coal operations at approximately the beginning of the second quarter 2001. For further information on the status of the sales of our energy businesses, see Note 2, "Decision to Sell Energy Businesses."
Western Energy's Rosebud Mine supplies all of the coal requirements of the Colstrip Units under separate contracts for Units 1 and 2 versus Units 3 and 4. A coal supply agreement (CSA) entered into in mid-1998 settled coal contract disputes and future coal price re-openers with the owners of Colstrip Units 3 and 4. On July 1, 2000, the new pricing provisions of the CSA took effect. These provisions will be fully implemented by July 1, 2001. We expect pretax income of Western Energy in 2001 to decrease approximately $1,500,000 from 2000 levels as a result of the new pricing provisions of the CSA. The Coal Transportation Agreement (CTA) between Western Energy and the owners of Colstrip Unit 3 and 4 also was amended in 1998. The new pricing provisions of the CTA will take effect July 1, 2001. We expect pretax income of Western Energy in 2001 to decrease approximately $1,900,000 (in addition to the CSA decreases described above) from 2000 levels as a result of the new pricing provisions of the CTA.
Reliant Energy is the purchaser of lignite produced by Northwestern Resources. The lignite supply agreement (LSA), as amended, grants Northwestern Resources the right to produce enough lignite to meet Reliant Energy's demand and the right of first refusal for alternative fuels through July 30, 2015. Through June 30, 2002, the LSA provides for cost reimbursement plus approximately $25,000,000 per year from the payment of management and dedication fees charged under the LSA pricing terms.
In late 1998, Reliant Energy and Northwestern Resources settled litigation regarding the pricing terms of the LSA and, in 1999, entered into a Settlement Agreement and Amendment of Existing Contracts. The Settlement Agreement allows Reliant Energy to blend petroleum coke with the lignite at a 20/80 ratio. Recently enacted electric power deregulation in Texas calls for emission reductions for generating units in the state. The effect of these environmental changes on Reliant Energy's ability to use petroleum coke and Powder River Basin coal will continue to be assessed in 2001.
FINANCIAL INFORMATION ABOUT INDUSTRY SEGMENTS
The following table shows, for the last three years, revenues contributed by any class of similar products or services from continuing operations that accounted for 10 percent or more of our consolidated revenues. We have classified earnings from unconsolidated investments in "Other income - net" for all periods presented and, therefore, have not included those earnings in this table.
| Percentage Of Revenues Contributed | ||
2000 | 1999 | 1998 | |
Telecommunications | 32% | 11% | 11% |
Electric Utility | 54% | 70% | 69% |
Natural Gas Utility | 13% | 14% | 14% |
For additional information on the financial results of our segments, see Note 15, "Information on Industry Segments."
ENVIRONMENTAL ISSUES
We are subject to numerous federal, state, and local environmental laws and regulations relating to pollution control and prevention and environmental remediation, including laws and regulations regarding clean air and water and the cleanup of contamination related to past business operations. We believe that we accrue an appropriate amount of estimated costs associated with reasonably foreseeable potential costs related to environmental regulation and cleanup requirements. We do not expect these costs to have a material adverse effect on our consolidated financial position, results of operations, or cash flows.
The Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), and some of its state counterparts, may require us to remove or mitigate adverse environmental effects resulting from the disposal or release of certain substances at sites that we owned or presently own, or at sites where these substances were disposed. We do not know the amount of costs associated with current site remediation efforts or future remediation because of the following uncertainties:
We do not expect the unknown costs to have a material adverse effect on our consolidated financial position, results of operations, or cash flows.
While we are a Potentially Responsible Party (PRP) at the Silver Bow Creek/Butte Area Superfund Site, a Consent Decree approved by the United States District Court for the District of Montana provides us with contribution protection in the event other PRPs claim contribution for cleanup costs they expend. We will continue, however, to address alleged soils contamination of the 30 acres of this site that we own. We do not expect cleanup costs to be material.
Toxic heavy metals in the silts resting behind the dam caused the EPA to include Milltown Dam on its list of priority CERCLA sites. The EPA is continuing its study of this situation, and its Record of Decision that will identify remedial actions and the party or parties responsible for them is expected in 2001. We believe that we have no responsibility for any remediation of any alleged releases at the Milltown Dam because of a specific statutory exemption in the CERCLA legislation.
The Montana Department of Environmental Quality (MDEQ) has listed the reservoir at the Thompson Falls Dam as a Comprehensive Environmental Cleanup and Responsibility Act (CECRA) site - Montana's equivalent of a CERCLA National Priority List site. In 1985 and 1986, researchers found elevated levels of heavy metals in sediments in the reservoir, and the EPA declared the site a "No Further Action" site pursuant to CERCLA. The MDEQ identified the site as a "Low Priority Site" because of the low probability of direct human contact and the lack of evidence of migration to groundwater supplies. Given the low priority designation for this site, we believe that the risk of material remediation is low. We retained pre-closing environmental liability relating to this CECRA listing when we sold the Thompson Falls Dam to PPL Montana.
For further information concerning our environmental liabilities associated with the sale of our generating assets sold to PPL Montana in December 1999, see Note 5, "Deregulation, Regulatory Matters, and 1999 Sale of Electric Generating Assets."
We have voluntarily cleaned up two sites where we operated manufactured gas plants, spending approximately $675,000. We are required to periodically monitor groundwater at the first two sites and report our results to the MDEQ. We have inspected and assessed a third possible cleanup site, but we have not completed discussions with the MDEQ and local regulatory agencies regarding any required cleanup of this site. Although we do not expect that we will be required to remediate the third site, we are likely to be required to periodically monitor the groundwater at this site for an indefinite period. We do not expect the costs of monitoring the three sites, or the possible cleanup of the third site, to be material.
EMPLOYEES
At December 31, 2000, we had 2,549 employees.
FOREIGN AND DOMESTIC OPERATIONS
We believe that financial information relating to the segment information for foreign and domestic operations and export sales is immaterial.
ITEM 2. PROPERTIES
TELECOMMUNICATIONS
Our fiber optic network and its component assets, which we own, lease, or hold pursuant to licenses, are our primary telecommunications properties. We either hold title to, or have proprietary rights in, the route miles constituting our fiber optic network. Those route miles to which we do not have legal title we hold principally through Indefeasible Rights-of-Use (IRU) agreements that extend for the economic life of the fiber.
We believe that we have obtained the necessary licenses, permits, easements, leases, and other rights and interests from third-party landowners and governmental authorities and have completed particular regulatory filings to permit us to install conduit and fiber. These rights and interests generally are nonexclusive and, when possible, we hold them under multi-year agreements with renewal options.
We also own 25 LMDS licenses in various marketing areas within the Pacific Northwest, Rocky Mountain, and Upper Midwest regions of the United States. We have 46 Points of Presence (POPs), facilities where we locate electronic equipment used to connect customers to our currently completed network, in 16 states and various colocation facilities throughout our network. We generally have a license or contractual right, and not legal title, to the property housing the POPs and colocation facilities. See Item 1, "Telecommunications Operations," under the "Network Expansion" and "Network Design" sections, for further information on our network.
We own a general office building, located in Butte, Montana, which houses executive and administrative offices and a network operating center. We also lease 23 other offices located throughout the United States, including a 20,000-square-foot facility in Missoula, Montana, where we will provide call center customer support services as well as handle customer billing and other functions.
Electric Utility
At December 31, 2000, we owned and operated 6,836 miles of electric transmission lines and 16,268 miles of electric distribution lines.Our electric transmission system extends through the western two thirds of Montana.
Our electric resource capacity is provided by 15 Qualifying Facility (QF) contracts that total 101 MWs of firm winter peak capacity and our Milltown Dam with 3 MWs gross capacity. In addition, we have two power-purchase agreements that meet our full energy requirements beyond what we have received from the QFs and Milltown Dam. For additional information on our power-purchase agreements, see Note 14, "Commitments," in the "Purchase Commitments" section.
Colstrip unit 4
Our unregulated Colstrip Unit 4 Lease Management Division leases a 30-percent share of Colstrip Unit 4, an 805 MW (gross capacity) coal-fired power plant located in southeastern Montana. A long-term coal supply contract with Western Energy provides the coal necessary to run the plant.
Natural Gas Utility
At December 31, 2000, we owned and operated 1,990 miles of natural gas transmission lines and 3,804 miles of natural gas distribution mains. We serve our natural gas customers from our transportation system, which extends through the western two thirds of Montana. We also have four natural gas storage fields that enable us to store natural gas in excess of system load requirements during the summer for delivery during winter periods of peak demand, enhancing system reliability. We produce a small amount of natural gas from fields in southern Montana to maintain our natural gas storage leases.
continental energy
When we sold Continental Energy in February 2001, we partially owned - through Continental Energy - nonutility power generation projects operating in Sweetwater, Paris, and Grimes County, Texas; Ferndale, Washington; and Uch, Pakistan. Continental Energy's share of the rated capacity of these projects was 438 MWs. Continental Energy's share of the rated capacity of projects in development was 500 MWs.
Coal
Western Energy has coal leases covering approximately 487,497,000 proved, probable, and recoverable tons of surface-mineable coal reserves at Colstrip, Montana. These tons average less than 1.6 pounds of sulfur dioxide per MMBTU. Approximately 201,620,000 tons of these reserves are committed to present contracts, relating principally to the Colstrip Units. Western Energy's subsidiary, Western SynCoal LLC, owns a patented coal-enhancement process and a coal-enhancement process demonstration plant at the Rosebud Mine that Western Energy operates.
Northwestern Resources has lignite leases in central Texas at the Jewett Mine covering approximately 136,300,000 proved, probable, and recoverable tons of surface-mineable lignite reserves. Northwestern Resources has dedicated all of these reserves to Reliant Energy.
Mortgage and Deed of Trust
A Mortgage and Deed of Trust (Mortgage) subjects our utility's physical properties, except subsidiary company assets and certain properties and assets now owned or hereafter acquired, to a first mortgage lien.
ITEM 3. LEGAL PROCEEDINGS
Paladin Associates, Inc.
We are defendants in litigation initiated in October 1995 by Paladin Associates, Inc. in the United States District Court for the District of Montana. Paladin, a natural gas broker that transported natural gas on our pipeline system, alleges that we and two other defendants violated antitrust law, breached contractual obligations, and committed torts for which Paladin is entitled to collect monetary damages as remedies. Paladin is seeking actual damages that it estimates to be approximately $10,000,000 which, if trebled, would be $30,000,000. In addition, it seeks unspecified punitive damages regarding its tort claims. We deny Paladin's allegations.
On May 4, 2000, the court granted the defendants' motions for summary judgment and dismissed all of Paladin's claims, though the court's final judgment is not yet entered. Entry of a final judgment will initiate the time period during which Paladin can appeal the dismissal.
TCA Building Company
Our subsidiary, Entech, and its subsidiary, Northwestern Resources, are defendants in litigation initiated by TCA Building Company in 1995 in the 261st Judicial District Court in Travis County, Texas. TCA has alleged that Entech and Northwestern Resources breached obligations to assist it in mining its property, that alleged promises underlying these obligations were tainted by fraud, and that Entech and Northwestern Resources wrongfully interfered with a contract and a business opportunity for TCA to sell lignite. TCA alleges that its damages, in addition to unspecified exemplary damages, are between $8,000,000 and $13,500,000. Entech and Northwestern Resources have asserted counterclaims that would substantially reduce these alleged amounts.
The Texas district court has granted motions filed by Entech and Northwestern Resources for summary judgment on all of TCA's claims, and TCA has appealed. The parties have argued the case on appeal, but the court has not yet issued a judgment.
Pursuant to the Stock Purchase Agreement that we entered into with Westmoreland Coal Company, Westmoreland will assume responsibility for defending this litigation relative to the claims against Northwestern Resources when our transaction with Westmoreland closes. While Westmoreland will be responsible for the claims against Northwestern Resources, we will remain responsible for defending this litigation relative to the claims against Entech.
For additional information on legal proceedings, see the "Environmental Issues" section of Item 1, "Business," and Note 13, "Contingencies," in the "Kerr Project" section.
Item 4. Submission of matters to a vote of security holders
None.
Part II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Common Stock Information
Our common stock is listed on the New York Stock Exchange and Pacific Exchange, Inc. The following table presents the high and low sale prices of our common stock, as well as dividends declared, for the years 2000 and 1999. We had 29,823 common shareholders of record on December 31, 2000. As discussed in Part I, our Board of Directors voted in October 2000 to eliminate the dividend payment on common stock. The final quarterly dividend on our common stock was $0.20 per share, payable on November 1, 2000.
Our Board of Directors approved a two-for-one stock split of our outstanding common stock, effective August 6, 1999, for all shareholders of record on July 16, 1999. We have adjusted all share and per-share information in this Annual Report on Form 10-K to reflect this split.
Common stock information:
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| Dividends |
1st Quarter | $65.750 | $34.625 | $0.20 |
2nd Quarter | 64.625 | 35.313 | 0.20 |
3rd Quarter | 39.940 | 28.500 | 0.20 |
4th Quarter | 37.380 | 18.500 | - |
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| Dividends |
1st Quarter | $41.000 | $24.563 | $0.20 |
2nd Quarter | 42.625 | 31.563 | 0.20 |
3rd Quarter | 36.313 | 27.500 | 0.20 |
4th Quarter | 37.375 | 26.813 | 0.20 |
Item 6. Selected FINANCIAL Data, 2000-1996
For additional information on the status of the sales of our energy businesses and our application of discontinued operations accounting to our coal and former oil and natural gas operations, see Note 2, "Decision to Sell Energy Businesses," and the "Results of Operations" section of MD&A. For additional information on how we classify earnings from unconsolidated investments, see MD&A, in the "2000 Compared With 1999" section, under "Consolidated Results."
balance sheet Items
2000 | 1999 | 1998 | 1997 | 1996 | |
(Thousands of Dollars) | |||||
ASSETS: | |||||
Utility plant | $1,636,885 | $1,543,127 | $2,246,847 | $2,216,198 | $2,236,309 |
Less accumulated depreciation |
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Net utility plant | 1,083,611 | 1,048,892 | 1,514,462 | 1,531,238 | 1,531,190 |
Nonutility property | 652,973 | 975,349 | 864,981 | 781,406 | 666,679 |
Less accumulated depreciation |
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Net nonutility property | 613,175 | 655,843 | 567,048 | 520,839 | 410,190 |
Total net plant and property | 1,696,786 | 1,704,735 | 2,081,510 | 2,052,077 | 1,941,380 |
Other assets | 1,120,008 | 1,344,008 | 846,585 | 753,819 | 756,835 |
Total Assets | $2,816,794 | $3,048,743 | $2,928,095 | $2,805,896 | $2,698,215 |
LIABILITIES AND SHAREHOLDERS' | |||||
Common shareholders' equity | $1,123,585 | $1,029,217 | $1,112,103 | $1,037,534 | $ 999,657 |
Unallocated stock held by |
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Preferred stock | 57,654 | 57,654 | 57,654 | 57,654 | 57,654 |
Company obligated mandatory |
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Long-term debt | 309,463 | 618,512 | 698,329 | 653,168 | 633,339 |
Other liabilities | 1,278,319 | 1,298,761 | 1,018,307 | 1,018,485 | 970,925 |
Total Liabilities and |
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Item 6. Selected FINANCIAL Data, 2000-1996 (Continued)
Income Statement Items
2000 | 1999 | 1998 | 1997 | 1996 | |
(Thousands of Dollars) | |||||
REVENUES | $ $ 999,708 | $ 777,172 | $ 770,957 | $ 680,116 | $ 666,466 |
EXPENSES: | |||||
Operations and maintenance | 612,712 | 370,870 | 366,400 | 305,880 | 303,404 |
Selling, general, and |
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Taxes other than income |
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Depreciation, depletion, and |
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922,102 | 639,243 | 616,972 | 532,338 | 509,251 | |
INCOME FROM CONTINUING |
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INTEREST EXPENSE AND OTHER | |||||
Interest expense | 34,408 | 41,593 | 59,373 | 54,133 | 48,267 |
Distributions on company |
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Other income - net | (72,085) | (38,407) | (103,419) | (38,008) | (22,782) |
(32,185) | 8,678 | (38,554) | 21,617 | 25,485 | |
Income from continuing |
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INCOME TAXES | 33,598 | 30,830 | 66,843 | 48,585 | 53,969 |
INCOME FROM CONTINUING |
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DISCONTINUED OPERATIONS: | |||||
Net income from discontinued |
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Net income from discontinued |
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Gain on sale of discontinued |
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Income from discontinued |
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NET INCOME | 199,491 | 150,346 | 165,620 | 128,632 | 119,386 |
DIVIDENDS ON PREFERRED STOCK | 3,690 | 3,690 | 3,690 | 3,690 | 8,358 |
Net income available for |
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Basic earnings per share of | |||||
Continuing operations | $ 0.69 | $ 0.86 | $ 1.11 | $ 0.67 | $ 0.64 |
Discontinued operations | 1.17 | 0.48 | 0.36 | 0.47 | 0.38 |
$ 1.86 | $ 1.34 | $ 1.47 | $ 1.14 | $ 1.02 | |
Diluted earnings per share of common stock |
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Dividends declared per share |
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Average number of common shares |
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Earnings coverage of fixed |
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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
As a result of our restructuring efforts, we have evaluated our operations to determine which segments should be included in continuing or discontinued operations. Because the sale of our utility business remains subject to shareholder approval, we have included the results of operations, financial position, and cash flows of our electric (including Colstrip Unit 4) and natural gas utility business in continuing operations. We plan to schedule a special meeting of our shareholders in the second or third quarter 2001 to consider and vote on the sale and other matters.
We have not afforded Continental Energy discontinued operations accounting treatment since we have historically reported Colstrip Unit 4 with Continental Energy as the Independent Power Group segment. Although we sold Continental Energy on February 21, 2001, the sale of our utility business includes Colstrip Unit 4. Consequently, we have reflected Continental Energy activity in continuing operations for all periods presented.
As a result of our Board of Directors' approval to enter into definitive agreements with respect to our former oil and natural gas and our coal operations, we have applied discontinued operations accounting treatment to these operations, resulting in the following:
Our planned restructuring is expected to transform our Company from a diversified electric and natural gas utility business to a national telecommunications transport services business. Because this restructuring remains subject to various approvals, we can provide no assurance that it will occur in the timeframe contemplated.For additional information on the status of the sales of our energy businesses and our application of discontinued operations accounting to our former oil and natural gas operations and coal operations, see Note 2, "Decision to Sell Energy Businesses."
Consolidated net income available for common stock was $195,801,000 in 2000, compared with $146,656,000 in 1999, and $161,930,000 in 1998.
The following table shows the sources of consolidated net income on a per-share (basic) basis for 2000, 1999, and 1998 and each source's percentage contribution to consolidated earnings per share.
Year Ended December 31 | ||||||
20001 | Percent Contribution | 1999 | Percent Contribution | 1998 | Percent Contribution | |
Continuing Operations | $0.69 | 37% | $0.86 | 64% | $1.11 | 76% |
Discontinued |
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Consolidated | $1.86 | 100% | $1.34 | 100% | $1.47 | 100% |
12000 figures for discontinued operations include gain on sale of discontinued oil and natural gas operations.
2000 Compared with 1999
Net income from continuing operations for 2000 decreased when compared with 1999. While our telecommunications and natural gas utility operations had improved operating results, and "Other income - net" increased as a result of gains recognized by Continental Energy from its unconsolidated investments, decreased income from electric utility operations more than offset these improvements.
We now classify all earnings from our unconsolidated investments in "Other income - net." We previously reported these earnings separately in revenues under "Earnings from unconsolidated investments" and have reclassified all amounts from prior periods to reflect this change.
Income from our telecommunications operations for 2000 nearly doubled when compared with 1999, increasing approximately 93 percent. Our June 30, 2000 acquisition contributed substantially to increased revenues.
For 2000, income from electric utility operations decreased approximately 84 percent when compared with 1999, primarily because of the effects of the December 1999 sale of our electric generating assets. Income from natural gas utility operations increased approximately 71 percent as compared to 1999, mainly due to an increase in rates and a weather-related increase in volumes sold.
Revenues and expenses in other operations decreased principally because these operations no longer reflect the electric trading and marketing activities of our former affiliate, The Montana Power Trading & Marketing (MPT&M), which was sold to PanCanadian.
Interest expense decreased mainly because of the net retirement of long-term debt in 1999 and early 2000, the effects of which were partially offset by a reversal of interest expense in the fourth quarter 1999 related to an environmental liability.
The increase of approximately $33,700,000 in "Other income - net" was principally due to Continental Energy's pretax gain recognized in the second quarter 2000 from the sale of its equity interest in the Brazos project in Cleburne, Texas, and increased interest income. "Other income - net" also includes approximately $1,500,000 of loss from unconsolidated telecommunications investments, as compared with approximately $9,800,000 of earnings for 1999. The decrease resulted primarily from anticipated losses from investments in two wireless joint ventures and a $6,000,000 decrease in dark-fiber transactions, mainly from the FTV Communications LLC (FTV) joint venture.
Income from discontinued operations increased compared with 1999 mainly because of the gain of approximately $62,000,000, net of income taxes and a regulatory liability of approximately $32,500,000, we recorded relating to the fourth quarter 2000 sale of our oil and natural gas operations.
CONTINUING OPERATIONS | |||
Year Ended December 31 | |||
2000 | 1999 | 1998 | |
(Thousands of Dollars) | |||
TELECOMMUNICATIONS: | |||
REVENUES: | |||
Revenues | $ 322,952 | $ 84,903 | $ 87,792 |
Intersegment revenues | 334 | 1,012 | 1,298 |
323,286 | 85,915 | 89,090 | |
EXPENSES: | |||
Operations and maintenance | 179,648 | 34,824 | 27,110 |
Selling, general, and administrative | 66,203 | 12,480 | 12,172 |
Taxes other than income taxes | 5,342 | 3,762 | 3,623 |
Depreciation and amortization | 22,423 | 9,048 | 7,090 |
273,616 | 60,114 | 49,995 | |
INCOME FROM TELECOMMUNICATIONS OPERATIONS | 49,670 | 25,801 | 39,095 |
UTILITY AND COLSTRIP UNIT 4 | |||
ELECTRIC UTILITY AND COLSTRIP UNIT 4: | |||
REVENUES: | |||
Revenues | 535,390 | 531,883 | 526,527 |
Intersegment revenues | 1,036 | 14,221 | 4,722 |
536,426 | 546,104 | 531,249 | |
EXPENSES: | |||
Power supply | 342,098 | 203,790 | 200,203 |
Transmission and distribution | 38,330 | 49,355 | 40,182 |
Selling, general, and administrative | 58,545 | 70,242 | 55,860 |
Taxes other than income taxes | 39,727 | 52,695 | 48,082 |
Depreciation and amortization | 39,559 | 56,282 | 59,213 |
518,259 | 432,364 | 403,540 | |
INCOME FROM ELECTRIC UTILITY AND COLSTRIP UNIT 4 |
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NATURAL GAS UTILITY: | |||
REVENUES: | |||
Revenues (other than gas supply cost revenues) | 91,457 | 78,657 | 75,414 |
Gas supply cost revenues | 37,916 | 32,759 | 31,940 |
Intersegment revenues | 269 | 331 | 425 |
129,642 | 111,747 | 107,779 | |
EXPENSES: | |||
Gas supply costs | 37,916 | 32,759 | 31,940 |
Other production, gathering, and exploration | 1,092 | 2,338 | 2,284 |
Transmission and distribution | 15,093 | 14,635 | 15,556 |
Selling, general, and administrative administrative | 24,371 | 21,944 | 20,191 |
Taxes other than income taxes | 14,227 | 14,333 | 14,084 |
Depreciation, depletion, and amortization | 8,830 | 9,279 | 8,705 |
101,529 | 95,288 | 92,760 | |
INCOME FROM NATURAL GAS UTILITY OPERATIONS | 28,113 | 16,459 | 15,019 |
CONTINUING OPERATIONS (Continued) | |||
Year Ended December 31 | |||
2000 | 1999 | 1998 | |
(Thousands of Dollars) | |||
CONTINENTAL ENERGY: | |||
REVENUES: | |||
Revenues | 1,000 | 1,310 | 1,296 |
EXPENSES: | |||
Operations and maintenance | 10 | 258 | 750 |
Selling, general, and administrative administrative | 2,361 | 1,310 | 1,903 |
Taxes other than income taxes | 1 | 2 | 1 |
Depreciationand amortization | 480 | 414 | 6,316 |
2,852 | 1,984 | 8,970 | |
LOSS FROM CONTINENTAL ENERGY OPERATIONS | (1,852) | (674) | (7,674) |
OTHER OPERATIONS: | |||
REVENUES: | |||
Revenues | 10,993 | 47,660 | 47,988 |
Intersegment revenues | 1,536 | 1,665 | 1,913 |
12,529 | 49,325 | 49,901 | |
EXPENSES: | |||
Operations and maintenance | 1,700 | 50,140 | 51,634 |
Selling, general, and administrative | 19,893 | 10,888 | 13,212 |
Taxes other than income taxes | 1,694 | 1,141 | 1,298 |
Depreciation and amortization | 5,734 | 4,553 | 3,921 |
29,021 | 66,722 | 70,065 | |
LOSS FROM OTHER OPERATIONS | (16,492) | (17,397) | (20,164) |
INTEREST EXPENSE AND OTHER INCOME: | |||
Interest | 34,408 | 41,593 | 59,373 |
Distributions on company obligated mandatorily |
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Other income - net | (72,085) | (38,407) | (103,419) |
(32,185) | 8,678 | (38,554) | |
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME |
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INCOME TAXES | 33,598 | 30,830 | 66,843 |
NET INCOME FROM CONTINUING OPERATIONS | 76,193 | 98,421 | 125,696 |
DIVIDENDS ON PREFERRED STOCK | 3,690 | 3,690 | 3,690 |
NET INCOME FROM CONTINUING OPERATIONS AVAILABLE |
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After completion of our proposed restructuring, we expect Touch America to bea stand-alone company focused on providing telecommunications services, primarily for wholesale and business customers. Because the restructuring of our Company is dependent on many variables, we cannot assure that we will be able to complete our restructuring or that, if our restructuring is completed, Touch America will be successful in meeting its goals. While the telecommunications business is constantly changing and increasingly competitive, we will strive to succeed as we focus on this business.
By the end of 2001, we expect to have approximately $1,600,000,000 in total assets, including approximately $350,000,000 in cash. We expect to have no debt and to generate approximately $670,000,000 in revenues during 2001 with an EBITDA margin modestly exceeding 20 percent, which was our margin during the last six months of 2000. Our calculation of EBITDA consists of earnings or loss before interest income and expense, income taxes, depreciation, and amortization. We calculate the EBITDA margin by dividing our EBITDA by revenues.
We continue to work toward a reduction of off-network carrier charges by integrating our operations and migrating customers onto our network. We also continue to seek to negotiate volume discounts with other carriers. If we succeed in these efforts, we would reduce our off-network costs which, in turn, would increase EBITDA and our EBITDA margin to a level in excess of the 20 percent mentioned above.
We expect to continue to add employees, particularly in the sales and sales-support areas. At the end of 1999, Touch America had approximately 185 employees. As a result of the June 30, 2000 telecommunications acquisition, we added nearly 200 employees, and at the end of 2000, we had increased our employee base to more than 600 employees. By the end of 2001, we expect to have approximately 1,200 employees.
Income from our telecommunications operations in 2000 nearly doubled when compared with 1999, increasing approximately $23,900,000, from $25,800,000 to $49,700,000. EBITDA in 2000 more than doubled when compared with 1999, increasing approximately $37,300,000, from $34,800,000 to $72,100,000. These significant increases resulted primarily from the June 30, 2000 acquisition from Qwest of wholesale, private line, long-distance, and other telecommunications customers in the former U S WEST fourteen-state region.
Revenues
Revenues increased on Touch America's broadband network compared to 1999.
Prior to the June acquisition, our telecommunications business generated approximately 63 percent of its service revenues from network services revenues, principally on our fiber optic network. Prior to the acquisition, retail sales comprised approximately 37 percent of service revenues, which were also provided primarily on our fiber optic network. The acquisition increased our customer base and the geographic distribution of customers, and it also resulted in a significant increase in the percentage of revenues from network services (wholesale and dedicated business line services), the primary focus of the efforts of our expanding sales force. For more information on the June 30 acquisition, see Note 4, "Acquisition of Telecommunications Properties."
In 2000, we began classifying all earnings from our unconsolidated investments in "Other income - net" and have reclassified amounts from prior periods.
The following table shows year-to-year changes in commercial and consumer long-distance revenues for the previous two years.
2000 | 1999 | |
Revenues (Millions of Dollars) | $58 | $4 |
Minutes sold | 867% | 31% |
Price per minute | (59%) | (9%) |
Customer growth | 460% | 26% |
Expenses
Operations and maintenance (O&M) expenses increased approximately $144,800,000 due primarily to higher off-network charges for access to other telecommunications companies' systems to carry the increased traffic discussed above. Selling, general, and administrative (SG&A) expenses increased approximately $53,700,000 as a result of customer growth and the increased costs of expanding Touch America's infrastructure and our sales and marketing efforts. Our sales and sales-support staff increased from approximately 50 at the beginning of the year to approximately 300 by the end of the year. As productivity of this expanding new sales force increases, SG&A as a percentage of revenue is expected to decrease. Taxes other than income taxes increased approximately $1,600,000 and depreciation and amortization expense increased approximately $13,400,000, mainly due to continuing expansion of our fiber optic network and the additional assets acquired in 2000.
As previously discussed, prior to the acquisition, much of our telecommunications services were provided on our network. The increase in customer numbers and geographic distribution of customers has resulted in a significant percentage increase in our use of other telecommunications companies' fiber optic networks. These off-network charges currently represent the single largest operating expense for our telecommunications operations. As we continue to integrate the acquired operations into our Company and further expand our network, we will seek to reduce this dependence on other carriers and correspondingly reduce our off-network charges.
Regulatory
The Telecommunications Act of 1996 provides for significant deregulation of the United States telecommunications industry, including the local exchange and long-distance industries. This legislation remains subject to judicial review and additional Federal Communications Commission rulemaking and, therefore, we are unable to predict the ultimate effect of this regulation on our business.
Telecommunications services remain subject to regulation at the federal, state, local, and international levels. These regulations affect us and our existing and potential customers. Delays in receiving required regulatory approvals or in completing interconnection agreements with local exchange carriers may have a material adverse effect on us. In addition, many regulatory actions are underway or being contemplated by federal, state, local, and international authorities. These future legislative, judicial, and regulatory agency actions could increase our costs, causing the loss of customers and revenues, in addition to impeding or prohibiting our growth.
Weather
As measured by heating degree-days, temperatures in 2000 for our service territory were 10 percent colder than 1999 and level with the historic average. Temperatures in 1999 were 3 percent warmer than 1998 and 9 percent warmer than the historic average.
Accounting for the Effects of Regulation
We apply Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation," to our regulated operations. Pursuant to this pronouncement, we recognize certain expenses and credits as they are reflected in revenues collected through rates established by cost-based regulation. Changes in regulation or changes in the competitive environment could result in our not meeting the criteria of SFAS No. 71. If we were to discontinue application of SFAS No. 71 for some or all of our regulated operations, we would have to eliminate the related regulatory assets and liabilities from the balance sheet and include the associated expenses and credits in income in the period when the discontinuation occurred, unless recovery of those costs was provided through rates charged to those customers in portions of the business that were to remain regulated.
We received proceeds in excess of book value for the sale of our generating assets and our previously regulated natural gas properties and are carrying the excess proceeds as a regulatory liability on the Consolidated Balance Sheet. For additional information on our Tier II filing, see Note 5, "Deregulation, Regulatory Matters, and 1999 Sale of Electric Generating Assets."
The Electric Act identifies regulatory assets and deferred charges that exist because of regulatory practices, as well as above-market costs associated with QF contracts, as recoverable transition costs. Based upon the anticipated recovery of these costs, we believe that discontinuing regulatory accounting treatment would not have a material adverse effect on our future consolidated financial position, results of operations, or cash flows. We expect our regulated transmission and distribution businesses will continue to have cost-based rates and, therefore, meet the criteria of SFAS No. 71.
In accordance with our October 31, 1998 Asset Purchase Agreement with PPL Montana, as amended June 29, 1999 and October 29, 1999, we expect to sell our portion of the 500-kilovolt transmission system associated with Colstrip Units 1, 2, and 3 to PPL Montana for $97,100,000. This transaction is expected to close in 2001. The after-tax proceeds that we expect to receive as a result of this transaction will remain with The Montana Power L.L.C., and we expect the gain resulting from the transaction to be addressed in the regulatory process.
After the completion of our proposed restructuring and sale of our electric and gas utility business to NorthWestern, Touch America shareholders will no longer be responsible for the obligations and liabilities of the utility operations. These liabilities and obligations will accompany the utility operations to NorthWestern.
Electric Utility (including Colstrip Unit 4)
Utility earnings are based on capital invested in utility plant. Because we no longer earn a return on approximately $497,000,000 of utility net plant as a result of the December 1999 sale of electric generating assets, we experienced an expected decline in utility earnings.
Prior to the sale, we billed revenues in part to cover the costs of operating the generating plants, pay taxes and interest, and to earn a return on our shareholders' investment. Since the sale, we continue to bill our core customers for energy supply, but now these revenues cover the costs to purchase power to serve these customers. These costs per MWh no longer fluctuate based on actual operating results, but are fixed based on an allocated cost-of-service price. Buyback contracts allow us to purchase power necessary to serve our core customers through the transition period ending on July 1, 2002. The price in the buyback contracts, which is annually capped at $22.25/MWh, represents our net fully allocated costs of service in current rates, replacing operations and maintenance expense, depreciation expense, property tax expense, and return on investment. We reflect the costs of purchased power under the buyback contracts in operating expenses as power supply expenses.
On December 21, 2000, the PSC extended our obligation to supply remaining customers from July 1, 2002 through June 30, 2004. We will act as an intermediary for our customers, purchasing energy in the market and supplying this energy to our customers. The possibility exists that, through legislative action, this obligation may be extended through June 30, 2007. We are working with the Montana Legislature and the PSC to fully recover the default supply costs.
On March 15, 2001, the PSC issued a Notice of Commission Action and Opportunity to Comment, stating the PSC's belief that it not only has continuing jurisdiction over our utility that provides fully regulated services to our customers, but also over the electric generating assets that we sold to PPL Montana in December 1999. In its Notice, the PSC stated that our closing of the sale of the electric generating assets to PPL Montana did not preclude the PSC from determining cost-based prices for customers during the extended transition period. In a work session on March 28, 2001, the PSC formally adopted its statement affirming its authority to make determinations regarding the generation assets during the extended transition period, while fostering the financial integrity of our utility.
In addition, the Montana Legislature is currently considering various energy-related proposals to maintain low energy prices. Several of these proposals address who should supply electric energy and what this energy should cost Montana consumers.
We cannot predict the ultimate outcome of these matters or their potential effect on our consolidated financial position, results of operations, or cash flows.
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 electric energy for customers who have chosen other commodity suppliers, we continue to earn transmission and distribution revenues for moving their electric energy across our transmission and distribution lines. We reflect transmission revenues as "Other" revenues and distribution revenues as "Distribution Only Revenues."
Revenues and Power Supply Expenses |
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2000 | 1999 | % | 2000 | 1999 | % | |
(Thousands of Dollars) | (Thousands of MWh) | |||||
REVENUES: | ||||||
General Business Bundled | ||||||
Residential | $ 127,816 | $ 127,572 | - | 1,979 | 1,810 | 9% |
Small Commercial, Small |
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|
|
|
|
|
Large Commercial, Large |
| 37,707 |
| 1,157 |
|
|
Irrigation and Street |
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|
|
|
|
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Total | 328,665 | 340,405 | (3%) | 5,730 | 5,523 | 4% |
General Business Distribution | ||||||
Residential | 577 | - | - | 7 | - | - |
Small Commercial, Small |
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|
|
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|
Large Commercial, Large |
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|
|
|
Total | 16,943 | 16,459 | 3% | 2,080 | 1,742 | 19% |
Total General Business Revenues | 345,608 | 356,864 | (3%) | 7,810 | 7,265 | 8% |
Sales to Other Utilities | 122,736 | 148,426 | (17%) | 2,172 | 5,023 | (57%) |
Other | 67,046 | 27,752 | 142% | - | - | - |
Intersegment | 1,036 | 13,062 | (92%) | - | 66 | - |
Total | $ 536,426 | $ 546,104 | (2%) | 9,982 | 12,354 | (19%) |
POWER SUPPLY EXPENSES: | ||||||
Hydroelectric | $ - | $ 21,576 | - | - | 3,692 | - |
Steam | - | 54,969 | - | - | 4,685 | - |
Purchased Power and Other | 342,098 | 127,245 | 169% | 8,737 | 4,626 | 89% |
Total | $ 342,098 | $ 203,790 | 68% | 8,737 | 13,003 | (33%) |
General Business Revenues
General Business Revenues decreased mainly because of a voluntary rate reduction filed with the PSC, effective February 2, 2000, and customers continuing to choose other suppliers. A weather-related increase in volumes sold partially offset this decrease. As discussed above, distribution revenues from customers who have chosen other suppliers are reflected as "General Business Revenues" while the associated transmission revenues are reflected as "Other" revenues in the table above.
Sales to Other Utilities
Sales to Other Utilities decreased mainly due to a decrease in sales of excess generation in the secondary markets related to the 1999 sale of our generating assets and the effects of an agreement with Colstrip Unit 4 and with the Los Angles Department of Water Power (LADWP). In December 1999, an agreement with the LADWP terminated the existing agreement (10 years remaining) and established a new agreement at a lower price. We received approximately $106,000,000 from the LADWP as a result of the termination of the existing agreement and the establishment of the new agreement. While the decrease in price under the new agreement effectively decreased our "Sales to Other Utilities" category, this decrease was offset in the " Other" revenues category from the recognition of revenues related to the prepayment over the remaining term of the agreement.
Other
Other revenues increased mainly because of increased revenues from the LADWP $106,000,000 prepayment discussed above, instruments relating to the long-term power supply agreements discussed in Note 13, "Contingencies," ancillary services revenues from our choice customers, and third-party transmission revenues from energy sales in the secondary market. Prior to the generation sale, our former affiliate, MPT&M, sold this energy in the secondary market, using our lines to transmit the energy across our service territory.
Intersegment
Intersegment revenues decreased principally because, as discussed above, MPT&M no longer sells energy in the secondary market.
Expenses
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 agreement that we use mainly to supply an industrial customer. A decrease in purchased power resulting from customers choosing other suppliers and from decreased fuel expenses because we no longer purchase fuel to operate the generating plants partially offset this increase.
Our agreements to supply electric energy to Duke Energy Trading & Marketing (DETM) and Puget Sound Energy (Puget) subject us to the possibility of unrecoverable losses because, to fulfill our supply obligations, we could have to purchase electric energy at market-based rates. In addition, our agreements to supply electric energy to several large industrial customers contain fixed-price terms and, therefore, subject us to the possibility of unrecoverable losses. For general information regarding the commodity price risk and potential adverse effects that we face as a result of our contractual commitments, see Item 7A, "Quantitative and Qualitative Disclosures About Market Risk," in the "Other-Than-Trading Instruments" section, under "Commodity Price Exposure." For specific information regarding how the DETM and Puget agreements expose us to commodity price risk, see Item 7A, in the "Commodity Price Exposure" section, under "Colstrip Unit 4."
Long-term power supply agreements, primarily an agreement with a large industrial customer, expose us to commodity price risk. That agreement obligates us to deliver to our 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. Until the end of 2002, we must supply this and other industrial customers with electric energy that we purchase through an agreement indexed to the Mid-Columbia (Mid-C) market. As a result, we are exposed to the risk that electric energy we purchase at Mid-C rates could be higher than the fixed sales rates that we receive pursuant to our power supply agreements.
For more specific information concerning the commodity price risk and potential adverse effects arising from our long-term power supply agreements, see Item 7A, in the "Commodity Price Exposure" section, under "Large Industrial Customers," and Note 13, "Contingencies," in the "Long-Term Power Supply Agreements" section.
Transmission and distribution expenses decreased primarily because, as discussed above, we are no longer selling surplus energy generated by us in the secondary markets. As a result, we did not incur the costs associated with using other utility companies' lines outside our service territory to transmit this energy.
SG&A expenses decreased approximately $11,700,000 mainly due to a decrease in regulatory amortizations related to the generation sale, decreased costs relating to the Enterprise Resource Planning (ERP) information system and the Enterprise Customer-Care (ECC) information system,decreased costs for public-purpose programs in accordance with the Universal System Benefits Charge (USBC) requirements of Montana's 1997 Electric Act, and decreased miscellaneous administrative items. We collect the costs associated with the public-purpose programs through a separate component of rates.
Taxes other than income taxes and depreciation expense decreased as a result of the sale of our electric generating assets.
Natural Gas Utility
The following table categorizes revenues and volumes related to our natural gas utility.
Revenues | Volumes | |||||
2000 | 1999 | % | 2000 | 1999 | % | |
(Thousands of Dollars) | (Thousands of Dkt) | |||||
REVENUES: | ||||||
Residential wells | $74,266 | $63,921 | 16% | 12,500 | 12,657 | (1%) |
Small Commercial, Small |
|
|
|
|
|
|
General Business Revenues Revenues: | 110,846 | 94,250 | 18% | 18,692 | 18,531 | 1% |
Less: Gas Supply Cost |
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|
|
|
|
|
General Business Revenues |
|
|
| 18,692 |
|
|
Sales to Other Utilities | 749 | 687 | 9% | 223 | 229 | (3%) |
Transportation | 16,918 | 15,197 | 11% | 22,953 | 24,426 | (6%) |
Other | 860 | 1,282 | (33%) | - | - | - |
Total | $91,457 | $78,657 | 16% | 41,868 | 43,186 | (3%) |
Revenues
All of our former Large Industrial and Large Commercial customers have now chosen other commodity suppliers. While we no longer supply the natural gas for those customers, we still earn transportation revenues from moving their natural gas through our pipelines.
"General Business Revenues," excluding gas-supply cost revenues, increased mainly because of a rate increase effective April 1, 2000 and an interim rate increase effective November 28, 2000. In addition, a weather-related increase in volumes sold and customer growth increased revenues. For additional information on our natural gas PSC filings, see Note 5, "Deregulation, Regulatory Matters, and 1999 Sale of Electric Generating Assets."
Expenses
Expenses, excluding gas-supply costs, increased chiefly because of regulatory amortizations and other miscellaneous administrative items.
Continental Energy's income from operations decreased approximately $1,200,000 mainly due to increased SG&A expenses resulting chiefly from implementation of the ERP information system.
Revenues and O&M expenses in other operations decreased primarily because these operations no longer reflect the electric trading activities of MPT&M. In addition, we purchased One Call Locators, Ltd. in January 2000 and its operating results are included in other operations. One Call's revenues and expenses partially offset the decreases mentioned above and are the primary cause for the increases in SG&A expenses and depreciation and amortization expense. We have reclassified into other operations all general corporate overhead expenses associated with, but not directly attributable to, the discontinued coal and oil and natural gas operations.
Interest expense decreased approximately $7,200,000 with the net retirement of long-term debt in 1999 and early 2000. This decrease was partially offset by the reversal of interest expense in the fourth quarter 1999 related to an environmental liability, which was reduced with the sale of our electric generating assets in December 1999.
"Other income - net" increased approximately $33,700,000 principally due to Continental Energy's pretax gain of approximately $34,300,000 recognized in the second quarter resulting from the sale of its equity interest in the Brazos project in Cleburne, Texas, and increased interest income of approximately $10,000,000. "Other income - net" also includes approximately $1,500,000 of loss from unconsolidated telecommunications investments, as compared with approximately $9,800,000 of earnings for 1999. The decrease results primarily from anticipated losses from investments in two wireless joint ventures and a decrease of approximately $6,000,000 in dark-fiber transactions, mainly from the FTV joint venture.
Our effective income tax rate increased primarily for two reasons: (1) in accordance with the Electric Act, we are allowed to recognize as income accelerated amortizations of investment tax credits (ITCs) during the transition period if our return on equity drops below 9.5 percent and, as a result, we recognized in the fourth quarter 1999 approximately $8,300,000 of ITCs associated with our electric utility's business; and (2) we recognized as income approximately $10,000,000 in unamortized ITCs associated with the December 1999 sale of our electric generating assets to PPL Montana.
DISCONTINUED OPERATIONS | |||
Year Ended December 31 | |||
2000 | 1999 | 1998 | |
(Thousands of Dollars) | |||
DISCONTINUED OPERATIONS: | |||
Income from discontinued coal operations, |
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Income from discontinued oil and natural |
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Gain on sale of discontinued oil and natural |
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NET INCOME FROM DISCONTINUED OPERATIONS |
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Income from our discontinued coal operations decreased mainly because of reduced revenues resulting from lower prices due to contract amendments, negotiated in 1998 that took 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 at Colstrip.
Income from our discontinued oil and natural gas operations increased, despite only ten months of operation in 2000, primarily because of higher commodity prices. The 1999 write-downs of Canadian natural gas properties also contributed to the improved performance in 2000. We also recorded a gain of approximately $62,000,000, net of income taxes and a regulatory liability of approximately $32,500,000, relating to the sale of these properties. For more information on the sale of these properties and the accounting and regulatory implications, see Note 2, "Decision to Sell Energy Businesses," in the "October 31, 2000 Sale of Oil and Natural Gas Operations" section.
1999 COMPARED WITH 1998
Net income from continuing operations for 1999 decreased when compared with 1998. The main cause of the decrease was reduced earnings from unconsolidated investments resulting from several events relating to Continental Energy's equity investments that had materially positive results in 1998. In addition, income from telecommunications decreased - mainly because of the discount associated with a 1999 prepayment - and income from electric utility operations decreased compared with 1998.
Income from telecommunications operations decreased approximately 34 percent compared with 1998. In January 1999, a customer of Touch America exercised its option to prepay, with a discount, all amounts due for the remaining 12-year initial term of a capacity agreement. As a result, Touch America received $257,000,000 and Touch America's income from operations for 1999 was approximately $23,200,000 lower than it would have been without the discounted prepayment. Increased private line and long-distance revenues partially offset the effects of the prepayment.
The electric utility's operating income decreased approximately 11 percent compared with 1998 primarily due to increased volumes of surplus power sold in the secondary markets at higher prices, coupled with revenues earned from transmitting energy for customers who chose other suppliers. Higher expenses - especially SG&A expenses and electric transmission and distribution expenses - more than offset the increased revenues.
The natural gas utility's operating income increased approximately 10 percent compared with 1998 mainly because of customer growth and a 1998 decrease in revenues to reflect a rate refund under a PSC ruling.
Continental Energy's income from operations increased $7,000,000 mainly because of reduced amortization expenses reflecting expenses recorded in 1998 to reduce the value of an equity investment resulting from a contract buyout.
Interest expense decreased approximately $17,800,000 primarily for two reasons: (1) an adjusted environmental liability, and (2) funds were used from the telecommunications prepayment received in January 1999 to reduce short-term borrowings.
"Other income - net" decreased approximately $65,000,000 principally because of the following events, which had positive effects on Continental Energy's 1998 income: (1) a contract settlement between the Bonneville Power Administration and an independent power partnership in which Continental Energy was a partner; (2) the sale of Continental Energy's interest in the Lockport project in New York; and (3) the effects of the buyout of Continental Energy's interest in the Encogen Four project in New York.
Revenues
On January 16, 1999, a Touch America customer exercised its option to prepay, with a discount, all amounts due for the remaining 12-year initial term of a capacity agreement. As a result, Touch America received $257,000,000 and revenues from sales on Touch America's fiber optic network were approximately $23,200,000 less than they would have been had the customer not exercised its option. (The effect for a full year is approximately $24,000,000.) Touch America is recognizing the prepayment in revenues over the remaining 10-year initial term of the agreement.
The increase in operating revenues, after adjusting for the accounting effects of the prepayment, mainly consists of two elements. First, it reflects increased network services revenues of approximately $10,100,000 due to higher revenues from sales of fiber capacity. Second, retail sales revenues, including Internet service and equipment servicerevenues, increased approximately $7,800,000 as a result of increased long-distance customer and minute sales and customer growth.
The following table shows year-to-year changes in long-distance revenues for the previous two years.
1999 | 1998 | |
Revenues (Millions of Dollars) | $4 | $3 |
Minutes sold | 31% | 43% |
Price per minute | (9%) | (15%) |
Customer growth | 26% | 61% |
Expenses
O&M expenses increased approximately $7,700,000 as a result of increased network services and retail sales revenues. Depreciation and amortization expense increased approximately $2,000,000 as a result of an increase in plant.
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 electric energy for customers who have chosen other commodity suppliers, we continue to earn transmission and distribution revenues for moving their electric energy across our transmission and distribution lines. We reflect transmission revenues as "Other" revenues and distribution revenues as "Distribution Only Revenues."
Revenues and Power Supply Expenses |
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1999 | 1998 | % | 1999 | 1998 | % | |
(Thousands of Dollars) | (Thousands of MWh) | |||||
REVENUES: | ||||||
General Business Bundled | ||||||
Residential | $ 127,572 | $ 125,523 | 2% | 1,810 | 1,927 | (6%) |
Small Commercial, Small |
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Large Commercial, Large | 37,707 | 82,667 |
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| (49%) |
Irrigation and Street |
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Total | 340,405 | 387,051 | (12%) | 5,523 | 7,017 | (21%) |
General Business Distribution Only Revenues: | ||||||
Small Commercial, Small |
|
179 |
|
|
|
|
Large Commercial, Large |
| 2,034 |
|
| 252 |
|
Total | 16,459 | 2,213 | 644% | 1,742 | 261 | 567% |
Total General Business Revenues | 356,864 | 389,264 | (8%) | 7,265 | 7,278 | - |
Sales to Other Utilities | 148,426 | 115,332 | 29% | 5,023 | 3,591 | 40% |
Other | 27,752 | 21,931 | 27% | - | - | - |
Intersegment | 13,062 | 4,722 | 177% | 66 | 125 | (47%) |
Total | $ 546,104 | $ 531,249 | 3% | 12,354 | 10,994 | 12% |
POWER SUPPLY EXPENSES: | ||||||
Hydroelectric | $ 21,576 | $ 22,266 | (3%) | 3,692 | 3,742 | (1%) |
Steam | 54,969 | 50,952 | 8% | 4,685 | 4,516 | 4% |
Purchased Power and Other | 127,245 | 126,985 | - | 4,626 | 3,758 | 23% |
Total | $ 203,790 | $ 200,203 | 2% | 13,003 | 12,016 | 8% |
General Business Revenues
Revenues from electric utility operations increased in 1999, while "General Business Revenues" decreased primarily because of a decrease in revenues from the Large Industrial Customer classification as these customers continued to choose other commodity suppliers. An increase in prices to recover the cost of public-purpose programs in accordance with the Electric Act lessened the effects of decreased revenues from Large Industrial Customers.
Sales to Other Utilities
Revenues from "Sales to Other Utilities" increased because of increased volumes sold in the secondary markets at higher average prices. We had more energy available to sell in the secondary markets because of increased plant availability as a result of less downtime for repairs and maintenance and lower consumption attributable to customers continuing to choose other suppliers.
Other
"Other" revenues increased mainly because of revenues earned for transmitting energy for customers who chose other suppliers. Prior to the Electric Act, we classified transmission revenues as "General Business Revenues." We now reflect transmission revenues from customers who chose other suppliers as "Other" revenues, while we still report transmission revenues from customers who have not chosen other suppliers as "General Business Revenues."
Intersegment
"Intersegment" revenues increased because of the revenues associated with MPT&M using our lines to transmit energy that it sold in the secondary markets. While we reflect sales in the secondary markets as "Sales to Other Utilities," as of July 1, 1998, we began reflecting revenues earned from the transmission of the energy sold to other utilities in the "Intersegment" line of the segmented schedule of revenues and expenses. The corresponding transmission volumes are the same volumes associated with the sale of energy in the secondary markets. Therefore, we report these volumes in the "Sales to Other Utilities" line in the table above.
Expenses
Power supply expenses increased primarily due to increased plant availability. Transmission and distribution expenses increased because of costs associated with using other companies' lines outside our service territory to transmit the energy sold in the secondary markets. Property taxes increased because of additional plant and higher assessed property values. Depreciation and amortization expense decreased because of expenses incurred in 1998 associated with software costs and property held for future use.
SG&A expenses increased approximately $14,400,000 mainly because of the following items:
The following table categorizes revenues and volumes related to our natural gas utility.
Revenues | Volumes | |||||
1999 | 1998 | % | 1999 | 1998 | % | |
(Thousands of Dollars) | (Thousands of Dkt) | |||||
REVENUES: | ||||||
Residential wells | $63,921 | $61,666 | 4% | 12,657 | 11,505 | 10% |
Small Commercial, Small |
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General Business Revenues Revenues: | 94,250 | 93,508 | 1% | 18,531 | 17,511 | 6% |
Less: Gas Supply Cost |
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General Business Revenues |
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Sales to Other Utilities | 687 | 606 | 13% | 229 | 200 | 15% |
Transportation | 15,197 | 14,844 | 2% | 24,426 | 27,320 | (11%) |
Other | 1,282 | (1,604) | 180% | - | - | - |
Total | $78,657 | $75,414 | 4% | 43,186 | 45,031 | (4%) |
Revenues
Increased revenues from customer growth and increased rates to recover higher gas-supply costs were offset by a decrease in revenues from industrial customers continuing to choose other commodity suppliers. As mentioned in the "2000 Compared With 1999" discussion, all of our former Large Industrial and Large Commercial customers have now chosen other commodity suppliers. "Other" revenues increased because of a 1998 decrease in revenues to reflect a rate refund in compliance with a PSC ruling.
Expenses
SG&A expenses increased chiefly because of expensed costs for implementing the ERP and ECC information systems. An increase relating to energy efficiency and public-purpose programs mostly offset a decrease in other administrative costs.
Continental Energy's operating income increased $7,000,000 mainly as a result of lower amortization expense in 1999 than in 1998 because Continental Energy recorded amortization expense of approximately $5,900,000 in 1998 to reflect the reduced value of its investment in the Encogen Four project as a result of the contract buyout.
With the sale of our generating assets, we will no longer be responsible for mitigating costs associated with Kerr Project operations after the date of the sale. We had previously recorded the present value of mitigation expenditures over the life of the license. From the date of the initial entry through the date of the sale, interest expense had been recorded to adjust the mitigation liability to current dollars. The mitigation liability has now been adjusted, and accrued interest expense was reversed. This adjustment to interest expense, coupled with the use of funds from the January 1999 telecommunications prepayment to reduce short-term borrowings, accounted for the majority of the decrease in interest expense of approximately $17,800,000. For additional information on the Kerr Project, see Note 13, "Contingencies."
"Other income - net" decreased approximately $65,000,000 mainly because of reduced earnings from unconsolidated investments. Earnings from unconsolidated independent power investments decreased approximately $68,500,000 mainly because of the three events discussed at the beginning of the MD&A section, "1999 Compared With 1998," under "Interest expense and other income - net."
Partially offsetting these reduced earnings from unconsolidated investments was increased interest income on investments of approximately $4,300,000.
The ITCs that we recognized in the fourth quarter 1999, as mentioned in the discussion of "2000 Compared With 1999," accounted for the majority of the decrease in our effective income tax rate for 1999 as compared with 1998.
Income from coal operations increased due to higher revenues resulting from increased tons sold and the effects of a one-time refund issued in the third quarter 1998 by Western Energy to Colstrip Units 3 and 4 customers that resulted in decreased 1998 revenues.
Increased income from oil and natural gas operations resulted from higher oil and natural gas prices and increased natural gas volumes sold. These higher prices and increased volumes more than offset 1999 decreases in oil volumes sold and write-downs of our Canadian natural gas properties.
Operating Activities
Net cash used for operating activities was $55,877,000 in 2000, compared to net cash provided by operating activities of $660,183,000 in 1999, and $255,677,000 in 1998. The current year decrease of $716,060,000 was attributable mainly to the following:
Investing Activities
Net cash used for investing activities was $133,877,000 in 2000, compared to net cash provided by investing activities of $306,504,000 in 1999 and net cash used for investing activities of $159,552,000 in 1998. The current year decrease of $440,381,000 was due primarily to increased capital expenditures, mainly related to the acquisition of telecommunications properties and joint network construction with AT&T, and a decrease in proceeds from the sales of property and investments related to the 1999 sale of our electric generating assets. Proceeds received from the sale of our oil and natural gas businesses partially offset this decrease.
Forecasted capital expenditures for 2001 and capital expenditures during the prior three years are as follows:
Forecasted | Actual | ||||
2001 | 2000 | 1999 | 1998 | ||
Continuing Operations: | |||||
Telecommunications | $ 448,000 | $ 554,119 | $ 153,617 | $ 56,203 | |
Utility | 20,0001 | 50,264 | 63,618 | 83,927 | |
IPG | - | 12,230 | - | 10,725 | |
Other | - | 27,603 | 15,957 | 189 | |
Total | $ 468,000 | $ 644,216 | $ 233,192 | $ 151,044 | |
1 The utility's capital expenditures for 2001 are forecast through the anticipated closing of the sale of our utility business. This sale is targeted to close approximately three months after the proxy statement/prospectus is filed and becomes effective.
Touch America expects to invest $448,000,000 in 2001. The majority of the capital expenditures will be invested to expand and develop Touch America's fiber optic network. Approximately $321,000,000 will be invested in fiber installation to build out the estimated 26,000-mile network, with another $86,000,000 invested in electronics to light the network. See Item 1, "Business," under the "Telecommunications Operations" section, and Note 14, "Commitments," for further discussion of Touch America's projects and commitments. We intend to invest the majority of the utility's capital budget in our electric and natural gas transmission and distribution systems.
We estimate that internally generated funds for 2001, including proceeds from the sale of our remaining energy businesses, will average 100 percent of Touch America's capital expenditures, and 481 percent of our utility's capital expenditures.
Financing Activities
Net cash used for financing activities was $246,236,000 in 2000, compared to $422,396,000 in 1999 and $88,779,000 in 1998.
For information regarding our repurchase of common stock, see Note 7, "Common Stock."
Dividends paid on common and preferred stock were $67,053,000 in 2000, $90,902,000 in 1999, and $91,598,000 in 1998. During 2000, our regular quarterly dividend level was 20 cents per share of outstanding stock or 80 cents per share on an annual basis. As discussed in Item 1, "Business," our Board of Directors voted in October 2000 to eliminate dividend payments on common stock effective the first quarter 2001, reflecting our transition to a telecommunications enterprise. The final quarterly dividend on our common stock was $0.20 per share, payable to shareholders of record on November 1, 2000.
Our consolidated borrowing ability under our Revolving Credit and Term Loan Agreements was $490,000,000, of which $390,000,000 was unused at December 31, 2000. On April 4, 2000, our $100,000,000 Revolving Credit Agreement for some of our nonutility operations terminated with no amounts outstanding. In 2000, we entered into a $30,000,000 Revolving Credit Agreement that expires on June 28, 2001 and a $200,000,000 90-Day Credit Agreement for use in our telecommunications operations that expired on November 8, 2000. At that time, Touch America entered into a five-year $400,000,000 Senior Secured Credit Facility consisting of a $200,000,000 Revolving Credit Agreement and a $200,000,000 Term Loan Agreement for use in our telecommunications operations.
Our long-term debt as a percentage of capitalization was 20 percent during 2000, 35 percent in 1999, and 37 percent in 1998. The current year ratio decreased due to the use of the generation sale proceeds to repurchase long-term debt. Approximately $169,054,000 of long-term debt will mature during the year 2001. The ratio could decrease during 2001 with the proceeds from the sales of our energy businesses available to repurchase long-term debt. We have also entered into long-term lease arrangements and other long-term contracts for sales and purchases that are not reflected on the Consolidated Balance Sheet. For additional information on the long-term lease arrangements and other long-term contracts, see Note 14, "Commitments."
For further information on our financing activities, see Note 10, "Long-Term Debt," and Note 11, "Short-Term Borrowing."
For the year ended December 31, 2000, our ratio of earnings to fixed charges was 2.39 times compared to 2.49 times for 1999 and 2.84 times for 1998. We used net income and income taxes only from continuing operations to calculate earnings. Fixed charges include interest from continuing and discontinued operations, the implicit interest of Colstrip Unit 4 rentals, and one third of all other rental payments.
We believe that, at currently anticipated levels, inflation will not materially affect our results of operations.
For a discussion of environmental issues and how they affect us, see Item 1, "Business," under the "Environmental Issues" section.
For information on new accounting pronouncements and how they affect us, see Note 16, "New Accounting Pronouncements."
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Our energy commodity activities and other investments and agreements expose us to the market risks associated with fluctuations in commodity prices, interest rates, and changes in foreign currency translation rates. We specify below what these risks are to our business and estimate what could occur under various adverse market conditions. Because we base our estimates on assumptions only, actual results of operations could differ materially from our estimates. These disclosures indicate only reasonably possible losses and do not necessarily indicate expected future losses.
TRADING INSTRUMENTS
We discuss the derivative financial instruments that we use to manage commodity price risk in our electric and natural gas utility businesses in Note 1, "Summary of Significant Accounting Policies," in the "Derivative Financial Instruments" section, in Note 13, "Contingencies," in the "Long-Term Power Supply Agreements" section, and below in "Other-Than-Trading Instruments." We do not use derivative financial instruments to hedge against exposure to fluctuations in interest rates or foreign currency exchange rates. However, we formerly had investments in independent power partnerships, some of which had used derivative financial instruments to hedge against interest rate exposure on floating rate debt. For further information on the February 21, 2001 sale of our independent power production business, see Note 2, "Decision to Sell Energy Businesses," in the "Sale of Continental Energy" section.
At December 31, 1999, we included derivative financial contracts relating to crude oil, natural gas, and natural gas liquids in the calculation of our Value at Risk limit, which was less than $2,000,000. At December 31, 2000, we no longer owned oil and natural gas operations and, therefore, had no crude oil, natural gas, or natural gas liquids trading and marketing operations.
OTHER-THAN-TRADING INSTRUMENTS
Continuing Operations
Qualifying Facilities
The Public Utilities Regulatory Policies Act (PURPA) requires a public utility to purchase power from QFs at a rate equal to what it would pay to generate or purchase power. The electric utility has 15 long-term QF contracts with expiration terms ranging from 2003 through 2032 that require us to make payments for energy capacity and energy received at prices established by the PSC. Because the wholesale electric energy market does not extend beyond 18 months, and we do not have bids on the sale of the QFs, we cannot make a meaningful estimation of the QFs' market value at December 31, 2000. These contracts are included in our Tier II filing with the PSC and anticipated sale of our utility business to Northwestern Corporation.
Wholesale Transition Service Agreements
Our electric utility also entered into two Wholesale Transition Service Agreements (WTSAs), effective December 17, 1999, with PPL Montana. These agreements enable us to fulfill our obligation to supply electric energy until July 2002 to those customers who have not chosen another supplier. Both agreements set the price of electric energy at a Mid-Columbia (Mid-C) index, with a monthly floor and an annual cap, and thus limit our exposure to price fluctuations. Under both agreements, the annual cap is $22.25/MWh, which has been in effect for most of 2000 because wholesale electric energy prices in the Pacific Northwest have been higher than this amount.
For a discussion of the PSC's March 15, 2001 issuance of a Notice of Commission Action and Opportunity to Comment, stating the PSC's belief that it not only has continuing jurisdiction over our utility that provides fully regulated services to our customers, but also over the electric generating assets that we sold to PPL Montana in December 1999, and various energy-related proposals currently under consideration by the Montana Legislature regarding the supply and cost of electric energy in Montana, see Item 1, "Business," in the "Notice of PSC Action and Legislative Proposals" section, and Item 7, MD&A, in the "Utility Operations" section, under "Electric Utility (including Colstrip Unit 4)." We cannot predict the ultimate outcome of these matters or their potential effect on our consolidated financial position, results of operation, or cash flows.
Colstrip Unit 4
We sell the leased share of Colstrip Unit 4 generation principally to Duke Energy Trading & Marketing (DETM) and to Puget Sound Energy (Puget) under agreements that expire at the same time as the initial term of our sale-leaseback agreement of Colstrip Unit 4. In December 1999, we agreed with the Los Angeles Department of Water & Power (LADWP) to terminate the 11 remaining years of the then-existing agreement, and entered into a new agreement to provide LADWP 111 MWs of capacity and energy from December 1999 to December 2010, at scheduled rates. We received $106,000,000 from the LADWP as consideration for the termination and establishment of the agreements, and LADWP immediately assigned the new agreement to DETM. The $106,000,000 reimbursed us for DETM's share of the fixed cost associated with the leased property and was recorded by us as deferred revenue, to be amortized over the life of the agreement. The scheduled rates of the new agreements with DETM and Puget are based on an estimation of Colstrip Unit 4's variable costs over the life of the agreements.
These agreements expose us to commodity price risk in two ways:
Based on the net present value of forecasted income discounted at our December 31, 2000 short-term borrowing rate of 8.05 percent, we estimate that the fair market value of these agreements would be a negative $48,200,000, which approximates the net liability recorded for our investment in Colstrip Unit 4 at December 31, 2000.
Large Industrial Customers
Several long-term power supply agreements with large industrial customers expose us to commodity price risk, to the extent that a portion of the electric energy that we are required to sell to these customers at fixed rates is purchased by us at rates indexed to a wholesale electric market, which can be higher than the fixed sales rate. We seek to mitigate our exposure to losses on these agreements with financial derivative instruments called "price swaps" and offsetting electric energy purchase and sales agreements.
Since June 1998, we have had a price swap agreement with our industrial customer whose agreement exposes us to most of the risk. The price swap converts a maximum of 43 MWs of the Mid-C index price of our supply agreement with that customer to a fixed price through May 31, 2001. At the same time, we entered into a separate fixed-price purchase and related Mid-C index-based sale of a maximum of 40 MWs of electric energy with two different counterparties, through May 31, 2001, to hedge electric energy purchased at the Mid-C index used to supply our industrial customers. Because the Mid-C index price is used for both the MWs purchased for the large industrial customer and the MWs sold to one of the counterparties, an increase in the Mid-C index would not change the effectiveness of our hedge of 40 MWs. However, if our industrial customer's consumption were to exceed a volume requiring more than the 40 MWs hedged, we would be exposed to additional losses from supplying this customer.
During the third quarter 2000, our industrial customer whose agreement exposes us to most of the risk increased its electric energy consumption by approximately 30 percent, and wholesale electric prices increased substantially. Because of these two events, the expenses of supplying electric energy to that industrial customer and, to a lesser extent, other industrial customers exceeded the associated revenues earned from these customers, the price swap, and fixed-price purchase/Mid-C sales hedge by approximately $8,400,000 for the third quarter. To mitigate future losses, we entered into another price swap with a counterparty that effectively hedges 35 MWs of the anticipated Mid-C based purchases to supply our industrial customers through March 31, 2001. Because that swap effectively hedges approximately 40 percent of the cost of purchasing 35 MWs at Mid-C for our customers, a hypothetical increase in the Mid-C index would not change the swap's effectiveness.
Based on the anticipated effects of the existing purchase and sales agreements, the financial swaps and customer usage estimates, we expect to experience losses of approximately $4,000,000 in the first quarter 2001. If we continue to purchase electric energy at index-based market rates, or do not have other effective swaps in place, we estimate that the losses on these industrial customers - based on the above usage estimates and on forward price projections and broker quotations as of December 29, 2000 - could aggregate approximately $25,000,000 in the second quarter 2001 and more in subsequent quarters. Because of the volatility of the electric energy market in the western United States, particularly in the Pacific Northwest, and future possibilities of supplying these customers from alternative sources, we believe that estimating losses that we may incur beyond the second quarter 2001 would not be meaningful.
We continue to seek other opportunities to mitigate the commodity price risk associated with our power supply agreements, although we cannot assure that these efforts will be successful. For more specific information about these events, see Note 13, "Contingencies," in the "Long-Term Power Supply Agreements" section.
Natural Gas Take-or-Pay Contracts
Our natural gas utility entered into take-or-pay contracts with Montana natural gas producers to provide adequate supplies of natural gas for our utility customers. We currently have five of these contracts, with expirations between 2001 and 2006, most of which price natural gas on a variant of the Alberta Energy Company "C" Hub (AECO-C) index. Because we expect to recover the reasonable cost associated with these contracts in future rates, we do not believe that these contracts subject us to commodity price risk.
Cobb Storage Sales
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 price based on the AECO-C index. To mitigate 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. For December 2000, we recognized a loss of approximately $300,000 on the swap and a profit of approximately $1,200,000 on the sale of the Cobb storage natural gas.
Based on the AECO-C forward prices at December 29, 2000, we estimate a loss of $3,000,000 on the swap to offset profits of $4,900,000 on the sale through February 2001. Since the swap agreement is an effective hedge of the Cobb storage sales, a hypothetical increase in the AECO-C would increase the loss on the swap and the profit on the sale by the same amount - approximately $600,000.
General
Some of these electric and natural gas agreements have liquidated damage clauses that require the non-performing party to pay the other party the positive difference between the market and contract prices plus transportation and other fees. We believe that the possibility of non-performance is remote and, therefore, have not calculated its financial effect.
We expect to recover all reasonable costs associated with the QF contracts through competitive transition charges (CTCs), all reasonable costs associated with the WTSA contracts in the electric restructuring process, and the reasonable costs associated with the take-or-pay contracts through future natural gas rates. Therefore, we do not expect these contracts to expose us to market risks related to commodity price fluctuations. However, recovery of the costs associated with these contracts is subject to regulatory lag or possible disallowance. For additional information, see Note 5, "Deregulation, Regulatory Matters, and 1999 Sale of Electric Generating Assets."
Our agreements to supply electric energy to DETM and Puget expose us to the possibility of unrecoverable losses primarily because of the two reasons discussed above in the "Colstrip Unit 4" section: (1) to fulfill our supply obligations, we could be required to purchase electric energy at market-based rates higher than the fixed sales rates that we receive pursuant to these agreements, and (2) we could experience higher-than-expected fuel costs at Colstrip Unit 4. As discussed above in the "Large Industrial Customers" section, our long-term power supply agreements with several large industrial customers subject us to the possibility of unrecoverable losses because we fulfill our obligations under these contracts by purchasing electric energy at market-based rates, which could be higher than the fixed sales rates we receive pursuant to these long-term power supply agreements.
Discontinued Coal Operations
Northwestern Resources has a full-lignite requirements supply agreement (LSA) through August 2015 for the delivery of lignite to two mine-mouth electric generating facilities. The contract currently provides for the reimbursement of certain mining costs as well as management and dedication fees and, therefore, does not expose us to commodity price risk. Under a settlement reached in August 1999, the pricing structure will change July 1, 2002 to one driven by the market for Power River Basin (PRB) coal adjusted for transportation and other costs. We estimate that, after mid-2002, a hypothetical 10 percent decrease of the PRB market price adjusted for transportation costs would reduce annual revenues by approximately $3,000,000.
Western Energy also has full-requirements contracts for the sale of coal to the four mine-mouth electric generating plants at Colstrip. The contract for Units 1 and 2 provides for a price re-opener in 2001 to adjust prices that reflect changes in mining costs and provide a reasonable profit. Because our mining costs are not directly tied to market price changes, the Units 1 and 2 contract is not subject to commodity price risk. The contract for Colstrip Units 3 and 4 requires that we constantly evaluate alternative supplies. However, neither Western Energy nor the Colstrip Steam Electric Station has a unit train off-loading facility. Because the prices of alternative supplies must include the substantial cost of constructing this facility, a hypothetical 10 percent decrease in the prices of these competitive coal supplies would not materially affect us.
For more information on the pending sale of our coal businesses, which we expect to close at approximately the beginning of the second quarter 2001, see Note 2, "Decision to Sell Energy Businesses."
SFAS No. 107, "Disclosures about Fair Value of Financial Instruments," defines instruments readily convertible to cash as "financial instruments." These financial instruments principally include our cost-basis investments in independent power projects, the reclamation fund, mandatorily redeemable preferred securities, and long-term debt. All of these instruments are exposed to potential loss in fair value from adverse changes in interest rates. Assuming the fair values estimated for the SFAS No. 107 analysis and a hypothetical 10 percent adverse change in interest rates, we estimate that (1) the potential loss at the December 31, 2000 fair value of the reclamation fund and cost-based investments would be immaterial; and (2) the potential loss at the December 31, 2000 fair values of the mandatorily redeemable preferred securities and long-term debt would be approximately $4,900,000 and $14,400,000, respectively. For more information about fair valuation, see Note 1, "Summary of Significant Accounting Policies," in the "Fair Value of Financial Instruments" section.
Our primary foreign currency exposure resulted from (1) our former Canadian subsidiaries - Altana Exploration Company and Altana Exploration Ltd. - exploring for, producing, gathering, processing, transporting, and marketing natural gas and crude oil in Canada, and (2) our former affiliate, MPT&M, trading and marketing natural gas in Canada. We sold these operations on October 31, 2000 and, consequently, reduced our exposure to adverse foreign currency fluctuations to an insignificant level.
At December 31, 2000, our businesses exposed us to most of the same kinds of risks that we reported at December 31, 1999. We summarize below the significant differences between our discussion of those risks in 1999 and 2000:
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Page
Management's Responsibility for Financial Statements 50
Report of Independent Accountants 51
Consolidated Financial Statements:
Consolidated Statements of Income for the Years Ended
December 31, 2000, 1999, and 1998 52
Consolidated Balance Sheets as of December 31, 2000 and 1999 53
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2000, 1999, and 1998 55
Consolidated Statements of Shareholders' Equity for the
Years Ended December 31, 2000, 1999, and 1998 56
Notes to Consolidated Financial Statements 57
Schedule II - Valuation and Qualifying Accounts and Reserves 117
Financial Statement Schedules not included in this Form 10-K have been omitted because they are inapplicable or the required information is shown in the Consolidated Financial Statements or in the Notes to the Consolidated Financial Statements.
MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS
The management of The Montana Power Company is responsible for the preparation and integrity of the consolidated financial statements of the Company. These financial statements have been prepared in accordance with generally accepted accounting principles, which are consistently applied, and appropriate in the circumstances. In preparing the financial statements, management makes appropriate estimates and judgements based upon available information. Management also prepared the other financial information in the annual report on Form 10-K and is responsible for its accuracy and consistency with the financial statements.
Management maintains systems of internal accounting control, which are adequate to provide reasonable assurance that the financial statements are accurate, in all material respects. The concept of reasonable assurance recognizes that there are inherent limitations in all systems of internal control in that the costs of such systems should not exceed the benefits to be derived. Management believes the Company's systems provide this appropriate balance.
The Company maintains an internal audit function that independently assesses the effectiveness of the systems and recommends possible improvements. PricewaterhouseCoopers LLP, the Company's independent accountants, also considered the systems in connection with its audit. Management has considered recommendations of the internal auditors and PricewaterhouseCoopers LLP concerning the systems and has taken cost-effective actions to respond appropriately to these recommendations.
The Board of Directors, acting through an Audit Committee composed entirely of directors who are not employees of the Company, is responsible for determining that management fulfills its responsibilities in the preparation of the financial statements. The Audit Committee recommends, and the Board of Directors appoints, the independent accountants. The independent accountants and internal auditors are assured of full and free access to the Audit Committee and meet with it to discuss their audit work, the Company's internal controls, financial reporting, and other matters. The Committee is also responsible for determining adherence to the Company's Code of Business Conduct (Code). The Code addresses, among other things, potential conflicts of interests and compliance with laws, including those relating to financial disclosure and the confidentiality of proprietary information.
The financial statements have been audited by PricewaterhouseCoopers LLP, which is responsible for conducting its examination in accordance with generally accepted auditing standards.
/s/ Robert P. Gannon /s/ J.P. Pederson
Chairman of the Board and Vice Chairman and
Chief Executive Officer Chief Financial Officer
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Shareholders of The Montana Power Company:
In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of The Montana Power Company and its subsidiaries at December 31, 2000 and 1999, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying index presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These consolidated financial statements and financial statement schedule are the responsibility of the Company's management; our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As more fully discussed in Note 1 to the Consolidated Financial Statements, as of July 1, 1999, the Company changed its method of accounting for revenues relating to certain agreements to grant and exchange fiber-use rights.
/s/ PricewaterhouseCoopers LLP
Portland, Oregon
February 21, 2001
THE MONTANA POWER COMPANY AND SUBSIDIARIES | |||
CONSOLIDATED STATEMENT OF INCOME | |||
Year Ended December 31 | |||
2000 | 1999 | 1998 | |
(Thousands of Dollars) | |||
(except per-share amounts) | |||
REVENUES | $ 999,708 | $ 777,172 | $ 770,957 |
EXPENSES: | |||
Operations and maintenance | 612,712 | 370,870 | 366,400 |
Selling, general, and administrative | 171,373 | 116,864 | 98,239 |
Taxes other than income taxes | 60,991 | 71,933 | 67,088 |
Depreciation, depletion, and amortization | 77,026 | 79,576 | 85,245 |
922,102 | 639,243 | 616,972 | |
INCOME FROM CONTINUING OPERATIONS | 77,606 | 137,929 | 153,985 |
INTEREST EXPENSE AND OTHER INCOME: | |||
Interest expense | 34,408 | 41,593 | 59,373 |
Distributions on company obligated mandatorily |
|
|
|
Other income - net | (72,085) | (38,407) | (103,419) |
(32,185) | 8,678 | (38,554) | |
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME |
|
|
|
INCOME TAXES | 33,598 | 30,830 | 66,843 |
INCOME FROM CONTINUING OPERATIONS | 76,193 | 98,421 | 125,696 |
DISCONTINUED OPERATIONS: | |||
Income from discontinued coal operations (less |
|
|
|
Income from discontinued oil and natural gas |
|
|
|
Gain on sale of discontinued oil and natural gas |
|
|
|
INCOME FROM DISCONTINUED OPERATIONS | 123,298 | 51,925 | 39,924 |
NET INCOME | 199,491 | 150,346 | 165,620 |
DIVIDENDS ON PREFERRED STOCK | 3,690 | 3,690 | 3,690 |
NET INCOME AVAILABLE FOR COMMON STOCK | $ 195,801 | $ 146,656 | $ 161,930 |
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - |
|
|
|
BASIC EARNINGS PER SHARE OF COMMON STOCK | $ 1.86 | $ 1.34 | $ 1.47 |
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - |
|
|
|
DILUTED EARNINGS PER SHARE OF COMMON STOCK | $ 1.84 | $ 1.33 | $ 1.47 |
The accompanying notes are an integral part of these financial statements. | |||
THE MONTANA POWER COMPANY AND SUBSIDIARIES | ||
CONSOLIDATED BALANCE SHEET | ||
ASSETS | ||
December 31 | ||
2000 | 1999 | |
(Thousands of Dollars) | ||
CURRENT ASSETS: | ||
Cash and cash equivalents | $ 118,417 | $ 554,407 |
Temporary investments | - | 40,417 |
Accounts receivable, net of allowance for doubtful |
|
|
Materials and supplies (principally at average cost) | 16,446 | 37,928 |
Prepayments and other assets | 71,806 | 53,733 |
Deferred income taxes | 17,738 | 18,303 |
Investment in discontinued coal operations | 93,870 | - |
618,575 | 887,036 | |
PROPERTY, PLANT, AND EQUIPMENT: | ||
Utility plant, less accumulated depreciation, |
|
|
Nonutility plant, less accumulated depreciation, |
|
|
1,696,786 | 1,704,735 | |
OTHER ASSETS: | ||
Intangibles, net of amortization | 152,409 | 922 |
Reclamation fund | - | 43,460 |
Telecommunications investments | 30,448 | 39,678 |
Other investments | 66,495 | 76,382 |
Advanced coal royalties | - | 12,506 |
Regulatory assets related to income taxes | 60,423 | 60,538 |
Regulatory assets - other | 142,434 | 150,486 |
Deferred income taxes | 21,419 | - |
Other | 27,805 | 73,000 |
501,433 | 456,972 | |
TOTAL ASSETS | $ 2,816,794 | $ 3,048,743 |
The accompanying notes are an integral part of these financial statements. | ||
THE MONTANA POWER COMPANY AND SUBSIDIARIES | ||
CONSOLIDATED BALANCE SHEET | ||
LIABILITIES AND SHAREHOLDERS' EQUITY | ||
December 31 | ||
2000 | 1999 | |
(Thousands of Dollars) | ||
CURRENT LIABILITIES: | ||
Accounts payable | $ 206,924 | $ 115,654 |
Dividends payable | 1,456 | 22,746 |
Income taxes payable | 104,093 | 152,739 |
Other taxes payable | 41,054 | 54,630 |
Regulatory liability - oil and natural gas sale | 32,549 | - |
Current portion of deferred revenue | 45,771 | 24,962 |
Short-term borrowing | 75,000 | - |
Long-term debt due within one year | 169,054 | 58,955 |
Interest accrued | 5,679 | 11,597 |
Other current liabilities | 38,422 | 67,315 |
720,002 | 508,598 | |
LONG-TERM LIABILITIES: | ||
Deferred income taxes | - | 8,847 |
Investment tax credits | 13,163 | 13,330 |
Deferred reclamation | - | 135,075 |
Deferred revenue | 235,578 | 311,751 |
Regulatory liability - net proceeds from the |
|
|
Other deferred credits | 94,689 | 101,434 |
558,317 | 790,163 | |
LONG-TERM DEBT: | ||
Long-term debt | 309,463 | 618,512 |
Company obligated mandatorily redeemable |
|
|
374,463 | 683,512 | |
SHAREHOLDERS' EQUITY: | ||
Preferred stock | 57,654 | 57,654 |
Common stock (240,000,000 shares without par value |
|
|
Treasury stock (6,616,000 and 4,682,100 shares |
|
|
Unallocated stock held by trustee for |
|
|
Retained earnings | 624,118 | 488,975 |
Accumulated other comprehensive loss | (34) | (17,659) |
1,164,012 | 1,066,470 | |
CONTINGENCIES AND COMMITMENTS (Notes 13 and 14) | ||
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY | $ 2,816,794 | $ 3,048,743 |
The accompanying notes are an integral part of these financial statements. | ||
THE MONTANA POWER COMPANY AND SUBSIDIARIES | |||
CONSOLIDATED STATEMENT OF CASH FLOWS | |||
Year Ended December 31 | |||
2000 | 1999 | 1998 | |
(Thousands of Dollars) | |||
NET CASH FLOWS FROM OPERATING ACTIVITIES: | |||
Net income | $ 199,491 | $ 150,346 | $ 165,620 |
Deduct: | |||
Income from discontinued operations | 61,292 | 51,925 | 39,924 |
Gain on sale of discontinued oil and natural gas |
|
|
|
Income from continuing operations | 76,193 | 98,421 | 125,696 |
Adjustments to reconcile income from continuing | |||
Depreciation, depletion, and amortization | 77,026 | 79,576 | 85,245 |
Write-downs of long-lived assets | - | 7,083 | - |
Deferred income taxes | (44,513) | (315,588) | (42,258) |
Noncash earnings from unconsolidated investments | (15,227) | (20,608) | (10,871) |
(Gains) losses on sales of property and |
|
|
|
Other noncash charges to net income - net | 5,020 | 25,154 | 32,131 |
Changes in assets and liabilities: | |||
Accounts and notes receivable | (142,177) | 12,333 | (30,393) |
Deferred income taxes | (11,039) | 3,379 | (4,745) |
Income taxes payable | (164,715) | 129,228 | 21,582 |
Accounts payable | 106,586 | 26,244 | (8,031) |
Deferred revenue and other | (72,511) | 291,790 | 11,800 |
Miscellaneous temporary investments | 40,417 | (40,417) | - |
Regulatory liability - net proceeds from the |
|
|
|
Other assets and liabilities - net | 64,626 | 104,414 | 34,678 |
Net cash provided by (used for) continuing |
|
|
|
Net cash provided by discontinued operations | 53,068 | 39,381 | 35,192 |
Net cash provided by (used for) operating |
|
|
|
NET CASH FLOWS FROM INVESTING ACTIVITIES: | |||
Capital expenditures | (644,216) | (233,192) | (151,044) |
Proceeds from sale of discontinued oil and natural |
|
|
|
Proceeds from sales of property and investments | 83,912 | 586,150 | 38,063 |
Additional investments | (2,050) | (1,272) | (7,732) |
Net cash provided by (used for) continuing |
|
|
|
Net cash used for discontinued investing activities | (46,516) | (45,182) | (38,839) |
Net cash provided by (used for) investing |
|
|
|
NET CASH FLOWS FROM FINANCING ACTIVITIES: | |||
Dividends paid | (67,053) | (90,902) | (91,598) |
Sales of common stock | 2,525 | 751 | 7,421 |
Purchase of treasury stock | (60,784) | (144,872) | - |
Issuance of long-term debt | 139,524 | 23,397 | 139,947 |
Retirement of long-term debt | (334,840) | (147,544) | (77,873) |
Net change in short-term borrowing | 75,000 | (69,820) | (64,138) |
Net cash used for continuing financing activities | (245,628) | (428,990) | (86,241) |
Net cash provided by (used for) discontinued |
|
|
|
Net cash used for financing activities | (246,236) | (422,396) | (88,779) |
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS | (435,990) | 544,291 | 7,346 |
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR | 554,407 | 10,116 | 2,770 |
CASH AND CASH EQUIVALENTS, END OF YEAR | $ 118,417 | $ 554,407 | $ 10,116 |
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION: | |||
Cash paid during the year for: | |||
Income taxes, net of refunds | $ 198,282 | $ 213,362 | $ 90,663 |
Interest | 46,709 | 53,273 | 67,777 |
The accompanying notes are an integral part of these financial statements. | |||
THE MONTANA POWER COMPANY AND SUBSIDIARIES | |||
CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY | |||
Year Ended December 31 | |||
2000 | 1999 | 1998 | |
(Thousands of Dollars) | |||
COMMON STOCK: | |||
Balance at beginning of year | $ 557,901 | $ 702,511 | $ 694,561 |
Issuances (149,834; 100,857; and 663,622 shares) | 2,384 | 357 | 7,950 |
Reacquired capital stock (1,933,900 and 4,682,100 | (60,784) | (144,872) | - |
Premium on capital stock | - | (95) | - |
Balance at end of year | 499,501 | 557,901 | 702,511 |
RETAINED EARNINGS AND OTHER SHAREHOLDERS' EQUITY: | |||
Balance at beginning of year | 488,975 | 430,309 | 356,327 |
Net income | 199,491 | 150,346 | 165,620 |
Dividends on common stock (60 cents per share for |
|
|
|
Dividends on preferred stock | (3,690) | (3,690) | (3,690) |
Other | 1,768 | 165 | 60 |
Balance at end of year | 624,118 | 488,975 | 430,309 |
ACCUMULATED OTHER COMPREHENSIVE LOSS: | |||
Balance at beginning of year | (17,659) | (20,717) | (13,354) |
Net income | 199,491 | 150,346 | 165,620 |
Foreign currency translation adjustments | 17,625 | 3,058 | (7,363) |
Total comprehensive income | 217,116 | 153,404 | 158,257 |
Deduct net income included in comprehensive income | (199,491) | (150,346) | (165,620) |
Other comprehensive income (loss) | 17,625 | 3,058 | (7,363) |
Balance at end of year | (34) | (17,659) | (20,717) |
UNALLOCATED STOCK HELD BY TRUSTEE FOR RETIREMENT | |||
Balance at beginning of year | (20,401) | (23,298) | (25,945) |
Distributions | 3,174 | 2,897 | 2,647 |
Balance at end of year | (17,227) | (20,401) | (23,298) |
PREFERRED STOCK | 57,654 | 57,654 | 57,654 |
TOTAL SHAREHOLDERS' EQUITY AT END OF YEAR | $1,164,012 | $1,066,470 | $1,146,459 |
The accompanying notes are an integral part of these financial statements. | |||
NOTES TO THE FINANCIAL STATEMENTS
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Our accounting policies conform with generally accepted accounting principles. With respect to our utility operations, these policies are in accordance with the accounting requirements and ratemaking practices of applicable regulatory authorities.
Preparing financial statements requires the use of estimates based on information available. Actual results may differ from our accounting estimates as new events occur or we obtain additional information.
We have made reclassifications to certain prior-year amounts to make them comparable to the 2000 presentation. We now classify all earnings from our unconsolidated investments in "Other income - net." We previously reported these earnings separately in revenues under "Earnings from unconsolidated investments" and have reclassified all amounts from prior periods to reflect this change. These reclassifications had no material effect on our previously reported consolidated financial position, results of operations, or cash flows.
The consolidated financial statements include accounts and results of our wholly owned subsidiaries. We have eliminated significant intercompany balances and transactions. We account for our significant telecommunications and independent power investments using the equity method, because we exercise significant influence over those operations.
Prior to 2000, we consolidated the accounts of certain oil and natural gas operations for fiscal years ending in November to facilitate the timely preparation of the consolidated financial statements. Beginning in the first quarter of 2000, the one-month lag in reporting for these operations was eliminated. The December 1999 results of operations for these entities, which would have previously been reported in results of the first quarter of 2000, were recorded as an adjustment to beginning retained earnings as of January 1, 2000. This adjustment increased retained earnings by approximately $1,500,000. We consider this amount to be immaterial to our consolidated financial position, results of operations, or cash flows.
We consider all liquid investments with original maturities of three months or less to be cash equivalents, and investments with original maturities over three months and up to one year as temporary investments. At December 31, 1999, all of our investments were available for sale, and their fair value approximates the value reported on the Consolidated Balance Sheet. We had no temporary investments at December 31, 2000.
Accounts receivable are presented net of allowance for doubtful accounts of $11,456,000 in 2000 and $2,105,000 in 1999.
The following table provides year-end balances of the major classifications of our property, plant, and equipment, which we record at cost:
December 31 | ||
2000 | 1999 | |
(Thousands of Dollars) | ||
UTILITY PLANT: | ||
Electric: | ||
Generation (including our share of |
|
|
Transmission | 412,885 | 405,061 |
Distribution | 604,070 | 573,531 |
Other | 135,477 | 94,698 |
Natural Gas: | ||
Production and storage | 71,681 | 73,959 |
Transmission | 167,416 | 163,968 |
Distribution | 151,039 | 147,764 |
Other | 39,841 | 30,693 |
Total Utility | 1,636,885 | 1,543,127 |
Less: Accumulated depreciation, |
|
|
1,083,611 | 1,048,892 | |
NONUTILITY PROPERTY, PLANT, AND EQUIPMENT: | ||
Telecommunications: | ||
Buildings and structures | 8,382 | 3,762 |
Fiber optic network | 90,925 | 48,503 |
Communications equipment | 176,329 | 53,128 |
Construction work-in-progress | 352,445 | 128,994 |
Other - telecommunications | 18,491 | 3,470 |
Total telecommunications | 646,572 | 237,857 |
Coal | - | 240,227 |
Oil and Natural Gas | - | 432,806 |
Other | 6,401 | 64,459 |
Total Nonutility | 652,973 | 975,349 |
Less: Accumulated depreciation, |
|
|
613,175 | 655,843 | |
Total Utility and Nonutility Property, accumulated depreciation, depletion, and amortization |
|
|
We capitalize the cost of plant additions and replacements, including an allowance for funds used during construction (AFUDC) of utility plant. We determine the rate used to compute AFUDC in accordance with a formula established by the Federal Energy Regulatory Commission (FERC). This rate averaged 8.6 percent for 2000, 7.1 percent for 1999, and 8.3 percent for 1998.
In addition, we capitalized interest of approximately $4,317,000 in connection with various telecommunications projects during 2000. This amount is included in telecommunications property, plant, and equipment in the table above.
We charge costs of utility depreciable units of property retired, plus costs of removal less salvage, to accumulated depreciation and recognize no gain or loss. We recognize gain or loss upon the sale or other disposition of nonutility property. We charge maintenance and repairs of plant and property, as well as replacements and renewals of items determined to be less than established units of plant, to operating expenses.
Included in the plant classifications are utility plant under construction in the amounts of $2,637,000 and $3,876,000 for 2000 and 1999, respectively, and coal and oil and natural gas plant under construction in the amount of $5,729,000 for 1999. In our telecommunications operations, we classify costs associated with uncompleted portions of our fiber optic network as construction work in progress and, upon completion, classify the costs as network systems. For joint-build construction contracts, we record the total costs of construction reduced by reimbursements received, resulting in a net cost of the asset constructed. We record exchanges of fiber-use rights as the cost of the asset transferred plus any cash paid or, alternatively, as the cost of the asset transferred less any cash received.
For information on the October 31, 2000 sale of our oil and natural gas businesses and the pending sale of our coal businesses, see Note 2, "Decision to Sell Energy Businesses."
We record provisions for depreciation and depletion at amounts substantially equivalent to calculations made on straight-line and unit-of-production methods by applying various rates based on useful lives of properties determined from engineering studies. As a percentage of the depreciable and depletable utility plant at the beginning of the year, our provisions for depreciation and depletion of utility plant were approximately 3.5 percent for 2000 and 3.0 percent for 1999 and 1998. We depreciate and amortize our telecommunications property, plant, and equipment on a straight-line basis over the estimated useful lives of the assets as follows:
Classification | Years | ||
Buildings and structures | 30 | ||
Fiber optic network | 20 | ||
Communications equipment | 10 | ||
Office furniture and equipment | 3-5 | ||
Other - telecommunications | 3-5 |
Our nonutility oil and natural gas operations used the successful-efforts method of accounting for exploration and development costs.
Prior to the sale of the electric generating assets discussed in Note 5, "Deregulation, Regulatory Matters, and 1999 Sale of Electric Generating Assets," we were a joint-owner of Colstrip Units 1, 2, and 3. We owned 50 percent of Units 1 and 2 and 30 percent of Unit 3. We continue to own a leasehold interest in 30 percent of Colstrip Unit 4. We also own an approximate 30-percent interest in the transmission facilities serving these units. At December 31, 2000, our investment in these facilities was $132,331,000 and the related accumulated depreciation was $48,103,000.
Each joint-owner provides its own financing. Our share of direct expenses associated with the operation and maintenance of these joint facilities, including Colstrip Units 1, 2, and 3 through December 17, 1999, is included in the corresponding operating expenses in the Consolidated Statement of Income.
The following table provides year-end balances of the major classifications of intangibles:
December 31 | ||
2000 | 1999 | |
(Thousands of Dollars) | ||
Telecommunications acquisition |
|
|
Goodwill | 8,559 | - |
Other | 3,957 | 1,239 |
Total intangibles | 158,150 | 1,239 |
Less: Accumulated amortization | 5,741 | 317 |
Total intangibles, net of |
|
|
For details on the intangibles recorded in conjunction with the telecommunications acquisition, see Note 4, "Acquisition of Telecommunications Properties." The excess of the January 2000 purchase price over the net assets of One Call Locators, Ltd. was recorded as goodwill and is being amortized over 15 years. Most other intangibles are being amortized over 5 years.
Under the current Colstrip Units 3 and 4 coal supply agreement, we maintain a reclamation fund representing restricted cash necessary to meet our estimated reclamation obligation at Western Energy for Units 3 and 4. We invest the funds required for these reclamation obligations until we need them to perform reclamation. At December 31, 2000, we had the funds invested entirely in a money market account. We regularly accrue an expense and an offsetting liability associated with our reclamation obligation. The reclamation fund is not offset against our accumulated liability, and both items are included in "Investment in discontinued coal operations" on the December 31, 2000 Consolidated Balance Sheet.
We record operating revenues monthly on the basis of consumption or service rendered. To match revenues with associated expenses, we accrue unbilled revenues for electric, natural gas, and telecommunication services delivered to customers but not yet billed at month-end. Our telecommunications service revenues are comprised of network services (wholesale and dedicated business line) revenues and retail sales (commercial and consumer long-distance) revenues. In conjunction with our efforts to expand our fiber optic network, we entered into agreements to grant and exchange fiber-use rights, principally through IRU agreements. Prior to July 1, 1999, we recognized revenues of fiber-use rights that qualified for sales-type lease accounting at the time of delivery and acceptance of the dark fiber by the customer. For those transactions, we determined cost of revenue by allocating the total estimated costs of the network to the specific fibers granted to the customer.
On July 8, 1999, the FASB issued Interpretation No. 43, "Real Estate Sales," which is an interpretation of SFAS No. 66, "Accounting for Sales of Real Estate." Effective July 1, 1999, therefore, we changed our revenue recognition policy. This interpretation was effective for transactions entered into after June 30, 1999, and requires entities to recognize revenues on fiber-use right agreements, or similar agreements, over the period of the agreement rather than at the time of execution if title to the fiber does not transfer to the customer by the end of the agreement term. In granting fiber-use rights, therefore, we record these transactions as operating leases and recognize revenues over the term of the agreement. The effect of this change in accounting resulted in approximately $7,000,000 of revenues that we did not record in 1999 from fiber-use right transactions entered into after June 30, 1999. Net income for 1999 would have been approximately $4,200,000 higher and both basic and diluted earnings per share would have been $0.03 higher if we were not required to make this accounting change.
The Emerging Issues Task Force (EITF) Issue No. 98-10 requires that energy contracts entered into under "trading activities" be marked to market with the gains or losses shown net in the income statement. EITF 98-10 is effective for fiscal years beginning after December 15, 1998. We adopted EITF 98-10 as of January 1, 1999, and accordingly mark to market energy contracts that qualify as "trading activities." The cumulative effect of adopting EITF 98-10 had no material effect on our consolidated financial position, results of operations, or cash flows.
For a discussion of Staff Accounting Bulletin (SAB) No. 101, "Revenue Recognition in Financial Statements," see Note 16, "New Accounting Pronouncements."
For our regulated operations, we follow SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." Pursuant to this pronouncement, certain expenses and credits, normally reflected in income as incurred, are recognized when included in rates and recovered from or refunded to the customers. Accordingly, we have recorded the following major classifications of regulatory assets and liabilities that will be recognized in expenses and revenues in future periods when the matching revenues are collected or refunded.
December 31 | ||||
2000 | 1999 | |||
Assets | Liabilities | Assets | Liabilities | |
(Thousands of Dollars) | ||||
Income Taxes | $ 58,452 | $ - | $ 57,526 | $ - |
Colstrip Unit 3 carrying |
|
|
|
|
Conservation programs | 27,956 | - | 28,378 | - |
Competitive transition |
|
|
|
|
Generation net proceeds in | - | 214,887 |
| 219,726 |
Proceeds from oil and | - | 32,549 | - | - |
Investment tax credits | - | 13,163 | - | 13,330 |
Other | 40,384 | 18,816 | 44,646 | 12,178 |
Subtotal | 216,094 | 279,415 | 222,812 | 245,234 |
Less: | ||||
Current portions | 13,237 | 34,979 | 11,788 | 3,402 |
Total | $ 202,857 | $ 244,436 | $ 211,024 | $ 241,832 |
Income taxes reflect the effects of temporary differences that we will recover in future rates. In August 1985, the PSC issued an order allowing us to recover deferred carrying charges and depreciation expenses over the remaining life of Colstrip Unit 3. These recoveries compensated us for unrecovered costs of our investment for the period from January 10, 1984 to August 29, 1985, when we placed the plant in service. We were amortizing this asset to expense and recovering in rates $1,831,000 per year. Conservation programs represent our Demand Side Management programs, which are in rate base and which we were amortizing to income over a 10-year period. We are recovering the CTCs, which relate to natural gas properties that we removed from regulation on November 1, 1997, through rates over 15 years. Investment tax credits and account balances included in "Other" represent items that we are amortizing currently or are subject to future regulatory confirmation.
With the sale of the electric generating assets, it is our position that any of these amounts related to electric supply should be recovered from sale proceeds in excess of book value. Amortization of these assets stopped in February 2000 when the expenses were removed from rates. For further information on the effects of the sale of our electric generating assets, see Note 5, "Deregulation, Regulatory Matters, and 1999 Sale of Electric Generating Assets."
When losses from costs of storm damage and environmental remediation obligations for our utility operations are probable and reasonably estimable, we charge these costs against established, approved operating reserves. The reserves' balance at December 31, 2000 was approximately $11,080,000 and at December 31, 1999 was approximately $11,166,000. We have included these reserves in "Current liabilities" on the Consolidated Balance Sheet.
We and our United States subsidiaries file a consolidated United States income tax return. We allocate consolidated United States income taxes to utility and nonutility operations as if we filed separate United States income tax returns for each operation. We defer income taxes to provide for the temporary differences between the financial reporting basis and the tax basis of our assets and liabilities. For further information on income taxes, see "Regulatory Assets and Liabilities" in this Note 1 and Note 6, "Income Tax Expense."
We defer revenues to account for the timing differences between cash received and revenues earned and reflect these amounts on the Consolidated Balance Sheet in "Deferred revenue." We reflect the current portion of these amounts in " Current portion of deferred revenue" on the Consolidated Balance Sheet. We are recognizing the prepayment received in January 1999 from a telecommunications customer and the payment received in December 1999 from the Los Angeles Department of Water and Power in revenues over the original terms of the agreements, approximately 11 years in each case.
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 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.
For comparative purposes, the following table shows consolidated basic net income per share.
Year Ended December 31 | |||
20001 | 1999 | 1998 | |
Continuing Operations | $0.69 | $0.86 | $1.11 |
Discontinued Operations | 1.17 | 0.48 | 0.36 |
Consolidated | $1.86 | $1.34 | $1.47 |
1 2000 "Discontinued Operations" figures include gain on sale of discontinued oil and natural gas operations. | |||
In accordance with SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of," we periodically review long-lived assets for impairment whenever events or changes in circumstances indicate that we may not recover the carrying amount of an asset.
Comprehensive income consists of net income and other comprehensive income (loss). For the years ended December 31, 2000, 1999, and 1998, 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 increases to retained earnings of $17,625,000 and $3,058,000 in 2000 and 1999 and a decrease of $7,363,000 in 1998.
Nearly all of the 2000 increase resulted from the sale of the Canadian subsidiaries of our former oil and natural gas businesses. In accordance with SFAS Nos. 52, "Foreign Currency Translation," and 130, "Reporting Comprehensive Income," we recognized the cumulative translation loss associated with those subsidiaries and included it in the computation of the gain on the October 31, 2000 sale of the oil and natural gas businesses. Including it reduced our gain by approximately $21,200,000. Because the translation adjustment was not part of the tax basis of the foreign subsidiaries' properties, it did not affect the calculation of taxes on the sale.
As discussed in Note 2, "Decision to Sell Energy Businesses," in the "October 31, 2000 Divestiture of Oil and Natural Gas Businesses and Pending Divestiture of Remaining Energy Businesses" section, we sold all of the stock of our oil and natural gas businesses on October 31, 2000, including MPT&M, which engaged in trading activities. At that time, we were using 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. Now, however, we use these derivative financial instruments only as discussed below.
Electric Swap Agreements
Long-term power supply agreements, primarily one with a large industrial customer, expose us to commodity price risk. We are exposed to this risk to the extent that a portion of the electric energy we are required to sell to our industrial customers at fixed rates is purchased at prices indexed to a wholesale electric market, which can be higher than the fixed sales rate that we receive pursuant to our power supply agreements. We mitigate our exposure to losses on these agreements with financial derivative instruments called "price swaps" and offsetting electric energy purchase and sales agreements.
Since June 1998, we have had a price swap agreement with one of our industrial customers that converts 43 MWs of the Mid-Columbia (Mid-C) index price of our supply agreement with that customer to a fixed price through May 2001. In fiscal year 2000, we also entered into another price swap with a counterparty that effectively hedges 35 MWs of the anticipated market-based purchases to supply that agreement through March 2001.
In accordance with the provisions of SFAS No. 80, "Accounting for Futures Contracts," we recognized gains and losses from the financial swaps in the same period in which we recognized the sales and related purchases under that agreement. For fiscal year 2000, we recognized a net gain of approximately $16,000,000 from these financial swaps and losses of approximately $32,200,000 from supplying large industrial customers. For more specific information about the commodity price risk that we face as a result of our long-term power supply agreements, see Note 13, "Contingencies," in the "Long-Term Power Supply Agreements" section.
An estimate of the fair market value of the swaps based on the Mid-C forward prices of December 29, 2000 aggregated approximately $21,800,000 as of December 31, 2000, which would offset approximately 40 percent of the expected losses on the above power supply agreements. For information on SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," and how we expect it to affect us, see Note 16, "New Accounting Pronouncements."
Natural Gas Utility Swaps
By drilling wells and adding compression at our Cobb storage reservoir, we are able to 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 price based on the Alberta Energy Company "C" Hub (AECO-C) index. 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.
For December 2000, we recognized a loss of approximately $300,000 on the swap and a profit of approximately $1,200,000 on the sale of the Cobb storage natural gas. Based on the AECO-C forward prices at December 29, 2000, we estimate a loss of approximately $3,000,000 on the swap to offset profits of $4,900,000 on the sale through February 2001. We are deferring the expected net profit of these transactions in accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation," until the PSC approves its inclusion in future rate schedules.
Continental Energy Operations
Continental Energy had investments in independent power partnerships, some of which had entered into derivative financial instruments to hedge interest rate exposure on floating-rate debt and natural gas price fluctuations. We believe that, as of December 31, 2000, we had not been exposed to any material adverse effects from the risks inherent in these instruments.
2000 | 1999 | |||
Carrying | Fair | Carrying | Fair | |
(Thousands of Dollars) | ||||
ASSETS: | ||||
Investment in independent |
|
|
|
|
Reclamation fund | 46,043 | 46,043 | 43,460 | 43,460 |
Other significant investments | 40,084 | 43,799 | 52,523 | 55,689 |
LIABILITIES: | ||||
Company obligated mandatorily |
|
|
|
|
Long-term debt (including due |
|
|
|
|
The following methods and assumptions were used to estimate fair value:
NOTE 2 - DECISION TO SELL ENERGY BUSINESSES
On March 28, 2000, after a careful review of options and strategies, our Board of Directors announced that we would begin the process of divesting our multiple energy businesses, separating them from Touch America. Following the merger and the sale of the utility business to NorthWestern, Touch America expects to use the cash proceeds from the sale of the oil and natural gas businesses, the coal businesses, the independent power production business, and the utility business to take advantage of opportunities in the telecommunications business. We expect these gross cash proceeds, before income taxes and transaction costs, to total approximately $1,300,000,000.
As a result of our restructuring efforts, we have evaluated our operations to determine which segments should be included in continuing or discontinued operations. Because the sale of our utility business remains subject to shareholder approval, we have included the results of operations, financial position, and cash flows of our electric (including Colstrip Unit 4) and natural gas utility business in continuing operations. We plan to schedule a special meeting of our shareholders in the second or third quarter 2001 to consider and vote on the sale and other matters.
We have not afforded Continental Energy discontinued operations accounting treatment since we have historically reported Colstrip Unit 4 with Continental Energy as the Independent Power Group segment. Although we sold Continental Energy on February 21, 2001, the sale of our utility business includes Colstrip Unit 4. Consequently, we have reflected Continental Energy activity in continuing operations for all periods presented.
As a result of our Board of Directors' approval to enter into definitive agreements with respect to our former oil and natural gas and our coal operations, we have applied discontinued operations accounting treatment to these operations, effective August 22, 2000 for our oil and natural gas operations and September 14, 2000 for our coal operations. The results of this treatment are the following:
The following table presents revenues separately for our discontinued oil and natural gas and coal operations:
Year Ended December 31 | ||||
2000 | 1999 | 1998 | ||
(Thousands of Dollars) | ||||
Oil and Natural Gas Operations | $ 348,698 | $ 355,532 | $ 239,268 | |
Coal Operations | 224,515 | 236,782 | 216,757 | |
On August 25, 2000, our wholly owned subsidiary, Entech, and Altana Exploration Company, Entech's wholly owned subsidiary, entered into a Stock and Asset Purchase Agreement with PanCanadian Petroleum Limited (PanCanadian Petroleum) and one of PanCanadian Petroleum's wholly owned subsidiaries, PanCanadian Energy, Inc. (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. (We collectively refer to PanCanadian Petroleum and PanCanadian Energy as PanCanadian.) The transaction closed on October 31, 2000, with a purchase price of US$475,000,000, subject to post-closing adjustments.
As a result of the transaction, we recorded a gain in the fourth quarter 2000 of approximately $62,000,000, net of income taxes and a regulatory liability of approximately $32,500,000. The $32,500,000 liability represents the portion of the proceeds from the sale of oil and natural gas businesses to PanCanadian attributable to properties previously in the natural gas utility's rate base. Based on gas stipulation agreements addressing the removal of natural gas production properties from regulation, we have agreed to share this amount with our natural gas utility ratepayers.
On September 19, 2000, Entech entered into a Stock Purchase Agreement with BBI pursuant to which BBI agreed to purchase the stock of Continental Energy, our remaining independent power production business. In January 2001, BBI assigned its right to purchase Continental Energy to BBI's wholly owned subsidiary, CES Acquisition Corp. The transaction closed on February 21, 2001, with a purchase price of $84,500,000, subject to post-closing adjustments. Based on the net book value of Continental Energy, we expect to record a gain in the first quarter 2001 of approximately$33,000,000, net of income taxes.
Pending Sale of Coal Operations
On September 15, 2000, Entech entered into a Stock Purchase Agreement with Westmoreland pursuant to which Westmoreland agreed to purchase the companies comprising our coal businesses. The purchase price is $138,000,000, subject to customary closing adjustments. We expect this transaction to close at approximately the beginning of the second quarter 2001 and, based on the net book value of our coal operations, we expect to record a gain on the sale.
The Montana Power L.L.C./Utility Business
On September 29, 2000, we entered into a Unit Purchase Agreement with NorthWestern Corporation, a South Dakota-based energy company, pursuant to which NorthWestern agreed, as discussed below, to purchase our affiliate, The Montana Power L.L.C., a Montana limited liability company (MPLLC). MPLLC will hold - among other assets, liabilities, commitments, and contingencies - our electric (including Colstrip Unit 4) and natural gas utility business. The consideration for MPLLC is approximately $1,090,000,000, and is comprised of cash of $602,000,000 and NorthWestern's assumption of up to $488,000,000 of our debt.
The transaction is targeted to close approximately three months after the proxy statement/prospectus is filed and becomes effective. The closing is subject to the approval of our shareholders, regulatory approvals from the PSC, and other customary conditions. We received approval for the sale from FERC in February 2001. We can provide no assurance that the transaction will close or, if it does, that the terms and conditions will remain unchanged.
For additional information on the special meeting of our shareholders to consider and vote on the sale and other matters, see Note 3, "Upcoming Special Meeting of Shareholders."
NOTE 3 - UPCOMING SPECIAL MEETING OF SHAREHOLDERS
Our Board of Directors has approved a merger that will create a new company, Touch America Holdings, Inc., to own what is today our telecommunications business. Immediately following this merger, our remaining energy business - consisting of our electric and natural gas utility - will be sold to NorthWestern. On completion of this merger and the sale of the utility business to NorthWestern, Touch America Holdings will own Touch America, Inc. and Tetragenics Company, which together will constitute its telecommunications operating business.
On completion of the merger, our shareholders will be deemed to receive one share of Touch America Holdings' common stock for each common share of The Montana Power Company, and one share of Touch America Holdings' Preferred Stock, $6.875 Series, for each share of The Montana Power Company's outstanding Preferred Stock, $6.875 Series.
We will hold a special meeting of our shareholders to consider and vote on the merger and the sale of the utility business to NorthWestern. In addition, shareholders of our common stock will be asked to vote in favor of the redemption of The Montana Power Company's outstanding Preferred Stock, $4.20 Series, and Preferred Stock, $6.00 Series. If the redemption of the preferred stock is not approved by at least a majority of all of our common shareholders, each shareholder of The Montana Power Company's Preferred Stock, $4.20 Series, and Preferred Stock, $6.00 Series, will be deemed to receive in the merger one share of Touch America Holdings' Preferred Stock, $4.20 Series, and Preferred Stock, $6.00 Series, for each outstanding share of The Montana Power Company's Preferred Stock, $4.20 Series, and Preferred Stock, $6.00 Series, respectively. We plan to schedule this special meeting of our shareholders for the second or third quarter 2001.
NOTE 4 - ACQUISITION OF TELECOMMUNICATIONS PROPERTIES
On June 30, 2000, in accordance with a previously executed stock purchase agreement, we acquired wholesale, private line, long-distance, and other telecommunications services in the former U S WEST fourteen-state region from Qwest for approximately $206,000,000, subject to post-closing adjustments. We estimate that Touch America's related capital expenditures, mainly to install electronics 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 approximately 1,800 route miles and associated electronics and switches that will connect to Touch America's existing fiber optic network. As a result of the acquisition, 173 sales and sales-support personnel in the fourteen-state region became employees of Touch America.
We accounted for the acquisition using the purchase method of accounting. As a result, we have allocated our cost of the acquisition to the assets acquired and liabilities assumed based on our estimates of their fair values as of the June 30, 2000 acquisition date. Accordingly, we recorded approximately $60,000,000 of property and equipment and approximately $146,000,000 of intangible assets related to this acquisition. We are amortizing the acquired property and equipment and intangible assets over their estimated useful lives on the straight-line basis in accordance with our stated policies.
We have received an appraisal of the acquired properties from an independent third party. We used this appraisal as a basis for recognizing the acquired assets and the depreciation and amortization in our consolidated financial statements. The balances reflected in our Consolidated Balance Sheet and related depreciation or amortization periods are as follows:
Balances | Depreciation or Amortization Periods | |
(Thousands |
| |
Tangible Assets: | ||
Furniture and equipment | $ 600 | 3-5 years |
Network assets - fiber | 9,200 | 20 years |
Network assets - optical electronics | 50,448 | 10 years |
Total Tangible Assets | $ 60,248 | |
Intangible Assets: | ||
Assembled workforce | $ 1,900 | 5 years |
Customer base - Wholesale | 15,300 | 5 years |
Customer base - Commercial | 3,200 | 3 years |
IRU capacity agreement | 125,234 | 20 years |
Total Intangible Assets | $ 145,634 |
The accounts of this acquisition have been included in our consolidated accounts since June 30, 2000.
The following table presents the summarized consolidated results of operations for the years ended December 31, 2000 and 1999 on an unaudited, pro forma basis as though this June 30, 2000 acquisition had occurred as of January 1, 1999:
Pro Forma Consolidated | ||
2000 | 1999 | |
(Thousands of Dollars) | ||
(except per-share amounts) | ||
Revenues | $1,154,735 | $1,068,425 |
Net Income from Continuing Operations | 94,481 | 129,231 |
Net Income Available for Common | 214,089 | 177,466 |
Earnings per share: | ||
Basic | $ 2.03 | $ 1.62 |
Diluted | $ 2.01 | $ 1.61 |
NOTE 5 - DEREGULATION, REGULATORY MATTERS, AND 1999 SALE OF ELECTRIC GENERATING ASSETS
The electric and natural gas utility businesses in Montana are transitioning to a competitive market in which commodity energy products and related services are sold directly to wholesale and retail customers. Montana's Electric Act, passed in 1997, 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. In December 2000, due to the lack of a competitive market for the supply of electric energy in Montana, the PSC extended the transition period two years, until July 1, 2004. Pursuant to the Electric Act, the electric utility is required to supply electric energy for the additional two-year period, and we are working with the Montana Legislature and the PSC to fully recover the default supply costs.
Montana's Natural Gas Act, also passed in 1997, provides that a utility may voluntarily offer its customers choice of natural gas suppliers and provide open access. We have opened access on our gas transmission and distribution systems and all of our natural gas customers have the opportunity of gas-supply choice.
Electric
Residential accounts previously in the competitive market largely returned to regulated supply in the fourth quarter 2000. Some industrial loads have curtailed operations due to high supply costs in the competitive market, reducing our electric load.
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; regulatory assets associated with the electric generating business; and a review of our electric generating assets sale, including the treatment of sale 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 freeze, which means that rates cannot change, or a rate cap, which means that rates cannot increase more than a certain level, during the initial transition period that ends July 1, 2002.
In May 2000, the district court ruled that the PSC must allow us to incorporate tracking mechanisms in our transition plan proposal and that the Electric Act authorized a rate cap. The PSC and the Large Customer Group appealed to the Montana Supreme Court the court's decision regarding tracking mechanisms, and we did not appeal its decision regarding the rate cap. 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 pending a resolution from the Montana Supreme Court and, therefore, we do not expect an order from the PSC until the third or fourth quarter 2001.
Natural Gas
Through December 31, 2000, approximately 240 natural gas customers with annual consumption of 5,000 dekatherms or more - 52 percent of our pre-choice natural gas-supply load - have chosen alternate suppliers since the transition to a competitive natural gas environment began in 1991.
Milltown Dam and our electric transmission operations remain subject to FERC and PSC regulation, and the PSC regulates our electric distribution operations.
Our natural gas transportation pipelines are generally not subject to FERC jurisdiction. We conduct limited interstate transportation subject to FERC jurisdiction, but FERC has allowed the PSC to set the rates for this interstate service. Our natural gas storage and distribution services, as well as our intrastate transportation services, are subject to PSC jurisdiction.
As a public utility, we also are subject to PSC jurisdiction when we issue, assume, or guarantee securities, or when we create liens on our properties.
Electric
FERC
On March 30, 1998, we submitted a cost-of-service filing with 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.
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 after the PSC issues its order.
PSC
In January 2000, as a result of the sale proceeds from the sale of our electric generating assets 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.
The Electric Act established a rate cap for all electric customers pursuant to which transmission and distribution rates could not be increased until July 1, 2000. On August 11, 2000, with the expiration of the Electric Act's cap, 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. On November 28, 2000, the PSC granted us an interim electric rate increase of approximately $14,500,000, with hearings on this submission held in late January and early February 2001. We expect a decision from the PSC during the second quarter 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 PSC work session in October 2000, the PSC denied our request. We sought reconsideration of the PSC's order, but the PSC also denied this request in January 2001. We have decided not to appeal this decision.
In accordance with our October 31, 1998 Asset Purchase Agreement with PPL Montana, as amended June 29, 1999 and October 29, 1999, we expect to sell our portion of the 500-kilovolt transmission system associated with Colstrip Units 1, 2, and 3 for $97,100,000. We expect this transaction to close in 2001. The after-tax proceeds that we expect to receive as a result of this transaction will remain with The Montana Power L.L.C.
Natural Gas/PSC
On January 19, 2001, we submitted with the PSC an Annual Gas Cost Tracker for an increase of approximately $51,000,000 and a Compliance Filing resulting from the sale of gathering and production properties previously in the natural gas utility's rate base for a credit of approximately $32,500,000. This resulted in a net increase of approximately $18,500,000 in revenues effective February 1, 2001. See Note 2, "Decision to Sell Energy Businesses," under the "Sale of Oil and Natural Gas Operations" section, for further information on the $32,500,000 credit to our natural gas utility ratepayers.
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. On November 28, 2000, the PSC granted us an interim natural gas rate increase of approximately $5,300,000, with hearings on this submission held in late January and early February 2001. We expect a decision from the PSC during the second quarter 2001.
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.
Assets Sold
On December 17, 1999, in accordance with the Asset Purchase Agreement entered into with PPL Montana, we sold substantially all of our electric generating assets and related contracts. We also sold an immaterial amount of associated transmission assets, totaling less than 40 miles. The asset sale did not include the Milltown Dam near Missoula, Montana (gross capacity of approximately 3 MWs) or any of our QF purchase-power contracts. It also did not include our leased share of the Colstrip Unit 4 generation or transmission assets.
As expected, the sale of our electric generating assets in December 1999 reduced the utility's net income for 2000. Utility revenues decreased because of discontinued off-system revenues that related to the electric generating assets sold. In addition, we no longer earn a return on our shareholders' investment in the electric generating assets. 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 our core customers for energy supply, but now these revenues recover the costs of the power that we purchase to serve these customers. The energy that we formerly generated and sold to core customers is now purchased pursuant to buyback contracts. The maximum price that we pay for power in the buyback contracts, $22.25/MWh, represents our net fully allocated supply 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 from these pre-closing environmental liabilities, including a limited indemnity obligation for losses arising from required remediation of pre-closing environmental conditions, whether known or unknown at the closing, limited to:
In December 2000, we received a claim notice related to this indemnity obligation. Based on available information, we do not expect this indemnity claim on the indemnity obligation to have a material adverse effect on our consolidated financial position, results of operations, or cash flows.
Cash Proceeds
At December 31, 1999, we recorded a regulatory liability and related deferred income tax to reflect the generation sale proceeds in excess of book value. The Company's current estimate of this liability, which will ultimately be determined in the Tier II docket, is approximately $215,000,000 before income taxes. This liability represents a deferral of the gain on the generation sale and nothing has been reflected in the Consolidated Statement of Income.
As part of our Tier II filing, we plan to deduct from the regulatory liabilities approximately $22,000,000 of other generation-related transition costs and approximately $65,600,000 of regulatory asset transition costs. The other generation-related transition costs consist mainly of SG&A costs and costs to retire debt. The regulatory asset transition costs consist mainly of capitalized conservation costs and carrying charges associated with Colstrip Unit 3.
We have used a portion of the net cash proceeds received (excluding the proceeds in excess of book value) to purchase shares of our common stock, to reduce debt, and to fund projects involving expansion of Touch America. For additional information on the purchase of shares of common stock and the reduction of debt, see Note 7, "Common Stock," and Note 10, "Long-Term Debt." For additional information on Touch America's projects, see Note 14, "Commitments," in the " Telecommunications" section.
Effect on 1999 Earnings
The asset sale affected positively our electric utility's 1999 earnings through the reversal of approximately $3,000,000 (after taxes) in interest expense recorded in prior years relating to Kerr Project liabilities and through recognition of approximately $10,000,000 in ITCs.
NOTE 6 - INCOME TAX EXPENSE
Income before income taxes was as follows:
Year Ended December 31 | |||
2000 | 1999 | 1998 | |
(Thousands of Dollars) | |||
Income from continuing operations: | |||
United States | $ 108,855 | $ 128,084 | $ 192,059 |
Canada | 237 | - | - |
Other countries | 699 | 1,167 | 480 |
109,791 | 129,251 | 192,539 | |
Income from discontinued operations | 192,241 | 65,158 | 51,255 |
$ 302,032 | $ 194,409 | $ 243,794 | |
The provision for income taxes differs from the amount of income tax that would result by applying the applicable United States statutory federal income tax rate to pretax income because of the following differences:
Year Ended December 31 | |||
2000 | 1999 | 1998 | |
(Thousands of Dollars) | |||
Computed "expected" income tax |
|
|
|
Adjustments for tax effects of: | |||
Statutory depletion | (2,535) | (3,440) | (4,156) |
Tax credits | (4,792) | (25,775) | (4,722) |
State income tax, net | 6,178 | 4,545 | 7,393 |
Reversal of utility book/tax |
|
|
|
Other | (6,141) | (4,628) | (8,453) |
Actual income tax expense | $ 102,541 | $ 44,063 | $ 78,174 |
Income tax expense as shown on the Consolidated Statement of Income consists of the following components:
Year Ended December 31 | |||
2000 | 1999 | 1998 | |
(Thousands of Dollars) | |||
Current: | |||
United States | $ 136,938 | $ 293,319 | $ 88,233 |
Canada | 13,669 | 1,710 | 1,212 |
Other countries | - | 30 | - |
State | 15,755 | 53,858 | 13,462 |
166,362 | 348,917 | 102,907 | |
Deferred: | |||
United States | (49,174) | (267,958) | (20,331) |
Canada | (7,509) | 9,930 | (1,851) |
Other countries | (18) | - | - |
State | (7,120) | (46,826) | (2,551) |
(63,821) | (304,854) | (24,733) | |
102,541 | 44,063 | 78,174 | |
Less: | |||
Income tax expense attributable |
|
|
|
Income tax expense attributable to |
|
|
|
Deferred tax (assets) liabilities are comprised of the following:
December 31 | ||
2000 | 1999 | |
(Thousands of Dollars) | ||
Plant related | $ 229,080 | $ 321,383 |
Investment in nonutility generation projects | 3,442 | 6,171 |
Other | 42,834 | 44,520 |
Gross deferred tax liabilities | 275,356 | 372,074 |
Coal reclamation | - | (48,096) |
Amortization of gain on sale/leaseback | (10,969) | (11,649) |
Deferred revenues | (99,319) | (103,578) |
Investment tax credit amortization | (8,553) | (14,055) |
Other | (195,672) | (204,152) |
Gross deferred tax assets | (314,513) | (381,530) |
Net deferred tax assets | (39,157) | (9,456) |
Less current deferred tax assets - net | (17,738) | (18,303) |
Total noncurrent deferred tax (assets) liabilities | $ (21,419) | $ 8,847 |
The change in net deferred tax (assets) liabilities differs from current year deferred tax expense as a result of the following:
Thousands | |
Change in noncurrent deferred tax | $ (29,701) |
Regulatory assets related to income taxes | 2,733 |
Current deferred tax assets - net | 2,587 |
Amortization of investment tax credits | (167) |
Coal deferred taxes reclassified to discontinued |
|
Other | (3,680) |
$ (1,846) | |
Discontinued operations deferred taxes | (61,975) |
Deferred tax expense | $ (63,821) |
NOTE 7 - COMMON STOCK
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 earlier 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 December 31, 2000, we had 103,742,934 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.
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. We purchased these shares at prices, including commissions, which ranged from $27.05 per share to $33.52 per share. The total cost was $144,872,000 for an average price of approximately $30.94 per share. In December 2000, weacquired an additional 1,933,900 shares of our stock under the program. The prices, including commissions, for these shares ranged from $27.26 per share to $33.53 per share and their total cost was $60,784,000 for an average price of approximately $31.43 per share. We have reflected the entire 6,616,000 shares purchased as treasury stock with a cost of $205,656,000 on the Consolidated Balance Sheet. As of March 16, 2001, the bank had acquired no further shares on our behalf.
We have a Shareholder Protection Rights Plan (SPRP) that provides one preferred share purchase right on each outstanding common share. Each purchase right entitles the registered holder, upon the occurrence of certain events, to purchase from us one one-hundredth of a share of Participating Preferred Shares, A Series, without par value. If it should become exercisable, each purchase right would have economic terms similar to one share of common stock. The purchase rights trade with the underlying shares and will, except under certain circumstances described in the SPRP, expire on June 6, 2009, unless redeemed earlier or exchanged by us.
Our Dividend Reinvestment and Stock Purchase Plan permits participants to: (a) acquire additional shares of common stock through the reinvestment of dividends on all or any specified number of common and/or preferred shares registered in their own names, or through optional cash payments of up to $60,000 per year; and (b) deposit common and preferred stock certificates into their Plan accounts for safekeeping. It also allows for other interested investors (residents of certain states) to make initial purchases of its common shares with a minimum of $100 and a maximum of $60,000 per year.
In conjunction with the pending divestiture of our energy businesses and our transition to a telecommunications enterprise, our Board of Directors voted in October 2000 to eliminate the dividend payment on our common stock effective the first quarter 2001. The final quarterly dividend on our common stock was $0.20 per share, payable on November 1, 2000. The Board's decision did not affect dividends on our preferred stock.
We have a 401(k) Retirement Savings Plan that covers eligible employees. We contribute, on behalf of the employee, a matching percentage of the amount contributed to the Plan by the employee. In 1990, we borrowed $40,000,000 at an interest rate of 9.2 percent to be repaid in equal annual installments over 15 years. The proceeds of the loan were lent on similar terms to the Plan Trustee, which used the proceeds to purchase 3,844,594 shares of our common stock. Shares acquired with loan proceeds are allocated monthly to Plan participants to help meet the Company's matching obligation. The loan, which is reflected as long-term debt, is offset by a similar amount in common shareholders' equity as unallocated stock. Our contributions plus the dividends on the shares held under the Plan are used to meet principal and interest payments on the loan with the Plan Trustee. As principal payments on the loan are made, long-term debt and the offset in common shareholders' equity are both reduced. At December 31, 2000, 2,756,662 shares had been allocated to the participants' accounts. We recognize expense for the Plan using the Shares Allocated Method, and the pretax expense was $4,267,000, $4,890,000, and $4,923,000 for 2000, 1999, and 1998, respectively.
Under the Long-Term Incentive Plan, we have issued options to our employees. Options issued to employees are not reflected in balance sheet accounts until exercised, at which time: (1) authorized, but unissued shares are issued to the employee; (2) the capital stock account is credited with the proceeds; and (3) no charges or credits to income are made.
Options were granted at the average of the high and low prices as reported on the New York Stock Exchange composite tape on the date granted and expire ten years from that date.
During 1999, a grant of 12,000 shares of restricted stock was issued to an individual under the Long-Term Incentive Plan. The award is subject to forfeiture or proration if the individual should terminate employment. In May 2000, restrictions were removed on 4,000 of the shares granted. Earned awards are reflected as common stock on the Consolidated Balance Sheet and as compensation expense in the Consolidated Statement of Income over the period of required employment. At December 31, 2000, 8,000 shares of restricted stock remained.
Option activity is summarized below:
2000 | 1999 | 1998 | ||||
Wtd Avg | Wtd Avg | Wtd Avg | ||||
Exercise | Exercise | Exercise | ||||
Shares | Price | Shares | Price | Shares | Price | |
Outstanding, beginning |
|
|
|
|
|
|
Granted | 1,199,545 | 34.36 | 919,510 | 32.14 | 2,234,658 | 24.50 |
Exercised | 149,834 | 17.07 | 88,857 | 10.83 | 702,562 | 11.25 |
Cancelled | 253,792 | 26.88 | 98,422 | 24.08 | 65,332 | 13.47 |
Outstanding, end of |
|
|
|
|
|
|
Shares under option at December 31, 2000, are summarized below:
Options Outstanding | Options Exercisable | |||||
Wtd Avg | Wtd Avg | Wtd Avg | ||||
Exercise | Exercise | Exercise | ||||
Exercise Price Range | Shares | Price | Life | Shares | Price | |
$10.81 to $11.31 | 228,099 | $11.05 | 5 yrs | 228,099 | $11.05 | |
$18.00 to $23.06 | 472,999 | 19.48 | 8 yrs | 383,446 | 18.64 | |
$26.53 to $32.50 | 2,359,346 | 28.21 | 9 yrs | 1,507,154 | 26.62 | |
$35.36 to $38.69 | 1,015,800 | 37.00 | 9 yrs | 258 | 35.36 | |
4,076,244 | 2,118,957 | |||||
As permitted by SFAS No. 123, "Accounting for Stock-Based Compensation," we have elected to follow Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" (APB 25), and related interpretations in accounting for our employee stock options. Under APB 25, because the exercise price of the employee stock options equals the market price of the underlying stock on the date of grant, no compensation expense is recognized. Disclosure of pro-forma information regarding net income and earnings per share is required by SFAS No. 123. This information has been determined as if we had accounted for our employee stock options under the fair value method of that statement. The weighted-average fair value of options granted in 2000, 1999, and 1998 was $16.35, $7.03, and $7.12 per share, respectively. We employed the binomial option-pricing model to estimate the fair value of each option grant on the date of grant. We used the following weighted-average assumptions for grants in 2000, 1999, and 1998, respectively: (1) risk-free interest rate of 6.05 percent, 6.35 percent, and 5.08 percent; (2) expected life of 6.2, 9.8, and 10 years; (3) expected volatility of 42.00 percent, 24.92 percent, and 19.34 percent; and (4) a dividend yield of zero percent, 5.97 percent, and 6.51 percent. Had we elected to use SFAS No. 123, compensation expense would have increased $11,827,000 in 2000, $5,280,000 in 1999, and $795,000 in 1998. The 2000 pro forma net income would be $188,632,000 with basic earnings per common share of $1.79 and diluted earnings per common share of $1.77. The 1999 pro forma net income would be $143,456,000 with basic earnings per common share of $1.31 and diluted earnings per common share of $1.30. The 1998 compensation expense effects on net income and earnings per share are not significant.
NOTE 8 - PREFERRED STOCK
We have 5,000,000 authorized shares of preferred stock. We cannot declare or pay dividends on our common stock while we have not either declared and set apart cumulative dividends or paid dividends on any of our preferred stock.
Our preferred stock is in three series as detailed in the following table:
Stated and Liquidation | Shares Issued | Thousands | |||
Series | Price* | 2000 | 1999 | 2000 | 1999 |
$6.875 | $100 | 360,800 | 360,800 | $36,080 | $36,080 |
6.00 | 100 | 159,589 | 159,589 | 15,959 | 15,959 |
4.20 | 100 | 60,000 | 60,000 | 6,025 | 6,025 |
Discount | - | - | (410) | (410) | |
580,389 | 580,389 | $57,654 | $57,654 | ||
*Plus accumulated dividends. | |||||
We have the option of redeeming our preferred stock with the consent or affirmative vote of the holders of a majority of the common shares on 30 days notice at $110 per share for our $6.00 Series and $103 per share for our $4.20 Series, plus accumulated dividends. Our $6.875 Series is redeemable in whole or in part, at any time on or after November 1, 2003, for a price beginning at $103.438 per share, which decreases annually through October 2013. After that time, the redemption price is $100 per share.
As discussed in Note 3, "Upcoming Special Meeting of Shareholders," we have asked our shareholders of common stock to vote in favor of the redemption of our outstanding Preferred Stock, $4.20 Series, and $6.00 Series. In addition, our Board of Directors will seek approval to redeem our Preferred Stock, $6.875 Series. We are not requesting our shareholders to take any action on this matter at this time.
NOTE 9 - COMPANY OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY TRUST
We established Montana Power Capital I (Trust) as a wholly owned business trust to issue common and preferred securities and hold Junior Subordinated Deferrable Interest Debentures (Subordinated Debentures) that we issue. At December 31, 2000 and 1999, 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.
On or after November 6, 2001, we can wholly redeem the Subordinated Debentures at any time, or partially redeem the Subordinated Debentures from time to time. We also can wholly redeem the Subordinated Debentures if certain events occur before that time. Upon repayment of the Subordinated Debentures at maturity or early redemption, the Trust Securities must be redeemed. In addition, we can terminate the Trust at any time and cause the pro rata distribution of the Subordinated Debentures to the holders of the Trust Securities.
Besides our obligations under the Subordinated Debentures, we have agreed to certain Back-up Undertakings. We have guaranteed, on a subordinated basis, payment of distributions on the Trust Securities, to the extent the Trust has funds available to pay such distributions. We also have agreed to pay all of the expenses of the Trust. Considered together with the Subordinated Debentures, the Back-up Undertakings constitute a full and unconditional guarantee of the Trust's obligations under the QUIPS. We are the owner of all the common securities of the Trust, which constitute 3 percent of the aggregate liquidation amount of all the Trust Securities.
NOTE 10 - LONG-TERM DEBT
The Mortgage and Deed of Trust (Mortgage) imposes a first mortgage lien on all physical properties owned, exclusive of subsidiary company assets and certain property and assets specifically excepted. The obligations collateralized are First Mortgage Bonds, including those First Mortgage Bonds designated as Secured Medium-Term Notes (MTNs) and those securing Pollution Control Revenue Bonds.
Long-term debt consists of the following:
December 31 | ||
2000 | 1999 | |
(Thousands of Dollars) | ||
First Mortgage Bonds: | ||
7 1/2% series, due 2001 | $ - | $ 25,000 |
7% series, due 2005 | 5,386 | 50,000 |
8 1/4% series, due 2007 | 365 | 55,000 |
8.95% series, due 2022 | 1,446 | 50,000 |
Secured Medium-Term Notes- |
|
|
Pollution Control Revenue Bonds: | ||
City of Forsyth, Montana |
|
|
5.90% series, due 2023 | 80,000 | 80,000 |
Unsecured Medium-Term Notes: | ||
Series A - maturing 2000-2022 8.68%-8.80% | - | 17,000 |
Series B - maturing 2001-2026 7.05%-7.96% | 100,000 | 100,000 |
$400 Million Senior Secured Credit Facility | 100,000 | - |
Natural Gas Transition Bonds - 6.20%, |
|
|
ESOP Notes Payable - 9.20%, due 2004 | 16,197 | 19,431 |
Revolving Credit Agreements | - | 17,502 |
Other | 1,365 | 28,111 |
Unamortized Discount and Premium | (2,859) | (3,797) |
478,517 | 677,467 | |
Less: Portion due within one year | 169,054 | 58,955 |
$ 309,463 | $ 618,512 | |
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 $182,803,000 of this amount, as follows:
We retired two additional issues of Series A Secured MTNs during 2000. On January 13, 2000, we retired $5,000,000 of 7.25 percent notes due January 19, 2024, and on June 1, 2000, we retired at maturity $20,000,000 of 7.20 percent notes.
On January 14, 2000, we retired $7,000,000 of 8.68 percent Series A Unsecured MTNs due February 7, 2022. We retired $10,000,000 of 8.80 percent Series A Unsecured MTNs at maturity on February 22, 2000.
All of the above debt retirements, including transaction costs, were made from the proceeds received from the 1999 sale of our electric generating assets.
On November 8, 2000, Touch America entered into 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. At December 31, 2000, $100,000,000 was outstanding under the term loan. Because the term loan must be prepaid under certain conditions, one of which is the sale of our remaining energy businesses, the amount has been classified as due within one year on the Consolidated Balance Sheet. The sale of Continental Energy on February 21, 2001, required us to pay down $27,600,000 on March 8, 2001. With this repayment, the term loan portion of the facility is permanently reduced from $200,000,000 to $172,400,000. Under this facility, interest is assessed against outstanding balances at a variable rate based on Touch America's credit rating and the London Interbank Offered Rate. At December 31, 2000, the rate was 9.5 percent. Annual commitment fees are based on the amount of loans outstanding, and at December 31, 2000, they were 1.0 percent on the unused revolver and 0.75 percent on the unused portion of the term loan.
The electric and natural gas legislation discussed in Note 5, "Deregulation, Regulatory Matters, and 1999 Sale of Electric Generating Assets" authorized the issuance of transition bonds. These securitization bonds involve the issuance of a non-recourse debt instrument. The bonds are repaid through, and secured by, a specified component of future revenues meant to recover the regulatory assets, thereby reducing the credit risk of the securities. This specific component of revenues is referred to as a CTC. An April 1998 PSC Financing Order relating to natural gas approved the issuance of up to $65,000,000 of such bonds. In December 1998, we issued $62,700,000 of 6.2 percent bonds. We will retire the bonds at six-month intervals from September 15, 1999, through March 15, 2012. Retirements are in varying amounts depending on revenues collected from customers. We established a special purpose entity (SPE), which is a wholly owned subsidiary, to issue the bonds. At December 31, 2000, approximately $58,412,000 was outstanding, of which approximately $4,162,000 was classified as due within one year on the Consolidated Balance Sheet.
Although the bonds were issued by an SPE and are without recourse to our general credit, the bonds are shown as debt on the Consolidated Balance Sheet. Similarly, the right to receive the revenues pledged to secure the bonds is a specific right of the SPE and not of Montana Power. However, as a wholly owned subsidiary, the SPE's revenues and expenses are shown as revenues and expenses in the Consolidated Statement of Income. Due to the regulatory mechanism for recognizing the operations of the SPE, including the amortization of the regulatory assets, we do not expect it to have a material effect on our consolidated financial position, results of operations, or cash flows.
To ensure that collections by the SPE are neither more nor less than the amount necessary to pay interest, principal, and other related issuance costs, we are required to file for periodic adjustments, or reconciliations, to the annual amounts to be collected by the SPE. The PSC is required to approve these adjustments.
Altana Exploration Ltd. (Altana), a wholly owned Canadian subsidiary, had an Extendible Revolving Term Credit agreement with the Royal Bank of Canada. The maximum amount of credit available under this agreement was $28,000,000 in Canadian dollars. At December 31, 1999, the United States dollar amount outstanding under the agreement was $17,502,000 ($24,259,000 Canadian dollars). We sold our oil and natural gas businesses, including Altana, on October 31, 2000, and this loan was assumed by the purchaser.
As discussed in Note 13, "Contingencies," we recorded long-term debt of approximately $57,000,000 regarding the Kerr mitigation in June 1997. This amount represented the net present value of future costs to be paid over the life of the license. With the sale of the generating assets, payments after the sale date are no longer our responsibility. Therefore, we reduced debt on the sale date to approximately $24,300,000. On December 30, 1999, we paid approximately $14,100,000 of this amount. We included the remaining balance of $10,200,000 at December 31, 1999, in "Other" in the table above, and it is classified as due within one year on the Consolidated Balance Sheet. The final payment for $10,200,000 occurred on January 3, 2000.
Continental Energy, a wholly owned subsidiary, had a $10,725,000 note associated with construction of the Tenaska Frontier Partners, LTD Project plant in Grimes County, Texas. The note was retired in October 2000. This non-interest bearing note secured by Continental Energy's guarantee to assure the availability of equity capital equal to Continental Energy's investment is included in the 1999 "Other" amount in the table above, and it is classified as due within one year on the 1999 Consolidated Balance Sheet.
Scheduled debt repayments on the long-term debt outstanding at December 31, 2000, amount to: $169,054,000 in 2001; $7,244,000 in 2002; $23,575,000 in 2003; $8,651,000 in 2004; $4,744,000 in 2005; and $265,249,000 thereafter.
NOTE 11 - Short-term borrowing
At December 31, 2000, we had committed lines of credit of $130,000,000 and uncommitted lines of $80,000,000. Facility or commitment fees on the committed lines of credit are not significant. We have the ability to issue up to $85,000,000 of commercial paper based on the total amount of unused committed lines of credit and revolving credit agreements.
At December 31, 2000, we had outstanding notes payable to banks for $75,000,000 at an average annual interest rate of 8.05 percent. Of these outstanding notes, $25,000,000 was issued from our committed lines of credit and the other $50,000,000 from our uncommitted lines of credit. In 2000, we replaced a $200,000,000 90-Day Credit Agreement with a $400,000,000 5-year Senior Secured Credit Facility, with Touch America as the borrower, for use in our telecommunications operations. For more information about this facility, see Note 10, "Long-Term Debt."
NOTE 12 - Retirement plans
We maintain trusteed, noncontributory retirement plans covering substantially all of our employees. Prior to 1998, our retirement benefits were based on salary, years of service, and social security integration levels. In 1998, we amended our retirement benefit plans' provisions. Our retirement benefits are now based on salary, age, and years of service.
Our plan assets consist primarily of domestic and foreign corporate stocks, domestic corporate bonds, and United States Government securities.
We also have an unfunded, nonqualified benefit plan for senior management, executives, and directors. In December 1998, we froze the benefits earned and curtailed the plan.
As a result of the sale of our electric generating assets in December 1999, 454 participants related to electric generation operations were curtailed from the retirement plan and approximately $22,700,000 in assets were transferred from the retirement plan trust in December 1999. Pursuant to the sales agreement, when the calculation was finalized in February 2000, approximately $3,200,000 of additional assets were transferred to the purchaser's trust. In accordance with SFAS No. 88, "Employers' Accounting for Settlements and Curtailments of Defined Benefit Pension Plans," we calculated a curtailment gain of approximately $4,100,000 and a settlement gain of approximately $7,800,000 in 1999. Due to regulatory accounting requirements, the gains were recorded as regulatory liabilities or offsets to regulatory assets, resulting in no income statement effect.
We offered a Special Retirement Program (SRP) to certain eligible employees during 2000. The SFAS No. 88 special termination charge resulting from 213 participants electing the SRP amounted to approximately $10,500,000. Of that amount, $661,000 was recorded as additional expense. Due to regulatory accounting requirements, the remaining amount was offset against regulatory liabilities, resulting in no income statement effect.
Effective October 31, 2000, we sold our oil and natural gas operations to PanCanadian. In conjunction with the sale, 90 participants were curtailed from the retirement plan and approximately $2,400,000 in assets were used to purchase annuities for benefits accrued through October 31, 2000. In accordance with SFAS No. 88, we calculated a curtailment gain of approximately $108,000 and a settlement gain of approximately $526,000.
Together with the majority of our subsidiaries, we also provide certain health care and life insurance benefits for eligible retired employees. The plan assets consist primarily of domestic and foreign corporate stocks, domestic corporate bonds, and United States Government securities. The PSC allows us to include in rates all utility Other Postretirement Benefits costs on the accrual basis provided by SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions."
We also have a voluntary 401(k) Retirement Savings Plan in conjunction with our retirement plans. We make matching contributions, including shares from a leveraged Employee Stock Ownership Plan arrangement and shares purchased on the open market. For costs associated with these plans, see Note 7, "Common Stock."
The following tables provide a reconciliation of the changes in the plans' benefit obligation, and fair value of assets over the two-year period ending December 31, 2000, and a statement of the funded status as of December 31 of both years:
Pension Benefits | Other Benefits | |||
2000 | 1999 | 2000 | 1999 | |
(Thousands of Dollars) | ||||
Change in benefit obligation: | ||||
Benefit obligation at January 1 | $ 242,005 | $ 273,401 | $ 21,628 | $ 24,512 |
Service cost on benefits earned | 5,820 | 8,724 | 571 | 844 |
Interest cost on projected |
|
|
|
|
Plan amendments | 7,578 | 8,578 | - | - |
Actuarial (gain)/loss | 588 | (32,712) | 4,773 | (502) |
Acquisitions/divestitures | - | - | (337) | - |
Curtailments | (462) | (5,712) | - | (3,093) |
Settlements | (2,429) | (18,096) | - | - |
Special termination benefits | 10,476 | - | - | - |
Adjustments for liability |
|
|
|
|
Gross benefits paid | (12,153) | (11,707) | (2,775) | (1,909) |
Benefit obligation at |
|
|
|
|
Change in plan assets: | ||||
Fair value of plan assets at |
|
|
|
|
Actual return/(loss) on plan |
|
|
|
|
Employer contributions | - | - | 2,237 | 2,817 |
Acquisitions/divestitures | (5,629) | (22,707) | - | - |
Adjustments for asset transfers | (2,682) | - | - | - |
Gross benefits paid | (9,942) | (9,546) | (2,775) | (1,909) |
Fair value of plan assets at |
|
|
|
|
Reconciliation of funded status: | ||||
Funded status at end of year | $ (15,405) | $ 34,262 | $ (15,895) | $ (11,712) |
Unrecognized net: | ||||
Actuarial gain | (28,394) | (65,893) | (1,129) | (6,263) |
Prior service cost | 23,310 | 17,856 | 1,593 | 1,822 |
Transition obligation | 121 | (363) | 10,554 | 11,751 |
Net amount recognized at |
|
|
|
|
The following table provides the amounts recognized in the Consolidated Balance Sheet as of December 31:
Pension Benefits | Other Benefits | |||
2000 | 1999 | 2000 | 1999 | |
(Thousands of Dollars) | ||||
Prepaid benefit cost | $ 942 | $ 7,571 | $ - | $ - |
Accrued benefit cost | (21,310) | (21,709) | (4,877) | (4,402) |
Net amount recognized at |
|
|
|
|
The following tables provide the components of net periodic benefit cost for the pension and other postretirement benefit plans, portions of which have been deferred or capitalized, for fiscal years 2000, 1999, and 1998:
Pension Benefits | |||
2000 | 1999 | 1998 | |
(Thousands of Dollars) | |||
Service cost on benefits earned | $ 5,820 | $ 8,719 | $ 8,079 |
Interest cost on projected benefit |
|
|
|
Expected return on plan assets | (23,894) | (25,650) | (22,870) |
Amortization of: | |||
Transition obligation | 44 | 43 | 358 |
Prior service cost | 1,826 | 1,741 | 1,468 |
Actuarial gain | (3,166) | (1,658) | (1,062) |
Immediate recognition of DC conversion | - | - | (142) |
Net periodic benefit cost (credit) | (1,079) | 2,735 | 4,069 |
Special termination benefit charge | 10,476 | - | - |
Curtailment (gain)/loss | (108) | (3,751) | 3,964 |
Settlement gain | (526) | (7,844) | - |
Net periodic benefit cost (credit) |
|
|
|
Other Benefits | |||
2000 | 1999 | 1998 | |
(Thousands of Dollars) | |||
Service cost on benefits earned | $ 571 | $ 844 | $ 777 |
Interest cost on projected benefit |
|
|
|
Expected return on plan assets | (818) | (722) | (671) |
Amortization of: | |||
Transition obligation | 897 | 1,098 | 1,120 |
Prior service cost | 166 | 177 | 69 |
Actuarial gain | (186) | (133) | (274) |
Net periodic benefit cost | 2,371 | 3,040 | 2,686 |
Curtailment gain | - | (374) | - |
Net periodic benefit cost after curtailments |
|
|
|
In 2000, funding for pension costs exceeded SFAS No. 87, "Employers' Accounting for Pensions," pension expense by $3,078,000. In 1999 and 1998, pension costs exceeded SFAS No. 87 pension expense by $1,631,000 and $1,780,000, respectively. The PSC allows recovery for the funding of pension costs through rates. Any differences between funding and expense are deferred for recognition in future periods. At December 31, 2000, the regulatory liability was $10,614,000.
The following assumptions were used in the determination of actuarial present values of the projected benefit obligation:
Pension Benefits | Other Benefits | |||
2000 | 1999 | 2000 | 1999 | |
(Thousands of Dollars) | ||||
Weighted average assumptions as | ||||
Discount rate | 7.50% | 7.75% | 7.50% | 7.75% |
Expected return on plan assets | 9.00% | 9.00% | 9.00% | 9.00% |
Rate of compensation increase | 4.40% | 4.40% | 4.40% | 4.40% |
Assumed health care costs trend rates have a significant effect on the amounts reported for the health care plans. A 1 percent change in assumed health care cost trend rates would have the following effects:
1% Increase | 1% Decrease | |
(Thousands of Dollars) | ||
Effect on total of service and interest cost |
|
|
Effect on the health care component of |
|
|
The assumed 2001 health care cost trend rates used to measure the expected cost of benefits covered by the plans is 9.00 percent. The trend rate decreases through 2007 to 5.50 percent.
NOTE 13 - CONTINGENCIES
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 this and another of FERC's orders and the United States Department of Interior's conditions contained in them. In December 2000, FERC issued an order approving a settlement among the parties. On February 15, 2001, the Circuit Court dismissed the petitions for review. Consequently, the approximately $24,000,000 that we paid into escrow in 2000 will be released to the Confederated Salish and Kootenai Tribes (Tribes) to be used in accordance with the terms of the settlement and, when we subsequently transfer to the Tribes 669 acres of land on the Flathead Indian Reservation, we will have fulfilled our obligations under the terms of this settlement. Because PPL Montana assumed the obligation in excess of $24,000,000, the basis in the properties sold decreased and the regulatory liability associated with the deferred gain on the sale increased accordingly.
Long-term power supply agreements, primarily an agreement with a large industrial customer, have exposed us losses and potential future losses. That agreement obligates us to deliver to our 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. Until the end of 2002, we must supply this and other industrial customers with electric energy purchased through an agreement indexed to the Mid-Columbia (Mid-C) market. As a result, we are exposed to the risk that electric energy we purchase at Mid-C prices can be higher than the fixed sales rates at which we are required to sell electric energy pursuant to our power supply agreements.
In June 1998, we entered into a swap with the industrial customer whose agreement exposes us to most of our risk, so that the customer could effectively purchase all of its electric energy from us at a fixed rate. At the same time, we entered into a separate fixed-price purchase and related Mid-C index 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 2000, however, our industrial customer whose contract exposes us to most of the commodity price risk increased its electric energy consumption, and wholesale electric prices increased substantially. The swap and related physical offset did not extend to the increase in our customer's consumption.
Specifically, the average monthly purchases of electric energy by this industrial customer 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-C 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 industrial 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 $8,400,000. 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.
To mitigate future losses, we entered into a five-month agreement in October 2000 with a counterparty - a fixed-for-floating financial swap whereby we fixed our purchase price on a portion of the electric energy needed to supply our industrial customers in exchange for a Mid-C index-based price. As long as our industrial customers do not materially change their estimated electric usage, this swap allows us to fix the total cost of supplying their electric energy during the term of the swap and, therefore, in conjunction with our existing agreements, should limit our losses from supplying these customers.
Based on the effects of the existing purchase and sales agreements, the financial swaps and customer usage, we incurred losses of approximately $6,000,000 in the fourth quarter 2000 and, assuming customer usage stays relatively constant, we expect to experience losses of approximately $4,000,000 in the first quarter 2001. If we continue to purchase electric energy at index-based market rates, or do not have other effective swaps in place, we estimate that the losses on agreements with these industrial customers - based on customer usage estimates and on forward price projections and broker quotations as of December 29, 2000 - could aggregate approximately $25,000,000 in the second quarter 2001 and more in subsequent quarters. Because of the volatility of the electric energy market in the western United States, particularly in the Pacific Northwest, and future possibilities of supplying these customers from alternative sources, we believe that estimating losses that we may experience beyond the second quarter 2001 would not be meaningful.
We will continue to recognize losses on these agreements if and as they occur. We continue to seek other opportunities to mitigate the commodity price risk associated with our power supply agreements, although we cannot assure that these efforts ultimately will be successful.
We and our subsidiaries are parties to various other legal claims, actions, and complaints arising in the ordinary course of business. We do not expect the conclusion of any of these matters to have a material adverse effect on our consolidated financial position, results of operations, or cash flows.
NOTE 14 - COMMITMENTS
Electric Utility
The Public Utilities Regulatory Policies Act (PURPA) requires a public utility to purchase power from QFs at a rate equal to what it would pay to generate or purchase power. These QFs are power production or co-generation facilities that meet size, fuel use, ownership, and operating and efficiency criteria specified by PURPA. The electric utility has 15 long-term QF contracts with expiration terms ranging from 2003 through 2032 that require us to make payments for energy capacity and energy received at prices established by the PSC. Three contracts account for 96 percent of the 101 MWs of capacity provided by these facilities. Montana's Electric Act designates the above-market portion of the QF costs as Competitive Transition Costs (CTCs) and allows for their recovery. For more information about CTCs, see Note 5, "Deregulation, Regulatory Matters, and 1999 Sale of Electric Generating Assets."
The Asset Purchase Agreement with PPL Montana, dated as of October 31, 1998 and amended June 29, 1999 and October 29, 1999, included two Wholesale Transition Service Agreements (WTSAs), effective December 17, 1999. These agreements enable us to fulfill our obligation to supply power until July 2002 to those customers who have not chosen another supplier. One agreement commits us to purchase 200 MWs per hour through December 2001, and the other agreement to purchase through June 2002 any power requirements remaining after having received power through the first WTSA, QFs, and Milltown Dam. Both agreements price the power sold at a market index, with a monthly floor and an annual cap. Under both agreements, the annual cap is $22.25/MWh, which has been in effect for most of 2000 because wholesale electric energy prices in the Pacific Northwest have been higher than this amount. Assuming an 8.05 percent discount rate (our average short-term borrowing rate at December 31, 2000), current market indices, and current load forecasts, we estimate the net present value of the power purchased under the WTSAs at $81,000,000 for 2001 and $34,000,000 for 2002.
Our former affiliate, The Montana Power Trading & Marketing Company (MPT&M) - which we sold on October 31, 2000 as part of the oil and natural gas businesses - had entered into several power purchase agreements in 1998. These agreements were assigned to the electric utility in 2000. One agreement obligates us to purchase 40 MWs per hour at a fixed rate until May 2001, and the other to purchase 100 MWs per hour of firm capacity and firm energy at 100 percent load factor at a market-indexed rate until August 2001.
Natural Gas Utility
The natural gas utility entered into take-or-pay contracts with Montana natural gas producers to provide adequate supplies of natural gas for our utility customers. We currently have six of these contracts, with expirations between 2002 and 2006. If we can supply customers with less expensive natural gas, we purchase the minimum required by the take-or-pay contracts. The cost of purchases through take-or-pay contracts is part of those costs submitted to the PSC for recovery in future rates. Since 1998, the natural gas utility enters only into one-year take-or-pay contracts, because of the uncertainty about the number and timing of customers who will choose another natural gas supplier under Montana's Natural Gas Act.
Exited Nonutility Operations
In our nonutility operations, we entered into various contracts that committed us to purchase electric energy and pipeline reserve capacity for natural gas shipments. We assigned the electric energy contracts to our utility operations in 2000, and we sold our former oil and natural gas operations on October 31, 2000.
Contractual Payments and Present Value
Total payments under all of these contracts for the prior three years were as follows:
Utility | Exited Nonutility | Total | |||
Electric | Natural Gas | Electric | Natural Gas | ||
(Thousands of Dollars) | |||||
2000 | $ 272,075 | $ 7,101 | $ - | $ 8,100 | $ 287,276 |
1999 | 61,274 | 4,069 | 26,076 | 7,898 | 99,317 |
1998 | 50,611 | 3,508 | 15,355 | 4,454 | 73,928 |
Under the above agreements, the present value of future minimum payments, at a discount rate of 8.05 percent, is as follows:
Utility | Total | ||
Electric | Natural Gas | ||
(Thousands of Dollars) | |||
2001 | $ 224,435 | $ 5,003 | $ 229,438 |
2002 | 42,905 | 4,450 | 47,355 |
2003 | 8,380 | 641 | 9,021 |
2004 | 8,001 | 546 | 8,547 |
2005 | 7,537 | 465 | 8,002 |
Remainder | 97,486 | 395 | 97,881 |
$ 388,744 | $ 11,500 | $ 400,244 | |
Discontinued Coal Operations
Northwestern Resources entered into a lignite lease agreement that requires minimum annual payments of $1,125,000, adjusted quarterly for inflation, for overriding royalties. The payments, which began in 1991, will continue until Northwestern Resources pays the equivalent of $18,750,000, in 1986 dollars. At December 31, 2000, the remaining payments under this agreement were $7,411,000. Under current mine plans, Northwestern Resources expects to recoup these payments through lignite sales.
Construction Projects
Touch America has contracted with Northern Telecom, Inc. (Nortel) to furnish and install optical electronic equipment on certain fiber optic networks. In 2000, Touch America paid approximately $26,400,000 for these installations and will schedule others in 2001 as segments of fiber optic networks under construction 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 June 30, 2000 acquisition of telecommunications properties, discussed in Note 4, "Acquisition of Telecommunications Properties." As of December 31, 2000,Touch America had invested approximately $48,900,000 of the estimated $70,000,000 installation cost.
In October 1999, Touch America entered into a contract to construct a high-speed, fiber optic network for AT&T Corp (AT&T). The contract allows Touch America to install its own fiber optic network at the same time and along the same routes it is constructing for AT&T. The network will span more than 4,300 miles and will cover six different routes in the West, Pacific Northwest, Northern Rocky Mountains, and Midwest. The contract contains capped performance incentives if we meet, and capped penalties if we do not meet, aggressive completion targets. All routes are scheduled for completion in mid-2001. We estimate the cost of the project at $488,000,000, of which approximately $205,000,000 was invested in 2000 and $283,000,000 is budgeted for 2001. We expect AT&T and other third parties to reimburse us for approximately 50 percent of the total cost, as stages of the project are completed.
In July 2000, Touch America entered into two separate agreements involving 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 the exclusive and indefeasible 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 $14,000,000 has been paid through December 2000. Annual maintenance fees are expected to be approximately $200,000 .
The second agreement, with the Chicago Transit Authority, gives Touch America an exclusive and indefeasible right to use 6 ducts along an approximately 18-mile route for 22 years, with an option to renew upon the mutual agreement of the parties. Touch America will pay $9,000,000 for these rights, of which $8,200,000 has been paid through December 2000. Annual maintenance fees are expected to be approximately $45,000.
In December 2000, Touch America contracted with Cisco Systems Inc (Cisco) to install computer equipment at 7 Points of Presence (POPs) on Touch America's fiber optic networks in the western United States. This equipment will allow Touch America to sell Internet Protocol (IP) at those sites. Touch America expects the installations to be completed in the second quarter 2001 and will pay Cisco $6,400,000 upon completion.
Joint Ventures
Touch America has entered into strategic alliances to expand its network and increase its revenues. In accordance with the agreements governing these 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 this route and expects to complete the route in mid-2001 at an estimated cost of $100,000,000. Touch America will purchase 4 of the 6 conduits of the network and sell 3 toAT&T and exchange another with a third party. Sierra Touch America, LLC will retain ownership of the remaining 2 conduits, of which each partner will have an equal share. At year-end 2000, Touch America and Sierra Pacific Communications each contributed $2,675,000 to the joint venture, and Touch America paid $10,000,000 toward the purchase of the 4 conduits. 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, formed a 50-50 joint venture named American Fiber Touch, LLC (AFT) to connect national and regional fiber optic networks between Plano, Illinois and St. Louis, Missouri. This network will make up 296 miles of the 4,300-mile fiber optic network discussed above. American Fiber Touch has begun construction of the Plano-St. Louis route and expects to complete it in the second quarter 2001 at an estimated cost of $43,000,000. At year-end 2000, Touch America had advanced $6,950,000 for construction costs, and it plans to contribute $14,600,000 in 2001.
In August 1999, Touch America and Xcel (formerly known as New Century Energies or NCE) formed a 50-50 joint venture called Northern Colorado Telecommunications, LLC to provide a full range of telecommunication services, including private line service, to enterprises in the Denver metropolitan area. For the venture, Xcel contributed long-term indefeasible rights of use of its existing fiber optic network in the Denver metropolitan area; Touch America will construct six miles of fiber optic cable and install optical electronic equipment at an estimated cost of $10,000,000. Since the project's inception, Touch America has contributed $3,800,000 and plans to contribute $4,500,000 in 2001 and $500,000 in both 2002 and 2003.
In August 1999, Touch America and Qwest Wireless (formerly known as U S WEST Wireless) entered into a 49.9-50.1 joint venture, TW Wireless (TWW), to provide "one number" wireless telephone service in an eight-state region of the Pacific Northwest and Upper Midwest. That service provides a customer with one directory number for cell phone and home or business phone. Both companies contributed PCS licenses to the venture. To date, Touch America has contributed approximately $20,700,000 toward the costs of the wireless infrastructure and will contribute an estimated total of $35,800,000 more in 2001 and 2002.
In November 1999, FTV Communications LLC (FTV), the limited liability company formed by Touch America, Williams Communications, and Enron Broadband Services, began an expansion of regeneration sites along the Portland to Las Vegas portion of the fiber optic route that FTV constructed. FTV expects to complete the project in the second quarter 2001, and Touch America's share of the costs is approximately $3,800,000.
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 sold its equity position in ITS in April 2000, with no gain or loss recorded. Under the terms of the exit agreement:
Exchanges
In March 2000, Touch America and Williams Communications, Inc. agreed to an exchange of fiber and cash to expand both companies' fiber optic networks. Touch America received 24 fibers on a 1,053-mile route and $650,000 in exchange for 24 fibers on a 1,213-mile route. This exchange will expand Touch America's network from Denver to Kansas City, Missouri to Des Moines to Minneapolis.
Investment
In January 2000, Touch America signed a purchase agreement with Minnesota PCS, LP (MPCS) to acquire a 25 percent interest in MPCS' wireless telephone business, which owns PCS licenses in North Dakota, South Dakota, Minnesota, and Wisconsin. In accordance with the agreement, Touch America made an initial equity investment of $2,700,000 in MPCS and in August 2000 loaned MPCS $12,000,000 in interest-bearing notes payable on October 1, 2002. From October through December 2000, Touch America loaned an additional $4,375,000 to MPCS to cover network construction and operating costs. Touch America also has guaranteed the payment of $7,420,000 in loans made to MPCS through 2007.
Leases
In January 2000, Touch America entered into a Reciprocal IRU Lease and Exchange Option Agreement with Velocita (formerly known as PF.Net Construction Corp). This agreement is a 20-year IRU lease with an option to exchange the leased property at a future date. Under the agreement, Touch America will lease approximately 5,900 route miles from Velocita and Velocita will lease approximately 4,400 miles of fiber from Touch America. Prior to commencement of the lease, Touch America will prepay $48,500,000 for the difference in route miles. The prepayment will be amortized to expense over the 20-year lease term. As of December 31, 2000, approximately $12,000,000 had been paid.
Based on all of the Touch America agreements above, the present value of Touch America's estimated payments discounted at a rate of 8.05 percent is as follows:
2001 | 2002 | 2003 | Total |
(Thousands of Dollars) | |||
$ 353,900 | $ 5,400 | $ 900 | $ 360,200 |
Touch America has also entered into operating lease agreements for private line, long-distance, local-access, and equipment services, as well as office space, with varying termination dates, for which it paid approximately $2,400,000 in 2000 and expects to pay approximately $4,000,000 in 2001.
On December 30, 1985, we sold our 30-percent share of Colstrip Unit 4 and agreed to lease back our share under a net, 25-year lease with annual payments of approximately $32,000,000. We have been accounting for this transaction as an operating lease. We did not sell this nonutility leasehold interest and its related assets and liabilities and contract obligations to PPL Montana in 1999. This lease is included in the anticipated sale of the utility business to Northwestern Corporation. We have no other material minimum operating lease payments.
Capitalized leases are not material and are included in other long-term debt.
Rental expense for the prior three years, including Colstrip Unit 4 and Touch America, was $44,300,000 for 2000, $59,300,000 for 1999, and $58,800,000 for 1998.
NOTE 15 - INFORMATION ON INDUSTRY SEGMENTS
Our continuing telecommunications business owns, operates, and develops a fiber optic network and provides wireless services mainly through PCS and LMDS. Our telecommunication business offers a full line of high-speed voice, data, video, and Internet services; provides colocation services; leases dark fiber and conduit rights on the network; and offers construction management oversight services for installation of fiber networks. Our continuing utility business purchases, transmits, and distributes electric energy and natural gas, and the Colstrip Unit 4 division manages long-term power supply agreements. Continental Energy developed and invested in independent power projects and other energy-related businesses. We closed the sale of Continental Energy on February 21, 2001.
In our discontinued coal operations, we mine and sell coal and lignite; in our former oil and natural gas operations, we explored for, developed, produced, processed, and sold crude oil and natural gas and traded crude oil, natural gas, and natural gas liquids.We closed the sale of our former 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, temporary investments, and administrative services' properties.
We consider segment information for foreign operations insignificant.
The following tables present selected information on our industry segments' continuing operations:
NOTE 15 - INFORMATION ON INDUSTRY SEGMENTS
Year Ended December 31, 2000 | |||
(Thousands of Dollars) | |||
CONTINUING | |||
Tele-communications |
|
| |
Sales to unaffiliated customers | $ 322,952 | $ 535,390 | $ 129,373 |
Intersegment sales | 334 | 1,036 | 269 |
Depreciation, depletion, and amortization | 22,423 | 39,559 | 8,830 |
Pretax operating income | 49,670 | 18,167 | 28,113 |
Interest expense | 812 | 30,289 | 16,077 |
Interest income | 1,109 | 16,614 | 4,869 |
Earnings from unconsolidated investments | (1,473) | - | - |
Income tax expense | 18,881 | (2,091) | 2,861 |
Capital expenditures | 554,119(a) | 42,718 | 7,546 |
Identifiable assets | 1,085,324(b) | 1,144,684 | 261,768 |
CONTINUING (continued) | |||
Continental | Other | Corporate | |
Sales to unaffiliated customers | $ 1,000 | $ 10,993 | $ - |
Intersegment sales | - | 1,536 | - |
Depreciation, depletion, and amortization | 480 | 5,734 | - |
Pretax operating loss | (1,852) | (16,492) | - |
Interest expense | 31 | 3,999 | - |
Interest income | 3,328 | 3,992 | - |
Earnings from unconsolidated investments | 55,627 | - | - |
Income tax expense | 20,318 | (6,371) | - |
Capital expenditures | 12,230 | 11,600 | 16,003 |
Identifiable assets | 37,091 | 16,755 | 177,524 |
RECONCILIATION TO CONSOLIDATED | |||
Segment Total | Adjustments(c) | Consolidated Total | |
Sales to unaffiliated customers | $ 999,708 | $ - | $ 999,708 |
Intersegment sales | 3,175 | (3,175) | - |
Depreciation, depletion, and amortization | 77,026 | - | 77,026 |
Pretax operating income | 77,606 | - | 77,606 |
Interest expense | 51,208 | (11,308) | 39,900 |
Interest income | 29,912 | (11,308) | 18,604 |
Earnings from unconsolidated investments | 54,154 | - | 54,154 |
Income tax expense | 33,598 | - | 33,598 |
Capital expenditures | 644,216 | - | 644,216 |
Identifiable assets | 2,723,146 | 282,129(d) | 3,005,275 |
(a)This amount includes approximately $205,900,000 related to our June 30, 2000 telecommunications acquisition.
(b)This amount includes approximately $145,600,000 of intangible assets related to our June 30, 2000 acquisition.
(c)The amounts indicated include certain eliminations between the business segments.
(d)The adjustment of identifiable assets represents the identifiable assets of discontinued coal operations. The " Consolidated Total" of identifiable assets represents the consolidated total of both continuing and discontinued industry segments and, therefore, differs from the Consolidated Balance Sheet (which nets assets and liabilities of discontinued operations). The difference between the $2,816,794,000 figure shown on the Consolidated Balance Sheet and the $3,005,275,000 shown above is attributable to $188,481,000 of discontinued coal liabilities that were netted with assets in "Investment in discontinued coal operations"on the Consolidated Balance Sheet.
Year Ended December 31, 1999 | |||
(Thousands of Dollars) | |||
CONTINUING | |||
Tele-communications |
|
| |
Sales to unaffiliated customers | $ 84,903 | $ 531,883 | $ 111,416 |
Intersegment sales | 1,012 | 14,221 | 331 |
Depreciation, depletion, and amortization | 9,048 | 56,282 | 9,279 |
Pretax operating income | 25,801 | 113,740 | 16,459 |
Interest expense | 1 | 38,467 | 15,229 |
Interest income | 810 | 4,524 | 545 |
Earnings from unconsolidated investments | 9,839 | - | - |
Income tax expense | 14,088 | 13,054 | 391 |
Capital expenditures | 153,617 | 50,503 | 13,115 |
Identifiable assets | 290,722 | 1,089,017 | 406,413 |
CONTINUING (continued) | |||
Continental | Other | Corporate | |
Sales to unaffiliated customers | $ 1,310 | $ 47,660 | $ - |
Intersegment sales | - | 1,665 | - |
Depreciation, depletion, and amortization | 414 | 4,553 | - |
Pretax operating loss | (674) | (17,397) | - |
Interest expense | 18 | 3,357 | - |
Interest revenue | 5,645 | 6,926 | - |
Earnings from unconsolidated investments | 21,042 | - | - |
Income tax expense | 8,136 | (4,839) | - |
Capital expenditures | - | - | 15,957 |
Identifiable assets | 24,114 | 14,008 | 630,417 |
RECONCILIATION TO CONSOLIDATED | |||
Segment Total | Adjustments(a) | Consolidated Total | |
Sales to unaffiliated customers | $ 777,172 | $ - | $ 777,172 |
Intersegment sales | 17,229 | (17,229) | - |
Depreciation, depletion, and amortization | 79,576 | - | 79,576 |
Pretax operating income | 137,929 | - | 137,929 |
Interest expense | 57,072 | (9,987) | 47,085 |
Interest income | 18,450 | (9,987) | 8,463 |
Earnings from unconsolidated investments | 30,881 | - | 30,881 |
Income tax expense | 30,830 | - | 30,830 |
Capital expenditures | 233,192 | - | 233,192 |
Identifiable assets | 2,454,691 | 594,052(b) | 3,048,743 |
(a)The amounts indicated include certain eliminations between the business segments.
(b)The adjustment of identifiable assets represents the identifiable assets of operations that became discontinued in 2000 - the consolidated coal and oil and natural gas operations.
Year Ended December 31, 1998 | |||
(Thousands of Dollars) | |||
CONTINUING | |||
Tele-communications |
|
| |
Sales to unaffiliated customers | $ 87,792 | $ 526,527 | $ 107,354 |
Intersegment sales | 1,298 | 4,722 | 425 |
Depreciation, depletion, and amortization | 7,090 | 59,213 | 8,705 |
Pretax operating income | 39,095 | 127,709 | 15,019 |
Interest expense | 1 | 48,903 | 12,946 |
Interest income | 668 | 4,523 | 925 |
Earnings from unconsolidated investments | 10,865 | - | - |
Income tax expense | 19,772 | 27,760 | 168 |
Capital expenditures | 56,203 | 61,938 | 21,989 |
Identifiable assets | 189,561 | 1,664,775 | 405,670 |
CONTINUING (continued) | |||
Continental | Other | Corporate | |
Sales to unaffiliated customers | $ 1,296 | $ 47,988 | $ - |
Intersegment sales | - | 1,913 | - |
Depreciation, depletion, and amortization | 6,316 | 3,921 | - |
Pretax operating loss | (7,674) | (20,164) | - |
Interest expense | 58 | 9,716 | - |
Interest income | 3,838 | 944 | - |
Earnings from unconsolidated investments | 89,525 | - | - |
Income tax expense | 30,946 | (11,803) | - |
Capital expenditures | 10,725 | - | 189 |
Identifiable assets | 33,483 | 14,213 | 43,211 |
RECONCILIATION TO CONSOLIDATED | |||
Segment Total | Adjustments(a) | Consolidated Total | |
Sales to unaffiliated customers | $ 770,957 | $ - | $ 770,957 |
Intersegment sales | 8,358 | (8,358) | - |
Depreciation, depletion, and amortization | 85,245 | - | 85,245 |
Pretax operating income | 153,985 | - | 153,985 |
Interest expense | 71,624 | (6,759) | 64,865 |
Interest income | 10,898 | (6,759) | 4,139 |
Earnings from unconsolidated investments | 100,390 | - | 100,390 |
Income tax expense | 66,843 | - | 66,843 |
Capital expenditures | 151,044 | - | 151,044 |
Identifiable assets | 2,350,913 | 577,182(b) | 2,928,095 |
(a)The amounts indicated include certain eliminations between the business segments.
(b)The adjustment of identifiable assets represents the identifiable assets of operations that became discontinued in 2000 - the consolidated coal and oil and natural gas operations.
NOTE 16 - NEW ACCOUNTING PRONOUNCEMENTS
SAB No. 101, "Revenue Recognition in Financial Statements" was issued by the SEC in December 1999 and is applicable to us beginning in the fourth quarter 2000.
As it relates to our companies, SAB No. 101 mainly affects Touch America. It requires that particular one-time charges received from customers be recognized as revenues over the period of time that the charges are earned rather than as revenues when assessed or paid. Our telecommunications operations realize payment of one-time fees for such items as installations and activations. Prior to SAB No. 101, we recognized these revenues when received. With the adoption of SAB No. 101 in the fourth quarter 2000, we now recognize these revenues over the period in which they are earned, which coincides with the number of years that those customers are anticipated to be customers of Touch America. The one-time charges all are received either from wholesale or commercial customers and, due to the number of transactions, the amounts cannot be segregated into the two customer classes. Under our policy, therefore, we amortize these deferred revenues over the average lives of wholesale and commercial customers. We have not deferred any costs for installations, activations, or subscriber acquisitions.
We have evaluated SAB No. 101, and the cumulative catch-up for its adoption had no material effect on our consolidated financial position, results of operations, or cash flows. The adoption of SAB No. 101 affected only our 2000 operations.
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, "Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133 was issued in June 1998. 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 delayed for one year the effective date of SFAS No. 133, meaning that we are required to adopt SFAS No. 133 on January 1, 2001.
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. As discussed in Note 2, "Decision to Sell Energy Businesses," we sold our oil and natural gas businesses - including MPT&M, which engaged in energy trading activities - on October 31, 2000.
We have reviewed our commodity purchase and sale agreements to evaluate exposure to potential embedded derivatives under SFAS No. 133 and SFAS No. 138. Effective January 1, 2001, we have accounted for the electric swap agreements described in Note 1, "Summary of Significant Accounting Policies," in the "Derivative Financial Instruments" section, as effective cash flow hedges pursuant to SFAS No. 133. Accordingly, these instruments have been marked to market, at January 1, 2001, with a corresponding credit entry made to Other Comprehensive Income for approximately $18,800,000 before income taxes, representing our cumulative transition adjustment in adopting SFAS No. 133.
QUARTERLY FINANCIAL DATA
Operating revenues, operating income, and net income from continuing operations; net income from discontinued operations; and consolidated net income per common share for the four quarters of 2000 and 1999 are shown in the tables below. Operating revenues and income include intersegment sales and expenses. Due to the seasonal nature of the utility business, the annual amounts are not generated evenly by quarter during the year.
For additional information on the status of the sales of our energy businesses and our application of discontinued operations accounting for our coal and former oil and natural gas operations, see Note 2, "Decision to Sell Energy Businesses," and the "Results of Operations" section of MD&A. For additional information on how we classify earnings from unconsolidated investments, see MD&A, in the "2000 Compared With 1999" section, under "Consolidated Results." ;
Quarter Ended1 & 2 | ||||
Dec. 31, | Sept. 30, | June 30, | March 31, | |
2000 | 2000 | 2000 | 2000 | |
(Thousands of Dollars) | ||||
(except per-share amounts) | ||||
Continuing operating revenues | $ 369,308 | $ 269,982 | $ 164,231 | $ 196,187 |
Continuing operating income | 35,046 | 12,017 | 4,741 | 25,802 |
Continuing net income | 27,758 | 6,858 | 22,779 | 15,108 |
Discontinued net income | 71,827 | 23,507 | 12,716 | 15,248 |
Consolidated net income available |
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|
Basic earnings per share of common |
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|
Diluted earnings per share of |
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1Adoption of SAB No. 101 had an immaterial effect for all quarters. | ||||
2In the fourth quarter 2000, we reclassified all "Earnings from unconsolidated investments" in "Other income - net." We previously reported these earnings separately in revenues and have reclassified all amounts from prior periods to reflect this change. In our Form 10-Q/A for the third quarter 2000, filed on April 9, 2001, we report these earnings separately in revenues rather than in "Other income - net." | ||||
QUARTERLY FINANCIAL DATA (Continued)
Quarter Ended | ||||
Dec. 31, | Sept. 30, | June 30, | March 31, | |
1999 | 1999 | 1999 | 1999 | |
(Thousands of Dollars) | ||||
(except per-share amounts) | ||||
Continuing operating revenues | $ 221,275 | $ 172,585 | $ 179,295 | $ 204,017 |
Continuing operating income | 43,574 | 20,346 | 32,084 | 41,925 |
Continuing net income | 47,367 | 10,997 | 13,671 | 22,696 |
Discontinued net income | 13,772 | 17,292 | 10,656 | 10,205 |
Consolidated net income available |
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|
Basic earnings per share of common |
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Diluted earnings per share of |
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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
DIRECTORS OF THE REGISTRANT
The following table shows our current Board of Directors, who are elected by our shareholders for staggered three-year terms, their ages at December 31, 2000, and the year they were elected. A brief description of their business experience during the past five years is also included.
Name | Age at | Position/Business Experience | ||
Terms Expiring in 2003 | ||||
Kay Foster | 59 | Director since January 1992. Ms. Foster is a resident of Billings, Montana; has been President of Planteriors Unlimited, Inc., an interior foliage plant sales and maintenance business in Billings and Missoula, Montana since April 1999; and has owned this business since December 1980. | ||
Carl Lehrkind III | 62 | Director since July 1984. Mr. Lehrkind is a resident of Bozeman, Montana; has been President of Lehrkind's, Inc., a beverage bottler and distributor in Bozeman, Montana, since February 1970; and has been President, Owner and Operator of Yellowstone Country Food and Beverage restaurants in Livingston, Montana and Miles City, Montana since February 1993. | ||
Jerrold P. Pederson | 58 | Director since July 1993. Mr. Pederson is a resident of Butte, Montana, and has been Vice Chairman of the Board since March 2000 and Chief Financial Officer of The Montana Power Company since May 1991. Recent Positions: Vice President from May 1991 to March 2000 and Chief Information Officer for The Montana Power Company from May 1996 to May 1999. | ||
Deborah D. McWhinney | 45 | Director since August 1999. Ms. McWhinney is a resident of San Francisco, California, and has been President, Services for Investment Managers, for Schwab, Inc., a provider of financial services, since February 2001 . Recent Positions: President of Internet Profiles Corporation (I/PRO), a provider of Web traffic measurement, auditing, and research from July 1999 to January 2001; Executive Vice President from May 1997 to July 1999 and Senior Vice President from 1995 to 1997 for VISA International; Vice President from 1986 to 1995 and Senior Vice President from 1990 to 1995 for Bank of America Retail Banking Group; and Vice President from 1981 to 1986 for Bank of America Corporate Banking Group. Other Directorships: Director, Novadigm, Inc. | ||
Terms Expiring in 2002 | ||||
Tucker Hart Adams | 62 | Director since September 1995. Dr. Adams is a resident of Colorado Springs, Colorado; has been President and Chief Executive Officer of The Adams Group Inc., a consulting firm specializing in economic research, analysis, and forecasting, since January 1989; and publishes the newsletter, "Today's Economy." Other Directorships: Trustee, Tax Free Fund of Colorado; Trustee, Aquila Rocky Mountain Equity Fund. | ||
Alan F. Cain | 61 | Director since March 1989. Mr. Cain is a resident of Bigfork, Montana, and was President and Chief Executive Officer of BlueCross BlueShield of Montana, a health service corporation, in Helena, Montana, from March 1986 until his retirement in September 1999. | ||
John G. Connors | 41 | Director since January 1998. Mr. Connors is a resident of Medina, Washington, and has been Senior Vice President of Finance and Administration and Chief Financial Officer of Microsoft Corporation, a computer software business, since January 2000. Recent Positions: Vice President from April 1999 to January 2000 for Microsoft Enterprise Group and Vice President and Chief Information Officer from July 1996 to April 1999 and Corporate Controller from April 1994 to July 1996 for Microsoft Corporation. Other Directorships: Director, Primus Knowledge Solutions, Inc. | ||
Robert P. Gannon | 56 | Director since January 1990. Mr. Gannon is a resident of Butte, Montana, and has been Chairman of the Board of Directors since January 1998, Chief Executive Officer since July 1997, and President since January 1990 for The Montana Power Company. Recent Positions: Vice Chairman of the Board of Directors from January 1996 to December 1997 and Chief Operating Officer responsible for utility operations from June 1992 to January 1996 for The Montana Power Company. | ||
Terms Expiring in 2001 | ||||
R. D. Corette | 60 | Director since July 1990. Mr. Corette is a resident of Butte, Montana, and has been an attorney, owner, and employee for Corette, Pohlman & Kebe, a law firm in Butte, Montana, since 1966. | ||
John R. Jester | 59 | Director since September 1995. Mr. Jester is a resident of Gig Harbor, Washington, and has been President of Bargain Street LLC, a retail firm, since September 1997. Recent Positions: President of Muzak Limited Partnership, a telecommunications-based business, from January 1988 to May 1997. | ||
Noble E. Vosburg | 59 | Director since October 1988. Mr. Vosburg is a resident of Great Falls, Montana, and has been President and Chief Executive Officer of Pacific Steel & Recycling, a steel service center and recycling business in Great Falls, Montana, since May 1982. | ||
EXECUTIVE OFFICERS OF THE REGISTRANT
The following table shows our current Executive Officers, who are elected or appointed annually by the Board of Directors, their ages at December 31, 2000, and their areas of responsibility. A brief description of their business experience during the past five years is also included.
Name | Age | Position/Business Experience |
R. P. Gannon | 56 | Chairman of the Board, President, and Chief Executive Officer. Mr. Gannon was elected to the Board of Directors in 1990 and was elected Chairman of the Board of Directors in 1998. He served as Vice Chairman of the Board of Directors from 1996 to 1997. He has served as President since 1990 and as Chief Executive Officer since 1997. |
J. P. Pederson | 58 | Vice Chairman of the Board and Chief Financial Officer. Mr. Pederson was elected to the Board of Directors in 1993. He was elected Vice Chairman in March 2000 and has served as Chief Financial Officer since 1991. He also served as Vice President from May 1991 - March 2000 and Chief Information Officer from 1996 - 1999. |
M. J. Meldahl | 51 | Executive Vice President and Chief Operating Officer, Technology Division. Mr. Meldahl has held his present position since 1998. He served as Vice President, Communication Services, Energy and Communications Division, from 1996 - 1998. He served as Vice President, Technology Operations - Entech, from 1997 - 1999 and as Vice President, Technology Division, from 1988 - 1996. |
J. D. Haffey | 55 | Executive Vice President and Chief Operating Officer, Energy Services Division. Mr. Haffey has held his present position since 1996. He served as Vice President of Administration and Regulatory Affairs from 1993 - - 1996. |
M. E. Zimmerman | 52 | Vice President and General Counsel. Mr. Zimmerman has held his present position since 1991. |
P. T. Fleming | 47 | Corporate Secretary. Mr. Fleming has held his present position since December 2000. He has been an attorney in our Company's legal department since 1984. |
P. K. Merrell | 48 | Vice President, Human Resources. Ms. Merrell has held her present position since 1996. She served as Secretary from 1993 - 2000. |
P. J. Cole | 43 | Vice President, Corporate Business Development. Mr. Cole has held his present position since 1999. He served as Vice President, Business Development and Regulatory Affairs, from 1996 - 1999. He served as Treasurer for the Utility Division from 1993 - 1996. |
D. S. Smith | 57 | Controller. Mr. Smith has held his present position since 1996. He served as Controller for Entech from 1988 - 1996. |
E. M. Senechal | 51 | Treasurer. Ms. Senechal has held her present position since 1996. She served as Vice President and Treasurer for Entech from 1984 - 1996. |
D. A. Johnson | 55 | Vice President, Distribution Services. Mr. Johnson has held his present position since 1996. He served as Vice President for Utility Services from 1993 - 1996. |
W. A. Pascoe | 44 | Vice President, Transmission Services. Mr. Pascoe has held his present position since 1997. He served as Assistant Vice President, Transmission Services, from 1996 - 1997 and as Manager of Transmission and Power Transactions from 1990 - 1996. |
D. J. Sullivan | 45 | Chief Information Officer. Mr. Sullivan has held his present position since 1999. He served as Executive Director of Information Systems from 1998 - 1999, Leader of Information Systems from 1996 - 1998, and General Manager of Information Systems from 1995 - 1996. |
SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
Section 16(a) of the Securities Exchange Act of 1934 requires our Directors, certain officers, and shareholders owning more than 10 percent of a class of shares to file reports of ownership and changes in ownership with the Securities and Exchange Commission and the New York Stock Exchange and to furnish us with copies of all reports filed. These reports must be filed by the tenth day of the month following the month in which a transaction occurred. Based solely on review of reports furnished to us and written representations from our Directors and officers, we believe that during 2000 all Directors and officers complied with the reporting requirements except for one late report filed by Ms. Deborah D. McWhinney.
ITEM 11. EXECUTIVE COMPENSATION
SUMMARY COMPENSATION TABLE
The following table shows the compensation paid to the Chief Executive Officer, the next four most highly compensated employees, and for an additional individual for whom compensation would have been reported pursuant to Item 402(a)(3)(iii) for services rendered during fiscal years 2000, 1999, and 1998 but for the fact that this individual was not serving as an executive officer at December 31, 2000. We refer to each of these officers as a "named executive officer."
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| |||||||
Awards | Payouts | |||||||
Principal Position |
|
($) |
($) |
|
|
($) | All Other Compen-sation6 ($) | |
R. P. Gannon CEO, Chairman of the Board & President | 2000 1999 1998 | 483,654 408,600 362,523 | 272,1143 263,6712 115,9201 |
0 0 | 191,100 214,800 84,000 | 0 126,000 51,757 | 6,800 15,054 6,400 | |
M. J. Meldahl Executive VP & COO, Technology Division | 2000 1999 1998 | 244,271 194,616 166,800 | 177,6453 177,1652 33,7501 |
438,7504 0 | 114,300 130,300 48,000 | 0 0 0 | 20,021 27,585 27,585 | |
J. P. Pederson Vice Chairman of the Board & Chief Financial Officer | 2000 1999 1998 | 234,736 200,022 186,850 | 117,3983 112,9152 48,5631 |
0 0 | 103,600 144,000 42,000 | 0 60,000 25,505 | 28,435 6,400 21,641 | |
J. D. Haffey Executive VP & COO, Energy Services Division | 2000 1999 1998 | 206,340 195,190 190,890 | 109,4243 115,3562 48,1951 |
0 0 | 42,000 42,000 42,000 | 0 84,000 16,771 | 30,740 25,400 28,644 | |
M. E. Zimmerman Vice President & General Counsel | 2000 1999 1998 | 181,230 171,436 167,660 | 53,9883 60,7912 33,7501 | 24,000 24,000 24,000 | 0 45,000 22,358 | 15,561 9,736 13,319 | ||
R. F. Cromer7 Executive VP & COO, Energy Supply Division | 2000 1999 1998 | 209,615 198,288 193,920 | 133,8133 117,1872 48,9601 |
0 0 | 42,000 42,000 42,000 | 0 84,000 48,976 | 6,800 39,888 16,192 | |
1Awards earned in 1997 and paid in 1998 under the 1997 Interim Bonus Plan.
2Awards earned in 1998 and paid in 1999 under the EVAÒ Bonus Plan.
3Awards were earned in 1999 and paid in 2000 under the EVAÒ Bonus Plan. Awards earned in 2000 under the EVAÒ Bonus Plan will be paid in 2001 as follows: Mr. Cromer, $50,891; Mr. Haffey, $80,523; Mr. Meldahl, $245,737; and Mr. Zimmerman, $26,013. Other bonuses for 2000, paid in 2001, are as follows: Mr. Gannon, $100,000; and Mr. Pederson, $34,375.
4Mr. Meldahl's award of restricted stock is subject to forfeiture or proration in the event he should terminate employment from us. The restrictions on 4,000 shares were removed on May 11, 2000. The remaining restrictions will elapse as follows: 4,000 shares on May 11, 2001; and 4,000 shares on May 11, 2002. The stock has voting and dividend rights. The market price on the date of grant was $36.5625 per share.
5This column shows the dividend equivalent awards on options that were awarded in 1996 and 1995 and paid in 1999 and 1998.
6This column shows:
(a) | the value of our matching contribution of stock made under our 401(k)Retirement Savings Plan; and |
(b) | compensation received for selling unused vacation time back to us, which is available to all employees: Mr. Haffey - $23,940; Mr. Meldahl - $13,221; Mr. Pederson - $21,635; and Mr. Zimmerman - $8,761. The amounts may include vacation accrued in prior years. |
7Mr. Cromer resigned as an Executive Officer on December 8, 2000.
OPTION GRANTS IN LAST FISCAL YEAR
The following table shows option grants to the named executive officers during the last fiscal year.
INDIVIDUAL GRANTS | |||||
Name | Number of Securities Underlying Options Granted (#) |
(%) |
Exercise Price3 ($/Share) |
Expiration Date |
Grant Date Present Value4 ($) |
R. P. Gannon | 84,0001 | 7.0 | 38.6875 | 06/26/2010 | 1,779,960a |
R. P. Gannon | 107,1002 | 8.9 | 32.5000 | 08/21/2010 | 1,887,102d |
M. J. Meldahl | 50,0001 | 4.2 | 38.6875 | 06/26/2010 | 1,059,500a |
M. J. Meldahl | 64,3002 | 5.4 | 32.5000 | 08/21/2010 | 1,132,966d |
J. P. Pederson | 50,0001 | 4.2 | 38.6875 | 06/26/2010 | 1,059,500a |
J. P. Pederson | 53,6002 | 4.5 | 32.5000 | 08/21/2010 | 944,432d |
J. D. Haffey | 42,0001 | 3.5 | 38.6875 | 06/26/2010 | 354,060c |
M. E. Zimmerman | 24,0001 | 2.0 | 38.6875 | 06/26/2010 | 508,560a |
R. F. Cromer | 42,0001 | 3.5 | 38.6875 | 06/26/2010 | 313,740b |
1This option is first exercisable on June 26, 2002, or (1) date of termination if the Option Holder's employment is terminated as a result of the Divestiture Plan announced in March 2000, or (2) date of Option Holder's retirement, or (3) upon the Option Holder's death or Disability.
2This option is first exercisable on August 21, 2008, except that the grant provides for early vesting prior to August 21, 2008 as follows: (1) 1/2 of the shares granted shall become exercisable if, at any time, our Common Stock, as reported on the New York Stock Exchange Composite Tape, is at or above $49.60 per share for a period of ten consecutive trading days; and (2) the remaining 1/2 of shares granted shall become exercisable, if at any time, our Common Stock, as reported on the New York Stock Exchange Composite Tape, is at or above $67.20 per share for a period of ten consecutive trading days, (3) in the event of the Option Holder's retirement, death or Disability prior to August 21, 2008, a pro rata portion of the option shall vest. The pro rata to be determined by the number of months as a portion of the eight year vesting period on the date of retirement, death or Disability.
3The exercise price was based on the average of our high and low Common Stock price as reported on the New York Stock Exchange Composite Transaction Tape (fair market value) on the grant date.
4The Binomial option pricing model was used to determine the present value of the options granted to the named executive officers. The assumptions used in the Binomial equation to determine the present value are presented below. (Note: All of the Year 2000 options were granted with a term-life of ten years. However, terminations resulting from divestiture of our energy businesses, and projected retirements of certain officers resulted in option terms, for the Binomial calculation, of approximately one and seven years, respectively.)
a 06/26/00 Grant: | |
Market price of stock - $38.6875 Exercise price of option - $38.6875 Stock Volatility - 42.0% Annualized risk-free interest rate - 6.28% 7-year option term Dividend yield - 0% Per option binomial value - $21.19 | |
b 06/26/00 Grant: | |
Market price of stock - $38.6875 Exercise price of option - $38.6875 Stock Volatility - 42.0% Annualized risk-free interest rate - 6.20% 1-year option term Dividend yield - 0% Per option binomial value - $7.47 | |
c 06/26/00 Grant: | |
Market price of stock - $38.6875 Exercise price of option - $38.6875 Stock Volatility - 42.0% Annualized risk-free interest rate - 6.15% 1.25 -year option term Dividend yield - 0% Per option binomial value - $8.43 | |
d 08/21/00 Grant: | |
Market price of stock - $32.5000 Exercise price of option - $32.5000 Stock Volatility - 42.0% Annualized risk-free interest rate - 6.00% 7 -year option term Dividend yield - 0% Per option binomial value - $17.62 | |
AGGREGATED OPTION EXERCISES IN 2000 AND FISCAL YEAR-END OPTION VALUES
The following table provides information with respect to the named executive officers, concerning exercise of stock options at fiscal year-end.
Exercise | Value Realized (Aggregate Market Price at Exercise Less Aggregate Exercise Price1) |
(#) |
In-the-Money-Options at Fiscal Year-End ($20.752) ($) | |
Name | (#) | ($) | Exercisable Unexercisable | Exercisable Unexercisable |
R. P. Gannon | 0 | 0 | 125,934 368,250 | 175,133 0 |
M. J. Meldahl | 0 | 0 | 64,150 204,450 | 66,000 0 |
J. P. Pederson | 5,600 | 67,025 | 117,500 214,500 | 474,142 0 |
J. D. Haffey | 0 | 0 | 61,334 84,000 | 257,112 0 |
M. E. Zimmerman | 1,000 | 21,363 | 55,762 48,000 | 370,727 0 |
R. F. Cromer | 5,123 | 119,687 | 90,626 84,000 | 538,646 0 |
1Based on the closing price of our Common Stock as reported on the New York Stock Exchange Composite Transaction Tape, on the date of exercise.
2Based on the closing price of our Common Stock as reported on the New York Stock Exchange Composite Transaction Tape, on December 31, 2000.
PENSION PLAN PLUS BENEFIT RESTORATION
The table below illustrates the estimated annual benefits payable to officers under our Pension Plan (a qualified defined benefit plan) and under our Benefit Restoration Plan for Senior Management Executives (a non-qualified defined benefit plan). The estimated annual benefits displayed become payable upon normal retirement at age 65 on January 1, 2001. These benefits will be reduced if the officer retires before reaching age 65. The amounts presented assume the officer elects a single life annuity benefit payment.
PENSION PLAN PLUS BENEFIT RESTORATION
Years of Service | ||||||
Remuneration | 15 | 20 | 25 | 30 | 35 | |
$150,000 | $ 84,942 | $ 95,724 | $ 106,589 | $ 117,584 | $ 128,982 | |
$175,000 | $ 100,378 | $ 113,108 | $ 125,900 | $ 138,824 | $ 152,209 | |
$200,000 | $ 113,814 | $ 128,492 | $ 143,210 | $ 158,063 | $ 173,436 | |
$225,000 | $ 129,250 | $ 145,875 | $ 162,521 | $ 179,302 | $ 196,662 | |
$250,000 | $ 142,686 | $ 161,259 | $ 179,831 | $ 198,542 | $ 217,888 | |
$275,000 | $ 158,122 | $ 178,643 | $ 199,142 | $ 219,781 | $ 241,115 | |
$300,000 | $ 171,558 | $ 194,026 | $ 216,453 | $ 239,021 | $ 262,342 | |
$325,000 | $ 186,994 | $ 211,410 | $ 235,763 | $ 260,260 | $ 285,568 | |
$350,000 | $ 202,429 | $ 228,794 | $ 255,073 | $ 281,499 | $ 308,795 | |
$375,000 | $ 215,865 | $ 244,178 | $ 272,384 | $ 300,739 | $ 330,022 | |
$400,000 | $ 231,301 | $ 262,561 | $ 291,695 | $ 321,978 | $ 353,248 | |
$425,000 | $ 244,737 | $ 276,945 | $ 309,005 | $ 341,218 | $ 374,475 | |
$450,000 | $ 260,173 | $ 294,328 | $ 328,316 | $ 362,457 | $ 397,701 | |
$475,000 | $ 275,609 | $ 311,712 | $ 347,626 | $ 383,697 | $ 420,928 | |
$500,000 | $ 289,045 | $ 327,096 | $ 364,937 | $ 402,936 | $ 442,155 | |
$550,000 | $ 299,916 | $ 341,856 | $ 383,556 | $ 425,412 | $ 468,612 | |
$600,000 | $ 310,788 | $ 356,628 | $ 402,180 | $ 447,888 | $ 495,060 | |
Qualified Pension Plan
Benefits provided by our Qualified Pension Plan (Plan) are determined by using a cash balance formula.
Our Plan's cash balance method of benefit accrual establishes a notional account for eligible participants. This account is credited each year with the following Company contributions:
The above additional credits are predicated upon the number of "points" a participant has at the beginning of the year. Points are determined by adding a participant's age and years of service. When an eligible participant elects to commence benefit payments, the participant's accrued cash balance account is converted to a monthly annuity payment.
The above table includes pension benefits that have been calculated using the cash balance formula.
As of March 1, 2001, credited years of service for our top six executive officers are as follows: 27 years for Mr. Gannon, age 56; 19 years for Mr. Meldahl, age 51; 35 years for Mr. Pederson, age 58; 28 years for Mr. Haffey, age 55; 20 years for Mr. Zimmerman, age 52; 33 years for Mr. Cromer, age 55.
Non-Qualified Pension Plan for Senior Management
Officers and certain other key employees also participate in a Non-Qualified Pension Plan called the Benefit Restoration Plan for Senior Management Executives (Plan). The named executive officers participate in the Plan, which provides for monthly benefit payments upon retirement to the participant over the participant's lifetime. In the event of the participant's death, the participant's beneficiary receives a benefit for the remainder of a 15-year period commencing on the date of the participant's retirement. This benefit is in addition to the Qualified Pension Plan benefit.
Life insurance carried on the Plan participants is owned by a Rabbi trust and helps fund the Plan. Participants in the Plan contributed toward the funding of the Plan. All death proceeds are specifically directed to the Plan trust for the sole purpose of paying for Plan benefits.
The Board of Directors approved the curtailment of the Plan effective December 31, 1998. All active participants, including the named executive officers, became vested in the Plan immediately upon curtailment, and the Plan was closed to additional participants. Existing Plan participants are entitled to receive the benefit accrued as of the date of curtailment with no further benefit accrual. This frozen benefit will become payable upon retirement or death.
Benefit determination under the curtailed plan includes a "make-up" amount equal to any decrease in the executive's Qualified Pension Plan benefit as a result of limitations imposed on the Pension Plan by Sections 415 and 401(a)(17) of the Internal Revenue Code of 1986, as amended. The statutory limitation "make-up" will be based on the officer's actual compensation and years of service at retirement.
The above table includes accrued benefits under the Plan as of the date of curtailment, as well as benefits that have been calculated to represent the statutory "make-up" amount for decreases in the executive's benefit under the Qualified Pension Plan.
COMPENSATION OF DIRECTORS
In 2000, compensation for Non-employee Directors included the following:
Non-employee Directors also receive $850 for attending each special meeting of the Board held in addition to the regularly scheduled Board meetings. Two special meetings of the Board were held in 2000.
Effective January 2001, the Committee on Directors' Affairs recommended, and the Board of Directors approved, an increase in Non-employee Directors' annual compensation, from $19,600 to $35,000. In addition, Non-employee Directors who chair the Personnel Committee, the Committee on Directors' Affairs, and the Audit Committee will receive $5,000 of additional annual compensation.
We have a Deferred Compensation Plan for Non-employee Directors that permits deferral of their annual retainer until the Director retires from the Board. The deferred compensation earns interest at the rate based on Moody's Average Baa Corporate Bond rates. No compensation was deferred in 2000.
In addition, we have a Non-employee Stock Compensation Plan that provides an annual grant of Common Stock to each Director and also permits a Director to receive any portion of the annual retainer in our Common Stock. Directors may elect to defer receipt of this stock payment until they cease to be a Director or until such other date as the Director elects. Deferred stock payments are credited as stock units to a separate deferred compensation account. At the end of the deferral period, the Director will be paid for the stock units in our Common Stock or the equivalent value in cash based upon the market value of our Common Stock at that time.
TERMINATION OF EMPLOYMENT AND CHANGE OF CONTROL ARRANGEMENTS
We have entered into individual severance benefit agreements with thirty-six of our employees to provide benefits after a change of control of our Company, if their employment is subsequently terminated by our Company without "cause," as defined in the agreements, or by the employees with "good reason," as defined in the agreements.
Three different tiers of these agreements exist. The agreements provide that, if within three years after the occurrence of a change of control, the employee is terminated by our Company without cause, or the employee terminates employment with our Company for good reason, the employee is entitled to the following:
In addition, if any amounts paid to a Tier 1 participant under his or her agreement, or otherwise in connection with his or her termination, are subject to the excise tax imposed under the Internal Revenue Code of 1986, as amended, in connection with a change of control, our Company shall pay an additional amount called a Gross-Up Payment equal to the amount of any such excise taxes and any state or federal taxes on the Gross-Up Payment.
The Tier 2 and Tier 3 agreements address the situation in which the amounts paid under his or her agreement, or otherwise in connection with his or her termination, would be subject to the excise tax imposed under the Internal Revenue Code of 1986, as amended, in connection with the change of control. If such payments or benefits less such excise tax are less than the maximum amount of the payments or benefits which could otherwise be payable to the individual without the imposition of the excise, then to the extent necessary to eliminate the imposition of the excise tax (a) such cash payment and benefits shall first be reduced if necessary, to zero and (b) all other non-cash payments and benefits shall not be reduced.
We have entered into Tier 1 agreements with Messrs. Cromer, Gannon, Haffey, Meldahl, Pederson, and three other executive officers of our Company. In addition, we have entered into Tier 2 agreements with five individuals and Tier 3 agreements with twenty-three individuals.
Pursuant to the Tier 1 agreements and based on estimates prepared using current data, Messrs. Gannon, Haffey, Meldahl, and Pederson would be entitled to payments of approximately $4,100,000; $1,700,000; $2,900,000; and $1,900,000, respectively, if their respective employment is terminated in connection with, or within 36 months following, the change of control, and Mr. Cromer is entitled to a change of control payment of approximately $1,900,000 as a result of his December 8, 2000 resignation as an executive officer of our Company. The three other executive officers who are party to a Tier 1 agreement with our Company would be entitled to an aggregate payment of approximately $3,700,000 if the employment of each such individual were to be terminated in connection with, or within 36 months following, the change of control. The five individuals who are party to a Tier 2 agreement would be entitled to an aggregate payment of approximately $2,400,000 if the employment of each such individual were to be terminated in connection with, or within 36 months following, the change of control. In addition, the twenty-two individuals who are party to a Tier 3 agreement with our Company would be entitled to an aggregate payment of approximately $4,400,000 if the employment of each such individual were to be terminated in connection with, or within 36 months following, the change of control.
Pursuant to the terms of the purchase agreement, NorthWestern has agreed to honor those individual change of control severance agreements and to assume all liability for any amounts or benefits due thereunder for employees who remain with the utility. However, NorthWestern has not assumed the obligations under the individual change of control severance agreement of any employee of our Company who is an employee of Touch America prior to the restructuring or who transfers to Touch America in connection with the restructuring. It is anticipated that Messrs. Gannon, Meldahl, and Pederson, as well as two additional holders of a Tier 1 agreement, one holder of a Tier 2 agreement, and thirteen holders of Tier 3 agreements, will be employed by Touch America following the restructuring. While Touch America will assume these obligations pursuant to the individual change of control severance agreements with respect to these employees, the transfer of these employees to Touch America will not constitute a termination of their employment for purposes of these individual change of control severance agreements.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
(a) 5 PERCENT BENEFICIAL OWNERS
Title of Class | Name and Address of Beneficial Owner | Amount and Nature of Ownership3 | Percent of Class |
$6.875 Series Preferred Stock | Lehman Brothers Holdings, Inc.1 New York, NY 10285 | 50,420 shares of $6.875 Series |
8.7 |
| Janus Capital Corporation2 Denver, CO 80206-4923 | 5,633,810 shares of Common Stock |
5.3 |
1On February 14, 2000, Lehman Bothers Holdings, Inc., a broker/dealer registered under Section 15 of the Securities Exchange Act of 1934, filed a schedule 13G report with the Securities and Exchange Commission reporting their ownership of Preferred Stock, $6.875 Series.
2On February 15, 2001, Janus Capital Corporation, an Investment Adviser registered under Section 203 of the Investment Advisers Act of 1940, and Thomas H. Bailey, a 12.2% owner and Chairman of the Board of Janus Capital Corporation, filed a joint Schedule 13G report with the Securities and Exchange Commission reporting their ownership of shares of our Common Stock.
3These securities were acquired in the ordinary course of business and were not for the purpose of having an effect on changing or influencing the control of The Montana Power Company and were not acquired in connection with, or as a participant in, any transaction having such purpose or effect.
(b) DIRECTORS' AND EXECUTIVE OFFICERS' STOCK OWNERSHIP
The following table shows the number of shares owned on February 1, 2001, by each of the directors and named executive officers listed in the Summary Compensation Table and by all of the directors and executive officers as a group.
Number of Shares Beneficially Owned | |||
Name of Owner | Common | Preferred | % of Class |
Tucker Hart Adams (1) (8) | 4,723 | 0 | * |
Alan F. Cain (2)(8) | 7,717 | 0 | * |
John G. Connors (8) | 24,570 | 0 | * |
R. D. Corette (8) | 11,369 | 0 | * |
Richard F. Cromer (3)(9)(10) | 116,621 | 250 | * |
Kay Foster (4)(8) | 11,348 | 0 | * |
Robert P. Gannon (5)(9) (10) | 187,489 | 0 | * |
Jack D. Haffey (9) (10) | 89,237 | 0 | * |
John R. Jester (8) | 11,985 | 0 | * |
Carl Lehrkind III (6) | 18,322 | 0 | * |
Michael Meldahl (9) (10) (12) | 92,830 | 4 | * |
Deborah D. McWhinney (8) | 6,025 | 0 | * |
Jerrold P. Pederson (9)(10) | 142,782 | 0 | * |
Noble E. Vosburg (7)(8) | 10,222 | 0 | * |
Michael E. Zimmerman (9) (10) | 69,372 | ||
All Directors and Executive | 1,093,103 |
254 |
1.05% |
*Less than 1 percent of each class of Common and Preferred.
Ms. Adams - 4,541;
Mr. Cain - 5,742;
Mr. Connors - 1,958;
Mr. Corette - 5,543,
Ms. Foster - 5,182;
Mr. Jester - 8,985;
Ms. McWhinney - 960; and
Mr. Vosburg - 5,205.
The holders of these units have no voting or investment power.
Mr. Cromer - 12,746;
Mr. Gannon - 18,643;
Mr. Haffey - 15,477;
Mr. Meldahl - 9,501;
Mr. Pederson - 17,682; and
Mr. Zimmerman - 7,920.
(10)Includes option shares exercisable within 60 days of December 31, 2000:
Mr. Cromer - 90,626;
Mr. Gannon - 121,650;
Mr. Haffey - 61,334;
Mr. Meldahl - 64,150;
Mr. Pederson - 117,500; and
Mr. Zimmerman - 55,762.
(11)Includes 141,012 shares held for executive officers in the 401(k) Retirement Savings Plan; 698,924 option shares exercisable within 60 days of December 31, 2000.
(12)Includes 4 shares of the $6.00 Series Preferred Stock.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) Please refer to Item 8, "Financial Statements and Supplementary Data," for a complete listing of all consolidated financial statements and financial statement schedules.
(b) We filed the following reports on Form 8-K:
Date | Subject | |
October 6, 2000 | Item 7 Exhibits. Excerpt of Press Release dated October 2, 2000, "Montana Power To Sell Utility to NorthWestern Corporation for $1.1 Billion." | |
October 25, 2000 | Item 5. Other Events. Discussion of Third Quarter Net Income. Item 7 Exhibits. Preliminary Consolidated Statements of Income for the Quarters Ended September 30, 2000 and 1999 and for the Nine Months Ended September 30, 2000 and 1999. Preliminary Continuing Operations Schedule of Revenues and Expenses for the Quarters Ended September 30, 2000 and 1999 and for the Nine Months Ended September 30, 2000 and 1999. Preliminary Discontinued Operations Listing of Income for the Quarters Ended September 30, 2000 and 1999 and for the Nine Months Ended September 30, 2000 and 1999. | |
November 15, 2000 | Item 2. Disposition of Properties. Disposition of Oil and Natural Gas Businesses. Item 7. Exhibits. Excerpt from Press Release dated October 31, 2000, "Montana Power Completes Sale of Oil and Gas Business." | |
ITEM 14.EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS (continued)
(c) | Exhibits | Incorporation by Reference | ||
| Previous Exhibit Designation | |||
2 | Asset Purchase Agreement | 1-4566 | 2(a) | |
2(a) | Amendment No. 1 to the Asset Purchase Agreement | 1-4566 | 2(a) | |
2(b) | Amendment No. 2 to the Asset Purchase Agreement | 1-4566 1999 | 2(b) | |
3(a) | Restated Articles of Incorporation, as amended | 33-56739 | 3(a) | |
3(a)(1) | Articles of Amendment to the Restated Articles of Incorporation | 1-4566 | 3(a)(1) | |
3(a)(2) | Articles of Amendment to the Restated Articles of Incorporation | |||
3(a)(3) | Amendment to the Articles of Incorporation | 1-4566 August 16, 1999 Form 10-Q | 3 | |
3(b) | By-laws, as adopted dated August 22, 1995 | 1-4566 | 3(b) | |
3(b)(1) | Amendment to By-laws dated August 27, 1996 | 1-4566 | 3(b) | |
3(b)(2) | Amendment to By-laws dated May 12, 1997 | 1-4566 | 3(b) | |
3(b)(3) | Amendment to By-laws dated December 9, 1997 | |||
4(a) | Mortgage and Deed of Trust | 2-5927 | 7(e) | |
4(b) | First Supplemental Indenture | 2-10834 | 4(e) | |
4(c) | Second Supplemental Indenture | 2-14237 | 4(d) | |
4(d) | Third Supplemental Indenture | 2-27121 | 2(a)-5 | |
4(e) | Fourth Supplemental Indenture | 2-36246 | 2(a)-6 | |
4(f) | Fifth Supplemental Indenture | 2-39536 | 2(a)-7 | |
4(g) | Sixth Supplemental Indenture | 2-49884 | 2(a)-8(a) | |
4(h) | Seventh Supplemental Indenture | 2-52268 | 2(a)-9 | |
4(i) | Eighth Supplemental Indenture | 2-53940 | 2(a)-10 | |
4(j) | Ninth Supplemental Indenture | 2-55036 | 2(a)-11 | |
4(k) | Tenth Supplemental Indenture | 2-63264 | 2(a)-12 | |
4(l) | Eleventh Supplemental Indenture | 2-86500 | 2(a)-13 | |
4(m) | Twelfth Supplemental Indenture | 33-42882 | 4(c) | |
4(n) | Thirteenth Supplemental Indenture | 33-55816 | 4(a)-14 | |
4(o) | Fourteenth Supplemental Indenture | 33-64576 | 4(c) | |
4(p) | Fifteenth Supplemental Indenture | 33-64576 | 4(d) | |
4(q) | Sixteenth Supplemental Indenture | 33-50235 | 99(a) | |
4(r) | Seventeenth Supplemental Indenture | 33-56739 | 99(a) | |
4(s) | Eighteenth Supplemental Indenture | 33-56739 | 99(b) | |
Instruments defining the rights of holders of long-term debt which are not required to be filed with the Commission will be furnished to the Commission upon request. | ||||
ITEM 14.EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS (continued)
Incorporation by Reference | ||||
| Previous Exhibit Designation | |||
4(t) | Rights Agreement dated as of June 6, 1989, between The Montana Power Company and First Chicago Trust Company of New York, as Rights Agent | 33-42882 | 4(d) | |
4(u) | Amendment to Rights Agreement dated March 2, 1999 | 1-4566 | 99(a) | |
10(a)(i) | Benefit Restoration Plan for Senior Management Executives and Board of Directors | 33-42882 | 10(a)(i) | |
10(a)(ii) | Deferred Compensation Plan for Non-Employee Directors | 33-42882 | 10(a)(ii) | |
10(a)(iii) | Long-Term Incentive Stock Ownership Plan | 1-4566 1992 Form 10-K | 10(a)(iii) | |
10(a)(iv) | Amended Long-Term Incentive Plan | 1-4566 August 16, 1999 | 10 | |
10(a)(iv) | The Montana Power Company Employee Stock Ownership Plan (Revised) | 33-28096 | 4(c) | |
10(a)(v) | Termination Compensation Agreements with Senior Management Executives | 1-4566 | 10(a)(v) | |
10(a)(vi) | Colstrip Unit #3 Wholesale Transmission Service Agreement (Exhibit F-1 to the Asset Purchase Agreement) | 1-4566 | 10(a) | |
10(a)(vii) | Non-Colstrip Unit #3 Wholesale Transmission Service Agreement (Exhibit F-2 to the Asset Purchase Agreement) | 1-4566 | 10(b) | |
10(a)(viii) | Generation Interconnection Agreement ((Exhibit G to the Asset Purchase Agreement) | 1-4566 | 10(c) | |
10(a)(ix) | Equity Contribution Agreement | 1-4566 | 10(d) | |
ITEM 14.EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS (continued)
Incorporation by Reference | ||||
| Previous Exhibit Designation | |||
10(b) | Stock and Asset Purchase Agreement (relating to the divestiture of our oil and natural gas businesses) dated as of August 25, 2000 among Entech, Inc., a Montana corporation and a wholly owned subsidiary of the Registrant; Altana Exploration Company, a Montana corporation and a wholly owned subsidiary of Entech, PanCanadian Petroleum Limited, a Canadian corporation; and PanCanadian Energy, Inc., a Delaware corporation and a wholly owned subsidiary of PanCanadian Petroleum. | 1-4566 | 10(a) | |
10(b)(i) | Stock and Asset Purchase (relating to the divestiture of our coal business) dated as of September 15, 2000 between Entech, Inc., a Montana corporation and a wholly owned subsidiary of the Registrant; and Westmoreland Coal Company, a Delaware corporation. | 1-4566 November 14, 2000 | 10(b) | |
10(b)(ii) | Stock and Asset Purchase (relating to the divestiture of our independent power business) dated as of September 19, 2000 between Entech, Inc., a Montana corporation and a wholly owned subsidiary of the Registrant; and BBI Power Corporation, a Delaware corporation. | 1-4566 November 14, 2000 Form 10-Q | 10(c) | |
10(b)(iii) | Stock and Asset Purchase (relating to the divestiture of our electric and natural gas utility businesses) dated as of September 29, 2000 among the Registrant, a Montana corporation; Touch America Holdings, Inc., a Delaware corporation and an affiliate of the Registrant; and NorthWestern Corporation, a Delaware corporation. | 1-4566 November 14, 2000 Form 10-Q | 10(d) | |
10(c) | Participation Agreements among United States Trust Company of New York, Burnham Leasing Corporation, and SGE (New York) Associates, Certain Institutions, The Montana Power Company and Bankers Trust Company | 33-42882 | 10(c) | |
12 | Statement Re Computation of Ratio of Earnings to Fixed Charges | |||
21 | Subsidiaries of the Registrant | |||
23 | Consent of Independent Accountants | |||
27 | Financial Data Schedule | |||
99 | Nineteenth Supplemental Indenture | |||
THE MONTANA POWER COMPANY AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
Column A | Column B | Column C | Column D | Column E | |
Additions | |||||
| Balance at | Charged to | Charged to |
| Balance |
(Thousands of Dollars) | |||||
Year Ended: | |||||
December 31, 2000 | |||||
Reserves deducted in | |||||
Doubtful accounts | |||||
Utility | $ 1,104 | $ 151 | $ - | $ 91 | $ 1,164 |
Nonutility | 1,001 | 9,355 | 3,219 | 3,283 | 10,292 |
Total | $ 2,105 | $ 9,506 | $ 3,219 | $ 3,374 | $ 11,456 |
December 31, 1999 | |||||
Reserves deducted in | |||||
Doubtful accounts | |||||
Utility | $ 1,044 | $ 2,010 | $ - | $ 1,950 | $ 1,104 |
Nonutility | 862 | 187 | (10) | 38 | 1,001 |
Total | $ 1,906 | $ 2,197 | $ (10) | $ 1,988 | $ 2,105 |
December 31, 1998 | |||||
Reserves deducted in | |||||
Doubtful accounts | |||||
Utility | $ 984 | $ 1,749 | $ - | $ 1,689 | $ 1,044 |
Nonutility | 827 | 182 | (11) | 136 | 862 |
Total | $ 1,811 | $ 1,931 | $ (11) | $ 1,825 | $ 1,906 |
* Deductions are of the nature for which the reserves were created. In the case of the reserve for doubtful accounts, deductions from this reserve are reduced by recoveries of amounts previously written off. | |||||
Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
THE MONTANA POWER COMPANY | ||
(Registrant) | ||
By | /s/ R. P. Gannon | |
R. P. Gannon | ||
(Chairman of the Board) | ||
Dated: April 6, 2001
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature | Title | Date | ||
/s/ Robert P. Gannon (Chief Executive Officer) | Principal Executive | April 6, 2001 | ||
/s/ J. P. Pederson (Vice Chairman and Chief | Principal Financial and | April 6, 2001 | ||
/s/ Tucker Hart Adams | Director | April 6, 2001 | ||
Tucker Hart Adams | ||||
/s/ Alan F. Cain | Director | April 6, 2001 | ||
Alan F. Cain | ||||
/s/ John G. Connors | Director | April 6, 2001 | ||
John G. Connors | ||||
/s/ R. D. Corette | Director | April 6, 2001 | ||
R. D. Corette | ||||
/s/ Kay Foster | Director | April 6, 2001 | ||
Kay Foster | ||||
/s/ John R. Jester | Director | April 6, 2001 | ||
John R. Jester | ||||
/s/ Carl Lehrkind III | Director | April 6, 2001 | ||
Carl Lehrkind III | ||||
/s/ Deborah D. McWhinney | Director | April 6, 2001 | ||
Deborah D. McWhinney | ||||
/s/ N. E. Vosburg | Director | April 6, 2001 | ||
N. E. Vosburg |
EXHIBIT INDEX
Exhibit 12
Statement Regarding Computation of Ratio of Earnings to Fixed Charges
Exhibit 21
Subsidiaries of the Registrant
Exhibit 23
Consent of Independent Accountants
Exhibit 27
Financial Data Schedule
Exhibit 99
Nineteenth Supplemental Indenture
Exhibit 12 | |||||
THE MONTANA POWER COMPANY | |||||
Computation of Ratio of Earnings to Fixed Charges | |||||
(Thousands of Dollars) | |||||
Year Ended December 31 | |||||
2000 | 1999 | 1998 | 1997 | 1996 | |
Net Income | $ 70,547 | $ 96,955 | $ 122,837 | $ 76,929 | $ 77,522 |
Income Taxes | 33,598 | 30,830 | 66,843 | 48,585 | 54,807 |
$104,145 | $ 127,785 | $ 189,680 | $ 125,514 | $ 132,329 | |
Fixed Charges: | |||||
Interest | $ 45,016 | $ 49,731 | $ 66,766 | $ 62,072 | $ 51,244 |
Amortization of Debt Discount, |
|
|
|
|
|
Rentals | 29,054 | 34,682 | 34,625 | 34,395 | 34,166 |
$ 74,893 | $ 85,682 | $ 102,947 | $ 98,005 | $ 87,020 | |
Earnings Before Income Taxes |
|
|
|
|
|
Ratio of Earnings to Fixed |
|
|
|
|
|
SUBSIDIARIES OF REGISTRANT | Exhibit 21 |
Percentage of Voting | |
Canadian-Montana Pipe Line Company An Alberta Corporation | 100 |
Colstrip Community Services Company A Montana Corporation | 100 |
Montana Power Capital 1 A Montana Corporation | 100 |
MPC Natural Gas Funding Trust A Montana Corporation | 100 |
Montana Power Services Company A Montana Corporation | 100 |
One Call Locators, Ltd. A Montana Corporation | 100 |
Discovery Energy Solutions, Inc. A Montana Corporation | 100 |
Touch America Holdings, Inc. A Delaware Corporation | 100 |
The Montana Power, LLC A Montana Corporation | 100 |
Entech LLC A Montana Corporation | 100 |
Entech, Inc. A Montana Corporation | 100 |
Continental Energy Services, Inc. A Montana Corporation | 100 |
EMPECO, Inc. A Montana Corporation (A wholly-owned subsidiary of Continental Energy Services, Inc.) | 100 |
EMPECO IV, Inc. A Montana Corporation (A wholly-owned subsidiary of Continental Energy Services, Inc.) | 100 |
Montana Energy Inc. A Montana Corporation (A wholly-owned subsidiary of Continental | 100 |
CES International, Inc. A Cayman Islands Corporation (A wholly-owned subsidiary of Continental Energy Services, Inc.) | 100 |
SUBSIDIARIES OF REGISTRANT | Exhibit 21 |
Percentage of Voting | |
PAK Energy, LLC A Cayman Islands Limited Life Corporation (A wholly-owned subsidiary of CES International, Inc., except 1% held by Montana Energy, Inc.) | 100 |
ECI Energy, Ltd. A Delaware Corporation Investment in English Partnership in a Gas-fired Cogeneration Project (A 47.5% owned subsidiary of Continental Energy Services, Inc.) | 50 |
Enserch Development Corporation One, Inc. A Delaware Corporation (A wholly owned subsidiary of Continental Energy Services, Inc.) | 100 |
Montana Grimes County, Inc. A Montana Corporation (A wholly owned subsidiary of Continental Energy Services, Inc.) | 100 |
Montana Grimes Frontier, Inc. A Montana Corporation Energy Services, Inc.) | 100 |
Western Energy Company A Montana Corporation | 100 |
Western SynCoal LLC (A Wholly-owned subsidiary of Western Energy Company) | 100 |
Northwestern Resources Co. A Montana Corporation | 100 |
Tetragenics Company A Montana Corporation | 100 |
New Horizon Technologies Energy Services, LLC A Montana Corporation (A 50.5% owned subsidiary of Tetragenics Company) | 50.5 |
Touch America, Inc. A Montana Corporation | 100 |
Touch America Intangible Holding Company, LLC A Delaware Corporation (A wholly-owned subsidiary of Touch America, Inc.) | 100 |
Touch America Purchasing Company, LLC A Delaware Corporation (A wholly-owned subsidiary of Touch America, Inc.) | 100 |
Touch America Services Group, Inc. A Delaware Corporation (A wholly-owned subsidiary of Touch America, Inc.) | 100 |
SUBSIDIARIES OF REGISTRANT | Exhibit 21 |
Percentage of Voting | |
Touch America Services, Inc. A Delaware Corporation (A wholly-owned subsidiary of Touch America, Inc.) | 100 |
Basin Resources, Inc. A Colorado Corporation | 100 |
Horizon Coal Services, Inc. A Montana Corporation | 100 |
North Central Energy Company A Colorado Corporation | 100 |
Note: The above listed companies are included in the Consolidated Financial Statements of the registrant. | |
CONSENT OF INDEPENDENT ACCOUNTANTS Exhibit 23
We hereby consent to the incorporation by reference in the Prospectuses constituting part of the Registration Statements on Form S-3 (No. 33-43655, 333-28877, 33-32275, 33-55816, 333-14369, 333-14369-01, and 333-17181), and to the incorporation by reference in the Registration Statements on Form S-8 (No. 333-59573, 33-24952 and 33-28096), of our report dated February 21, 2001, appearing on page 51 of The Montana Power Company's Annual Report on Form 10-K for the year ended December 31, 2000.
/s/ PricewaterhouseCoopers LLP
Portland, Oregon
April 9, 2001
Exhibit 99
THE MONTANA POWER COMPANY
TO
THE BANK OF NEW YORK
AND
DOUGLAS J. MACINNES
As Trustees under The Montana
Power Company's Mortgage and
Deed of Trust, dated as of
October 1, 1945
_______________
NINETEENTH SUPPLEMENTAL INDENTURE
Providing, among other things, for
First Mortgage Bonds, 0% Series due 1999
_______________
Dated as of December 16, 1999
NINETEENTH SUPPLEMENTAL INDENTURE
_____________________
NINETEENTH SUPPLEMENTAL INDENTURE, dated as of December 16, 1999, between THE MONTANA POWER COMPANY, a corporation of the State of Montana (successor by merger to The Montana Power Company, a corporation of the State of New Jersey), whose post office address is 40 East Broadway, Butte, Montana 59701 (hereinafter sometimes called the Company), and THE BANK OF NEW YORK, a corporation of the State of New York, whose principal corporate trust office is located at 101 Barclay Street, New York, New York, 10286 (successor to Morgan Guaranty Trust Company, formerly Guaranty Trust Company of New York, hereinafter sometimes called the Corporate Trustee) and DOUGLAS J. MACINNES (successor to Arthur E. Burke, Karl R. Henrich, H.H. Gould, R. Amundsen, P.J. Crowley and W.T. Cunningham, said Douglas J. MacInnes being hereinafter sometimes called the Co-Trustee, and the Corporate Trustee and the Co-Trustee being hereinafter together sometimes called the Trustees), as Trustees under the Mortgage and Deed of Trust, dated as of October 1, 1945 (hereinafter called the Mortgage and, together with any indentures supplemental thereto, hereinafter sometimes called the Indenture), which Mortgage was executed and delivered by The Montana Power Company, a corporation of the State of New Jersey (hereinafter sometimes called the Company-New Jersey) to Guaranty Trust Company of New York and Arthur E. Burke, to secure the payment of bonds issued or to be issued under and in accordance with the provisions of the Mortgage, reference to which Mortgage is hereby made, this instrument (hereinafter called the Nineteenth Supplemental Indenture) being supplemental thereto;
WHEREAS, the Mortgage was or is to be recorded in the official records of various counties in the states of Montana, Idaho and Wyoming, which counties include or will include all counties in which this Nineteenth Supplemental Indenture is to be recorded; and
WHEREAS, by the Mortgage, the Company-New Jersey covenanted that it would execute and deliver such supplemental indenture or indentures and such further instruments and do such further acts as might be necessary or proper to carry out more effectually the purposes of the Indenture and to make subject to the lien of the Indenture any property thereafter acquired, made or constructed and intended to be subject to the lien thereof; and
WHEREAS, the Company-New Jersey executed and delivered to the Trustees its First Supplemental Indenture, dated as of May 1, 1954 (hereinafter called the First Supplemental Indenture); and its Second Supplemental Indenture, dated as of April 1, 1959 (hereinafter called the Second Supplemental Indenture); and
WHEREAS, the Company-New Jersey was merged into the Company on November 30, 1961, and to evidence the succession of the Company to the Company-New Jersey and the assumption by the Company of the covenants and conditions of the Company-New Jersey in the bonds and in the Indenture contained and to enable the Company to have and exercise the powers and rights of the Company-New Jersey under the Indenture in accordance with the terms thereof, the Company executed and delivered to the Trustees its Third Supplemental Indenture, dated as of November 30, 1961 (hereinafter called the Third Supplemental Indenture); and
WHEREAS, the Company executed and delivered to the Trustees its Fourth Supplemental Indenture, dated as of April 1, 1970 (hereinafter called the Fourth Supplemental Indenture); its Fifth Supplemental Indenture, dated as of April 1, 1971 (hereinafter called the Fifth Supplemental Indenture); its Sixth Supplemental Indenture, dated as of March 1, 1974 (hereinafter called the Sixth Supplemental Indenture); its Seventh Supplemental Indenture, dated as of December 1, 1974 (hereinafter called the Seventh Supplemental Indenture); its Eighth Supplemental Indenture, dated as of July 1, 1975 (hereinafter called the Eighth Supplemental Indenture); its Ninth Supplemental Indenture, dated as of December 1, 1975 (hereinafter called the Ninth Supplemental Indenture); its Tenth Supplemental Indenture, dated as of January 1, 1979 (hereinafter called the Tenth Supplemental Indenture); its Eleventh Supplemental Indenture, dated as of October 1, 1983 (hereinafter called the Eleventh Supplemental Indenture); its Twelfth Supplemental Indenture, dated as of January 1, 1984 (hereinafter called the Twelth Supplemental Indenture); its Thirteenth Supplemental Indenture, dated as of December 1, 1991 (hereinafter called the Thirteenth Supplemental Indenture); its Fourteenth Supplemental Indenture, dated as of January 1, 1993 (hereinafter called the Fourteenth Supplemental Indenture); its Fifteenth Supplemental Indenture, dated as of March 1, 1993 (hereinafter called the Fifteenth Supplemental Indenture); and its Sixteenth Supplemental Indenture, dated as of May 1, 1993 (hereinafter called the Sixteenth Supplemental Indenture); its Seventeenth Supplemental Indenture, dated as of December 1, 1993 (hereinafter called the Seventeenth Supplemental Indenture); and its Eighteenth Supplemental Indenture, dated as of August 5, 1994 (hereinafter called the Eighteenth Supplemental Indenture); and
WHEREAS, the First, Second, Third, Fourth, Fifth, Sixth, Seventh, Eighth, Ninth, Tenth, Eleventh, Twelfth, Thirteenth, Fourteenth, Fifteenth, Sixteenth, Seventeenth and Eighteenth Supplemental Indentures were or are to be recorded in the official records of various counties in the states of Montana, Idaho and Wyoming, which counties include all counties in which this Nineteenth Supplemental Indenture is to be recorded; and
WHEREAS, an instrument dated March 15, 1955 was executed by the Company-New Jersey appointing Karl R. Henrich as Co-Trustee in succession to said Arthur E. Burke, resigned, under the Mortgage and by Karl R. Henrich accepting the appointment as Co-Trustee under the Mortgage in succession to said Arthur E. Burke, which instrument was recorded in various counties in the states of Montana, Idaho and Wyoming; and
WHEREAS, an instrument dated June 29, 1962 was executed by the Company appointing H.H. Gould as Co-Trustee in succession to said Karl R. Henrich, resigned, under the Mortgage and by H.H. Gould accepting the appointment as Co-Trustee under the Mortgage in succession to said Karl R. Henrich, which instrument was recorded in various counties in the states of Montana, Idaho and Wyoming; and
WHEREAS, an instrument dated June 22, 1973 was executed by the Company appointing R. Amundsen as Co-Trustee in succession to said H.H. Gould, resigned, under the Mortgage and by R. Amundsen accepting the appointment as Co-Trustee under the Mortgage in succession to said H.H. Gould, which instrument was recorded in various counties in the states of Montana, Idaho and Wyoming; and
WHEREAS, an instrument dated July 1, 1986 was executed by the Company appointing P.J. Crowley as Co-Trustee in succession to said R. Amundsen, resigned, under the Mortgage and by P.J. Crowley accepting the appointment as Co-Trustee under the Mortgage in succession to said R. Amundsen, which instrument was recorded in various counties in the states of Montana, Idaho and Wyoming; and
WHEREAS, the Eighteenth Supplemental Indenture, dated August 5, 1994, was executed by the Company appointing (i) W.T. Cunningham as Co-Trustee in succession to said P.J. Crowley, resigned, under the Mortgage and by W.T. Cunningham accepting the appointment as Co-Trustee under the Mortgage in succession to said P.J. Crowley and (ii) The Bank Of New York as Corporate Trustee in succession to Morgan Guaranty Trust Company of New York, resigned, under the Mortgage and by The Bank Of New York accepting the appointment as Corporate Trustee under the Mortgage in succession to said Morgan Guaranty Trust Company of New York, which supplemental indenture was recorded in various counties in the states of Montana, Idaho and Wyoming; and
WHEREAS, an instrument dated March 29, 1999 was executed by the Company appointing Douglas J. MacInnes as Co-Trustee in succession to said W.T. Cunningham, resigned, under the Mortgage and by Douglas J. MacInnes accepting the appointment as Co-Trustee under the Mortgage in succession to said W.T. Cunningham, which instrument was recorded in various counties in the states of Montana, Idaho and Wyoming; and
WHEREAS, in addition to the property described in the Mortgage, the Company has acquired certain other property, rights and interests in property; and
WHEREAS, the Company-New Jersey or the Company has heretofore issued, in accordance with the provisions of the Mortgage, the following series of First Mortgage Bonds:
Series | Principal Amount | Principal Amount Outstanding |
2-7/8% Series due 1975 | $40,000,000 | NONE |
3-1/8% Series due 1984 | 6,000,000 | NONE |
4-1/2% Series due 1989 | 15,000,000 | NONE |
8-1/4% Series due 1974 | 30,000,000 | NONE |
7-1/2% Series due 2001 | 25,000,000 | $25,000,000 |
8-5/8% Series due 2004 | 60,000,000 | NONE |
8-3/4% Series due 1981 | 30,000,000 | NONE |
9.60% Series due 2005 | 35,000,000 | NONE |
9.70% Series due 2005 | 65,000,000 | NONE |
9-7/8% Series due 2009 | 50,000,000 | NONE |
11-3/4% Series due 1993 | 75,000,000 | NONE |
10/10-1/8% Series due 2004/2014 | 80,000,000 | NONE |
8-1/8% Series due 2014 | 41,200,000 | NONE |
7.70% Series due 1999 | 55,000,000 | NONE |
8-1/4% Series due 2007 | 55,000,000 | 55,000,000 |
8.95% Series due 2022 | 50,000,000 | 50,000,000 |
Secured Medium-Term Notes | 128,000,000 | 88,000,000 |
7% Series due 2005 | 50,000,000 | 50,000,000 |
6-1/8% Series due 2023 | 90,205,000 | 90,205,000 |
5.90% Series due 2023 | 80,000,000 | 80,000,000 |
which bonds are also hereinafter sometimes called bonds of the First through Twentieth Series, respectively; and
WHEREAS, Section 8 of the Mortgage provides that the form of each series of bonds (other than the First Series) issued thereunder and of the coupons to be attached to coupon bonds of such series shall be established by Resolution of the Board of Directors of the Company and that the form of such series, as established by said Board of Directors, shall specify the descriptive title of the bonds and various other terms thereof, and may also contain such provisions not inconsistent with the provisions of the Indenture as the Board of Directors may, in its discretion, cause to be inserted therein expressing or referring to the terms and conditions upon which such bonds are to be issued and/or secured under the Indenture; and
WHEREAS, Section 120 of the Mortgage provides, among other things, that any power, privilege or right expressly or impliedly reserved to or in any way conferred upon the Company by any provision of the Indenture, whether such power, privilege or right is in any way restricted or is unrestricted, may be in whole or in part waived or surrendered or subjected to any restriction if at the time unrestricted or to additional restriction if already restricted, and the Company may enter into any further covenants, limitations or restrictions for the benefit of any one or more series of bonds issued thereunder, or the Company may cure any ambiguity contained therein or in any supplemental indenture or may (in lieu of establishment by Resolution as provided in Section 8 of the Mortgage) establish the terms and provisions of any series of bonds other than said First Series, by an instrument in writing executed and acknowledged by the Company in such manner as would be necessary to entitle a conveyance of real estate to record in all of the states in which any property at the time subject to the lien of the Indenture shall be situated; and
WHEREAS, the Company now desires to create a new series of bonds and (pursuant to the provisions of Section 120 of the Mortgage) to add to its covenants and agreements contained in the Mortgage certain other covenants and agreements to be observed by it and to alter and amend in certain respects the covenants and provisions contained in the Indenture; and
WHEREAS, the execution and delivery by the Company of this Nineteenth Supplemental Indenture, and the terms of the bonds of the Twenty-First Series, hereinafter referred to, have been duly authorized by the Board of Directors of the Company by appropriate Resolutions of said Board of Directors;
NOW THEREFORE, THIS INDENTURE WITNESSETH: That the Company, in consideration of the premises and of $1.00 to it duly paid by the Trustees at or before the ensealing and delivery of these presents, the receipt whereof is hereby acknowledged, and in further evidence of assurance of the estate, title and rights of the Trustees and in order further to secure the payment of both the principal of the interest and premium, if any, on the bonds from time to time issued under the Indenture, according to their tenor and effect and the performance of all the provisions of the Indenture (including any modification made as in the Mortgage provided) and of said bonds, and to confirm the lien of the Mortgage on certain after-acquired property, hereby grants, bargains, sells, releases, conveys, assigns, transfers, mortgages, pledges, sets over and confirms (subject, however, to Excepted Encumbrances as defined in Section 6 of the Mortgage) unto Douglas J. MacInnes and (to the extent of its legal capacity to hold the same for the purposes hereof) to The Bank of New York, as Trustees under the Indenture, and to their successor or successors in said trust, and to said Trustees and their successors and assigns forever, all property, real, personal and mixed, of the kind or nature specifically mentioned in the Mortgage, as heretofore supplemented, or of any other kind or nature (whether or not located in the State of Montana), acquired by the Company after the date of the execution and delivery of Mortgage, as heretofore supplemented (except any herein or in the Mortgage, as heretofore supplemented, expressly excepted), now owned or, subject to the provisions of subsection (I) of Section 87 of the Mortgage, hereafter acquired by the Company (by purchase, consolidation, merger, donation, construction, erection or in any other way) and wheresoever situated, including (without in anywise limiting or impairing by the enumeration of the same the scope and intent of the foregoing or of any general description contained in the Indenture) all lands, power sites, flowage rights, water rights, water locations, water appropriations, ditches, flumes, reservoirs, reservoir sites, canals, raceways, dams, dam sites, aqueducts, and all other rights or means for appropriating, conveying, storing and supplying water; all rights of way and roads; all plants for the generation of electricity by steam, water and/or other power; all power houses, gas plants, street lighting systems, standards and other equipment incidental thereto, telephone, radio and television systems, air-conditioning systems and equipment incidental thereto, water works, water systems, steam heat and hot water plants, substations, lines, service and supply systems, bridges, culverts, tracks, ice or refrigeration plants and equipment, offices, buildings and other structures and the equipment thereof; all machinery, engines, boilers, dynamos, electric, gas and other machines, regulators, meters, transformers, generators, motors, electrical, gas and mechanical appliances, conduits, cables, water, steam heat, gas or other pipes, gas mains and pipes, service pipes, fittings, valves and connections, pole and transmission lines, wires, cables, tools, implements, apparatus, furniture and chattels; all franchises, consents or permits; all lines for transmission and distribution of electric current, gas, steam heat or water for any purpose including towers, poles, wires, cables, pipes, conduits, ducts and all apparatus for use in connection therewith; all real estate, lands, easements, servitudes, licenses, permits, franchises, privileges, rights of way and other rights in or relating to real estate or the occupancy of the same and (except as herein or in the Mortgage, as heretofore supplemented, expressly excepted) all the right, title and interest of the Company in and to all other property of any kind or nature appertaining to and/or used and/or occupied and/or enjoyed in connection with any property hereinbefore or in the Mortgage, as heretofore supplemented, described.
TOGETHER with all and singular the tenements, hereditaments, prescriptions, servitudes and appurtenances belonging or in anywise appertaining to the aforesaid property or any part thereof, with the reversion and reversions, remainder and remainders and (subject to the provisions of Section 57 of the Mortgage) the tolls, rents, revenues, issues, earnings, income, product and profits thereof, and all the estate, right, title and interest and claim whatsoever, at law as well as in equity, which the Company now has or may hereafter acquire in and to the aforesaid property and franchises and every part and parcel thereof.
IT IS HEREBY AGREED by the Company that, subject to the provisions of subsection (I) of Section 87 of the Mortgage, all the property, rights, and franchises acquired by the Company (by purchase, consolidation, merger, donation, construction, erection or any other way) after the date hereof, except any herein or in the Mortgage, as heretofore supplemented, expressly excepted, shall be and are as fully granted and conveyed hereby and as fully embraced within the lien hereof and the lien of the Mortgage, as supplemented, as if such property, rights and franchises were now owned by the Company and were specifically described herein and conveyed hereby.
PROVIDED that the following are not and are not intended to be now or hereafter granted, bargained, sold, released, conveyed, assigned, transferred, mortgaged, hypothecated, affected, pledged, set over or confirmed hereunder are hereby expressly excepted from the lien and operation of the Mortgage, as supplemented, namely: (1) cash, shares of stock, bonds, notes and other obligations and other securities not specifically pledged, paid, deposited, delivered or held under the Mortgage, as supplemented, or covenanted so to be; (2) merchandise, equipment, apparatus, materials or supplies held for the purpose of sale or other disposition in the usual course of business; fuel, oil and similar materials and supplies consumable in the operations of any of the properties of the Company; all aircraft, tractors, rolling stock, trolley coaches, buses, motor coaches, automobiles, motor trucks, and other vehicles and materials and supplies held for the purpose of repairing or replacing (in whole or part) any of the same; (3) bills, notes and accounts receivable, judgments, demands and chooses in action, and all contracts, leases and operating agreements not specifically pledged under the Mortgage, as supplemented, or covenanted so to be; the Company's contractual rights or other interest in or with respect to tires not owned by the Company; (4) the last day of the term of any lease or leasehold which may be or become subject to the lien of the Mortgage, as supplemented; (5) electric, energy, gas, steam, water, ice, and other materials or products generated, manufactured, produced, purchased or acquired by the Company for sale, distribution or use in the ordinary course of its business; all timber, minerals, mineral rights and royalties and all Gas and Oil Production Property, as defined in Section 4 of the Mortgage; (6) the Company's franchise to be a corporation; and (7) any property heretofore released pursuant to any provisions of the Indenture and not heretofore disposed of by the Company; provided, however, that the property and rights expressly excepted from the lien and operation of the Mortgage, as supplemented, in the above subdivisions (2) and (3) shall (to the extent permitted by law) cease to be so excepted in the event and as of the date that either or both of the Trustees or a receiver or trustee shall enter upon and take possession of the Mortgaged and Pledged Property in the manner provided in Article XIII of the Mortgage by reason of the occurrence of a Default as defined in Section 65 thereof.
TO HAVE AND TO HOLD all such properties, real, personal and mixed, granted, bargained, sold, released, conveyed, assigned, transferred, mortgaged, pledged, set over or confirmed by the Company as aforesaid, or intended so to be, unto DOUGLAS J. MACINNES and (to the extent of its legal capacity to hold the same for the purposes hereof) unto THE BANK OF NEW YORK, as Trustees, and their successors and assigns forever.
IN TRUST NEVERTHELESS, for the same purposes and upon the same terms, trusts and conditions and subject to and with the same provisos and covenants as are set forth in the Mortgage, as supplemented, this Nineteenth Supplemental Indenture being supplemental thereto.
AND IT IS HEREBY COVENANTED by the Company that all the terms, conditions, provisos, covenants and provisions contained in the Mortgage, as supplemented, shall affect and apply to the property hereinbefore described and conveyed and to the estate, rights, obligations and duties of the Company and the Trustees and the beneficiaries of the trust with respect to said property, and to the Trustees and their successors as Trustees of said property in the same manner and with the same effect as if the said property had been owned at the time of the execution of the Mortgage, and had been specifically and at length described in and conveyed to the Trustees, by the Mortgage as a part of the property therein stated to be conveyed.
The Company further covenants and agrees to and with the Trustees and their successors in said trust under the Indenture, as follows:
ARTICLE I
Twenty-First Series of Bonds
Section 1
. There shall be a series of bonds designated "0% Series due 1999" (herein sometimes referred to as the "Twenty-First Series"), each of which shall also bear the descriptive title "First Mortgage Bond", and the form thereof, which shall be established by Resolution of the Board of Directors of the Company, shall contain suitable provisions with respect to the matters hereinafter in this Section specified. Bonds of the Twenty-First Series shall mature on December 16, 1999, and shall be authenticated as a fully registered bond in the denominations of $1.00 or integral multiples of $1.00; it shall not bear interest; the principal of said bond to be payable at the office or agency of the Company in the Borough of Manhattan, The City of New York, in such coin or currency of the United States of America as at the time of payment is legal tender for public and private debts. Bonds of the Twenty-First Series shall be dated as provided in Section 10 of the Mortgage.
At the option of the registered owner, any bonds of the Twenty-First Series, upon surrender thereof for cancellation at the office or agency of the Company in the Borough of Manhattan, The City of New York, shall be exchangeable for a like aggregate principal amount of bonds of the same series of other authorized denominations.
Bonds of the Twenty-First Series shall be transferable upon the surrender thereof for cancellation, together with a written instrument of transfer in form approved by the registrar, duly executed by the registered owner or by his duly authorized attorney, at the office or agency of the Company in the Borough of Manhattan, The City of New York.
Upon any exchange or transfer of bonds of the Twenty-First Series, the Company may make a charge therefor sufficient to reimburse it for any tax or taxes or other governmental charge, as provided in Section 12 of the Mortgage, but the Company hereby waives any right to make a charge in addition thereto for any exchange or transfer of bonds of the Twenty-First Series.
Upon the delivery of this Nineteenth Supplemental Indenture, bonds of the Twenty-First Series in the aggregate principal amount of $210,321,007 are to be authenticated forthwith and will be Outstanding in addition to $25,000,000 aggregate principal amount of bonds of the Fifth Series, $55,000,000 aggregate principal amount of bonds of the Fifteenth Series, $50,000,000 aggregate principal amount of bonds of the Sixteenth Series, $88,000,000 aggregate principal amount of bonds of the Seventeenth Series, $50,000,000 aggregate principal amount of bonds of the Eighteenth Series, $90,205,000 aggregate principal amount of bonds of the Nineteenth Series and $80,000,000 aggregate principal amount of bonds of the Twentieth Series Outstanding at the date of delivery of this Nineteenth Supplemental Indenture.
Bonds of the Twenty-First Series shall not be redeemable prior to maturity.
ARTICLE II
Miscellaneous Provisions
Section 2
. Subject to the amendments provided for in this Nineteenth Supplemental Indenture, the terms defined in the Mortgage shall, for all purposes of this Nineteenth Supplemental Indenture, have the meanings specified in the Mortgage.
Section 3
. The Trustees hereby accept the trusts herein declared, provided, created or supplemented and agree to perform the same upon the terms and conditions herein and in the Mortgage, as heretofore supplemented, set forth and upon the following terms and conditions:
The Trustees shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this Nineteenth Supplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made by the Company solely. In general, each and every term and condition contained in Article XVII of the Mortgage shall apply to and form part of this Nineteenth Supplemental Indenture with the same force and effect as if the same were herein set forth in full with such omissions, variations and insertions, if any, as may be appropriate to make the same conform to the provisions of this Nineteenth Supplemental Indenture.
Section 4
. Whenever in this Nineteenth Supplemental Indenture any of the parties hereto is named or referred to, this shall, subject to the provisions of Articles XVI and XVII of the Mortgage, be deemed to include the successors and assigns of such party, and all the covenants and agreements in this Nineteenth Supplemental Indenture contained by or on behalf of the Company, or by or on behalf of the Trustees shall, subject as aforesaid, bind and inure to the respective benefits of the respective successors and assigns of such parties, whether so expressed or not.
Section 5
. Nothing in this Nineteenth Supplemental Indenture, expressed or implied, is intended, or shall be construed, to confer upon, or to give to, any person, firm or corporation, other than the parties hereto and the holders of the bonds and coupons Outstanding under the Indenture, any right, remedy or claim under or by reason of this Nineteenth Supplemental Indenture or any covenant, condition, stipulation, promise or agreement hereof, and all the covenants, conditions, stipulations, promises and agreements in this Nineteenth Supplemental Indenture contained by or on behalf of the Company shall be for the sole and exclusive benefit of the parties hereto, and of the holders of the bonds and coupons Outstanding under the Indenture.
Section 6
. This Nineteenth Supplemental Indenture shall be executed in several counterparts, each of which shall be an original and all of which shall constitute but one and the same instrument.
IN WITNESS WHEREOF, THE MONTANA POWER COMPANY has caused its corporate name to be hereunto affixed, and this instrument to be signed and sealed by its President or one of its Vice Presidents, and its corporate seal to be attested by its Secretary or one of its Assistant Secretaries for and in its behalf, and THE BANK OF NEW YORK, in token of its acceptance of the trust hereby created, has caused its corporate name to be hereunto affixed, and this instrument to be signed and sealed by one of its Vice Presidents, and its corporate seal to be attested by one of its Assistant Vice Presidents
Assistant Secretaries, and Douglass J. MacInnes, for all like purposes, has hereunto set his hand and affixed his seal, as of the day and year first above written.
THE MONTANA POWER COMPANY
By:______________________________
Vice President
Attest:
____________________________
Assistant Secretary
Executed, sealed and delivered by
THE MONTANA POWER COMPANY in the presence of:
____________________________
____________________________
THE BANK OF NEW YORK,
as Corporate Trustee
By:______________________________
Michael Culhane
Vice President
Attest:
_____________________________
Assistant Treasurer
Executed, sealed and delivered
by THE BANK OF NEW YORK in the presence of:
______________________________
______________________________
__________________________________
Douglas J. MacInnes, as Co-Trustee
Executed, sealed and delivered
by DOUGLAS J. MACINNES in the presence of:
______________________________
______________________________
STATE OF NEW YORK )
) ss:
COUNTY OF NEW YORK )
On this _____ day of December, in the year 1999, before me personally came DOUGLAS J. MACINNES to me known, who, being by me duly sworn, did depose and say that he resides at ___________________________________________________________________; that he is _________________________ of The Bank of New York, the corporation described in and which executed the above instrument; that he knows the seal of said corporation; that the seal affixed to said instrument is such corporate seal; that it was so affixed by authority of the board of directors of said corporation, and that he signed his name thereto by like authority.
_______________________________________
WILLIAM J. CASSELS
Notary Public, State of New York
No. 01CA5027729
Qualified in Bronx County
Certificate filed in New York County
Commission Expires May 16, 2000
STATE OF MONTANA )
) ss.:
COUNTY OF )
On this ___ day of December, in the year 1999, before me, ______________________, a Notary Public in and for the State of Montana, personally came and appeared _______________________, to me known and known to me to be a Vice President of THE MONTANA POWER COMPANY, the corporation that executed the within instrument, and acknowledged to me that such corporation executed the same, and being by me duly sworn, did depose and say that he resides at _______________________________________________; that he is a Vice President of THE MONTANA POWER COMPANY, the corporation described in and which executed the within and above instrument; that he knows the seal of said corporation; that the seal affixed to said instrument is such corporate seal; that it was so affixed by order of the Board of Directors of said corporation, and that he signed his name thereto by like order.
IN WITNESS WHEREOF, I have hereunto subscribed my name and affixed my official seal the day and year in this certificate first above written.
_____________________________
STATE OF NEW YORK )
) ss:
COUNTY OF NEW YORK )
On this _____ day of December, in the year 1999, before me personally came MICHAEL CULHANE to me known, who, being by me duly sworn, did depose and say that he resides at 611 80th Street, Brooklyn, New York 11209; that he is a Vice President of The Bank of New York, the corporation described in and which executed the above instrument; that he knows the seal of said corporation; that the seal affixed to said instrument is such corporate seal; that it was so affixed by authority of the board of directors of said corporation, and that he signed his name thereto by like authority.
_______________________________________
WILLIAM J. CASSELS
Notary Public, State of New York
No. 01CA5027729
Qualified in Bronx County
Certificate filed in New York County
Commission Expires May 16, 2000
STATE OF NEW YORK )
) ss:
COUNTY OF NEW YORK )
On this _____ day of December, in the year 1999, before me personally came Douglas J. MacInnes to me known, who, being by me duly sworn, did depose and say that he resides at ________________________; that he is __________________ of The Bank of New York, the corporation described in and which executed the above instrument; that he knows the seal of said corporation; that the seal affixed to said instrument is such corporate seal; that it was so affixed by authority of the board of directors of said corporation, and that he signed his name thereto by like authority.
_______________________________________
WILLIAM J. CASSELS
Notary Public, State of New York
No. 01CA5027729
Qualified in Bronx County
Certificate filed in New York County
Commission Expires May 16, 2000
