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. We engage in a number of diversified energy and communications businesses.
We regularly assess our business units and evaluate opportunities to create, develop, and maximize the value of our diverse businesses. The Board of Directors is considering various options to optimize the value of Touch America, Inc., our telecommunications subsidiary, and maximize shareholder value. On January 25, 2000, we announced that Goldman, Sachs & Co. will assist us in evaluating options with respect to implementing a strategy to separate Touch America from Montana Power. In pursuing this strategy, we will continue to investigate different approaches, including asset purchases and sales, the issuance of securities, and other transactions that may materially affect our results of operations, liquidity, dividends, capital structure, and capital resources. For additional information on how pursuing our 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."
Our business is organized as follows:
. UTILITY
We operate regulated electric and natural gas utilities. Our electric and natural gas service territory covers approximately 107,600 square miles, or approximately 73 percent of Montana, making us one of the country's largest utilities in terms of service territory. Dominant industries operating within our service territory are mining, agriculture, selected manufacturing, railroads, tourism and recreation, and the forest-products industry. We serve approximately 439,000 customers, or approximately 80 percent of the population within our service territory. For information about how weather affects our utility operations, see MD&A, "Utility Operations."
Regulated Electric Utility
Our regulated electric utility purchases, transmits (movement of bulk quantities of energy), and distributes (movement of
energy from transmission system to consumer) electric energy. We provide electric energy to 191 communities and their surrounding rural areas throughout Montana. We also provide electric energy to Yellowstone National Park and to cooperatives that serve approximately 76,000 residents.
On December 17, 1999, we sold substantially all of our electric generating assets to PPL Montana, LLC, a subsidiary of PP&L Global, Inc., for approximately $758,600,000. We have used some of the sales proceeds to repurchase shares of our common stock, and we have begun to use some of the proceeds to retire long-term debt. We also intend to use some of the proceeds to expand Touch America.
Pursuant to the terms of our Asset Purchase Agreement with PPL Montana, we would receive another $152,000,000 from PPL Montana if it were to acquire additional gross capacity in the Colstrip Units 1, 2, and 3 generating units located in Colstrip, Montana from Portland General Electric Company (Portland General) and Puget Sound Energy, Inc. (Puget). On February 29, 2000, the Oregon Public Utility Commission denied the application of Portland General for approval to sell Portland General's interest in the Colstrip Units 3 and 4 plants. We cannot predict the ultimate outcome of this proceeding.
For additional information on the sale, its accounting and regulatory implications, and our use of sale proceeds, see Note 5, "Sale of Electric Generating Assets," and MD&A, "Liquidity and Capital Resources."
Regulated Gas Utility
Our regulated natural gas utility purchases, transports, distributes, and stores natural gas. We provide natural gas to 109 communities throughout Montana.
. NONUTILITY
Our nonutility businesses include telecommunications, coal, independent power, and oil and natural gas operations. We operate these businesses as subsidiary companies of our wholly owned subsidiary, Entech, Inc.
Telecommunications
Through Touch America, our telecommunications operation designs, develops, constructs, operates, maintains, and manages a fiber-optic network and wireless facilities. Touch America's fiber-optic network, which spans 14 states, is described in Item 2, "Properties," under the "Telecommunications Properties" section. Touch America provides wireless services mainly through Personal Communication Services (PCS) and Local Multi-Point Distribution Services (LMDS). Touch America also sells long-distance, Internet, and private-line services and telecommunications equipment.
Coal
Through Western Energy Company, we mine and sell coal at the Rosebud Mine in Colstrip, Montana, primarily to mine-mouth customers. Through Northwestern Resources Co., we mine and sell lignite at the Jewett Mine in central Texas, with all sales to one customer.
Independent Power
Through Continental Energy Services, Inc. (CES), our independent power operation develops, invests in, and operates independent power projects and other energy-related businesses. Through the Colstrip Unit 4 Lease Management Division, it also sells electricity from our leased interest in Colstrip Unit 4.
Oil and Gas
Our oil and natural gas operation explores for, develops, produces, processes, and sells oil and natural gas in the United States and Canada. Through our affiliate, The Montana Power Trading & Marketing Company (MPT&M), it also trades and markets crude oil, natural gas, and natural gas liquids.
- -------------------------------------------------------------------------------- Table The following table shows, for the last three years, revenues contributed by any class of similar products or services that accounted for 10 percent or more of consolidated revenues, which includes Earnings from Unconsolidated Investments. - -------------------------------------------------------------------------------- Percentage Of Revenues Contributed By Any Class Of Similar Products Or Services That Accounted For 10 Percent Or More Of Business Unit Consolidated Revenues - -------------------------------------------------------------------------------- 1999 1998 1997 ----------------------------- Electric Utility 34% 36% 43% Natural Gas Utility -- -- 12% Telecommunications -- -- -- Coal 15% 14% 16% Independent Power -- 13% -- Oil and Natural Gas 25% 17% 16% - --------------------------------------------------------------------------------
FINANCIAL INFORMATION ABOUT INDUSTRY SEGMENTS
For additional information on the financial results of our segments, including a discussion of revenues earned by Northwestern Resources from sales to a single customer and revenues earned by our independent power operations from sales to two customers, see Note 13, "Information on Industry Segments."
ELECTRIC UTILITY OPERATIONS
. ELECTRIC TRANSMISSION SYSTEM
Our electric transmission system forms an integral part of
the Northwest Power Pool. This pool consists of the major electric suppliers in the Pacific Northwest region of the United States; British Columbia, Canada; and parts of Alberta, Canada.
In April 1996, the Federal Energy Regulatory Commission (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 (including MPT&M when it traded and marketed electricity) have used our transmission system 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.
In May 1999, FERC began a rulemaking process to establish its authority regarding Regional Transmission Organizations (RTOs). An RTO is an organization that attempts to capture synergies and efficiencies created by combining individually operated transmission systems into a single operation, focusing on operational and strategic transmission issues. On December 20, 1999, FERC issued Order No. 2000, its most recent order regarding RTOs. The goal of Order No. 2000 is the voluntary and timely formation of RTOs by all public utilities that own, operate, or control interstate transmission facilities. In accordance with the FERC Order, we must file a proposal with FERC by October 15, 2000, describing our efforts to participate in an RTO that will be operational by December 15, 2001. If efforts to participate in an RTO are unsuccessful, then we must describe our plans to overcome particular obstacles as we continue to work toward RTO participation.
We are a member of the Western Systems Coordinating Council (WSCC), organized by 84 member systems and 21 affiliates in the 14 western states of the United States; British Columbia, Canada; Alberta, Canada; and Mexico. The WSCC seeks to ensure reliability of the interconnected transmission system.
We participate in an interconnection agreement with Avista Corporation, IdaCorp, Inc., and PacifiCorp (which was acquired by Scottish Power). This agreement provides for the sharing of transmission capacity of certain lines on the interconnected systems. We also operate, in coordination with our own transmission lines and facilities, the Colstrip transmission lines and facilities, which connect to the four Colstrip generating units.
Together with Western Area Power Administration (WAPA), effective July 1, 1999, we terminated a long-standing bilateral transmission arrangement, and replaced it with service agreements under our respective OATTs. While certain details remain to be completed, service has commenced pursuant to those OATT service agreements.
We have been a party to the Pacific Northwest Coordination Agreement (PNCA), which coordinates the hydroelectric operations of the 18 parties' hydroelectric generating facilities in the Columbia River Basin. Pursuant to the Asset Purchase Agreement with PPL Montana and the sale of the Kerr and Thompson Falls hydroelectric facilities (our former facilities that were coordinated under the PNCA), we agreed to assign our interest in the PNCA to PPL Montana. We did not assign this interest at the December 17, 1999, closing of our transaction with PPL Montana because we had not obtained all necessary consents and regulatory approvals by that date. We have now obtained the consent of the other parties to the PNCA for this assignment, which remains subject to FERC approval. On February 25, 2000, we submitted a joint filing with PPL Montana to seek FERC approval of the assignment. We expect FERC to take action on the filings by May 2000.
. 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. The Electric Act also defined the role of the Montana Public Service Commission (PSC) in licensing suppliers in the state, regulating distribution services, and promulgating rules to prohibit anti-competitive and abusive practices. For additional information on Montana's Electric Act and the regulatory environment in which our electric utility operates, see Note 4, "Deregulation and Regulatory Matters."
Under the Electric Act, we are obligated to continue to supply electric energy to customers in our service territory who have not chosen, or have not had an opportunity to choose, other power suppliers during the transition period. This obligation requires us to have a sufficient power supply to meet these customers` electric needs. Our sales agreement with PPL Montana includes buyback contracts pursuant to which we expect to purchase electric energy from PPL Montana to supply our remaining customers. The buyback contracts are effective through December 31, 2001, and June 30, 2002, after which we may be required to act as a "default supplier" and supply our remaining customers. At that time, we will purchase energy as necessary in the secondary market. We expect to recover any costs related to this electric supply through rates charged to these customers. For additional information on the effects of deregulation, see Note 4, "Deregulation and Regulatory Matters."
. COMPETITIVE ENVIRONMENT
Our regulated electric utility is now primarily a transmission and distribution services utility, and the PSC continues to regulate our transmission and distribution services and approve the rates that we charge for these services. By selling substantially all of our electric generating assets to PPL Montana, we eliminated a high-risk activity. The buyback contracts entered into with PPL Montana - together with the sale of our assets - eliminate our operational risk. While we
may be required to serve as the "default supplier" after the transition period ends on July 1, 2002, we expect to recover costs incurred to serve these customers. For information regarding commodity price risk that we face as a result of the sale of our generating assets, see Note 3, "Commitments," in the "Sales Commitments" section. For additional information on Montana's Electric Act and the regulatory environment in which our electric utility operates, see Note 4, "Deregulation and Regulatory Matters." For information on the sale of substantially all of our electric generating assets, see Note 5, "Sale of Electric Generating Assets."
NATURAL GAS UTILITY OPERATIONS
. NATURAL GAS REQUIREMENTS
Natural gas supply requirements in 1999 totaled 18,828 thousands of dekatherms (MDkt), of which 6,973 MDkt were purchased from third-party contracts with Montana suppliers and 1,160 MDkt were purchased from third-party contracts with Canadian suppliers. We purchased a total of 10,695 MDkt, or approximately 56.8 percent of the natural gas supply requirements for the year, from our unregulated affiliates. We estimate that our natural gas requirements for 2000 will be approximately 20,230 MDkt.
. NATURAL GAS RESOURCES
We fulfill our natural gas requirements through our unregulated affiliates, which have access to natural gas in the United States and in Canada, third-party contracts with Montana suppliers, and third-party contracts with Canadian suppliers. We take delivery of all natural gas within the Montana border. Approximately two-thirds of our nonaffiliated gas purchases have contract terms of one year, from November through October. We anticipate that our unregulated businesses and third-party contracts will supply our natural gas requirements for 2000.
. GAS TRANSPORTATION
We transported natural gas volumes of 24,426 MDkt in 1999, 27,516 MDkt in 1998, and 26,478 MDkt in 1997. We expect to transport approximately 24,000 MDkt in 2000. The reduction in transportation volumes is due primarily to anticipated weaker off-system markets and the loss of a large industrial, on-system transportation customer.
. COMPETITIVE ENVIRONMENT
Montana's Natural Gas Utility Restructuring and Customer Choice Act (Natural Gas Act) provided that natural gas utilities, such as Montana Power, could offer customers choice of natural gas suppliers and provide open access. Because restructuring is voluntary, no deadline for choice exists. Montana's Natural Gas Act also defined the PSC's role in licensing suppliers in the state, regulating transportation and distribution services, and promulgating rules to prohibit anti-competitive and abusive practices. For additional information on Montana's Natural Gas Act and the regulatory environment in which our natural gas utility operates, see Note 4, "Deregulation and Regulatory Matters."
TELECOMMUNICATIONS OPERATIONS
. BUSINESS
Touch America is expanding its nationwide fiber-optic network. We expect Touch America's fiber network to extend approximately 23,000 miles by the end of 2001. For information on Touch America's fiber-optic network, see Item 2, "Properties," in the "Telecommunications Properties" section.
Touch America is constructing a fiber network, in conjunction with AT&T, that will span more than 4,300 miles. The network includes new fiber 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 expect various third parties, including AT&T, to cover approximately one-half of our estimated $500,000,000 total project cost.
In January 2000, Touch America announced an exchange of fiber and conduits with PF.Net, a telecommunications company based in New Jersey. Touch America will receive approximately 5,900 route miles from PF.Net, with all segments expected to be complete by the end of 2001.
Touch America is focused on increasing network traffic principally through a combination of relationships with anchor customers (large-volume commercial or wholesale customers), alliances with third parties, and acquisitions. Touch America continues to provide wholesale services through leasing lit (fully operational) or dim (regeneration equipment but no optical equipment) fiber capacity, and selling dark (no optical or regeneration equipment) fiber to other telecommunications companies.
Touch America and New Century Energies entered into a joint venture in 1999, Northern Colorado Telecommunications LLC, to provide a full range of telecommunications services, including private-line services, to enterprises in the Denver metropolitan area. Primarily through its PCS and LMDS technologies, Touch America is creating "last-mile" connections, which connect a fiber network via wireless applications. In 1999, Touch America and US WEST Wireless entered into a joint venture, TW Wireless (TWW), to provide "one number" 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 telephones.
On March 13, 2000, Touch America signed an agreement with Qwest Communications International Inc. to acquire wholesale, private-line, and long-distance telecommunications services, which currently serve approximately 250,000 customers in the Pacific Northwest, Rocky Mountain, and Upper Midwest regions. Touch America also would acquire
approximately 1,800 route miles of fiber within these regions.
For additional information on Touch America's alliances and acquisitions, see Note 3, "Commitments," in the "Telecommunications" section.
. COMPETITIVE ENVIRONMENT
Our low-cost fiber network helps us to compete in national and regional telecommunications markets. We attempt to mitigate the risks inherent in the telecommunications industry by expanding our fiber-optic network and increasing traffic on that network. We also believe that our presence in the telecommunications industry for more than 16 years has provided us with experience that will help reduce our risks.
The trend in telecommunications toward business combinations and alliances is creating new competitors with resources greater than ours. To succeed, we must continually change and improve our products in response to rapid technological developments and changes in operating systems, Internet access and communications, application and networking software, and computer and communications hardware. 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 mitigate this risk through our joint-venture alliances with other telecommunications companies. Some of these joint ventures, because they are highly leveraged, expose us to interest rate and financing risk.
In providing interstate telecommunications services, we comply with federal telecommunications laws and regulations prescribed by the Federal Communications Commission. At the state level, we are subject to regulations by the various state public service commissions. We do not expect actions by these regulatory agencies to adversely affect our operations.
COAL OPERATIONS
. BUSINESS
At our Rosebud Mine in Colstrip, Montana, in the northern Powder River Basin, 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 90 percent of Western Energy's 1999 coal sales volumes. During 1999, Western Energy mined and sold 10,601,000 tons, of which 3,295,000 tons were affiliated sales. We estimate production to be 11,415,000 tons in 2000, and 11,413,000 tons in 2001.
Northwestern Resources' Jewett Mine, located in central Texas, supplies surface-mined lignite under a long-term lignite supply agreement (LSA) to the two electric generating units located adjacent to the mine. Reliant Energy (Reliant) owns these electric generating units. Northwestern Resources sold 8,934,702 tons in 1999. We estimate that Northwestern Resources' production for 2000 will be 7,800,000 tons, and approximately 8,000,000 tons annually thereafter.
. COMPETITIVE ENVIRONMENT
We sell our current production from the Rosebud and Jewett mines under long-term contracts to mine-mouth customers. 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. The coal supply agreement between Western Energy and the owners of Colstrip Units 1 and 2 provides for a final price re-opener in 2001. An Amended and Restated Coal Supply Agreement dated August 28, 1998, settled coal contract disputes and future coal price re-openers with the owners of Colstrip Units 3 and 4. Prior to mid-2000, Western Energy expects to see a modest profit reduction as a result of the settlement. In mid-2000, the new pricing provisions of the Amended and Restated Coal Supply Agreement take effect. When the new pricing provisions of the Amended and Restated Coal Supply Agreement are fully implemented in 2002, we expect pretax income to decrease from current levels by $12,000,000 per year. We expect this decrease to be partially offset by efficiency and cost-savings measures of $2,000,000. The December 17, 1999, sale of our interests in Colstrip Units 1, 2, and 3 did not affect the terms of the coal supply agreements with Colstrip Units 1 and 2 or Units 3 and 4.
The Rosebud Mine also sells coal to other parties because it has production capacity exceeding the fuel requirements for the Colstrip Units. Competition for these sales comes from Montana and Wyoming Powder River Basin producers located south of the mine. These producers generally experience lower operating costs and lower sulfur content than the coal from the Rosebud Mine. Therefore, we anticipate only modest contract sales and no significant spot market sales for the foreseeable future.
Reliant is the purchaser of lignite produced by Northwestern Resources. The LSA requires Northwestern Resources to produce enough lignite to meet Reliant's demand through July 30, 2015. 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 and Northwestern Resources settled litigation regarding the pricing terms of the LSA and signed a letter of intent regarding amendments to the LSA. This 1998 letter of intent was superseded by a Settlement Agreement and Amendment of Existing Contracts in 1999. The Settlement Agreement allows Reliant to blend petroleum coke with the lignite at a 20/80 ratio. As of December 31, 1999, Reliant had not obtained certain required permits to implement this change. 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's ability to use petroleum coke will be assessed in 2000.
Under the terms of the settlement, lignite prices will continue
to be set under pre-settlement pricing terms through June 30, 2002. From July 1, 2002, through July 30, 2015, lignite prices will be the lesser of (1) a redetermined price set to be competitive with Powder River Basin coal supplies (subject to an established minimum), or (2) the price that would have otherwise been paid under the pre-settlement pricing terms. Northwestern Resources expects that, if the market value of Powder River Basin coal stays flat until the agreement is fully implemented, the competitive-pricing structure could result in a reduction of annual pretax income of approximately $7,000,000 beginning July 1, 2002, through July 30, 2015. Northwestern Resources plans to mitigate this effect through efficiency and cost-savings measures.
INDEPENDENT POWER OPERATIONS
. BUSINESS
CES develops and invests in independent power projects. CES' Colstrip 4 Lease Management Division sells the leased share of Colstrip Unit 4 generation principally to the Los Angeles Department of Water and Power (LADWP) and to Puget under contracts with terms coexistent with the lease associated with the 1985 sale-leaseback of our interest in Colstrip Unit 4 (expiring December 29, 2010). In December 1999, an agreement with the LADWP terminated the existing agreement (11 years remaining) and established a new agreement. 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 and were not adversely affected by the transaction. The LADWP has assigned all of its rights and obligations under the new agreement to a third party.
CES, through a wholly owned subsidiary, holds a managing general partner interest in the 255 MW Encogen One Project located in Sweetwater, Texas. For more information on CES' projects, see Item 2, "Properties," under the "Independent Power Properties" section.
In 1998, CES sold its share of the Lockport Project in the state of New York. CES also participated in the settlement of a power-purchase agreement with respect to a different project in New York. As a result of this settlement, the project owners dismantled the plant and CES exited the partnership in 1999.
. COMPETITIVE ENVIRONMENT
Most of CES' current revenues are derived from long-term power supply contracts. Some long-term power supply contracts in the nonutility power industry are under pressure from customers to negotiate pricing. CES works with its partners and customers to attempt to mitigate effects of contracts that may reflect pricing higher than current market prices. CES also seeks to target specific industrial customers for future expansion and establish itself as the provider of choice for onsite generation projects.
OIL AND NATURAL GAS OPERATIONS
. BUSINESS
We conduct our oil and natural gas operations primarily through our United States subsidiaries, which include North American Resources Company, MP Gas Company, and Altana Exploration Co., and our Canadian subsidiaries, which include Altana Exploration Ltd. and Canadian-Montana Gas Company Limited. Effective January 1, 2000, we combined all of the assets, liabilities, and shareholders' equity of Canadian-Montana Gas Company into Altana Exploration Ltd.
MPT&M principally trades crude oil, natural gas, and natural gas liquids commodities and derivatives.
. COMPETITIVE ENVIRONMENT
Our nonutility oil and natural gas businesses compete with major oil and natural gas companies and other independent and individual producers and operators. For our natural gas operations in the United States, we intend to emphasize development of midstream, fee-based gas gathering and gas processing services in a strategic transition away from the natural gas commodity exploration and production business. We intend to focus our efforts in Canada on natural gas production and developing markets, primarily in southeast Alberta.
We currently sell natural gas production in both the United States and Canada under short-term, spot-market, and long-term contracts. Approximately 9.0 Mmcf, or 4 percent of our United States natural gas reserves, are dedicated to a long-term contract expiring in 2007. Approximately 105,831 Mmcf, or 84 percent of our Canadian natural gas reserves, are dedicated to long-term contracts expiring 2003 through 2005.
Additionally, our affiliate, MPT&M, competes for our former natural gas utility customers who have exercised consumer choice.
ENVIRONMENTAL ISSUES
. GENERAL
Our diversified businesses subject us 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 accrue an appropriate amount of estimated costs associated with reasonably foreseeable potential environmental cleanup costs. We do not expect these costs to materially affect 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 uncertainties relating to, among other matters, the following:
. We do not know all sites for which we may be alleged or found to be responsible.
. We cannot estimate with any degree of reasonable certainty the total costs for sites that we have identified.
We do not expect the unknown costs to have a materially adverse effect on our consolidated financial position, results of operations, or cash flows.
. SILVER BOW CREEK/BUTTE AREA SUPERFUND SITE
We are a Potentially Responsible Party (PRP) at the Silver Bow Creek/Butte Area Superfund Site. A Consent Decree recognizing our "de minimis" contributor status is pending approval of the United States District Court for the District of Montana. Upon approval of the Consent Decree, and payment of $100,000, we would receive a release from further liability for cleanup costs. Further, the Consent Decree would provide contribution protection in the event other PRPs claim contribution for cleanup costs they expend. Given the expected approval of the Consent Decree, the substantial financial capability of other PRPs named by the Environmental Protection Agency (EPA), and the limited connection between our property ownership along with the "mining-related" character of the alleged contamination of this site, we do not believe we are exposed to material liability regarding this site.
We will, however, continue to address alleged soils contamination of the 30 acres of this site that we own. We do not expect cleanup costs to be material.
. MILLTOWN DAM SITE
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.
. THOMPSON FALLS
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. 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, the risk of material remediation is very low. As discussed in Note 5, "Sale of Electric Generating Assets," we retained pre-closing environmental liability relating to this CECRA listing when we sold the dam to PPL Montana.
. SALE OF ELECTRIC GENERATING ASSETS
For further information concerning our environmental liabilities associated with the generating assets sold to PPL Montana, see Note 5, "Sale of Electric Generating Assets."
. SITES OF MANUFACTURED GAS PLANTS
We have voluntarily cleaned up two sites where we operated manufactured gas plants, spending approximately $675,000. We have inspected and assessed a third site. We are required to periodically monitor groundwater at the first two sites and report our results to the MDEQ. We have not completed discussions with the MDEQ and local regulatory agencies regarding the third site. Although we do not expect that we will be required to remediate the third site, we are likely to be required to monitor the groundwater at this site for an indefinite period. We do not expect the costs of monitoring to be material.
. OIL AND NATURAL GAS
Our Canadian subsidiaries are involved with abandonment and remediation of depleted wells and surface facilities in Alberta, Canada. This work addresses cleanup under the direction of Alberta Environmental and reflects normal activity within the oil and gas industry. Approximately 35 sites are under active reclamation. We have completed cleanup of 70 sites through 1999, of which 31 sites are either awaiting final inspection by Alberta Environmental or are in the final stages of monitoring vegetation growth, which must occur before we can apply for cleanup certification. Since 1995, we have spent approximately $800,000 (United States dollars) for cleanup of the identified sites. We estimate that we will spend an additional $500,000 (United States dollars) for cleanup of affected sites through the year 2004. This estimate may change depending on acquisitions or divestitures of Canadian properties that may occur over the five-year period.
EMPLOYEES
At December 31, 1999, we had 2,416 employees. Of these, 754 are members of collective bargaining units involving 11 unions. Current union contracts will expire at various times during the next three years. The December 17, 1999, sale of our electric generating assets resulted in the transfer of 474 persons to PPL Montana, which we have reflected in the above figures.
FOREIGN AND DOMESTIC OPERATIONS
We believe that financial information relating to the segment information for foreign and domestic operations and export sales, other than the information previously disclosed regarding our Canadian subsidiaries, is immaterial.
ITEM 2.
ITEM 2. PROPERTIES - ------------------
ELECTRIC UTILITY PROPERTIES
Our electric transmission system extends through the western two-thirds area of Montana. At December 31, 1999, we owned and operated 6,833 miles of transmission lines and 16,017 miles of distribution lines.
Our electric resource capacity is provided by two power-purchase agreements with PPL Montana, 15 Qualifying Facility (QF) contracts that total 101 MWs of firm winter peak capacity, and Milltown Dam (3 MWs gross capacity). For additional information on our power-purchase agreements, see Note 3, "Commitments," in the "Purchase Commitments" section.
NATURAL GAS UTILITY PROPERTIES
We serve all of our natural gas customers from our transportation system, which extends through the western two-thirds area of Montana. At December 31, 1999, we owned and operated 2,120 miles of natural gas transportation lines and 3,598 miles of distribution mains. We also have four natural gas storage fields, which are an important part of our transportation system. These fields 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.
While our unregulated businesses now operate the natural gas producing properties, our natural gas utility still produces a small amount of natural gas from fields in southern Montana and Wyoming to maintain our natural gas storage leases. See Item 8, "Financial Statements and Supplementary Data - Oil and Natural Gas Producing Activities," for additional information relating to our net recoverable utility natural gas reserves.
- -------------------------------------------------------------------------------- Table Total produced, royalty, and purchased natural gas volumes during the last three years follow, with all volumes in MDkt: - -------------------------------------------------------------------------------- United States Canada Produced Royalty Purchased Produced Royalty Purchased ------------------------------------------------------------------
1999 ....... -- -- 17,668 -- -- 1,160
1998 ....... -- -- 10,798 -- -- 9,440
1997 ....... 3,784 294 8,334 3,420 683 7,170 - --------------------------------------------------------------------------------
TELECOMMUNICATIONS PROPERTIES
Touch America has staffed offices in Minneapolis, Minnesota; Fargo, North Dakota; Billings, Bozeman, Helena, Butte, Great Falls, Kalispell, and Missoula, Montana; Boise, Idaho; Spokane and Seattle, Washington; Eugene, Oregon; Casper, Wyoming; and Denver, Colorado. Touch America owns 25 LMDS licenses in various marketing areas within nine states in the Pacific Northwest, Rocky Mountain, and Upper Midwest regions of the United States.
. JOINT VENTURES
(a) Tetragenics is a wholly owned subsidiary of Entech.
. FIBER-OPTIC NETWORK
Through Touch America, we own or hold interests in the fiber-optic routes listed below:
OPERATIONAL - -------------------------------------------------------------------------------- Route Route Miles - ---------------------------------------------------------------------------- Within Montana ...................................................... 1,615 Seattle-Minneapolis ................................................. 2,033 Denver-Montana-Canadian Border ...................................... 1,070 Minneapolis-Green Bay-Chicago ....................................... 544 Denver Metropolitan Area ............................................ 230 Denver-Colorado Springs-Dallas ...................................... 1,302 Spokane-Boise ....................................................... 487 Portland-Boise-Salt Lake City- Las Vegas-Los Angeles ............................................ 1,715 Portland-Seattle .................................................... 200 Portland-Sacramento-Los Angeles (b) ................................. 1,500 ------ Total Operational Route Miles .................................... 10,696 ====== - --------------------------------------------------------------------------------
(b) The Portland-to-Sacramento section of this route has been delayed due to permitting issues.
Touch America either holds title to, or has contractual rights in, the above operational route miles. Those route miles not owned by Touch America are held principally through Indefeasible Rights-of-Use (IRUs).
UNDER CONSTRUCTION - -------------------------------------------------------------------------------- Anticipated Route Operational Route Miles Date - -------------------------------------------------------------------------------- Minneapolis-Des Moines- Topeka-Denver (c) ................................... 1,050 2000 Rexburg-American Falls, ID ............................. 280 2000 Salt Lake City-Denver .................................. 632 2000 Seattle-Yakima-Spokane ................................. 400 2000 Spokane-Billings ....................................... 625 2000 Minneapolis-Madison-Chicago ............................ 500 2000 St. Louis-Plano, IL .................................... 330 2000 Houston-New Orleans-Jacksonville ....................... 1,050 2000 Chicago-Detroit ........................................ 400 2000 Sacramento-Salt Lake City .............................. 770 2001 Denver-Omaha-Des Moines-Chicago ........................ 1,100 2001 Los Angeles-San Diego-Phoenix- Dallas-Houston ...................................... 2,330 2001 Jacksonville-Orlando-Atlanta ........................... 560 2001 Atlanta-Washington, DC-New York City ................... 1,140 2001 St. Louis-Kansas City .................................. 285 2001 Kansas City-Tulsa ...................................... 265 2001 Tulsa-Dallas ........................................... 330 2001 ------ Total Route Miles Under Construction ................ 12,047 ====== - --------------------------------------------------------------------------------
(c) This route will become operational in 2000, pending signing of the contract.
The above tables do not include the 1,800 miles that Touch America expects to acquire as a result of the agreement with Qwest signed on March 13, 2000.
COAL PROPERTIES
Western Energy leases and produces coal from Montana properties, and Northwestern Resources leases and produces lignite from Texas properties. Western Energy's subsidiary, Western SynCoal LLC (Western SynCoal), owns a patented coal-enhancement process and a coal-enhancement process demonstration plant at the Rosebud Mine that Western Energy operates.
Western Energy has coal leases covering approximately 497,686,000 proved, probable, and recoverable tons of surface-mineable coal reserves at Colstrip. These tons average less than 1.6 pounds of sulfur dioxide per MMBTU. Approximately 211,809,000 tons of these reserves are committed to present contracts, relating principally to the Colstrip Units.
Northwestern Resources has lignite leases in central Texas at the Jewett Mine covering approximately 144,500,000 proved, probable, and recoverable tons of surface-mineable lignite reserves. Northwestern Resources has dedicated all of these reserves to Reliant.
INDEPENDENT POWER PROPERTIES - -------------------------------------------------------------------------------- Table Through CES, we partially own or have contract rights in nonutility power generation projects as listed below: - --------------------------------------------------------------------------------
. PROJECTS IN OPERATION
(a) CES holds a managing partner interest in this project (through its wholly owned subsidiary, Enserch Development Corporation One, Inc).
(b) This co-generation facility has a long-term contract with North American Resources Company (Entech's subsidiary) to purchase a portion of its natural gas supply.
(c) Interest is the contractual right to utilize one-third of 168 MWs of capacity to produce electricity for sale from a 1,725 MW natural gas-fired electric generating facility.
OIL AND NATURAL GAS PROPERTIES
Our producing oil and natural gas properties in the United States are principally located in Wyoming, Colorado, Oklahoma, and Montana. Our Canadian properties are principally located in Alberta. One of our subsidiaries has agreements to supply 81 Bcf of natural gas to four co-generation facilities over a period of 5 to 11 years, for which there are sufficient proved, developed, and undeveloped reserves, and controls related sales of production, sufficient to supply all of the remaining natural gas required by those agreements. Approximately 9.0 Bcf are dedicated to supply one of these contracts.
The United States wells listed above include multiple completions of 269 gross productive natural gas wells, or 214 net productive natural gas wells. They also include 3 gross productive oil wells, or 3 net productive oil wells. The wells located in Canada include multiple completions of one gross productive natural gas well, or a 0.5 net productive natural gas well.
For information on properties acquired, see Item 8, "Supplementary Data - Oil and Natural Gas Producing Activities."
No significant change has occurred and no event has taken place since December 31, 1999, that would materially affect the estimated quantities of proved reserves. For information pertaining to the net recoverable oil and natural gas reserves, see Item 8, "Supplementary Data - Oil and Natural Gas Producing Activities."
NOTE: We converted natural gas production to barrel-of-oil equivalents based on a ratio of 6 Mcf to 1 barrel of oil.
We sold nonutility oil, natural gas, and natural gas liquids production pursuant to short-term and long-term contracts at posted prices or pursuant to forward-market arrangements. From 1997 to 1999, average sales prices changed due to market fluctuations. Natural gas sales include the sale under a contract with our utility operations to supply customers who have not chosen other natural gas suppliers. This contract expires November 1, 2002. Average production costs in the United States decreased as a result of the prior year inclusion of non-recurring environmental and compliance work required on the processing facilities and operating efficiencies in both the United States and Canada.
MORTGAGE AND DEED OF TRUST
A Mortgage and Deed of Trust (Mortgage) subjects all of our physical properties, except subsidiary company assets and certain specified properties and assets now owned or hereafter acquired, to a first mortgage lien.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS - -------------------------
PALADIN ASSOCIATES, INC.
We and North American Resources Company (NARCO), Entech's subsidiary, 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 Northridge Petroleum Marketing, a Canadian corporation, NARCO and Montana Power violated antitrust law, breached contractual obligations, and committed torts for which Paladin is entitled to collect monetary damages. Paladin is seeking actual damages that it estimates to be approximately $10,000,000, which, if trebled, would amount to $30,000,000. In addition, it seeks unspecified punitive damages regarding its tort claims.
We and NARCO deny Paladin's allegations. Because the alleged wrongful and illegal antitrust actions were subject to state and federal regulation, we and NARCO are asserting a state action defense. Summary judgment motions and motions to limit issues at the trial are pending the court's determination. The previously scheduled January 2000 trial of this matter has been postponed and has not been rescheduled.
TCA BUILDING COMPANY
Entech and Northwestern Resources, its subsidiary, are defendants in litigation initiated by TCA Building Company in 1995 in the 261st Judicial District Court in Travis County, Texas. TCA 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 our subsidiaries 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 granted motions filed by Entech and Northwestern Resources for summary judgment on all of TCA's claims. We cannot predict whether TCA will appeal or the ultimate resolution of TCA's claims.
For additional information on legal proceedings, see the "Environmental Issues" section of Item 1, "Business," and Note 2, "Contingencies."
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS - -----------------------------------------------------------
None.
PART II - -------
ITEM 5.
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 the 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 1999 and 1998. The number of common shareholders of record on December 31, 1999, was 31,976, and the number of common shareholders of record on March 3, 2000, was 31,778. As discussed in Part I, the 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, and we have adjusted all share and per-share information to reflect the split.
- -------------------------------------------------------------------------------- Table Common stock information: - -------------------------------------------------------------------------------- Dividends Declared Per 1999 High Low Share -------------------------------------------------------------------- 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
- -------------------------------------------------------------------------------- Dividends Declared Per 1998 High Low Share -------------------------------------------------------------------- 1st quarter $ 18.407 $ 14.532 $ 0.20 2nd quarter 19.250 16.907 0.20 3rd quarter 22.625 16.625 0.20 4th quarter 28.563 20.563 0.20 - --------------------------------------------------------------------------------
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS - ------------------------------------------------------------------------------- OF OPERATIONS - -------------
RESULTS OF OPERATIONS
Consolidated net income available for common stock was $146,656,000 in 1999, compared with $161,930,000 in 1998 and $124,942,000 in 1997.
1999 Compared With 1998 - -----------------------
UTILITY
The utility's net income increased primarily because we recognized as income approximately $18,300,000 in unamortized investment tax credits (ITCs) in the fourth quarter 1999.
. Approximately $10,000,000 of these previously deferred ITCs were associated with the sale of our electric generating assets.
. Approximately $8,300,000 of these previously deferred ITCs were recognized as income in accordance with provisions of the Electric Act, which authorizes accelerated amortizations if the electric utility's return on equity drops below 9.5 percent.
As a result of the sale, we also reversed accrued interest expense related to the Kerr Project. The after-tax effect of this adjustment to interest expense positively affected the utility's 1999 earnings by approximately $3,000,000.
The electric utility's operating income decreased compared with 1998 for the following reasons:
. Revenues increased 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 selling, general, and administrative (SG&A) expenses and electric transmission and distribution expenses - more than offset the increased revenues. Approximately $5,800,000 of the increase in SG&A expenses was attributable to costs associated with implementing new information systems.
The natural gas utility's operating income increased compared with 1998 mainly because of customer growth and a 1998 decrease in revenues to reflect a rate refund under a PSC ruling.
NONUTILITY
The nonutility's net income for 1999 decreased, compared with 1998, primarily because of the effects of one-time favorable events involving our independent power business, Continental Energy Services, Inc. (CES), during 1998. The nonutility businesses had operating results for 1999 as follows:
. Income from telecommunications operations decreased compared with 1998. On January 16, 1999, a customer of Touch America exercised its option to prepay, with a discount, all amounts due for the remaining twelve-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 reduced the operating-income effects of the prepayment.
. Income from coal operations increased due to higher revenues resulting from increased tons sold and the effects in the third quarter 1998 of a one-time refund issued by Western Energy to Colstrip Units 3 and 4 customers, which decreased 1998 revenues.
. Income from independent power operations decreased because of the following events, which had materially positive effects on CES' 1998 income: (1) a contract settlement between the Bonneville Power Administration and an independent power partnership in which CES was a partner; (2) the sale of CES' interest in the Lockport project in New York; and (3) the effects of the buyout of CES' interest in the Encogen Four project in New York.
. Increased income from oil and natural gas operations resulted from higher oil and natural gas prices and increased natural gas volumes sold, which more than offset decreases in oil volumes sold and write-downs of natural gas properties.
1998 Compared With 1997 - -----------------------
Consolidated earnings for the year ended December 31, 1998, were $1.47 per share, an increase of $0.33 per share, or approximately 29 percent, over 1997 earnings of $1.14 per share.
Our 1998 financial performance reflects nonutility business successes, which significantly offset the effects of utility deregulation and weak oil and gas prices. Our telecommunications and independent power businesses provided significant increases in annual earnings. Our utility operations suffered not only from the effects of deregulation, but also from weather - which was 6 percent warmer than normal.
Approximately $0.39 per share of the increased earnings resulted from the following events in our independent power business: (1) an arbitration award against the Bonneville Power Administration for breach of a power purchase agreement, resulting in a gain to CES of approximately $42,200,000; (2) a gain of approximately $14,200,000 on the sale of CES' interest in the Lockport, New York project; and (3) a gain of approximately $14,200,000 (including partial sale of plant) as a result of a third-quarter settlement with a power purchaser and the owners of a project, including CES.
Increased rates and increased secondary sales resulted in an increase of approximately $17,600,000 in electric revenues. Natural gas general business revenues decreased by approximately $14,400,000 mainly because of customer choice and warmer weather. Although lower maintenance expenses reduced power-supply costs, our utility also was affected by charges associated with curtailment of a benefit plan and higher depreciation associated with property that we had held for future construction of a generating plant.
Touch America recorded approximately $10,900,000 in earnings from unconsolidated investments as a result of its share of dark-fiber sales through its interest in the FTV joint venture. Revenues from telecommunications operations increased approximately $51,000,000. The increase was primarily attributable to the effects of (1) a full year's operation of Touch America's expanded fiber-optic network linking Seattle to Minneapolis-St. Paul and Denver to Canada, resulting in dark-fiber sales, and (2) increased long-distance revenues.
Oil and natural gas earnings declined when compared with 1997. Production constraints and comparatively low prices caused the decline.
- -------------------------------------------------------------------------------- Table Utility Operations
Year Ended December 31 - -------------------------------------------------------------------------------- 1999 1998 1997 ------------------------------------ (Thousands of Dollars) ELECTRIC UTILITY: - ----------------- REVENUES: Revenues ........................... $ 456,933 $ 450,719 $ 435,986 Intersegment revenues .............. 13,616 7,576 4,685 ------------------------------------ 470,549 458,295 440,671 EXPENSES: Power supply ....................... 138,705 137,415 143,224 Transmission and distribution ...... 49,355 40,182 38,359 Selling, general, and administrative 67,392 53,017 50,872 Taxes other than income taxes ...... 50,857 46,316 45,540 Depreciation and amortization ...... 53,574 56,524 51,674 ------------------------------------ 359,883 333,454 329,669 ------------------------------------ INCOME FROM ELECTRIC OPERATIONS .... 110,666 124,841 111,002
NATURAL GAS UTILITY: - -------------------- REVENUES: Revenues (other than gas supply cost revenues) ................. 78,359 75,112 105,220 Gas supply cost revenues ........... 32,759 31,940 17,135 Intersegment revenues .............. 629 727 588 ------------------------------------ 111,747 107,779 122,943 EXPENSES: Gas supply costs ................... 32,759 31,940 17,135 Other production, gathering, and exploration ................ 2,338 2,284 8,572 Transmission and distribution ...... 14,635 15,556 14,163 Selling, general, and administrative 21,944 20,191 17,889 Taxes other than income taxes ...... 14,333 14,084 15,251 Depreciation, depletion, and amortization ............... 9,279 8,705 11,939 ------------------------------------ 95,288 92,760 84,949 ------------------------------------ INCOME FROM GAS OPERATIONS ......... 16,459 15,019 37,994
INTEREST EXPENSE AND OTHER INCOME: - ---------------------------------- Interest ........................... 48,204 56,357 52,191 Distributions on company obligated mandatorily redeemable preferred securities of subsidiary trust . 5,492 5,492 5,492 Other income - net ................. (3,565) (3,723) (7,128) ------------------------------------ 50,131 58,126 50,555 INCOME TAXES ............................ 11,940 26,559 35,643 ------------------------------------ NET INCOME .............................. 65,054 55,175 62,798 DIVIDENDS ON PREFERRED STOCK ............ 3,690 3,690 3,690 ------------------------------------ UTILITY NET INCOME AVAILABLE FOR COMMON STOCK ................... $ 61,364 $ 51,485 $ 59,108 ====================================
UTILITY OPERATIONS
Weather affects the demand for electricity and natural gas, especially among residential and commercial customers. Very cold winters increase demand, while mild winters reduce demand. The weather's effect is measured using degree-days, which is the difference between the average daily actual temperature and a baseline temperature of 65 degrees. Heating degree-days result when the average daily actual temperature is less than the baseline. As measured by heating degree-days,
the 1999 temperatures for our service territory were 3 percent warmer than 1998 and 9 percent warmer than the historic average. Temperatures in 1998 were 6 percent warmer than 1997 and the historic average.
Weather, streamflow conditions, and the wholesale power markets in the Northwest and California influenced our electric wholesale revenues, purchased-power expenses, and output of thermal generation. Regional purchased-power prices were higher in 1999 than 1998 and, consequently, we did not displace thermal generation as in prior years.
Utility earnings are based on capital invested in utility plant. We expect our electric utility income to decrease as a result of the sale of our generating assets.
. ACCOUNTING FOR THE EFFECTS OF REGULATION
For our regulated operations, we follow Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." 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.
With the sale of our generating assets, we received proceeds in excess of the book value of the regulated assets. Until the PSC reaches a decision in our Tier II filing, we are carrying these excess proceeds as a liability on the Consolidated Balance Sheet and have not recorded a gain on the sale.
For additional information on our Tier II filing, see Note 4, "Deregulation and Regulatory Matters." 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 this 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.
. ELECTRIC UTILITY
1999 Compared With 1998 - -----------------------
- -------------------------------------------------------------------------------- Table The following table categorizes revenues and volumes into General Business Revenues, Sales to Other Utilities, Other, and Intersegment. It also shows Bundled Revenues and Distribution Only Revenues separately for General Business Revenues. While we no longer supply the electricity for customers who have chosen other commodity suppliers, we continue to earn transmission and distribution revenues for moving their electricity across our transmission and distribution lines. We reflect transmission revenues as Other Revenues and distribution revenues as Distribution Only Revenues. We expect these revenues to continue to increase as additional customers move to choice. For customers who have not chosen other suppliers, Bundled Revenues reflect fully bundled rates for supplying, transmitting, and distributing electricity. We expect these revenues to continue to decrease as additional customers move to choice.
- -------------------------------------------------------------------------------- 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. With the sale of substantially all of our generating assets, we no longer sell energy in the secondary markets.
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 others' 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:
. An increase of approximately $7,900,000 for energy efficiency and public-purpose programs to comply with the Universal System Benefits Charge (USBC) requirements of the Electric Act. In accordance with the Electric Act, we collect these costs through a separate component of rates.
. Costs of approximately $2,000,000 incurred to train staff and to reengineer business processes to implement a new Enterprise Resource Planning (ERP) information system and similar costs of approximately $3,800,000 for a new Enterprise Customer Care (E-CIS) information system.
. Increases in other administrative costs of approximately $2,700,000, which were mostly offset by decreased benefit expenses of approximately $2,000,000 relating to the curtailment of a benefit plan in the prior year.
. ELECTRIC UTILITY
1998 Compared With 1997 - -----------------------
- --------------------------------------------------------------------------------
Table 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. - --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Revenues
Revenues increased during the period primarily due to higher rates. While volumes sold decreased due to the transfer of electric-trading activities to nonutility operations in the third quarter of 1998, revenues from Sales to Other Utilities increased from higher average prices and steam generation, resulting in more energy available to sell in the secondary market. Other revenues increased as a result of an actuarial pension plan adjustment, along with transmission revenues from customers who chose other suppliers.
Expenses
Power-supply expenses decreased primarily due to lower steam maintenance, which was partially offset by increased purchased-power costs. Although we purchased less power through electric-trading activities as a result of the transfer of these activities to nonutility operations, purchased-power costs increased due to higher prices.
Increased SG&A expenses resulted primarily from increased outsourcing costs and higher benefit charges associated with curtailment of a benefit plan. The absence of severance costs in the current year partially offset this increase. Depreciation and amortization expense increased because of expenses associated with software costs and property held for future use.
. NATURAL GAS UTILITY
1999 Compared With 1998 - -----------------------
- -------------------------------------------------------------------------------- Table The following table categorizes revenues and volumes into General Business Revenues, Sales to Other Utilities, Transportation, and Other.
- --------------------------------------------------------------------------------
* With the implementation of our E-CIS, we now report natural gas revenues in dekatherms (Dkt). A Dkt measures the heat used and is the basis of how we bill our customers.
- -------------------------------------------------------------------------------- Revenues
All of our former Large Industrial and Large Commercial customers have now chosen other commodity suppliers. While we no longer supply the natural gas for those customers, we still earn transportation revenues from moving their natural gas through our pipelines. We reflect these revenues as Transportation revenues in the table.
General Business Revenues remained relatively flat. 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. For additional information on deregulation, see Note 4, "Deregulation and Regulatory Matters." 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 system and the E-CIS system. An increase relating to energy efficiency and public-purpose programs mostly offset a decrease in other administrative costs.
1998 Compared With 1997 - -----------------------
- -------------------------------------------------------------------------------- Table The following table categorizes revenues and volumes into General Business Revenues, Sales to Other Utilities, Transportation, and Other.
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Revenues
Natural gas revenues, excluding gas-supply cost revenues, decreased in 1998 primarily due to weather-related reductions in volumes sold. Slightly higher tariff rates and customer growth partially offset the revenue decrease. A decrease in Other revenues, due to the November 1997 restructuring of our natural gas utility and an increase in gas-supply cost refunds to our customers, was partially offset by an increase in Transportation revenues. For additional information on deregulation, see Note 4, "Deregulation and Regulatory Matters."
Expenses
In November 1997, we transferred substantially all of our regulated natural gas production assets to an unregulated affiliate. Since that time, we have included operating expenses related to the transferred assets in the nonutility oil and natural gas operations. The absence of these expenses in the utility operations resulted in net reductions in other production, gathering, and exploration costs.
As a result of the restructuring, we have contracted to purchase most of our natural gas from our nonutility affiliate. The contract price includes costs associated with the transferred assets and returns on those assets. Gas cost revenues and expenses, which are always equal due to regulated rate and accounting procedures, increased throughout 1998 due to the new purchase contract. Amortizations of prior period under-collections also contributed to the increase.
Higher SG&A expenses for the period resulted primarily from increased amortizations of regulatory assets, which are collected in rates, as well as higher outsourcing charges.
Depreciation, depletion, and amortization expense decreased due to the transfer of the natural gas production properties as discussed above.
. INTEREST EXPENSE AND INCOME TAXES
1999 Compared With 1998 - -----------------------
Interest Expense
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. With the sale, our obligation to make payments for future periods ended. The mitigation liability has now been adjusted, and accrued interest expense was reversed. This adjustment to interest expense accounts for the majority of the decrease in interest expense of approximately $8,200,000. For additional information on the Kerr Project, see Note 2, "Contingencies."
Income Taxes
In accordance with the Electric Act, we are allowed to recognize as income accelerated amortizations of ITCs during the transition period if our return on equity drops below 9.5 percent. As a result, we recognized approximately $8,300,000 of ITCs associated with our electric utility's business.
In addition, we recognized as income approximately $10,000,000 in unamortized ITCs associated with the sale of our electric generating assets to PPL Montana.
1998 Compared With 1997 - -----------------------
Interest expense increased in 1998 due to additional long-term borrowing and interest accrued on the Kerr Project mitigation liability as well as interest associated with a federal income tax settlement. Partially offsetting this increase was a decrease in short-term borrowing and the absence of interest paid in 1997 in conjunction with a contract settlement.
- -------------------------------------------------------------------------------- Table Nonutility Operations
Year Ended December 31 - -------------------------------------------------------------------------------- 1999 1998 1997 ------------------------------------ (Thousands of Dollars) TELECOMMUNICATIONS: REVENUES: Revenues ........................... $ 84,350 $ 87,748 $ 46,691 Earnings from unconsolidated investments .................... 10,392 10,909 435 Intersegment revenues .............. 1,012 1,298 799 ------------------------------------ 95,754 99,955 47,925 EXPENSES: Operations and maintenance ......... 34,824 27,110 22,385 Selling, general, and administrative 12,480 12,172 8,825 Taxes other than income taxes ...... 3,762 3,623 2,294 Depreciation and amortization ...... 9,048 7,090 2,494 ------------------------------------ 60,114 49,995 35,998 ------------------------------------ INCOME FROM TELECOMMUNICATIONS OPERATIONS ..................... 35,640 49,960 11,927 COAL: REVENUES: Revenues ........................... 197,053 177,961 167,623 Intersegment revenues .............. 39,729 38,796 34,164 ------------------------------------ 236,782 216,757 201,787 EXPENSES: Operations and maintenance ......... 150,801 132,963 119,085 Selling, general, and administrative 16,174 20,588 21,355 Taxes other than income taxes ...... 25,759 24,050 23,455 Depreciation and amortization ...... 7,446 6,596 9,043 ------------------------------------ 200,180 184,197 172,938 ------------------------------------ INCOME FROM COAL OPERATIONS ........ 36,602 32,560 28,849
INDEPENDENT POWER: REVENUES: Revenues ........................... 75,101 73,707 70,932 Earnings from unconsolidated investments .................... 21,042 89,525 14,980 Intersegment sales ................. 1,764 2,014 1,820 ------------------------------------ 97,907 165,246 87,732
EXPENSES: Operations and maintenance ......... 65,343 65,009 63,837 Selling, general, and administrative 4,160 4,746 4,290 Taxes other than income taxes ...... 1,840 1,767 1,868 Depreciation and amortization ...... 3,122 9,005 2,774 ------------------------------------ 74,465 80,527 72,769 ------------------------------------ INCOME FROM INDEPENDENT POWER OPERATIONS ............... $ 23,442 $ 84,719 $ 14,963
OIL AND NATURAL GAS: REVENUES: Revenues ........................... $ 338,869 $ 221,662 $ 163,656 Intersegment revenues .............. 16,663 17,606 3,120 ------------------------------------ 355,532 239,268 166,776 EXPENSES: Operations and maintenance ......... 284,517 183,536 118,266 Selling, general, and administrative 18,091 20,925 10,723 Taxes other than income taxes ...... 6,049 4,908 4,555 Depreciation, depletion, and amortization ............... 23,832 22,259 16,922 Write-downs of long-lived assets ... 7,083 -- -- ------------------------------------ 339,572 231,628 150,466 INCOME FROM OIL AND NATURAL GAS OPERATIONS ......... 15,960 7,640 16,310
OTHER OPERATIONS: REVENUES: Revenues ........................... 47,451 47,988 939 Intersegment revenues .............. 1,874 1,913 5,719 ------------------------------------ 49,325 49,901 6,658 EXPENSES: Operations and maintenance ......... 50,140 51,634 3,780 Selling, general, and administrative (49) 2,210 6,923 Taxes other than income taxes ...... 1,281 1,433 4 Depreciation and amortization ...... 4,844 4,088 494 ------------------------------------ 56,216 59,365 11,201 ------------------------------------ LOSS FROM OTHER OPERATIONS ..................... (6,891) (9,464) (4,543)
INTEREST EXPENSE AND OTHER INCOME: Interest ........................... 4,910 11,420 6,605 Other income - net ................. (17,572) (8,065) (31,160) ------------------------------------ (12,662) 3,355 (24,555) ------------------------------------ INCOME BEFORE INCOME TAXES .............. 117,415 162,060 92,061 INCOME TAXES ............................ 32,123 51,615 26,227 ------------------------------------ NONUTILITY NET INCOME AVAILABLE FOR COMMON STOCK ......... $ 85,292 $ 110,445 $ 65,834 ====================================
NONUTILITY OPERATIONS
. TELECOMMUNICATIONS OPERATIONS
1999 Compared With 1998 - -----------------------
Because Touch America received the $257,000,000 prepayment on January 16, 1999, 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 will be approximately $24,000,000.) Touch America is recognizing the prepayment in revenues over the remaining term of the agreement. Earnings from unconsolidated investments, approximately $9,800,000 of which were attributable to revenues from dark-fiber sales through the FTV joint venture, were approximately $10,400,000 in 1999, compared with earnings from unconsolidated investments in 1998 of approximately $10,900,000. The decrease primarily resulted from a change in how we account for dark-fiber transactions. The change in accounting resulted from Financial Accounting Standards Board (FASB) Interpretation No. 43, "Real Estate Sales" (an interpretation of SFAS No. 66, "Accounting for Sales of Real Estate"). As a result, Touch America will recognize earnings of approximately $7,000,000 from dark-fiber transactions pursuant to existing agreements entered into after June 30, 1999, over the applicable contract term.
After adjusting private-line revenues for the accounting effects of the prepayment and after excluding the dark-fiber sales included in earnings from unconsolidated investments, Touch America's 1999 operating revenues increased approximately 21 percent as compared to 1998. With the same adjustments above, Touch America's 1999 operating income increased approximately 24 percent.
The increase in operating revenues, after the above adjustments, mainly consists of two elements. First, it reflects increased private-line revenues of approximately $10,100,000 due to higher revenues from sales of fiber capacity. Second, long-distance revenues, including Internet-service and equipment-service revenues, increased approximately $7,800,000 as a result of increased long-distance customer and minute sales and customer growth.
- -------------------------------------------------------------------------------- Table The following table shows year-to-date changes in long-distance revenues for the previous two years, in millions of dollars, and the related percentage changes in minutes sold, price per minute, and customer growth. - -------------------------------------------------------------------------------- 1999 1998 --------------------- Revenues .................... $ 4 $ 3 Minutes sold ................ 31% 43% Price per minute ............ (9%) (15%) Customer growth ............. 26% 61% - --------------------------------------------------------------------------------
Operations and maintenance (O&M) expense increased approximately $7,700,000 as a result of increased private-line, equipment-service, and long-distance sales. Depreciation and amortization expense increased approximately $2,000,000 as a result of an increase in plant.
1998 Compared With 1997 - -----------------------
Revenues from telecommunications operations increased primarily due to sales on Touch America's Washington-to-Minnesota and Colorado-to-Canada fiber-optic network and a higher volume of long-distance minutes sold. We began earning revenues from the fiber-optic network late in the third quarter of 1997. We have a one-third interest in the FTV joint venture, which made dark-fiber sales on an inland Portland-to-Los Angeles fiber-optic network. These dark-fiber sales account for the $10,500,000 increase in earnings from unconsolidated investments.
Expenses for 1998 were higher due to the operation of Touch America's fiber-optic network mentioned above, increased marketing expenses, and costs related to the increased long-distance service.
. COAL OPERATIONS
1999 Compared With 1998 - -----------------------
Income from coal operations in 1999 increased approximately $4,000,000 over 1998 mainly because of a one-time refund in 1998 to Colstrip Units 3 and 4 owners. Northwestern Resources' lignite revenues increased approximately $13,600,000 as a result of a 1 percent increase in volumes sold and an increase in reimbursable mining costs, partially offset by a reversal of revenues previously recorded for deferred benefits.
Western Energy's consolidated 1999 revenues increased approximately $6,400,000 over 1998 primarily because Western Energy paid approximately $7,900,000 in one-time refunds in the third quarter of 1998 to the owners of Colstrip Units 3 and 4 to settle contract disputes. This increase was offset in part by a refund of $2,700,000 in the first quarter of 1999 for final pit reclamation funds previously collected. In addition, volumes sold at the Rosebud Mine increased 1 percent in 1999.
O&M expenses increased approximately $17,800,000 due to higher royalties, equipment maintenance and rentals, and overburden stripping costs. SG&A expenses decreased approximately $4,400,000 primarily from reversal of deferred benefit costs at Northwestern Resources in 1999 and a lease abandonment in the fourth quarter of 1998. Taxes other than income taxes increased due to the higher value of coal sold in 1999 and a property tax refund received by Northwestern Resources at the Jewett Mine in the third quarter of 1998, partially offset by credits resulting from a court decision upholding Western Energy's position regarding severance tax credits.
1998 Compared With 1997 - -----------------------
Income from coal operations increased by $3,700,000 primarily due to an increase in tons sold. Revenues from the Rosebud Mine, including revenues from a synthetic fuel project at the mine, increased $9,500,000. Volume of coal sold to the Colstrip Units in 1998 was 18 percent higher due to less downtime for repairs and scheduled maintenance at the Colstrip generating plants. These increased volumes were partially offset by lower prices resulting from contract dispute settlements with Puget in February 1997 and with the other non-operating owners in August 1998. As discussed earlier, these changes will result in modest profit reductions until mid-year 2000 with greater price reductions thereafter. Revenues from the Jewett Mine rose $5,500,000 primarily as a result of an increase in reimbursable mining expenses, partially offset by a 4 percent decrease in tons of lignite sold.
O&M expenses increased primarily due to higher volumes at the Rosebud Mine and increased stripping costs at the Jewett Mine. Depreciation and amortization expenses decreased primarily as a result of the resolution of matters booked in a prior year relating to the former Colorado mining operations.
. INDEPENDENT POWER OPERATIONS
1999 Compared With 1998 - -----------------------
Earnings from unconsolidated 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." After adjusting 1998 earnings from unconsolidated investments by those items, CES' 1999 revenues increased approximately $5,400,000 from its existing projects as a result of improved operations.
Amortization expense was lower than in 1998 because CES 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.
1998 Compared With 1997 - -----------------------
Earnings from unconsolidated investments increased approximately $74,500,000 primarily because of CES' recognition of earnings in 1998 as a result of the events discussed above.
Expenses increased approximately $7,800,000 mainly because of a $6,200,000 increase in the amortization of CES' independent power investments. Power-supply expenses increased $2,200,000 resulting from increased generation, partially offset by a decrease in project development costs of $1,100,000.
. OIL AND NATURAL GAS OPERATIONS
- -------------------------------------------------------------------------------- Table The following table shows year-to-year changes for the previous two years, in millions of dollars, in the various classifications of revenues, and the related percentage changes in volumes sold and prices received. - -------------------------------------------------------------------------------- 1999 1998 --------------------------------- Natural gas -revenue $ 101 $ 72 -volume 36% 96% -price/Mcf 11% (20%)
Natural gas liquids -revenue $ 12 $ 12 -volume 49% 244% -price/bbl 11% (10%)
Oil -revenue $ 1 $ (12) -volume (16%) (38%) -price/bbl 30% (38%)
Miscellaneous -revenue $ 2 $ -- - --------------------------------------------------------------------------------
1999 Compared With 1998 - -----------------------
Income from oil and natural gas operations increased approximately $8,300,000 due mainly to higher market prices in 1999. Natural gas revenues increased because marketing and trading revenues and volumes were significantly higher as a result of increased sales into California and Midwestern markets. Natural gas production and prices were both higher than the prior year. Revenues from oil operations were slightly higher because improved prices more than offset lower production. Natural gas liquids revenues were higher, again because of increased marketing and trading activities and higher prices.
O&M expenses increased mainly because of higher purchased natural gas and higher gas prices. SG&A expenses decreased primarily from reduced incentive compensation accruals and lower expenditures for outside services. Taxes other than income taxes increased because of the higher value of the natural gas produced from our reserves. Depreciation, depletion, and amortization expenses increased reflecting higher natural gas production, as well as write-downs of long-lived assets in our Canadian 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."
1998 Compared With 1997 - -----------------------
Income from oil and natural gas operations decreased primarily due to lower market prices in 1998. In addition to lower prices, revenues from oil operations decreased due to the sale of production properties. Natural gas and natural gas liquids revenues increased due to production from properties
acquired in the second quarter of 1997 and from former utility assets transferred to oil and natural gas operations in the fourth quarter of 1997. In addition, marketing to wholesale customers in California started in the second quarter of 1998. These increases were partially offset by lower prices in 1998.
O&M expenses increased due to the costs of operating the acquired properties and transferred assets and because of purchased natural gas needed to serve the new wholesale customers. Lower prices for purchased gas partially offset this increase. New operations also accounted for the increases in SG&A and depreciation, depletion, and amortization expenses.
. INTEREST EXPENSE AND OTHER INCOME, AND INCOME TAXES
1999 Compared With 1998 - -----------------------
Interest expense decreased primarily because we used funds from the telecommunications prepayment to reduce nonutility debt.
Other income - net increased by approximately $9,500,000, of which approximately $4,400,000 was attributable to interest income received on investments. The remaining increase is largely because of increased intersegment interest income on loans from nonutility operations to utility operations.
Income tax expense decreased because of lower pretax income and an estimated lower effective tax rate for 1999.
1998 Compared With 1997 - -----------------------
Interest expense increased primarily due to increases in the amount of outstanding borrowings to provide short-term financing for our nonutility operations expansion and higher interest rates.
Other income - net decreased due to 1997 gains of approximately $23,000,000 on sales of non-strategic oil and natural gas properties and a $10,300,000 gain on the sale of our investment in a Brazilian gold mine. These gains were partially offset by a loss on the sale of non-strategic Wyoming coal properties. The absence of dividend income from the Brazilian gold mine and interest income associated with a 1997 settlement with the IRS also reduced other income.
The increase in income tax expense resulted from higher pretax income as well as a credit to expense in 1997 associated with a settlement with the IRS.
LIQUIDITY AND CAPITAL RESOURCES
. OPERATING ACTIVITIES
Net cash provided by operating activities was $660,183,000 in 1999, compared to $255,677,000 in 1998, and $201,091,000 in 1997. The current year increase of $404,506,000 was attributable mainly to a $257,000,000 prepayment received in January 1999 from a Touch America customer and $106,000,000 that we received as a result of the termination of the purchase-power agreement with the LADWP and the establishment of the new agreement. We are recognizing these revenues over the remaining terms of the Touch America agreement and the new agreement with the LADWP. Both agreements have approximately 11 years remaining. We used cash from the telecommunications prepayment to reduce long-term debt and short-term borrowings and pay taxes on the prepayment and on expected gains resulting from the sale of our electric generating assets. We expect to use the LADWP proceeds for general corporate purposes, including the expansion of Touch America.
. INVESTING ACTIVITIES
Net cash provided by investing activities was $306,504,000 in 1999, compared to net cash used for investing activities of $159,552,000 in 1998 and $199,368,000 in 1997. The current year increase of $466,056,000 was due primarily to the proceeds received from the sale of our generating assets. As discussed in the "Financing Activities" section below, we have used some of the sales proceeds to repurchase shares of our common stock, and we have begun to retire long-term debt. We also intend to use some of the proceeds to expand Touch America. See Note 5, "Sale of Electric Generating Assets," for information regarding the sale of our generating assets and the use of proceeds from the sale. - --------------------------------------------------------------------------------
Table Forecasted capital expenditures for 2000 and capital expenditures during the prior three years are as follows:
- -------------------------------------------------------------------------------- Forecasted Actual --------------------------------------------- 2000 1999 1998 1997 --------- -------------------------------- (Thousands of Dollars) Utility ........................ $ 57,000 $ 63,598 $ 83,323 $138,318 Nonutility* .................... 397,000 221,709 130,078 173,368 -------- ------------------------------- Total ....................... $454,000 $285,307 $213,401 $311,686 ======== ===============================
*Approximately $287,000,000 of the $397,000,000 forecasted 2000 nonutility capital expenditures is for telecommunications operations. These forecasted capital expenditures do not include amounts that may be necessary as a result of the Qwest asset acquisition discussed in Note 3, "Commitments." If the Qwest acquisition is closed, we do not expect the purchase price and subsequent additional related capital expenditures to exceed $300,000,000.
- --------------------------------------------------------------------------------
Consistent with our strategy, we intend to invest the majority of our utility's capital expenditures during 2000 in upgrading our electric and natural gas transmission and distribution systems, and extending our electric and natural gas distribution lines. Similarly, we expect to invest the majority of our nonutility capital expenditures during 2000 on expanding and developing Touch America's fiber-optic network and wireless
communications systems. We also expect Touch America's network traffic to increase and, therefore, expect these efforts to result in further capital expenditures. See Item 1, "Business," under the "Telecommunications Operations," and Note 3, "Commitments," for further discussion of Touch America's projects and commitments. In addition, we expect expenditures for future project investments by our independent power operations; drilling, development, and capital-improvement projects for our natural gas operations; and the implementation of our ERP system.
We estimate that internally generated funds for 2000, by business unit, will average 142 percent of our utility's capital expenditures, exclusive of the expenses associated with the sale of our generation facilities, and 26 percent of our nonutility construction program, exclusive of the Qwest asset acquisition discussed in Note 3, "Commitments." We expect to finance any remaining capital expenditure balances, as well as the repayment of maturing long-term debt, with the remaining generation-sale proceeds, short-term and long-term debt, and with sales of equity securities. The amounts and timing of these activities will depend upon future market conditions. We expect to have adequate sources of external capital to meet our financing needs.
. FINANCING ACTIVITIES
Net cash used for financing activities was $422,396,000 in 1999, compared to $88,779,000 in 1998 and $27,981,000 in 1997.
In December 1998, the MPC Natural Gas Funding Trust (Trust), a wholly owned subsidiary, issued $62,700,000 of 6.2 percent asset-backed securities known as transition bonds. On February 1, 1999, we used the majority of these proceeds to retire $55,000,000 of our 7.7 percent First Mortgage Bonds. The transition bonds will be retired from funds collected by the Trust through usage-based charges levied on natural gas transportation and distribution customers. The retirements will occur at six-month intervals from September 15, 1999, through March 15, 2012, and will be in varying amounts depending on revenues collected from customers. At December 31, 1999, $2,603,194 is classified as due within one year on the Consolidated Balance Sheet.
As part of the Tier II rate filing discussed in Note 4, "Deregulation and Regulatory Matters," we indicated our intention to retire approximately $266,000,000 of long-term debt. We estimate that the expenses associated with these retirements will be approximately $20,000,000. On September 3, 1999, we retired $10,000,000 of our 7.875 percent Series B Unsecured Medium-Term Notes (MTNs) due December 23, 2026. We retired an additional $5,000,000 of these MTNs on October 13, 1999. In addition, we retired $5,000,000 of 7.25 percent Secured MTNs due January 19, 2024, and $7,000,000 of 8.68 percent Unsecured Series A MTNs due February 7, 2022, in January of 2000. We plan to retire the remaining $239,000,000 of long-term debt throughout the year 2000.
We retired at maturity $2,500,000 of 8.90 percent Series A MTNs on October 1, 1999.
See Note 7, "Common Stock," for a discussion of our December 23, 1999, purchase of 4,682,100 shares of our common stock, at a cost of $144,872,000, through our share-repurchase program.
Dividends paid on common and preferred stock were $90,902,000 in 1999, $91,598,000 in 1998, and $91,112,000 in 1997. During 1999, our regular quarterly dividend level was 20 cents per share of outstanding stock or 80 cents per share on an annual basis.
The Board of Directors periodically reviews our dividend policy to ensure that our dividend payout and dividend rate are appropriate given our business plan, strategy, and outlook. Our common stock dividend rate is dependent on our results of operations, financial position, anticipated future uses of cash, and other factors. In assessing the dividend policy, the Board of Directors also evaluates the effect of the sale of our generation assets and the continued growth of, and investment in, Touch America. As discussed in Item 1, Goldman, Sachs & Co. is assisting in evaluating options with respect to implementing a strategy to separate Touch America from Montana Power and maximize shareholder value. The Board of Directors will continue to assess and adjust our dividend policy in light of these and other developments.
The consolidated borrowing ability under our Revolving Credit and Term Loan Agreements was $179,400,000, of which $161,900,000 was unused at December 31, 1999. We also have short-term borrowing facilities with commercial banks that provide both committed and uncommitted lines of credit and the ability to sell commercial paper.
Our long-term debt as a percentage of capitalization was 35 percent during 1999, and 37 percent in 1998 and 1997. Approximately $59,000,000 of long-term debt will mature during the year 2000. With the generation sales proceeds available to repurchase long-term debt, the above ratio could decrease during 2000. 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, see Note 3, "Commitments."
While we do not expect to issue additional First Mortgage Bonds in 2000, the Mortgage and Deed of Trust would not preclude us from issuing sufficient First Mortgage Bonds to meet our expected financing requirements for the year. Neither our restated Articles of Incorporation, the Mortgage and Deed of Trust, or our Sinking Fund Debenture Agreement contain any restrictions on issuance of short-term debt or preferred stock.
See Note 10, "Long-Term Debt," and Note 11, "Short-Term Borrowing," for further information on our financing activities.
SEC RATIO OF EARNINGS TO FIXED CHARGES
For the twelve months ended December 31, 1999, our ratio of earnings to fixed charges was 3.25 times compared to
3.34 times for 1998 and 2.94 times for 1997. Fixed charges include interest, the implicit interest of Colstrip Unit 4 rentals, and one-third of all other rental payments.
INFLATION
We believe that, at currently anticipated levels, inflation will not materially affect our results of operations.
YEAR 2000
We did not have any significant disruptions as a result of the calendar rollover from 1999 to 2000. To achieve this result, we inventoried critical information technology (IT) systems and non-information (non-IT) systems, analyzed the systems to determine their Year 2000 (Y2K) readiness, replaced or repaired systems, if necessary, and tested the systems to ensure their availability and integrity. We completed and tested contingency plans to ensure business continuity in the event of unanticipated problems, but we did not have to activate any of our contingency plans.
We did not establish a formal process to track Y2K expenditures. Many of the measures that mitigated Y2K effects coincided with normal operations and maintenance and, therefore, were not accounted for separately as Y2K expenditures. For example, a capital upgrade to the energy management system that cost $460,000 was necessary to provide additional functionality and also resulted in a Y2K benefit. Likewise, we implemented a new method of customer billing at a cost of $3,100,000 and although it addressed the Y2K issue, the new method was planned for reasons other than Y2K. Our Information Services Department did track its Y2K expenditures and estimates that it spent approximately $2,400,000 to address the Y2K issue. Although we are unable to estimate our overall costs of ensuring that we were Y2K ready, these costs were not material to our consolidated financial position, results of operations, or cash flows.
The above information is a Year 2000 Readiness Disclosure pursuant to the Federal Year 2000 Information and Readiness Disclosure Act.
NEW ACCOUNTING PRONOUNCEMENTS
New requirements associated with the accounting for derivative instruments and hedging and trading activities eventually will affect MPT&M. In addition, a recent interpretation of how to properly account for certain dark-fiber sales has affected Touch America.
. SFAS No. 133 AND SFAS No. 137
In June 1998, the Financial Accounting Standards Board (FASB) issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133 requires that all derivative instruments be recorded on an entity's balance sheet at fair value. The statement also expands the definition of a derivative. In July 1999, the FASB issued SFAS No. 137, "Accounting for Derivative Instruments and Hedging Activities: Deferral of the Effective Date of FASB Statement No. 133." SFAS No. 137 delays for one year the effective date of SFAS No. 133. This delay means that we are not required to adopt SFAS No. 133 until January 1, 2001. However, we can adopt it earlier if we choose to do so. We have not yet determined the effect that adopting SFAS No. 133 will have on our consolidated financial position, results of operations, or cash flows.
Changes in the fair value of derivatives will be recognized each period either in current earnings or as a component of comprehensive income, depending on whether the derivative is designated as part of a hedge transaction. The statement distinguishes between (1) fair-value hedges, defined as hedges of assets, liabilities, or firm commitments, and (2) cash-flow hedges, defined as hedges of future cash flows related to a variable-rate asset or liability or a forecasted transaction. Recognition of changes in the fair value of a fair-value hedge will generally be offset in the income statement by the recognition of the change in the fair value of the hedged item. Recognition of changes in the fair value of a cash-flow hedge will be reported as a component of comprehensive income. The gains or losses on the derivative instruments that are reported in comprehensive income will be reclassified into current earnings in the periods in which the earnings are affected by the variability of the cash flows of the hedged item. The ineffective portions of all hedges will be recognized in current earnings.
. FASB INTERPRETATION NO. 43
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." This interpretation, which requires entities to recognize revenues from dark-fiber sales over the period of the contract rather than at the time of sale if title to the rights of use does not transfer to the lessee at the end of the contract, applies to transactions entered into after June 30, 1999. As a result of FASB Interpretation No. 43, we changed how we account for transactions involving dark-fiber sales on a prospective basis. Rather than recognizing approximately $7,000,000 in revenues in the fourth quarter from dark-fiber transactions pursuant to existing agreements entered into after June 30, 1999, Touch America will recognize these earnings over the term of the applicable contract.
ENVIRONMENTAL ISSUES
For a discussion of environmental issues and how they affect us, see Item 1, "Business," under the "Environmental Issues" section.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK - -------------------------------------------------------------------
Our energy commodity-producing, trading, and marketing activities and other investments and agreements expose us to the market risks associated with fluctuations in commodity prices, interest rates, and changes in foreign currency translation rates. We specify below what these risks are to our businesses and estimate what could occur under certain adverse market conditions and other assumptions. Because we base our estimates on assumptions only, actual results under the conditions assumed below could differ materially from our estimates. In addition, these disclosures indicate only reasonably possible losses and do not necessarily indicate expected future losses.
TRADING INSTRUMENTS
Commodity price risk represents the primary market risk to which our unregulated energy-commodity producing, trading, and marketing operations are exposed. We discuss the derivative financial instruments that we use to manage this risk in Note 1, "Summary of Significant Accounting Policies, Derivative Financial Instruments." We do not use derivative financial instruments to hedge against exposure to fluctuations in interest rates or foreign currency exchange rates. We do, however, have investments in independent power partnerships, some of which have used derivative financial instruments to hedge against interest rate exposure on floating rate debt. At December 31, 1999, however, we believe that we would not experience any material adverse effects from the risks inherent in the independent power partnerships' instruments.
. ELECTRICITY
In June 1998, prior to our August 1998 decision to exit the electric trading and marketing businesses, MPT&M entered into a derivative financial transaction, called a "swap," in conjunction with one of our electric retail sales contracts. That swap allows us to receive the difference between a fixed price and a market-index price for electricity. We net the difference against the cost of purchasing electricity to serve the retail sales contract. Thus, the swap, which expires before the supply contract, allows us to mitigate our losses on the retail sales contract.
. CRUDE OIL, NATURAL GAS, AND NATURAL GAS LIQUIDS
In December 1998, our Audit Committee adopted commodity risk-management policies and practices to govern the execution, recording, and reporting of derivative financial instruments and physical transactions associated with the trading and marketing activity of crude oil, natural gas, and natural gas liquids engaged in by MPT&M. These policies and practices require MPT&M to identify, quantify, and report commodity risks and to hold regular Risk Management Committee meetings. Our Risk Management Committee (1) approves the risk-related trading activities in which MPT&M participates and the kinds of instruments that MPT&M may use, and (2) recommends to our Audit Committee specific limits for MPT&M's trading activity.
MPT&M's value-at-risk (VaR) is based on J.P. Morgan's RiskMetrics(TM) approach: variance/co-variance. This approach uses historical estimates of volatility and correlation and values optionality using delta equivalents. Thus, it provides us a measure of MPT&M's exposure to potential losses from future adverse changes in the fair value of the commodities and financial instruments MPT&M trades. Because actual future changes in markets - prices, volatilities, and correlations - may be inconsistent with historical observations, MPT&M's VaR as measured by RiskMetrics(TM) may not accurately reflect future adverse changes in fair values.
MPT&M calculates its VaR assuming a forward 24-month time period, a one-day holding period, and a 95 percent confidence level. The calculation indicates how much MPT&M could lose from its trading transactions under those and other assumptions. At December 31, 1999, MPT&M's VaR calculation for physical and financial crude oil, natural gas, and natural gas liquids transactions, including forecasts of affiliate-owned production, was approximately $1,400,000.
Our Audit Committee established a "VaR limit" to manage our exposure to potential losses from trading activity. MPT&M must report to that committee the number of times it exceeds the established limit. On June 21, 1999, our Audit Committee increased MPT&M's VaR limit to $2,000,000, to include crude oil and natural gas liquids and forecasts of affiliate-owned production.
VAR RESULTS
. From January 1, 1999, through June 20, 1999, when MPT&M's VaR limit was set at $1,000,000, it reported daily adverse changes in fair values in excess of that $1,000,000 limit on seven occasions;
. From June 21, 1999, through December 31, 1999, when MPT&M's VaR limit was set at $2,000,000, it reported daily adverse changes in fair values in excess of that $2,000,000 limit on six occasions; and
. From January 1, 2000, through March 1, 2000, MPT&M reported daily adverse changes in fair values in excess of its VaR limit on no occasions.
. COUNTERPARTY CREDIT RISK
Commodity price changes may provide a motive to our counterparties to default on their delivery or payment obligations to us under our physical and financial crude oil, natural gas, and natural gas liquids trading instruments. Our
corporate credit risk policy requires us to investigate and monitor the creditworthiness of our physical and financial trading counterparties. We do not expect nonperformance by these trading counterparties to have a material adverse effect on our consolidated financial position, results of operations, or cash flows.
. SUMMARY OF 1998 AND COMPARISON OF 1999 WITH 1998
At December 31, 1998, we had no derivative financial contracts relating to crude oil or natural gas liquids, nor did our VaR limit include those commodities. At December 31, 1999, we include derivative financial contracts relating to those commodities in the calculation of our VaR limit. At both dates, however, our VaR calculation was less than $2,000,000.
OTHER-THAN-TRADING INSTRUMENTS
. COMMODITY PRICE EXPOSURE
UTILITY
The Public Utilities Regulatory Policies Act (PURPA) required that our electric utility enter into agreements with Qualifying Facilities (QFs) for the purchase or exchange of electricity under contracts with expiration terms ranging from 2003 through 2031. At December 31, 1999, we estimate that these contracts could result in above-market costs of between $300,000,000 and $500,000,000 throughout their duration. A hypothetical 10 percent adverse change in the market price for electricity increases the potential above-market costs by $25,000,000 to $30,000,000. We are evaluating options for divestiture of these contracts.
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 power until July 2002 to those customers who have not chosen another supplier. Both agreements price the power sold at a market index, with a monthly floor and an annual cap and, therefore, limit our exposure to price fluctuations of the electricity market to the cap, but expose us to price fluctuations below the floor.
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 six of these contracts, with expirations between 2000 and 2006.
These electric and natural gas agreements have liquidating 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 the possibility of regulatory lag or even disallowance. For additional information, see Note 4, "Deregulation and Regulatory Matters."
We entered into a contract to sell electricity to an industrial customer at terms that include a fixed price for a portion of the power delivered and an index-based price for another portion. Approximately three years from now, the contract provides that we sell all power to our customer at an index-based price. Since the sale of our generating assets on December 17, 1999, we have had to serve this customer with power purchased in the electricity market. Because the price of that power could be greater than the fixed-price portion of the contract, the fixed-price portion subjects us to commodity price risk. With the uncertainties relating to the supply requirements of the contract and uncertainties surrounding various arrangements that would allow us to serve the contractual demand, we cannot determine at this time the potential effects of this contract on our future consolidated financial position, results of operations, and cash flows. MPT&M has entered into a swap agreement to mitigate the commodity price risk inherent in this contract, and we continue to examine other options to minimize our costs.
NONUTILITY
Northwestern Resources has a full-lignite requirements supply agreement (LSA) through July 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 Powder 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. 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.
1999 Form 10-K The Montana Power Company - -------------------------------------------------------------------------------- Part II . Item 7A . Quantitative And Qualitative Disclosures About Market Risk
However, neither Western Energy nor the Colstrip Project Division 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.
Before MPT&M exited the electric trading and marketing business, it entered into both electric purchase and sale contracts, expiring between 2000 and 2002. Some of these contracts are based on indexed-based prices and others on fixed prices. The fair values of the fixed-price contracts are subject to changes in electric market prices.
CES has equity interests in various electric generation and co-generation projects, expiring between 2008 and 2023. These projects sell power under contracts with prices determined by PURPA and other contracts with indexed-based or fixed prices. Even the fixed-price contracts limit our exposure to commodity price risk, because fuel costs are controlled through long-term or pass-through contracts.
CES' Colstrip 4 Lease Management Division sells the leased share of Colstrip Unit 4 generation principally to the LADWP and to Puget under contracts that expire at the same time as our sale-leaseback agreement of Colstrip Unit 4. In December 1999, we agreed with the LADWP to terminate the 11 remaining years of the existing contract, and we entered into a new power purchase agreement with the LADWP to provide 111 MWs of capacity and energy from December 21, 1999, to December 29, 2010, scheduled at rates over the duration of the agreement. We received $106,000,000 from the LADWP as consideration for the termination of the existing agreement and the establishment of the new agreement. The new agreement subjects us to commodity price risk to the extent that our operational and fuel costs exceed the revenues allowable under the price schedule.
- -------------------------------------------------------------------------------- Table Based on mark-to-market analyses and the net present value of forecasted cash flows at December 31, 1999, the table set forth below contains estimates of the fair market values of the above electric purchase and sale contracts as well as the effect on those values of a hypothetical 10 percent increase in electricity prices: - --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
. INTEREST RATE EXPOSURE
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 in the December 31, 1999, fair value of the reclamation fund and cost-based investments would be immaterial; and (2) the potential loss in the December 31, 1999, fair values of the mandatorily redeemable preferred securities and long-term debt would be approximately $5,700,000 and $26,500,000, respectively. Note 1, "Summary of Significant Accounting Policies, Fair Value of Financial Instruments," provides further information about fair valuation.
. FOREIGN CURRENCY EXPOSURE
Our primary foreign currency exposure results from (1) our Canadian subsidiaries - Altana Exploration Company and Altana Exploration Ltd. - exploring for, producing, gathering, processing, transporting, and marketing natural gas and crude oil in Canada, and (2) MPT&M trading and marketing natural gas in Canada. There has been no material change in these activities or the corresponding foreign currency risk associated with these activities. We believe, therefore, that the market risk associated with a hypothetical 10 percent adverse change in foreign currency translation is immaterial.
. SUMMARY OF 1998 AND COMPARISON OF 1999 WITH 1998
At December 31, 1998, our utility and nonutility businesses exposed us to 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 1998 and 1999:
. In 1998, we estimated the commodity price risk associated with Northwestern Resources' contract from 2002 to 2015, assuming that the market price of PRB coal would remain flat. In 1999, we did not consider that assumption relevant and, therefore, did not estimate its effect on Northwestern Resources' projected pretax income.
. In 1998, we did not estimate the total fair market value of CES' equity investments in power sale projects or the effect of a hypothetical 10 percent increase of electric market prices on that fair market value. Based on the same assumptions that we used to calculate those values for 1999 above, we estimate that, at December 31, 1998, those values would have been $111,500,000 and $104,000,000, respectively.
. In 1998, we estimated that a hypothetical 10 percent increase in interest rates would decrease the fair market values of our long-term debt by $15,200,000. In 1999, we estimated that it would decrease it by $26,500,000. The estimated decrease was greater in 1999 due to the higher interest rates of 1999 used to compute the fair market value of long-term debt.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA - ---------------------------------------------------
INDEX TO FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Page
Management's Responsibility for Financial Statements ........................................... 58
Report of Independent Accountants ....................................... 58
Consolidated Financial Statements:
Consolidated Statements of Income for the Years Ended December 31, 1999, 1998, and 1997 .............................. 59
Consolidated Balance Sheets as of December 31, 1999 and 1998 ..................................... 60
Consolidated Statements of Cash Flows for the Years Ended December 31, 1999, 1998, and 1997 .............................. 62
Consolidated Statements of Common Shareholders' Equity for the Years Ended December 31, 1999, 1998, and 1997 .............................. 63
Notes to Consolidated Financial Statements ......................... 64
Supplementary Data (Unaudited) .......................................... 88
Financial Statement Schedule II, Valuation and Qualifying Accounts and Reserves .......................... 98
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 judgments 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 the internal auditors' and PricewaterhouseCoopers LLP's recommendations 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
Robert P. Gannon J. P. Pederson Chairman of the Board and Vice President and Chief Executive Officer Chief Financial Officer
- -------------------------------------------------------------------------------- REPORT OF INDEPENDENT ACCOUNTANTS
[LOGO OF PRICEWATERHOUSECOOPERS LLP]
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, 1999 and 1998, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1999, in conformity with accounting principles generally accepted in the United States. 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 statement. These financial statements and financial statement schedule are the responsibility of the Company's management; our responsibility is to express an opinion on these 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, 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 the opinion expressed above.
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 transactions involving the sale of dark fiber.
/s/ PriceWaterhouseCoopers LLP
Portland, Oregon
February 10, 2000, except in Note 3 for the final paragraph under the "Telecommunications" section entitled "Investments and Acquisitions," as to which the date is March 13, 2000
The accompanying notes are an integral part of these statements.
The accompanying notes are an integral part of these statements.
The accompanying notes are an integral part of these statements.
The accompanying notes are an integral part of these statements.
The accompanying notes are an integral part of these statements.
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - ---------------------------------------------------
BASIS OF ACCOUNTING
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.
USE OF ESTIMATES
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.
RECLASSIFICATIONS
We have made reclassifications to certain prior-year amounts to make them comparable to the 1999 presentation. These changes had no effect on previously reported results of operations or shareholders' equity.
CONSOLIDATION PRINCIPLES
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. To facilitate the timely preparation of the consolidated financial statements, the accounts of certain operations have been consolidated for fiscal years ending in November. The consolidated financial statements in fiscal year 2000 will eliminate the one-month lag in reporting for these operations. The results of operations of December 1999 for these entities, which would have previously been reported in results of fiscal year 2000, will be recorded as an adjustment to beginning retained earnings for fiscal year 2000.
. PROPERTY AND PLANT
- -------------------------------------------------------------------------------- Table The following table provides year-end balances of the major classifications of property and plant: - -------------------------------------------------------------------------------- December 31 ----------------------- 1999 1998 ----------------------- (Thousands of Dollars) UTILITY PLANT: - ------------- Electric: Generation (including jointly owned) ................................ $ 11,954 $ 724,483 Transmission .................................... 372,174 373,630 Distribution .................................... 573,531 550,844 Other ........................................... 92,684 192,899 Natural Gas: Production and storage .......................... 73,959 75,658 Transmission .................................... 163,968 152,804 Distribution .................................... 147,764 146,896 Other ........................................... 30,693 29,633 ----------------------- Total Utility ................................. 1,466,727 2,246,847
NONUTILITY PLANT: - ---------------- Coal ............................................ 240,228 237,913 Oil and Natural Gas ............................. 432,763 388,153 Technology ...................................... 238,147 113,474 Electric generation ............................. 76,536 76,189 Other ........................................... 64,323 49,252 ----------------------- Total Nonutility .............................. 1,051,997 864,981 ----------------------- Total Plant ................................... $2,518,724 $3,111,828 =======================
- --------------------------------------------------------------------------------
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 7.1 percent for 1999, 8.3 percent for 1998, and 8.0 percent for 1997. 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.
For information on the sale of our electric generating assets, see Note 5, "Sale of Electric Generating Assets."
Included in the plant classifications are utility plant under construction in the amounts of $3,782,000 and $37,966,000 for 1999 and 1998, respectively, and nonutility plant under construction in the amounts of $134,817,000 and $10,990,000 for 1999 and 1998, respectively.
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 percent for 1999, 1998, and 1997.
Our nonutility oil and natural gas operations use the successful-efforts method of accounting for exploration and development costs.
JOINTLY OWNED ELECTRIC PLANT
Prior to the sale of the utility generating assets discussed in Note 5, "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 also owned an approximate 30 percent interest in the transmission facilities serving these units. After the asset sale, we still own the transmission assets and associated microwave equipment which remain in property, plant, and equipment and, at December 31, 1999, our investment in these facilities was $43,380,000 and the related accumulated depreciation was $15,452,000.
We also own $43,084,000 and $33,370,000 of the nonutility Colstrip Unit 4 share of common production plant and transmission plant, which is included in nonutility plant "Electric generation" in the property, plant, and equipment table above. The accumulated depreciation related to Unit 4 production and transmission plant was $20,327,000 and $9,255,000, respectively.
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.
RECLAMATION FUND
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, 1999, 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.
REVENUE AND EXPENSE RECOGNITION
We record operating revenues 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.
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 was not significant.
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." This interpretation, which requires entities to recognize revenues from dark-fiber sales over the period of the contract rather than at the time the contract was entered into, if title to the rights of use does not transfer to the lessee at the end of the contract, applies to transactions entered into after June 30, 1999. As a result of FASB Interpretation No. 43, we changed, on a prospective basis, how we account for transactions involving dark-fiber sales. Rather than recognizing approximately $7,000,000 in revenues in the fourth quarter from dark-fiber transactions pursuant to existing agreements entered into after June 30, 1999, Touch America will recognize these earnings over the applicable contract term. 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.
REGULATORY ASSETS AND LIABILITIES
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 regulatory assets and liabilities that will be recognized in expenses and revenues in future periods when the matching revenues are collected.
- --------------------------------------------------------------------------------
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 generating assets, it is our position that any of these amounts related to electric supply should be recovered from sales proceeds in excess of book value. For further information on the effects of the sale of our electric generating assets, see Note 5, "Sale of Electric Generating Assets." For further information on the removal in 1997 of our natural gas production assets from rate base, see Note 4, "Deregulation and Regulatory Matters."
CASH AND CASH EQUIVALENTS AND TEMPORARY INVESTMENTS
We consider all liquid investments with original maturities of three months or less as 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 approximate the value reported on the Consolidated Balance Sheet.
ACCOUNTS RECEIVABLE
Accounts receivable are presented net of allowance for doubtful accounts of $2,105,000 in 1999 and $1,906,000 in 1998.
STORM DAMAGE AND ENVIRONMENTAL REMEDIATION COSTS
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. We consider the reserves adequate. The reserves balance at December 31, 1999, was approximately $11,200,000, and at December 31, 1998, was approximately $9,300,000. We have included these reserves in "current liabilities" on the Consolidated Balance Sheet.
INCOME TAXES
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 also Note 6, "Income Tax Expense."
DEFERRED REVENUES
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 "Other Current Liabilities" on the Consolidated Balance Sheet. We are recognizing the $257,000,000 prepayment received in January 1999 from a telecommunications customer and the $106,000,000 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.
NET INCOME PER SHARE OF COMMON STOCK
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.
ASSET IMPAIRMENT
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 (Loss)
FASB defines comprehensive income as all changes to the equity of a business enterprise during a period, except for those resulting from transactions with owners. For example, dividend distributions are excepted. Comprehensive income consists of net income and other comprehensive income. Net income includes such items as income from continuing operations, discontinued operations, extraordinary items, and cumulative effects of changes in accounting principle. Other comprehensive income includes foreign currency translations, adjustments of minimum pension liability, and unrealized gains and losses on certain investments in debt and equity securities.
For the years ended December 31, 1999, 1998, and 1997, 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 $3,058,000 in 1999, and decreases to retained earnings of $7,363,000 in 1998 and $2,181,000 in 1997. No current income tax effects resulted from the adjustments, nor will there be any net income effects unless we sell a foreign subsidiary.
Most of the 1998 adjustment was the result of transferring a Canadian natural gas production company from utility to nonutility operations. Until November 1, 1997, the property, plant and equipment (PP&E) of that company was included in our natural gas utility rate base at its original United States dollar value. After that company was transferred to nonutility operations, we were no longer required to state its PP&E at original United States dollar value, but were required, instead, to convert its PP&E at the foreign exchange rate in effect at the balance sheet date. At the time of the transfer, the Canadian-United States exchange rate was considerably lower than the rates used to convert most of the original United States dollar values of that company's PP&E. Consequently, the adjustment from original to current United States dollar value decreased other comprehensive income approximately $5,100,000 in 1998.
DERIVATIVE FINANCIAL INSTRUMENTS
. TRADING AND MARKETING OF ELECTRICITY
Although we decided in August 1998 to exit the electric trading and marketing businesses, The Montana Power Trading & Marketing Company (MPT&M), a subsidiary of Entech, remains a party to a single derivative financial instrument. MPT&M entered into this instrument in June 1998 with an electric retail customer to manage a portion of the customer's commodity price risk, and the instrument expires in approximately fifteen months. We do not expect this instrument to have a material effect on our consolidated financial position, results of operations, or cash flows.
. TRADING AND MARKETING OF CRUDE OIL, NATURAL GAS, AND NATURAL GAS LIQUIDS
We produce, purchase, transport, and sell crude oil, natural gas, and natural gas liquids. Changes in the prices of these commodities can affect our financial results. We manage this exposure to price risk, in part, through MPT&M's use of derivative financial instruments.
DERIVATIVE FINANCIAL INSTRUMENTS USED
We use derivative financial instruments to reduce earnings volatility and stabilize cash flows by hedging some of the price risk associated with our nonutility energy commodity-producing assets, contractual commitments for firm supply, and natural gas transportation agreements. We also use derivative financial instruments in speculative transactions to seek enhanced profitability based on expected market movements, as discussed below in "Speculative Transactions." In all cases, financial swap and option agreements constitute the principal kinds of derivative financial instruments used for these purposes.
SWAP AGREEMENTS
Under a typical swap agreement, we make or receive payments based on the difference between a specified fixed price and a variable price of crude oil or natural gas at the time of settlement. The variable price is either a crude oil or natural gas price quoted on the New York Mercantile Exchange or a natural gas price quoted in Inside FERC's Gas Market Report or other recognized industry index.
OPTION AGREEMENTS
Under a typical option agreement, we make or receive monthly payments based on the difference between the actual price of crude oil or natural gas and the price established in a private agreement at the time of execution. Receiving or making payments is dependent on whether we buy (own or hold) or sell (write or issue) the option. Buying options involves paying a premium - the price of the option - and selling options involves receiving a premium. When we use options, we defer all premiums paid or received and recognize the applicable expenses or revenues monthly throughout the option term. As of December 31, 1999, our deferred revenues due to option premiums was $1,700,000.
HEDGED TRANSACTIONS
Hedged transactions are those in which we have a position (either current or anticipated) in an underlying commodity or derivative of that commodity that exposes us to risk if the price of the underlying item adversely changes. We enter into these transactions primarily to reduce earnings volatility and stabilize cash flows. We recognize gains or losses from these derivative financial instruments in the Consolidated Statement of Income at the same time that we recognize the revenues or expenses associated with the underlying hedged item; until then, we do not reflect these gains or losses in our financial
statements. At December 31, 1999, we had unrecognized gains of approximately $2,100,000 related to these transactions. As of December 31, 1999, we had not terminated any hedging instrument before the date of the anticipated commodity production, commodity purchase or sale, or natural gas transportation commitment.
At December 31, 1999, we had no hedge agreements on natural gas production, but we did have swap and option agreements on approximately 1,280,000 barrels, or 46 percent of our estimated nonutility crude oil and natural gas liquids production through December 2001. In addition, we had swap and option agreements to hedge approximately 5.0 Bcf, or 20.1 percent of our expected delivery obligations under long-term natural gas sales contracts through December 2000. At December 31, 1999, we also had sold swap and option agreements to hedge approximately 25.4 Bcf of our nonutility natural gas pipeline transportation obligations under contracts through December 2001, and we had purchased swap and option agreements to hedge approximately 27.4 Bcf of these obligations.
SPECULATIVE TRANSACTIONS
We also enter into derivative financial transactions in which we have no underlying price risk exposure nor any interest in making or taking delivery of crude oil or natural gas commodities. We try, by these speculative transactions, to profit from the market movements of the prices of these commodities. In accordance with EITF Issue No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities," we mark to market all of our speculative transactions and recognize any corresponding gain or loss in the Consolidated Statement of Income. Through December 31, 1999, we recorded pretax gains of approximately $700,000 related to these transactions.
COUNTERPARTY CREDIT RISK
Commodity price changes may provide a motive to our counterparties to default on their delivery or payment obligations to us under our physical and financial crude oil, natural gas, and natural gas liquids trading instruments. Our corporate credit risk policy requires us to investigate and monitor the creditworthiness of our physical and financial trading counterparties.
INDEPENDENT POWER OPERATIONS
CES has investments in independent power partnerships, some of which have 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, 1999, we have not been exposed to any material adverse effects from the risks inherent in these instruments.
- --------------------------------------------------------------------------------
The following methods and assumptions were used to estimate fair value:
. Investments in independent power projects - The fair value represents our assessment of the present value of net future cash flows embodied in these investments, discounted to reflect current market rates of return.
. Reclamation fund and other investments - The carrying value of most of the investments approximates fair value as the investments have short maturities or the carrying value equals their cash surrender value. Fair value for the remainder of the investments was estimated based on the discounted value of the future cash flows expected to be received using a rate of return expected on similar current investments.
. Mandatorily redeemable preferred securities and long-term debt - The fair value was estimated using quoted market rates for the same or similar instruments. Where quotes were not available, fair value was estimated by discounting expected future cash flows using year-end incremental borrowing rates.
NOTE 2 - CONTINGENCIES - ----------------------
KERR PROJECT
A FERC order that preceded our sale of the Kerr Project to PPL Montana required us to implement a plan to mitigate the effect of 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. A payment of approximately $15,600,000 for the period from 1985 to 1997 was included in this amount. In the sale of the Kerr Project, PPL Montana assumed the obligation to make post-closing license compliance payments; however, we retained the obligation to make payments regarding pre-closing license compliance payments.
In December 1998 and January 1999, we asked the United States Court of Appeals for the District of Columbia Circuit to review FERC's orders and the United States Department of Interior's conditions contained in them. On September 17, 1999, the court granted the motion of the parties and intervenors to hold up the appeal pending settlement efforts. In December 1999, we, along with PPL Montana, the United States Department of the Interior, the Confederated Salish and Kootenai Tribes (the Tribes), and Trout Unlimited, in a court-ordered mediation, agreed in principle to settle this litigation.
A Statement of Agreement containing the principles for settlement of the disputes underlying the appeals was developed in December 1999. It provides that its terms are binding against all parties, with the understanding that the signatory parties will jointly draft additional documents as necessary to establish the terms of the settlement in detail. The parties are currently in the process of drafting these documents, but the court's procedure requires that the parties keep the settlement terms confidential. We have paid our settlement payment under the Statement of Agreement into an escrow account. If the parties agree on these additional documents, and if FERC approves, in a final non-appealable order, the settlement terms as reflected in proposed license amendments, we will dismiss the petitions in the court of appeals, and the escrow agent will release the payments to the Tribes. In addition, we will transfer to the Tribes 669 acres of land we own on the Flathead Indian Reservation. If the parties cannot agree upon the additional documents or FERC does not approve the proposed license amendments in the form agreed to by the parties, or if, as a result of the appeal of a FERC order, that order is not final after a specified period, the money will be returned to us, and the litigation will resume. The settlement, subject to the conditions described above, substantially reduces our obligation to pay for fish, wildlife, and habitat mitigation assigned to the pre-closing period in the sale of the Kerr Project.
MISCELLANEOUS
We 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 operation, or cash flows.
NOTE 3 - COMMITMENTS - --------------------
PURCHASE 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 2031 that require us to make payments for capacity and energy received at prices currently above market. 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 4, "Deregulation and Regulatory Matters."
The Asset Purchase Agreement (Agreement) dated as of October 31, 1998, and amended June 29, 1999 and October 29, 1999, with PPL Montana included the assignment of our contract with Basin Electric Power Cooperative (Basin) to PPL Montana. That contract committed us to purchase 98 MWs of seasonal capacity from Basin from 1994 until November 2010 at prices above current and projected market prices. However, Basin did not release us from that contract. Consequently, if PPL Montana were to default, Basin could hold us liable to perform according to the terms of the contract. Because we believe that PPL Montana will not default, we do not consider this contract our unconditional purchase obligation.
The Agreement also 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 will not have 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, which we still own and operate. Both agreements price the power sold at a market index, with a monthly floor and an annual cap. Assuming a 7.23 percent discount rate and current load forecasts, the net present value of the power purchased under the WTSAs may range from $94,000,000 to $104,000,000 for 2000, $61,000,000 to $69,000,000 for 2001, and $24,000,000 to $27,000,000 for 2002. In accordance with SFAS No. 47, "Disclosure of Long-Term Obligations," we use the lower estimate in the tables below.
. 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 2000 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.
. TRADING AND MARKETING
Before the sale of our electric generating facilities, MPT&M supplied its customers with power purchased mainly from our generation facilities. Anticipating the sale of those facilities, MPT&M entered into two electric purchase contracts in August 1998. One contract obligates MPT&M to purchase 40 MWs per hour at a fixed rate from October 1999 through 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. We sell this power to several large customers with whom we have contracts to supply power at negotiated rates.
. OIL AND GAS
Nonutility oil and natural gas operations have one take-or-pay contract, expiring in 2006, to purchase natural gas, and contracts with pipeline companies, with expiration dates between 2000 and 2013, to provide reserve capacity for natural gas shipments to customers.
- -------------------------------------------------------------------------------- Table Total payments under these contracts for the prior three years were as follows: - --------------------------------------------------------------------------------
Utility Nonutility Total ------------------------------------------------------- Electric Natural Gas Electric Natural Gas ------------------------------------------------------- (Thousands of Dollars)
1999 ............ $61,274 $ 4,069 $26,076 $ 7,898 $99,317 1998 ............ 50,611 3,508 15,355 4,454 73,928 1997 ............ 44,153 7,554 -- 3,289 54,996
- -------------------------------------------------------------------------------- Table Under the above agreements, the present value of future minimum payments, at a discount rate of 7.23 percent, is as follows:
- --------------------------------------------------------------------------------
Utility Nonutility Total ------------------------------------------------------- Electric Natural Gas Electric Natural Gas ------------------------------------------------------- (Thousands of Dollars)
2000 ........ $102,050 $ 4,023 $24,315 $ 7,647 $138,035 2001 ........ 69,752 2,312 10,743 4,661 87,468 2002 ........ 32,052 1,945 -- 2,200 36,197 2003 ........ 7,543 317 -- 2,051 9,911 2004 ........ 7,317 280 -- 1,912 9,509 Remainder ... 106,074 502 -- 17,594 124,170 ------------------------------------------------------- $324,788 $ 9,379 $35,058 $ 36,065 $405,290 =======================================================
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. COAL
Northwestern Resources entered into a lignite lease agreement that requires minimum annual payments of overriding royalty that began in 1991 for $1,125,000, adjusted quarterly for inflation. The payments will continue until Northwestern Resources pays the equivalent of $18,750,000, in 1986 dollars. At December 31, 1999, the remaining payments under this agreement were $7,217,000. Under current mine plans, Northwestern Resources should recoup these payments through lignite sales.
Northwestern Resources also agreed to pay the State of Texas $2,250,000 in May 2000 for a highway relocation that enables it to gain access to lignite under existing leases.
. TELECOMMUNICATIONS
Construction Projects
In 1999 and 1998, Touch America contracted with Northern Telecom, Inc. (Nortel) to install optical electronic equipment on certain fiber-optic networks. (That equipment transmits pulses of laser light through the fiber to increase the rate at which data are transmitted.) We expect the installations to be completed in the fourth quarter of 2000 at a cost of $51,800,000, of which $28,300,000 was paid in 1999 and 1998 in the aggregate, and $23,500,000 is scheduled for payment in 2000. In 1999, Touch America also contracted with Nortel to upgrade a telephone switch in the first quarter of 2000 at a cost of $3,000,000. TW Wireless (TWW), a joint venture of Touch America and US WEST Wireless, will lease the switch from Touch America for the life of the venture.
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 the network 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. The first route is scheduled for completion in the fourth quarter of 2000 and the last route in the second quarter of 2001. We estimate the cost of the project at $500,000,000, of which approximately one-half will be expended in 2000. 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.
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 January 2000, Touch America and AEP Communications LLC, a subsidiary of American Electric Power, formed a 50-50 joint venture named America Fiber Touch, LLC (AFT) to connect national and regional fiber-optic networks. The venture's first project is to construct a 330-mile fiber-optic route between St. Louis, Missouri, and Plano, Illinois, which makes up the Midwest route of the 4,300 mile build-out discussed above. This Midwest route is scheduled for completion in December 2000, at an estimated cost of $25,000,000, of which Touch America's portion is $12,500,000.
In August 1999, Touch America and New Century Energies (NCE) formed a 50-50 joint venture named Northern Colorado Telecommunications LLC to provide a full range of telecommunication services, including private-line service, to enterprises in the Denver metropolitan area by the middle of 2000. For the venture, NCE 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. In 1999, Touch America contributed $1,500,000 to the venture and plans to contribute $7,000,000 in 2000 and $1,500,000 in 2001.
In 1999, Touch America and Iowa Network Services, Inc. formed Iowa Telecommunications Services, Inc. (ITS). ITS will purchase from a third party 280,422 domestic access lines connected to 296 telephone exchanges in Iowa. Touch America holds a 31 percent interest in ITS, in which Touch America will invest approximately $46,000,000. ITS will fund the purchase of access lines and telephone exchanges primarily through long-term non-recourse debt, obligating ITS solely. We expect this transaction to close in the second quarter of 2000, subject to the satisfaction of various conditions and receipt of required regulatory approvals. In 1999, Touch America loaned ITS $5,000,000 to purchase computers and licenses, and will loan ITS another $5,000,000 for operations at payments scheduled for the first four months of 2000. These notes are payable on demand.
In August 1999, Touch America and US WEST Wireless entered into 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. Touch America holds approximately a 50 percent interest in the venture and will contribute approximately $45,000,000 over the next two years toward construction of TWW's physical infrastructure. Both companies contributed PCS licenses to the venture.
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 mid-2000. Touch America's share of the costs will be approximately $3,300,000.
Exchanges
In January 2000, Touch America and PF.Net, a privately held telecommunications company, agreed to an exchange of fiber, conduit, and cash to expand both companies' fiber-optic networks. Touch America receives approximately 5,900 route miles of fiber and conduit from PF.Net, in exchange for 4,400 miles of Touch America's fiber and conduit and a cash payment of $48,500,000 for the difference in route miles. This exchange will expand Touch America's network 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. Touch America paid $4,850,000 down and will pay the remainder as segments of the routes under construction are completed. Segments are scheduled for completion at various times in 2000 and 2001.
Investments and Acquisitions
In January 2000, Touch America agreed to purchase, from Century Tel Inc., 400 route miles of fiber-optic network linking Chicago and Detroit through central and southern Michigan communities for approximately $10,000,000.
In January 2000, Touch America signed a purchase agreement with Minnesota PCS, LP (MPCS) to acquire a 25 percent interest in MPCS' wireless telephone business, which owns PCS licenses in North Dakota, South Dakota, Minnesota, and Wisconsin. In accordance with the agreement, Touch America expects to make a $2,700,000 equity payment to MPCS and, over the years 2000-2001, will loan it $12,000,000 in interest-bearing notes payable on October 1, 2002. The agreement also obligates Touch America, until 2007, to $7,000,000 in guarantees for loans made to MPCS by the Rural Telephone Financing Corporation. The guarantees are callable only upon MPCS' default.
On March 13, 2000, Touch America signed an agreement with Qwest to acquire for approximately $190,000,000, subject to certain adjustments, Qwest's wholesale, private-line and long-distance telecommunications services in US WEST's 14-state region, which covers 250,000 customers for voice, data, and video services with multimedia and high-speed data applications. By this agreement, Touch America will also acquire a fiber-optic network of 1,800 route miles and associated optronics and switches. The network will connect to Touch America's fiber-optic network, and Touch America will offer employment to Qwest's sales agents in the region. We expect this acquisition to close in mid-2000, subject to the satisfaction of various conditions and the receipt of required regulatory approvals.
SALES COMMITMENTS
Our nonutility oil and natural gas operations have agreed to supply approximately 81 Bcf of natural gas to four co-generation facilities. These contracts have expiration dates between 2005 and 2011. We can supply the remaining natural gas required by these contracts with sufficient proved, developed, and undeveloped reserves and by our control of commitments to sell our production.
We entered into a contract to sell electricity to an industrial customer at terms that include a fixed price for a portion of the power delivered and an index-based price for another portion. Approximately three years from now, the contract provides that we sell all power to our customer at an index-based price. We have been supplying our customer with power purchased through an index-based contract between MPT&M and a power generator that remains effective through July 2001. Our industrial customer has given us usage estimates that do not exceed the amount of electricity that we are committed to purchase.
Because the price of power under the index-based purchase contract could exceed the price of power under the fixed-price portion of our sales contract, we are subject to commodity price risk. Due to uncertainties relating to the supply requirements of the sales contract and uncertainties surrounding various arrangements that would allow us to serve the contractual demand, we are unable to determine the effects that this contract ultimately may have on our consolidated financial position, results of operations, or cash flows. We will continue to examine our options and take steps to mitigate the commodity price risk that we face because of our fixed-price sales contract.
MPT&M has agreements, expiring between December 2000 and December 2002, with four other industrial customers to sell a maximum of approximately 103.8 MWs and a minimum of 59.3 MWs per hour. MPT&M can supply these customers from power purchased through contracts with a power generator discussed above under "Purchase Commitments."
LEASE COMMITMENTS
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. 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, was $66,000,000 for 1999, $63,000,000 for 1998, and $60,000,000 for 1997.
We have restated the previously reported 1998 and 1997 rental expenses of $58,800,000 and $56,600,000 for the inclusion of property taxes paid in accordance with our Colstrip Unit 4 Sale Lease-Back Agreement.
NOTE 4 - DEREGULATION AND REGULATORY MATTERS - --------------------------------------------
DEREGULATION
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. 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. Since restructuring is voluntary, no deadline for choice exists.
. ELECTRIC
Through December 1999, approximately 900 electric customers representing more than 1,300 accounts crossing all customer classifications - or approximately 27 percent of our pre-choice electric load - have moved to competitive supply since the inception of customer choice on July 1, 1998. Residential customers were eligible to move to choice during the fourth quarter of 1999. However, the majority of the load associated with our pre-choice electric customers who moved to other suppliers was predominantly industrial and large commercial customers.
As required by the Electric Act, we filed a comprehensive transition plan with the PSC in July 1997. Initial hearings on the filing began in April 1998, and the issues were separated into two groups: Tier I and Tier II.
Tier I issues dealt with:
. Accounting orders; . Customer choice for large industrial customers; . Pilot programs for the remaining customers; and . Standards of conduct for utility and nonutility affiliates.
Tier II issues address:
. The recovery and treatment of the QF purchase-power contract costs, which are above-market costs; . Regulatory assets associated with our electric generating business; and . A review of our electric generating assets sale, including the treatment of sale proceeds in excess of the book value of the assets and other generation-related transition costs.
In June 1998, the PSC rendered an order on Tier I issues, and on July 1, 1999, we filed a case with the PSC to resolve
Tier II issues. We will update our Tier II filing as a result of the closing of the sale of our electric generating assets, but we do not expect an order from the PSC until late 2000.
With deregulation and the resulting competition, certain generation and power supply-related costs become stranded, or unrecoverable, absent recovery from customers as a transition cost. CTCs are generation and power supply-related costs that we incurred in the regulated environment with the expectation that we would recover these costs from our customers well into the future. Included within the CTCs are the following: (1) generation-related regulatory assets, (2) utility owned generation and other purchase-power contracts, and (3) our purchase-power contracts with the QFs. We are evaluating options with respect to the QF contracts to minimize costs and are working on a number of potential buy-out agreements. The owners of the QF contracts must approve any agreements related to the contracts. In addition, the PSC must approve future cost recovery. The Electric Act allows us to issue transition bonds to refinance CTCs.
In the implementation of our comprehensive transition plan, we have initiated litigation in Montana District Court in Butte seeking reversal of a PSC decision regarding our ability to use tracking mechanisms to ensure fair and accurate recovery of above-market QF costs and certain other transition costs. In an order issued as part of its consideration of our transition plan, the PSC concluded that the Electric Act does not provide for tracking mechanisms and that transition costs must be mitigated and determined as a final matter in the transition filing. In the litigation, we also are seeking court clarification on whether the Electric Act authorized a rate freeze or a rate cap during the transition period that ends July 1, 2002. The PSC has concluded that the Electric Act authorized a rate cap, but we disagree with this interpretation.
. NATURAL GAS
Through December 1999, approximately 240 natural gas customers with annual consumption of 5,000 Dkt or more - or 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.
In accordance with a 1997 PSC order, we transferred substantially all of our natural gas utility's production assets to unregulated affiliates in 1997 at an agreed-upon amount, which was approximately $33,600,000 lower than the book value of the assets. As a component of CTCs, the PSC is allowing us to recover from our transportation and distribution customers (a) this $33,600,000 difference between transfer value and book value, and (b) approximately $25,400,000 of existing regulatory assets related to the natural gas production assets. In 1998, we issued $62,700,000 in transition bonds to refinance the CTCs for the benefit of customers. The transition bonds will be retired over 15 years through rate revenues established in accordance with Montana's Natural Gas Act. The amortization of the assets is proportionate to the repayment of principal on the bonds, resulting in no net income statement impact. The transition plan also includes a fixed-price supply contract until July 1, 2002 between our unregulated gas supply operations and our regulated distribution operations to serve the remaining customers who have not chosen other suppliers.
REGULATORY MATTERS
Milltown Dam and our electric transmission operations remain subject to FERC and PSC regulation, and the PSC regulates our electric distribution operations.
As a Hinshaw pipeline (interstate pipeline exempt from FERC jurisdiction), our natural gas transportation pipelines are not subject to FERC jurisdiction. However, we conduct interstate transportation subject to FERC jurisdiction, through an exception of our Hinshaw status. Presently, FERC has allowed the PSC to set the rates for this interstate service. Our natural gas distribution and storage operations remain subject to PSC regulation. In addition, the Alberta Energy and Utilities Board, the National Energy Board of Canada, and the United States Department of Energy all must approve the importing of Canadian natural gas.
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 filed a request with FERC to increase our open-access transmission rates and the rates for bundled wholesale electric service to two rural electric cooperatives. FERC approved an interim increase in rates charged for transmission service, pending final approval in 2000.
In January 1999, we reached a rate settlement with one of the cooperatives, resulting in an immaterial increase in rates for bundled wholesale electric service. This cooperative moved to another supplier in December 1999.
In March 1999, we reached a separate settlement with the other cooperative. Rates did not change as a result of the settlement. The cooperative was able to retain its right to continue with its separate rate-reduction complaint. We agreed to assist the cooperative in moving to choice when its full-service wholesale contract expires in exchange for its agreement to withdraw the rate-reduction complaint. This cooperative will move to another supplier in June 2000.
Finally, on March 11, 1999, we reached a settlement on open-access transmission rates. This settlement increased transmission rates by approximately $4,300,000, which had a positive effect on the results of our transmission operations.
We will also pursue, through new FERC proceedings, recovery of the transition costs associated with serving both of the wholesale electric cooperatives to correspond with our transition-costs recovery proceedings in Montana.
PSC
The Electric Act established a rate freeze for all electric customers, meaning that transmission and distribution rates cannot be increased until July 1, 2000. In January 2000, we filed a voluntary rate reduction with the PSC for approximately $16,700,000 annually, which we would implement by using the sales proceeds in excess of the book value from the recent generation sale. The reduction is effective on an interim basis pending PSC review of our Tier II filing. For additional information on the generation sale, see Note 5, "Sale of Electric Generating Assets."
. NATURAL GAS
On August 12, 1999, we filed a natural gas rate docket with the PSC requesting, among other matters, an increase in annual revenues of $15,400,000, with a proposed interim increase of $11,500,000. The filing also proposes:
. An alternative rate plan; . "Trackers" to reflect property taxes and replacement facilities in rates on a more timely basis; . A change in the allocation of costs to customer classes; and . Rate-design changes that include recovery of distribution charges through a fixed monthly system charge.
On December 9, 1999, the PSC approved an interim increase of $7,600,000 regarding the natural gas rate docket discussed above. Since then, we negotiated a settlement with a group of intervenors concerning this natural gas rate filing. The settlement allows for an increase of annual revenues of $10,300,000, which includes the interim increase of $7,600,000. The PSC will discuss the settlement at a working session in March 2000. If the settlement is acceptable, the rates will be implemented shortly thereafter.
On November 17, 1999, we filed a second natural gas rate docket with the PSC requesting recovery of costs associated with tracking gas costs annually. Approval by the PSC would result in an increase in annual revenues of $4,800,000. On December 9, 1999, the PSC approved an interim increase for this amount until we receive the final order, which we expect by mid-2000.
NOTE 5 - SALE OF ELECTRIC GENERATING ASSETS
ASSETS SOLD
On December 17, 1999, in accordance with the Agreement, we sold to PPL Montana substantially all of our electric generating assets, related contracts, and associated transmission assets totaling less than 40 miles. This included 11 of our 12 hydroelectric facilities; a storage reservoir; a coal-fired thermal generating plant at Billings, Montana; all of our interest in three coal-fired thermal generating plants at Colstrip, Montana; and other related assets, including inventories associated with the power plants. The total gross capacity of the hydroelectric facilities and coal-fired thermal generating plants sold to PPL Montana was 1,314.5 MWs.
The asset sale did not include the Milltown Dam near Missoula, Montana (gross capacity of 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.
In the sale of these assets, we generally retained all pre-closing obligations, and PPL Montana assumed all post-closing obligations. However, with respect to environmental liabilities, PPL Montana assumed all pre-closing (subject to the indemnification provisions discussed below) and post-closing environmental liabilities associated with the purchased assets, with three exceptions for pre-closing liabilities:
. Payment of fines or penalties imposed by regulatory authorities related to pre-closing activity; . Liability for pre-closing "off-site" activity, such as transportation, disposal, or storage of hazardous material; and . Remediation costs of any silts behind the Thompson Falls Dam related to pre-closing activity.
We agreed to indemnify PPL Montana from losses arising from pre-closing environmental conditions. The indemnity for required remediation of pre-closing conditions, whether known or unknown at the closing, is limited to:
. 50 percent of the loss. (Our share of this indemnity obligation at the Colstrip Project is limited to our pro-rata share of this 50 percent based on our pre-sale ownership share.)
. A two-year period after closing for unknown conditions. The indemnity for required remediation of pre-closing conditions known at the time of the closing continues indefinitely.
. An aggregate amount no greater than 10 percent of the purchase price paid for the assets.
We do not expect this indemnity obligation to have a material adverse effect on our consolidated financial position, results of operations, or cash flows. We have accrued the estimated amount of the potential liability associated with these retained obligations.
CASH PROCEEDS
The cash proceeds received for the sale of the assets, including pro-rated adjustments for such items as property taxes, was approximately $758,600,000 (including approximately $1,000,000 received in 2000.) Our transaction costs to complete the sale amounted to approximately $12,100,000.
At December 31, 1999, we recorded approximately $219,700,000 as net proceeds in excess of the book value, based on net cash proceeds of $746,500,000 less (1) approximately $497,300,000 book value of the assets sold and (2) approximately $29,500,000 of previously flowed-through tax benefits. We also recorded an income tax liability of approximately $164,100,000, based on the net proceeds less the tax basis of the assets sold.
As part of our Tier II filing, we plan to deduct from the regulatory liabilities approximately $39,300,000 of other generation-related transition costs and approximately $64,600,000 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.
PPL Montana also agreed to purchase 1,058 MWs of additional gross capacity in Colstrip, Montana from Puget and Portland General. Pursuant to the terms of the Agreement with PPL Montana, we would receive an additional $152,000,000 from PPL Montana, for added value, if Puget and Portland General both close their transactions. The added value would arise from the controlling interest in the Colstrip Units that PPL Montana would hold, as a result of the combination of our former assets with those of Puget and Portland General. However, if only Puget or Portland General - but not both - closes its respective transaction, we will receive only $117,000,000 from PPL Montana rather than $152,000,000. If neither Puget or Portland General closes its transaction, the Agreement provides that, subject to the receipt of required regulatory approvals, PPL Montana will purchase the portion of our 500-kilovolt Colstrip transmission system not associated with Colstrip Unit 4. Our sales proceeds from PPL Montana for these properties would be $97,100,000.
During February 2000, the Oregon Public Utility Commission indicated that it would deny Portland General's request to sell its ownership interest in Colstrip Units 3 and 4 to PPL Montana.
EFFECT ON 1999 EARNINGS
The asset sale positively affected 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.
USE OF PROCEEDS
We have used a portion of the net cash proceeds received (less the sale proceeds in excess of the book value) for the following general corporate purposes:
. Funding utility and nonutility projects, including those involving expansion of Touch America; . Reducing debt; and . Purchasing shares of our common stock.
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."
NOTE 6 - Income tax expense - ---------------------------
- -------------------------------------------------------------------------------- Table Income before income taxes was as follows: - -------------------------------------------------------------------------------- 1999 1998 1997 --------------------------------------------- (Thousands of Dollars)
United States ............. $ 189,186 $ 246,242 $ 177,114 Canada .................... 3,871 (2,927) 12,780 Other countries ........... 1,352 479 608 --------------------------------------------- $ 194,409 $ 243,794 $ 190,502 =============================================
- -------------------------------------------------------------------------------- Table 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: - -------------------------------------------------------------------------------- 1999 1998 1997 --------------------------------------------- (Thousands of Dollars)
Computed "expected" income tax expense ................ $ 68,043 $ 85,328 $ 66,675 Adjustments for tax effects of: Statutory depletion .......... (3,440) (4,156) (2,891) Tax credits .......... (25,775) (4,722) (11,645) State income tax, net ................ 4,545 7,393 7,147 Reversal of utility book/tax depreciation ....... 5,318 2,784 5,636 Other ................ (4,628) (8,453) (3,052) --------------------------------------------- Actual income tax expense ............ $ 44,063 $ 78,174 $ 61,870 =============================================
- -------------------------------------------------------------------------------- Table Income tax expense as shown on the Consolidated Statement of Income consists of the following components: - -------------------------------------------------------------------------------- 1999 1998 1997 --------------------------------------------- (Thousands of Dollars) Current: United States .......... $ 293,319 $ 88,233 $ 36,680 Canada ................. 1,710 1,212 994 Other countries ........ 30 -- 3,684 State .................. 53,858 13,462 9,835 --------------------------------------------- 348,917 102,907 51,193 --------------------------------------------- Deferred: United States .......... (267,958) (20,331) 6,491 Canada ................. 9,930 (1,851) 2,802 State .................. (46,826) (2,551) 1,384 --------------------------------------------- (304,854) (24,733) 10,677 --------------------------------------------- $ 44,063 $ 78,174 $ 61,870 =============================================
- -------------------------------------------------------------------------------- Table Deferred tax liabilities (assets) are comprised of the following: - -------------------------------------------------------------------------------- December 31 ---------------------------- 1999 1998 ---------------------------- (Thousands of Dollars)
Plant related .............................. $ 321,383 $ 403,832 Investment in nonutility generation projects ..................... 6,171 7,132 Other ...................................... 44,520 35,344 ---------------------------- Gross deferred tax liabilities ....................... 372,074 446,308 ----------------------------
Coal reclamation ........................... (48,096) (47,487) Amortization of gain on sale/leaseback .......................... (11,649) (12,755) Deferred revenues .......................... (103,578) -- Investment tax credit amortization ............................ (14,055) (21,833) Other ...................................... (204,152) (59,082) ---------------------------- Gross deferred tax assets ............... (381,530) (141,157) ----------------------------
Net deferred tax (assets) liabilities ........................... (9,456) 305,151 Less current deferred tax assets - net ...................... (18,303) (18,755) ---------------------------- Total noncurrent deferred tax liabilities ......................... $ 8,847 $ 323,906 ============================
- -------------------------------------------------------------------------------- Table The change in net deferred tax liabilities differs from current year deferred tax expense as a result of the following: - --------------------------------------------------------------------------------
December 31 ------------- (Thousands of Dollars)
Change in noncurrent deferred tax ........................... $(315,059) Regulatory assets related to income taxes ................... 61,182 Current deferred tax assets - net ........................... 452 Amortization of investment tax credits ...................... (21,732) Other ....................................................... (29,697) --------- Deferred tax expense ................................... $(304,854) ========= - --------------------------------------------------------------------------------
NOTE 7 - COMMON STOCK - ---------------------
STOCK SPLIT
On June 22, 1999, the Board of Directors approved a two-for-one split of our outstanding common stock. As a result of the split, which was effective August 6, 1999, for all shareholders of record on July 16, 1999, 55,099,015 outstanding shares of common stock were converted to 110,198,030 outstanding shares of common stock. We have retroactively applied the split to all periods presented.
SHARE REPURCHASE PROGRAM
In 1998, the Board of Directors authorized a share-repurchase program over the next five years to repurchase up to 20,000,000 shares, (approximately 18 percent of our then outstanding common stock) on the open market or in privately negotiated transactions. As of December 31, 1999, we had 105,536,873 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.
As a result of this authorization, we entered into a Forward Equity Acquisition Transaction (FEAT) program with a bank that committed to purchase on our behalf up to 5,000,000 shares, but not to exceed $125,000,000. On November 12, 1999, we amended the FEAT program to increase the monetary limit to $200,000,000. The expiration date of the program is October 31, 2000. Until that date, when all transactions must be settled, we can elect to fully or partially settle either on a full physical (cash) or a net share basis. A full physical settlement would be the purchase of shares from the bank for cash at the bank's average purchase price, including 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, including interest costs less dividends. Only at the time that the transactions are settled can our capital or outstanding stock be affected, and settlement has no effect on results of operations.
Since the FEAT program began and through December 23, 1999, the bank had acquired for us 4,682,100 shares of our stock. The purchase of these shares averaged approximately $30.94 per share and ranged from $27.05 per share to $33.52 per share for a total cost of $144,872,000. On December 23, 1999, we used proceeds from the sale of our generation assets to effect a full physical settlement for that amount. We have reflected the shares purchased as treasury stock on the Consolidated Balance Sheet. As of December 31, 1999, no additional shares had been acquired under the program.
SHAREHOLDER PROTECTION RIGHTS PLAN
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.
DIVIDEND REINVESTMENT AND STOCK PURCHASE PLAN
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 common shares with a minimum of $100 and a maximum of $60,000 per year.
RETIREMENT SAVINGS PLAN
We have a Retirement Savings Plan that covers all regular 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 to Plan participants. 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, 1999, 2,500,678 shares had been allocated to the participants' accounts. We recognize expense for the Plan using the Shares Allocated Method, and the pretax expense was $4,890,000, $4,923,000, and $5,194,000 for 1999, 1998, and 1997, respectively.
LONG-TERM INCENTIVE PLAN
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.
On December 31, 1999, restrictions were removed on the remaining shares of restricted stock issued in 1994 under the Long-Term Incentive Plan. During 1999, a grant of 12,000 shares of restricted stock was issued to an individual. The award is subject to forfeiture or proration if the individual should terminate employment. 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, 1999, 12,000 shares of restricted stock remained.
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 1999 and 1998 was $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 1999 and 1998, respectively: (1) risk-free interest rate of 6.35 percent and 5.08 percent; (2) expected life of 9.8 and 10 years; (3) expected volatility of 24.92 percent and 19.34 percent; and (4) a dividend yield of 5.97 percent and 6.51 percent. Had we elected to use SFAS No. 123, compensation expense would have increased $5,280,000 in 1999, $795,000 in 1998, and $195,000 in 1997. 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 and 1997 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.
- -------------------------------------------------------------------------------- Table Our preferred stock is in three series as detailed in the following table: - -------------------------------------------------------------------------------- Shares Issued Thousands Stated and and Outstanding of Dollars Liquidation --------------------------------------------- Series Price* 1999 1998 1999 1998 - -------------------------------------------------------------------------------- $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.
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, 1999 and 1998, 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 can also 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, and we 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 and those securing Pollution Control Revenue Bonds.
- -------------------------------------------------------------------------------- Table Long-term debt consists of the following: - -------------------------------------------------------------------------------- December 31 ----------------------- 1999 1998 ----------------------- (Thousands of Dollars) First Mortgage Bonds: 7.7% series, due 1999 ............................. $ 55,000 7 1/2% series, due 2001 ........................... $ 25,000 25,000 7% series, due 2005 ............................... 50,000 50,000 8 1/4% series, due 2007 ........................... 55,000 55,000 8.95% series, due 2022 ............................ 50,000 50,000 Secured Medium-Term Notes - maturing 2000-2025 7.20%-8.11% ................ 88,000 88,000 Pollution Control Revenue Bonds: City of Forsyth, Montana 6 1/8% series, due 2023 ..................... 90,205 90,205 5.9% series, due 2023 ....................... 80,000 80,000 Natural Gas Transition Bonds - 6.20%, due 2012 ....... 61,015 62,700 ESOP Notes Payable - 9.2%, due 2004 .................. 19,431 22,392 Unsecured Medium-Term Notes: Series A - maturing 1999-2022 8.68%-8.9% ......... 17,000 19,500 Series B - maturing 2001-2026 6.37%-7.96% ........ 100,000 115,000 Revolving Credit Agreements .......................... 17,502 14,241 Other ................................................ 28,111 71,779 Unamortized Discount and Premium ..................... (3,797) (4,196) ----------------------- 677,467 794,621 Less: Portion due within one year ................... 58,955 96,292 ----------------------- $ 618,512 $ 698,329 ======================
- --------------------------------------------------------------------------------
On February 1, 1999, we used the proceeds from asset-backed securities issued by the special purpose entity (SPE) discussed below to retire $55,000,000 of our 7.7 percent First Mortgage Bonds.
The electric and natural gas legislation discussed in Note 4, "Deregulation and Regulatory Matters," 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 an SPE, which is a wholly owned subsidiary, to issue the bonds. At December 31, 1999, approximately $61,015,000 was outstanding, of which approximately $2,600,000 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's. 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.
We retired at maturity $2,500,000 of 8.90 percent Series A Unsecured Medium-Term Notes (MTNs) on October 1, 1999.
On September 3, 1999, we retired $10,000,000 of our 7.875 percent Series B Unsecured MTNs due December 23, 2026. We retired an additional $5,000,000 of these MTNs on October 13, 1999.
Altana Exploration Ltd. (Altana), a wholly owned Canadian subsidiary, purchased the stock of a Canadian company for approximately $26,500,000 (United States dollars) in December 1997. We arranged financing for the purchase through an Extendible Revolving Term Credit agreement between Altana and the Royal Bank of Canada. The maximum amount of credit available under this agreement is $28,000,000 in Canadian dollars. At December 31, 1999 and 1998, the United States dollar amounts outstanding under the agreement were $17,502,000 ($24,259,000 Canadian dollars) and $14,241,000 ($21,796,000 Canadian dollars), respectively. These amounts are included in "Revolving Credit Agreements" in the table above. Interest under the agreement is calculated on the Royal Bank's prime rate that ranged from 6.25 percent to 6.75 percent during 1999.
In April 1997, we entered into a $160,000,000 Revolving Credit Agreement (Credit Agreement) for some of our nonutility operations. Under the terms of the Credit Agreement, the amount of the facility decreased on March 31, 1998, reducing the borrowing ability to $100,000,000. This Credit Agreement terminates on April 4, 2000, and all outstanding borrowings must be repaid on this date. Fixed or variable interest rate options are available under the Credit Agreement with facility fees or commitment fees on the unused portions.
As discussed in Note 2, "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 $10,200,000 in "Other" in the table above, and it is classified as due within one year on the Consolidated Balance Sheet at December 31, 1999. The final payment for $10,200,000 occurred on January 3, 2000.
Scheduled debt repayments for the five years ending December 31, 2004, on the long-term debt outstanding at December 31, 1999, amount to: $59,000,000 in 2000; $94,000,000 in 2001; $9,000,000 in 2002; $42,000,000 in 2003; $9,000,000 in 2004; and $464,000,000 thereafter. However, as part of the Tier II rate filing discussed in Note 4, "Deregulation and Regulatory Matters," we indicated our intention to retire approximately $266,000,000 of long-term debt. We estimate that the expenses associated with these retirements will be approximately $20,000,000. As discussed above, we have already repurchased $15,000,000 of our 7.875 percent Series B Unsecured MTNs due December 23, 2026. In addition, we repurchased $5,000,000 of 7.25 percent Secured MTNs due January 19, 2024, and $7,000,000 of 8.68 percent Unsecured Series A MTNs due February 7, 2022, in January of 2000. We plan to retire additional long-term debt throughout 2000.
NOTE 11 - SHORT-TERM BORROWING - ------------------------------
We have short-term borrowing facilities with commercial banks that provide both committed and uncommitted lines of credit and the ability to sell commercial paper. Bank borrowings either bear interest at the lender's floating base rate and may be repaid at any time, or have fixed rates of interest and maturities. Commercial paper has fixed rates of interest and maturities.
At December 31, 1999, we had lines of credit consisting of $210,000,000 committed and $95,000,000 uncommitted. Facility fees or commitment fees on the committed lines of credit are not significant. We have the ability to issue up to $145,000,000 of commercial paper based on the total of unused committed lines of credit and revolving credit agreements.
At December 31, 1999, we had no short-term obligations. At December 31, 1998, we had notes payable to banks for $40,000,000 at 5.87 percent interest and commercial paper issued for $29,820,000 at 6.04 percent interest.
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 plan's benefit 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 and accrued approximately $4,300,000 of expense in accordance with SFAS No. 88, "Employers' Accounting for Settlements and Curtailments of Defined Benefit Pension Plans."
As a result of the sale of our electric generating assets to PPL Montana, 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 to the PPL retirement plan trust. Pursuant to the Agreement, an estimated $3,100,000 of assets will be transferred to the PPL trust when the calculation is finalized in 2000. In accordance with SFAS No. 88, we calculated a curtailment gain of approximately $4,100,000 and a settlement gain of approximately $7,800,000. Due to regulatory accounting treatment, the gains were recorded as regulatory liabilities or offsets to regulatory assets, resulting in no income statement impact.
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 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."
- -------------------------------------------------------------------------------- Table 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 1999, 1998, and 1997: - -------------------------------------------------------------------------------- Pension Benefits --------------------------------- 1999 1998 1997 --------------------------------- (Thousands of Dollars) Service cost on benefits earned ............. $ 8,719 $ 8,079 $ 6,625 Interest cost on projected benefit obligation .............................. 19,540 18,238 16,316 Expected return on plan assets .............. (25,650) (22,870) (19,900) Amortization of: Transition obligation ................... 43 358 383 Prior service cost ...................... 1,741 1,468 965 Actuarial gains ......................... (1,658) (1,062) (1,474) Immediate recognition of DC conversion ...... -- (142) -- --------------------------------- Net periodic benefit cost ................... 2,735 4,069 2,915 Curtailment (gain) loss ..................... (3,751) 3,964 960 Settlement gain ............................. (7,844) -- -- --------------------------------- Net periodic benefit cost after curtailments and settlements ......................... $ (8,860) $ 8,033 $ 3,875 =================================
Other Benefits --------------------------------- 1999 1998 1997 --------------------------------- (Thousands of Dollars) Service cost on benefits earned ............. $ 844 $ 777 $ 571 Interest cost on projected benefit obligation 1,776 1,665 1,486 Expected return on plan assets .............. (722) (671) (459) Amortization of: Transition obligation ................... 1,098 1,120 1,100 Prior service cost ...................... 177 69 -- Actuarial gain .......................... (133) (274) (384) --------------------------------- Net periodic benefit cost ................... 3,040 2,686 2,314 Curtailment gain ............................ (374) -- -- --------------------------------- Net periodic benefit cost after curtailments $ 2,666 $ 2,686 $ 2,314 =================================
In 1999, funding for pension costs exceeded SFAS No. 87, "Employers Accounting for Pensions," pension expense by $1,631,000. In 1998 and 1997, pension costs exceeded SFAS No. 87 pension expense by $1,780,000 and $5,441,000, 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, 1999, the regulatory liability was $5,755,000.
- --------------------------------------------------------------------------------
The assumed 2000 health care cost trend rates used to measure the expected cost of benefits covered by the plans is 7.00 percent. The trend rate decreases through 2004 to 5 percent.
NOTE 13 - INFORMATION ON INDUSTRY SEGMENTS - ------------------------------------------
Our utility operations purchase, transmit, and distribute electricity and natural gas. With the sale of our electric generating assets other than Milltown Dam, we no longer are primarily engaged in regulated electric generation. In our nonutility businesses, our telecommunications operation designs, develops, constructs, operates, maintains, and manages a fiber-optic network and wireless facilities; it also sells long-distance, Internet, and private-line services and equipment. In other nonutility operations, we mine and sell coal and lignite; manage long-term power sales, and develop and invest in independent power projects and other energy-related businesses; and explore for, develop, produce, process, and sell oil and natural gas. We also trade crude oil, natural gas, and natural gas liquids.
In 1997, our coal operations recognized $104,231,000 in revenues from sales to Reliant Energy. This amount exceeded 10 percent of our 1997 consolidated revenues. The loss of these revenues would have a material adverse effect on our coal operations. In our independent power operations, the loss of revenues pursuant to contracts with two customers would have a material adverse effect on that segment.
The PSC approved our open-access and reorganization plan for our natural gas utility effective November 1, 1997. Under the approved plan, we transferred substantially all of our utility's natural gas production assets, including those of a Canadian subsidiary, to our nonutility oil and natural gas operations as of that date.
We consider segment information for foreign operations immaterial.
- -------------------------------------------------------------------------------- Table Information on industry segments - --------------------------------------------------------------------------------
OPERATIONS INFORMATION: UTILITY ----------------------- Electric Natural Gas ----------------------- Sales to unaffiliated customers .................... $456,933 $111,118 Earnings from unconsolidated investments ........... -- -- Intersegment revenues .............................. 13,616 629 Depreciation, depletion, and amortization .......... 53,574 9,279 Write-downs of long-lived assets ................... -- -- Pretax operating income (loss) ..................... 110,666 16,459 Interest expense ................................... 38,467 15,229 Interest revenue ................................... 3,801 545 Income tax expense ................................. 11,549 391 Capital expenditures ............................... 50,167 13,115 Identifiable assets ................................ 910,066 406,413
UTILITY ----------------------- Electric Natural Gas ----------------------- Sales to unaffiliated customers .................... $450,719 $107,052 Earnings from unconsolidated investments ........... -- -- Intersegment revenues .............................. 7,576 727 Depreciation, depletion, and amortization .......... 56,524 8,705 Pretax operating income (loss) ..................... 124,841 15,019 Interest expense ................................... 48,903 12,946 Interest revenue ................................... 3,521 925 Income tax expense ................................. 26,391 168 Capital expenditures ............................... 61,334 21,989 Identifiable assets ................................ 1,577,583 405,670
UTILITY ----------------------- Electric Natural Gas ----------------------- Sales to unaffiliated customers .................... $435,986 $122,355 Earnings from unconsolidated investments ........... -- -- Intersegment revenues .............................. 4,685 588 Depreciation, depletion, and amortization .......... 51,674 11,939 Pretax operating income (loss) ..................... 111,002 37,994 Interest expense ................................... 44,571 13,112 Interest revenue ................................... 5,626 2,174 Income tax expense ................................. 25,969 9,674 Capital expenditures ............................... 122,639 15,679 Identifiable assets ................................ 1,560,055 390,463
* The amounts indicated include certain eliminations among the business segments.
SUPPLEMENTARY DATA (Unaudited) - ------------------------------
OIL AND NATURAL GAS PRODUCING ACTIVITIES
OIL AND NATURAL GAS PRODUCING ACTIVITIES (Continued)
- --------------------------------------------------------------------------------
Our nonutility United States natural gas, natural gas liquids, and oil reserves increased in 1999 primarily due to successful drilling in Wyoming, Colorado, and Oklahoma. Substantially higher year-end prices, which improve production economics, also increased our United States reserves. In 1999, as in the prior year, our Canadian natural gas reserves increased due to successful development drilling in Southeast Alberta. Upward price revisions also increased our Canadian natural gas liquids and oil reserves. These Canadian increases were partially offset by downward revisions reflecting disappointing performance in the Caroline field.
Nonutility United States natural gas and natural gas liquids reserves increased in 1998 with the addition of undeveloped reserves in Colorado and successful drilling in Wyoming and Oklahoma. However, the additions were partially offset by downward price revisions of petroleum products. That downward price revision also caused a significant decrease in United States oil reserves. The Canadian natural gas reserves increased because of successful exploratory drilling in Southeast Alberta. Oil reserves in Canada decreased due to the sale of an Alberta producing property and downward price revisions. Canadian oil and natural gas reserves were also revised downward to reflect poorer-than-expected performance in two fields.
Nonutility United States natural gas and natural gas liquids reserves increased in 1997 because of the acquisition of reserves in place, successful drilling in Oklahoma and Wyoming, and the transfer of previously regulated Montana properties. Oil reserves decreased because of the sale of reserves in Kansas. The Canadian natural gas reserves increase is due to the purchase of reserves in place, and transfer of previously regulated Canadian properties to the nonutility Supply Division. Oil reserves in Canada also decreased because of the sale of some Alberta properties.
As determined by engineers, utility natural gas reserves were revised during 1997 due to changes in projected performance or changes in the Company's ownership interest in specific fields. On November 1, 1997, the PSC approved the deregulation of the utility's natural gas production properties, the result of which was the transfer of all of the Canadian and significantly all of the United States natural gas reserves to the nonutility operations. Since that date, utility natural gas reserves have been produced to maintain utility natural gas storage leases and to supply fuel for electric generation.
When the utility owned the reserves that were transferred to the nonutility on November 1, 1997, petroleum engineers estimated reserves on the basis of utility business guidelines; that is, mechanical recoverability at reasonable and prudent costs. With deregulation and transfer, petroleum engineers began to estimate reserves on the basis of mechanical recoverability under market price conditions. Estimating reserves on that basis has resulted in downward revisions of nonutility United States and Canadian natural gas reserves in 1997.
OIL AND NATURAL GAS PRODUCING ACTIVITIES (Continued)
The following table presents information for 1999, 1998, and 1997 on the capitalized costs relating to utility natural gas producing activities, costs incurred in utility natural gas property acquisition, exploration, and development activities and certain utility natural gas production costs reflected in results of operations. As a regulated public utility, we are authorized to earn a rate of return on our utility natural gas plant rate base. Our net cost of natural gas in underground storage is included in the natural gas plant, which is a part of the utility rate base. Due to the commingling of produced natural gas with purchased and royalty natural gas for sale to utility customers and application of the ratemaking process to the utility natural gas producing activities, we are unable to identify revenues resulting solely from utility natural gas producing activities. Accordingly, the information on revenues, income taxes, results of operations, and estimated future net cash flows and changes therein relating to proved utility natural gas reserves are not presented for our utility natural gas producing activities.
OIL AND NATURAL GAS PRODUCING ACTIVITIES (Continued)
The following table presents information for 1999, 1998, and 1997 on the capitalized costs relating to nonutility oil and natural gas producing activities, costs incurred in nonutility oil and natural gas property acquisition, exploration, and development activities and results of nonutility operations for oil and natural gas producing activities:
* United States excludes capitalized costs and associated accumulated depreciation, revenues, and expenses related to support equipment and facilities. The capitalized costs of support equipment and facilities were $73,127,000, $70,304,000, and $53,359,000 and the associated accumulated depreciation was $12,248,000, $8,939,000, and $5,288,000 for 1999, 1998, and 1997, respectively. - --------------------------------------------------------------------------------
Estimated future cash flows are computed by applying year-end prices and contract prices, when appropriate, of oil and natural gas to year-end quantities of proved reserves. Estimated future development and production costs are determined by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at the end of the year, based on year-end costs. Estimated future income tax expenses are calculated by applying year-end statutory tax rates to estimated future pretax net cash flows related to proved oil and natural gas reserves, less the tax basis of the properties involved. The future income tax expenses give effect to permanent differences, tax credits and deferred taxes relating to proved oil and natural gas reserves.
These estimates are furnished and calculated in accordance with requirements of the Financial Accounting Standards Board and the Securities and Exchange Commission (SEC). Management believes the usefulness of these projections is limited because of the unpredictable variances in expenses, capital forecasts, and crude oil and natural gas prices. Estimates of future net cash flows presented do not represent management's assessment of our future profitability or future cash flow. Management's investment and operating decisions are based upon reserve estimates that include proved reserves prescribed by the SEC as well as probable reserves, and upon different price and cost assumptions from those used here.
OIL AND NATURAL GAS PRODUCING ACTIVITIES (Continued)
- --------------------------------------------------------------------------------
Extensions, discoveries, and improved recovery, less related costs, represent the present value of current year reserve additions valued at year-end prices less actual unit production costs for the current year. For the years 1999 and 1998, the amount described as Other is primarily the result of changes in the timing of production.
QUARTERLY FINANCIAL DATA
ITEM 9.
ITEM 9. DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE - -----------------------------------------------------------------------------
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT - -----------------------------------------------------------
Information on The Montana Power Company Directors is incorporated by reference from the Company's Notice of 2000 Annual Meeting of Shareholders and Proxy Statement, pages 6 - 8.
- -------------------------------------------------------------------------------- Table The following table shows our current Executive Officers, who are elected or appointed annually by our Board of Directors, their ages at December 31, 1999, 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 55 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 57 Vice President, Chief Financial Officer. Mr. Pederson was elected to the Board of Directors in 1993. He has served as Vice President and Chief Financial Officer since 1991. He also served as Chief Information Officer from 1996 - 1999.
M. J. Meldahl 50 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 54 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.
R. F. Cromer 54 Executive Vice President and Chief Operating Officer, Energy Supply Division. Mr. Cromer has held his present position since 1996. He has served as Chief Executive Officer, Continental Energy Services, since 1998. He also served as President of Continental Energy Services from 1996 - 1998 and as President and Chief Operating Officer of Continental Energy Services from 1992 - 1996.
P. K. Merrell 47 Vice President, Human Resources, and Secretary. Ms. Merrell has held her present position since 1996. She served as Vice President and Secretary from 1993 - 1996.
M. E. Zimmerman 51 Vice President and General Counsel. Mr. Zimmerman has held his present position since 1991.
P. J. Cole 42 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 56 Controller. Mr. Smith has held his present position since 1996. He served as Controller for Entech from 1988 - 1996.
E. M. Senechal 50 Treasurer. Ms. Senechal has held her present position since 1996. She served as Vice President and Treasurer for Entech from 1984 - 1996.
- -------------------------------------------------------------------------------- Name Age Position/Business Experience - --------------------------------------------------------------------------------
D. A. Johnson 54 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 43 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 44 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.
W. S. Dee 59 Vice President, Marketing. Mr. Dee has held his present position since 1997. He was employed as a consultant with Leo Burnett Inc., an advertising agency, from 1993 - 1996. Mr. Dee will retire as our Vice President, Marketing, effective March 31, 2000.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION - -------------------------------
Incorporated by reference from Notice of 2000 Annual Meeting of Shareholders and Proxy Statement, pages 15 - 20.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT - -----------------------------------------------------------------------
Incorporated by reference from Notice of 2000 Annual Meeting of Shareholders and Proxy Statement, pages 9 - 11.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS - -------------------------------------------------------
None.
PART IV - -------
ITEM 14.
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 26, 1999 Item 5. Other Events. Discussion of Third Quarter Net Income.
Item 7. Exhibits. Consolidated Statements of Income for the Quarters Ended September 30, 1999 and 1998, Nine Months Ended September 30, 1999 and 1998, and for the Twelve Months Ended September 30, 1999 and 1998. Utility Operations Schedule of Revenues and Expenses for the Quarters Ended September 30, 1999 and 1998, Nine Months Ended September 30, 1999 and 1998, and for the Twelve Months Ended September 30, 1999 and 1998. Nonutility Operations Schedule of Revenues and Expenses for the Quarters Ended September 30, 1999 and 1998, Nine Months Ended September 30, 1999 and 1998, and for the Twelve Months Ended September 30, 1999 and 1998.
January 3, 2000 Item 2. Disposition of Assets. Sale of Generation Assets. Date of earliest event reported: December 17, 1999.
Item 7. Financial Statements and Exhibits. Unaudited Pro Forma Consolidated Statements of Income for the Twelve Months Ended December 31, 1998 and Nine Months Ended September 30, 1999. Unaudited Pro Forma Consolidated Balance Sheet at September 30, 1999.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (CONT.)
(c) Exhibits
Instruments defining the rights of holders of long-term debt which are not required to be filed with the SEC will be furnished to the SEC upon request.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (Cont.)
THE MONTANA POWER COMPANY AND SUBSIDIARIES SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
* 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, a duly authorized signatory.
THE MONTANA POWER COMPANY
By /s/ Robert P. Gannon ----------------------- Robert P. Gannon (Chairman of the Board)
Date: March 15, 2000
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 Principal Executive - -------------------------- Officer and Director March 15, 2000 Robert P. Gannon (Chief Executive Officer)
/s/ J. P. Pederson Principal Financial March 15, 2000 - -------------------------- and Accounting J. P. Pederson Officer and Director (Vice President and Chief Financial Officer)
/s/ Tucker Hart Adams Director March 15, 2000 - -------------------------- Tucker Hart Adams
/s/ Alan F. Cain Director March 15, 2000 - -------------------------- Alan F. Cain
/s/ John G. Connors Director March 15, 2000 - -------------------------- John G. Connors
/s/ R. D. Corette Director March 15, 2000 - -------------------------- R. D. Corette
/s/ Kay Foster Director March 15, 2000 - -------------------------- Kay Foster
/s/ John R. Jester Director March 15, 2000 - -------------------------- John R. Jester
/s/ Carl Lehrkind III Director March 15, 2000 - -------------------------- Carl Lehrkind III
/s/ Deborah D. McWhinney Director March 15, 2000 - -------------------------- Deborah D. McWhinney
/s/ N. E. Vosburg Director March 15, 2000 - -------------------------- N. E. Vosburg
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