SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One) |
/X/ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) |
For the fiscal year ended March 31, 2001
OR
/ / | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE |
For the Transition period from _________ to _________
Commission File Number 1-5152
PACIFICORP
(Exact name of registrant as specified in its charter)
State of Oregon | 93-0246090 |
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Registrant's telephone number, including area code: (503) 813-5000
Securities registered pursuant to section 12(b) of the Act:
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Securities registered pursuant to Section 12(g) of the Act:
Title of each Class
5% Preferred Stock (Cumulative; $100 Stated Value)
Serial Preferred Stock (Cumulative; $100 Stated Value)
No Par Serial Preferred Stock (Cumulative; Various Stated Values)
Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES X NO ___
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X]
On May 18, 2001, the aggregate market value of the shares of voting and nonvoting common equity of the Registrant held by nonaffiliates was $0.
As of May 18, 2001, there were 297,324,604 shares of common stock outstanding. (All common shares are indirectly owned by Scottish Power plc, 1 Atlantic Quay, Glasgow, G2 8SP, Scotland.)
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Transition Report on Form 10-QT of the Registrant for the quarter ended March 31, 1999 are incorporated by reference in Part II.
TABLE OF CONTENTS
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DEFINITIONS
When the following terms are used in the text they will have the meanings indicated:
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PART I
THE ORGANIZATION
The Company is an electricity company in the United States. The Company conducts its retail electric utility business as Pacific Power and Utah Power, and engages in power production and sales on a wholesale basis under the name PacifiCorp. Holdings owns the stock of subsidiaries conducting businesses not regulated as domestic electric utilities.
The Company's strategic business plan is to focus on its energy businesses in the western United States. As part of its strategic business plan, the Company has sold most of its other United States and international businesses, and has previously terminated all of its business development activities outside of the United States. On September 6, 2000, the Company completed the sale of its indirect ownership of Powercor. On November 17, 2000, the Company completed the sale of its 19.9% indirect interest in Hazelwood. Holdings continues to liquidate portions of the loan and leasing portfolio of PFS. PFS presently expects to retain only its tax-advantaged investments in leveraged lease assets and some immaterial notes receivable, and to limit its pursuit of new tax-advantaged investment opportunities. See "AUSTRALIAN ELECTRIC OPERATIONS" and "OTHER OPERATIONS."
On November 29, 1999, the Company and ScottishPower completed a merger under which the Company became an indirect subsidiary of ScottishPower (the "Merger"). The Company continues to operate under its current name, and its headquarters remains in Portland, Oregon. As a result of the Merger, the Company became part of a public utility holding company group. The Company's operations are now subject to the requirements and restrictions of the Public Utility Holding Company Act of 1935.
The Company's year end is March 31. The years ended March 31, 2001 and 2000 and quarterly periods within those years are referred to as 2001 and 2000, respectively. References to future years are to years ending March 31. The year ended December 31, 1998 is referred to as 1998. Australian electric operations' year end remained December 31. Consequently, the Company's statements of consolidated income and consolidated cash flows as of and for the year ended March 31, 2001 include Australian electric operations' financial statements for the period from January 1, 2000 to the dates of sale.
As a result of the Merger, the Company developed and commenced a transition plan (the "Transition Plan") to implement significant organizational and operational changes. See Note 2 of Notes to the Consolidated Financial Statements under ITEM 8.
From time to time, the Company may issue forward-looking statements under the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 that involve a number of risks and uncertainties. Although the Company believes the expectations reflected in such forward-looking statements are
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based on reasonable assumptions, it can give no assurance that its expectations will be realized. Forward-looking statements involve known and unknown risks, which may cause the Company's actual results to differ materially from those expected. The following factors are among the factors that could cause actual results to differ materially from the forward-looking statements: utility commission practices; political developments; regional, national and international economic conditions; weather and behavioral variations affecting customer usage; competition and supply in bulk power and natural gas markets; hydroelectric and natural gas production; coal quality and prices; unscheduled generation outages; disruption or constraints to transmission facilities; hydro-facility relicensing; energy purchase and sales activities; environmental, regulatory and tax legislation, including industry restructure and deregulation initiatives; nonperformance by counterparties; technological developments in the electricity industry; and the cost and availability of debt and equity capital. Any forward-looking statements issued by the Company should be considered in light of these factors.
The Company's 8 1/4% Cumulative Quarterly Income Preferred Securities (Series A Preferred Securities) of PacifiCorp Capital I, a wholly-owned subsidiary trust, and the 7.70% Trust Preferred Securities (Series B Preferred Securities) of PacifiCorp Capital II, a wholly-owned subsidiary trust, are traded on the New York Stock Exchange.
DOMESTIC ELECTRIC OPERATIONS
The Company conducts its domestic retail electric utility operations as Pacific Power and Utah Power, and engages in wholesale electric transactions under the name PacifiCorp. Pacific Power and Utah Power provide electric service within their respective service territories. Power production, wholesale sales, fuel supply and administrative functions are managed on a coordinated basis.
The Company has been experiencing the adverse effect of unusually high market prices due to inadequate generating capacity in the Western System Coordinating Council (the "WSCC"). The balance of energy supply and demand has tightened considerably in the year due to generation facility outages in the WSCC, including the unscheduled outage of the Company's 430 megawatt ("MW") Hunter unit on November 24, 2000, lower hydro availability, higher natural gas prices and growth in demand throughout the WSCC due in large part to economic growth. Prices paid by the Company to provide certain load balancing resources to supply its load have exceeded the amounts it received through retail rates and wholesale prices. In November 2000, the Company filed applications seeking deferred accounting treatment for future net power costs varying from costs included in determining retail rates in the states of Utah, Idaho, Wyoming and Oregon as more fully described in "Regulation - Deferred Power Cost Filings." The Company has received approval of deferred accounting treatment covering a portion of the power cost variances from these states that will help mitigate some of the adverse effect of higher market prices, assuming that recovery mechanisms are implemented as anticipated. The Company has also requested recovery in Utah, Oregon, Wyoming and California of increasing costs.
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During the third quarter of 2001 and continuing into the fourth quarter of 2001, the demand for electric energy in the western United States exceeded the available generation resources. As a result, supply shortages occurred, particularly affecting electricity availability in California. None of the Company's service territory has experienced such severe supply shortages, however, resources and demand in the region are in a tightly balanced condition. A substantial portion of the power provided to the California market from the Pacific Northwest has come from hydroelectric generation facilities. Those resources are now reduced due to the low snow pack and precipitation, resulting in low stream flow being experienced over the past six months. The outlook for improvement in the availability of electricity supply for the next year is poor in part due to the continuation of high demand, low hydro resource availability in the water year ending September 2001, demands on hydro resources for irrigation and migrating fish protection and lead time needed to place new generation facilities into production. The Company is accelerating its efforts to bring new generation on line.
Public utilities in the western United States, including the Company, and governors in the western states have been promoting conservation as a method to ease the current and potential future energy shortage. Voluntary action by retail customers has been requested. Actions have been initiated to pay industrial and commercial electricity users to forgo power consumption by shutting down their operations so that power can be diverted to other uses and residential customers. The Company has participated in such power consumption management through its Demand Side Management program. These actions, along with increasing prices paid by customers for power, may reduce the rate of electricity consumption.
As a result of purchasing electricity to cover load at prices higher than could be recovered in retail rates and wholesale prices, coupled with the California power market structuring, two of California's largest investor-owned utilities, Southern California Edison Co. ("SCE") and Pacific Gas and Electric Co. ("PG&E") issued warnings in the latter half of 2001 of their impending inability to meet payment commitments. In the fourth quarter of 2001, SCE and PG&E defaulted on payments owed to various creditors. In April 2001, PG&E filed for Chapter 11 reorganization. These defaults have resulted in the subsequent defaults by the California Power Exchange (the "CPX"), the California Independent Systems Operator (the "Cal ISO") and the Automated Power Exchange. While the Company's exposure to loss as a direct result of these defaults is low, the exposure that the Company has to other entities that have been counterparties in energy transactions with these California entities could be significant depending on the level of purchases and sales that existed and continues with these defaulting entities. This activity in the western electricity market has also had a negative impact on the willingness of the financial markets to provide financing on conditions and at rates that have historically been available to the Company. See "ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - BUSINESS RISK."
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The Company's operations are exposed to risks, including legislative and governmental regulations, the price and supply of purchased power, fuel and natural gas, recovery of purchased power costs and purchased natural gas costs, weather conditions, availability of generation facilities, competition, technology and availability of funding. In addition, the energy business exposes the Company to the financial, liquidity, credit and commodity price risks associated with wholesale sales and purchases. See "ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - BUSINESS RISK."
The region's turbulence and the financial troubles of the California energy market are drawing attention from various state and federal regulatory and political authorities. Numerous changes to the current operating structure have been proposed to address the region's issues. To date, no changes have been implemented that materially affect the Company's operations; however, the situation may change in the future.
Service Area
The Company serves approximately 1.5 million retail customers in service territories aggregating about 135,800 square miles in portions of six western states: Utah, Oregon, Wyoming, Washington, Idaho, and California. The service area's diverse regional economies range from rural, agricultural and mining areas to urbanized manufacturing and government service centers. No one segment of the economy dominates, which mitigates exposure to economic swings. In the eastern portion of the service area, Wyoming and eastern Utah, the main industrial activities are mining and extracting coal, oil, natural gas, uranium, and oil shale. In the western part of the service territory, mainly consisting of Oregon and southeastern Washington, the economy generally revolves around agriculture and manufacturing, with pulp and paper, lumber and wood products, food processing, high technology, and primary metals being the largest industrial sectors.
The Company is currently seeking to exit operations in California. See "Proposed Asset Dispositions."
The geographical distribution of the Company's retail electric operating revenues for the year ended March 31, 2001 was Utah, 38%; Oregon, 33%; Wyoming, 13%; Washington, 8%; Idaho, 6%; and California, 2%.
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Customers
Electric utility revenues and energy sales, by class of customer, for the years ended March 31, 2001 and 2000, the three months ended March 31, 1999, and the year ended December 31, 1998, were as follows:
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As a result of the geographically diversified area of operations, the Company's service territory has historically had complementary seasonal load patterns. In the western sector, customer demand peaks in the winter months due to space heating requirements. In the eastern sector, customer demand peaks in the summer when irrigation and cooling systems are heavily used. Many factors affect per customer consumption of electricity. For residential customers, within a given year, weather conditions are the dominant cause of usage variations from normal seasonal patterns. However, the price of electricity is also considered a significant factor. In response to recent region-wide electricity supply shortages, the Company is actively promoting electricity conservation programs, which may cause usage variations. See "Regulation" for additional information.
During 2001, no single retail customer accounted for more than 2% of the Company's retail utility revenues and the 20 largest retail customers accounted for 15% of total retail electric revenues.
Competition
In many cases, customers have the option to switch energy sources for heating and air conditioning. In addition, certain of the Company's industrial customers are seeking choice of suppliers, options to build their own generation or cogeneration, or the use of alternative energy sources such as natural gas. When a competitive marketplace exists, customers will make their energy purchasing decision based upon many factors, including price, service and system reliability.
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During 2001, the Company continued to operate its electricity distribution and retail sales business as a regulated monopoly throughout most of its franchise service territories. However, the Company anticipates increasing competition, principally as a result of industry restructuring, deregulation and increased marketing by alternative energy suppliers.
Beginning in April 1998, California retail electric energy sales have been subject to open market competition. The Company's generation in California, which represents 1% of total nameplate rating, is currently regulated, but, under present legislation, energy supply will not be state regulated beginning April 2002. The Company has not determined what effects, if any, this will have on the financial reporting and results of its generation business. Deregulation in Oregon has been moving forward, but caution is being taken to avoid the problems that have been encountered in California. It is expected that regulators will act prudently to protect the state's utilities from potential hazards of deregulation. Four other states, Utah, Wyoming, Washington and Idaho, have been slow in deregulating their electric markets. See "Regulation." The Company supports increased customer choice under terms and conditions that are equitable to all stakeholders.
The Energy Policy Act, passed in 1992, opened wholesale competition to energy brokers, independent power producers and power marketers. In 1996, the FERC ordered all investor-owned utilities to allow others access to their transmission systems for wholesale power sales ("open access"). This access must be provided at the same price and terms the utilities would apply to their own wholesale customers. The Company is working with eight other utilities, including the federal Bonneville Power Administration ("BPA"), to form a regional transmission organization. See "Regulation - Regional Transmission Organization ("RTO")." Competition is also influenced by availability and price of alternate energy sources and the general demand for electrical power.
The Company has formulated strategies to meet these challenges. The Company is marketing power supply services to other utilities in the western United States, including dispatch assistance, daily system load monitoring, backup power, power storage and power marketing, and services to retail customers that encourage efficient use of energy. Effective January 1, 1998, the California Public Utilities Commission (the "CPUC") adopted rules regulating the nontariffed sale of energy and energy products and services by utilities and their affiliates. The rules also mandated a 10% rate reduction in tariffed electricity prices in California, which resulted in a $3.5 million annual reduction in the Company's revenues. The Company has decided to refrain from marketing nontariffed energy products and services to retail customers in California, but intends to continue limited purchases and sales in the wholesale business, selling to utilities in California and marketers elsewhere in the western United States. See "ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - BUSINESS RISK."
The Company believes that the regulatory initiatives that are underway in each of the states it services may eventually bring competition for electricity generation services. This change in the regulatory structure may significantly affect the Company's future financial position, results of operations and cash
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flows. The Company intends to seek regular price increases to the extent it underearns its allowed rate of return. This intention, consistent with the strategic direction implemented in 1998, provides a continued foundation for use of Statement of Financial Accounting Standards ("SFAS") No. 71 in its financial statements. The Company currently has outstanding rate increase requests before the state commissions in California, Oregon, Utah, and Wyoming. See "Regulation."
Power and Fuel Supply
The supply of power has not kept pace with the growing demand in the western United States and the Company is experiencing the effect of high market prices associated with this shortage. Prices paid by the Company to provide certain load balancing resources to supply its load may continue to exceed the amounts it receives through retail rates and wholesale prices.
The Company owns or has interests in generating plants with an aggregate nameplate rating of 8,280 MW and plant net capability of 7,832 MW. See "ITEM 2. PROPERTIES." With its present generating facilities, under average water conditions, the Company would expect that approximately 5% of its energy requirements for 2002 would be supplied by its hydroelectric plants and 67% by its thermal plants. The balance of 28% would be obtained under long-term purchase contracts, and interchange and other purchase arrangements. The Pacific Northwest is experiencing a period of decreased rainfall, which has resulted in less favorable hydroelectric generation. These conditions may cause the hydroelectric expectations not to be met, as the needs of fish migration and irrigation could utilize water that otherwise would be used to produce electricity. During 2001, approximately 4% and 60% of the Company's energy requirements were supplied by its hydroelectric and thermal generation plants, respectively, and the remaining 36% by purchased power. Thermal generation's contribution to energy requirements was reduced by the sale of the Centralia plant in May of 2000 and the Hunter unit outage. This outage occurred on November 24, 2000 and continued until May 2001.
The Company's generating facilities are interconnected through its own transmission lines or by contract through the lines of others. Substantially all generating facilities and reservoirs located within the western states are managed on a coordinated basis to obtain maximum load carrying capability and efficiency.
As of March 31, 2001, the Company had 229 million tons of recoverable coal reserves that are mined by the Company or its affiliates. The coal from these reserves is dedicated to Company generation plants that are near the mines. During 2001, these mines supplied approximately one half of the Company's total coal requirements. Coal is also acquired through long-term and short-term contracts.
The Company has entered into long-term and short-term natural gas contracts to supply its generation plants that use natural gas with the fuel needed for operations. See "ITEM 2. PROPERTIES" for information regarding generating plant energy sources.
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Wholesale Sales and Purchased Power
Wholesale sales of power contribute significantly to total revenues even though the Company has scaled back wholesale sales from 1998 levels. The Company's wholesale sales complement its retail business and enhance the efficient use of its generating capacity over the long term.
The Company's transmission system connects with other utilities in the Pacific Northwest having low-cost hydroelectric generation and with utilities in California and the southwestern United States having higher-cost, fossil-fuel generation. The transmission system is available for common use consistent with open access regulatory requirements. If the Company is in a surplus power position, the Company is able to sell excess generation into the wholesale market.
Historically, during the winter, the Company was able to purchase power from utilities in the southwestern United States, either for its own peak requirements or for resale to other regional utilities. During the summer, the Company was historically able to sell excess power to utilities in the southwestern United States to assist them in meeting their peak requirements.
In addition to its base of thermal and hydroelectric generation assets, the Company utilizes a mix of long-term and short-term firm power purchases and nonfirm purchases to meet its load obligations and to make sales to other utilities. Many of the Company's purchased power contracts have fixed price components, which provide some protection against the current price volatility. See Note 14 of Notes to the Consolidated Financial Statements under Item 8 for further information on long-term wholesale sales and purchased power contracts.
The Company currently purchases 925 MW of firm capacity annually from the BPA pursuant to a long-term agreement. The purchase amount declines annually to 750 MW in July 2003 and again to 575 MW in July 2004 through August 2011. The Company's annual payment under this agreement for the period ended March 31, 2001 was $65 million. The price for this capacity is a per MW charge, therefore, the costs associated with this agreement will decline as the MW purchase declines. The price is adjusted by the rate of change in the BPA's Average System Cost. The next scheduled price change will be October 1, 2001. The Company expects a slight decline in price.
Under the requirements of the Public Utility Regulatory Policies Act of 1978, the Company purchases the output of qualifying facilities constructed and operated by entities that are not public utilities. During 2001, the Company purchased an average of 109 MW from qualifying facilities, compared to an average of 112 MW in 2000. Long-term firm power purchases supplied 13% of the Company's total energy requirements in 2001. Short-term firm and nonfirm power purchases supplied 23% of the Company's total energy requirements in 2001. See Note 14 of Notes to the Consolidated Financial Statements under ITEM 8 for further discussion on the Company's commitments and contingencies.
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Proposed Asset Dispositions
In July 1998, the Company announced its intention to sell its California electric distribution assets. This action was in response to the continued decline in earnings on the assets and the changes in the legislative and regulatory environments in California. The Company had an agreement with Nor-Cal Electric Authority ("Nor-Cal") for the sale of the Company's California electric distribution assets for $178 million. On December 21, 2000, the CPUC approved an Administrative Law Judge's decision to dismiss the application for approval of the sale. The Company is currently in discussion with Nor-Cal to evaluate its options with respect to this sale.
Projected Demand
The Company continues to experience economic growth in several portions of its service territory and retail energy sales for the Company have grown at a compound annual rate of 2.1% since 1995. This increase in demand is happening throughout the WSCC, due in large part to economic growth. Future increases in demand are dependent upon several factors, including the impact of Demand Side Management programs and higher prices. The Company plans for resources to meet its current and expected retail and wholesale load obligations. Resource availability, price volatility and load volatility may materially impact power costs to the Company. The Company is pursuing price increases in jurisdictions where it does not earn an appropriate rate of return and will seek operating efficiencies as outlined in the Transition Plan. For more information, see Note 2 of Notes to the Consolidated Financial Statements under ITEM 8.
For the periods 2002 to 2005, the average annual growth in retail MWh sales in the Company's franchise service territories is estimated to be about 1.7%, excluding the potential effects of decreased demand resulting from conservation efforts and higher prices. Because of price increases throughout the region, the Company anticipates that demand growth will slow or may even reverse. During this period, the Company may lose retail energy sales to other suppliers in connection with deregulation of the electric industry. As the electric industry evolves toward deregulation, the Company expects to have opportunities to sell any excess power in wholesale markets. The Company's actual results will be determined by a variety of factors, including the outcome of deregulation in the electric industry, economic and demographic growth, and competition.
Environmental Issues
Federal, state and local authorities regulate many of the Company's activities pursuant to laws designed to restore, protect and enhance the quality of the environment. These laws have increased the cost of providing electric service. The Company is unable to predict what material impact, if any, future changes in environmental laws and regulations may have on the Company's consolidated financial position, results of operations, cash flows, liquidity, and capital expenditure requirements.
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All of the Company's mining operations are subject to reclamation and closure requirements. The Company monitors these requirements and annually revises its cost estimates to meet existing legal and regulatory requirements of the various jurisdictions in which it operates. Compliance with future requirements could result in higher expenditures for both capital improvements and operating costs.
Air Quality. The Company's fossil fuel-fired electricity generation plants are subject to regulation under federal, state and local requirements. Emission controls, low sulfur coal, environmentally conscious plant operating practices and continuous emissions monitoring are all utilized to enable coal-burning plants to comply with emission limits, opacity limits, visibility and other air quality requirements. The United States Environmental Protection Agency (the "EPA") has implemented new regulations addressing regional haze. Carbon dioxide emissions are the subject of growing world-wide discussion and action in the context of global warming, but such emissions are not currently regulated. The Company's coal-burning plants, along with all other major coal-burning plants in the United States, participated in an effort to gather additional information about mercury emissions pursuant to a request issued by the EPA. Based in part on this effort, the EPA has indicated that controls to regulate mercury emissions from coal-burning plants will be brought forward by 2003.
The Company has received Title V Air Operating Permits for all of its coal and natural gas-fired power plants. In response to a 1998 citizens group challenge of the operating permits for the Company's Naughton and Jim Bridger power plants, the EPA ordered the state of Wyoming to reissue those permits with new continuous opacity monitoring requirements in place. The plants are currently working with the state of Wyoming to determine what, if any, new requirements should be imposed.
In 1999, the EPA commenced enforcement actions alleging violations of New Source Review requirements by the owners of certain coal-fired generating plants in the eastern and mid-western United States. The Company is not part of that action. However, in December 2000, the EPA notified the Company that it is investigating similar issues at four of the Company's coal plants. The Company is cooperating with that investigation by gathering and providing requested information to the EPA.
Electromagnetic Fields. A number of studies continue to examine the possibility of adverse health effects from electromagnetic fields ("EMF"), without conclusive results. Certain states and cities have enacted regulations to limit the strength of magnetic fields at the edge of transmission line rights-of-way. Other than in California, none of the state agencies with jurisdiction over the Company's operations have adopted formal rules or programs with respect to magnetic fields or magnetic field considerations in the siting of electric facilities. The CPUC has issued an interim order requiring utilities to implement no-cost or low-cost mitigation steps in the design of new facilities. It is uncertain whether the Company's operations may be adversely affected in other ways as a result of EMF concerns.
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Endangered Species. Protection of the habitat of endangered and threatened species makes it difficult and more costly to perform some of the core activities of the Company, including the siting, construction and operation of new and existing transmission and distribution facilities, as well as generation plants. In addition, endangered species issues impact the relicensing of existing hydroelectric generating projects, generally raising the price the Company must pay to purchase wholesale power from hydroelectric facilities owned by others, reducing output and increasing the costs of operating the Company's own hydroelectric resources. These actions could also result in further restrictions on timber harvesting and reduce electricity sales to Domestic electric operations' customers in the wood products industry.
Environmental Cleanups. Under the Federal Comprehensive Environmental Response, Compensation and Liability Act and similar state statutes, entities that disposed of or arranged for the disposal of hazardous substances may be liable for cleanup of the contaminated property. In addition, the current or former owners or operators of affected sites also may be liable. The Company has been identified as a potentially responsible party in connection with a number of cleanup sites because of current or past ownership or operation of the property or because the Company sent hazardous waste or other hazardous substances to the property in the past. The Company has completed several cleanup actions and is actively participating in investigations and remedial actions at other sites. The costs associated with those actions are not expected to be material to the Company's consolidated financial position, results of operations, cash flows, liquidity, or capital expenditure requirements.
Water Quality. The Federal Clean Water Act and individual state clean water regulations require a permit for the discharge of waste water, including storm water runoff from the power plants and coal storage areas, into surface waters. Also, permits may be required in some cases for discharges into ground waters. The Company believes that it currently has all required permits and management systems in place to assure compliance with permit requirements.
Regulation
The Company is subject to the jurisdiction of public utility regulatory authorities of each of the states in which it conducts retail electric operations as to prices, services, accounting, issuance of securities and other matters. Commissioners are appointed by the individual state's governor for varying terms. The Company is a "licensee" and a "public utility" as those terms are used in the Federal Power Act (the "FPA") and is, therefore, subject to regulation by the FERC as to accounting policies and practices, certain prices and other matters. Most of the Company's hydroelectric plants are licensed as major projects under the FPA and certain of these projects are licensed under the Oregon Hydroelectric Act. As a result of the Merger, the Company is also subject to the requirements and restrictions of the Public Utility Holding Company Act of 1935.
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The Company's hydroelectric portfolio consists of 53 plants that include 87 generating units with a total capacity of approximately 1,100 MW. Ninety-seven percent of the installed capacity is regulated by the FERC through 20 individual licenses. These projects account for about 14 percent of the Company's total generating capacity and provide operational benefits such as peaking capacity, generation, spinning reserves and voltage control.
Nearly all of the Company's hydroelectric projects are in some stage of relicensing under the FPA. The relicensing process is an extremely political and public regulatory process that involves controversial resource issues. In the new licenses, the FERC is expected to impose conditions designed to address the impact of the projects on fish and other environmental concerns. In addition, under the FPA and other laws, the state and federal agencies and tribes have mandatory conditioning authorities that give them significant influence and control in the relicensing process. It is extremely difficult to determine the economic impact of these mandates, but capital expenditures and operating costs are expected to increase in future periods while generation losses may result due to environmental and fish concerns. As a result of these issues, the Company has analyzed the costs and benefits of relicensing the Condit dam and has agreed to remove the Condit dam at a cost of approximately $16 million.
During 1998, the Company filed new depreciation rates with the respective regulatory commissions in the states of Oregon, Utah and Wyoming based upon a depreciation study. New depreciation rates were filed in Washington as part of a general rate case filing and subsequently approved by the Washington Utilities and Transportation Commission (the "WUTC") in an order dated August 9, 2000. New depreciation rates were approved by the Utah Public Service Commission (the "UPSC") in an order dated January 6, 2000, the Oregon Public Utility Commission (the "OPUC") in an order dated May 31, 2000 and the Wyoming Public Service Commission (the "WPSC") in an order dated July 28, 2000. The impact of the proposed changes in depreciation is being incorporated into the current general rate cases in Utah, Oregon and Wyoming. Based on the depreciation rates that have been approved, annual depreciation expense would be increased by approximately $20 million. The increase in depreciation expense is primarily due to revisions of the estimated costs of removal for steam production and distribution plants. For the period April 1, 2000 to March 31, 2002, the Utah and Wyoming commissions have ordered a reversal of a portion of previously accrued depreciation. These reversals in total, for both states, will amount to approximately $14 million per year for two years.
Between February 10 and April 6, 2000, the Company received approval orders from all states in which the Company operates for the sale of the Company's interests in the Centralia plant and mine. FERC approved the sale on January 13, 2000 and the sale was completed on May 4, 2000.
The Company filed requests with the commissions in the states it serves to grant deferred accounting treatment for the effects of SFAS No. 133 on the financial statements of the Company. The estimated effect of adopting SFAS No. 133 on April 1, 2001 assumes that the Company will receive regulatory orders directing the deferral, as a regulatory asset or liability, of the effects of
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fair valuing long-term contracts that are included in the Company's rates. The income statement impact of SFAS No. 133 would be partially offset, on an ongoing basis, by the change in the regulatory asset or liability allowed under the deferred accounting order.
On February 7, 2001, the Company filed applications with the UPSC, the WPSC, the Idaho Public Utilities Commission (the "IPUC") and the OPUC requesting accounting orders to defer $27 million in unrecovered costs associated with its Trail Mountain coal mine. The Company ceased operations at the mine on March 7, 2001. The mine is located in Central Utah and supplied fuel to the Hunter Plant. In April 2001, the IPUC and the WPSC approved deferred accounting treatment of their portions of costs associated with the Trail Mountain coal mine closure.
On October 30, 2000, the Company and BPA executed a 10-year settlement agreement that replaced the Residential Exchange Program. This settlement will be effective October 1, 2001 and is expected to provide the Company's residential and irrigation customers in Oregon, Washington and Idaho with benefits equaling $76 million per year during the first five years of the agreement. These benefits pass through to customers and do not impact the Company's earnings.
Merger Credits:
As a result of the Merger, the Company is required to provide benefits to rate payers through fixed reductions in rates or "Merger Credits." The Company's total obligation for merger credits is $133.4 million through the period ending December 31, 2004. A portion of this amount must be provided without offset or reduction of any kind and, accordingly, the Company recorded $57.2 million as a liability and current expense in its financial statements for the year ended March 31, 2000. In the second quarter of 2001, the Company recorded $12 million as a liability and current expense in relation to the August 9, 2000 order from the WUTC, which impacted the Company's ability to offset merger credits in the future. See Note 2 of Notes to the Consolidated Financial Statements under ITEM 8. The remaining $64.2 million obligation of the Company with respect to merger credits is subject to possible offset if the Company demonstrates in a future rate case, to the satisfaction of the respective commissions, that merger-related cost reductions have occurred and are being reflected in rates. This $64.2 million obligation will be reflected in future periods.
Rate Increases Granted:
On October 25, 2000, the WUTC approved the Company's application for a system benefits charge to recover costs associated with funding energy efficiency programs. The Company will collect approximately $2.8 million per year through December 31, 2002.
On September 27, 2000, the Company received an order from the OPUC authorizing increased prices in Oregon for residential customers of 2.33%, commercial and small industrial customers of 1.37%, large industrial customers of 0.4%, and public street lighting customers of 1.27%. These price increases are expected to result in annual revenues of $14 million. The order was effective on October 1, 2000.
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On August 9, 2000, the Company received an order from the WUTC that authorized the Company to increase rates by 3% on September 1, 2000, 3% on January 1, 2002 and 1% on January 1, 2003.
On June 20, 2000, the Company received approval from the OPUC for an overall price increase of 1.8%, or $13.7 million, through an annual adjustment as part of the alternative form of regulation ("AFOR") process previously authorized in Oregon. Of this amount, approximately $10 million is offset by costs mandated by regulators. The increase will cause rates for residential customers to rise by 2.9%, for large industrial users by 1.1%, and for commercial customers by 0.5%. The new rates took effect July 1, 2000 and are expected to increase annual revenues by approximately $3.7 million net of costs mandated by the OPUC. The AFOR is authorized to run through June 30, 2001. Existing rates in Oregon will continue unchanged after the AFOR's termination until new rates are authorized by the OPUC.
On May 25, 2000, the Company received an order from the WPSC authorizing an increase in prices, which is expected to result in increased annual revenues of $11 million. The Company received authorization for an additional $1 million increase effective July 19, 2000.
On May 24, 2000, the Company received an order from the UPSC authorizing increased prices in Utah for residential, irrigation, small commercial and lighting customers of 4.24% and large commercial and industrial customers of less than 1%. These price increases are expected to result in additional annual revenues of $17 million. The order was effective on May 25, 2000 and allowed recovery of early retirement and pension costs, reclamation costs, and Year 2000 and other information systems costs that had previously been written off. As a result, $17 million in regulatory assets was established in the first quarter of 2001 relating to cost recoveries which required no additional review and $25 million in regulatory assets was established in the second quarter of 2001 relating to cost recoveries which successfully passed additional review. An additional $7 million may be recovered in future periods following further review.
Rate Increases Submitted for Regulatory Approval:
On March 16, 2001, the Company filed a request with the CPUC for an increase in electricity prices for its customers in California. If approved by the CPUC, the request would increase prices about 13.77% overall, or $7.4 million. Hearings are scheduled for the week of August 20, 2001.
On December 18, 2000, the Company filed a request with the WPSC for an increase in electricity prices for its customers in Wyoming. If approved by the WPSC, the request would increase prices about 3.4% overall, or $9 million. The rate resulted from an agreement with the Wyoming Consumer Advocate Staff, in which the Company agreed to limit this request to $8 million plus the effect of any revisions to the Company's depreciation rates that were approved as part of a previous filing with the WPSC. The agreement also called for any rate increase to be effective no sooner than 12 months after the date of the order of the previous case, which was May 25, 2000.
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On January 12, 2001, the Company filed a request with the UPSC for an increase in electricity prices for its customers in Utah. This request encompassed normalized power costs that vary from the level assumed in Utah rates based on the twelve months ended September 30, 2000 test year and did not include those power cost variances associated with the Hunter outage as discussed below under "Deferred Power Cost Filings." If approved, the request would increase prices by approximately 19.1% overall, or $142 million. Concurrently, the Company filed a separate emergency petition for interim relief asking that the increase become effective January 22, 2001. On February 2, 2001, the Commission granted an interim rate increase of $70 million, effective February 2, 2001, subject to refund if the final rate order does not provide for at least this level of recovery.
On November 1, 2000, the Company filed the unbundling information required under Oregon Senate Bill 1149 ("SB 1149") rules and requested a related $160 million in increased revenues. On January 24, 2001, the OPUC staff filed a settlement proposal recommending an $18.5 million rate increase. This was later revised on February 6, 2001 to reflect a $28.9 million increase. On March 8, 2001, the Company and OPUC staff signed a partial stipulation that settled the majority of issues raised by OPUC staff and reduced the Company's requested increase by $19.5 million. On March 12, 2001, staff and intervenors filed their direct case in the docket. See "Deregulation."
Deferred Power Cost Filings:
On November 1, 2000, the Company filed applications seeking deferred accounting treatment for net power costs that vary from costs included in determining retail rates in the states of Utah, Idaho, Wyoming, and Oregon. The applications sought to defer these power cost variances beginning November 1, 2000.
Subsequent to the November 1, 2000 filings, the Company's Hunter power plant in Utah experienced a failure of a 430 MW generation unit. Since the commencement of the outage, the cost of power purchases to replace the output of the Hunter unit has exceeded that unit's costs included in current rates.
The Utah deferred accounting filing originally encompassed all power costs that vary from the level assumed in Utah rates since November 1, 2000. In light of the Company's January 12, 2001 Utah rate increase request, which included recovery of the power cost variances not related to the Hunter outage, the Utah deferred accounting filing was effectively amended by stipulation to include only the cost variances associated with the Hunter outage. Hunter deferred accounting was adopted by the Commission effective November 24, 2000, the date the outage began. During 2001, the Company has deferred $79 million relating to the Utah approval of the power cost variances related to Hunter.
The Oregon deferred accounting filing encompassed all power costs that vary from the level in Oregon rates since November 1, 2000, including costs to replace lost generation resulting from the Hunter outage. On January 18, 2001, the Company requested a 3%, or $23 million, rate increase effective February 1, which would provide partial recovery of post-October 31, 2000 power cost variances attributable to Oregon over an amortization period. This
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3% rate increase is the maximum allowed for deferred costs under the Oregon statutes. On January 23, 2001, the OPUC authorized deferred accounting for power costs of $23 million. The Company has deferred the $23 million as of March 31, 2001. On February 20, 2001, the OPUC authorized the 3% rate increase effective February 21, 2001. On May 11, 2001, the OPUC ordered a continuation of the deferral of a portion of net power costs varying from the level in Oregon rates. Costs subject to deferral are those that exceed a stipulated deadband. Outside the deadband, a portion of these costs are deferred based on stipulated ratios. The OPUC also ordered the Company to work with the commission staff and intervenors to develop a baseline around which the deadband mechanism will operate. Power costs for Oregon operations that vary from amounts in rates are being recognized in the Company's income statement pending resolution of this new deferral mechanism.
On February 12, 2001, the IPUC approved the Company's deferred accounting filing for all power costs that vary from the level assumed in Idaho rates for the period November 1, 2000 through October 31, 2001, including costs to replace lost generation resulting from the Hunter unit outage. The Company has deferred $11 million related to this approval as of March 31, 2001.
Approval for deferral of power costs that vary from rate assumptions was received from the WPSC on November 30, 2000. The Company is currently working with the WPSC to develop a power cost adjustment mechanism for recovery of these deferred amounts. During 2001, $27 million of power costs were deferred, which encompassed all net purchased power costs that varied from the level in Wyoming rates since November 30, 2000, including costs to replace lost generation resulting from the Hunter unit outage.
The Company is reviewing its options in Washington, where it agreed to a 5-year rate plan in June 2000, before purchased power costs significantly increased. The Company is looking at ways to reopen that rate plan to either defer, or obtain rate inclusion of, power costs that vary from the level in current Washington rates.
Regional Transmission Organization ("RTO"):
The Company, in conjunction with eight other utilities, is involved in a voluntary effort to form a RTO, named RTO West, in support of FERC Order 2000. FERC Order 2000 requires all public utilities that own, operate or control interstate electric transmission to file a proposal for a RTO. The nine members of RTO West will be Avista Corporation, BPA, Idaho Power Company, Montana Power Company, Nevada Power Company, PacifiCorp, Portland General Electric Company, Puget Sound Energy, Inc. and Sierra Pacific Power Company. Creation of RTO West is subject to regulatory approvals from the FERC and the states served by these entities. RTO West plans to operate all transmission facilities needed for bulk power transfers and control about 30,000 miles of the 50,000 miles of transmission line owned by the entities. On October 16, October 23 and December 1, 2000, the members made filings addressing structural, operational and contractual issues associated with the RTO formation. On April 25, 2001, the FERC accepted the key components of these filings, including the governance structure, scope and configuration. FERC suggested that RTO West could serve as the basis for the ultimate formation of an RTO encompassing the entire WSCC. Because of the continuing development, the Company cannot currently quantify the impact, if any, of the RTO formation on its future operations.
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Demand Side Management:
In December 2000 and January 2001, the Company filed for Pilot Energy Exchange Service programs in Oregon, Washington, Utah, Idaho and Wyoming. These programs are an optional, supplemental service that allows participating customers an opportunity to voluntarily reduce their electricity usage in exchange for a payment at times and at prices determined by the Company. The customer must execute an agreement prior to being allowed to receive service under the program. The Company expects these programs to be an economic alternative to paying higher market prices by reducing the system-wide demand for electricity. In March 2001, the Company submitted proposals to expand the programs to all customers of one MW and greater in Oregon, Washington, Utah, Idaho, and Wyoming. The exchange had achieved over 9,500 MWh of load curtailment through March 31, 2001 and is expected to grow as the customer base expands.
In March 2001, the Company also filed and received regulatory approval to implement voluntary curtailment programs for irrigation customers in Oregon and Washington. Similar filings were submitted in Idaho and Utah and are under regulatory review.
The Company filed for approval of Residential Usage Incentives in all states it serves in April 2001. If approved, the incentives would provide a 20% credit on monthly bills in June, July, August and September of 2001 for residential customers who reduce their monthly kWh usage from the corresponding month one year ago by 20%. The Company believes this program will set clear and simple targets for customers to receive benefits if they conserve energy.
Proposed Restructuring:
On December 1, 2000, the Company filed requests with the utility commissions in Oregon, Utah, Wyoming, Washington and Idaho to change the way the Company is regulated. A similar filing is planned for California. The proposed plan would change the Company's legal and regulatory structure and result in the creation of six state electric distribution companies, a generation company that also holds transmission assets and a service company, all subsidiaries of a new holding company. The proposal is designed to provide a permanent allocation of generation benefits and costs among states that will allow each to pursue the regulatory policies they deem appropriate without affecting customers in other states or treating shareholders unfairly. Approval for these proposals must be obtained from the utility commissions in Oregon, Utah, Wyoming, Washington, Idaho and California, as well as from the FERC and the Securities and Exchange Commission ("SEC"). This process is expected to take more than a year.
Deregulation:
During 1999, legislation was enacted in Oregon that requires competition for industrial and large commercial customers of both the Company and Portland General Electric Company by October 1, 2001. Under the legislation, the Company is required to unbundle rates for generation, transmission, distribution, and other retail services, and offer residential customers a cost-of-service rate option, and a portfolio of rate options that includes new renewable energy resources and market-based generation. SB 1149 authorizes the OPUC to make decisions on a variety of important issues, including the method
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for valuation of stranded costs/benefits. The OPUC may provide incentives for divestiture of generation assets or the functional separation of such assets. Generation asset divestiture is not mandated and is solely at the Company's discretion. Transition charges may be included in the direct access, portfolio rate option, and cost-of-service rates. SB 1149 requires the OPUC to report to the Oregon state legislature by January 1, 2003 as to whether residential electric customers would benefit from direct access.
On October 2, 2000, the Company filed its plans to implement the requirements outlined by SB 1149 and subsequent commission rules. On November 1, 2000, the Company filed the unbundling information required under SB 1149 rules and requested a related $160 million in increased revenues. On December 1, 2000, the Company filed a resource plan to address the manner in which the Company proposes to use its generation resources under SB 1149.
This resource plan presented the estimate of the value of the Company's generating facilities. This valuation was based on various assumptions, including future electricity prices and cost estimates for compliance with existing and anticipated air quality regulations impacting the Company's thermal generation, as well as the estimated costs associated with relicensing of the Company's hydroelectric facilities. The Company's preliminary analyses indicate that the after-tax present value of the air quality and hydroelectric costs over the projected useful life of the thermal plants, and the term of the licenses in the case of the hydroelectric licenses, could exceed $1 billion predominantly in increased capital expenditures. The final cost is dependent on a variety of factors, including the actual terms and applicability of existing and anticipated environmental laws and regulations, the costs associated with lost generation, developments in pollution control technologies, and the actual terms and conditions of any new hydroelectric licenses. The ultimate impact of these compliance costs on the Company will depend on the regulatory treatment of such costs, whether the Company elects to sell or abandon facilities rather than make the required capital expenditures, and numerous other factors, many of which are beyond the Company's control.
In February 2001, the Company made its resource plan supplemental filing. This filing addressed the potential rate impacts and transition charges and credits associated with implementation of the resource plan options. The supplemental filing also proposed that the preferred plan for implementing direct retail access in Oregon would involve the restructuring proposals discussed above. See "Proposed Restructuring." The Commission has adopted a temporary rule extending the decision date on the resource plan from April 1, 2001 to September 1, 2001.
On January 3, 2001, the OPUC adopted public purpose rules as required by SB 1149. The rules require electric utilities and suppliers that provide electricity services to direct access consumers to collect public purpose charges equal to 3% of the total revenues for electricity services, distribution, ancillary services, metering and billing, transition charges, and other types of costs that were included in electric rates on January 23, 1999.
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The Company will continue to participate in the OPUC proceedings to establish the rules and procedures that will implement the new law. The Company will also continue to evaluate the finance and accounting impacts, including the continued propriety of applying SFAS No. 71, as the OPUC proceedings progress. The impacts, if any, are uncertain.
Due to the current market instability, proposals have been made to alter, defer or suspend implementation of deregulation as prescribed by SB 1149. The ultimate outcome of these proposals and the effects, if any, on the Company are uncertain at this time.
The 2001 Utah legislative session passed a bill that repealed a 2000 Utah legislative session bill that could have significantly changed the way in which utilities are regulated in the state. The 2000 bill would have become effective July 1, 2001.
The Utah legislature also passed a bill extending the life of a legislative task force created in 1997 to study restructuring issues. The bill authorizes this task force to meet as often as twice a month to prepare legislation to implement an electrical restructuring plan for presentation and consideration in the 2002 legislative session, unless it is not in Utah's best interest to do so.
The Company intends to seek recovery of all of its prudent costs, including stranded costs, in the event of deregulation.However, due to the current lack of definitive legislation, the Company cannot predict whether it will be successful. At March 31, 2001, the Company's SFAS No. 71 regulatory assets for all states totaled $1,082 million, of which approximately $556 million is applicable to generation. The Company has no regulatory assets outside of its Domestic electric operations. Because of the potential regulatory and/or legislative action in Utah, Oregon, Wyoming, Idaho and Washington, the Company may have regulatory asset write-offs and charges for impairment of long-lived assets in future periods relating to the generation portion of its business. Impairment would be measured in accordance with SFAS No. 121, which requires the recognition of impairment on long-lived assets when book values exceed expected future cash flows. Integral parts of future cash flow estimates include estimated future prices to be received, the expected future cash cost of operations, sales and load growth forecasts and the nature of any legislative or regulatory cost recovery mechanisms.
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Construction Program
The following table shows actual construction costs for 2001 and the Company's estimated construction costs for 2002 through 2004, including costs of acquiring demand-side resources. The estimates of construction costs for 2002 through 2004 are subject to continuing review and revision as appropriate by the Company.
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AUSTRALIAN ELECTRIC OPERATIONS
On September 6, 2000, the Company completed the sale of its indirect ownership of Powercor and, on November 17, 2000, the Company completed the sale of its 19.9% indirect interest in Hazelwood. See Note 17 of Notes to the Consolidated Financial Statements under ITEM 8. The Company incurred a total loss on the sale of its Australian electric operations of $184 million, pretax, and $198 million, after-tax. Australian electric operations was primarily made up of Powercor, until its sale in September 2000. Powercor was the largest electricity distribution company in Victoria, Australia, based on sales volume revenues, geographic scope and number of customers. Powercor's Distribution Business consisted of the ownership, management and operation of electricity distribution and subtransmission network. Powercor's Supply Business conducted the commercial functions of purchasing, marketing and selling of electricity.
OTHER OPERATIONS
Financial Services
PFS is a holding company principally engaged in holding investments in tax advantaged and leveraged lease assets (primarily aircraft).
PFS made its last investment in aircraft or loans relating to aircraft in 1992. At March 31, 2001, PFS's aviation finance portfolio had total leveraged lease and other financial assets of $307 million (28 aircraft), representing approximately 90% of PFS's consolidated assets.
PFS has four plants in the Birmingham, Alabama area that produce a synthetic coal fuel utilizing technology licensed from Covol Technologies, Inc., which is designed to qualify for tax credits under Section 29 of the Internal Revenue Code. The Company does not currently have sufficient income tax liability to utilize all of these tax credits. The Company is pursuing the sale of its synthetic coal producing plants.
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US Competitive Energy Businesses
In connection with an internal restructuring of the Company, the Company transferred its interest in two nonregulated energy companies to an affiliated entity, PacifiCorp Holdings, Inc. ("PHI"), in March 2001. The transfer price, which was an estimate of the market value based on future cash flows, was $72 million. PHI financed the acquisition through a loan from Holdings. The income and cash flow impacts from the two companies are included in the 2001 results, but the assets and liabilities associated with those businesses were removed from the consolidated balance sheet upon the transfer to PHI.
EMPLOYEES
PacifiCorp and its subsidiaries had 6,626 employees on March 31, 2001. Of these employees, 6,595 were employed by PacifiCorp and its mining affiliates and 31 were employed by PFS and other subsidiaries.
As a result of the Merger, the Company developed and commenced the Transition Plan in May 2000 to implement significant organizational and operational changes. As part of this Transition Plan, the Company expects to reduce its workforce company-wide by approximately 1,600 from 1998 levels over a five-year period ending in 2005, mainly through early retirement, voluntary severance and attrition. For more information, see Note 2 of Notes to the Consolidated Financial Statements under ITEM 8.
Approximately 62% of the employees of PacifiCorp and its mining affiliates are covered by union contracts, principally with the International Brotherhood of Electrical Workers, the Utility Workers Union of America and the United Mine Workers of America.
In the Company's judgment, employee relations are satisfactory.
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ITEM 2. PROPERTIES
The Company owns 52 hydroelectric generating plants and has an interest in one additional plant, with an aggregate nameplate rating of 1,078 MW and plant net capability of 1,137 MW. It also owns or has interests in 17 thermal-electric generating plants with an aggregate nameplate rating of 7,169 MW and plant net capability of 6,663 MW. The Company also jointly owns one wind power generating plant with an aggregate nameplate rating of 33 MW and plant net capability of 33 MW. The following table summarizes the Company's existing generating facilities:
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*Jointly owned plants; amount shown represents the Company's share only.
NOTE: Hydroelectric project locations are stated by locality and river
watershed.
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The Company's generating facilities are interconnected through its own transmission lines or by contract through the lines of others. Substantially all generating facilities and reservoirs located within the western states are managed on a coordinated basis to obtain maximum load carrying capability and efficiency. Portions of the Company's transmission and distribution systems are located, by franchise or permit, upon public lands, roads and streets and, by easement or license, upon the lands of other third parties.
Substantially all of the Company's electric utility property is subject to the lien of the Company's Mortgage and Deed of Trust.
The following table describes the Company's recoverable coal reserves as of March 31, 2001. All coal reserves are dedicated to nearby Company operated generating plants. Recoverability by surface mining methods typically ranges between 90% and 95%. Recoverability by underground mining techniques ranges from 50% to 70%. The Company considers that the respective coal reserves assigned to the Craig, Dave Johnston, Huntington, Hunter and Jim Bridger plants, together with coal available under both long-term and short-term contracts with external suppliers, will be sufficient to provide these plants with fuel that meets the Clean Air Act standards effective in 1999, for their current economically useful lives. The sulfur content of the coal reserves ranges from 0.43% to 0.84% and the British Thermal Units value per pound of the reserves ranges from 7,600 to 11,400. Coal reserve estimates are subject to adjustment as a result of the development of additional data, new mining technology and changes in regulation and economic factors affecting the utilization of such reserves.
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(1) These coal reserves are leased and mined by Trapper Mining, Inc., a Delaware nonstock corporation operated on a cooperative basis, in which the Company has an ownership interest of approximately 20%.
(2) These coal reserves are mined by subsidiaries of the Company and are in underground mines.
(3) These coal reserves are leased and mined by Bridger Coal Company, a joint venture between Pacific Minerals, Inc., a subsidiary of the Company, and a subsidiary of Idaho Power Company. Pacific Minerals, Inc. has a two-thirds interest in the joint venture.
Most of the Company's coal reserves are held pursuant to leases from the federal government through the Bureau of Land Management and from certain states and private parties. The leases generally have multi-year terms that may be renewed or extended and require payment of rentals and royalties. In
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addition, federal and state regulations require that comprehensive environmental protection and reclamation standards be met during the course of mining operations and upon completion of mining activities. In 2001, the Company expended $10 million of reclamation costs and accrued $1 million of estimated final mining reclamation costs. Final mine reclamation funds have been established with respect to certain of the Company's mining properties. At March 31, 2001, the Company's pro rata portion of these reclamation funds totaled $57 million and the Company had an accrued reclamation liability of $132 million at March 31, 2001.
ITEM 3. LEGAL PROCEEDINGS
The Company and its subsidiaries are parties to various legal claims, actions and complaints, one of which is described below. Although it is impossible to predict with certainty whether or not the Company and its subsidiaries will ultimately be successful in its legal proceedings or, if not, what the impact might be, management believes that disposition of these matters will not have a material adverse effect on the Company's consolidated financial results.
The parties have settled the litigation ofSierra Club v. Tri-State Generation and Transmission Association, Inc., Public Service Company of Colorado, Inc., Salt River Project Agricultural Improvement and Power District, PacifiCorp and Platte River Power Authority, Civil Action No. 96-B2368, US District Court for the District of Colorado. This settlement does not have a material financial impact on the Company.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No information is required to be reported pursuant to this item.
PART II
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Under the Public Utility Holding Company Act of 1935, the Company may pay dividends out of capital or unearned surplus only with SEC approval. Dividends from earned surplus are permitted without approval. The Company has received approval to pay dividends out of unearned surplus of the lesser of $900 million or the proceeds received from sales of nonutility assets.
ITEM 6. SELECTED FINANCIAL DATA
The information required by this item is included under "Selected Financial Information" on page 103 of this Report.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
OVERVIEW OF 2001
Unless otherwise stated, references to periods in 2001 and 2000 are to periods in the years ended March 31, 2001 and 2000, respectively, while references to periods in 1998 are to the year ended December 31, 1998.
The Company's strategic business plan is to focus on its energy businesses in the western United States. As part of its strategic business plan, the Company has sold most of its other United States and international businesses, and has previously terminated all of its business development activities outside of the United States. In 2001, the Company completed its divestiture of the Australian electric operations (Powercor and Hazelwood). On September 6, 2000, the Company completed the sale of its indirect ownership of Powercor. On November 17, 2000, the Company completed the sale of its 19.9% indirect interest in Hazelwood.
As a result of the November 29, 1999 Merger, the Company has developed and commenced its Transition Plan to implement significant organizational and operational changes. These changes are intended to lead to improved service to customers, continued strong investment in communities and enhanced value for shareholders. The Transition Plan is the outcome of an intense five-month review of the Company's business. More than 200 initiatives and changes have been proposed. By 2004, the initiatives are expected to deliver annual cost savings from 1998 levels of $300 million in operating expenses and $250 million in capital expenditures. The Company intends to invest approximately $150 million over the same period for training and new technology. The Company expects to reduce its workforce company-wide by approximately 1,600 over a five-year period, mainly through early retirement, voluntary severance and attrition. The estimated early retirement and severance costs are being deferred and amortized over future periods, as ordered by the various utility commission accounting orders received by the Company. The overall favorable variances in operations and maintenance expense and administrative and general expenses during 2001 can be attributed in part to effects of implementing the Transition Plan.
Australian electric operations' financial results for the period from January 1, 2000 to the dates of sale are included in the Company's financial results for the year ended March 31, 2001. Australian electric operations'
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financial results for the calendar year ended December 31, 1999 are included in the Company's financial results for the year ended March 31, 2000. For the purpose of this discussion, these financial results are referred to as "2001" and "2000" results, respectively.
(Loss) Earnings Overview of the Company
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(1) (Loss) earnings contribution on common stock by segment: (a) does not reflect elimination for interest on intercompany borrowing arrangements; (b) includes income taxes on a separate company basis, with any benefit or detriment of consolidation reflected in Other operations and (c) is net of preferred dividend requirements and minority interest (which is reported as a component of Minority interest and other).
(2) Represents the discontinued operations of TPC and the eastern United States energy trading activities of PPM.
The Company recorded a loss on common stock of $106 million in 2001 compared to earnings of $65 million in 2000. The 2001 results included a loss of $198 million from the sale of Australian electric operations, $218 million of which represents the loss on sale recorded at Australian electric operations partially offset by a $20 million net gain recorded at Other operations on the settlement of foreign currency exchange swaps and debt repayment expense. The 2001 results also included $27 million after-tax for regulatory asset write backs and $5 million after-tax in merger costs compared to $180 million in the 2000 period. The results for the 2000 period also included a $15 million after-tax write-off of projects under construction, that were abandoned in the period. Excluding these items, earnings would have been $70 million in 2001 and $260 million in the preceding period. This variance is mainly attributable to higher purchased power costs in 2001 compared to 2000.
See Note 2 of Notes to the Consolidated Financial Statements under ITEM 8 for a table showing where merger costs have been recorded in the Company's financial results. See Note 17 of Notes to the Consolidated Financial Statements under ITEM 8 for information regarding the sale of Australian electric operations.
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In 2001, the Company, along with other utilities in the WSCC, has been challenged by the market and economic conditions of the electricity industry in the region. The economic growth of the region has spurred the increase in demand for electricity. At the same time, generation resources have been impacted by the lack of new generation facility construction, unplanned outages in generation facilities, including the November 24, 2000 outage of the Company's 430 MW Hunter unit, and by the low snow pack and rainfall resulting in low hydroelectric generation. The limited current and forecasted hydro resources are also in demand for meeting irrigation needs and for protection of migrating fish.
All these conditions have led to unprecedented high short-term firm and spot market prices. To meet certain load and contractual obligations, the Company has had to purchase power at prices that have exceeded the revenues received from retail rates and committed wholesale sales. If the supply of electricity does not improve, the demand does not decrease or customer rates do not increase sufficiently, the Company may be required to continue to purchase electricity at prices greater than amounts received in revenues.
In November 2000, the Company filed applications seeking deferred accounting treatment for future net power costs that vary from costs included in determining retail rates in the states of Utah, Idaho, Wyoming and Oregon. The Company has received approval of deferred accounting treatment from these states to cover a portion of these cost variances. This will help mitigate a portion of the adverse effect of higher market prices, assuming that recovery mechanisms are implemented as anticipated. The Company requested recovery from customers in Utah, Oregon, Wyoming and California of increasing costs and has also requested power cost adjustments in Oregon and Wyoming. These power cost adjustments provide for continued periodic adjustment of rates for costs incurred that vary from costs included in tariffed rates.
Public utilities in the western United States, including the Company, and governors in the western states, have all been promoting conservation as a method to ease the current and potential future energy shortage. Actions have been initiated to pay industrial and commercial electricity users to forgo power consumption by shutting down their operations so that power could be redistributed to other uses and residential customers. The Company has participated in such power redistribution through its voluntary Demand Side Management program. The Company is also addressing supply and demand issues through contracting power from customer-owned generation, providing consumer education about conservation, working with regulators to develop rate structures to promote conservation and providing monetary incentives to customers for reduction in usage. These actions along with increasing prices paid by customers for power may reduce the rate of electricity consumption.
Disruptions in the western electricity market have had a negative impact on the willingness of the financial markets to provide financing on conditions and at rates that have historically been available to the Company. At March 31, 2001, PacifiCorp had a $500 million committed bank revolving credit agreement that expires in August 2001. The Company relies upon this facility in part to provide committed back-up for short-term borrowing and for daily liquidity requirements for $175 million of unenhanced pollution control
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revenue bonds. The Company is currently seeking to replace the existing credit facility. While the Company believes this facility will be successfully replaced at costs marginally higher than historical rates, no assurances can be given as to this outcome. Regulatory authorities limit PacifiCorp to $1.5 billion of short-term debt, of which $241 million was outstanding at March 31, 2001 at a weighted average rate of 5.7%. See Notes 7 and 8 of Notes to the Consolidated Financial Statements under ITEM 8 for additional information.
While in 2001, the Company incurred a greater cost of purchasing power at higher prices than the benefit received from making wholesale sales in the market, the impact was mitigated by the Company's overall near balanced supply and demand portfolio. Other utilities in the WSCC have been severely impacted as a result of purchasing electricity to cover load at prices higher than could be recovered in retail rates and wholesale prices. This impact, coupled with significantly higher natural gas prices and the effects of the California power market restructuring, led to SCE and PG&E defaulting in the fourth quarter of 2001 on payments owed to various creditors. In April 2001, PG&E filed for Chapter 11 reorganization. These defaults have resulted in the subsequent defaults by the CPX, the Cal ISO and the Automated Power Exchange. The Company has limited exposure to these California entities at March 31, 2001. The exposure that the Company has to other entities that have been counterparties in energy transactions with these California entities could be significant depending on the level of purchases and sales that existed and continues with these defaulting entities. The ramifications to future operations in the WSCC from these events are uncertain.
The Company's operations are exposed to risks, including legislative and governmental regulations, the price and supply of purchased power, fuel and natural gas, recovery of purchased power costs and purchased natural gas costs, weather conditions, availability of generation facilities, competition, technology and availability of funding. In addition, the energy business exposes the Company to the financial, liquidity, credit and commodity price risks associated with wholesale sales and purchases. For additional information, see "Business Risk."
Domestic electric operations' contribution to earnings on common stock was $110 million in 2001. After adjusting earnings by $5 million for merger costs and $27 million for regulatory asset write backs, the contribution would have been $88 million. Domestic electric operations' earnings contribution in 2000 was $11 million. After adjusting 2000 earnings by $177 million for merger costs and a write-off of projects under construction of $15 million, the contribution would have been $203 million. The $115 million decrease in adjusted earnings was the result of several factors, including the unprecedented short-term firm and spot market prices, lower hydro resources, load increases and the adverse effect of the Hunter unit outage.
Australian electric operations' recorded a loss of $187 million in 2001. This $226 million decrease from the prior year was primarily due to the $218 million loss recorded at Australian electric operations on its sale in 2001.
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Other operations reported a net loss of $29 million in 2001 as compared to earnings of $14 million in 2000. A primary cause of this change was the decrease in 2001 of PFS's earnings contribution, primarily due to the Company's inability to use tax credits of $28 million and a decrease in operating income of $6 million, generated by the synthetic fuel operations owned by subsidiaries of PFS. Interest income in 2001 increased $8 million compared to the prior year as a result of an increase in investments of cash received from the sale of Australian electric operations. Interest expense decreased $8 million due to a decrease in debt balances.
The Company's combined federal and state effective income tax rate from continuing operations was 196% for 2001, 62% for 2000, and 35% for 1998. The tax rate in 2001 varied from the statutory rate primarily due to the substantially nondeductible losses on the sales of its Australian operations and reserves for tax on outstanding Internal Revenue Service examination issues. The primary cause for the variance from the statutory tax rate in 2000 was the nondeductible nature of many merger costs. For a reconciliation of effective tax rate to statutory rate, see Note 15 of Notes to the Consolidated Financial Statements under ITEM 8.
A report on Form 10-Q for the three-month transition period of January 1, 1999 through March 31, 1999 was filed with the Securities and Exchange Commission on January 13, 2000. Pages 13 through 20 thereof are incorporated herein by reference.
FORWARD-LOOKING STATEMENTS
The information in the tables and text in this document includes certain forward-looking statements that involve a number of risks and uncertainties that may influence the financial performance and earnings of the Company. When used in this "Management's Discussion and Analysis of Financial Condition and Results of Operations," the words "estimates," "expects," "anticipates," "forecasts," "plans," "intends" and variations of such words and similar expressions are intended to identify forward-looking statements that involve risks and uncertainties. There can be no assurance the results predicted will be realized. Actual results will vary from those represented by the forecasts, and those variations may be material.
The following are among the factors that could cause actual results to differ materially from the forward-looking statements: utility commission practices; political developments; regional, national and international economic conditions; weather and behavioral variations affecting customer usage; competition and supply in bulk power and natural gas markets; hydroelectric and natural gas production; coal quality and prices; unscheduled generation outages; disruption or constraints to transmission facilities; hydro-facility relicensing; energy purchase and sales activities; environmental, regulatory and tax legislation, including industry restructure and deregulation initiatives; nonperformance by counterparties; technological developments in the electricity industry; proposed asset dispositions and the cost and availability of debt and equity capital. Any forward-looking statements issued by the Company should be considered in light of these factors.
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DOMESTIC ELECTRIC OPERATIONS
OVERVIEW
The year 2001 was a period of unprecedented change in the utility and energy businesses. Market forces described above drove record increases in purchased power prices and economic growth tightened the availability of excess power. During the period, the Company, along with other WSCC companies, was required to purchase power at unprecedentedly high short-term firm and spot market prices. The increase in power prices was driven by numerous factors, including increased load demands resulting from economic growth in the region, unusually low hydroelectric conditions, and unplanned outages in generation facilities in the WSCC, along with high natural gas prices. On November 24, 2000, the Company's Hunter power plant experienced a failure of a 430 MW generation unit that returned to service during May 2001. In May 2000, the Company sold the Centralia plant and mine, which had contributed up to 637 MW of the Company's generation portfolio. While these market conditions contributed to doubling of wholesale revenues to $2.08 billion, the $1.05 billion increase in wholesale revenues was more than offset by the $1.52 billion, or 159%, increase in purchased power costs.
Domestic electric operations' contribution to earnings on common stock was $110 million in 2001 compared to $11 million in 2000. The nondeductible nature of most merger costs contributed to an effective tax rate of 81% in 2000 compared to 41% in 2001 for Domestic electric operations.
Income before income taxes was $216 million in 2001 and $155 million in 2000. Significant, nonrecurring items in 2001 include $9 million pretax in merger costs and regulatory asset write backs of $43 million pretax, which reduced operating expenses. After adjusting for these nonrecurring items, income before income taxes would have been $182 million in 2001. Significant, nonrecurring expenses in 2000 included $207 million pretax in merger costs and $23 million of write-offs of assets under construction. After adjusting for these nonrecurring items, income before income taxes would have been $385 million in 2000. This $203 million decrease in adjusted income before income taxes was primarily the result of the net unfavorable impact of a reduction in wholesale sales volume and increased purchased power costs described above, partially offset by retail and other revenue growth of $194 million and decreased other operations and maintenance and administrative, general and other tax expense.
The Company achieved $101 million, or 12%, reduction in operations and maintenance and administrative, general and other tax expense, which can be largely attributed to savings realized in implementation of the Transition Plan, the May 2000 sale of the Centralia plant and mine, and a favorable variance due to the $23 million pretax prior year write-off of assets under construction. See Notes 2, 5 and 17 of Notes to the Consolidated Financial Statements under ITEM 8.
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REVENUES
Revenues | |||
For the year ended | March 31, | December 31, | |
Millions of dollars | 2001 | 2000 | 1998 |
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Energy Sales | |||
For the year ended | March 31, | December 31, | |
Thousands of MWh | 2001 | 2000 | 1998 |
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Total Domestic electric operations revenues increased $1.24 billion, or 38%, from 2000 to $4.53 billion in 2001. This was primarily attributable to increases in wholesale sales of $1.05 billion and a $134 million increase in retail revenues.
Wholesale revenues increased $1.05 billion, or 102%. Sales prices for short-term firm and spot market sales averaged $107 per MWh in 2001 compared to $27 per MWh in 2000, resulting in a price related increase of $1.56 billion. Partially offsetting this was a 27% decrease in short-term firm and spot market sales that decreased revenues by $560 million. This decrease in volume was due to the sale of the Centralia plant, the decrease in hydro availability, the outage of the Hunter unit, and the increase in load requirements, all of which impacted the amount of available power to sell on the short-term and spot market. Increased prices and volumes relating to long-term firm contracts added $36 million and $13 million, respectively, to revenues.
Residential revenues increased by $53 million, or 7%. Growth in the average number of customers of 2% added $14 million to revenues. Price increases in Oregon, Utah and Wyoming added $27 million to revenues in 2001. Volume increases of 3%, primarily due to weather, increased residential revenues by $12 million.
Industrial revenues increased $36 million, or 5%. Price increases in Oregon, Utah and Wyoming increased revenues by $31 million. Increased irrigation usage added $9 million to revenues.
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Commercial revenues increased $43 million, or 6%, primarily as a result of strong economic activity in Utah and Oregon. Growth in the average number of commercial customers of 3% added $22 million to revenues and volume increases of 6% added $20 million to revenues.
Other revenues increased by $60 million, or 82%, primarily due to an increase in wheeling revenues from increased usage of the Company's transmission system by third parties.
2000 compared to 1998 - Revenues decreased 32%, or $1.55 billion, in 2000 primarily due to decreased wholesale energy volumes. A 75% decrease in short-term firm and spot market sales volumes decreased wholesale revenues by $1.56 billion. This volume reduction was the result of a decision made in prior years to scale back wholesale sales volumes from 1998 levels. Residential revenues decreased $8 million primarily due to the effect of the 1998 Utah rate order that lowered revenues in 2000, partially offset by customer growth. Industrial revenues decreased $11 million primarily due to the effect of the Utah rate order and open access pilot programs in Oregon. Commercial revenues increased $14 million primarily due to customer growth and increased customer usage, partially offset by the effect of the Utah rate order. Other revenues increased $7 million primarily due to increased wheeling revenues.
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OPERATING EXPENSES
For the year ended | March 31, | December 31, | |
Millions of dollars | 2001 | 2000 | 1998 |
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Operating expenses increased $1.38 billion, or 51%, to $4.08 billion in 2001. This was primarily attributable to increased purchased power expense due to significantly increased prices on short-term firm and spot market purchased power and an increase in the volume purchased resulting from increased demand. Additional factors included a decrease in the Company's system generation resulting from the outage of the Hunter unit, the decrease in hydro availability, and the sale of the Centralia plant and mine.
Purchased power expense was $2.48 billion, an increase of $1.52 billion, or 159%. Significantly higher prices on short-term firm and spot market purchases increased purchased power expense by $1.25 billion, which is net of the effect of deferred accounting treatment received from the regulatory authorities in Utah, Oregon, Wyoming, and Idaho of $139 million for power costs that vary from costs included in determining rates. Supply in the WSCC did not keep pace with increased demand due in large part to economic growth. These factors, along with unanticipated generation outages in the WSCC, including the outage at the Company's Hunter unit, and the reduction in supply from hydroelectric facilities due to unusually low precipitation, led to increases in the level and volatility of power prices in 2001. Short-term firm and spot market purchase prices averaged $103 per MWh in 2001 compared to $28 per MWh in 2000. Short-term firm and spot market purchase volumes were flat compared to the prior year. Increased prices and volumes relating to long-term firm contracts added $92 million and $105 million, respectively, to purchased power expense. Increased usage of transmission systems owned by third parties added $43 million to expense.
Fuel expense decreased $21 million, or 4%, to $491 million. This decrease is attributed to an 8% reduction in thermal generation to 48.5 million MWh, which reflects the May 2000 sale of the Centralia plant and the unplanned Hunter unit outage. Additionally, hydroelectric production decreased 37% to 3.4 million MWh due to unusually low rainfall in the region, which had the effect of increasing the average overall cost per MWh.
Total operations and maintenance expense and administrative, general and other tax expense decreased by $101 million. The Company is implementing the Transition Plan and the effects of that process are included in the variances in operations and maintenance expense, as well as administrative, general and taxes, other than income taxes discussed below.
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Other operations and maintenance expense decreased $19 million, or 4%. The sale of the Centralia plant and mine drove a $6 million decrease in expense. Bad debt expense decreased by $8 million. Operations and maintenance expense in 2000 included $23 million of write-offs of assets under construction and $4 million of write-offs of obsolete inventory. Offsetting these net favorable variances was increased labor expense of $19 million resulting from an increasing amount of work relating to expense rather than capital projects.
Depreciation and amortization expense increased $9 million, or 2%, to $389 million primarily due to increased depreciation rates.
Administrative, general and taxes, other than income taxes decreased $82 million, or 27%. Decreased labor and severance costs contributed $51 million to this variance, including $14 million of merger costs recorded in the prior year. Employee related expenses decreased $33 million, primarily due to the impact of favorable returns on pension plan assets on pension expense.
Included within other operating income in 2001 was a $43 million gain relating to rate orders received which provided recovery for previously denied costs and resulted in the establishment of $43 million of regulatory assets. In addition, the Company recorded a loss of $14 million on the sale of the Centralia plant and mine. See Note 17 of Notes to the Consolidated Financial Statements under ITEM 8.
2000 compared to 1998 - Operating expenses decreased $1.57 billion in 2000 primarily due to lower purchased power volumes. A 77% decrease in short-term firm and spot market energy purchases decreased purchased power expense by $1.58 billion. This volume reduction was the result of a decision made in prior years to reduce wholesale sales volumes from 1998 levels. Other operations and maintenance expense increased $93 million, which included $23 million of write-offs of assets under construction. In addition, costs reclassified from administrative and general upon conversion to the SAP software operating environment increased operations and maintenance expense by $15 million in 2000 and an increasing amount of work relating to operations and maintenance rather than capital projects added $14 million. Increased materials and contracts primarily relating to steam plant overhaul costs added $11 million to operations and maintenance expenses, increased employee costs added $9 million, and increased collection activity added $8 million. Administrative, general and taxes, other than income taxes expense decreased $31 million. This decrease includes $15 million of costs reclassified to operations and maintenance expense in 2000 and a $16 million decrease in SAP and Year 2000 conversion and other consulting costs. Special charges in 1998 consisted of the costs of an early retirement and cost reduction program.
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INTEREST EXPENSE AND OTHER, INCOME TAX EXPENSE AND PREFERRED DIVIDENDS
For the year ended | March 31, | December 31, | |
Millions of dollars | 2001 | 2000 | 1998 |
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Domestic electric operations interest expense decreased $16 million primarily due to proceeds received from asset sales and dividends received from Holdings that were used to pay down intercompany and external debt balances. The 2000 results included $191 million of merger costs compared to $9 million in 2001. The expense in 2001 is primarily related to merger credits in the state of Washington becoming unavailable for offset. See Note 2 of Notes to the Consolidated Financial Statements under ITEM 8.
Income tax expense decreased $38 million due to nondeductible merger costs in the prior year, partially offset by higher taxable income in the current year. The nondeductible nature of most merger costs contributed to an effective tax rate of 81% in 2000 compared to 41% in 2001 at Domestic electric operations. For a reconciliation of effective tax rate to statutory rate, see Note 15 of Notes to the Consolidated Financial Statements under ITEM 8.
2000 compared to 1998 - Interest expense was $51 million lower primarily due to the dividends received from Holdings that were used to pay down intercompany and external debt balances. Merger costs were $177 million higher primarily due to taxes paid for stock transfers to complete the merger and the merger credits ordered in various states. Income tax expense was $22 million higher primarily due to an increase in nondeductible merger transaction costs, partially offset by the decline in taxable income. The nondeductible nature of most merger costs contributed to an effective tax rate of 81% in 2000 compared to 41% in 1998 at Domestic electric operations. For a reconciliation of effective tax rate to statutory rate, see Note 15 of Notes to the Consolidated Financial Statements under ITEM 8.
INDUSTRY CHANGE, COMPETITION AND DEREGULATION
Industry Change - The electric power industry continues to experience change. The key driver for this change is public, regulatory and governmental support for replacing the traditional cost-of-service regulatory framework with an open market competitive framework where the customers have a choice of energy supplier. The pace at which this change will occur has slowed as regulators and legislators struggle with conversion and implementation issues. Current market prices and California's attempt to implement a form of deregulation and its consequences on the market have slowed the progress of deregulation in many areas of the western United States. However, federal laws and regulations
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have been amended to provide for open access to transmission systems, and various states have adopted or are considering new regulations to allow open access for all energy suppliers. If portions or all of the Company's operations become deregulated, the Company's risks and opportunities would change, reflecting greater exposure to market forces and reduced or eliminated regulatory influence. Accordingly, the Company would also need to evaluate the appropriateness of applying SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." Under deregulation, the Company may be required to discontinue its application of SFAS No. 71 to all or a portion of its business, which could result in a partial or complete write off of regulatory assets and liabilities. For additional information concerning the regulatory, competitive and environmental issues facing the Company, see "ITEM 1. BUSINESS - DOMESTIC ELECTRIC OPERATIONS - Regulation," "- Competition" and "- Environmental Issues." Also, see Note 5 of Notes to the Consolidated Financial Statements under ITEM 8 for information on accounting for the effects of regulation.
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AUSTRALIAN ELECTRIC OPERATIONS
On September 6, 2000, the Company completed the sale of its indirect ownership of Powercor pursuant to the August 2, 2000 agreement to sell Powercor and the Company's 19.9% interest in Hazelwood. On November 17, 2000, the Company completed the sale of its interest in Hazelwood to National Power Australia Holdings Pty Ltd, a wholly-owned indirect subsidiary of International Power plc, pursuant to the partnership's pre-emptive rights process. See Note 17 of Notes to the Consolidated Financial Statements under ITEM 8.
Australian electric operations' financial results for the period from January 1, 2000 to the dates of sale are included in the Company's financial results for the year ended March 31, 2001. Australian electric operations' financial results for the calendar year ended December 31, 1999 are included in the Company's financial results for the year ended March 31, 2000. For the purpose of this discussion, these financial results are referred to as "2001" and "2000" results, respectively.
Currency Exchange - The average currency exchange rate for converting Australian dollars to United States dollars was 0.60 in 2001 compared to 0.65 in 2000, an 8% decrease for the year. The net effect of the exchange rate fluctuation had minimal net effect on Australian electric operations' earnings contribution in 2001. The following discussion excludes the effects of the lower currency exchange rate in 2001.
Results for 2001 are not directly comparable to 2000 as the sale of the Australian electric operations was substantially completed on September 6, 2000 so the 2001 results represent eight months of operations compared with the 12 months shown for 2000 .
In 2001, Australian electric operations contributed a loss of $187 million compared to earnings of $39 million in 2000. This decrease was primarily due to the $218 million loss recorded at Australian electric operations on the sale of Powercor and the 19.9% interest in Hazelwood. See Note 17 of Notes to the Consolidated Financial Statements under ITEM 8.
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REVENUES
For the year ended | |||
Millions of dollars | 2001 | 2000 | 1998 |
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OPERATING EXPENSES
Purchased power | $157.6 | $260.0 | $255.0 |
INTEREST EXPENSE AND OTHER AND INCOME TAXES
Interest expense | $ 37.5 | $ 58.4 | $ 57.9 |
Overall, 2001 results (excluding the loss on the sale) are lower than in 2000 due to a shorter period of operation resulting from the sale. The following discussion is a comparison of the eight-month period of ownership in 2001 to the same eight-month period in 2000. Australian electric operations' total 2001 revenues increased $13 million compared to the 2000 period. The increase was primarily due to an increase in volume. Total operating expenses increased $220 million, primarily due to a $218 million loss recorded on the sale of the Australian electric operations. Purchased power expense decreased $17 million primarily due to the impact of a favorable court ruling in resolution of a dispute with one of Powercor's suppliers. An increase in administrative and general expenses of $15 million was primarily due to costs associated with a project to transition to full retail contestability. Interest expense for the eight-month period in 2001 was approximately $2 million higher than the expense in the 2000 period. After adjusting pretax earnings for the loss on the sale of Australian electric operations, income taxes increased by $3 million, primarily due to an increase in taxable income. See Note 15 of Notes to the Consolidated Financial Statements under ITEM 8 for a discussion of the income tax treatment on the loss from the sale.
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2000 compared to 1998
The average currency exchange rate for converting Australian dollars to United States dollars was 0.65 in 2000 compared to 0.63 in 1998, a 3% increase for the year. The net effect of the exchange rate fluctuation on net income was minimal in 2000. The following discussion reflects variances without the effects of the higher currency exchange rate in 2000.
Revenues decreased $13 million, or 2%, in 2000 primarily due to a 3% decrease in energy sales volumes. Revenues within Powercor's franchise area decreased $2 million due to price decreases for customers and $17 million due to a 378 million kWh decrease in volumes. Other revenues increased $7 million primarily due to recognition of a sales tax contract settlement payment received from the Australian Government of $4 million and refunds received with the dissolution of the Victoria Power Exchange of $2 million.
Operating expenses decreased $20 million, or 4%, in 2000. Total purchased power expense decreased $2 million. Other operations and maintenance expense decreased $39 million. The decrease in expense was related to an increase in external network revenue of $18 million relating to customers within Powercor's distribution area being supplied electricity by competitors, a decrease in external network fees of $11 million and a $9 million decrease due to reclassification to administrative and general of construction service expense. Administrative, general and taxes, other than income taxes increased $22 million. An increase of $9 million was attributable to the aforementioned reclassification from other operations and maintenance. Restructuring costs increased $4 million over 1998. A project to transition to full retail contestability increased expenses by $3 million, and salaries and incentives increased $4 million. Income taxes increased by $16 million, primarily due to an increase in taxable income.
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OTHER OPERATIONS
(Loss) earnings Contribution | |||
For the year ended | March 31, | December 31, | |
Millions of dollars | 2001 | 2000 | 1998 |
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(a) These items reflected a tax rate of approximately 38%.
Other operations reported a loss of $29 million for 2001 compared to earnings of $14 million in 2000.
In 2001, earnings contribution decreased due to the Company's inability to use tax credits of $28 million and a decrease in operating income of $6 million, both related to the synthetic fuel operations owned by subsidiaries of PFS. The Company did not have sufficient income tax liability to utilize all of the alternative fuel credits generated by these operations. See Note 15 of Notes to the Consolidated Financial Statements under ITEM 8. The sale of the Company's investment in Australian electric operations resulted in a net gain on settlement of foreign currency exchange swaps and debt repayment expense of $20 million. See Note 17 of Notes to the Consolidated Financial Statements under ITEM 8. Additionally, interest income in 2001 increased $8 million compared to the prior year as a result of an increase in investments of cash received from the sale of Australian electric operations. Interest expense decreased $8 million due to a decrease in debt balances. In 2000, results included losses associated with exiting energy development businesses of approximately $7 million, as well as merger costs of $3 million. A write down, to anticipated net realizable value, of off-lease assets that are being sold increased the loss by $5 million in 2001.
Other - net includes tax expense related to reevaluation of tax liabilities from settled and ongoing tax examinations. For a reconciliation of effective tax rate to statutory rate, see Note 15 of Notes to the Consolidated Financial Statements under ITEM 8.
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2000 compared to 1998 - Earnings contribution of Other operations in 2000 increased $66 million compared to 1998. Results for 1998 included a loss of $32 million related to the decision to shut down or sell the Company's energy development businesses. Additionally, there was a loss of $55 million associated with the Company's terminated bid for The Energy Group ("TEG") and closing associated foreign exchange positions. The loss associated with TEG was partially offset by a gain of $10 million on the sale of TEG shares. In comparison, earnings in 2000 included a decrease in interest income of $31 million, resulting from a reduction in investments due to dividend payments made by Holdings to Domestic electric operations, offset by an increase of earnings at PFS's synthetic fuel operations of $13 million.
DISCONTINUED OPERATIONS
Discontinued operations reported earnings in 2000 of $1 million compared to losses of $147 million in 1998. The 1998 results included $105 million for the loss anticipated to exit the eastern United States energy trading business and a loss of $42 million for operating losses prior to the decision to exit. On April 1, 1999, Holdings sold TPC for $150 million. Exiting these energy trading activities resulted in a net after-tax gain of $1 million in 2000. See Note 4 of Notes to the Consolidated Financial Statements under ITEM 8.
In 1998, the pretax loss associated with exiting the eastern United States energy trading business was $155 million. This loss consisted of write downs of intangible assets of $83 million and the costs to exit a portion of the business and sell another portion of the business of $72 million. The exiting costs included anticipated severance payments and operating costs to the selling date and selling expenses. The remaining values for these businesses represented the estimated market value of the fixed assets of the companies and the estimated remaining working capital at the sale date.
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LIQUIDITY AND CAPITAL RESOURCES
OPERATING ACTIVITIES
Cash flows from continuing operations decreased $118 million from 2000 to 2001. This decrease was largely due to the impact of significantly higher purchased power prices on net income, combined with regulated rates that did not reflect the costs to purchase power, which were only partially offset by cash from working capital increases. The Company has received deferred accounting treatment for a portion of net power costs that vary from costs included in determining retail rates in the states of Utah, Oregon, Idaho, and Wyoming, and is currently working with these states to develop recovery mechanisms for the deferred costs. Additionally, the Company has asked for rate increase requests before the state commissions in California, Oregon, Utah and Wyoming. For more detail on deferred power cost and rate increase filings, see "ITEM 1. DOMESTIC ELECTRIC OPERATIONS - Regulation."
INVESTING ACTIVITIES
Capital spending totaled $486 million in 2001 compared with $574 million in 2000. Construction expenditures decreased in 2001 primarily due to lower expenditures at Domestic electric operations, which can be attributed to the sale of the Centralia plant and mine and timing of capital projects. Proceeds from asset sales in 2001 were primarily the result of the sales of Powercor, the Company's interest in Hazelwood and the Centralia plant and mine, while proceeds from asset sales in 2000 were attributable to the sale of TPC.
On September 6, 2000, the Company completed the sale of its indirect ownership of Powercor pursuant to the August 2, 2000 agreement to sell Powercor and the Company's 19.9% interest in Hazelwood. On November 17, 2000, the Company completed the sale of its interest in Hazelwood to National Power Australia Holdings Pty Ltd, a wholly-owned indirect subsidiary of International Power plc, pursuant to the partnership's pre-emptive rights process. See Note 17 of Notes to the Consolidated Financial Statements under ITEM 8.
On May 4, 2000, the utility partners who owned the 1,340 MW coal-fired Centralia Power Plant sold the plant and the adjacent coal mine owned by the Company to TransAlta for approximately $500 million. See Note 17 of Notes to the Consolidated Financial Statements under ITEM 8.
On April 1, 1999, Holdings sold TPC for $150 million. Exiting its energy trading business in the eastern United States and its other energy development businesses resulted in a net after-tax gain of $1 million in the first quarter of 2000.
FINANCING ACTIVITIES
In November 2000, the Company retired $176 million of junior subordinated debentures with a portion of the proceeds from the Powercor sale.
In July 2000, Holdings paid off $250 million of debt in anticipation of the Powercor sale.
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During 2001, the Company declared dividends on common stock of $390 million and paid dividends on common stock of $332 million to an indirect subsidiary of ScottishPower. On November 16, 2000, the Company declared a dividend on common stock of $80 million, of which $22 million was paid on February 12, 2001 and $58 million was payable at March 31, 2001. These dividends were declared at a rate that is consistent with the Company's historic pre-merger rate per share. See Note 18 of Notes to the Consolidated Financial Statements under ITEM 8.
The Company declared dividends of $15 million on preferred stock during 2001 and had $4 million in preferred dividends declared but unpaid at March 31, 2001.
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CAPITALIZATION
| March 31, | |||
2001 | 2000 | |||
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The Company manages its capitalization and liquidity position in a consolidated manner through policies established by senior management and the Board of Directors. These policies, subject to periodic review and revision, have resulted from a review of historical and projected practices for businesses and industries that have financial and operating characteristics similar to the Company and its principal business operations.
The Company's policies attempt to balance the interests of all shareholders, ratepayers and creditors. In addition, given the changes that are occurring within the industry and market segments in which the Company operates, these policies are intended to remain sufficiently flexible to allow the Company to respond to these developments.
On a consolidated basis, the Company attempts to maintain total debt at approximately 48% to 54% of capitalization. The total debt to capitalization ratio was 44% at March 31, 2001 as a result of paying down debt with proceeds from asset sales. The Company expects, over time, to maintain its capital structure in accordance with its targets. The Company also attempts to maintain a preferred stock ratio, including subordinated debt, at 8% to 12% of capitalization. The preferred stock ratio was 8% at March 31, 2001. The Company has made commitments in connection with the Merger not to make distributions that result in a reduction of common equity, without approval, to below 36% of total capitalization, increasing over time to 40%.
Long-term debt at March 31, 2000 included Australian electric operations debt of $841 million, which the buyer assumed as a condition of the sale.
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VARIABLE RATE LIABILITIES
| March 31, | |
2001 | 2000 | |
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The Company's capitalization policy targets consolidated variable rate liabilities at between 10% and 25% of total capitalization.
AVAILABLE CREDIT FACILITIES
At March 31, 2001, PacifiCorp had a $500 million committed bank revolving credit agreement that expires in August 2001. The Company relies upon this facility in part to provide for committed back-up for short-term borrowing and daily liquidity requirements related to $175 million of unenhanced pollution control revenue bonds. The Company is currently seeking to replace the existing credit facility. Regulatory authorities limit PacifiCorp to $1.5 billion of short-term debt, of which $241 million was outstanding at March 31, 2001 at a weighted average rate of 5.7%. See Notes 7 and 8 of Notes to the Consolidated Financial Statements for additional information under ITEM 8.
The Company believes that its existing and available capital resources and the anticipated replacement of the revolving credit facility will be sufficient to meet working capital, dividend and construction needs in 2002. While the Company believes the revolving credit facility will be successfully replaced at costs marginally higher than historical rates, no assurances can be given as to this outcome.
LIMITATIONS
In addition to the Company's capital structure policies, its debt capacity is also governed by its contractual commitments. PacifiCorp's principal debt limitation is a 60% debt to defined capitalization test contained in its principal credit agreements. Based on the Company's most restrictive agreement, management believes that PacifiCorp and its subsidiaries could have borrowed an additional $2.8 billion of debt at March 31, 2001.
Under PacifiCorp's principal credit agreements, it is an event of default if any person or group, other than ScottishPower, acquires 35% or more of PacifiCorp's common shares or if, during any period of 14 consecutive months, individuals who were directors of PacifiCorp on the first day of such period (and any new directors whose election or nomination was approved by such individuals and directors) cease to constitute a majority of the Board of Directors.
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BUSINESS RISK
The Company participates in a wholesale energy market that includes public utility companies, power and natural gas marketers, which may or may not be affiliated with public utility companies, government entities and other entities. The participants in this market trade not only electricity and natural gas as commodities but also derivative commodity instruments such as futures, swaps, options and other financial instruments. The pricing for this wholesale market is largely unregulated and most transactions are conducted on an "over-the-counter" basis, there being no central clearing mechanism (except in the case of specific instruments traded on the commodity exchanges).
The Company is subject to the various risks inherent in the energy business, including market risk, regulatory/political risk, credit risk and interest rate risk.
Market Risk
Market risk is, in general, the risk of fluctuations in the market price of electricity. Market price is influenced primarily by factors relating to supply and demand. Those factors include the adequacy of generating capacity, scheduled and unscheduled outages of generating facilities, hydroelectric availability, prices and availability of fuel sources for generation, disruptions or constraints to transmission facilities, weather conditions, economic growth, transmission capacity and other factors. The Company has been experiencing the adverse effect of higher market prices due to inadequate generating capacity in the WSCC, generating facility outages in the WSCC, including the unscheduled outage of the Company's Hunter unit, lower hydro availability, high natural gas prices and increases in demand throughout the WSCC due in large part to economic growth.
During 2001, significant price volatility, driven in part by the change in availability of resources and demand for energy throughout the WSCC, materially impacted the cost of meeting the Company's system load requirements. While the Company plans for resources to meet its current and expected retail and wholesale load obligations, resource availability, price volatility and load volatility may materially impact the power costs to the Company and profits from excess power sales in the future. Prices paid by the Company to provide certain load balancing resources to supply its load may continue to exceed the amounts it receives through retail rates and wholesale prices. The Company has filed applications seeking deferred accounting treatment for net power costs that vary from costs included in determining retail rates in the states of Utah, Idaho, Wyoming and Oregon. Approval of certain cost deferrals has been received in these states, and the Company is working with the commissions in these states to develop mechanisms for the recovery of these cost deferrals. Approval of deferred accounting treatment mitigates a portion of the price risk, assuming that recovery mechanisms are implemented as anticipated. The Company has recorded approved deferred amounts as regulatory assets. If recovery mechanisms are not implemented as anticipated, the Company would write off these regulatory assets. See Note 5 of Notes to the Consolidated Financial Statements under ITEM 8.
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Regulatory/Political Risk
The WSCC is experiencing extraordinary market conditions. Recent wholesale prices have greatly exceeded historical norms, reflecting high natural gas prices, low hydro conditions, unexpected generation outages and load growth, among other factors. Physical supply constraints have led to rolling blackouts in certain areas of the WSCC. None of the Company's service territory has experienced such severe constraints, although resources and demand in the region are in a tightly balanced condition. The region's turbulence and the financial troubles of the California energy market are drawing attention from various state and federal regulatory and political authorities. Numerous changes to the current operating structure have been proposed to address the region's issues. To date, no changes have been implemented that materially affect the Company's operations; however, the situation may change favorably or adversely in the future.
The Company is subject to the jurisdiction of federal and state regulatory authorities. The rates the Company may charge its retail customers are determined by these regulators. The rates authorized by the regulators may be less than the costs to the Company to provide electrical service to its customers.
Nearly all of the Company's hydroelectric projects are in some stage of relicensing under the FPA. The relicensing process is an extremely political and public regulatory process that involves controversial resource issues. The Company is unable to predict the requirements that may be imposed during the relicensing process, the economic impact of those requirements, whether new licenses will ultimately be issued or whether the Company will be willing to meet the relicensing requirements to continue operating its hydroelectric projects. For more information on hydroelectric relicensing, see "DOMESTIC ELECTRIC OPERATIONS - Regulation" under ITEM 1.
Federal, state and local authorities regulate many of the Company's activities pursuant to laws designed to restore, protect and enhance the quality of the environment. The Company is unable to predict what material impact, if any, future changes in environmental laws and regulations may have on the Company's consolidated financial position, results of operations, cash flows, liquidity, and capital expenditure requirements. For more discussion related to environmental issues, see "DOMESTIC ELECTRIC OPERATIONS - Environmental Issues" under ITEM 1.
Credit Risk
Credit risk relates to the risk of loss that might occur as a result of nonperformance by counterparties of their contractual obligations to deliver electricity and make financial settlements. Credit risk may be concentrated to the extent that one or more groups of counterparties have similar economic, industry or other characteristics that would cause their ability to meet contractual obligations to be similarly affected by changes in market or other conditions. In addition, credit risk includes not only the risk that a counterparty may default due to circumstances relating directly to it, but also the risk that a counterparty may default due to circumstances which relate to other market participants which have a direct or indirect
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relationship with such counterparty. The Company seeks to mitigate credit risk (and concentrations thereof) by applying specific eligibility criteria to prospective counterparties. However, despite mitigation efforts, defaults by counterparties occur from time to time. To date, no such default has had a material adverse effect on the Company. The Company continues to actively monitor the credit worthiness of those counterparties with whom it executes wholesale energy purchase and sales transactions within the WSCC, including those in California, and uses a variety of risk mitigation techniques to limit its exposure where it believes appropriate. At March 31, 2001, the Company had receivables of $1 million from SCE, a less than investment grade purchaser of power, $1 million from San Diego Gas and Electric Co., and no receivable directly from PG&E, a company that filed for Chapter 11 reorganization in April 2001. The Company has not taken specific reserves against these amounts. The Company, like all participants in the regional market, has exposure to other participants who may have credit exposure to the utilities in California. To mitigate exposure to the financial risks of these counterparties, the Company has entered into netting, margining and guarantee arrangements. The Company calculates reserves for all of its credit exposure by grouping counterparties, based upon managerial judgment and rating, and then calculating a reserve based upon a ratings agency historical default rate.
At March 31, 2001, the Company had no receivables related to its direct energy transactions with the CPX and a receivable of $6 million from the Cal ISO. The majority of this amount has been reserved based on the estimated amounts indirectly receivable from companies defaulting on payments to Cal ISO. Under default provisions contained in the CPX tariff, the CPX has charged back some of the defaults of CPX participants to remaining participants, including the Company, based upon the level of purchase and sales activity of each participant during the preceding three-month period. The Company has paid $2 million in charge-backs to the CPX related to SCE's default on its payments to the CPX. Subsequent to this payment, FERC ruled that charge-backs are not permissible. As a result of this FERC ruling, the Company has recorded a receivable and demanded a refund of this $2 million charge-back from the CPX.
Interest Rate Risk
The Company manages its debt requirements with a balance of short-term and long-term debt, with an expectation of limited issuance of new long-term debt. With increasing cash requirements resulting from maturities of long term debt and manditorily redeemable preferred stock, the unusually high purchased power prices and the impact of the Hunter plant outage on purchased power volumes, the Company is utilizing a growing amount of short-term debt until these costs are recovered from customers or longer term financing is completed. In January and February 2001, the Company's credit outlook was lowered by two credit rating agencies, citing the impact of high purchased power prices, the Hunter outage, and the uncertainty and expected delay between incurring and recovering the deferred power costs from customers. Any adverse change to the Company's credit rating could negatively impact the Company's ability to borrow and the interest rates that the Company is charged. The Company is currently seeking to replace its existing credit facility. The activity in the western electricity market has had a negative impact on the willingness of the financial markets to provide financing on conditions and at rates that have
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historically been available to the Company. While the Company believes this facility will be successfully replaced at interest rates marginally higher than historical rates, no assurances can be given as to this outcome.
RISK MANAGEMENT
Risk is an inherent part of the Company's business and activities. The risk management process established by the Company is designed to identify, assess, monitor and manage each of the various types of risk involved in its business and activities. Central to its risk management process, the Company has established a risk management committee with overall responsibility for establishing and reviewing the Company's policies and procedures for controlling and managing its risks. The senior risk management committee relies on the Company's treasury and risk management departments and its operating units to carry out its risk management directives and execute various hedging and energy purchase and sales strategies.
The risk management process established by the Company is designed to measure quantitative market risk exposure and identify qualitative market risk exposure in its businesses. To assist in managing the volatility relating to these exposures, the Company enters into various derivative transactions consistent with the Company's derivative policy. That policy governs the Company's use of derivative instruments and its energy purchase and sales practices and describes the Company's credit policy and management information systems required to effectively monitor such derivative use. The Company's derivative policy provides for the use of only those instruments that have a close correlation with its portfolio of assets, liabilities or anticipated transactions. The derivative policy includes as its objective that interest rate and foreign exchange derivative instruments will be used for hedging and not for speculation. The derivative policy also governs the energy purchase and sales activities and is generally designed for hedging the Company's existing energy and asset exposures.
RISK MEASUREMENT
Value at Risk Analysis
The tests discussed below for exposure to interest rate fluctuations are based on a Value at Risk ("VAR") approach using a one-year horizon and a 95% confidence level and assuming a one-day holding period in normal market conditions. The VAR model is a risk analysis tool that attempts to measure the potential losses in fair value, earnings or cash flow from changes in market conditions and does not purport to represent actual losses in fair value that may be incurred by the Company. The VAR model also calculates the potential gain in fair market value or improvement in earnings and cash flow associated with favorable market price movements.
Sensitivity Analysis
The Company measures its market risk related to its commodity price exposure positions by utilizing a variance sensitivity analysis. This sensitivity analysis measures the potential loss or gain in fair value, earnings or cash flow based on a hypothetical immediate 10% change (increase or decrease) in
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prices for its commodity derivatives. The fair value of such positions are a summation of the fair values calculated for each commodity derivative by valuing each position and option at quoted futures prices or assumed forward prices.
EXPOSURE ANALYSIS
Interest Rate Exposure
The Company may use interest rate swaps, forwards, futures and collars to adjust the characteristics of its liability portfolio. This strategy is consistent with the Company's capital structure policy which provides guidance on overall debt to equity and variable rate debt as a percent of capitalization levels for both the consolidated organization and its principal subsidiaries.
The Company's risk to interest rate changes is primarily a noncash fair market value exposure and generally not a cash or current interest expense exposure. This is due to the size of the Company's fixed rate, long-term debt portfolio relative to variable rate debt.
The table below shows the potential loss in fair market value ("FMV") of the Company's interest rate sensitive positions, for continuing operations, as of March 31, 2000 and 2001, as well as the Company's quarterly high and low potential losses.
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Commodity Price Exposure
The Company's market risk to commodity price change is primarily related to its electricity commodities which are subject to fluctuations due to unpredictable factors, such as weather, which impacts supply and demand. The Company's energy purchase and sales activities are governed by the derivative policy and the risk levels established as part of that policy.
The Company's energy commodity price exposure arises principally from its electric supply obligation in the United States. The Company manages this risk principally through the operation of its 7,832 MW generation and transmission system in the western United States and through its wholesale energy purchase and sales activities. Electricity futures contracts are utilized to hedge Domestic electric operations' excess or shortage of net electricity for future months. The changes in market value of such contracts have had a high correlation to the price changes of the hedged commodity.
Gains and losses relating to qualifying hedges of firm commitments or anticipated inventory transactions are deferred on the balance sheet and included in the basis of the underlying transactions.
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A sensitivity analysis has been prepared to estimate the Company's exposure to market risk related to commodity price exposure of its financial instrument derivative positions for electricity. Based on the Company's derivative price exposure at March 31, 2001 and 2000, a near-term adverse change in commodity prices of 10% would have no impact on 2001 pretax earnings and would negatively impact pretax earnings by $18 million in 2000. This decrease is a result of the sales of Australian electric operations and a subsidiary of Holdings in 2001.
INFLATION
Due to the capital-intensive nature of the Company's core businesses, inflation may have a significant impact on replacement of property, acquisition and development activities and final mine reclamation costs. To date, management does not believe that inflation has had a significant impact on any of the Company's other businesses.
NEW ACCOUNTING STANDARDS
The Company adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS No. 138, effective April 1, 2001. The statement requires that the Company recognize all derivatives, as defined in the statement, on the balance sheet at fair value. Derivatives, or any portion thereof, that are not an effective hedge, must be adjusted to fair value through income. If a derivative qualifies as an effective hedge, changes in the fair value of the derivative either will be offset against the change in fair value of the hedged asset, liability, or firm commitment recognized in earnings, or will be recognized in accumulated other comprehensive income until the hedged items are recognized in earnings.
Based on analysis to date, the Company expects that the most significant impact of complying with SFAS No. 133 will be the ongoing market adjustments to the income statement from wholesale purchase and sales activities that qualify for treatment as derivatives. Based on current interpretation of SFAS No. 133 and other guidance, the Company is classifying its wholesale forward contracts as follows:
- Normal Purchases and Sales: These forward contracts are excluded from the requirements of SFAS No. 133. The realized gains and losses on these contracts are reflected in the income statement at the contract settlement date. The wholesale contracts that generally qualify as normal purchases and sales are long term contracts that are not settled for cash.
- Cash Flow Hedge: The unrealized gains and losses related to these forward contracts will be included in accumulated other comprehensive income, a component of common shareholder's equity. Cash flow hedges are wholesale contracts for short-term purchases to cover probable load that may be settled for cash.
- Wholesale Purchases and Sales: The unrealized gains and losses related to these forward contracts will be reflected in the income statement. These contracts are the ones not classified as normal purchases and sales or cash flow hedges.
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Unrealized gains and losses from forward contracts represent the differences between the forward contract prices and the market prices at any given date until the final settlement of the contract. The realized gain or loss on the forward contract recorded at the contract settlement represents the difference between the contract price and actual cost of the commodity that was purchased or sold. On April 1, 2001, the Company expects to record the cumulative effects of adopting SFAS No. 133 in its financial statements by recording the following after-tax unrealized gains or losses on forward contracts as of April 1, 2001:
- - - Cumulative effect of a change in accounting principle:
- Income Statement: $113 million of unrealized loss;
- Other Comprehensive Income, a component of shareholders' equity:
$617 million of unrealized gain;
- - - FAS 133 Contract asset - net: $102 million; and
- - - Regulatory asset - net: $711 million
The volatility of the wholesale power market, continual changes in the types of forward contracts of the Company and certain issues that are still being addressed by the Financial Accounting Standards Board (the "FASB") Derivatives Implementation Group ("DIG") may impact the amounts that have been and will be recognized under SFAS No. 133. The estimated effect of adopting SFAS No. 133 on April 1, 2001 assumes that the Company will receive regulatory orders directing the deferral, as a regulatory asset or liability, of the effects of fair valuing long-term contracts that are included in the Company's rates.
The Company is required under SFAS No. 133 to classify certain of its sales and purchase contracts as derivatives. As a public utility, the Company's intent in entering into these contracts, generally, is to balance its electric load with available resources. When possible, the Company satisfies its load requirements with electricity from its owned generating facilities. While SFAS No. 133 requires fluctuations in market prices to be reflected in the income statement and accumulated other comprehensive income, the final impact of settling these contracts may be significantly different than represented in interim financial reports.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information required by this item is included under "Risk Management," and "Risk Measurement - Value at Risk Analysis," and "- Sensitivity Analysis," and "Exposure Analysis - Interest Rate Exposure," and "- Commodity Price Exposure" on pages 49 through 51 of this Report under ITEM 7.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
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REPORT OF MANAGEMENT
The management of PacifiCorp and its subsidiaries (the "Company") is responsible for preparing the accompanying consolidated financial statements and for their integrity and objectivity. The statements were prepared in accordance with generally accepted accounting principles. The financial statements include amounts that are based on management's best estimates and judgments. Management also prepared the other information in the annual report and is responsible for its accuracy and consistency with the financial statements.
The Company's financial statements were audited by PricewaterhouseCoopers LLP ("PricewaterhouseCoopers") with respect to the years ended March 31, 2001 and 2000, and by Deloitte & Touche LLP ("Deloitte & Touche") with respect to prior periods, both independent public accountants. Management made available to PricewaterhouseCoopers and Deloitte & Touche all the Company's financial records and related data, as well as the minutes of shareholders' and directors' meetings.
Management of the Company established and maintains an internal control structure that provides reasonable assurance as to the integrity and reliability of the financial statements, the protection of assets from unauthorized use or disposition and the prevention and detection of materially fraudulent financial reporting. The Company maintains an internal auditing program that independently assesses the effectiveness of the internal control structure and recommends possible improvements. PricewaterhouseCoopers and Deloitte & Touche considered that internal control structure in connection with their audits. Management reviews significant recommendations by the internal auditors, PricewaterhouseCoopers and Deloitte & Touche concerning the Company's internal control structure and ensures appropriate cost-effective actions are taken.
The Company's "Guide to Business Conduct" is distributed to employees throughout the Company to provide a basis for ethical standards and conduct. The guide addresses, among other things, potential conflicts of interests and compliance with laws, including those relating to financial disclosure and the confidentiality of proprietary information.
Alan V. Richardson
President and Chief Executive Officer
Karen K. Clark
Senior Vice President and Chief Financial Officer
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Report of Independent Accountants
To the Board of Directors and Shareholders of
PacifiCorp:
In our opinion, based on our audits and the report of other auditors, the accompanying consolidated balance sheets and the related statements of consolidated (loss) income, changes in common shareholders' equity and cash flows present fairly, in all material respects, the financial position of PacifiCorp and its subsidiaries at March 31, 2001 and 2000, and the results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We did not audit the financial statements of Pacificorp Australia Limited Liability Company and its subsidiaries, a wholly-owned subsidiary, which statements reflect total assets of $1,855,035,000 as of December 31, 1999, and total revenues of $617,563,000 for the year ended December 31, 1999. Those statements were audited by other auditors whose report thereon has been furnished to us, and our opinion expressed herein, insofar as it relates to the amounts included for Pacificorp Australia Limited Liability Company and its subsidiaries, is based solely on the report of the other auditors. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits and the report of other auditors provide a reasonable basis for our opinion.
PricewaterhouseCoopers LLP
Portland, Oregon
April 18, 2001
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INDEPENDENT AUDITORS' REPORT
To the Board of Directors and Shareholders of PacifiCorp:
We have audited the accompanying statements of consolidated (loss) income, consolidated changes in common shareholders' equity and consolidated cash flows of PacifiCorp and subsidiaries for the three months ended March 31, 1999 and the year ended December 31, 1998. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the consolidated results of operations and cash flows of PacifiCorp and subsidiaries for the three months ended March 31, 1999 and the year ended December 31, 1998, in conformity with accounting principles generally accepted in the United States of America.
DELOITTE & TOUCHE LLP
Portland, Oregon
February 11, 2000
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(See accompanying Notes to the Consolidated Financial Statements)
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(See accompanying Notes to the Consolidated Financial Statements)
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CONSOLIDATED BALANCE SHEETS
ASSETS
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LIABILITIES, REDEEMABLE PREFERRED STOCK AND SHAREHOLDERS' EQUITY
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STATEMENTS OF CONSOLIDATED CHANGES IN COMMON SHAREHOLDERS' EQUITY
Millions of dollars, Thousands of shares
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Years ended March 31, 2001 and 2000, December 31, 1998
and the three months ended March 31, 1999
NOTE 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
BASIS OF PRESENTATION
The consolidated financial statements of PacifiCorp and its subsidiaries (the "Company" or "Companies") include the integrated domestic electric utility operating divisions of Pacific Power and Utah Power and its wholly-owned and majority-owned subsidiaries. Major subsidiaries, all of which are wholly-owned, are: PacifiCorp Group Holdings Company ("Holdings"), which held directly or through its wholly-owned subsidiary, PacifiCorp International Group Holdings Company, all of the Company's nonintegrated electric utility investments, including Powercor Australia Ltd. ("Powercor"), an Australian electricity distributor, until its sale on September 6, 2000 (see Note 17), and includes PacifiCorp Financial Services, Inc. ("PFS"), a financial services business. Significant intercompany transactions and balances have been eliminated upon consolidation.
Investments in and advances to affiliated companies represent investments in unconsolidated affiliated companies carried on the equity basis, which approximates the Company's equity in their underlying net book value.
In March 2001, the Company transferred its interest in two nonregulated energy companies to an affiliated entity, PacifiCorp Holdings, Inc. ("PHI"). See Note 17.
During October 1998, the Company decided to exit its energy trading business, which consisted of TPC Corporation ("TPC") and the eastern United States electricity trading operations of PacifiCorp Power Marketing, Inc. ("PPM"), which was accounted for as discontinued operation. On April 1, 1999, the Company sold TPC. See Note 4.
During May 1998, the Company sold a majority of the real estate assets held by PFS. In 1998, the Company also decided to exit the majority of its other energy development businesses and recorded them at estimated net realizable value less selling costs in September 1998. See Note 17.
CONCENTRATION OF CUSTOMERS
During 2001, no single retail customer accounted for more than 2% of the Company's Domestic electric operations' retail utility revenues and the 20 largest retail customers accounted for 15% of total retail electric revenues. The geographical distribution of the Company's Domestic electric operations' retail operating revenues for the year ended March 31, 2001 was Utah, 38%; Oregon, 33%; Wyoming, 13%; Washington, 8%; Idaho, 6%; and California, 2%.
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CHANGE IN FISCAL YEAR
On November 29, 1999, the Company and Scottish Power plc ("ScottishPower") completed a merger under which the Company became an indirect subsidiary of ScottishPower (the "Merger"). As a result of the Merger, the Company's year end is March 31. See Note 2. The years ended March 31, 2001 and 2000 and quarterly periods within those years are referred to as 2001 and 2000, respectively. References to future years are to years ending March 31. The year ended December 31, 1998 is referred to as 1998. Australian electric operation's year end remained December 31. Consequently, the Company's statements of consolidated income and consolidated cash flows as of and for the year ended March 31, 2001 include Australian electric operation's financial statements for the period from January 1, 2000 to the dates of sale. In accordance with guidelines of the Securities and Exchange Commission (the "SEC"), twelve months of income and expense for Australian electric operations were included in the consolidated statement of income for 2000. Australian electric operation's results of operations for the three months ended March 31, 1999 reported in the Company's transition period were recorded as a deduction to retained earnings in 2000, and cash flow activity for the same period was reflected within "Other" in the operating activities section of the consolidated statement of cash flows.
USE OF ESTIMATES
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements. Actual results could differ from those estimates.
REGULATION
Accounting for the domestic electric utility business conforms with generally accepted accounting principles as applied to regulated public utilities and as prescribed by agencies and the commissions of the various locations in which the domestic electric utility business operates. The Company prepares its financial statements as they relate to Domestic electric operations in accordance with Statement of Financial Accounting Standards ("SFAS") No. 71, "Accounting for the Effects of Certain Types of Regulation." See Note 5.
ASSET IMPAIRMENTS
Long-lived assets to be held and used by the Company are reviewed for impairment when events or circumstances indicate costs may not be recoverable. Such reviews are performed in accordance with SFAS No. 121. The impacts of regulation on cash flows are considered when determining impairment. Impairment losses on long-lived assets are recognized when book values exceed expected undiscounted future cash flows with the impairment measured on a discounted future cash flows basis.
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CASH AND CASH EQUIVALENTS
For the purposes of these financial statements, the Company considers all liquid investments with maturities of three months or less at the time of acquisition to be cash equivalents.
RELATED PARTY TRANSACTIONS
At March 31, 2001 and 2000, the Company had $14 million and $5 million, respectively, of accrued liabilities payable to ScottishPower. These liabilities primarily represent costs incurred by ScottishPower employees employed as Company management and ScottishPower employees who were temporarily working for the Company on its transition plan. In addition, at March 31, 2001, the Company had a $370 million note and related accrued interest receivable from a directly owned subsidiary of ScottishPower. Interest income on the note was $14 million during 2001.
At March 31, 2001, the Company had $5 million of accrued liabilities payable to PHI. In addition, at March 31, 2001, the Company had $74 million in accounts and notes receivable from PHI. At March 31, 2000, the Company had no amounts payable to or receivable from PHI.
Interest rates on related party borrowings approximate lender's cost of capital and are reset at 30-day intervals. The applicable rates at March 31, 2001 ranged from 5.08% to 5.23%.
ALLOWANCE FOR DOUBTFUL ACCOUNTS
The Company provided $11 million, $22 million and $16 million for doubtful accounts in 2001, 2000 and 1998, respectively. Write-offs of uncollectible accounts were $11 million, $19 million and $17 million in 2001, 2000 and 1998, respectively.
INVENTORY VALUATION
Inventories, consisting of $68 million and $57 million of fuel, and $93 million and $121 million of material and supplies, at March 31, 2001 and 2000, respectively, are generally valued at the lower of average cost or market.
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment are stated at original cost of contracted services, direct labor and materials, interest capitalized during construction and indirect charges for engineering, supervision and similar overhead items. The cost of depreciable domestic electric utility properties retired, including the cost of removal, less salvage, is charged to accumulated depreciation. The costs of planned major maintenance activities are accounted for as the costs are incurred. Planned major maintenance activities include scheduled overhauls at generation plants. Other repair and maintenance costs for property, plant and equipment are also accounted for as incurred.
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DEPRECIATION AND AMORTIZATION
At March 31, 2001, the average depreciable lives of property, plant and equipment by category for Domestic electric operations were: Production, 41 years; Transmission, 58 years; Distribution, 42 years and Other, 20 years.
Depreciation and amortization is generally computed by the straight-line method in one of the following two manners, either as prescribed by the Company's various regulatory jurisdictions for Domestic electric operations' regulated assets, or over the assets' estimated useful lives. Provisions for depreciation (excluding amortization of capital leases) in the Domestic electric and Australian electric businesses were 3.1%, 3.2% and 3.3% of average depreciable assets in 2001, 2000 and 1998, respectively.
INTANGIBLE ASSETS
Intangible assets consisted of license and other intangible costs relating to Australian electric operations ($395 million and $31 million, respectively, at March 31, 2000). These costs were offset by accumulated amortization ($43 million at March 31, 2000). Licenses and other intangible costs were generally being amortized over 40 years. Intangible assets of $343 million were written off in 2001 due to the sale of Australian electric operations.
FINANCE ASSETS
Finance assets consist of finance receivables, leveraged leases and operating leases and are not significant to the Company in terms of revenue or net income. The Company's leasing operations consist principally of leveraged aircraft leases. Investments in finance assets are net of accumulated impairment charges and allowances for credit losses of $43 million and $35 million at March 31, 2001 and 2000, respectively. The Company provided $7 million, $11 million and zero for impairment charges and credit losses in 2001, 2000 and 1998, respectively. Write-offs for impairment charges and credit losses were zero, $2 million and $20 million in 2001, 2000 and 1998, respectively.
DEFERRED CHARGES AND OTHER
Deferred Charges and Other are comprised primarily of funds held in trust for the final reclamation of a leased coal mining property, unamortized debt expense, long term customer loans and receivables, certain employee benefit plan assets, and net amounts for corporate owned life insurance.
The Company maintains a trust relating to final reclamation of a leased coal mining property. Amounts funded are based on estimated future reclamation costs and estimated future coal deliveries. In both 2001 and 2000, the Company reviewed funding requirements based on estimated future gains and interest earnings on trust assets and the projected future reclamation liability. The Company determined that no funding was required for both 2001 and 2000. Securities held in the reclamation trust fund are recorded at market value in accordance with SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities." See Note 11. Trust assets include debt and equity
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securities classified as available for sale. Securities available for sale are carried at fair value with net unrealized gains or losses excluded from income and reported as accumulated other comprehensive income, a component of shareholders' equity. Realized gains or losses are determined on the specific identification method.
ENVIRONMENTAL COSTS, MINE RECLAMATION AND CLOSURE COSTS
The Company's mining operations are subject to reclamation and closure requirements. The Company monitors these requirements and periodically revises its cost estimates to meet existing legal and regulatory requirements of the various jurisdictions in which it operates. The Company expenses current mine reclamation costs. Costs for reclamation are accrued using the units-of-production method such that estimated final mine reclamation and closure costs are fully accrued at completion of mining activities, except where the Company has decided to close a mine. When a mine is closed, the Company records the estimated cost to complete the mine closure and seeks recovery of any incremental costs through rates. The Company believes that it has adequately provided for its reclamation obligations, assuming ongoing operations of its mines. Total estimated final reclamation costs, including the Company's and minority interest joint owners' portions, for all mines with which the Company is involved was $190 million at March 31, 2001. These amounts are expected to be paid over the next 40 years.
The liabilities for environmental clean-up related costs are generally recorded on an undiscounted basis. These liabilities are recorded in the balance sheet in "Deferred Credits - Other" at March 31, 2001 and 2000 as follows:
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(b) At March 31, 2000, the Company had approximately $26 million accrued for its share of the Centralia mine reclamation costs. These reclamation costs were assumed by the buyer as a condition of the sale. See Note 17.
(c) Expected to be paid over 19 years.
(d) Expected to be paid over 22 years.
The Company had trust fund assets of $85.1 million and $100.5 million at March 31, 2001 and 2000, respectively, relating to mine reclamation, including minority interest joint owners' portion.
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INTEREST CAPITALIZED
Costs of debt and equity applicable to domestic electric utility properties are capitalized during construction. The composite capitalization rates were 7.3% for 2001, 7.9% for 2000 and 5.7% for 1998.
INCOME TAXES
The Company uses the liability method of accounting for deferred income taxes. Deferred tax liabilities and assets reflect the expected future tax consequences, based on enacted tax law, of temporary differences between the tax bases of assets and liabilities and their financial reporting amounts.
Prior to 1980, Domestic electric operations did not provide deferred taxes on many of the timing differences between book and tax depreciation. In prior years, these benefits were flowed through to the utility customer as prescribed by the Company's various regulatory jurisdictions. Deferred income tax liabilities and regulatory assets have been established for those flow through tax benefits. See Note 15.
Investment tax credits for regulated Domestic electric operations are deferred and amortized to income over periods prescribed by the Company's various regulatory jurisdictions.
Provisions for United States income taxes were made on the undistributed earnings of the Company's international businesses.
FOREIGN CURRENCY
Until sold, financial statements for foreign subsidiaries were translated into United States dollars at end of period exchange rates as to assets and liabilities and weighted average exchange rates as to revenues and expenses. The resulting translation gains or losses were accumulated in the "accumulated other comprehensive income" account, a component of common equity and comprehensive income. All gains and losses resulting from foreign currency transactions are included in the determination of net income.
DERIVATIVES
Gains and losses on hedges of existing assets and liabilities are included in the carrying amounts of those assets or liabilities and are recognized in income as part of the carrying amounts. Gains and losses relating to hedges of anticipated transactions and firm commitments are deferred on the balance sheet and recognized in income when the transaction occurs. Nonhedged derivative instruments are marked-to-market with gains or losses recognized in the determination of net income.
The derivative policy includes as its objective that interest rates and foreign exchange derivative instruments will be used for hedging and not for speculation. The derivative policy also governs the energy purchase and sales activities and is generally designed for hedging the Company's existing load and asset exposures.
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REVENUE RECOGNITION
The Company accrues estimated unbilled revenues for electric services provided after cycle billing to month-end.
COMPREHENSIVE INCOME
As permitted by SFAS No. 130, "Reporting Comprehensive Income," the Company has not included a statement of comprehensive income. Instead the Company included the amounts on the Statement of Consolidated Changes in Common Shareholders' Equity.
ENERGY TRADING
Revenues and purchased energy expense for PPM's energy trading and marketing activities are recorded upon settlement of transactions. Beginning January 1, 1999, in accordance with Emerging Issues Task Force ("EITF") 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities," PPM applied mark-to-market accounting for all energy trading activities and presents the net margin in revenues. The energy trading activities were transferred to an affiliated company in 2001. See Note 17.
PREFERRED STOCK RETIRED
Amounts paid in excess of the net carrying value of preferred stock retired are amortized over five years in accordance with regulatory orders.
STOCK BASED COMPENSATION
As permitted by SFAS No. 123, "Accounting for Stock Based Compensation," the Company has elected to follow Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" ("APB 25") and related interpretations in accounting for employee stock options issued to Company employees. Under APB 25, because the exercise price of employee stock options equals the market price of the underlying stock on the date of grant, no compensation expense is recorded. Upon completion of the Merger, PacifiCorp stock is no longer being issued for compensatory purposes. See Notes 2 and 16.
NEW ACCOUNTING STANDARDS
The Company adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS No. 138, effective April 1, 2001. The statement requires that the Company recognize all derivatives, as defined in the statement, on the balance sheet at fair value. Derivatives, or any portion thereof, that are not an effective hedge, must be adjusted to fair value through income. If a derivative qualifies as an effective hedge, changes in the fair value of the derivative either will be offset against the change in fair value of the hedged asset, liability, or firm commitment recognized in earnings, or will be recognized in accumulated other comprehensive income until the hedged items are recognized in earnings.
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Based on analysis to date, the Company expects that the most significant impact of complying with SFAS No. 133 will be the ongoing market adjustments to the income statement from wholesale purchase and sales activities that qualify for treatment as derivatives. Based on current interpretation of SFAS No. 133 and other guidance, the Company is classifying its wholesale forward contracts as follows:
- Normal Purchases and Sales: These forward contracts are excluded from the requirements of SFAS No. 133. The realized gains and losses on these contracts are reflected in the income statement at the contract settlement date. The wholesale contracts that generally qualify as normal purchases and sales are long term contracts that are not settled for cash.
- Cash Flow Hedge: The unrealized gains and losses related to these forward contracts will be included in accumulated other comprehensive income, a component of common shareholder's equity. Cash flow hedges are wholesale contracts for short-term purchases to cover probable load that may be settled for cash.
- Wholesale Purchases and Sales: The unrealized gains and losses related to these forward contracts will be reflected in the income statement. These contracts are the ones not classified as normal purchases and sales or cash flow hedges.
Unrealized gains and losses from forward contracts represent the differences between the forward contract prices and the market prices at any given date until the final settlement of the contract. The realized gain or loss on the forward contract recorded at the contract settlement represents the difference between the contract price and actual cost of the commodity that was purchased or sold. On April 1, 2001, the Company expects to record the cumulative effects of adopting SFAS No. 133 in its financial statements by recording the following after-tax unrealized gains or losses on forward contracts as of April 1, 2001:
- - - Cumulative effect of a change in accounting principle:
- Income Statement: $113 million of unrealized loss;
- Other Comprehensive Income, a component of shareholders' equity:
$617 million of unrealized gain;
- - - FAS 133 Contract asset - net: $102 million; and
- - - Regulatory asset - net: $711 million
The volatility of the wholesale power market, continual changes in the types of forward contracts of the Company and certain issues that are still being addressed by the Financial Accounting Standards Board (the "FASB") Derivatives Implementation Group ("DIG") may impact the amounts that have been and will be recognized under SFAS No. 133. The estimated effect of adopting SFAS No. 133 on April 1, 2001 assumes that the Company will receive regulatory orders directing the deferral, as a regulatory asset or liability, of the effects of fair valuing long-term contracts that are included in the Company's rates.
The Company is required under SFAS No. 133 to classify certain of its sales and purchase contracts as derivatives. As a public utility, the Company's intent in entering into these contracts, generally, is to balance its electric
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load with available resources. When possible, the Company satisfies its load requirements with electricity from its owned generating facilities. While SFAS No. 133 requires fluctuations in market prices to be reflected in the income statement and accumulated other comprehensive income, the final impact of settling these contracts may be significantly different than represented in interim financial reports.
RECLASSIFICATION
Certain amounts from prior years have been reclassified to conform with the 2001 method of presentation. These reclassifications had no effect on previously reported consolidated net income.
NOTE 2 SCOTTISHPOWER MERGER
On November 29, 1999, the Company and ScottishPower completed the Merger under which the Company became an indirect subsidiary of ScottishPower. The Company continues to operate under its current name, and its headquarters remains in Portland, Oregon. As a result of the Merger, the Company became part of a public utility holding company group. The Company's operations are now subject to the requirements and restrictions of the Public Utility Holding Company Act of 1935.
Each share of the Company's common stock was converted tax-free into a right to receive 0.58 American Depositary Shares ("ADS") (each ADS represents four ordinary shares) or 2.32 ordinary shares of ScottishPower. Cash was paid in lieu of fractional shares.
The following table shows where merger costs have been recorded in the Company's financial results.
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As a result of the Merger, the Company has implemented a transition plan (the "Transition Plan") with significant organizational and operational changes. The Company expects to reduce its workforce company-wide by approximately 1,600 from 1998 levels over a five-year period ending in 2005, mainly through early retirement, voluntary severance and attrition. The estimated early retirement and severance costs are being deferred and amortized over future periods, as ordered by the various utility commission accounting orders received by the Company. The Company recorded $158 million in regulatory assets and $17 million in deferred charges as a result of the accounting orders issued by state regulatory bodies for these estimated costs. As of March 31, 2001, the Company had $63 million of accrued liabilities in deferred credits - other relating to these early retirement and severance costs. Below is a summary of the accrual recorded and payments made during 2001 related to the deferred costs described above.
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NOTE 3 BID FOR THE ENERGY GROUP
During 1997 and 1998, the Company sought to acquire The Energy Group PLC ("TEG"), a diversified international energy group with operations in the United Kingdom, the United States and Australia. In March 1998, another United States utility made a tender offer at a price higher than the Company's offer and on April 30, 1998, the Company announced that it would not increase its revised offer for TEG.
The Company recorded an $89 million pretax charge ($55 million after-tax) to 1998 earnings, included in "TEG costs," for bank commitment and facility fees, foreign currency option contract expense, legal expenses and other related costs incurred since the Company's original bid for TEG in June of 1997. These costs had been deferred pending the outcome of the transaction.
Additionally, in connection with the attempt to acquire TEG, a subsidiary of the Company purchased approximately 46 million shares of TEG at a price of 820 pence per share, or $625 million. The Company recorded a pretax gain on the TEG shares of $16 million ($10 million after-tax), included in "TEG costs," when they were sold on June 2, 1998.
NOTE 4 DISCONTINUED OPERATIONS
In October 1998, the Company decided to exit its energy trading business by offering for sale TPC, and ceasing PPM's electricity trading operations conducted in the eastern United States. PPM's activities in the eastern United States have been discontinued and all the related forward electricity trading
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has been closed. On April 1, 1999, Holdings sold TPC to NIPSCO Industries, Inc. for $150 million. Exiting these energy trading activities resulted in a net after-tax gain of $1 million in the first quarter of 2000.
During the year ended December 31, 1998, PPM's eastern energy trading and TPC generated revenues of $2.96 billion. The loss from those discontinued operations was $42 million, net of taxes of $24 million, and the loss on disposal was $105 million, net of income tax benefit of $50 million and $52 million of provision for operating losses during phase-out period. Net loss from discontinued operations for the year ended December 31, 1998 was $147 million.
At March 31, 2001 and 2000, Holdings had $8 million and $15 million, respectively, of liabilities in "Customer deposits and other" relating to discontinued operations.
NOTE 5 ACCOUNTING FOR THE EFFECTS OF REGULATION
Regulated utilities have historically applied the provisions of SFAS No. 71 which is based on the premise that regulators will set rates that allow for the recovery of a utility's costs, including cost of capital. Accounting under SFAS No. 71 is appropriate as long as: rates are established by or subject to approval by independent, third-party regulators; rates are designed to recover the specific enterprise's cost-of-service; and in view of demand for service, it is reasonable to assume that rates are set at levels that will recover costs and can be collected from customers. In applying SFAS No. 71, the Company must give consideration to changes in the level of demand or competition during the cost recovery period. In accordance with SFAS No. 71, Domestic electric operations capitalizes certain costs as regulatory assets in accordance with regulatory authority whereby those costs will be expensed and recovered in future periods.
The EITF of the FASB concluded in 1997 that SFAS No. 71 should be discontinued when detailed legislation or regulatory orders regarding competition are issued. Additionally, the EITF concluded that regulatory assets and liabilities applicable to businesses being deregulated should be written off unless their recovery is provided for through future regulated cash flows. The Company continuously evaluates the appropriateness of applying SFAS No. 71 to each of its jurisdictions. At March 31, 2001, management concluded that SFAS No. 71 was appropriate for its Domestic electric operations. However, if efforts to deregulate progress, the Company may in the future be required to discontinue its application of SFAS No. 71 to all or a portion of its business.
The Company is subject to the jurisdiction of public utility regulatory authorities of each of the states in which it conducts retail electric operations as to prices, services, accounting, issuance of securities and other matters. The jurisdictions in which the Company operates are in various stages of evaluating deregulation. At present, the Company is subject to cost based rate making for its Domestic electric operations business. The Company is a "licensee" and a "public utility" as those terms are used in the Federal Power Act (the "FPA") and is, therefore, subject to regulation by the Federal
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Energy Regulatory Commission (the "FERC") as to accounting policies and practices, certain prices and other matters.
Regulatory assets include the following:
March 31/Millions of dollars | 2001 | 2000 |
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(a) Excludes $107 million and $115 million as of March 31, 2001 and 2000, respectively, of investment tax credit regulatory liabilities.
(b) Represents the unamortized amount of retirement and severance costs related to the Transition Plan that the state commissions allowed to be deferred and amortized. Recovery of the amortization is being sought in the general rate cases.
(c) Represents the deferred net power costs that vary from costs included in determining retail rates in the states of Utah, Oregon, Idaho and Wyoming. The Company anticipates that it will get recovery of these costs.
(d) Additional losses on debt reacquired in 2001 offset the amortization recorded during that year.
(e) A UPSC order during 2001 allowed recovery of early retirement and pension costs, reclamation costs, and Year 2000 and other information system costs that had previously been written off.
Regulatory liabilities include the following:
March 31/Millions of dollars | 2001 | 2000 |
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(a) Represents the gain on the sale of the Centralia plant and mine that is being returned to customers as ordered by the state commissions in connection with approving the sale. The gain amounts claimed by the jurisdictions the Company serves exceeded the actual gain on the transaction by $14 million resulting in a loss on sale that was recorded in Other operating income.
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The Company evaluates the recovery of all regulatory assets annually. The evaluation includes the probability of recovery as well as changes in the regulatory environment. Because of the potential regulatory and/or legislative action in Utah, Oregon, Wyoming, Idaho and Washington, the Company may have regulatory asset write-offs and charges for impairment of long-lived assets in future periods. Impairment would be measured in accordance with the Company's asset impairment policy. See Note 1.
DEPRECIATION RATE INCREASE
During 1998, the Company filed new depreciation rates in the states of Oregon, Utah and Wyoming based upon a depreciation study. New depreciation rates were filed in Washington as part of a general rate case filing. New depreciation rates were approved by the commissions during 2000. The impact of the proposed changes in depreciation is being incorporated into the current general rate cases in Utah, Oregon and Wyoming. Based on the depreciation rates that have been approved, annual depreciation expense would be increased by approximately $20 million. The increase in depreciation expense is primarily due to revisions of the estimated costs of removal for steam production and distribution plants. For the period April 1, 2000 to March 31, 2002, the Utah and Wyoming commissions have ordered a reversal of a portion of previously accrued depreciation. These reversals in total, for both states, will amount to approximately $14 million per year for two years.
MERGER CREDITS
As a result of the Merger, the Company is required to provide benefits to rate payers through fixed reductions in rates or "Merger Credits." The Company's total obligation for merger credits is $133.4 million through the period ending December 31, 2004. A portion of this amount must be provided without offset or reduction of any kind and, accordingly, the Company recorded $57.2 million as a liability and current expense in its financial statements for the year ended March 31, 2000. In the second quarter of 2001, the Company recorded $12 million as a liability and current expense in relation to the August 9, 2000 order from the WUTC, which impacted the Company's ability to offset merger credits in the future. See Note 2. The remaining $64.2 million obligation of the Company with respect to merger credits is subject to possible offset if the Company demonstrates in a future rate case, to the satisfaction of the respective commissions, that merger-related cost reductions have occurred and are being reflected in rates. This $64.2 million obligation will be reflected in future periods.
RATE INCREASES GRANTED
On October 25, 2000, the WUTC approved the Company's application for a system benefits charge to recover costs associated with funding energy efficiency programs. The Company will collect approximately $2.8 million per year through December 31, 2002.
On September 27, 2000, the Company received an order from the OPUC authorizing increased prices in Oregon for residential customers of 2.33%, commercial and small industrial customers of 1.37%, large industrial customers of 0.4%, and
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public street lighting customers of 1.27%. These price increases are expected to result in annual revenues of $14 million. The order was effective on October 1, 2000.
On August 9, 2000, the Company received an order from the WUTC that authorized the Company to increase rates by 3% on September 1, 2000, 3% on January 1, 2002 and 1% on January 1, 2003.
On June 20, 2000, the Company received approval from the OPUC for an overall price increase of 1.8%, or $13.7 million, through an annual adjustment as part of the alternative form of regulation ("AFOR") process previously authorized in Oregon. Of this amount, approximately $10 million is offset by costs mandated by regulators. The increase will cause rates for residential customers to rise by 2.9%, for large industrial users by 1.1%, and for commercial customers by 0.5%. The new rates took effect July 1, 2000 and are expected to increase annual revenues by approximately $3.7 million net of costs mandated by the OPUC. The AFOR is authorized to run through June 30, 2001. Existing rates in Oregon will continue unchanged after the AFOR's termination until new rates are authorized by the OPUC.
On May 25, 2000, the Company received an order from the WPSC authorizing an increase in prices, which is expected to result in increased annual revenues of $11 million. The Company received authorization for an additional $1 million increase effective July 19, 2000.
On May 24, 2000, the Company received an order from the UPSC authorizing increased prices in Utah for residential, irrigation, small commercial and lighting customers of 4.24% and large commercial and industrial customers of less than 1%. These price increases are expected to result in additional annual revenues of $17 million. The order was effective on May 25, 2000 and allowed recovery of early retirement and pension costs, reclamation costs, and Year 2000 and other information systems costs that had previously been written off. As a result, $17 million in regulatory assets was established in the first quarter of 2001 relating to cost recoveries which required no additional review and $25 million in regulatory assets was established in the second quarter of 2001 relating to cost recoveries which successfully passed additional review. An additional $7 million may be recovered in future periods following further review.
DEFERRED POWER COST FILINGS
On November 1, 2000, the Company filed applications seeking deferred accounting treatment for net power costs that vary from costs included in determining retail rates in the states of Utah, Idaho, Wyoming, and Oregon. The applications sought to defer these power cost variances beginning November 1, 2000.
Subsequent to the November 1, 2000 filings, the Company's Hunter power plant in Utah experienced a failure of a 430 megawatt ("MW") generation unit. Since the commencement of the outage, the cost of power purchases to replace the output of the Hunter unit has exceeded that unit's costs included in current rates.
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The Utah deferred accounting filing originally encompassed all power costs that vary from the level assumed in Utah rates since November 1, 2000. In light of the Company's January 12, 2001 Utah rate increase request, which included recovery of the power cost variances not related to the Hunter outage, the Utah deferred accounting filing was effectively amended by stipulation to include only the cost variances associated with the Hunter outage. Hunter deferred accounting was adopted by the Commission effective November 24, 2000, the date the outage began. During 2001, the Company has deferred $79 million relating to the Utah approval of the power cost variances related to Hunter.
The Oregon deferred accounting filing encompassed all power costs that vary from the level in Oregon rates since November 1, 2000, including costs to replace lost generation resulting from the Hunter outage. On January 18, 2001, the Company requested a 3%, or $23 million, rate increase effective February 1, which would provide partial recovery of post-October 31, 2000 power cost variances attributable to Oregon over an amortization period. This 3% rate increase is the maximum allowed for deferred costs under the Oregon statutes. On January 23, 2001, the OPUC authorized deferred accounting for power costs of $23 million. The Company has deferred the $23 million as of March 31, 2001. On February 20, 2001, the OPUC authorized the 3% rate increase effective February 21, 2001.
On February 12, 2001, the IPUC approved the Company's deferred accounting filing for all power costs that vary from the level assumed in Idaho rates for the period November 1, 2000 through October 31, 2001, including costs to replace lost generation resulting from the Hunter unit outage. The Company has deferred $11 million related to this approval as of March 31, 2001.
Approval for deferral of power costs that vary from rate assumptions was received from the WPSC on November 30, 2000. The Company is currently working with the WPSC to develop a power cost adjustment mechanism for recovery of these deferred amounts. During 2001, $27 million of power costs were deferred, which encompassed all net purchased power costs that varied from the level in Wyoming rates since November 30, 2000, including costs to replace lost generation resulting from the Hunter unit outage.
NOTE 6 SPECIAL CHARGES
In January 1998, the Company announced a plan to reduce its work force in the United States by approximately 600 positions, or 7% of the work force in the United States. The Company offered enhanced early retirement to approximately 1,200 employees. The actual net work force reduction from this program was 759 positions, with 981 employees accepting the offer and 222 vacated positions backfilled. The pretax cost of $113 million ($70 million after-tax) was recorded in March 1998.
In the fall of 1998, the Company initiated a cost reduction program that included involuntary employee severance and enhanced early retirement for employees who met certain age and service criteria and were displaced in conjunction with the cost reduction initiatives. Approximately 167 employees were displaced, with 35 of them eligible for the enhanced early retirement, and the Company recorded a $10 million ($6 million after-tax) expense in special charges.
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Below is a summary of the accrual recorded and payments made during 1998 relating to the work force reduction initiatives described above.
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As of March 31, 2001, substantially all of the remaining obligations relating to work force reduction initiatives had been satisfied.
NOTE 7 SHORT-TERM DEBT AND BORROWING ARRANGEMENTS
PacifiCorp's short-term debt and borrowing arrangements were as follows:
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(a) Computed by dividing the total interest on principal amounts outstanding at the end of the period by the weighted daily principal amounts outstanding.
At March 31, 2001, commercial paper and bank line borrowings were supported by a $500 million revolving credit agreement, which expires in August 2001. The Company is currently seeking to replace the existing credit facility.
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NOTE 8 LONG-TERM DEBT
The Company's long-term debt was as follows:
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(a) Pollution control revenue bonds of $71 million are secured by pledged first mortgage bonds generally at the same interest rates, maturity dates and redemption provisions as the pollution control revenue bonds.
(b) Interest rates fluctuate based on various rates, primarily on certificate of deposit rates, interbank borrowing rates, prime rates or other short-term market rates.
(c) In November 2000, the Company redeemed its Junior subordinated debentures with a portion of the proceeds from the Powercor sale.
(d) The March 31, 2000 balance included debt of Australian subsidiaries of $412 million and long-term debt of Holdings of $250 million. In July 2000, Holdings paid off the $250 million of debt in anticipation of the Powercor sale. The Australian debt was assumed by the buyer as a condition of the sale.
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(e) Interest rates fluctuated based on Australian Bank Bill Acceptance Rates. A revolving loan agreement required that at least 50% of the borrowings must be hedged against variations in interest rates. Approximately $413 million was hedged at March 31, 2000 at an average rate of 7% and for an average life of 4.5 years. The Companies had the ability to support short-term borrowings and current debt being refinanced on a long-term basis through revolving lines of credit and, therefore, based upon management's intent, had classified $429 million of short-term debt as long-term debt at March 31, 2000. The Australian bank bill borrowings and commercial paper were assumed by the buyer as a condition of the sale.
First mortgage bonds of the Company may be issued in amounts limited by Domestic electric operations' property, earnings and other provisions of the mortgage indenture. Approximately $11 billion of the eligible assets (based on original cost) of PacifiCorp are subject to the lien of the mortgage. Approximately $700 million of first mortgage bonds were callable at March 31, 2001 at redemption prices dependent upon U.S. Treasury yields. Approximately $665 million of pollution control revenue bonds were callable at March 31, 2001 at redemption prices ranging from 100% to 103% based on the series and redemption dates. Subsidiary notes are callable at face amount. The remaining long-term debt was not callable at March 31, 2001.
The junior subordinated debentures were unsecured obligations of the Company and were subordinated to the Company's first mortgage bonds, pollution control revenue bonds, commercial paper, bank debt and any future senior indebtedness.
The annual maturities of long-term debt, capitalized lease obligations and redeemable preferred stock outstanding are $151 million, $155 million, $140 million, $244 million and $289 million in 2002 through 2006, respectively.
The Company made interest payments, net of capitalized interest, of $337 million, $402 million, $116 million and $444 million in 2001, 2000, the three months ended March 31, 1999, and the year 1998, respectively.
NOTE 9 GUARANTEED PREFERRED BENEFICIAL INTERESTS IN
COMPANY'S JUNIOR SUBORDINATED DEBENTURES
Wholly-owned subsidiary trusts of the Company (the "Trusts") have issued, in public offerings, redeemable preferred securities ("Preferred Securities") representing preferred undivided beneficial interests in the assets of the Trusts, with liquidation amounts of $25 per Preferred Security. The sole assets of the Trusts are Junior Subordinated Deferrable Interest Debentures of the Company that bear interest at the same rates as the Preferred Securities to which they relate, and certain rights under related guarantees by the Company.
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Preferred Securities outstanding were as follows:
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NOTE 10 COMMON AND PREFERRED STOCK
The Company has one class of common stock with no par value. A total of 750,000,000 shares were authorized and 297,324,604 were issued and outstanding at March 31, 2001 and 2000.
Common Dividend Restrictions - ScottishPower is the sole indirect shareholder of the Company's common stock. The Company is restricted from paying dividends or making other distributions to ScottishPower without prior OPUC approval to the extent such payment or distribution would reduce the Company's common stock equity below a specified percentage of its total capitalization. The percentage of total capitalization increases over time from 35% after December 31, 1999 to 40% after December 31, 2004. In addition, the Company must give the OPUC 30 days prior notice of any special cash dividend or any transfer involving more than five percent of PacifiCorp's retained earnings in a six-month period. The Company is also subject to maximum debt to total capitalization levels under various debt agreements.
Under the Public Utility Holding Company Act of 1935, the Company may pay dividends out of capital or unearned surplus only with SEC approval. Dividends from earned surplus are permitted without approval. The Company has received approval to pay dividends out of unearned surplus of the lesser of $900 million or the proceeds received from sales of nonutility assets.
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Generally, preferred stock is redeemable at stipulated prices plus accrued dividends, subject to certain restrictions. Upon voluntary or involuntary liquidation, all preferred stock is entitled to stated value or a specified preference amount per share plus accrued dividends. Any premium paid on redemptions of preferred stock is capitalized, and recovery is sought through future rates. Dividends on all preferred stock are cumulative.
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Mandatory redemption requirements at stated value plus accrued dividends on No Par Serial Preferred Stock are as follows: the $7.70 series is redeemable in its entirety on August 15, 2001; and 37,500 shares of the $7.48 series are redeemable on each June 15 from 2002 through 2006, with all shares outstanding on June 15, 2007 redeemable on that date. If the Company is in default in its obligation to make any future redemptions on the $7.48 series, it may not pay cash dividends on common stock.
The Company had $58 million and $4 million in common and preferred dividends, respectively, declared but unpaid at March 31, 2001 and $4 million in preferred dividends declared but unpaid at March 31, 2000.
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NOTE 11 SECURITIES AVAILABLE FOR SALE
The amortized cost and fair value of reclamation trust securities and other investments, which are classified as available for sale, were as follows:
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The quoted market price of securities is used to estimate the securities' fair value.
The amortized cost and estimated fair value of debt securities at March 31, 2001 and 2000 by contractual maturities are shown below. Actual maturities may differ from contractual maturities because borrowers may have the right to call or prepay obligations with or without call or prepayment penalties.
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Proceeds, gross gains and gross losses from realized sales of available-for-sale securities using the specific identification method were as follows for the years ended March 31, 2001 and 2000, the three months ended March 31, 1999 and the year ended December 31, 1998:
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NOTE 12 FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
Through the application of its capital structure policies that govern the use of equity and debt, including duration, maturity and repricing intervals, the Company seeks to reduce its net income and cash flow exposure to changing interest and other commodity price risks. The Company may utilize derivative instruments to modify or eliminate its exposure from adverse movements in interest and foreign currency rates. The use of these derivative instruments is governed by the Company's derivative policy, which includes as its objective that interest rate and foreign exchange derivative instruments will be used for hedging and not for speculation. As such, only those instruments that have a high correlation with the Company's underlying exposure can be utilized. The derivative policy also governs energy purchase and sales activities and is generally designed for hedging the Company's existing energy exposures. The Company may modify or amend the capital structure or derivative structure at its discretion. Certain state utility commissions have claimed jurisdiction over financial derivatives, and as such the Company must obtain regulatory approvals to enter into financial derivative transactions.
The Company did not enter into any new financial derivative contracts during the year, and at March 31, 2001 had no outstanding financial derivative contracts. The interest rate and foreign exchange derivatives outstanding at March 31, 2000 related to its investment in Powercor, which was sold in September 2000.
Notional Amounts and Credit Exposure of Derivatives - The notional amounts of derivatives summarized below do not represent amounts exchanged and, therefore, are not a measure of the exposure of the Company through its use of derivatives. The amounts exchanged are calculated on the basis of the notional amounts and other terms of the derivatives, which relate to interest rates, exchange rates or other indexes.
The Company's derivative policy provides that counterparties must satisfy established credit ratings. The credit exposure of interest rate, foreign exchange and forward contracts is represented by the fair value of contracts with a positive fair value at the reporting date.
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Interest Rate Risk Management - The Company has entered into various types of interest rate contracts to assist in managing its interest rate risk, as indicated in the following table:
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The Company has used interest rate swaps, collars, futures and forwards to adjust the characteristics of its liability portfolio, allowing the Company to establish a mix of fixed or variable interest rates on its outstanding debt within the Company's overall capital structure guidelines for leverage and variable interest rate risk.
Under the various interest rate swap agreements, the Company agreed with other parties to exchange, at specified intervals, the difference between fixed-rate and variable-rate interest amounts calculated by reference to an agreed notional principal amount. The following table indicates the weighted-average interest rates of the swaps at March 31, 2000. Average variable rates are based on rates implied in the yield curve at March 31, 2000.
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Foreign Exchange Risk Management - The Company's principal foreign exchange exposure related to its investment in its Australian electric operations. The Company hedged its exposure through both Australian-dollar denominated bank borrowings, which hedged approximately 55% to 60% of its total exposure, and through a series of amortizing currency swaps, which hedged approximately half of the remaining exposure. At March 31, 2000, the Company had recorded a deferred pretax gain of $31 million in "Deferred Credits - Other" relating to these hedges.
At March 31, 2000, Holdings held three combined interest rate and currency swaps that would have terminated in 2002, with an aggregate notional amount of $202 million to hedge a portion of its net investment in Powercor to fluctuations in the Australian dollar. The interest rate portions of these three swaps were effectively offset in 1997 by the purchase of an overlay swap transaction with approximately the same terms. The four swaps were terminated at the time of the sale of Powercor in September 2000.
Commodity Risk Management - The Company utilized electricity futures contracts that qualified as financial instruments in its nonregulated operations of PPM. See Note 17.
The Company had 44 open sales NYMEX futures contracts at March 31, 2000, with a notional quantity of 19,000 MWh. The fair market value of these open sales contracts at March 31, 2000 was less than $1 million.
84
NOTE 13 FAIR VALUE OF FINANCIAL INSTRUMENTS
March 31, 2001 | March 31, 2000 | |||
| Carrying | Fair | Carrying | Fair |
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(1) Represents long-term debt and long-term debt classified as currently maturing, less capitalized lease obligations.
The carrying value of cash and cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. The fair value of the finance note receivable approximates its carrying value at March 31, 2001 and March 31, 2000.
The fair value of the Company's long-term debt, Preferred Securities and redeemable preferred stock has been estimated by discounting projected future cash flows, using the current rate at which similar loans would be made to borrowers with similar credit ratings and for the same maturities. Current maturities of long-term debt were included.
The fair value of interest rate derivatives and currency swaps is the estimated amount the Company would receive to terminate the agreements, taking into account current interest and currency exchange rates and the current creditworthiness of the agreement counterparties.
NOTE 14 COMMITMENTS AND CONTINGENCIES
ENVIRONMENTAL ISSUES
The Company is subject to numerous environmental laws including: the Federal Clean Air Act, as enforced by the Environmental Protection Agency and various state agencies; the 1990 Clean Air Act Amendments; the Endangered Species Act, particularly as it relates to certain potentially endangered species of salmon; the Comprehensive Environmental Response, Compensation and Liability Act, relating to environmental cleanups; along with the Federal Resource Conservation and Recovery Act and the Clean Water Act relating to water quality. These laws could potentially impact future operations. For those contingencies identified at March 31, 2001, principally the Superfund sites where the Company has been or may be designated as a potentially responsible party and Clean Air Act matters, future costs associated with the disposition of these matters are expected to be addressed in future regulatory requests and, therefore, are not expected to be material to the Company's consolidated financial statements.
85
LITIGATION
The Company and its subsidiaries are parties to various legal claims, actions and complaints, certain of which involve material amounts. Although the Company is unable to predict with certainty whether or not it will ultimately be successful in these legal proceedings or, if not, what the impact might be, management currently believes that disposition of these matters will not have a materially adverse effect on the Company's consolidated financial statements.
MINE RECLAMATION
During 1997, the Company made the decision to cease operations at the Glenrock Mine. The decline in both Powder River Basin coal prices and Burlington Northern rail rates, coupled with changing mine geology, made the continued operation of the Glenrock Mine uneconomical. Final reclamation efforts are ongoing at the Glenrock Mine. The Company expects most reclamation activities will be completed by 2006. Pursuant to the Surface Mine Control and Reclamation Act, the Company will then be required to monitor the reclamation work. The monitoring period will last an additional ten years.
HYDROELECTRIC RELICENSING
The Company's hydroelectric portfolio consists of 53 plants that include 87 generating units with a total capacity of approximately 1,100 MW. Ninety-seven percent of the installed capacity is regulated by the FERC through 20 individual licenses. Nearly all of the Company's hydroelectric projects are in some stage of relicensing under the FPA. Hydro relicensing and the related environmental compliance requirements are subject to a high degree of change in estimation. However, the Company expects that these costs will be significant and consist primarily of future capital expenditures.
CALIFORNIA - CREDIT RISK
At March 31, 2001, the Company had receivables of $1 million from Southern California Edison Co. ("SCE"), a less than investment grade purchaser of power, $1 million from San Diego Gas and Electric Co., and no receivable directly from Pacific Gas and Electric Co., a company that filed for Chapter 11 reorganization in April 2001. The Company has not taken specific reserves against these amounts. The Company, like all participants in the regional market, has exposure to other participants who may have credit exposure to the utilities in California. To mitigate exposure to the financial risks of these counterparties, the Company has entered into netting, margining and guarantee arrangements. The Company calculates reserves for all of its credit exposure by grouping counterparties, based upon managerial judgement and rating, and then calculating a reserve based upon a ratings agency historical default rate.
86
At March 31, 2001, the Company had no receivables related to its direct energy transactions with the California Power Exchange (the "CPX") and a receivable of $6 million from the California Independent System Operator (the "Cal ISO"). The majority of this amount has been reserved based on the estimated amounts indirectly receivable from companies defaulting on payments to Cal ISO. Under default provisions contained in the CPX tariff, the CPX has charged back some of the defaults of CPX participants to remaining participants, including the Company, based upon the level of purchase and sales activity of each participant during the preceding three-month period. The Company has paid $2 million in charge-backs to the CPX related to SCE's default on its payments to the CPX. Subsequent to this payment, FERC ruled that charge-backs are not permissible. As a result of this FERC ruling, the Company has recorded a receivable and demanded a refund of this $2 million charge-back from the CPX.
CONSTRUCTION AND OTHER
The Company has an ongoing construction program and, as a part of this program, substantial commitments have been made.
Holdings also has provided a performance guarantee on the operation of a plant managed by a related party.
LEASES
The Company has certain properties under leases with various expiration dates and renewal options. Rentals on lease renewals are subject to negotiation. Certain leases provide for options to purchase at fair market value. The Company is also committed to pay all taxes, expenses of operation (other than depreciation) and maintenance applicable to the leased property.
Net rent expense for the years ended March 31, 2001 and 2000, the three months ended March 31, 1999, and the year ended December 31, 1998 was $9 million, $16 million, $5 million and $17 million, respectively.
Future minimum lease payments under noncancellable operating leases are $18 million, $2 million, $1 million, $1 million and $1 million for 2002 through 2006, respectively.
87
JOINTLY OWNED FACILITIES
At March 31, 2001, Domestic electric operations' participation in jointly owned facilities was as follows:
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(a) The Centralia plant was sold on May 4, 2000. The joint owners of the plant retained ownership in the Skookumchuck Dam and related facilities. For additional information on the sale, see Note 17.
(b) Includes kilovolt lines and substations.
(c) Plant, inventory, fuel and decommissioning costs totaling $19 million relating to the Trojan Plant were included in regulatory assets at March 31, 2001.
(d) Represents the excess of the cost of the acquired interest in purchased facilities over their original net book value.
(e) Additionally, the Company has contracted to purchase the remaining 50% of the output of the plant.
Under the joint agreements, each participating utility is responsible for financing its share of construction, operating and leasing costs. Domestic electric operations' portion is recorded in its applicable operations, maintenance and tax accounts, which is consistent with wholly-owned plants.
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LONG-TERM WHOLESALE SALES AND PURCHASED POWER CONTRACTS
Domestic electric operations manages its energy resource requirements by integrating long-term firm, short-term and spot market purchases with its own generating resources to economically dispatch the system (within the boundaries of FERC requirements) and meet commitments for wholesale sales and retail load growth. The long-term wholesale sales commitments include contracts with minimum sales requirements of $472 million, $442 million, $279 million, $232 million and $199 million for the years 2002 through 2006, respectively. As part of its energy resource portfolio, Domestic electric operations acquires a portion of its power through long-term purchases and/or exchange agreements which require minimum fixed payments of $421 million, $402 million, $338 million, $322 million and $319 million for the years 2002 through 2006, respectively. The purchase contracts include agreements with the BPA, the Hermiston Plant and a number of cogenerating facilities.
Excluded from the minimum fixed annual payments above are commitments to purchase power from several hydroelectric projects under long-term arrangements with public utility districts. These purchases are made on a "cost-of-service" basis for a stated percentage of project output and for a like percentage of project annual costs (operating expenses and debt service). These costs are included in operations expense. Domestic electric operations is required to pay its portion of operating costs and its portion of the debt service, whether or not any power is produced. The arrangements provide for nonwithdrawable power and the majority also provide for additional power, withdrawable by the districts upon one to five years' notice. For 2001, such purchases approximated 3% of energy requirements.
At March 31, 2001, Domestic electric operations' share of long-term arrangements with public utility districts was as follows:
Generating | Year Contract | Capacity | Percentage | Annual |
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(a) Annual costs in millions of dollars. Includes debt service of $8 million. The Company's minimum debt service obligation at March 31, 2001 was $9 million, $9 million, $9 million, $8 million and $7 million for the years 2002 through 2006, respectively.
The Company has a 4% interest in the Intermountain Power Project (the "Project"), located in central Utah. The Company and the city of Los Angeles have agreed that the City will purchase capacity and energy from Company plants equal to the Company's 4% entitlement of the Project at a price equivalent to 4% of the expenses and debt service of the Project.
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SHORT-TERM WHOLESALE SALES AND PURCHASED POWER CONTRACTS
At March 31, 2001, Domestic electric operations had short-term wholesale forward sales commitments that included contracts with minimum sales requirements of $397 million for the year 2002. At March 31, 2001, short-term forward purchase agreements require minimum fixed payments of $818 million for the year 2002.
FUEL CONTRACTS
Domestic electric operations has take or pay coal and natural gas contracts that require minimum fixed payments of $121 million, $141 million, $144 million, $142 million and $137 million for 2002 through 2006, respectively.
In May 1999, Domestic electric operations entered into a coal mining lease agreement for exclusive rights to mine the Mill Fork Tract in Emery County, Utah. The agreement calls for a lease bonus bid payment of $25 million, payable annually in March in installments of $5 million through 2003.
COMMITMENTS FOR 2002 OLYMPIC WINTER GAMES
The Company has committed to provide electric service to the 2002 Olympic Winter Games in Salt Lake City, Utah in exchange for being recognized as the official electric utility supplier. While the contract is still being finalized, the Company has agreed to provide up to 78,467 MWh of energy to Salt Lake Organizing Committee owned or leased facilities through 2004. The Company has also agreed to provide temporary electrical facilities to serve loads at approximately 12 Olympic competition and noncompetition venue sites.
RESOURCE MANAGEMENT
The Company, as a public utility and a franchise supplier, has an obligation to manage resources to supply its customers. Rates charged to most customers are tariff rates authorized by regulatory agencies. See Note 5.
NOTE 15 INCOME TAXES
Upon its acquisition by ScottishPower, the Company became a member of a group that files its federal and state tax returns on a consolidated basis. Prior to that time, the Company filed directly with the taxing authorities. Tax expense is calculated on a separate return basis. Amounts payable for federal and state taxes are remitted to the Company's parent.
The Company's combined federal and state effective income tax rate from continuing operations was 196% for 2001, 62% for 2000, 39% for the three months ended March 31, 1999 and 35% for 1998. The primary causes for the tax rate increase over the statutory rate for the year ended March 31, 2001 are the substantially nondeductible losses on sales of the Australian operations and reserves for tax on outstanding Internal Revenue Service ("IRS") examination issues. The Company did not have enough capital gains to offset the capital losses resulting from the sale of the Australian operations and does not anticipate any further tax benefit from these losses. See Note 17.
90
The primary cause of the increase in the tax rate over the statutory rate for the year ended March 31, 2000 was the nondeductible nature of many merger costs.
The difference between taxes calculated as if the statutory federal tax rate of 35% was applied to income from continuing operations before income taxes and the recorded tax expense is reconciled as follows:
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(a) The Company did not have enough capital gains to offset the capital losses resulting from the sale of the Australian operations and does not anticipate any further tax benefit from these losses.
The provision for income taxes is summarized as follows:
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2001 | 2000 | 1999 | 1998 | |
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91
The tax effects of significant items comprising the Company's net deferred tax liability were as follows:
March 31/Millions of dollars | 2001 | 2000 |
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The Company completed its discussions with the IRS Appeals Division for the 1989 and 1990 tax years during 1998. A total of $8 million was paid as part of the resolution. In 1999, the Company filed for relief in Tax Court with respect to two remaining issues. The tax impact for which a liability has been established for these two issues is $4 million.
The Company has received an IRS examination report for 1991, 1992 and 1993 proposing adjustments that would increase current taxes payable by $97 million. The Company protested many of these proposed adjustments and discussions continue with the IRS to resolve the disputed issues.
During 1999, the IRS commenced examination of the Company's tax returns for the years 1994 through 1999.
The Company received net income tax refunds of $64 million for 2001 and $2 million each for 2000 and the three months ended March 31, 1999. The Company made income tax payments of $504 million in 1998.
NOTE 16 EMPLOYMENT BENEFIT PLANS
Retirement Plans - The Company has pension plans covering substantially all employees. Benefits under the plan in the United States are based on the employee's years of service and average monthly pay in the 60 consecutive months of highest pay out of the last 120 months, with adjustments to reflect benefits estimated to be received from Social Security. Pension costs are funded annually by no more than the maximum amount of pension expense that can be deducted for federal income tax purposes. Unfunded prior service costs are amortized over the remaining service period of employees expected to receive benefits. At March 31, 2001, plan assets were primarily invested in common stocks, bonds and United States government obligations.
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All permanent employees of Powercor engaged prior to October 4, 1994 were members of Division B or C of the Superannuation Fund (the "Fund") which provided defined benefits in the form of pensions (Division B) or lump sums (Division C). Both defined benefit Funds are closed to new members. Members who chose to contribute did so at rates of 3% or 6% of eligible salaries. Powercor employees engaged after October 4, 1994 were members of Division D of the Fund, which was a defined contribution fund in which members contributed up to 20% of eligible salaries. In 2001, Powercor made no contributions to Division B and C funds. In 2000, Powercor made contributions of $2 million to Division B and C funds. During the year ended December 31, 1998, Powercor made no contributions to Division B and C funds due to surplus amounts in these funds. Powercor contributed to the Division D Fund at rates ranging from 6%-10% of eligible salaries in all years.
The net periodic pension (benefit) cost and significant assumptions are summarized as follows:
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The change in the projected benefit obligation, change in plan assets and funded status are as follows:
March 31/Millions of dollars | 2001 | 2000 |
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(a) Represents a reduction in the Company's projected benefit obligation as a consequence of an amended agreement with IBEW Local 57, under which employees under age 50 on July 1, 1999 receive their future service pension benefits from a new plan being jointly administered by the Union and the Company.
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Employee Savings and Stock Ownership Plan - The Company has an employee savings and stock ownership plan that qualifies as a tax-deferred arrangement under the Internal Revenue Code. Participating United States employees may defer up to 16% of their compensation, subject to certain regulatory limitations. The Company matches 50% of employee contributions on amounts deferred up to 6% of total compensation, with ScottishPower ADS, vesting that portion over five years. The Company makes an additional contribution of ScottishPower ADS to qualifying employees equal to a percentage of the employee's eligible earnings. These contributions are immediately vested. Company contributions to the savings plan were $18 million and $19 million for the years ended March 31, 2001 and 2000, respectively, $5 million for the three months ended March 31, 1999, and $18 million for the year ended December 31, 1998, and represent amounts expensed for each period.
Other Postretirement Benefits - Domestic electric operations provides health care and life insurance benefits through various plans for eligible retirees on a basis substantially similar to those who are active employees. The cost of postretirement benefits is accrued over the active service period of employees. The transition obligation represents the unrecognized prior service cost and is being amortized over a period of 20 years. For those employees retired at January 1, 1994, the Company funds postretirement benefit expense on a pay-as-you-go basis and has an unfunded accrued liability of $141.7 million at March 31, 2001. For those employees retiring after January 1, 1994, the Company funds postretirement benefit expense through a combination of funding vehicles. The Company contributed nothing to the funded plan for the year ended March 31, 2001, $6 million of postretirement benefits for the year ended March 31, 2000, nothing for the three months ended March 31, 1999 and $27 million for 1998. These funds are invested in common stocks, bonds and United States government obligations.
The net periodic postretirement benefit cost and significant assumptions are summarized as follows:
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The change in the accumulated postretirement benefit obligation (the "APBO"), change in plan assets and funded status are as follows:
March 31/Millions of dollars | 2001 | 2000 |
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(a) Represented the effect of a plan change that reduced the maximum dollar subsidy from the Company for the cost of retiree medical coverage after age 65 for employees retiring on or after January 1, 2000.
(b) Represents the one-time charge for enhanced postretirement medical benefits for employees accepting the voluntary Workforce Transition Retirement Program offering in 2001.
96
The assumed health care cost trend rate gradually decreases over 16 years. The health care cost trend rate assumption has a significant effect on the amounts reported. Increasing the assumed health care cost trend rate by one percentage point would have increased the APBO as of March 31, 2001 by $18.6 million, and the annual net periodic postretirement benefit costs by $1.7 million. Decreasing the assumed health care cost trend rate by one percentage point would have reduced the APBO as of March 31, 2001 by $22.8 million, and the annual net periodic postretirement benefit costs by $2.0 million.
Postemployment Benefits - Domestic electric operations provides certain postemployment benefits to former employees and their dependants during the period following employment but before retirement. The costs of these benefits are accrued as they are incurred. Benefits include salary continuation, severance benefits, disability benefits and continuation of health care benefits for terminated and disabled employees and workers compensation benefits. Accrued costs for postemployment benefits were $9 million and $8 million for the years ended March 31, 2001 and March 31, 2000, respectively, $2 million for the three months ended March 31, 1999 and $12 million for the year ended December 31, 1998.
Early Retirement Offer - See Notes 2 and 6 for details relating to early retirement offerings.
Stock Option Incentive Plan - During 1997, the Company adopted a Stock Option Incentive Plan (the "Plan"). The exercise price of options granted under the Plan have been at 100% of the fair market value of the common stock on the date of the grant. Stock options generally become exercisable in two or three equal installments on each of the first through third anniversaries of the grant date. The maximum exercise period under the Plan is ten years. In early 1998, the Company registered 11,500,000 shares of its common stock with the Securities and Exchange Commission for issuance under the Plan.
Upon completion of the Merger, all stock options granted prior to January 1999 became 100% vested. All outstanding stock options were converted into options to purchase ScottishPower ADS. Stock options to purchase ScottishPower ADS granted subsequent to the Merger vest over the same number of years as stock options granted prior to the Merger.
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The table below summarizes the stock option activity under the Plan.
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At March 31, 2001, options for 2,496,389 ScottishPower ADS were exercisable with a weighted average exercise price of $35.43 per share. The weighted average life of the options outstanding at March 31, 2001 was six years. At March 31, 2000, options for 2,214,455 ScottishPower ADS were exercisable with a weighted average exercise price of $37.85 per share. The weighted average life of the options outstanding at March 31, 2000 was eight years.
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As permitted by SFAS No. 123, the Company has elected to account for these options under APB No. 25. Accordingly, no compensation expense has been recognized for these options. Had the Company determined compensation cost based on the fair value at the grant date for all stock options vesting in each period under SFAS No. 123, the Company's net income would have been reduced to the pro forma amounts below:
For the year ended | March 31, | March 31, | December 31, |
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The fair value of options granted was less than one half million dollars, $9 million and $14 million in 2001, 2000 and 1998, respectively. The fair value of each option grant was estimated on the date of grant using the Black-Scholes option-pricing model with the following assumptions used:
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NOTE 17 ACQUISITIONS AND DISPOSITIONS
In connection with an internal restructuring of the Company, the Company transferred its interest in two nonregulated energy companies to an affiliated entity, PHI, in March 2001. The transfer price of $72 million was based on an estimate of market value. PHI financed the acquisition through a loan from Holdings. The income and cash flow impacts from the two companies are included in the 2001 results, but the assets and liabilities associated with those businesses were removed from the consolidated balance sheet upon the transfer to PHI. No gain was recognized on the transfer. The difference between the transfer price and the book value was recorded as an adjustment to equity.
On September 6, 2000, the Company completed the sale of its ownership of Powercor pursuant to the August 2, 2000 agreement to sell Powercor and the Company's 19.9% interest in Hazelwood, both indirectly owned subsidiaries of the Company, to Cheung Kong Infrastructure and Hongkong Electric Holdings for approximately AUS $2.4 billion, including repayment or assumption of debt of approximately AUS $1.3 billion. Powercor and Hazelwood represented all of the Australian electric operations segment of the Company. Of the estimated $673 million in net Powercor sales proceeds, which are subject to final selling expenses and other adjustments, $350 million was lent to a directly owned subsidiary of ScottishPower. The remaining proceeds of $323 million were used to repay debt of the Company. The Company recorded an estimated impairment of $188 million in anticipation of the loss on the sale of the Australian electric operations segment in the first quarter of 2001, which was adjusted in the second quarter of 2001 to $197 million upon the completion of the sale of its indirect ownership of Powercor. The sale of the Company's
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interest in Hazelwood was completed on November 17, 2000, to National Power Australia Holdings Pty Ltd, a wholly-owned indirect subsidiary of International Power plc, for approximately AUS $88 million, which resulted in an additional loss of $1 million in the third quarter of 2001. In October 1998, the Company recorded a pretax loss of $28 million ($17 million after-tax), which is included in "Write down of investments in energy development companies" on the income statement, to reduce its carrying value in Hazelwood to estimated net realizable value less selling costs. This write down was arrived at using cash flow projections. The $46 million in net proceeds from the sale of Hazelwood was lent to a directly owned subsidiary of ScottishPower.
The loss on sale of Australian electric operations for the year ended March 31, 2001 is as follows:
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(a) The Company did not have enough capital gains to offset this capital loss and does not anticipate any further tax benefit from this loss.
On May 4, 2000, the utility partners (including the Company) who owned the 1,340 MW coal-fired Centralia Power Plant sold the plant and the adjacent coal mine, wholly-owned and operated by the Company, to TransAlta for approximately $500 million. The Company operated the plant and owned a 47.5% share. After the return to customers required by the regulatory approvals, the Company recorded a loss of approximately $14 million on the sale. The timing of this return to customers varies by state. Pursuant to the sale, TransAlta has agreed to assume the reclamation costs for the Centralia coal mine. At March 31, 2000, the Company had approximately $26 million accrued for its share of the Centralia mine reclamation costs, which was used to reduce the selling price and was incorporated into the calculation of the net loss on the sale.
The Company's discontinued energy trading business included the eastern United States electricity trading operations of PPM and the natural gas marketing and storage operations of TPC. PPM's wholesale power trading activities in the eastern United States have been discontinued, and all related forward energy trading has been closed. On April 1, 1999, Holdings sold TPC to NIPSCO Industries, Inc. for $150 million. This activity resulted in a net after-tax gain of $1 million in the first quarter of 2000. See Note 4.
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On November 5, 1998, the Company sold its Montana distribution assets to Flathead Electric Cooperative, Inc. and received proceeds of $89 million, net of taxes and customer refunds. The Company returned $4 million of the $8 million gain to Montana customers.
In October 1998, the Company decided to exit the majority of its other energy development businesses as a result of its refocus on the western United States and Australian electricity businesses. These energy development businesses are generally wholly-owned subsidiaries of the Company or subsidiaries in which the Company has a majority ownership. The pretax loss associated with exiting the energy development businesses was $52 million ($32 million after-tax) and is included in "Write down of investments in energy development companies" on the income statement. The remaining values for these businesses were arrived at using cash flow projections and estimated market value for fixed assets. Some of these businesses have been exited through the discontinuance of their operations while others are held for sale. Through September 1998, these businesses recorded pretax losses of $18 million ($13 million after-tax). From October 1, 1998 through December 31, 1998, Holdings recorded a pretax expense of $5 million ($3 million after-tax) relating to these operations.
During May 1998, PFS received approximately $80 million in cash proceeds for the sale of a majority of its real estate assets, which approximated book value.
The Company had an agreement with Nor-Cal Electric Authority ("Nor-Cal") for the sale of the Company's California electric distribution assets for $178 million. On December 21, 2000, the California Public Utilities Commission approved an Administrative Law Judge's decision to dismiss the application for approval of the sale. The Company is currently in discussion with Nor-Cal to evaluate its options with respect to this sale.
All assets subject to disposition, other than discontinued operations, continued to be utilized in operations of the Company. As such, no separate accounting treatment or classification has been given to such assets.
NOTE 18 SEGMENT INFORMATION
The Company operated in two business segments (excluding other and discontinued operations): Domestic electric operations and Australian electric operations. The Company identified the segments based on management responsibility within the United States and Australia. Domestic electric operations includes the regulated retail and wholesale electric operations in the six western states in which it operates. Australian electric operations included the deregulated electric operations in Australia. Other operations consists of PFS, the western energy trading activities and other energy development businesses, as well as the activities of Holdings, including financing costs. None of the businesses within Other operations are significant enough for segment treatment.
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SELECTED FINANCIAL INFORMATION (UNAUDITED)
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(a) Other operations includes the operations of PFS, PGC, the western United States wholesale trading activities of PPM, as well as the activities of Holdings, including financing costs, and elimination entries.
(b) Discontinued operations included the Company's interest in PTI, TPC and the eastern energy trading business of PPM.
(c) Extraordinary item included a regulatory asset impairment pertaining to generation resources that were allocable to operations in California and Montana.
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DOMESTIC ELECTRIC OPERATIONS (UNAUDITED)
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*Not a meaningful number.
(a) Includes a $43 million asset write-back from receipt of a regulatory order and a $14 million loss on the sale of the Centralia plant and mine.
(b) Includes merger costs of $16.0 million.
(c) Does not reflect elimination of interest on intercompany borrowing
arrangements and includes income taxes on a separate-company basis.
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DOMESTIC ELECTRIC OPERATIONS STATISTICS (UNAUDITED)
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(a) Excludes off-system sales.
(b) Includes firm off-system sales.
(c) Generating capability, short-term and long-term firm purchases at time of firm peak.
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AUSTRALIAN ELECTRIC OPERATIONS (UNAUDITED)(a)
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(a) Results of operations are included until the dates of disposal, September 6, 2000 for Powercor and November 17, 2000 for Hazelwood.
(b) Australian electric operations' financial results for the period from January 1, 2000 to the dates of sale are included in the Company's financial results for the year ended March 31, 2001. Australian electric operations' financial results for the year ended December 31, 1999 are included in PacifiCorp's consolidated results for the year ended March 31, 2000. See Note 1.
(c) For the year ended December 31, 1996, the equity in losses of Hazelwood were included since the September 13, 1996 acquisition date.
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OTHER OPERATIONS (UNAUDITED)
Other operations include the operations of PFS, PGC, the western United States energy trading activities of PPM and several start-up-phase ventures, as well as the activities of Holdings, including financing costs. PGC assets were sold on November 5, 1997 and a majority of the real estate assets of PFS were sold during May 1998. The Company transferred its interest in two nonregulated energy companies to an affiliated entity, PHI, in March 2001.
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Millions of dollars | 2001 | 2000 | 1999 | 1998 | 1997 | 1996 |
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Capital spending | $ 67 | $ 2 | $ - | $ 53 | $ 140 | $ 56 |
(a) Included $3.1 million in merger costs for the year ended March 31, 2000.
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SUPPLEMENTAL INFORMATION
QUARTERLY FINANCIAL DATA (UNAUDITED)
Quarters Ended | ||||
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(a) The Company recorded an impairment of $188 million after-tax in anticipation of the loss on the sale of the Company's indirect ownership of Powercor and the Company's 19.9% interest in Hazelwood. See Note 17.
(b) The Company established $25 million in regulatory assets resulting from successful resolution of previously denied costs addressed in the Utah rate order received in May 2000. The Company recorded an additional loss of $9 million after-tax upon the completion of the sale of its indirect ownership of Powercor. See Notes 5 and 17.
(c) Increases in purchased power expenses exceeded the increases in revenues by $130 million. Purchased power expense increased as a result of the continuing increase in demand, generation outages and lower hydro generation. This increase is net of $16 million of accounting deferrals received from the Wyoming Commission for power cost variances.
(d) The Company reversed $28 million in alternative fuel tax credits because its tax liability was not sufficient to utilize those credits.
(e) Increases in purchased power expense exceeded the increases in revenues by $26 million net of accounting deferrals of $123 million pretax related to accounting orders received from the commissions in Utah, Oregon, Wyoming, and Idaho for power cost variances. See Note 5.
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(f) Includes a $66 million tax reserve relating to reevaluation of tax liabilities from settled and ongoing tax examinations.
(g) The Company recorded an after-tax charge of $190 million relating to merger costs, $15 million relating to the write-off of projects under construction and $11 million relating to recalculation of contract fees owed by Powercor. In addition, the Company recorded after-tax earnings of $18 million relating to the favorable outcome of a contract dispute Powercor was having with one of its suppliers. See Note 2.
A significant portion of the operations are of a seasonal nature.
See Note 4 for information regarding discontinued operations.
On March 31, 2001, there was one common shareholder of record.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
No information is required to be reported pursuant to this item.
PART III
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Terry F. Hudgens, (46), Senior Vice President of the Company. Director since April 2000.
Mr. Hudgens was elected Senior Vice President on April 1, 2000. He was President of Texaco Natural Gas from 1996 to 2000. From 1990 to 1996, he was the Vice President of Business Development and Tariffs for Texaco Trading and Transportation, Inc.
Judith A. Johansen, (42), Executive Vice President of the Company. Director since December 2000.
Ms. Johansen was elected Executive Vice President on December 1, 2000. She was Administrator and Chief Executive Officer of the Bonneville Power Administration ("BPA") in Portland, Oregon from June 1998 to November 2000. From 1996 to May 1998, Ms. Johansen was vice president of business development with Avista Energy and from 1994 to 1996 was BPA's vice president for generation supply.
Nolan E. Karras, (56). Director since February 1993.
Mr. Karras is President of The Karras Company, Inc., investment advisers, Roy, Utah, and has served in that capacity since 1983. He is Chief Executive Officer of Western Hay Company, Inc., and a nonexecutive director of Beneficial Life Insurance Company and American General Savings Bank. He also served as a Member of the Utah House of Representatives from 1981 to 1990, and as Speaker of the Utah House of Representatives from 1989 to 1990.
William D. Landels, (58), Executive Vice President of the Company. Director since November 1999.
Mr. Landels has been with ScottishPower since 1985. He was elected Executive Vice President and Director of the Company effective upon the merger with ScottishPower in November 1999. Prior to that, he served with the ScottishPower Group in various senior management roles, including as Managing Director of Manweb, Managing Director of Energy Supply, and Managing Director of Distribution.
Andrew N. MacRitchie, (37), Senior Vice President of the Company. Director since May 2000.
Mr. MacRitchie was elected Senior Vice President in May 2000. Mr. MacRitchie has been with ScottishPower since 1986. He served as the Transition Director for the PacifiCorp merger from December 1999 to May 2000. He served as ScottishPower's U.S. Chief of Staff on the PacifiCorp merger from December 1998 to December 1999 and, prior to that, he served as Manager, Business and Organizational Development.
Keith R. McKennon, (67). Director since November 1990.
Mr. McKennon served as PacifiCorp Board Chairman from 1994 until November 1999 and as President and Chief Executive Officer from 1998 until November 1999. He is a member of the ScottishPower Board of Directors. Prior to joining PacifiCorp, he was Chairman from 1992 until 1994 and CEO of Dow Corning
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Corporation, Midland, Michigan from 1992 until 1993. He is a director of the Oregon Historical Society and a member of the Oregon State University President's Advisory Council, Foreign & Colonial Investment Trust plc, The Law Debenture Corporation plc and Pantheon International Participations plc.
Robert G. Miller, (57). Director since August 1994.
Mr. Miller joined the Board as nonexecutive director on November 30, 1999. He is a director of PacifiCorp, and formerly served as Chairman of the PacifiCorp Board's Finance Committee. He was elected Chairman and CEO of Rite Aid Corp in December 1999, having previously been Vice Chairman of The Kroger Company from May to December 1999 and, prior to that, President and CEO of Fred Meyer, Inc., since 1997, and Chairman since 1991.
Michael J. Pittman, (48), Senior Vice President of the Company. Director since May 2000.
Mr. Pittman was elected a Senior Vice President of the Company in May 2000. He formerly served as a Vice President of the Company from May 1993.
Alan V. Richardson, (54), President and Chief Executive Officer of the Company. Director since November 1999.
Mr. Richardson was elected Chief Executive Officer and Director of the Company effective upon the merger with ScottishPower in November 1999 and was named President on March 16, 2000. He is a member of the ScottishPower Board of Directors. Prior to the merger, Mr. Richardson was Managing Director of Power Systems at ScottishPower from 1995 to 1999, and has been with ScottishPower since 1991.
Kenneth L. Vowles, (59). Director since November 1999.
Mr. Vowles joined ScottishPower in September 1990 and was appointed to the ScottishPower Board in September 1994. He is currently the international executive director of ScottishPower, the Chairman of Manweb and a nonexecutive director of Mining Scotland Limited.
The following is a list of the executive officers of the Company not named above. There are no family relationships among the executive officers of the Company. Officers of the Company are normally elected annually.
Andrew P. Haller, (49), Senior Vice President, CorporateSecretary and General Counsel since December 2000.
Mr. Haller was chief executive for the U.S. operations of Kvaerner Process prior to joining PacifiCorp. Mr. Haller began his career with Kvaerner in 1987, and held various senior counsel and management positions, including Senior Vice President of Chemicals, Polymers and Hydrocarbons-Americas. From 1998 to 1999, he served as the Associate General Counsel for the parent company, Kvaerner ASA, in its U.S. corporate headquarters.
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rendered in the year ended March 31, 2001 is fully deductible, with the exception of severance compensation paid to certain former executives.
Compensation Program Components
The Board, assisted by its outside consultant, evaluates the total compensation package of executives (excluding ScottishPower executives on international assignment) annually in relation to competitive pay levels. Given the increasingly competitive global environment in which PacifiCorp must operate and the competitive marketplace for executive talent required for future success, in 1996 PacifiCorp reevaluated its historical practice of using the electric utility industry as its primary market reference point. In 1997, the Personnel Committee began placing greater weighting on the general industry as the market reference base for long-term incentive purposes.
In the year ended March 31, 2001, the Board continued to focus its market-based comparisons on the relevant industry for each officer. The Board utilized the electric utility industry as its exclusive basis for market
comparison for positions with a principal focus on electric operations. For positions with a corporate-wide focus, the Board used a weighting of approximately 67% general industry and 33% electric utility industry. In all cases, compensation is targeted at market median levels, with a recognition that total compensation greater than market median, in any specific time period, anticipates that company performance exceed the median performance of peer companies.
PacifiCorp's executive compensation programs have three principal elements: base salary, annual incentive compensation and long-term incentive compensation, as described below.
Base Salaries
Base salaries and target incentive amounts are reviewed for adjustment at least annually based upon competitive pay levels, individual performance and potential, and changes in duties and responsibilities. Base salary and the incentive target are set at a level such that total annual compensation for satisfactory performance would approximate the midpoint of pay levels in the comparison group used to develop competitive data. In the year ended March 31, 2001, the base salaries of executive officers were increased, based on market analysis, to reflect competitive market changes and changes in the responsibilities of some officers.
Annual Incentives
All corporate officers (except ScottishPower executives on international assignment), including those listed in the Summary Compensation Table with the exception of Mr. Richardson, participated in the PacifiCorp executive incentive program. The performance goals for 2001 were weighted 75% company earnings before interest and taxes ("EBIT") and 25% business unit performance. All executive incentive program participants may have their incentive awards modified (in the range of 0% to 120% of calculated payout) by their individual performance, relative to established objectives, as evaluated by their immediate supervisor. The maximum allowable award from the executive incentive program for all participants is 150% of their guideline award.
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Long-Term Incentives
The PacifiCorp Board annually reviews and approves grants of restricted stock and stock options under the Stock Incentive Plan. In determining restricted stock awards, the Board considers criteria such as:
. total shareholder return relative to peer companies;
. financial growth over time relative to peer companies;
. and other factors such as achievement of long-term goals, strategies
and plans.
The Board approves grants of stock options based upon competitive award levels. Restricted stock awards under the Stock Incentive Plan are subject to terms, conditions and restrictions as may be determined by the Board to be consistent with the plan and the best interests of the shareholders. The restrictions include stock transfer restrictions and forfeiture provisions designed to facilitate the participants' achievement of specified stock ownership goals. Participants are also required to invest their own personal resources in ScottishPower stock (American Depository Shares or ordinary shares) in order to meet the vesting requirements associated with these grants. The Summary Compensation Table below shows the grants of restricted stock made to the listed executive officers under the Stock Incentive Plan in 2001, 2000 and 1999.
All stock options awarded to officers and senior management of PacifiCorp in 2000 and 1999 are nonstatutory, nondiscounted options with a three-year vesting requirement and a ten-year term from the date of the grant. Ms. Johansen and Mr. Haller were awarded grants of stock options on joining the Company. There were no grants of stock options to the remaining named executives in 2001.
ScottishPower Executive Officers on International Assignment
Executive officers who are international assignees from ScottishPower are maintained on their home country remuneration program. The compensation for these individuals is determined by the ScottishPower Remuneration Committee, which consists solely of independent nonexecutive directors.
The ScottishPower Remuneration Committee is responsible for ensuring that the remuneration arrangements for executives attract and retain executives of high quality, who have the requisite skills and are incentivized to achieve performance which exceeds that of ScottishPower's competitors. Furthermore, the Committee's objective is to ensure that incentive schemes are in line with best practice and promote the interests of shareholders.
The Remuneration Committee believes that to attract and retain key executives of high caliber, the remuneration package it offers must be market-competitive. The remuneration strategy is to adopt a mid-market position on all senior management remuneration packages, and to provide packages above the mid-market level only where supported by demonstrably superior personal performance.
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In setting remuneration levels, the Remuneration Committee commissioned an independent evaluation of the roles of the executives, and also of the next levels of management within ScottishPower. The Committee has also continued to take independent advice from external remuneration consultants on market-level remuneration, based on comparisons with companies of similar size and complexity. In considering the comparator companies, the consultants have included a number of other utilities but have not restricted their study solely to utilities.
After careful consideration, the Remuneration Committee is confident that the remuneration policy stated for ScottishPower is appropriate. In line with its objectives to build an international energy business, ScottishPower has recruited a number of executives with key business skills, and hence a reward structure broadly equivalent to other large UK listed companies with international operations was necessary. The major components of ScottishPower's remuneration programs are described below.
Base Salaries
The Remuneration Committee sets the base salary for each PacifiCorp executive on international assignment by reference both to individual performance through a formal appraisal system, and to external market data, based on the job evaluation principles and reflecting similar roles in other comparable companies.
Annual Performance-Related Bonus
Executives participate in ScottishPower's performance-related pay schemes. All payments under the schemes are nonpensionable and noncontractual and are subject to the approval of the Remuneration Committee.
The 2000-01 scheme for executive directors provided a bonus of a maximum of 75% of salary, with half determined by ScottishPower's financial performance. The balance of the bonus is linked to each executive's achievement of key strategic objectives, both short-term and long-term. Objectives are set annually and performance against these is reviewed on a six-month basis. Mr. Richardson earned $160,500 incentive award during the performance period ended March 31, 2001.
Long Term Incentive Plan
ScottishPower operates a Long Term Incentive Plan ("LTIP") for executives that links the rewards closely between management and shareholders, and focuses on long-term corporate performance.
Under the current plan, awards to earn shares in ScottishPower are made to the participants up to a maximum value equal to 60% of base salary if certain performance measures are met. These measures relate to the sustained underlying financial performance of ScottishPower and customer service standards.
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The number of shares that the executive will actually receive is dependent upon ScottishPower's comparative total shareholder return performance over a three-year performance period. Half of each award is measured against the constituent companies of the Financial Times Stock Exchange ("FTSE") 100 Index and half against the UK electricity and water sector.
The arrangements provide for a percentage of each half of the award to be earned depending upon ScottishPower's ranking within the relevant comparator group as follows: 100% if ScottishPower ranks in the top quartile; 40% if ScottishPower is at median of the comparator group. The percentage is calculated on a straight-line basis between median and upper quartile; and no award is made if ScottishPower ranks below median.
Once the awards have been earned, they must be held for another year before they may be exercised. The plan participant may elect to receive the shares at any time between the fourth year and the seventh year after the award has been fully earned.
Compensation of the Chief Executive Officer
On November 29, 1999, Mr. Richardson assumed responsibilities as Chief Executive Officer and President of PacifiCorp. Mr. Richardson has a base salary of $405,000 and a maximum annual incentive award of 75% of base salary. He is also eligible for participation in the ScottishPower Long Term Incentive Program which provides an opportunity to earn a maximum long term award of up to 60% of base salary. Mr. Richardson is on an international assignment in the U.S. and, therefore, receives international assignment benefits as described in the "Summary Compensation Table."
The Board report on executive compensation detailed above has been submitted by the Board of Directors listed below.
Ian M. Russell, Chairman
Karen K. Clark
Terry F. Hudgens
Judith A. Johansen
Nolan E. Karras
William D. Landels
Andrew N. MacRitchie
Keith R. McKennon
Robert G. Miller
Michael J. Pittman
Alan V. Richardson
Kenneth L. Vowles
Executive Compensation
The following table sets forth information concerning compensation for services in all capacities to PacifiCorp and its subsidiaries for the years ended March 31, 2001, 2000 and 1999 of those persons who were the Chief Executive Officer of PacifiCorp during any portion of the fiscal year, the four other most highly compensated executive officers of PacifiCorp who were serving as executive officers at the end of the last completed fiscal year and
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one other individual for whom disclosure would have otherwise been required but for the fact that this individual was no longer an executive officer as of March 31, 2001.
Summary Compensation Table
Annual Compensation(1) | Long-Term Compensation | |||||||
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| Restricted | Securities | LTIP | ScottishPower | All Other |
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___________
(1) May include amounts deferred pursuant to the Compensation Reduction Plan, under which key executives and directors may defer receipt of cash compensation until retirement or a preset future date. Amounts deferred are invested in ScottishPower ADS or a cash account on which interest is paid at a rate equal to the Moody's Intermediate Corporate Bond Yield for AA rated Public Utility Bonds. All years referenced are 12-month periods ended March 31.
(2) Includes amounts paid to executive officers in the form of international assignment benefits, including foreign housing allowances. For 2001 these amounts were $424,830 and $116,412 for Messrs. Richardson and Lorenzini, respectively. For 2000 these amounts were $65,273 and $60,400 for Messrs. Richardson and Lorenzini, respectively. Included in 1999 was $371,133 for international assignment benefits for Mr. Lorenzini.
(3) Refer to the Board Report on Executive Compensation for a description of PacifiCorp's annual executive incentive plans. Incentive amounts are reported for the year in which they were received by the executive officers. Amounts in this column for 2001 include special bonuses and hire on bonuses. These amounts are $150,000, $130,000 and $7,000 for Ms. Clark and Messrs. Hudgens and Meier, respectively. Amounts in this column for 2000 included a special bonus that was paid upon the closure of the Merger with ScottishPower. These amounts were $46,500, $75,000, $125,000 and $100,000 for Messrs. Richardson, Lorenzini, Pittman and Meier, respectively. In 2000, Ms. Clark received a hire on bonus of $100,000. Amounts in this column for 1999 included special incentive awards for accomplishments in 1998 and 1999. These amounts were $80,000, $75,000 and $50,000 for Messrs. Lorenzini, Pittman and Meier, respectively.
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(4) Previous years' awards represented restricted stock grants made in February 2000 and 1999 pursuant to the Stock Incentive Plan. In general, restricted stock awards vest over a four-year period from the date of grant, subject to compliance with the stock ownership and other terms of the grant. On March 31, 2001, the aggregate value of all restricted stock holdings, based on the market value of the shares at March 31, 2001, without giving effect to the diminution of value attributed to the restrictions on such stock, and the aggregate number of restricted share holdings of Ms. Clark and Messrs. Richardson, Lorenzini, Hudgens, Pittman and Meier were $88,492, $368, $0, $64,894, $58,523 and $58,523, respectively. Regular quarterly dividends are paid on the restricted stock. Participants may defer receipt of restricted stock awards to their stock accounts under the Compensation Reduction Plan.
(5) Amounts shown for 2000 included a retention stock option award for Messrs. Pittman and Meier. These amounts were 108,207 and 72,842, respectively.
(6) Amount represents the value associated with the vesting and subsequent payout of shares for Mr. Lorenzini's 1999 and 2000 restricted stock grants, due to his retirement from PacifiCorp on September 29, 2000.
(7) Represents the number of ScottishPower ordinary performance shares contingently granted in 2001 and 2000 that can be earned under the terms of the ScottishPower Long Term Incentive Plan.
(8) Amounts shown for the year ended March 31, 2001 include:
(a) During 2001, Mr. Richardson purchased 50 shares under the
ScottishPower Employee Share Ownership Plan ("ESOP"). Under the
terms of the plan, ScottishPower matches the number of shares
bought by the individual. The value of the 50 shares bought by
ScottishPower, for Mr. Richardson, was $368.
(b) Severance for Mr. Lorenzini in the amount of $578,890.
(c) Contributions to the PacifiCorp K Plus Employee Savings and
Stock Ownership Plan for each of Ms. Clark and Messrs. Hudgens,
Pittman and Meier.
(d) Portions of premiums on term life insurance policies that
PacifiCorp paid for Ms. Clark and Messrs. Hudgens, Lorenzini,
Pittman and Meier in the amounts of $472, $444, $209, $360 and
$334, respectively. These benefits are available to all employees.
Additionally, this column includes vehicle allowance paid to
Ms. Clark, Messrs. Lorenzini, Hudgens, Pittman and Meier in the
amount of $10,800, $1,062, $9,000, $9,000 and $9,000, respectively.
Option Grants in 2001
Ms. Clark and Messrs. Richardson, Lorenzini, Hudgens, Pittman and Meier were not awarded options in 2001.
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Aggregated Option Exercises in 2001
and Year End Option Values
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(1) All options are for ScottishPower ADS, except Mr. Richardson's options, which are for ScottishPower ordinary shares.
Severance Arrangements
The PacifiCorp Executive Severance Plan provides severance benefits to certain executive level employees who are designated by the PacifiCorp Board, in its sole discretion, including the executive officers named in the Summary Compensation Table, with the exception of Mr. Richardson, who is an international assignee and does not participate in the Severance Plan, and Mr. Lorenzini, who has terminated and is receiving benefits. To qualify for severance benefits, the executive must have terminated employment for one of the following reasons:
(1) voluntary termination as a result of a material alteration in the executive's assignment that has a detrimental impact on the executive's employment. A "material alteration in assignment" includes any of the following:
(a) a material reduction in the scope of the executive's duties
and responsibilities;
(b) a material reduction in the executive's authority; or
(c) any reduction in base pay or a reduction in annualized base
salary and target bonus of at least 15%, if the change is not due
to a general reduction unrelated to the change in assignment; or
(2) involuntary termination (including a company-initiated resignation) for reasons other than for cause.
In addition, the Severance Plan provides enhanced severance benefits in the event of certain terminations during the 24-month period following a qualifying change-in-control transaction, including the Merger with ScottishPower. Executives designated by the PacifiCorp Board are eligible for change-in-control benefits resulting from either a PacifiCorp-initiated termination without "cause", or a resignation generally within two months
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after a "material alteration of position". During the 24-month protection period under the Severance Plan, "cause" means the executive's gross misconduct or gross negligence or conduct that indicates a reckless disregard for the consequences and has a material adverse effect on PacifiCorp or its affiliates, and "material alteration in position" means the occurrence of any of the following:
(1) a change in reporting relationship to a lower level;
(2) a material reduction in the scope of duties and responsibilities;
(3) a material reduction in authority;
(4) a "material reduction in compensation"; or
(5) relocation of executive's work location to an office more than 100 miles from the executive's office or more than 60 miles from the executive's home.
A "material reduction in compensation" occurs when an executive's annualized base salary is reduced by any amount or the annualized base salary and target bonus opportunity combined is reduced by at least 15% of the combined total opportunity before the change in compensation.
If qualified for the enhanced severance benefits, an executive would receive severance pay in an amount equal to either two, two and one-half or three times the "annual cash compensation" of such executive, depending on the level set by the Board. "Annual cash compensation" is defined as annualized base salary, target annual incentive opportunity and annualized auto allowance in effect on a material alteration or termination, whichever is greater. If the payment would result in imposition of an excise tax under IRC Section 4999, PacifiCorp is required to make an additional payment to compensate the executive for the effect of such excise tax. The executive would also receive continuation of subsidized health insurance from six to 24 months depending on length of service, and a minimum of 12 months' executive-level outplacement services. Several executives, including Mr. Lorenzini, have terminated and qualified to receive change-in-control benefits.
Other than in connection with a change-in-control, the definition of cause is determined by PacifiCorp in its discretion and by the Board in the event of an appeal by the employee. The Severance Plan does not apply to the termination of an executive for reasons of normal retirement, death or total disability or to a termination for cause or for voluntary termination other than as specified above. Other than in connection with a change-in-control, executives named in the Summary Compensation Table (other than Mr. Richardson) are eligible for a severance payment equal to one to two times the executive's total cash compensation, three months of health insurance benefits and outplacement benefits. Total cash compensation is defined as the annualized base salary, target annual incentive opportunity and the annualized auto allowance in effect on the earlier of a material alteration or termination.
Mr. Richardson's employment is governed by his 12-month rolling service contract with ScottishPower. There is no pre-determined amount of severance in the event of a company-initiated termination.
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Retirement Plans
PacifiCorp and most of its subsidiaries have adopted noncontributory defined benefit retirement plans for their employees, other than employees subject to collective bargaining agreements that do not provide for coverage. Certain executive officers, including the executive officers named in the Summary Compensation Table (other than Mr. Richardson), are also eligible to participate in PacifiCorp's nonqualified supplemental executive retirement plan. The following description assumes participation in both the retirement plans and the supplemental plan. Participants receive benefits at retirement payable for life based on length of service with PacifiCorp or its subsidiaries and average pay in the 60 consecutive months of highest pay out of the last 120 months, and pay for this purpose would include salary and bonuses as reflected in the Summary Compensation Table above. Benefits are based on 50% of final average pay plus up to an additional 15% of final average pay depending upon whether PacifiCorp meets certain performance goals set for each fiscal year by the Board. Participants may also elect actuarially equivalent alternative forms of benefits. Retirement benefits are reduced to reflect Social Security benefits as well as certain prior employer retirement benefits. Participants are entitled to receive full benefits upon retirement after age 60 with at least 15 years of service. Participants are also entitled to receive reduced benefits upon early retirement after age 55 or after age 50 with at least 15 years of service and 5 years of participation in the supplemental plan.
The following table shows the estimated annual retirement benefit payable upon retirement at age 60 as of January 1, 2001. Amounts in the table reflect payments from the retirement plans and the supplemental plan combined.
Estimated Annual Pension at Retirement (1)
Years of Service (2) | ||||
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(1) The benefits shown in this table assume that the individual will remain in the employ of PacifiCorp until retirement at age 60, that the plans will continue in their present form and that PacifiCorp achieves its performance goals under the supplemental plan in all years. Amounts shown do not reflect the Social Security offset.
(2) The number of credited years of service used to compute benefits under the plans for Ms. Clark and Messrs. Lorenzini, Hudgens, Pittman and Meier are 1, 13, 1, 21 and 3, respectively. Mr. Richardson does not participate in this plan.
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Mr. Richardson is provided retirement benefits through the main pension scheme of ScottishPower, and through an executive top-up pension plan that provides a maximum pension of two thirds of final salary on retirement at age 63. This benefit is reduced where service is less than 20 years. Pensionable salary is normally base salary in the 12 months prior to leaving ScottishPower. Mr. Richardson does not participate in any of the pension programs sponsored by PacifiCorp.
Details of pension benefits earned by Mr. Richardson are shown below:
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(1) Transferred in benefits represent pension rights accrued in respect of previous employments.
(2) The transfer value has been calculated on the basis of actuarial advice less contributions.
The pension entitlement shown is that which would be paid annually on retirement based on service to the end of the year assuming normal retirement at age 63. Eligible participants have the option to pay additional voluntary contributions; neither the contributions nor the resulting benefits are included in the above table.
Executives who joined ScottishPower on or after June 1, 1989 are subject to the earnings cap introduced in the Finance Act 1989. Pension entitlements which cannot be provided through ScottishPower's approved programs due to the earnings cap are provided through unapproved pension arrangements. The pension benefits disclosed above include approved and unapproved pension arrangements.
Retention Agreements
In order to retain executives who would otherwise have had the right to resign for any reason between 12 and 14 months following the ScottishPower merger and qualify for the enhanced change-in-control supplemental retirement benefits, the Company has entered into retention agreements with qualifying executives (Messrs. Pittman and Meier). Those retention agreements provide for the same enhanced supplemental retirement benefits if the qualifying executives satisfy the retention criteria. Qualifying executives were required to waive their rights to unilaterally resign and receive the enhanced supplemental retirement benefits but will be eligible to receive these same enhancements if they either (1) have a subsequent qualifying "involuntarily termination" or "material alteration" in position or (2) continue employment through the established retention date of December 1, 2002.
These retention agreements also require qualifying executives to waive any rights to executive severance benefits which they may have otherwise claimed due to material alterations in their positions as of the date of the retention
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agreement. Unless there is a subsequent "involuntarily termination" or "material alteration" in position as defined in the Severance Plan, this waiver of severance benefits applies to these executives through November 28, 2004. The executives' waiver of severance benefits was in exchange for the enhanced supplemental retirement benefits described above, retention bonuses determined individually in the Company's discretion for each executive, and special stock option awards that vest over a three-year retention period at 25% for each of the first two years and 50% in the third year.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
All common shares of the Company are indirectly owned by Scottish Power plc, 1 Atlantic Quay, Glasgow, G2 8SP, Scotland.
The following table sets forth certain information as of March 31, 2001 regarding the beneficial ownership of ScottishPower ordinary shares ("ordinary shares") by (1) each of the executive officers named in the Summary Compensation Table under Item 11 above, (2) each director of PacifiCorp as detailed under Item 10 and (3) all executive officers and directors as a group. As of March 31, 2001, each of the directors and executive officers identified above and all directors and executive officers of the Company as a group owned less than 1% of the outstanding ordinary shares of ScottishPower.
| Number of shares |
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(1) Includes ownership of (a) shares held by family members even though beneficial ownership of such shares may be disclaimed, (b) shares held for the account of such persons pursuant to the PacifiCorp Compensation Reduction Plan and the PacifiCorp K Plus Savings and Stock Ownership Plan, (c) shares granted and vested or unvested shares for which the individual has voting but not investment power under the PacifiCorp Stock Incentive Plan, (d) shares granted and vested under the LTIP and (e) shares held in the ESOP.
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(2) Options granted in ScottishPower ADS ("ADS") under the PacifiCorp Stock Incentive Plan have been converted into options in ordinary shares in the above table. One ADS equates to four ordinary shares.
(3) Mr. Meier resigned from the Company, effective April 1, 2001. Between April 1, 2001 and May 18, 2001 he became beneficially entitled to a further 2,028 restricted shares subject to vesting and 17,788 shares subject to vesting under the PacifiCorp Stock Incentive Plan.
Mr. Lorenzini's interests have been excluded from the above table as he retired from the Company on September 29, 2000.
Between April 1, 2001 and May 18, 2001, Messrs. Russell, Landels, Richardson and Vowles have become beneficially entitled to a further 12,682, 3,869, 4,578 and 9,028, respectively, of shares subject to vesting under the LTIP.
On May 9, 2001, Mr. Richardson exercised 9,661 of his vested shares under the LTIP.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this item is set forth under "Executive Compensation" in Item 11 and "Security Ownership of Certain Beneficial Owners and Management" in Item 12 above.
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*(2)c - Centralia Plant Purchase and Sale Agreement, dated as of May 7, 1999, by and among PacifiCorp, Public Utility District No. 1 of Snohomish County, Washington, Puget Sound Energy, Inc., City of Tacoma, Washington, Avista Corporation, City of Seattle, Washington, Portland General Electric Company, Public Utility District No. 1 of Gray Harbor County, Washington and TECWA Power, Inc. (Exhibit (2)c, Form 10-K for the year ended March 31, 2000, File No. 1-5152).
*(2)d - Centralia Coal Mine Purchase and Sale Agreement, dated as of May 7, 1999, by and among PacifiCorp, Centralia Mining Company and TECWA Fuel, Inc. (Exhibit (2)d, Form 10-K for the year ended March 31, 2000, File No. 1-5152).
*(3)a -- Third Restated Articles of Incorporation of the Company (Exhibit (3)b, Form 10-K for the year ended December 31, 1996, File No. 1-5152).
*(3)b -- Bylaws of the Company effective November 29, 1999 (Exhibit (3)b, Form 10-K for the year ended March 31, 2000, File No. 1-5152).
*(4)a -- Mortgage and Deed of Trust dated as of January 9, 1989, between the Company and Morgan Guaranty Trust Company of New York (The Chase Manhattan Bank, successor), Trustee, as supplemented and modified by thirteen Supplemental Indentures (Exhibit 4-E, Form 8-B, File No. 1-5152; Exhibit (4)(b), File No. 33-31861; Exhibit (4)(a), Form 8-K dated January 9, 1990, File No. 1-5152; Exhibit 4(a), Form 8-K dated September 11, 1991, File No. 1-5152; Exhibit 4(a), Form 8-K dated January 7, 1992, File No. 1-5152; Exhibit 4(a), Form 10-Q for the quarter ended March 31, 1992, File No. 1-5152; and Exhibit 4(a), Form 10-Q for the quarter ended September 30, 1992, File No. 1-5152; Exhibit 4(a), Form 8-K dated April 1, 1993, File No. 1-5152; Exhibit 4(a), Form 10-Q for the quarter ended September 30, 1993, File No. 1-5152; Exhibit 4(a), Form 10-Q for the quarter ended June 30, 1994, File No. 1-5152; Exhibit (4)b, Form 10-K for the year ended December 31, 1994, File No. 1-5152; and Exhibit (4)b, Form 10-K for the year ended December 31, 1995, File No. 1-5152; Exhibit (4)b, Form 10-K for the year ended December 31, 1996, File No. 1-5152); and (Exhibit (4)b, Form 10-K for year ended December 31, 1998, File No. 1-5152).
*(4)b -- Third Restated Articles of Incorporation and Bylaws. See (3)a and (3)b above.
In reliance upon item 601(4)(iii) of Regulation S-K, various instruments defining the rights of holders of long-term debt of the Registrant and its subsidiaries are not being filed because the total amount authorized under each such instrument does not exceed 10% of the total assets of the Registrant and its subsidiaries on a consolidated basis. The Registrant hereby agrees to furnish a copy of any such instrument to the Commission upon request.
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*(10)a -- Short-Term Surplus Firm Capacity Sale Agreement executed July 9, 1992 by the United States of America Department of Energy acting by and through the Bonneville Power Administration and Pacific Power & Light Company (Exhibit (10)n, Form 10-K for the year ended December 31, 1992, File No. 1-5152).
*(10)b -- Restated Surplus Firm Capacity Sale Agreement executed September 27, 1994 by the United States of America Department of Energy acting by and through the Bonneville Power Administration and Pacific Power & Light Company (Exhibit (10)t, Form 10-K for the year ended December 31, 1994, File No. 1-5152).
(13) -- Form 10-QT for the transition period from January 1, 1999 to March 31, 1999.
(21) -- Subsidiaries.
(23)a -- Consent of Deloitte & Touche LLP with respect to Annual Report on Form 10-K.
(23)b -- Consent of PricewaterhouseCoopers LLP with respect to Annual Report on Form 10-K.
(23)c -- Consent of Deloitte Touche Tohmatsu with respect to Annual Report on Form 10-K.
(23)d -- Report of Independent Accountants with respect to PacifiCorp Australia Limited Liability Company and its subsidiaries.
(24) -- Powers of Attorney.
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*Incorporated herein by reference.
(b) Reports on Form 8-K.
On Form 8-K dated February 2, 2001, under "Item 5. Other Events," the Company filed two news releases concerning the Utah Public Service Commission granting an immediate $70 million rate increase.
(c) See (a) 3. above.
(d) See (a) 2. above.
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SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON ITS BEHALF BY THE UNDERSIGNED THEREUNTO DULY AUTHORIZED.
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Date: May 24, 2001
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED.
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