SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
/X/ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended March 31, 2000
OR
/ / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the Transition period from _________ to _________
Commission File Number 1-5152
PACIFICORP
(Exact name of registrant as specified in its charter)
State of Oregon 93-0246090
(State or other jurisdiction (I.R.S. Employer Identification No.)
of incorporation or organization)
825 N.E. Multnomah, Portland, Oregon 97232
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (503) 813-5000
Securities registered pursuant to section 12(b) of the Act:
| Name of each exchange | |
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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 1, 2000, the aggregate market value of the shares of voting and nonvoting common equity of the Registrant held by nonaffiliates was $0.
As of June 14, 2000, there were 297,324,604 shares of common stock outstanding. (All common shares are indirectly owned by ScottishPower.)
DOCUMENTS INCORPORATED BY REFERENCE
None.
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
ITEM 1. BUSINESS
THE ORGANIZATION
The Company is an electricity company in the United States and Australia. 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, including Powercor, the largest of the five electric distribution companies in Victoria, Australia.
The Company's strategic business plan is to focus on its electricity businesses in the western United States. As part of its strategic business plan, the Company will sell its other United States and international businesses, and has previously terminated all of its business development activities outside of the United States. During January 2000, the Company committed to seek a buyer for Powercor. 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 limit its pursuit of new tax-advantaged investment opportunities. See "AUSTRALIAN ELECTRIC OPERATIONS," "DISCONTINUED OPERATIONS," and "OTHER OPERATIONS."
On November 29, 1999, the Company and ScottishPower completed their proposed 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 will remain 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.
In the Merger, each share of the Company's 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.
Effective November 30, 1999, the Company changed its fiscal year end from December 31 to March 31, which is the fiscal year end for ScottishPower. A report on Form 10-Q for the three-month transition period from January 1, 1999 through March 31, 1999 was filed with the Securities and Exchange Commission on January 13, 2000. The year ended March 31, 2000 and quarterly periods within that year are referred to as 2000. All future years refer to fiscal years ending March 31. The years ended December 31, 1998 and 1997 are referred to as 1998 and 1997, respectively. Powercor's fiscal year end remains December 31. Consequently, the Company's consolidated balance sheet and statements of consolidated income and consolidated cash flows as of and for year ended March 31, 2000 include Powercor's financial statements as of and for the year ended December 31, 1999.
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As a result of the Merger, the Company has developed and commenced a transition plan (the "Transition Plan") to implement significant organizational and operational changes. For more information, see "ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - OVERVIEW OF 2000."
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 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; regional, national and international economic conditions; weather variations affecting customer usage, competition in bulk power and natural gas markets and hydroelectric and natural gas production; hydro-facility relicensing; energy trading activities; environmental, regulatory and tax legislation, including industry restructure and deregulation initiatives; technological developments in the electricity industry; foreign exchange rates; proposed asset dispositions; and the cost 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 3/8% Quarterly Income Debt Securities (Junior Subordinated Deferrable Interest Debentures, Series A) and 8.55% Quarterly Income Debt Securities (Junior Subordinated Deferrable Interest Debentures, Series B) are traded on the New York Stock Exchange. The 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% Cumulative Quarterly Income Preferred Securities (Series B Preferred Securities) of PacifiCorp Capital II, a wholly owned subsidiary trust, are also 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.
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 Company's service area contains diversified industrial and agricultural economies. Principal industrial customers include oil and gas extraction, lumber and wood products, paper and allied products, chemicals, primary metals, mining companies, high technology, and agribusiness. Agricultural products include potatoes, hay, grain and livestock.
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The Company is currently exiting operations in California. See "Proposed Asset Additions and Dispositions."
The geographical distribution of the Company's retail electric operating revenues for the year ended March 31, 2000 was Utah, 38%; Oregon, 33%; Wyoming, 13%; Washington, 8%; Idaho, 6%; and California, 2%.
Customers
Electric utility revenues and energy sales, by class of customer, for the year ended March 31, 2000, the three months ended March 31, 1999, and the years ended December 31, 1998 and 1997, were as follows:
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The Company's service territory has 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.
During 2000, no single retail customer accounted for more than 2% of the Company's retail utility revenues and the 20 largest retail customers accounted for 14% 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
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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.
During 2000, 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 provision of tariffed services in California will continue to be regulated while any competitive sales of electricity will be unregulated. The other states in the Company's service territory have, to varying degrees, examined retail competition and industry restructuring, but only Oregon has enacted comprehensive legislation. Generally, the other states are moving more slowly towards competition than was originally anticipated by the Company. See "Regulation." The Company supports increased customer choice under terms and conditions that are equitable to all stakeholders.
During July 1999, legislation was enacted in Oregon that requires competition for industrial and large commercial customers of both the Company and Portland General Electric by October 1, 2001. Residential customers will have the option of selecting a cost of service rate or a portfolio of energy commodity rate options. The law generally exempts publicly-owned utilities and Idaho Power's Oregon service territory. The law authorizes the Oregon Public Utility Commission (the "OPUC") to make decisions on a variety of important issues, including the method for valuation of stranded costs/benefits, consumer protections, marketer certification, environmental issues, and competitive services. The legislation also calls for the establishment of a code-of-conduct for electric companies and their affiliates to protect consumers against anti-competitive practices. The legislation directs the investor-owned utilities to collect a 3% public benefit charge from all of its distribution customers. The Company is currently participating in the OPUC proceedings to establish the rules and procedures that will implement the new law. The Company will continue to evaluate the finance and accounting impacts, including the continued propriety of applying Statement of Financial Accounting Standards ("SFAS") No. 71, as the OPUC proceedings progress. The impacts, if any, are uncertain.
The Energy Policy Act, passed in 1992, opened wholesale competition to energy brokers, independent power producers and power marketers. In 1996, the Federal Energy Regulatory Commission (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. Competition is also influenced by availability and price of alternate energy sources and the general demand for electrical power.
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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 mandated a 10% rate reduction, which resulted in a $3.5 million annual reduction in revenues. The Company has decided to refrain from marketing products and services to retail customers in California but intends to continue limited trading in the wholesale business, selling to utilities in California and marketers elsewhere in the western United States.
The Company believes that the regulatory initiatives that are underway in each of the states may eventually bring competition for the electricity generation services. This change in the regulatory structure may significantly affect the Company's future financial position, results of operations and cash 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 SFAS No. 71 in its financial statements. In 1999, the Company filed for rate increases before the state commissions in Oregon, Utah, Washington and Wyoming. See "Regulation."
Power and Fuel Supply
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.
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. In periods of favorable hydroelectric generation conditions, the Company utilizes lower-cost hydroelectric power to supply a greater portion of its load and sells its displaced higher-cost thermal generation to other utilities. In periods of less favorable hydroelectric generation conditions, the Company sells its excess thermal generation to utilities that are more dependent on hydroelectric generation than the Company. During the winter, the Company is 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 is able to sell excess power to utilities in the southwestern United States to assist them in meeting their peak requirements. See "Wholesale Sales and Purchased Power."
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The Company owns or has interests in generating plants with an aggregate nameplate rating of 8,331 megawatts ("MW") and plant net capability of 7,829 MW. See "ITEM 2. PROPERTIES." With its present generating facilities, under average water conditions, the Company expects that approximately 6% of its energy requirements for 2001 will be supplied by its hydroelectric plants and 64% by its thermal plants. The balance of 30% is expected to be obtained under long-term purchase contracts, and interchange and other purchase arrangements. During 2000, approximately 7% and 61% of the Company's energy requirements were supplied by its hydroelectric and thermal generation plants, respectively, and the remaining 32% by purchased power.
The Company currently purchases 1,100 MW of firm capacity annually from the federal Bonneville Power Administration ("BPA") pursuant to a long-term agreement. The purchase amount declines to 925 MW annually beginning in July 2000, declining to 750 MW annually 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, 2000 was $74 million. The agreement provides for the amount of the payment to decline proportionately as the amount of power purchased declines and also to change at the rate of change of BPA's average system cost. The next change to BPA's average system cost is expected to occur in 2001 and will be determined by BPA in future rate proceedings.
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 2000, the Company purchased an average of 112 MW from qualifying facilities, compared to an average of 98 MW in 1998. See Note 14 of Notes to the Consolidated Financial Statements under ITEM 8 for additional details relating to the Company's purchase of power under long-term arrangements.
The Company plans and manages its capacity, energy purchases and energy resources based on critical water conditions. Under critical or better water conditions in the Pacific Northwest, the Company believes that it has adequate reserve capacity for its requirements. The Company's historical total firm peak load (including both retail and firm wholesale sales) of 12,301 MW occurred on February 10, 1998, and its historical on-system firm peak load of 7,909 MW occurred on December 21, 1998.
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. In 2000, the Company's wholesale revenues decreased 60% and its wholesale energy volume sold decreased 64% from the prior year. Wholesale sales accounted for 42% of the Company's total energy sales and 32% of its total energy revenues in 2000.
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. Long-term firm power purchases supplied 10% of the Company's total energy requirements in 2000. Short-term firm and nonfirm power purchases
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supplied 22% of the Company's total energy requirements in 2000. See Note 14 of Notes to the Consolidated Financial Statements under ITEM 8 for further discussion on long-term firm power purchases requirements.
Asset Sales
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, subject to certain post-closing adjustments. The Company operated the plant and owned a 47.5% share. After the return to customers, required by the regulatory approvals, the Company estimates a $14 million loss will be realized on the sale. The timing of this return to customers varies by state. The sale was pursued by the owners, in part, because of emerging deregulation, competition in the electricity industry and the need for environmental compliance expenditures. 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 has been incorporated into the estimate of net loss on the sale.
Proposed Asset Additions and 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. On July 15, 1999, the Company signed a definitive agreement for the sale of the assets to Nor-Cal Electric Authority for $178 million. The Company does not expect to incur a material gain or loss on this sale. On August 16, 1999, the Company filed an application with the CPUC for approval of the sale. FERC approved the sale on January 28, 2000. The sale is expected to close in the fall of 2000.
On April 12, 2000, the Company announced the closure of the Trail Mountain Mine in the fall of 2001 after the lease is mined out. This will result in the eventual displacement of 200 employees. The mine is located in Central Utah and supplies fuel to the Hunter Plant. The fuel for the Hunter Plant will be provided by the Company's Deer Creek Mine and other Utah mines. With the early closure of the mine, there may be additional reclamation costs for which the Company would seek recovery through future rate cases.
Projected Demand
The Company continues to benefit from positive economic conditions in several portions of its service territory and retail energy sales for the Company have experienced compound annual growth of 2.0% since 1994. The Company is seeing a turnaround from the downturn in international economic conditions, particularly in the Far East and Japan, that negatively impacted the Company's service territories in the Pacific Northwest and many of the industries the Company serves. 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 a transition plan which resulted from the Merger.
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For the periods 2001 to 2004, the average annual growth in retail kilowatt hour ("kWh") sales in the Company's franchise service territories is estimated to be about 1.4%. 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.
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 operations, principally its fossil fuel-fired electric generating plants, are subject to regulation under the Federal Clean Air Act, individual state clean air requirements and in some cases local air authority requirements. The primary air pollutants of concern are sulfur dioxide ("SO2"), nitrogen oxides ("NOx"), particulate matter (currently PM10) and opacities. In addition, visibility requirements impact the coal-burning plants. Although not presently regulated, emissions of carbon dioxide ("CO2") and mercury from coal-burning facilities generally are of increasing public concern.
The United States Environmental Protection Agency (the "EPA") has recently commenced enforcement actions against the owners of certain coal-fired generating plants in the eastern and midwestern United States. The EPA is alleging that the plant owners have failed to obtain the necessary permits under the Clean Air Act in connection with certain alleged modifications at the plants and that the owners have failed to install additional pollution control equipment as required. If the EPA is successful in asserting its position, the companies named in the action will be required to make significant capital expenditures to install pollution control equipment. The Company does not have an ownership interest in any of the plants involved in these matters, and the Company is not a party to any of these actions. Nevertheless, the Company has become aware that the EPA is engaged in fact-finding with respect to many coal-fired generating plants in the country. The Company is unable to predict the outcome of the EPA's fact-finding effort.
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Pollutants -- Emission controls, low sulfur coal, plant operating practices and continuous emissions monitoring are all utilized to enable coal-burning plants to comply with opacity, visibility and other air quality requirements. All of the Company's coal-burning plants burn low sulfur coal and are equipped with controls to limit emissions of particulate matter. Many of the Company's coal-burning plants, representing the majority of its installed capacity, have been equipped with controls which reduce the quantity of SO2 emissions. The SO2 emission allowances awarded to the Company under the Federal Clean Air Act, and those allowances expected to be awarded annually in the future, are sufficient to enable the Company to meet its current and expected future requirements. In addition, the Company has taken advantage of opportunities to sell SO2 allowances to other entities.
Visibility -- Various federal and state agencies, as well as private environmental awareness groups, have raised concerns about perceived visibility degradation in some areas which are in proximity to some of the Company's coal-burning plants. Numerous visibility studies have been completed or are in the process of completion near Company coal-burning plants in Colorado, Utah, Washington and Wyoming. To date, no additional emission control requirements at Company facilities have resulted directly from these studies, although the potential exists for significant additional control requirements if visibility degradation in the study areas is reasonably attributed to the Company's coal-burning plants. The EPA also has implemented new regulations addressing regional haze. These proposed regulations have the potential to impose significant new control requirements on certain of the Company's older coal-burning plants that are not otherwise subject to the most stringent emission limits.
Climate Change -- CO2 emissions are the subject of growing world-wide discussion and action in the context of global warming, but such emissions are not currently regulated. All of the Company's coal-burning plants emit CO2. In late 1997, the United States and other parties to the United Nations Framework Convention on Climate Change adopted the Kyoto Protocol regarding the control and reduction of so-called greenhouse gas emissions (including CO2). The United States signed the protocol in November 1998, but the United States Senate has not yet ratified it. The Kyoto Protocol, if ultimately ratified, has the potential to impose significant new costs and operational restrictions on the Company's coal-burning plants.
Mercury -- The Company's coal-burning plants, along with all other major coal-burning plants in the United States, are participating 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 is scheduled to decide during calendar 2000 whether to regulate mercury emissions from coal-burning plants. If passed, new mercury emission requirements have the potential to impose significant new control and operational constraints on the Company's coal-burning plants.
Air Operating Permits -- The Company has received Title V Air Operating Permits for all of its coal and natural gas-fired power plants. In 1998, a citizen group challenged the issuance of the operating permits for the Company's Naughton and Jim Bridger power plants, but the EPA still has not yet
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acted on that challenge. The Company believes that it currently has all required permits and management systems in place to assure compliance with operating permit requirements.
Enforcement -- In addition to general regulation, the Company is subject to ongoing enforcement action by regulatory agencies and private citizens regarding compliance with air quality requirements. A federal lawsuit filed in 1996 by the Sierra Club against the owners, including the Company, of units one and two of the Craig Generating Station alleged, among other things, violations of opacity requirements. The lawsuit seeks civil monetary penalties and an injunction. See "ITEM 3. LEGAL PROCEEDINGS."
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.
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 generating 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 and increasing the costs of operating the Company's own hydroelectric resources. These actions could also result in further restrictions on timber harvesting and adversely affect 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.
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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 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 Federal Power Act 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 requirement and restrictions of the Public Utility Holding Company Act of 1935.
The Company is currently in the process of relicensing or preparing to relicense 16 separate hydroelectric projects under the Federal Power Act. These projects, some of which are grouped together under a single license, represent approximately 1,000 MW, or about 94% of the Company's total hydroelectric nameplate capacity and about 14% of its total generating capacity. 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. See "Environmental Issues - Endangered Species." The Company is unable to predict the impact of imposition of such conditions, but capital expenditures and operating costs are expected to increase in future periods. In addition, the Company may refuse to accept renewed licenses for certain projects if the terms of renewal would make the projects uneconomical to operate. The Company 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. The Utah Public Service Commission (the "UPSC") approved new depreciation rates in an order dated January 6, 2000. The OPUC approved new depreciation rates in an order dated May 31, 2000. Stipulated rates have been agreed upon in Wyoming, with a final order still pending. The impact of the proposed changes in depreciation is being incorporated into the current general rate cases in Oregon and Washington and the next general rate case in the other states. Based on the depreciation rates that have been approved and are pending approval, 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 plant. 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 all states, will amount to approximately $14 million per year.
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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. The sale was completed on May 4, 2000. FERC approved the sale on January 13, 2000. For additional information on the sale of Centralia, see "Asset Sales."
Merger Orders
On June 10, 1999, the CPUC issued an order approving the Merger. The CPUC conditioned its approval on the Company's acceptance of requirements which primarily addressed the Commission's ability to continue to regulate the Company's California service territory.
On November 22, 1999, the Wyoming Public Service Commission ("WPSC") issued an order approving the Merger. The Company agreed to make an informational filing in 2001 that guarantees reflection of $4 million per year in merger savings in future rate cases. The Company separately agreed to limit any rate increase filing in 1999 to $12 million and in the following year to $8 million plus the effect of any change in depreciation rates. See "Regulation."
On October 6, 1999, the OPUC issued an order approving the Merger. As part of this approval, the Company agreed to provide a merger credit to retail customers of $12 million per year for three years beginning in calendar 2001 and $15 million in calendar 2004. In calendar 2003 and 2004, $9 million and $12 million, respectively, of the credit can be partially or wholly eliminated to the extent that merger-related cost savings are reflected in prices.
On October 14, 1999, the Washington Utilities & Transportation Commission (the "WUTC") approved the Merger. As part of this approval, the Company agreed to provide retail customers a merger credit of $3 million per year for four years beginning in calendar 2001. The credit can be wholly or partially eliminated in all years to the extent that merger-related cost savings are reflected in prices.
On November 15, 1999, the Idaho Public Utilities Commission (the "IPUC") approved the Merger. As part of this approval, the Company agreed to provide a $1.6 million per year merger credit to retail customers for four years beginning in calendar 2000. The credit can be wholly or partially eliminated in years three and four to the extent that merger-related cost savings are reflected in prices.
On November 24, 1999, the UPSC approved the Merger. As part of this approval, the Company agreed to provide a merger credit for retail customers of $12 million per year for four years beginning in calendar 2000. The credit can be wholly or partially eliminated in years three and four to the extent that merger-related cost savings are reflected in prices.
The Company's total obligation for merger credits described above is $133.4 million over the period ending December 31, 2004. Of this amount, $57.2 million must be provided without offset or reduction of any kind and, accordingly, the Company has recorded $57.2 million as a liability and current expense in its financial statements for the year ended March 31, 2000. The
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remaining $76.2 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 $76.2 million obligation will be reflected in future periods.
A summary of regulatory and legislative developments in the states where the Company conducts its distribution and retail electric operations is set forth below.
Utah. On March 4, 1999, the UPSC ordered the Company to reduce revenues in Utah by $85 million, or 12%, annually. The ordered reduction was the culmination of a general rate case that began in 1997. Additionally, the UPSC ordered a refund to be issued through a credit on customer bills of $40 million. The Company recorded a $38 million reduction in revenues in 1998 and recorded the remaining $2 million in the three months ended March 31, 1999. The refund covers the period from March 14, 1997 to February 28, 1999. The beginning date is consistent with the timing of Utah legislation imposing a moratorium on rate changes after the Utah Division of Public Utilities (the "UDPU") and the Utah Committee of Consumer Services (the "UCCS") requested a general rate case. The $85 million reduction commenced on March 1, 1999. The order also reduced the Company's authorized rate of return on equity from 12.1% to 10.5%.
On September 20, 1999, the Company filed for a rate increase before the UPSC. The Company asked for an increase of $67 million, or 9.9%, based on a test year ended December 31, 1998 and a requested 11.25% return on equity. On March 15, 2000, the Company filed a revised request of $55.2 million. On May 24, 2000, the Company received an order from the UPSC authorizing the Company to increase prices in Utah for residential, irrigation, small commercial and lighting customers by 4.24% and large commercial and industrial customers by less than 1%. The price increase is expected to result in annual revenues of $17 million. The order allowed a rate of return on equity of 11% and was effective on May 25, 2000.
The 2000 Utah legislative session passed a bill that could significantly change the way in which utilities are regulated in the state. The bill provides guidelines under which the interests of all parties will be protected and balanced in the ratemaking process. It directs the UPSC to determine fair rates by balancing the interests of utility customers with the need of utilities to maintain financial stability. This legislation also streamlines state government by consolidating the UDPU and the UCCS into one agency - the Office of Public Advocate. The bill modifies the nature of UPSC proceedings by encouraging and providing an opportunity for timely and reasonable settlements without restricting the rights of all interested persons to participate in a formal administrative process. Finally, the legislation requires Utah regulators to reflect "known and measurable" changes to financial data when hearing a rate case. This bill is effective July 1, 2001.
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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 2001 legislative session, unless it is not in Utah's best interest to do so.
Oregon. The OPUC and the Company have agreed to an Alternate Form of Regulation ("AFOR") for the Company's Oregon distribution business. The AFOR allows for index-related price increases in 1998, 1999 and 2000, with an annual cap of 2% of distribution revenues in any one year and an overall cap of 5% over the three-year period. The annual revenue increase for the twelve months ended December 31, 1999 was approximately $6.2 million. The AFOR also includes incentives to invest in renewable resources and penalties for failure to maintain the service quality levels. On April 30, 1999, the Company filed for changes in the prices it charges Oregon customers under the AFOR. The filing also contained a request to increase the revenues collected under the Company's system benefits charge. The changes were approved by the OPUC in June 1999, and became effective July 1, 1999. This resulted in a price increase of approximately 1.3%, or $9 million annually, in Oregon. On April 28, 2000, the Company made an additional AFOR filing for a price increase of 1.8%, or $14 million annually. Of this amount, approximately $10 million is offset by costs mandated by regulators.
On November 5, 1999, the Company filed for a general rate increase in Oregon. The Company is asking for an increase of $61.8 million, or 8.5%. The Company's effective date for this increase is expected to be in the fall of 2000. The OPUC staff has submitted a preliminary report raising issues that in the aggregate could produce a $101 million rate reduction after giving effect to the Centralia sale. The staff testimony is due in June 2000 and hearings are scheduled for August 2000.
During July 1999, legislation was enacted in Oregon that requires competition for industrial and large commercial customers of both the Company and Portland General Electric by October 1, 2001. See "Competition."
Wyoming. On July 26, 1999, the Company filed for a rate increase before the WPSC. The Company requested an increase of $12 million, or 4.9%, based on a test year ended December 31, 1998. The Company has also stipulated that any rate increase filings through May 2001 will not exceed $8 million plus the effects of any change in depreciation rates. On May 23, 2000, the Company received an order from the WPSC authorizing the Company to increase prices in Wyoming, resulting in increased annual revenues of $11 million. The order allowed a total rate of return of 8.85%, a return on common equity of 11.25% and was effective May 25, 2000. The WPSC did not allow recovery of approximately $1 million of the requested $12 million increase allocated to partial requirements industrial customers, finding that the cost of service study was not sufficient to support the increase to this class. The Company is in the process of refiling for this $1 million increase with a supplemental cost of service study.
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Washington. On November 23, 1999, the Company filed for a rate increase before the WUTC. This rate increase contains two phases. In the first phase, the Company is asking for an increase of $14.6 million, or 8.10%. Including the systems benefit charge, which will be used to fund conservation and new renewable development projects, this increase is $17.4 million, or 9.64%. In the second phase, the Company is requesting an increase of $11.2 million, or 5.65%. The effective date for phase one of this proposed tariff increase is expected to be in the fall of 2000, and phase two would become effective one year following the effective date of phase one.
Idaho. On April 28, 2000, the Company filed documents with the IPUC to implement the next step in the gradual retirement of a BPA energy credit. The proposed reduction in the credit would increase electric prices for the Company's residential and irrigation customers in southeastern Idaho. The filing, once approved by the IPUC, would reduce the credits from the BPA and increase residential prices 3.35%, or $1 million, and irrigation prices 8%, or $2 million. These price increases phase out the BPA credit and do not have any impact on earnings.
Congress created the federal credit in 1980 to share the benefits of federally owned hydroelectric plants with customers of investor-owned utilities in the Columbia River drainage area. Congress recommended in 1995 that the current exchange method be phased out by June 2001. In 1997, the Company reached a settlement with BPA to implement the order of Congress. The settlement provided credits of $48 million over five years for the Company's customers, which lessens the impact of price increases as the BPA exchange credit is phased out.
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, 2000, the Company's SFAS No. 71 regulatory assets for all states totaled $703 million, of which approximately $310 million is applicable to generation. The Company has no regulatory assets outside of 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 2000 and the Company's estimated construction costs for 2001 through 2003, including costs of acquiring demand-side resources. The estimates of construction costs for 2001 through 2003 are subject to continuing review and appropriate revision by the Company and are based on the Company's transition plan.
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AUSTRALIAN ELECTRIC OPERATIONS
Powercor
General
Powercor, an indirect, wholly owned subsidiary of Holdings, is the largest electricity distribution company ("Distribution Company") in Victoria, Australia, based on sales volume, revenues, geographic scope and number of customers. Powercor's principal business segments are its Distribution Business and its Supply Business. The Distribution Business consists of the distribution of electricity to approximately 570,000 customers within Powercor's distribution area, covering from the western suburbs of Melbourne to central and western Victoria. The Supply Business consists of the purchase of electricity from generators and the sale of such electricity to customers in Powercor's distribution service area and other parts of Victoria, New South Wales ("NSW"), the Australian Capital Territory ("ACT") and Queensland. Powercor's distribution service area covers approximately 57,900 square miles (64% of the total area of Victoria), has a population of approximately 1.5 million (32% of Victoria's population) and accounts for 26% of Victoria's Gross State Product. In 1999, Victoria accounted for approximately 25% of Australia's total population, approximately 32% of Australia's manufacturing industry output and approximately 26% of Australia's Gross Domestic Product, although it represents only approximately 3% of the total area of Australia.
During January 2000, the Company decided to seek a buyer for Powercor. Powercor's fiscal year end remains December 31.
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Distribution Business
Powercor's Distribution Business consists of the ownership, management and operation of the electricity distribution and subtransmission network in its distribution service area. The primary activity of the Distribution Business is the receipt of electricity from Victoria's high voltage transmission system (the "Grid") and the distribution of electricity to customers in Powercor's distribution service area. Substantially all of the Distribution Business is a regulated monopoly. Almost all customers within Powercor's distribution service area are connected to its distribution network, whether electricity is supplied by Powercor or another retail supplier. In 2000, the Distribution Business generated all of Powercor's operating income.
The Distribution Business has grown in both its customer base and the volume of electricity distributed, primarily reflecting economic growth in Victoria generally and Powercor's distribution service area in particular. The following table sets forth the volumes of electricity distributed by Powercor for the years indicated. See "Regulation-Distribution Pricing Regulation" below.
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The Distribution Business of Powercor has not experienced significant competition. Powercor believes that the economics underlying building and maintaining a duplicate distribution network in its distribution service area will restrict the introduction of another network. However, to the extent customers establish or increase their own generation capacity, establish their own private distribution networks, become directly connected to the Grid, or relocate operations outside Powercor's distribution service area, such customers would not require the distribution services of Powercor except in certain cases for standby connection services. As of December 31, 1999, Powercor had not lost any distribution revenues to customers as a result of self-generation, cogeneration or the establishment of private distribution networks. Although Powercor believes that it has effective strategies in place to minimize this type of load loss, there can be no assurance, particularly in view of its large industrial customer base, that the Distribution Business will not experience loss of revenues in the future as a result of such competition.
The major operating expenses of the Distribution Business are distribution use-of-system costs, use-of-transmission-system fees and connection service charges. The use-of-transmission-system fees and connection service charges, regulated by the Tariff Order (see "Regulation - The Tariff Order" below), are payable to the Victorian Energy Network Corporation ("VENCORP"), a corporate body established under Victoria's Electricity Industry Act 1993 (the "EIA"),
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and the company that owns and maintains the Grid, GPU Power Net Victoria ("GPU"), respectively. The fees paid constitute VENCORP's and GPU's costs associated with operation, maintenance and administration of the Grid. The distribution use-of-system costs are Powercor's fundamental operating expenses that result from operating and maintaining its distribution network. Unlike use-of-transmission-system fees and connection service charges, Powercor has the ability, and, given the current distribution price-cap regulatory structure, a significant incentive, to control such distribution use-of-system costs through a variety of cost reduction initiatives. However, there can be no assurance that Powercor's cost efficiency initiatives will yield sufficient savings to increase Powercor's margins from the Distribution Business to offset any network tariff reductions that may result from the Office of Regulator General's (the "ORG") review of distribution tariffs charged by Distribution Companies beginning in 2001, as described below under "Regulation-Distribution Pricing Regulation."
Supply Business
The Supply Business conducts the commercial functions of purchasing, marketing and selling of electricity and is responsible for the management of the price, purchasing and volume risks associated with such functions and end-use demand management. Supply Business customers are subject to partial competition, which is progressing toward full competition beginning January 1, 2001. See "Regulation-Supply Pricing Regulation" below.
The customer metered sites, energy usage in millions of kWh and percentages, as well as percentages of Powercor's revenues from the Supply Business for franchise customers in Powercor's distribution service area and for contestable customers are set forth below:
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The customer metered sites, energy usage in millions of kWh and percentages of Powercor's revenues from the Supply Business for residential, commercial, industrial and other customers for the years 2000 and 1998 are set forth below:
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(1) Connections as of the date shown.
(2) Other customers include farm customers and public lighting.
The Supply Business revenue is derived from major industries such as chemicals, petroleum, food and beverage, wholesale and retail, metal processing and transport equipment. No single customer accounted for more than 3% of Powercor's total revenues in 2000.
Powercor purchases all of its power for sale to franchise customers, other than cogeneration output, through the competitive wholesale market for electricity in Victoria (the "Pool"). As of December 13, 1998, the respective state wholesale markets consolidated to a National Electricity Market ("NEM") which is operated by the National Electricity Market Management Company ("NEMMCO"). There are two major components of the wholesale electricity market: (i) the competitive energy market, centered primarily around the Pool, which establishes the spot price for the sale of electricity by generators to suppliers and (ii) the contract trade, which involves bilateral financial contracts between electricity buyers and sellers outside the Pool that are used to hedge against Pool price volatility. The principal function of the Pool is to allow market forces rather than monopolized central planning to determine the amount, mix and cost characteristics of generating plants and the level and shape of demand of suppliers.
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Powercor is a party to a series of bilateral financial "vesting contracts" that have been structured to hedge the price for Powercor's forecasted franchise energy requirements through December 31, 2000. These vesting contracts take the form of two-way and one-way contracts. Two-way vesting contracts are structured such that generators and Distribution Companies, including Powercor, compensate each other for the difference between the system marginal price, which is the spot price payable to generators in the wholesale market via the Pool, and the contract price up to a specified price cap. One-way vesting contracts provide for amounts to be paid by generators to Distribution Companies for differences when the system marginal price is above a specified price cap. As franchise customers of the Supply Business become contestable, the notional amount of the vesting contracts is reduced accordingly.
Powercor also has hedging contracts that relate to contestable customer loads in order to manage electricity price risk. Historically, Powercor has hedged each electricity sales contract with a back-to-back purchase contract. Increasingly, however, as the contestable customer market grows and as the Australian electricity futures market develops, Powercor is hedging its supply obligations on a portfolio-wide basis. Powercor's policy is to hedge most of its supply obligations and to monitor the financial risk exposure of its unhedged positions.
As of January 1, 2001, all customers in Victoria, the ACT and NSW are scheduled to be contestable, eliminating the use of vesting contracts. Powercor is currently investigating hedging options in preparation for a fully contestable market. Powercor believes that full retail competition in Victoria will be phased in over six months from the official January 1, 2001 start date.
Regulation
Powercor is the largest of the five distribution businesses ("DBs") formed when the Victorian State Government decided to privatize, and eventually deregulate, its electricity industry. As the Victorian market becomes more open to competition and additional customers can choose their energy supplier, Powercor and the other DBs will continue to maintain a monopoly on their individual network areas. These businesses derive much of their revenue from the network fee that is paid for the use of the distribution system.
The ORG. The Victorian government established the ORG pursuant to the Office of the Regulator-General Act 1994 to regulate different Victorian industries. In the context of regulating activities within the electricity industry, the ORG has powers under the EIA. The ORG's functions pursuant to the EIA include granting licenses to generate, transmit, distribute or supply electricity, ensuring compliance with industry codes and rules, administering cross-ownership provisions and administering the Victorian Electricity Supply Industry Tariff Order (the "Tariff Order").
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Licenses. Unless covered by an exemption, the EIA prohibits, without a relevant license, the activities of generation of electricity for supply or sale, transmission, distribution, supply or sale of electricity or operation of a wholesale electricity market. Licenses are issued by the ORG after the applicant has satisfied specific criteria and subject to the satisfaction of ongoing conditions, such as continued compliance with industry codes and rules.
Powercor has an exclusive license to distribute electricity to franchise customers in its distribution service area. This will expire on January 1, 2001. Powercor also has nonexclusive licenses to supply electricity to all customers in its distribution service area and elsewhere in Victoria, NSW, ACT and Queensland. See "Supply Pricing Regulation." The Hazelwood Partnership has a license to generate and sell electricity to the wholesale market in Victoria and NSW. See "Hazelwood" below.
The Tariff Order. Pursuant to the EIA, the Tariff Order regulates charges for connection to, and use of, the transmission system, distribution use-of-system charges that can be levied by Distribution Companies and tariffs for the sale of electricity to franchise customers until December 31, 2000. The ORG is charged with the regulatory oversight of the Tariff Order. The Tariff Order is the key instrument the ORG uses to regulate network prices in the Victorian electricity supply industry.
Distribution Pricing Regulation. Under distribution licenses granted by the ORG, the Distribution Companies are able to levy the following charges, which include their profit: (i) network tariffs, which include recovery of distribution use-of-system costs, use-of-transmission-system fees and GPU connection service charges, (ii) connection charges for connecting customers to the network, taking into account that a portion of the costs of connection are recovered through network tariffs and (iii) charges for other services, which are required to be fair and reasonable. The level of distribution charges, as one element of the network tariffs, is regulated under the Tariff Order through December 31, 2000 pursuant to a formula. The formula is the Consumer Price Index for Melbourne ("CPI") minus a fixed percentage ("X"), or CPI-X. This formula attempts to ensure that the annual increase in the weighted average of distribution charges (weighted by the forecast quantity of electricity to be delivered and adjusted for under and over recovery in previous financial years) does not exceed CPI-1%.
Existing network tariffs are subject to review by the ORG within the framework of, and the principles set forth in, the Tariff Order. In particular, the Tariff Order provides that the ORG, in connection with such review of network tariffs, can only reset the network tariffs for a period of not less than five years, the ORG must utilize price capping and not rate of return regulation and the ORG must consider the need to (i) provide each Distribution Company with incentives to operate efficiently, (ii) ensure a fair sharing of benefits achieved through efficiency between customers and Distribution Companies and (iii) ensure appropriate incentives for capital expenditures and maintenance of the distribution networks. The ORG released a draft Distribution Price Review determination in mid-May 2000. This draft suggested reducing Powercor's regulated distribution revenue in 2001 to $168.7 million (as converted using the May 31, 2000 currency exchange rate of 0.58). This is largely driven by a
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proposed reduction in the regulated rate of return from 11.9% to 7.4% (pre-tax, real). This would result in an average real network tariff cut of 20.6% on January 1, 2001, and an average real reduction of 1% each year thereafter. This is a preliminary report, and a final determination will be made in September 2000 following further consultation.
Supply Pricing Regulation. Under the retail portions of their licenses, Distribution Companies are required, pursuant to the Tariff Order, to supply electricity to franchise customers through December 2000, at prices no greater than the prices specified in the applicable Maximum Uniform Tariff ("MUT") for such customers. The prices specified in the MUTs are therefore fully regulated and inclusive of all network and distribution related charges and energy costs. Powercor's MUTs are adjusted annually by a percentage equal to CPI minus a fixed percentage. Commencing July 1, 2000, the annual adjustments for large and medium businesses will be the CPI and will be the CPI-1% for medium and small businesses and residential and rural customers. The CPI for the years ended December 31, 1999, 1998 and 1997 was 1.8%, 1.2% and 0.2%, respectively.
Prices charged to contestable customers are subject to competitive forces and, therefore, are not directly regulated by the ORG, in contrast to prices charged to franchise customers. Prices to contestable customers include regulated network charges (transmission and distribution) and competitively determined energy supply charges.
Customers in Victoria, the ACT and NSW with annual consumption in excess of 160 megawatt hours ("MWh") per year are now contestable. Customers with usage of 160 MWh per year or less are not currently contestable but will become contestable on January 1, 2001 in Victoria, the ACT and NSW.
Customers in Queensland with annual consumption of 200 kWh per year can now choose their electricity retailer and there are plans to introduce contestability for all customers on January 1, 2001.
For a description of Powercor's properties, see "ITEM 2. PROPERTIES - AUSTRALIA."
Environmental Issues
The nature of Powercor's operations exposes it to risks of varying degrees associated with bushfires and other environmental issues.
Approximately 63% of Powercor's assets are located in fire prone zones. Powercor and its predecessors have developed a comprehensive bushfire risk management and mitigation system to reduce bushfire exposure. This system is based on regular inspections of poles and conductors and the identification and reporting of maintenance items existing on the network that may contribute to an electrically initiated bushfire.
Powercor is subject to various Australian federal and Victorian state environmental regulations, the most significant of which is the Victorian Environment Protection Act of 1970 ("VEPA"). The VEPA regulates, in particular, the discharge of waste into air, land and water, site
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contamination, the emission of noise and the storage, recycling and disposal of solid and industrial waste. The VEPA established the Environment Protection Authority ("Authority") and grants the Authority a wide range of powers to control and prevent environmental pollution. These powers include issuing approvals for construction of works that may cause noise or emissions to air, water or land, waste discharge licenses and pollution abatement notices. Powercor believes it is currently in material compliance with the provisions of the VEPA and no licenses or work approvals from the Authority are currently required for activities undertaken by Powercor.
Hazelwood
General
Hazelwood Pacific Pty Ltd ("Hazelwood Pacific"), an indirect, wholly owned subsidiary of Holdings, holds a 19.9% interest in the Hazelwood Power Partnership (the "Hazelwood Partnership"), which owns a 1,600 MW, brown coal-fired thermal power station (the "Hazelwood Plant") and the adjacent brown coal mine (the "Hazelwood Mine") in Victoria, Australia. The Hazelwood Partnership is composed of Hazelwood Pacific, an affiliate of National Power Corporation PLC ("National Power") (71.94%), and two companies associated with the Commonwealth Bank group of Australia (8.16%). National Power oversees the Hazelwood Plant operations and the Company oversees operations at the Hazelwood Mine. In the fourth quarter of 1998, the Company announced its intent to sell its equity interest in the Hazelwood Partnership and began soliciting bids. Accordingly, the Company recorded a pretax loss of $28 million ($17 million after-tax) to reduce its carrying value in the Hazelwood Power Station to its estimated net realizable value less selling costs.
Through December 2001, Hazelwood Pacific estimates that its contribution to the capital expenditure commitments of the Hazelwood Plant will be $8 million and $6 million for the years 2000 and 2001, respectively. The investment is accounted for on an equity basis. For 1999 and 1998, equity losses from Hazelwood were $2.6 million and $5.5 million, respectively.
The Hazelwood Partnership sells its power through the National Electricity Market and enters into bilateral financial contracts with Australian distribution companies, such as Powercor. Prices vary with weather, economic growth and other factors affecting the supply of and demand for power. Power prices tend to be lowest during Australia's summer months (the fourth and first calendar quarters), except during periods of unusually high temperatures.
For a description of Hazelwood properties, see ITEM 2. PROPERTIES - AUSTRALIA.
Environmental Issues
The operations of the Hazelwood Partnership are subject to environmental regulation. The Hazelwood Partnership is required to obtain licenses from the Authority in connection with certain of its operations, including operations involving the emission or discharge of pollutants. These licenses are generally issued to the Hazelwood Partnership in the ordinary course of business and are terminable upon breach or violation.
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The Hazelwood Plant is fired by brown coal and consequently emits more greenhouse gas per unit of power produced than is emitted by power plants fired by black coal or natural gas. The Australian government has participated in negotiations with governments of other countries with respect to greenhouse gas emission levels. As a result of the December 1997 Kyoto Climate Change Conference, the Australian government committed to limitations on greenhouse gas emissions. It is anticipated that the Australian government will introduce some measures to control greenhouse gas emissions. Such measures could increase capital expenditures at the Hazelwood Plant and could have the effect of making brown coal fired generators less competitive.
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, 2000, 100% of the aircraft in PFS's portfolio investment were Stage III noise compliant. At March 31, 2000, PFS's aviation finance portfolio had total leveraged lease and other financial assets of $326 million (28 aircraft), representing approximately 76% of PFS's consolidated assets.
PFS has four plants in the Birmingham, Alabama area which produce a synthetic coal fuel designed to qualify for tax credits under Section 29 of the Internal Revenue Code. The technology utilized by the plants is licensed from Covol Technologies, Inc.
US Competitive Energy Businesses
The Klamath Cogeneration Project is a 484 MW natural gas-fired power plant under construction near Klamath Falls, Oregon. The City of Klamath Falls owns the plant and PPM is under contract for management, operations and fuel supply. In addition, upon commercial operation, PPM will purchase 227 MW of output from the plant for resale to third parties, and market on behalf of the City the remaining output to municipal and commercial buyers in the Pacific Northwest and northern California. The plant was financed in April 1999 with proceeds from revenue bonds issued by the City of Klamath Falls. Construction began in June 1999 and the plant has a planned commercial operation date of July 2001.
During October 1998, the Company decided to cease operations of its energy trading business in the eastern United States (see "DISCONTINUED OPERATIONS"). The Company amended its FERC tariff to allow PPM to engage in trading business in the western United States. Certain regulatory constraints, however, preclude this business from utilizing the Company's utility assets. The business may add assets in the western United States to support its marketing and trading activity.
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International Operations
Beginning in October 1998, the Company decided to focus on its western United States electric business and to sell or shut down all international businesses and activities, subject to achieving reasonable economic and other terms. The process of exiting the international businesses is nearing completion.
DISCONTINUED OPERATIONS
The Company's discontinued energy trading business includes 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 forward energy trading 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.
EMPLOYEES
PacifiCorp and its subsidiaries had 8,832 employees on March 31, 2000. Of these employees, 7,681 were employed by PacifiCorp and its mining affiliates, 1,043 were employed by Powercor and 108 were employed by PPM, PFS and other subsidiaries.
As a result of the Merger, the Company has developed and commenced the Transition Plan to implement significant organizational and operational changes. As part of this Transition Plan, the Company expects to reduce its work force company-wide by approximately 1,600 over the next five years, mainly through early retirement, voluntary severance and attrition. For more information, see "ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - OVERVIEW OF 2000."
Approximately 55% 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. Due to changes in Australian laws, information concerning union membership is no longer available to employers.
In the Company's judgment, employee relations are satisfactory.
ITEM 2. PROPERTIES
UNITED STATES
The Company owns 52 hydroelectric generating plants and has an interest in one additional plant, with an aggregate nameplate rating of 1,068 MW and plant net capability of 1,131 MW. It also owns or has interests in 17 thermal-electric generating plants with an aggregate nameplate rating of 7,231 MW and plant net capability of 6,666 MW. The Company also jointly owns one wind power generating plant with an aggregate nameplate rating of 33 MW and plant net
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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.
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 Pacific Northwest region 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.
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For a discussion of the sale of the Centralia plant and mine, see "Asset Sales."
Substantially all of the Company's electric utility plants are 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, 2000, excluding the Centralia mine, which was subsequently sold. 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 mined by subsidiaries of the Company.
(2) 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%.
(3) These coal reserves are in underground mines and include the Mill Fork Track of 36 million tons.
(4) 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.
(5) The Company ceased mining operations at this location in October 1999.
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 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 2000, the Company expended $10.6 million of reclamation costs and accrued $4.9 million of estimated final mining reclamation costs. Final mine reclamation funds have
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been established with respect to certain of the Company's mining properties. At March 31, 2000, the Company's pro rata portion of these reclamation funds totaled $67.0 million and the Company had an accrued reclamation liability of $138.7 million at March 31, 2000.
AUSTRALIA
Powercor's electrical distribution network, located in Victoria, Australia, comprises: (i) 66 kilovolts ("kV") and 22 kV subtransmission lines and underground subtransmission cables that transport wholesale energy from 12 terminal stations owned by GPU and controlled, under lease, by the Victoria Power Exchange; (ii) 53 zone substations that transform electricity to lower voltages (22 kV and below) and then distribute the energy through the distribution network; and (iii) 22 kV, 11 kV and 6.6 kV distribution lines, including distribution substations that transform electricity to low voltages (415 volts and below) suitable for connection to the majority of the customers. In addition, Powercor leases its principal executive offices at 40 Market St, Melbourne in Victoria under a four-year lease with an option to renew for another eight years.
The Hazelwood Plant has four stages, each with two 200 MW boiler and turbo generator units, and was constructed progressively between November 1964 and August 1971. The plant has eight units, all of which were in service at March 31, 2000. The Hazelwood Mine has between 400 million and 450 million recoverable tons of brown coal, which is expected to provide the Hazelwood Plant with sufficient quantities of coal. The Hazelwood Plant and Mine are anticipated to be sold along with Powercor. For a discussion of the proposed sale of Powercor, see "ITEM 1. BUSINESS - AUSTRALIAN ELECTRIC OPERATIONS - Powercor - General."
ITEM 3. LEGAL PROCEEDINGS
The Company and its subsidiaries are parties to various legal claims, actions and complaints, two of which are 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.
On October 9, 1996, the Sierra Club filed an action against the Company and the other joint owners of Units 1 and 2 of the Craig Electric Generating Station (the "Station") under the citizen's suit provisions of the Federal Clean Air Act alleging, based upon reports from emissions monitors at the Station, that over 14,000 violations of state and federal opacity standards have occurred over a five-year period at Units 1 and 2 of the Station. (Sierra 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). The Company has a 19.28% interest in Units 1 and 2 of the Station, which is operated by Tri-State Generation and Transmission Association and located in Craig, Colorado.
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The action seeks injunctive relief requiring the defendants to operate the Station in compliance with applicable statutes and regulations, the imposition of civil penalties, litigation costs, attorneys' fees and mitigation. The Federal Clean Air Act provides for penalties of up to $27,500 per day for each violation, but the level of penalties imposed in any particular instance is discretionary. The complaint alleges that the Company and Public Service Company of Colorado are responsible for the alleged violations beginning with the second quarter of 1992, when they acquired their interests in the Station, and that the other owners are responsible for the alleged violations during the entire period. The complaint alleges that there were approximately 10,000 violations since the second quarter of 1992. On March 18, 1999, the district court issued its order regarding summary judgment motions filed by the parties. The court ruled, among other things, that the emission monitors may be used by the plaintiff to establish violations of opacity standards, but that the plant owners are entitled to prove that the reported information is flawed.
Over the period from November 1997 to May 1998, Powercor entered into 11 electricity hedging contracts with a NSW State-owned generator (the "Generator") for the supply of electricity between 1998 and 2008. The contracts were designed to support the long-term supply of electricity by Powercor to its customers and to minimize Powercor's exposure to large fluctuations in the spot electricity price. When the wholesale market price for electricity moved against the Generator in May 1998, the Generator denied that any final and binding contracts had been entered into with Powercor, as both parties had not signed final versions of the confirmations setting out the terms and conditions of each transaction. However, an ISDA Master Agreement was in place between the parties which governed the negotiation, contracting and settlement process of individual contracts between them.
The Generator refused to honor the contracts and Powercor commenced proceedings against the Generator, claiming in the Supreme Court of Victoria that the contracts were valid and enforceable. (Powercor Australia Ltd. v. Pacific Power, Commercial List No. 4931, Case No. 2067 of 1998, Supreme Court of Victoria.) In December 1999, a ruling was issued in favor of Powercor. Specific performance was ordered of the 11 electricity hedge contracts, which were in dispute. Further, the following orders were made requiring payments by the Generator to Powercor: the Generator made payment of $29 million on December 17, 1999 attributable to the performance of the contracts from July 1, 1998 to judgment. This amount reflects the difference between actual payments and payments under the hedges plus interest of $1 million; and the Generator made payment of $2 million on December 24, 1999 as an agreed sum for legal expenses and other costs relating to the proceedings.
On December 21, 1999, the Generator appealed the judgments, declarations and orders on 80 grounds, including substantially all of the key aspects of the decision. The appeal is listed for hearing on October 2, 2000 for eight days.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No information is required to be reported pursuant to this item.
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PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
PacifiCorp is a subsidiary of ScottishPower, which owns all 297,324,604 shares of PacifiCorp's outstanding common stock. Therefore, there is no public market for PacifiCorp's common stock. Dividend information required by this item is included under "Quarterly Financial Data" on page 111 of this Report.
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 is between 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.
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.
ITEM 6. SELECTED FINANCIAL DATA
The information required by this item is included under "Selected Financial Information" on page 106 of this Report.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
OVERVIEW OF 2000
During 2000, the Company began to see the results of its plan to focus on its electricity businesses in the western United States and reduce costs. In April 1999, the Company sold TPC for $150 million. In January 2000, the Company decided to seek a buyer for its Australian utility, Powercor. The Company will seek to sell Hazelwood along with Powercor.
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 will remain 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.
In the Merger, each share of the Company's stock was converted tax-free into a right to receive 0.58 ADS (each ADS represents four ordinary shares) or 2.32 ordinary shares of ScottishPower. Cash was paid in lieu of fractional shares.
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As a result of the 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 work force company-wide by approximately 1,600 over the same five-year period, mainly through early retirement, voluntary severance and attrition. The cost of the early retirement offering will not be determinable until the end of June 2000, the deadline for election by eligible employees. The Company intends to seek regulatory orders to recover costs incurred under the Transition Plan.
A new management structure has been established, including key appointments from ScottishPower, the Company and also from well-known US companies.
Unless otherwise stated, references below to periods in 2000 are to periods in the fiscal year ended March 31, 2000, while references to periods in 1998 and 1997 are to periods in the years ended December 31, 1998 and 1997, respectively.
Australian Electric Operations' financial results for the year ended December 31, 1999 are included in PacifiCorp's financial results for the year ended March 31, 2000. For purposes of this discussion, these financial results are referred to as results for "2000".
Earnings Overview of the Company
Earnings (loss) on common stock | March 31, | December 31, | |
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In 2000 and 1998, the Company incurred a series of nonrecurring items, including ScottishPower merger costs, special charges, discontinued operations of certain businesses and acquisition transaction costs. The table below sets forth the effects of these items to assist the reader.
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Effects of nonrecurring items on earnings:
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(a) In 1998, the Company reported earnings excluding nonrecurring items of $300 million. Included in the calculation of $300 million were Utah rate order adjustments similar to those recorded in 2000 operations. Accordingly, those adjustments are not shown above as nonrecurring.
Earnings on common stock for the Company increased $120 million in 2000 compared to 1998. The Company's 2000 earnings of $65 million reflected $180 million for ScottishPower merger costs and $15 million relating to write-offs of projects under construction.
The Company's 1998 loss of $55 million included special charges of $77 million relating to the Company's early retirement program announced in January 1998 and the additional early retirement offer announced in the fourth quarter of 1998, $13 million for ScottishPower merger costs, $55 million relating to the write off of costs associated with The Energy Group PLC ("TEG") transaction and the closing of foreign currency options in April 1998 associated with the terminated bid for TEG and a $10 million gain on sale of TEG shares. In addition, the Company recorded charges in 1998 of $155 million, which included $105 million relating to the provision for losses on disposition of TPC and the eastern U.S. energy trading segment, $17 million relating to the write down of the Company's investment in Hazelwood, and $32 million relating to the provision for losses on disposition of other energy development businesses.
Excluding these nonrecurring items, the Company's 2000 earnings on common stock from continuing operations would have been $258 million compared to $276 million in 1998, a decrease of $18 million.
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The following table shows where ScottishPower merger costs have been recorded in the Company's financial results.
ScottishPower Merger Costs | March 31, | December 31, | March 31, | December 31, |
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Domestic Electric Operations' contribution to earnings on common stock was $11 million in 2000. After adjusting earnings by $192 million for ScottishPower merger costs and a write-off of projects under construction, the contribution was $203 million. Domestic Electric Operations' contribution to earnings on common stock in 1998 was $131 million. After adjusting earnings by $90 million for special charges and other adjustments, the contribution was $221 million. The $18 million decrease from 1998 earnings was the result of several factors, including lower wholesale margins in the western United States.
Australian Electric Operations' contribution to earnings was $39 million in 2000. After adjusting earnings by $1 million for currency exchange rate fluctuations, the contribution was $38 million. The currency exchange rate for converting Australian dollars to United States dollars averaged 0.65 in 2000 compared to 0.63 in 1998, a 3% increase. The 2000 earnings were impacted by increased network revenues due to the effects of contestability. The 1998 earnings of $13 million included the impact of the $17 million write down of the Company's investment in the Hazelwood Power Station.
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Other Operations reported net income of $14 million in 2000 as compared to a loss of $52 million in 1998. The 2000 results included $3 million in expenses relating to ScottishPower merger costs, as well as a decrease in interest income of $31 million. An income increase at PFS's synthetic fuel producing businesses in 2000 totaled $13 million. After-tax losses associated with exiting energy development businesses were approximately $7 million in 2000 and $19 million in 1998. The 1998 results included $32 million in losses relating to the decision to exit the energy development businesses, $55 million in costs associated with the Company's terminated bid for TEG and closing foreign currency options in April 1998, and a gain of $10 million relating to the sale of TEG shares.
Discontinued Operations reported a net after-tax gain on exiting discontinued operations of $1 million in 2000 compared to losses in 1998 of $147 million. The 1998 results included $105 million for the losses anticipated to dispose of TPC and exit the eastern United States energy trading business and a loss of $42 million relating to these operations prior to discontinuance.
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; regional, national and international economic conditions; weather variations affecting customer usage; competition and prices in electric power and natural gas markets and hydroelectric and natural gas production; hydro-facility relicensing; energy trading activities; environmental, regulatory and tax legislation, including industry restructure and deregulation initiatives; technological developments in the electricity industry; foreign exchange rates; proposed asset dispositions; and the cost 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
REVENUES
Revenues | March 31, | December 31, | |
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Total Domestic Electric Operations' revenues decreased $1.55 billion, or 32%, from 1998 to $3.29 billion in 2000 primarily due to a decrease in wholesale revenues of $1.55 billion. Retail revenues were flat compared to 1998, remaining at $2.20 billion.
Wholesale revenues decreased $1.55 billion, or 60%. The decrease in revenues was driven by a 64% decline in energy volumes. Short-term firm and spot market sales volumes decreased 75%, creating a $1.56 billion decrease in revenues. Sales prices for short-term firm and spot market sales averaged $27 per megawatt hour ("MWh") in 2000 compared to $26 per MWh in 1998, resulting in $24 million in additional revenues. Decreased long-term firm contract prices lowered wholesale revenues by $19 million in 2000. The decline in energy volumes is consistent with the Company's decision to scale back short-term wholesale sales.
Short-Term Firm and Spot Market Sales
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Residential revenues were down $8 million, or 1%. Excluding the impact of the sale of the Company's distribution assets in Montana in 1998, residential revenues were up $5 million, energy volumes were up 2% and customer growth was 3%. Growth in the average number of residential customers added $20 million to revenues. Price increases in Oregon added $6 million to revenues in 2000. A
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rate order issued by the Utah Commission in 1998 decreased residential revenues by $36 million in 2000. This decrease was partially offset by the one-time Utah rate order refund that reduced revenues by $16 million in 1998.
Industrial revenues were down $11 million, or 2%. Excluding the impact of the Montana sale, industrial revenues were down $2 million, energy volumes were down 1% and average number of customers declined 2%. The Company participated in open access pilot programs in Oregon, which ended in 1998, that reduced revenues $10 million in 2000. Increased irrigation usage added $5 million to industrial revenues in 2000. The Utah rate order decreased industrial revenues by $17 million in 2000. This decrease was offset by the one-time Utah rate order refund that reduced revenues in 1998 by $8 million and other changes in the average price for electricity, which added $10 million in 2000.
Commercial revenues were up $14 million, or 2%. Excluding the impact of the Montana sale, commercial revenues were up $24 million, energy volumes were up 6% and customer growth was 3%. Growth in the average number of commercial customers added $24 million to revenues and volume increases added $16 million to revenues. The Utah rate order decreased commercial revenues by $33 million in 2000. This decrease was partially offset by the one-time Utah rate order refund that reduced revenues in 1998 by $13 million and other changes in the average price for electricity, which added $6 million in 2000.
Other revenues increased by $7 million, or 7%. The primary cause of this favorable variance was an $11 million increase in wheeling revenues resulting from new contracts for transmitting electricity for other companies across the Company's system and increased volume under existing wheeling contracts.
1998 compared to 1997 - Revenues rose 31%, or $1.14 billion, in 1998 primarily due to increased wholesale energy volumes and sales prices. A 59% increase in wholesale energy volumes sold increased wholesale revenues by $917 million and higher sales prices in short-term firm and spot market sales increased wholesale revenues by $242 million. Residential revenues decreased $7 million primarily due to the Utah rate order and decreased customer usage, partially offset by customer growth. Commercial revenues increased $13 million primarily due to customer growth and increased customer usage, partially offset by the effect of the Utah rate order. Other revenues decreased $18 million primarily due to revenue adjustments relating to changes in property tax legislation.
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OPERATING EXPENSES
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Operating expenses decreased $1.57 billion, or 37%, to $2.70 billion in 2000, primarily as a result of a $1.54 billion decrease in purchased power costs.
In addition to base energy and capacity from its thermal and hydroelectric resources, the Company utilizes a mix of long-term, short-term and nonfirm power purchases to meet its own retail load commitments and to make wholesale power sales to other utilities. Purchased power expense decreased $1.54 billion, or 62%, to $958 million in 2000. The lower expense was primarily due to a 61 million MWh decrease in short-term firm and spot market energy purchases, a 77% decrease from 1998, which decreased purchased power expense by $1.58 billion. Short-term firm and spot market purchase prices averaged $28 per MWh in 2000 versus $26 per MWh in 1998, a 9% increase. The increase in purchase prices added $42 million to costs in 2000. The reduced level of power purchases in 2000 is consistent with the Company's decision to scale back short-term wholesale sales.
Short-Term Firm and Spot Market Purchases
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Fuel expense was up $7 million, or 2%, to $485 million in 2000. Thermal generation increased 1% to 52.4 million MWh. Increased expense from the higher generation was partially offset by lower cost per MWh. The average cost per MWh decreased to $9.25 from $9.37 in 1998 due to improved operating efficiencies at Company-operated mines. Hydroelectric generation remained flat compared to 1998.
Other operations and maintenance expense increased $99 million, or 22%, to $556 million in 2000. In 2000, the Company completed an analysis of construction projects and determined to abandon a number of early stage projects. Write-offs of these assets were $23 million pretax. Increased tree trimming added $6 million to expenses, increased materials and contracts primarily relating to steam plant overhaul costs added $11 million, increased employee costs added $9 million and write-offs of obsolete inventory added $4 million. An increasing amount of work relating to expense rather than
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capital projects resulted in $14 million of additional transmission and distribution expenses. Customer accounting, service and sales expenses increased $8 million due to increased collection activity. Employee costs resulting from higher than normal employee turnover added $2 million to expenses. Costs related to the Foote Creek wind turbines, placed in service at the end of 1998, also added $2 million to expenses. In addition, operations and maintenance was up $15 million due to costs reclassified from administrative and general upon conversion to the SAP software operating environment.
Depreciation and amortization expense increased $19 million, or 5%, to $406 million primarily due to increased plant in service and increased depreciation on the new SAP software system.
Administrative, general and taxes - other expenses decreased $32 million, or 10%, to $299 million. This decrease included $15 million of costs reclassified to operations and maintenance expense upon conversion to SAP. In addition, pension costs decreased $4 million in 2000 due to favorable returns on plan assets. Costs of converting to SAP decreased $4 million, other consulting services also decreased $9 million and Year 2000 conversion costs decreased $3 million. Increased employee costs relating to the Merger of $14 million were completely offset by decreased labor and other employee expenses.
Special charges recorded in 1998 were the costs of early retirement and cost reduction programs implemented in the first and fourth quarters of 1998. The net work force reduction was approximately 930 positions and the Company recorded $77 million of after-tax charges in 1998 relating to the programs.
1998 compared to 1997 - Operating expenses increased $1.17 billion in 1998 due to higher purchased power volumes and prices. Short-term firm and spot market energy purchases increased 33.9 million MWh, a 74% increase from 1997, which increased purchased power expense by $937 million. Short-term firm and spot market purchase prices were, on average, 36% higher in 1998, which added $255 million to purchased power costs. Special charges decreased $47 million in 1998. Special charges in 1998 consisted of the costs of an early retirement and cost reduction program. Special charges in 1997 included the Glenrock mine closure costs of $64 million, the write-off of deferred regulatory pension costs of $87 million, and impairment charges on information system assets of $19 million.
OTHER INCOME AND EXPENSE
Interest expense was $51 million lower primarily due to the dividends received from Holdings that were used to pay down intercompany debt owed to Holdings and some external debt. ScottishPower 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. Other income increased $7 million primarily due to decreased new product expense and a settlement received from the federal government for loss of coal rights upon creation of a new national park in Utah. Income tax expense was $125 million, an increase of $22 million, primarily due to an increase in nondeductible merger transaction costs, partially offset by the decline in taxable income. See Note 15 of Notes to the Consolidated Financial Statements under ITEM 8.
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1998 compared to 1997 - Other expenses increased $20 million in 1998, which included $13 million of ScottishPower merger costs and $6 million of higher minority interest expense relating to the issuance of quarterly income preferred securities in August 1997. Income tax expense decreased $9 million due to the decline in pretax income.
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. However, federal laws and regulations 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. 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."
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AUSTRALIAN ELECTRIC OPERATIONS
Powercor's principal businesses are to sell electricity to franchise and contestable customers inside and outside its franchise area and to provide electricity distribution services to customers within its regulated network distribution service area. Franchise customers are those customers that cannot yet choose an electricity supplier, while contestable customers have the opportunity to choose suppliers. Powercor purchases all of its electricity supply from a national electricity market.
Victoria and NSW are currently divided between franchise and contestable customers. Customers in both states with annual consumption of more than 160 MWh are now contestable. Customers with usage of 160 MWh per year or less will become contestable on January 1, 2001 in Victoria, the ACT and NSW. If a Powercor customer chooses a different retailer, Powercor will continue to receive network distribution revenues associated with that customer. Powercor was granted licenses to sell electricity to customers in the States of Queensland and ACT in early 1998.
Australian Electric Operations' financial results for the year ended December 31, 1999 are included in PacifiCorp's financial results for the year ended March 31, 2000. For purposes of this discussion, these financial results are referred to as "2000" results.
In 2000, Australian Electric Operations contributed earnings of $39 million compared to $13 million in 1998. Operating expense reductions increased the contribution to earnings, however, lower market prices resulting from an increasing level of deregulation, partially offset by lower purchased power expense, caused margins on energy sold to decline. Also, in 1998, Australian Electric Operations recorded a $17 million loss on the write down of its investment in Hazelwood to estimated net realizable value less selling costs.
Currency Risks - Australian Electric Operations' results of operations and financial position are translated from Australian dollars into United States dollars for consolidation into the Company's financial statements. Changes in the prevailing exchange rate may have a material effect on the Company's consolidated financial statements. 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 effect of the exchange rate fluctuation was an increase of $1 million in net income in 2000. The currency exchange rate at May 31, 2000 was 0.58. The following discussion excludes the effects of the higher currency exchange rate in 2000.
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REVENUES
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Australia reported 2000 revenues of $618 million, a $13 million, or 2%, decrease from 1998. The decrease was primarily attributable to a reduction in energy sales volumes of 372 million kWh, or 3%.
Inside Powercor's franchise area, revenues declined $19 million, $17 million due to a 378 million kWh decrease in volumes and $2 million due to price decreases for customers.
Energy volumes sold to contestable customers outside Powercor's franchise area were up 6 million kWh in 2000. This increase was primarily due to customer gains in Queensland, the ACT and NSW. The revenue increase resulting from the additional energy volumes sold was offset by lower rates, primarily in Victoria.
Other revenues increased $7 million in 2000 primarily due to recognition of a sales tax contract settlement payment received from the Australian Government of $4 million, and $4 million from construction projects for customers who own their own distribution assets, as well as refunds received with the dissolution of the Victoria Power Exchange of $2 million. These increases were offset due to $4 million for Tariff H revenue recognition in 1998.
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1998 compared to 1997
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Revenues increased $11 million, or 1%, in 1998 primarily due to an 8% increase in energy sales volumes. Increased market share in the contestable market in Victoria and NSW added $7 million and $39 million, respectively. Lower prices for contestable sales reduced revenues by $12 million. Revenues within Powercor's franchise area decreased $13 million due to lower average realized prices and $8 million due to a 177 million kWh decrease in volumes.
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OPERATING EXPENSES
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Purchased power expense decreased $2 million, or 1%, in 2000. A favorable court ruling received on a contract dispute resulted in decreased expense of $24 million. A 6% decrease in purchased power volumes reduced costs by $16 million. These decreases were partially offset by increases of $11 million in payments to counterparties due to recalculation of contract fees and $24 million of increases in purchased power costs.
The power supplier in the contract dispute noted above did not meet its contractual obligation to deliver power to Powercor at the agreed upon rate, which forced Powercor to purchase power on the open market at a higher rate. On November 17, 1999, the Supreme Court of Victoria upheld the validity of these contracts and on December 14, 1999 ordered specific performance on the remaining contracts and payment of $29 million for failure to perform in the past. On December 21, 1999, the power supplier filed a notice of appeal seeking to overturn all of the judgments against it. The Company expects the decision to be upheld. See "ITEM 3. LEGAL PROCEEDINGS."
Other operations and maintenance expense decreased $39 million, or 27%, in 2000. The decrease in expense is related to an increase in external network revenue, accounted for on a net basis against other network costs, 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, a $9 million decrease due to reclassifying expenses to administrative and general, and a $1 million decrease in maintenance expense because of mild weather.
Administrative, general and taxes - other increased $22 million, or 47%, in 2000. An increase of $9 million was attributable to a reclassification of construction services expenses, for services provided to other companies, from other operations and maintenance. Restructuring costs increased $4 million over 1998. A project to help transition to full retail contestability increased expenses by $3 million, salaries and incentives increased $4 million, and legal fees due to the power supply contract dispute increased $1 million.
Interest expense decreased $1 million in 2000 to $58 million as a result of lower debt balances. Other expense decreased $30 million primarily due to the 1998 pretax write down of $28 million that reduced the carrying value of the Company's investment in the Hazelwood Power Station to its estimated net
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realizable value less selling costs and $5 million in costs for removal of certain energy efficiency devices in connection with a product recall. Equity losses in Hazelwood were $3 million, a decrease of $3 million over 1998, primarily due to decreased maintenance costs. Income tax expense increased $16 million due primarily to an increase in taxable income.
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1998 compared to 1997
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Operating expenses increased $26 million, or 5%, in 1998. Increased sales to contestable customers outside Powercor's franchise area resulted in increased purchased power expense of $28 million and higher network fees of $40 million, which were partially offset by decreased purchased power prices of $35 million, and higher network revenues of $12 million from customers inside Powercor's franchise area that were serviced by other energy suppliers.
REGULATION
For additional information concerning the regulatory and environmental issues facing the Australian Electric Operations, see "ITEM 1. BUSINESS - AUSTRALIAN ELECTRIC OPERATIONS - Regulation" and "- Environmental Issues."
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OTHER OPERATIONS
Earnings Contribution | March 31, | December 31, | |
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During 2000, Other Operations included the activities of Holdings, PFS and energy development businesses. Other operations reported earnings of $14 million in 2000 compared to a loss of $52 million in 1998. The 2000 results include ScottishPower merger costs of $3 million. Interest income decreased $31 million as the result of cash dividends paid by Holdings to Domestic Electric in January 1999 and October 1998. This cash had been invested by Holdings in interest bearing instruments prior to payment of the dividends. Income at PFS's synthetic fuel producing businesses increased $13 million. The 1998 results included losses relating to the decision to shut down or sell the Company's other energy development businesses totaling $32 million. After-tax losses associated with exiting these businesses were approximately $7 million in 2000. In 1998, these businesses incurred $19 million of after-tax losses. In addition, 1998 included $55 million in costs associated with the Company's terminated bid for TEG and closing foreign currency options in April 1998 associated with the terminated bid for TEG, and a gain of $10 million relating to the sale of TEG shares.
PFS has tax-advantaged investments in leasing operations that consist principally of aircraft leases. For 2000, PFS reported net income of $16 million, a $7 million increase from 1998. This increase was primarily attributable to increased tax credits received on the sales of synthetic coal, which was offset by a decrease as a result of the sale of its affordable housing properties in 1998. PFS sold its investments in affordable housing in 1998 for $80 million, which approximated book value.
The energy development businesses that the Company decided to exit in 1998 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 in 1998 and was included in "Write down of investments in energy development businesses" 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 being held for sale. The process of exiting these businesses is nearing completion.
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1998 compared to 1997 - The $43 million decrease in earnings contribution of Other Operations in 1998 was primarily attributable to a loss of $32 million relating to the decision to shut down or sell the Company's energy development businesses. A loss of $54 million was associated with the Company's terminated bid for TEG, as well as $2 million relating to closing foreign exchange positions associated with the terminated bid. This loss was partially offset by a gain of $10 million relating to the sale of TEG shares.
Results from Other Operations in 1998 benefited from a $40 million after-tax increase in interest income and reduced interest expense as the result of cash received from 1997 asset sales.
In 1997, the Company completed the sale of its independent power subsidiary, Pacific Generation Company ("PGC"), for approximately $150 million in cash, resulting in a gain of $30 million. PGC contributed income of $10 million in 1997 prior to completion of the sale.
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.
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 remaining working capital at the expected sale date.
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LIQUIDITY AND CAPITAL RESOURCES
OPERATING ACTIVITIES
Cash flows from continuing operations increased $98 million from 1998 to 2000. This increase was largely due to cash expenditures in 1998 relating to taxes on 1998 and 1997 asset sales.
INVESTING ACTIVITIES
Investing in 2000 focused on continued capital spending to improve and expand existing operations. In addition, the Company disposed of non-strategic assets such as TPC in 2000 and the Montana electric distribution assets and the majority of the tax-advantaged investments in affordable housing owned by PFS in 1998.
On May 4, 2000, the utility partners who own 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. For additional information concerning the sale of the Centralia plant and mine, see "ITEM 1. BUSINESS - DOMESTIC ELECTRIC OPERATIONS - Asset Sales."
On October 23, 1998, the Company announced its intent to exit its energy trading business in the eastern United States and its other energy development businesses. As a result, the Company recorded an after-tax loss of $137 million for these businesses. In addition, the Company recorded an after-tax loss of $17 million to reduce the Company's carrying value in the Hazelwood Power Station to its net realizable value less selling costs. 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 the first quarter of 2000. On July 9, 1998, the Company announced its intention to sell its California and Montana electric distribution assets. On November 5, 1998, the Company sold its Montana electric 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 on the sale to Montana customers as negotiated with the Montana Public Service Commission and the Montana Consumer Counsel. For additional information on the sale of the California electric distribution assets, see "ITEM 1. BUSINESS - DOMESTIC ELECTRIC OPERATIONS - Proposed Asset Additions and Dispositions."
In October 1998, Holdings paid a dividend of $500 million to Domestic Electric. Domestic Electric used the proceeds to pay down intercompany debt owed to Holdings. In January 1999, Holdings paid a dividend of $660 million to Domestic Electric. Domestic Electric used the proceeds to pay down short-term debt and intercompany debt and temporarily invested the remainder in money market funds. In March 2000, Holdings paid a dividend of $49 million to Domestic Electric. Domestic Electric used the proceeds to pay down short-term debt and temporarily invested the remainder in money market funds.
The Company believes that its existing and available capital resources are sufficient to meet working capital, dividend and construction needs in 2001.
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BID FOR THE ENERGY GROUP
During 1997 and 1998, the Company sought to acquire 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 and option losses," 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) when they were sold on June 2, 1998.
Upon initiation of the original tender offer in June 1997, the Company also entered into foreign currency exchange contracts. The financing facilities associated with the June 1997 offer for TEG terminated upon referral to the Monopolies and Mergers Commission and the Company initiated steps to unwind its foreign currency exchange positions consistent with its policies on derivatives. As a result of the termination of these positions and initial option costs, the Company realized a pretax loss of approximately $106 million ($65 million after-tax) in the third quarter of 1997.
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CAPITALIZATION
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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 48% to 54% of capitalization. The debt to capitalization ratio was 48% at March 31, 2000. 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, 2000. The Company has made commitments in connection with the Merger not to reduce common equity, without approval, to below 35% of total capitalization, increasing over time to 40%.
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VARIABLE RATE LIABILITIES
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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, 2000, PacifiCorp had $800 million of committed bank revolving credit agreements. Regulatory authorities limit PacifiCorp to $1.5 billion of short-term debt, of which $109 million was outstanding at March 31, 2000. At March 31, 2000, subsidiaries of PacifiCorp had $723 million of committed bank revolving credit agreements. The Company had $429 million of short-term debt classified as long-term debt at March 31, 2000, as it had the intent and ability to support such short-term borrowings through the various revolving credit facilities on a long-term basis. See Notes 7 and 8 of Notes to Consolidated Financial Statements for additional information under ITEM 8.
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 $2.5 billion of debt at March 31, 2000.
Under PacifiCorp's principal credit agreements, it is an event of default if any person or group 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. However, no event of default occurred solely as a result of ScottishPower acquiring all of the outstanding common shares of PacifiCorp, or controlling the election or nomination of directors.
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
51
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 trading strategies. The policies and procedures that guide the Company's risk management activities are contained in the Company's derivative policy.
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 trading practices and contains 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 rates and foreign exchange derivative instruments will be used for hedging and not for speculation. The derivative policy also governs the energy trading activities and is generally designed for hedging the Company's existing energy exposures but does provide for limited speculation activities within defined risk limits.
RISK MEASUREMENT
Value at Risk Analysis
The tests discussed below for exposure to interest rate and currency exchange 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 commodities price exposure positions by utilizing a 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 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 at quoted futures prices or assumed forward prices.
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EXPOSURE ANALYSIS
Interest Rate Exposure
The Company's market risk to interest rate changes is primarily related to long-term debt with fixed interest rates. The Company uses 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 table below shows the potential loss in fair market value of the Company's interest rate sensitive positions as of December 31, 1998 and March 31, 2000, as well as the Company's quarterly high and low potential losses.
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Because of the size of the Company's fixed rate portfolio and lower levels of short-term debt as a result of asset sales, the significant majority of this average daily exposure is a noncash fair market value exposure and generally not a cash or current interest expense exposure.
Currency Rate Exposure
The Company's market risk to currency rate changes is primarily related to its investment in the Australian Electric Operations. The Company uses currency swaps, currency forwards and futures to hedge its foreign activities and, where use is governed by the derivative policy, the Company utilizes Australian dollar denominated borrowings to hedge the majority of the foreign exchange risks associated with Australian Electric Operations. Results of hedging activities relating to foreign net asset exposure are reflected in the accumulated other comprehensive income section of shareholders' equity, offsetting a portion of the translation of the net assets of Australian Electric Operations.
Gains and losses relating to qualifying hedges of foreign currency firm commitments (or anticipated transactions) are deferred on the balance sheet and are included in the basis of the underlying transactions. To the extent that a qualifying hedge is terminated or ceases to be effective as a hedge, any deferred gains and losses up to that point continue to be deferred and are included in the basis of the underlying transaction. To the extent that anticipated transactions are no longer likely to occur, the related hedges are closed with gains or losses charged to earnings on a current basis.
In addition to the foreign currency exposure related to its investment in Australian Electric Operations, the Company also includes in the currency rate exposure VAR analysis the mark-to-market risk associated with its energy supply related contracts for differences supporting its commitment to the customers of Australian Electric Operations.
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The table below shows the potential loss in pre-tax cash flow of the Company's currency rate sensitive positions as of December 31, 1998 and March 31, 2000, 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 trading 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 and Australia. In the United States, the Company manages this risk principally through the operation of its 7,829 MW generation and transmission system in the western Unites States and through its wholesale energy trading activities. Derivative instruments are not significantly utilized in the management of the Unites States electricity position. In Australia, the Victorian government currently limits the amount of generation that can be owned by an electric supply company and, as a result, the risk associated with Australian Electric Operations energy supply obligations is managed through the use of electricity forward contracts (referred to as "contracts for differences") with Victorian generators. Under these forward contracts, the Company receives or makes payment based on a differential between a contracted price and the actual spot market of electricity. Additionally, 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. Derivative instruments, other than contracts for differences, are not significantly utilized in Australian Electric Operations' risk management process.
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.
A sensitivity analysis has been prepared to estimate the Company's exposure to market risk related to commodity price exposure of its derivative positions for electricity. Based on the Company's derivative price exposure at March 31, 2000 and December 31, 1998, a near-term adverse change in commodity prices of 10% would negatively impact pre-tax earnings by $18 million and $16 million, respectively.
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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
In June 1999, SFAS No. 137 was issued, which deferred the effective date of SFAS No. 133 to the fiscal years beginning after June 15, 2000. SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," requires an entity to recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. A company may implement SFAS No. 133, as of the beginning of any fiscal quarter after the June 1998 issuance; however, the statement cannot be applied retrospectively. The Company does not plan to adopt SFAS No. 133 early. Adoption of this standard will have an effect on the Company's financial position and results of operations; however, the magnitude of the effect will be determined by the hedges and derivatives that the Company has in place at the date of adoption of the standard. The effects in future periods will be dependent upon the derivatives and hedges in place at the end of each period and cannot be presently determined.
In July 1999, the EITF reached a consensus on Issue No. 99-9, "Effect of Derivative Gains and Losses on the Capitalization of Interest" ("EITF 99-9"). EITF 99-9 clarifies the application of SFAS No. 34, which establishes standards for capitalizing interest cost as part of the historical cost of acquiring certain assets, in conjunction with SFAS No. 133 (see discussion above). The Company anticipates that the cumulative effect of the adoption of EITF 99-9 at April 1, 2001 will be immaterial on the Company's financial position, results of operations and cash flows.
From November 29, 1999 to March 24, 2000, the SEC issued Staff Accounting Bulletins No. 100, 101 and 101A. The effect of adoption of these bulletins is not expected to have a material effect on the Company's financial position or results of operations.
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," "Currency Rate Exposure" and "Commodity Price Exposure" on pages 51 through 54 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 year ended March 31, 2000, or by Deloitte & Touche LLP ("Deloitte & Touche") with respect to prior periods, 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.
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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
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 audit and the report of other auditors, the accompanying consolidated balance sheet and the related statements of consolidated income, common shareholders' equity and cash flows present fairly, in all material respects, the financial position of PacifiCorp and its subsidiaries at March 31, 2000, and the results of their operations and their cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States. 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 audit. 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 audit of these statements in accordance with auditing standards generally accepted in the United States, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit and the report of other auditors provide a reasonable basis for the opinion expressed above. The financial statements of the Company as of March 31, 1999 (not separately presented herein) and as of December 31, 1998, and for the three months ended March 31, 1999 and for each of the two years in the period ended December 31, 1998 were audited by other independent accountants whose report dated February 11, 2000 expressed an unqualified opinion on those statements.
PricewaterhouseCoopers LLP
Portland, Oregon
May 4, 2000, except for the fourth, fourteenth, and twentieth
paragraphs of Note 5, as to which the date is May 31, 2000
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INDEPENDENT AUDITORS' REPORT
TO THE BOARD OF DIRECTORS AND SHAREHOLDERS OF PACIFICORP:
We have audited the accompanying consolidated balance sheet of PacifiCorp and subsidiaries as of December 31, 1998, and the related statements of consolidated income, consolidated changes in common shareholders' equity and consolidated cash flows for the three months ended March 31, 1999 and each of the years ended December 31, 1998 and 1997. 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 financial position of PacifiCorp and subsidiaries at December 31, 1998, and the results of their operations and their cash flows for the three months ended March 31, 1999 and each of the years ended December 31, 1998 and 1997, 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 Consolidated Financial Statements)
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CONSOLIDATED BALANCE SHEETS
ASSETS
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LIABILITIES 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 CONSOLIDATED FINANCIAL STATEMENTS
Years ended March 31, 2000, December 31, 1998 and 1997
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 holds 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, and PacifiCorp Financial Services, Inc. ("PFS"), a financial services business. Significant intercompany transactions and balances have been eliminated upon consolidation.
During 2000, 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 14% of total retail electric revenues. The geographical distribution of the Company's domestic electric operations' retail operating revenues for the year ended March 31, 2000 was Utah, 38%; Oregon, 33%; Wyoming, 13%; Washington, 8%; Idaho, 6%; and California, 2%.
Investments in and advances to affiliated companies represent investments in unconsolidated affiliated companies carried on the equity basis, which approximate the Company's equity in their underlying net book value.
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.
The Company sold its wholly owned telecommunications subsidiary on December 1, 1997. See Note 4. The Company sold Pacific Generation Company ("PGC") on November 5, 1997, and the natural gas gathering and processing assets of TPC on December 1, 1997. During May 1998, the Company sold a majority of the real estate assets held by PFS. See Note 17.
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.
CHANGE IN FISCAL YEAR
Effective November 30, 1999, the Company changed its fiscal year end from December 31 to March 31, which is the fiscal year end for Scottish Power plc ("ScottishPower"). See Note 2. A report on Form 10-Q for the three-month
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transition period from January 1, 1999 through March 31, 1999 was filed with the Securities and Exchange Commission on January 13, 2000. The year ending March 31, 2000 and quarterly periods within that year are referred to as 2000. All future years refer to fiscal years ended March 31. The years ended December 31, 1998 and 1997 are referred to as 1998 and 1997, respectively. Powercor's fiscal year end remains December 31. Consequently, the Company's statement of consolidated income, statement of consolidated cash flows and consolidated balance sheet as of and for the year ended March 31, 2000 include Powercor's financial statements as of December 31, 1999 and for the year then ended. In accordance with guidelines of the Securities and Exchange Commission, twelve months of income and expense for Powercor were included in the consolidated statement of income for 2000. Powercor'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 as a single line item 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 and certain identifiable intangibles 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.
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.
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FOREIGN CURRENCY
Financial statements for foreign subsidiaries are 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 are 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.
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. Repair and maintenance costs for property, plant and equipment are expensed as incurred.
DEPRECIATION AND AMORTIZATION
At March 31, 2000, the average depreciable lives of property, plant and equipment by category were: Domestic Electric Operations -- Production, 41 years; Transmission, 58 years; Distribution, 42 years; Other, 20 years; and Australian Electric Operations, 26 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 3.2%, 3.3% and 3.4% of average depreciable assets in 2000, 1998 and 1997, respectively.
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. This is consistent with industry practices, and the Company believes that it has adequately provided for its reclamation obligations, assuming ongoing operations of its mines.
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The liabilities for environmental clean-up related costs are generally recorded on an undiscounted basis in 2000 dollars. These liabilities are recorded in the balance sheet at March 31, 2000 and December 31, 1998 as follows:
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Mine reclamation (a)(b) | $ 203.5 | $ 193.2 |
(a) Amounts include the Company's and minority interest joint owners'
portion of mine reclamation costs.
(b) Amounts are included in "Deferred Credits - Other" on the balance sheet.
(c) Amounts are included in "Regulatory assets - net" on the balance sheet.
The Company had trust fund assets of $100.5 million and $77.9 million at March 31, 2000 and December 31, 1998, respectively, relating to mine reclamation, including minority interest joint owners' portion.
INVENTORY VALUATION
Inventories are generally valued at the lower of average cost or market.
INTANGIBLE ASSETS
Intangible assets consist of license and other intangible costs relating to Australian Electric Operations ($395 million and $31 million, respectively, in 2000 and $375 million and $24 million, respectively, in 1998). These costs are offset by accumulated amortization ($43 million in 2000 and $30 million in 1998). Licenses and other intangible costs are generally being amortized over 40 years. Intangible assets increased $20 million in 2000 due to changes in foreign currency exchange rates.
FINANCE ASSETS
Finance assets consist of finance receivables, leveraged leases and operating leases and are not significant to the Company in terms of revenue, net income or assets. 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 $35 million and $27 million at March 31, 2000 and December 31, 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 2000 and 1998, the Company reviewed funding requirements based on estimated future gains and interest
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earnings on trust assets and the projected future reclamation liability. The Company determined that no funding was required for both 2000 and 1998. 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 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 stockholders' equity. Realized gains or losses are determined on the specific identification method.
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 trading activities and is generally designed for hedging the Company's existing energy exposures but does provide for limited speculation activities within defined risk limits.
INTEREST CAPITALIZED
Costs of debt and equity applicable to domestic electric utility properties are capitalized during construction. The composite capitalization rates were 7.9% for 2000 and 5.7% for 1998 and 1997.
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 are made on the undistributed earnings of the Company's international businesses.
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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 the Company's energy trading and marketing activities are recorded upon delivery of electricity. Beginning January 1, 1999, the Company applied mark-to-market accounting for all energy trading activities and presented the net margin.
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 had elected in prior years to follow Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" ("APB 25") and related interpretations in accounting for its employee stock options. 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 was recorded. Upon completion of the merger with ScottishPower, PacifiCorp stock is no longer being issued for compensatory purposes. See Notes 2 and 16.
NEW ACCOUNTING STANDARDS
In June 1999, the Financial Accounting Standards Board ("FASB") issued SFAS No. 137, which deferred the effective date of SFAS No. 133 to the fiscal years beginning after June 15, 2000. SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," requires an entity to recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. A company may implement SFAS No. 133, as of the beginning of any fiscal quarter after the June 1998 issuance; however, the statement cannot be applied retrospectively. The Company does not plan to adopt SFAS No. 133 early. Adoption of this standard will have an effect on the Company's financial position and results of operations; however, the magnitude of the effect will be determined by the hedges and derivatives that the Company has in place at the date of adoption of the standard. The effects in future periods will be dependent upon the derivatives and hedges in place at the end of each period and cannot be presently determined.
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In July 1999, the Emerging Issues Task Force of the FASB (the "EITF") reached a consensus on Issue No. 99-9, "Effect of Derivative Gains and Losses on the Capitalization of Interest" ("EITF 99-9"). EITF 99-9 clarifies the application of SFAS No. 34, "Capitalization of Interest Cost," which establishes standards for capitalizing interest cost as part of the historical cost of acquiring certain assets, in conjunction with SFAS No. 133 (see discussion above). The Company anticipates that the cumulative effect of the adoption of EITF 99-9 at April 1, 2001 will be immaterial on the Company's financial position, results of operations and cash flows.
From November 29, 1999 to March 24, 2000, the SEC issued Staff Accounting Bulletins No. 100, 101 and 101A. The effect of adoption of these bulletins is not expected to have a material effect on the Company's financial position or results of operations.
RECLASSIFICATION
Certain amounts from prior years have been reclassified to conform with the 2000 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 their merger (the "Merger") under which the Company became an indirect subsidiary of ScottishPower. The Company continues to operate under its current name, and its headquarters will remain in Portland, Oregon. As a result of the merger with ScottishPower, 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 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.
For the years ended March 31, 2000 and December 31, 1998, the Company incurred expense of $212 million ($180 million after-tax) and $13 million pretax and after-tax, respectively, in costs associated with the ScottishPower merger. No costs associated with the ScottishPower merger were incurred during the three months ended March 31, 1999.
At March 31, 2000, the Company had $5 million of accrued liabilities payable to ScottishPower. These liabilities represent costs incurred by ScottishPower employees employed as Company management and ScottishPower employees temporarily working for the Company on its transition plan.
On May 4, 2000 the Company announced that as a result of the Merger with ScottishPower, the Company has developed and commenced a transition plan to implement significant organizational and operational changes. 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. The Company expects to reduce its workforce company-wide by approximately 1,600 over a
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five-year period, mainly through early retirement, voluntary severance and attrition. The cost of the early retirement offering will not be determinable until the end of June 2000, the deadline for election by eligible employees. These changes are intended to lead to improved service to customers, continued strong investment in communities and enhanced value for shareholders.
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 and option losses," 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) when they were sold on June 2, 1998.
Upon initiation of the original tender offer in June 1997, the Company also entered into foreign currency exchange contracts. The financing facilities associated with the June 1997 offer for TEG terminated upon referral to the Monopolies and Mergers Commission and the Company initiated steps to unwind its foreign currency exchange positions consistent with its policies on derivatives. As a result of the termination of these positions and initial option costs, the Company realized a pretax loss of approximately $106 million ($65 million after-tax) in the third quarter of 1997.
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 forward electricity trading 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.
On December 1, 1997, Holdings completed the sale of Pacific Telecom, Inc. ("PTI") to Century Telephone Enterprises, Inc. ("Century"). Pursuant to a stock purchase agreement dated June 11, 1997, Century acquired all the stock of PTI for $1.5 billion in cash plus the assumption of PTI's debt of $713 million. The sale resulted in a gain of $365 million net of income taxes of $306 million. A portion of the proceeds from the sale of PTI were used to
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repay short-term debt of Holdings. The remaining proceeds were invested in short-term money market instruments and Holdings temporarily advanced excess funds to Domestic Electric Operations for retirement of short-term debt.
The net assets, operating results and cash flows of the energy trading segment and PTI have been classified as discontinued operations for all periods presented in the consolidated financial statements and notes.
Summarized operating results for PPM's eastern energy trading and TPC were as follows:
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As mentioned previously, net assets of the discontinued operations were sold April 1, 1999. Net assets of the discontinued operations of the energy trading segment and assets held for sale consisted of the following:
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At March 31, 2000 and December 31, 1998, Holdings had $15 million and $34 million, respectively, of liabilities in "Customer deposits and other" relating to the sale of the 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 order regarding competition is 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.
Legislative actions in California and Montana during 1996 and 1997 mandated customer choice of electricity supplier, moving away from cost-based regulation to competitive market rates for the generation portion of the electric business. As a result of these legislative actions, the Company evaluated its generation regulatory assets and liabilities in California and Montana based upon future regulated cash flows and ceased the application of SFAS No. 71 to its generation business allocable to California and Montana. Domestic Electric Operations recorded an extraordinary loss of $16 million in 1997 for the write off of regulatory assets in those states. The regulatory assets written off resulted primarily from deferred taxes allocated to California and Montana. The allocation among the states was based on plant balances.
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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. The Utah Public Service Commission (the "UPSC") approved new depreciation rates in an order dated January 6, 2000. The Oregon Public Utility Commission (the "OPUC") approved new depreciation rates in an order dated May 31, 2000. Stipulated rates have been agreed upon in Wyoming, with a final order still pending. The impact of the proposed changes in depreciation is being incorporated into the current general rate cases in Oregon and Washington and the next general rate case in the other states. Based on the depreciation rates that have been approved and are pending approval, 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 plant. 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 all states, will amount to approximately $14 million per year.
Merger Orders
On June 10, 1999, the California Public Utility Commission (the "CPUC") issued an order approving the Merger. The CPUC conditioned its approval on the Company's acceptance of requirements which primarily addressed the Commission's ability to continue to regulate the Company's California service territory.
On November 22, 1999, the Wyoming Public Service Commission ("WPSC") issued an order approving the Merger. The Company agreed to make an informational filing in 2001 that guarantees $4 million per year in merger savings in future rate cases. The Company separately agreed to limit any rate increase filing in 1999 to $12 million and in the following year to $8 million plus the effect of any change in depreciation rates.
On October 6, 1999, the OPUC issued an order approving the Merger. As part of this approval, the Company agreed to provide a merger credit to retail customers of $12 million per year for three years beginning in calendar 2001 and $15 million in calendar 2004. In calendar 2003 and 2004, $9 million and $12 million, respectively, of the credit can be partially or wholly eliminated to the extent that merger-related cost savings are reflected in prices.
On October 14, 1999, the Washington Utilities & Transportation Commission (the "WUTC") approved the Merger. As part of this approval, the Company agreed to provide retail customers a merger credit of $3 million per year for four years beginning in calendar 2001. The credit can be wholly or partially eliminated in all years to the extent that merger-related cost savings are reflected in prices.
On November 15, 1999, the Idaho Public Utilities Commission (the "IPUC") approved the Merger. As part of this approval, the Company agreed to provide a $1.6 million per year merger credit to retail customers for four years beginning in calendar 2000. The credit can be wholly or partially eliminated in years three and four to the extent that merger-related cost savings are reflected in prices.
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On November 24, 1999, the UPSC approved the Merger. As part of this approval, the Company agreed to provide a merger credit for retail customers of $12 million per year for four years beginning in calendar 2000. The credit can be wholly or partially eliminated in years three and four to the extent that merger-related cost savings are reflected in prices.
The Company's total obligation for merger credits described above is $133.4 million over the period ending December 31, 2004. Of this amount, $57.2 million must be provided without offset or reduction of any kind and, accordingly, the Company has recorded $57.2 million as a liability and current expense in its financial statements for the year ended March 31, 2000. The remaining $76.2 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 $76.2 million obligation will be reflected in future periods.
Regulation
A summary of regulatory and legislative developments in the states where the Company conducts its distribution and retail electric operations is set forth below.
Utah. On March 4, 1999, the UPSC ordered the Company to reduce revenues in Utah by $85 million, or 12%, annually. The ordered reduction was the culmination of a general rate case that began in 1997. Additionally, the UPSC ordered a refund to be issued through a credit on customer bills of $40 million. The Company recorded a $38 million reduction in revenues in 1998 and recorded the remaining $2 million in the three months ended March 31, 1999. The refund covers the period from March 14, 1997 to February 28, 1999. The beginning date is consistent with the timing of Utah legislation imposing a moratorium on rate changes after the Utah Division of Public Utilities (the "UDPU") and the Utah Committee of Consumer Services (the "UCCS") requested a general rate case. The $85 million reduction commenced on March 1, 1999. The order also reduced the Company's authorized rate of return on equity from 12.1% to 10.5%.
On September 20, 1999, the Company filed for a rate increase before the UPSC. The Company asked for an increase of $67 million, or 9.9%, based on a test year ended December 31, 1998 and a requested 11.25% return on equity. On March 15, 2000, the Company filed a revised request of $55.2 million. On May 24, 2000, the Company received an order from the UPSC authorizing the Company to increase prices in Utah for residential, irrigation, small commercial and lighting customers by 4.24% and large commercial and industrial customers by less than 1%. The price increase is expected to result in annual revenues of $17 million. The order allowed a rate of return on equity of 11% and was effective on May 25, 2000.
The 2000 Utah legislative session passed a bill that could significantly change the way in which utilities are regulated in the state. The bill provides guidelines under which the interests of all parties will be protected and balanced in the ratemaking process. It directs the UPSC to determine fair rates by balancing the interests of utility customers with the need of
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utilities to maintain financial stability. This legislation also streamlines state government by consolidating the UDPU and the UCCS into one agency - the Office of Public Advocate. The bill modifies the nature of UPSC proceedings by encouraging and providing an opportunity for timely and reasonable settlements without restricting the rights of all interested persons to participate in a formal administrative process. Finally, the legislation requires Utah regulators to reflect "known and measurable" changes to financial data when hearing a rate case. This bill is 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 2001 legislative session, unless it is not in Utah's best interest to do so.
Oregon. The OPUC and the Company have agreed to an Alternate Form of Regulation ("AFOR") for the Company's Oregon distribution business. The AFOR allows for index-related price increases in 1998, 1999 and 2000, with an annual cap of 2% of distribution revenues in any one year and an overall cap of 5% over the three-year period. The annual revenue increase for the twelve months ended December 31, 1999 was approximately $6.2 million. The AFOR also includes incentives to invest in renewable resources and penalties for failure to maintain the service quality levels. On April 30, 1999, the Company filed for changes in the prices it charges Oregon customers under the AFOR. The filing also contained a request to increase the revenues collected under the Company's system benefits charge. The changes were approved by the OPUC in June 1999, and became effective July 1, 1999. This resulted in a price increase of approximately 1.3%, or $9 million annually, in Oregon. On April 28, 2000, the Company made an additional AFOR filing for a price increase of 1.8%, or $14 million annually. Of this amount, approximately $10 million is offset by costs mandated by regulators.
On November 5, 1999, the Company filed for a general rate increase in Oregon. The Company is asking for an increase of $61.8 million, or 8.5%. The Company's effective date for this increase is expected to be in the fall of 2000. The OPUC staff has submitted a preliminary report raising issues that in the aggregate could produce a $101 million rate reduction after giving effect to the Centralia sale. The staff testimony is due in June 2000 and hearings are scheduled for August 2000.
During July 1999, legislation was enacted in Oregon that requires competition for industrial and large commercial customers of both the Company and Portland General Electric by October 1, 2001. Residential customers will receive a portfolio of energy commodity rate options. The law generally exempts publicly-owned utilities and Idaho Power's Oregon service territory. The law authorizes the OPUC to make decisions on a variety of important issues, including the method for valuation of stranded costs/benefits, consumer protections, marketer certification, environmental issues, and competitive services. The legislation also calls for the establishment of a code-of-conduct for electric companies and their affiliates to protect consumers against anti-competitive practices. The legislation directs the investor-owned
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utilities to collect a 3% public benefit charge from all of its distribution customers. The Company is currently participating in the OPUC proceedings to establish the rules and procedures that will implement the new law. The Company will 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.
Wyoming. On July 26, 1999, the Company filed for a rate increase before the WPSC. The Company requested an increase of $12 million, or 4.9%, based on a test year ended December 31, 1998. The Company has also stipulated that any rate increase filings through May 2001 will not exceed $8 million plus the effects of any change in depreciation rates. On May 23, 2000, the Company received an order from the WPSC authorizing the Company to increase prices in Wyoming, resulting in increased annual revenues of $11 million. The order allowed a total rate of return of 8.85%, a return on common equity of 11.25% and was effective May 25, 2000. The WPSC did not allow recovery of approximately $1 million of the requested $12 million increase allocated to partial requirements industrial customers, finding that the cost of service study was not sufficient to support the increase to this class. The Company is in the process of refiling for this $1 million increase with a supplemental cost of service study.
Washington. On November 23, 1999, the Company filed for a rate increase before the WUTC. This rate increase contains two phases. In the first phase, the Company is asking for an increase of $14.6 million, or 8.10%. Including the systems benefit charge, which will be used to fund conservation and new renewable development projects, this increase is $17.4 million, or 9.64%. In the second phase, the Company is requesting an increase of $11.2 million, or 5.65%. The effective date for phase one of this proposed tariff increase is expected to be in the fall of 2000, and phase two would become effective one year following the effective date of phase one.
Idaho. On April 28, 2000, the Company filed documents with the IPUC to implement the next step in the gradual retirement of a BPA energy credit. The proposed reduction in the credit would increase electric prices for the Company's residential and irrigation customers in southeastern Idaho. The filing, once approved by the IPUC, would reduce the credits from the BPA and increase residential prices 3.35%, or $1 million, and irrigation prices 8%, or $2 million. These price increases phase out the BPA credit and do not have any impact on earnings.
The move toward an open or competitive marketplace for electric power may result in "stranded costs" relating to certain current investments, deferred costs and contractual commitments incurred under regulation that may not be recoverable in a competitive market. The calculation of stranded costs requires certain complex and interrelated assumptions to be made, the most critical of which is the expected market price of electricity. The Company and many industry analysts believe that market forces in the United States will continue to drive retail energy prices down as excess capacity of existing generation resources persists. This projected trend in price decreases is consistent with other commodities and services that have gone through
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deregulation. Contrary to historical price trends, certain other parties believe prices will increase in the future resulting in a stranded benefit to the Company. The key attributes that affect market price include excess generation capacity, the marginal cost of the high-cost provider that is required to meet market demand, the cost of adding new capacity and the price of natural gas.
Regulatory assets-net included the following:
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(a) Excludes $115 million as of March 31, 2000 and $125 million as of December 31, 1998 of investment tax credit regulatory liabilities.
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 SFAS No. 121, which requires the recognition of impairment on long-lived assets when book values exceed expected future cash flows.
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, 2000, substantially all of the remaining obligations relating to work force reduction initiatives had been satisfied.
In December 1997, Domestic Electric Operations recorded in operating income special charges of $170 million ($106 million after-tax). The pretax special charges included the write off of $87 million of deferred regulatory pension assets, a $19 million write off of certain information system assets associated with the Company's decision to proceed with an installation of SAP enterprise-wide software and $64 million of costs resulting from the decision to close Glenrock Coal Company. 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.
NOTE 7 SHORT-TERM DEBT AND BORROWING ARRANGEMENTS
The Companies' 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.
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At March 31, 2000, PacifiCorp's commercial paper and bank line borrowings were supported by revolving credit agreements totaling $800 million. At March 31, 2000, subsidiaries had committed bank revolving credit agreements totaling $723 million.
The Companies have the intent and ability to support short-term borrowings on a long-term basis through various revolving credit agreements, the earliest of which expires in October 2000. At March 31, 2000, subsidiaries had $429 million of short-term debt classified as long-term. See Note 8.
NOTE 8 LONG-TERM DEBT
The Company's long-term debt was as follows:
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(a) 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) Interest rates fluctuate based on Australian Bank Bill Acceptance Rates. A revolving loan agreement requires 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.
(d) The Companies have 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, have classified $429 million of short-term debt as long-term debt.
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 $12 billion of the eligible assets (based on original cost) of PacifiCorp is subject to the lien of the mortgage.
The junior subordinated debentures are unsecured obligations of the Company and are 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 $187 million, $731 million, $155 million, $140 million and $244 million in 2001 through 2005, respectively.
The Company made interest payments, net of capitalized interest, of $402 million, $116 million, $444 million and $414 million in 2000, the three months ended March 31, 1999, and the years 1998 and 1997, 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
Common Dividend Restrictions - ScottishPower is the sole 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 is between 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.
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.
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Generally, preferred stock is redeemable at stipulated prices plus accrued dividends, subject to certain restrictions. Upon 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.
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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.
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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:
| Gross | Gross |
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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, 2000 and December 31, 1998 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.
| March 31, 2000 | December 31, 1998 | ||
Amortized | Estimated | Amortized | Estimated | |
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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 year ended March 31, 2000, the three months ended March 31, 1999 and the years ended December 31, 1998 and 1997:
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December 31, | December 31, | |||
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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 utilizes 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 rates 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 commodity exposure can be utilized. The derivative policy also governs energy trading activities and is generally designed for hedging the Company's existing energy exposures but does provide for limited speculative activities within defined risk limits.
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 is exposed to credit-related losses in the event of nonperformance by counterparties to financial instruments, but it does not expect any counterparties to fail to meet their obligations given their high credit ratings. The Company's derivative policy provides that counterparties must satisfy established credit ratings and currently a majority of the Company's counterparties are rated "A" or better. 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 enters into various types of interest rate contracts to assist in managing its interest rate risk, as indicated in the following table:
| Notional Amount | |
March 31, | December 31, | |
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The Company uses 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.
The use of interest rate collars, futures and forwards has been limited to use in the Australian Electric Operations. The futures and forwards, when used, are accounted for as hedges of the Australian bank bill borrowings.
Under the various interest rate swap agreements, the Company agrees 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. Average variable rates are based on rates implied in the yield curve at year end; these may change significantly, affecting future cash flows. Swap contracts are principally between one and eight years in duration. Maturation of derivatives over the next five years consists of $255 million, $95 million and $36 million in 2001 through 2003, respectively, with none maturing in 2004 and 2005.
March 31, | December 31, | |
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Foreign Exchange Risk Management - The Company's principal foreign exchange exposure relates to its investment in its Australian Electric Operations. The Company has hedged its exposure through both Australian-dollar denominated bank borrowings, which hedge approximately 55% to 60% of its total exposure, and through a series of amortizing currency swaps, which hedge approximately half of the remaining exposure. In January 1998, Australian Electric Operations issued $400 million of 6.15% Notes due 2008. At the same time, in order to mitigate foreign currency exchange risk and consistent with the directives in the Company's derivative policy, Australian Electric Operations entered into a series of cross currency swaps in the same amount and for the same duration as the underlying United States denominated notes.
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At March 31, 2000, Holdings held three combined interest rate and currency swaps that terminate 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 net amounts of these swaps have not had a significant impact on net income.
Commodity Risk Management - The Company has utilized electricity forward contracts (referred to as "contracts for differences") to hedge exposure to electricity price risk on anticipated transactions or firm commitments in its Australian Electric Operations. Under these forward contracts, the Company receives or makes payment based on a differential between a contracted price and the actual spot market of electricity. Additionally, electricity futures contracts are utilized to hedge Domestic Electric Operations' excess or shortage of net electricity for future months.
At March 31, 2000, Australian Electric Operations had 309 forward contracts with electricity generation companies on notional quantities amounting to approximately 31.7 million megawatt hours ("MWh"). The average fixed price to be paid by Australian Electric Operations was $20.80 per MWh compared to the average price of similar contracts at March 31, 2000 of $25.29. At December 31, 1998, Australian Electric Operations had 290 forward contracts with electricity generation companies on notional quantities amounting to approximately 34.4 million MWh through the year 2007. The average fixed price to be paid by Australian Electric Operations was $17.99 per MWh compared to the average price of similar contracts at December 31, 1998 of $22.20. It is not practicable to determine the fair value of the forward contracts held by Australian Electric Operations because of the limited number of transactions and the inactive trading in the electricity spot market.
The Company had open NYMEX futures contracts as follows:
March 31, | December 31, | |
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Trading Activities - The fair market values of open positions at March 31, 2000 was $1 million. Such transactions involve delivery of electricity, which is accounted for as revenue or purchased power expense. At March 31, 2000, the Company had open purchase positions with a notional amount of approximately $67.2 million, or 2.0 million MWh, and open sell positions for approximately $57.5 million, or 1.7 million MWh.
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NOTE 13 FAIR VALUE OF FINANCIAL INSTRUMENTS
March 31, 2000 | December 31, 1998 | |||
| Carrying | Fair | Carrying | Fair |
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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, 2000 and December 31, 1998.
The fair value of the Company's long-term debt 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 the Preferred Securities was based on closing market prices and the fair value of redeemable preferred stock was based on bid prices from an investment bank.
The fair value of interest rate derivatives and currency swaps is the estimated amount the Company would receive (pay) 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
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 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, 2000, 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 not expected to be material to the Company's consolidated financial statements.
On October 9, 1996, the Sierra Club filed an action against the Company and the other joint owners of Units 1 and 2 of the Craig Electric Generating Station (the "Station") under the citizen's suit provisions of the Federal Clean Air Act alleging, based upon reports from emissions monitors at the Station, that over 14,000 violations of state and federal opacity standards have occurred over a five-year period at Units 1 and 2 of the Station. (Sierra
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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). The Company has a 19.28% interest in Units 1 and 2 of the Station, which is operated by Tri-State Generation and Transmission Association and located in Craig, Colorado.
The action seeks injunctive relief requiring the defendants to operate the Station in compliance with applicable statutes and regulations, the imposition of civil penalties, litigation costs, attorneys' fees and mitigation. The Federal Clean Air Act provides for penalties of up to $27,500 per day for each violation, but the level of penalties imposed in any particular instance is discretionary. The complaint alleges that the Company and Public Service Company of Colorado are responsible for the alleged violations beginning with the second quarter of 1992, when they acquired their interests in the Station, and that the other owners are responsible for the alleged violations during the entire period. The complaint alleges that there were approximately 10,000 violations since the second quarter of 1992. On March 18, 1999, the district court issued its order regarding summary judgment motions filed by the parties. The court ruled, among other things, that the emission monitors may be used by the plaintiff to establish violations of opacity standards, but that the plant owners are entitled to prove that the reported information is flawed.
Over the period from November 1997 to May 1998, Powercor entered into 11 electricity hedging contracts with a NSW State-owned generator (the "Generator") for the notional supply of electricity between 1998 and 2008. The contracts were designed to support the long-term supply of electricity by Powercor to its customers and to minimize Powercor's exposure to large fluctuations in the spot electricity price. When the wholesale market price for electricity moved against the Generator in May 1998, the Generator denied that any final and binding contracts had been entered into with Powercor, as both parties had not signed final versions of the confirmations setting out the terms and conditions of each transaction. However, an ISDA Master Agreement was in place between the parties which governed the negotiation, contracting and settlement process of individual contracts between them.
The Generator refused to honor the contracts and Powercor issued proceedings against the Generator, claiming in the Supreme Court of Victoria that the contracts were valid and enforceable. (Powercor Australia Ltd. v. Pacific Power, Commercial List No. 4931, Case No. 2067 of 1998, Supreme Court of Victoria.) In December 1999 a ruling was issued in favor of Powercor. Specific performance was ordered of the 11 electricity hedge contracts, which were in dispute. Further, the following orders were made requiring payments by the Generator to Powercor: the Generator made payment of $29 million on December 17, 1999 attributable to the performance of the contracts from July 1, 1998 to judgment. This amount reflects the difference between actual payments and payments under the hedges plus interest of $1 million; and the Generator made payment of $2 million on December 24, 1999 as an agreed sum for legal expenses and other costs relating to the proceedings.
On December 21, 1999, the Generator appealed the judgments, declarations and orders on 80 grounds, including substantially all of the key aspects of the decision. The appeal is listed for hearing on October 2, 2000 for eight days.
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The Company announced the closure of the Trail Mountain mine on April 12, 2000. Mining operations at Trail Mountain will cease in the fall of 2001. With the early closure of the mine, there may be additional reclamation costs for which the Company would seek recovery through future rates.
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.
Construction and Other - Construction and acquisitions are estimated at $429 million for 2001. As a part of these programs, substantial commitments have been made.
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 year ended March 31, 2000, the three months ended March 31, 1999, and the years ended December 31, 1998 and December 31, 1997 was $16 million, $5 million, $17 million and $15 million, respectively.
Future minimum lease payments under noncancellable operating leases are $5 million, $4 million, $4 million, $3 million and $2 million for 2001 through 2005, respectively.
Jointly Owned Facilities - At March 31, 2000, Domestic Electric Operations' participation in jointly owned facilities was as follows:
| Electric | Plant |
| Construction |
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(a) Includes kilovolt lines and substations.
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(b) Plant, inventory, fuel and decommissioning costs totaling $21 million relating to the Trojan Plant were included in regulatory assets-net at March 31, 2000.
(c) Excludes unallocated acquisition adjustments of $104 million at March 31, 2000, that represents, for regulatory accounting, the excess of the cost of the acquired interest in the facilities over their original cost net of accumulated depreciation.
(d) Additionally, the Company has contracted to purchase the remaining 50% of the output of the plant.
(e) The owners sold the plant on May 4, 2000. For additional information on the sale, see Note 17.
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.
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 the Federal Energy Regulatory Commission (the "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 $410 million, $346 million, $334 million, $312 million and $280 million for the years 2001 through 2005, 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 $291 million, $286 million, $281 million, $245 million and $227 million for the years 2001 through 2005, respectively. The purchase contracts include agreements with the Bonneville Power Administration, 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 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 2000, such purchases approximated 3% of energy requirements.
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At March 31, 2000, 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, include debt service of $7.8 million.
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.
The Klamath Cogeneration Project plant, being constructed in conjunction with the City of Klamath Falls, has a planned commercial operation date of July 2001. Upon commercial operation, PPM is under contract to purchase approximately 47% of the total megawatt capacity from the plant for resale to third parties, and market on behalf of the City the remaining output to municipal and commercial buyers in the Pacific Northwest and northern California. PPM is also under contract for management, operations and fuel supply. Holdings has provided a guarantee of $60 million of subordinated debt of the project.
Powercor has an unconditional purchase obligation agreement that requires them to purchase a cogenerator's production in excess of that required for the cogenerator's use. The amount of energy required to be purchased cannot be estimated at this time. In 2000, 1998 and 1997, Powercor purchased 137,655 MWh, 155,311 MWh and 171,217 MWh, respectively, at $49.68, $50.44 and $57.61 per MWh.
Fuel Contracts - Domestic Electric Operations has take or pay coal and natural gas contracts which require minimum fixed payments of $115 million, $118 million, $134 million, $138 million and $142 million for 2001 through 2005, 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.
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NOTE 15 INCOME TAXES
The Company's combined federal and state effective income tax rate from continuing operations was 62% for the year ended March 31, 2000, 39% for the three months ended March 31, 1999, 35% for calendar year 1998 and 32% for calendar year 1997. The primary driver for the increase in the tax rate for the year ended March 31, 2000 was the non-deductible 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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March 31, | March 31, | December 31, | December 31, | |
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The provision for income taxes is summarized as follows:
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March 31, | March 31, | December 31, | December 31, | |
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The tax effects of significant items comprising the Company's net deferred tax liability were as follows:
| March 31, | December 31, |
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The Company has received an Internal Revenue Service ("IRS") examination report for 1991, 1992 and 1993, proposing adjustments that would increase current taxes payable by $97 million. The Company filed a protest of many of these proposed adjustments in December 1998. Discussions with the Appeals Division of the IRS commenced in November 1999 with the intent to reach resolution of many of the disputed issues.
The Company completed its discussions with the Appeals Division for the 1989 and 1990 tax years during 1998. A total of $8 million was paid as part of resolution of many of the issues. In 1999, the Company filed for relief in Tax Court with respect to two issues where it still has disagreement. The tax impact for these two issues is $4 million.
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 $2 million each for 2000 and the three months ended March 31, 1999. The Company made income tax payments of $504 million and $134 million in 1998 and 1997, respectively.
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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 which 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, 2000, plan assets were primarily invested in common stocks, bonds and United States government obligations.
All permanent employees of Powercor engaged prior to October 4, 1994 are members of Division B or C of the Superannuation Fund (the "Fund") which provides 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 choose to contribute do so at rates of 3% or 6% of eligible salaries. Powercor employees engaged after October 4, 1994 are members of Division D of the Fund, which is a defined contribution fund in which members may contribute up to 20% of eligible salaries. In 2000, Powercor made contributions of approximately $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 both years.
The net periodic pension cost and significant assumptions are summarized as follows:
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| Three |
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March 31, | March 31, | December 31, | December 31, | |
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The change in the projected benefit obligation, change in plan assets and funded status are as follows:
| March 31, | December 31, |
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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 Sections 401(k), 401(a), 409, 501 and 4975(e)(7) of the Internal Revenue Code. Participating United States employees may defer up to 16% of their compensation, subject to certain regulatory limitations. The Company matches a portion of employee contributions 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
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earnings. These contributions are immediately vested. Company contributions to the savings plan were $19 million for the year ended March 31, 2000, $5 million for the three months ended March 31, 1999, and $18 million and $20 million for the years 1998 and 1997, respectively.
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 $144 million at March 31, 2000. For those employees retiring after January 1, 1994, the Company funds postretirement benefit expense through a combination of funding vehicles. The Company contributed to the funded plan $6 million of postretirement benefits for the year ended March 31, 2000, nothing for the three months ended March 31, 1999, $27 million for 1998 and $18 million for 1997. 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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March 31, | March 31, | December 31, | December 31, | |
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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, | December 31, |
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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, 2000 by $25 million, and the annual net periodic postretirement benefit costs by $2 million. Decreasing the assumed health care cost trend rate by one percentage point would have reduced the APBO as of March 31, 2000 by $24 million, and the annual net periodic postretirement benefit costs by $2 million.
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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 $8 million for the year ended March 31, 2000, $2 million for the three months ended March 31, 1999 and $12 million for the year ended December 31, 1998.
Early Retirement Offer - See Note 6 for details of the early retirement offering in 1998.
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 ADSs.
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The table below summarizes the stock option activity under the Plan.
Weighted |
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At March 31, 2000, options for 2,214,455 ScottishPower ADSs 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. At December 31, 1998, options for 591,201 PacifiCorp shares were exercisable with a weighted average exercise price of $20.18 per share. The weighted average life of the options outstanding at December 31, 1998 was nine 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 its stock options under SFAS No. 123, the Company's net income would have been reduced to the pro forma amounts below:
| Year ended | Year Ended |
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The fair value of options granted during the year was $9 million and $14 million in 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:
2000 | 1998 | 1997 | |
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NOTE 17 ACQUISITIONS AND DISPOSITIONS
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 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.
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, subject to certain post-closing adjustments. The Company operated the plant and owned a 47.5% share. After the return to customers required by the regulatory approvals, the Company estimates a $14 million loss will be realized on the sale. The timing of this return to customers varies by state. The sale was pursued by the owners, in part, because of emerging deregulation, competition in the electricity industry and the need for environmental compliance expenditures. 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 has been incorporated into the estimate of net loss on the sale.
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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 investment in energy development businesses" 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.
On December 1, 1997, TPC sold all of the capital stock of three subsidiaries that hold its natural gas gathering and processing systems for $195 million in cash, before tax payments of $23 million. No gain or loss was recognized on the sale. In October 1998, the Company announced its intention to sell the remaining business of TPC. See Note 4.
On November 5, 1997, Holdings completed the sale of PGC for approximately $150 million in cash. A pretax gain on the sale of $57 million ($30 million after-tax) was recognized in the fourth quarter of 1997.
During January 2000, the Company decided to seek a buyer for Powercor.
In July 1998, the Company announced its intent 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. On April 9, 1999, the Company announced it had entered into a letter of intent with Nor-Cal Electric Authority for the sale of the assets to Nor-Cal for $178 million. A definitive agreement was signed on July 15, 1999. The FERC approved the sale on January 28, 2000. The California Public Utility Commission must now approve the sale, which is expected to close in the fall of 2000.
In October 1998, the Company announced its intention to sell its 19.9% interest in the Hazelwood Power Partnership ("Hazelwood") as a result of its refocus on the western United States. Hazelwood is an equity investment included in the Company's financial statements as part of Australian Electric Operations. The Company recorded a pretax loss of $28 million ($17 million after-tax), which is included in "Write down of investment in energy
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development businesses" on the income statement, to reduce its carrying value in the Hazelwood Power Station to estimated net realizable value less selling costs. This write down was arrived at using cash flow projections. For 2000, the three months ended March 31, 1999, and 1998, Hazelwood recorded losses of $3 million pretax ($2 million after-tax), $4 million pretax ($2 million after tax) and $7 million pretax ($5 million after-tax), respectively.
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 operates 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 includes 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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2000 | 1999 | 1998 | 1997 | 1996 | 1995 | |
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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 includes the Company's interest in PTI, TPC and the eastern energy trading business of PPM.
(c) Extraordinary item includes a regulatory asset impairment pertaining to generation resources that are allocable to operations in California and Montana.
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DOMESTIC ELECTRIC OPERATIONS (UNAUDITED)
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*Not a meaningful number.
(a) Does not reflect elimination of interest on intercompany borrowing
arrangements and includes income taxes on a separate-company basis.
(b) Includes ScottishPower merger costs of $16.0 million.
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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 and firm purchases at time of firm peak.
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AUSTRALIAN ELECTRIC OPERATIONS (UNAUDITED)(a)
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*Not a meaningful number.
(a) Results of operations are included since dates of acquisition, December 12, 1995 for Powercor and September 13, 1996 for Hazelwood.
(b) Comparison done without consideration of the changes in currency exchange rates.
(c) 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.
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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.
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Capital spending | $ 2 | $ - | $ 53 | $ 140 | $ 56 | $ 44 |
(a) During 1997, the Company generated $1.8 billion of cash, excluding $370 million of current income tax liabilities, from sales of assets with carrying values of $822 million. See Notes 4 and 17.
(b) Includes $3.1 million in ScottishPower merger costs.
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SUPPLEMENTAL INFORMATION
QUARTERLY FINANCIAL DATA (UNAUDITED)
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A significant portion of the operations are of a seasonal nature.
Effective November 30, 1999, the Company changed its year end from December 31 to March 31. See Note 1 to the consolidated financial statements. Quarterly data presented for the 2000 period is for the fiscal year ended March 31, 2000. Quarterly data for the 1998 period is for the calendar year ended December 31, 1998. The quarterly data for the stub period January 1, 1999 through March 31, 1999 is presented on the Statement of Consolidated Income.
In the quarter ended June 30, 1999, the Company recorded an after-tax charge of $8 million relating to ScottishPower merger costs. See Note 2 to the consolidated financial statements.
In the quarter ended September 30, 1999, the Company recorded an after-tax charge of $4 million relating to ScottishPower merger costs. See Note 2 to the consolidated financial statements.
In the quarter ended December 31, 1999, the Company recorded an after-tax charge of $190 million relating to ScottishPower merger costs, $15 million relating to the write-off of projects under construction and $11 million
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relating to recalculation of contract fees owed by Powercor. In addition, the Company recorded after-tax earnings $18 million relating to the favorable outcome of a contract dispute Powercor was having with one of its suppliers. See Note 2 to the consolidated financial statements.
In the quarter ended March 31, 2000, the Company recorded after-tax earnings of $22 million relating to the overaccrual of ScottishPower merger costs. See Note 2 to the consolidated financial statements.
In the quarter ended March 31, 1998, the Company recorded an after-tax charge of $54 million relating to the write off of TEG transaction costs and $70 million relating to the early retirement offer. See Notes 3 and 6 to the consolidated financial statements.
In the quarter ended September 30, 1998, the Company recorded an after-tax charge of $119 million relating to the provision for losses anticipated in the disposition of PPM and TPC. In addition, the Company recorded an after-tax charge of $32 million relating to the provision for losses anticipated in the disposition of the Company's other energy businesses. See Notes 4 and 17 to the consolidated financial statements.
In the quarter ended December 31, 1998, the Company recorded $13 million relating to ScottishPower merger costs, $17 million relating to the write down of its investment in Hazelwood and $14 million of income relating to revised losses for discontinued operations due to the pending sale of TPC for $133 million plus a working capital adjustment at closing. See Notes 2, 4 and 17 to the consolidated financial statements.
See Note 4 to the consolidated financial statements for information regarding discontinued operations.
On March 31, 2000, 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
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The following is a list of directors of the Company.
Sir Ian Robinson, (58), Chairman of the Board of the Company.
Sir Ian Robinson was elected Chairman of the Board of the Company effective upon the merger with ScottishPower in November 1999. He has served as Chief Executive of ScottishPower since 1995 and is a member of the ScottishPower Board of Directors.
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Karen K. Clark, (39), Chief Financial Officer of the Company. Director since 2000.
Ms. Clark was elected Chief Financial Officer on January 16, 2000. She was Senior Vice President-Finance at Sunbeam, Inc. from May 1998 to January 2000. From 1997 to 1998, Ms. Clark was Vice President-Finance of The Coleman Company, Inc. and was Corporate Controller for Precision Castparts Corp. from 1994 to 1997.
Terry Hudgens, (45), Senior Vice President of the Company. Director since 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.
Nolan E. Karras, (55). Director since 1993.
Mr. Karras is President of The Karras Company, Inc., investment advisers, Roy, Utah, since 1983. He is Chief Executive Officer of Western Hay Company, Inc., and a non-executive 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, (57), Executive Vice President of the Company. Director since 1999.
Mr. Landels was elected Executive Vice President and Director of the Company effective upon the merger with ScottishPower in November 1999. Formerly, 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.
Andy MacRitchie, (36), Senior Vice President of the Company. Director since 2000.
Mr. MacRitchie has been with ScottishPower since 1986. He led the ScottishPower merger team through the successful negotiation and settlement process with state regulatory commissions and then took up the role of Transition Director, leading a combined PacifiCorp/ScottishPower senior management team (50 people) in the development of comprehensive change plans for PacifiCorp.
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Keith R. McKennon, (66). Director since 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. Prior to joining PacifiCorp, he was Chairman from 1992 until 1994 and CEO of Dow Corning 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.
Timothy E. Meier, (47), Senior Vice President of the Company. Director since 2000.
Mr. Meier was elected Senior Vice President of the Company on May 15, 2000. He was Senior Vice President of U.S. Bancorp from 1991 until joining PacifiCorp in September 1997.
Robert G. Miller, (56). Director since 1994.
Mr. Miller joined the Board as non-executive 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.
Mike Pittman, (47), Senior Vice President of the Company. Director since 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, (53), President and Chief Executive Officer of the Company. Director since 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.
Ian M. Russell, (47). Director since 1999.
Mr. Russell was appointed Deputy Chief Executive of ScottishPower in November 1998, having previously been appointed Finance Director of ScottishPower in April 1994 and serving in both capacities from November 1998 to December 1999. In his present capacity, he is responsible for UK and US operations and is also non-executive Chairman of Thus plc.
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Kenneth L. Vowles, (58). Director since 1999.
Mr. Vowles joined ScottishPower in September 1990 and was appointed to the ScottishPower Board in September 1994.
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.
Paul G. Lorenzini, (58), Senior Vice President of the Company.
Mr. Lorenzini was elected a Senior Vice President of the Company in May 1994. He served as President of Pacific Power from January 1992 to May 1994.
C. Alex Miller, (42), Vice President of the Company.
Mr. Miller was elected a Vice President in November of 1999. Mr. Miller was President and CEO of Edison Source, a division of Edison International from 1996 to 1997. From 1993-1996, Mr. Miller was Vice President and Treasurer of Southern California Edison Company.
Robert R. Dalley, (46), Controller and Chief Accounting Officer of the Company.
Mr. Dalley was elected Controller and Chief Accounting Officer of the Company in August 1998. He served as Assistant Controller from March 1998 to August 1998 and as an Assistant Vice President of the Company from July 1992 to March 1998.
Bruce N. Williams, (41), Treasurer of the Company
Mr. Williams was elected Treasurer of the Company on February 16, 2000. He served as Assistant Treasurer from 1990.
ITEM 11. EXECUTIVE COMPENSATION
Board Report on Executive Compensation
Introduction
PacifiCorp merged with ScottishPower on November 29, 1999 (the "Merger") and the Company has shifted from a calendar fiscal year to a fiscal year ending March 31. Therefore, this Board report on executive compensation covers the period which began January 1, 1999 and ended March 31, 2000.
Prior to the Merger, the Personnel Committee of the PacifiCorp Board, which was composed entirely of independent, non-employee directors, was responsible for approving compensation levels for officers of PacifiCorp, administering executive compensation plans as authorized by the PacifiCorp Board and recommending executive compensation plans and compensation of the Chief Executive Officer to the PacifiCorp Board for approval. Since the Merger,
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these responsibilities have been assumed by the PacifiCorp Board of Directors. However, as it relates to any stock based compensation, these matters must also be approved by the Remuneration Committee of the Board of ScottishPower, which is comprised entirely of independent, non-employee directors. The following Board report describes the components of PacifiCorp's executive compensation program and the basis upon which determinations were made for the period from January 1, 1999 to March 31, 2000.
Compensation Philosophy
PacifiCorp's philosophy is that executive compensation should be linked closely to corporate performance and increases in shareholder value. PacifiCorp's compensation program has the following objectives:
. Provide competitive total compensation that enables PacifiCorp to attract and retain key executives.
. Provide variable compensation opportunities that are linked to company and individual performance.
. Establish an appropriate balance between incentives focused on short-term objectives and those encouraging sustained earnings performance and increases in shareholder value.
Qualifying compensation for deductibility under IRC Section 162(m) is one of the factors the Board considers in designing its incentive compensation arrangements. IRC Section 162(m) limits to $1,000,000 the annual deduction by a publicly held corporation of compensation paid to any executive, except with respect to certain forms of incentive compensation that qualify for exclusion. Although it is the Board's intent to design and administer compensation programs that maximize deductibility, the Board views the objectives outlined above as more important than compliance with the technical requirements necessary to exclude compensation from the deductibility limit of IRC Section 162(m). Nevertheless, the Board believes that nearly all compensation paid to the executive officers for services rendered in the fiscal year ended March 31, 2000 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 using the general industry as the market reference base for long-term incentive purposes.
In the fiscal year ended March 31, 2000, 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
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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. For officers with responsibilities outside the electric operations, relevant industry data were used for comparison. In all cases, compensation is targeted at market median levels, with a recognition that total compensation greater than market median requires, in any specific time period, 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 fiscal year ended March 31, 2000, the base salaries of executive officers were increased, based on market analysis, by an average of 2.3% 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 calendar 1999 were exclusively company earnings per share ("EPS"). All executive incentive program participants may have their incentive awards modified (in the range of zero to 120%) 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. Considering the challenges of measuring earnings performance following the Merger, the Board assigned an EPS factor of 121% for the year of 1999. Mr. McKennon, the Chief Executive Officer until November 29, 1999, received 121% of his 1999 target award for the year 1999.
Long-Term Incentives
The PacifiCorp Board approved grants of restricted stock and stock options in early 1999 and again in early 2000 under the Stock Incentive Plan. In determining restricted stock awards, the Board considered criteria such as:
. total shareholder return relative to peer companies;
. earnings per share growth over time relative to peer companies;
. and other factors such as achievement of long-term goals, strategies and plans.
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Based upon an assessment of these criteria, PacifiCorp established a pool of restricted stock equal to 50% of competitive award levels in 1999 and 130% in 2000. The shares in the pool were allocated to participants based on individual performance.
The Board also approved 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 company stock (PacifiCorp common stock before the Merger and ScottishPower American Depository Shares or ordinary shares since the Merger) 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 fiscal years 1998, 1999 and 2000.
All stock options awarded to officers and senior management of PacifiCorp in fiscal years 1998, 1999 and 2000 are non-statutory, non-discounted options with a three-year vesting requirement and a ten-year term from the date of the grant. Grants of stock options in fiscal year 2000 to named executives are shown in the table under "Option Grants in Last Fiscal Year."
In May 1998 and again in May 1999, the Board also approved a grant of non-statutory and non-discounted stock options to all employees except officers and senior managers. Full-time employees received options for 100 shares while part-time employees were granted options for 75 shares. These grants become fully vested two years from the grant, and employees have ten years to exercise the options. All restricted stock awards and stock options granted prior to February 1999 became fully vested upon the Merger.
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 non-executive directors.
The ScottishPower Remuneration Committee is responsible for ensuring that the rewards for executives attracts and retains 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 market median position on all senior management remuneration packages, and to provide packages above the market median 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 the company. The Committee has also continued to take independent advice from external remuneration consultants on market-level remuneration, based on comparison 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 multi-utility 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 non-pensionable and non-contractual and are subject to the approval of the Remuneration Committee.
The 1999/2000 scheme provided a bonus of a maximum of 50% of salary, with up to a maximum of 25% of base salary determined by the company's performance. Measurement is by reference to a matrix of performance against targets of earnings per share and return on capital employed, to reflect shareholder value. The balance of the bonus, a maximum of 25% of base salary, 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 every six months. Mr. Richardson earned the maximum incentive award during the performance period ended March 31, 2000.
Long Term Incentive Plan
ScottishPower operates a Long Term Incentive Plan 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 the company and customer service standards.
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The number of shares which 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 FTSE 100 Index and half against the 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 the company ranks in the top decile; 90% if the company ranks in the second decile; 80% if the company ranks in the third decile; 60% if the company ranks in the fourth decile; 40% if the company ranks in the fifth decile; and no award is made if the company ranks in the sixth decile or lower.
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
In February 1999, the PacifiCorp Board approved a grant of 3,500 restricted shares of PacifiCorp common stock to Mr. McKennon under the Stock Incentive Plan based upon a review of company performance during 1998. The PacifiCorp Board also granted to Mr. McKennon, in February 1999, non-qualified stock options for 250,000 shares of PacifiCorp common stock as part of its effort to provide motivation for future stock price appreciation. These restricted shares and stock options were converted on November 29, 1999, in the Merger, to ScottishPower American Depository Shares ("ADS"). Using the conversion formula specified in the Merger agreement, this resulted in 2,030 restricted ScottishPower ADS shares and 145,000 ScottishPower ADS stock options. Mr. McKennon's salary did not increase during his employment with PacifiCorp.
On November 29, 1999, the effective date of the Merger, Mr. McKennon resigned as Chairman of the Board, Chief Executive Officer and President and became a non-employee director of ScottishPower in the position of Vice Chairman. Mr. McKennon was not eligible for severance pay and benefits. Mr. McKennon's restricted stock and stock options were partially vested in February 2000 and will continue to vest as long as Mr. McKennon remains on the Board of PacifiCorp or ScottishPower.
On November 29, 1999, Mr. Richardson assumed Mr. McKennon's responsibilities as Chief Executive Officer and President. The ScottishPower Board approved an employment agreement with Mr. Richardson that provides him a base salary of $341,000 and a maximum annual incentive award of 60% 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 equal to 60% of base salary. Mr. Richardson is on an international assignment in the
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U.S. and, therefore, receives international assignment benefits as described in the "Summary Compensation Table" below.
BOARD OF DIRECTORS
Sir Ian Robinson, Chairman
Karen K. Clark
Terry Hudgens
Nolan E. Karras
William D. Landels
Andy MacRitchie
Keith R. McKennon
Timothy E. Meier
Robert G. Miller
Mike Pittman
Alan V. Richardson
Ian M. Russell
Kenneth L. Vowles
Executive Compensation
The following table sets forth information concerning compensation for services in all capacities to PacifiCorp and its subsidiaries for fiscal years ended March 31, 2000, 1999 and 1998 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 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, 2000.
Summary Compensation Table
Annual Compensation(1) | Long-Term Compensation | ||||||
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(1) May include amounts deferred pursuant to the Compensation Reduction Plan, under which key executives and directors may defer, until retirement or a
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preset future date, receipt of cash compensation to a stock account to be invested in company common stock or to 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.
(2) Includes amounts paid to executive officers in the form of international assignment benefits, including foreign housing allowances. These amounts were $65,273 and $60,400 for Messrs. Richardson and Lorenzini, respectively, in the fiscal year ended March 31, 2000. Included in 1999 is $371,133 for international assignment benefits for Mr. Lorenzini.
(3) Please 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 the related services were performed. Amounts in this column for 2000 include a special bonus that was paid upon the closure of the Merger with ScottishPower. These amounts are $46,500, $350,000, $250,000, $75,000, $25,000, $138,200, and $125,000 for Messrs. Richardson, McKennon, O'Brien, Lorenzini, Sickels, Miller and Pittman, respectively. Amounts in this column for 1999 include special incentive awards for accomplishments in 1998 and 1999. These amounts are $250,000; $80,000; $40,000; and $75,000 for Messrs. O'Brien, Lorenzini, Miller and Pittman, respectively.
(4) Includes restricted stock grants made in (a) February 2000, 1999 and 1998 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. The 1998 grants became vested at the time of the Merger. At March 31, 2000, the aggregate value of all restricted stock holdings, based on the market value of the shares at March 31, 2000, without giving effect to the diminution of value attributed to the restrictions on such stock, and the aggregate number of restricted share holdings of Messrs. McKennon, Lorenzini, Sickels, Miller and Pittman were $48,244, $167,246, $59,223, $52,886 and $96,995, 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 the fiscal year ended March 31, 2000 include (a) contributions to the PacifiCorp K Plus Employee Savings and Stock Ownership Plan for each of Messrs. McKennon, O'Brien, Lorenzini, Sickels, Miller and Pittman and (b) portions of premiums on term life insurance policies which PacifiCorp paid for Messrs. McKennon, O'Brien, Lorenzini, Sickels, Miller and Pittman in the amounts of $842, $547, $418, $346, $300 and $338, respectively. These benefits are available to all employees.
(6) Mr. Richardson became President and Chief Executive Officer after Mr. McKennon's resignation in November 1999.
(7) Represents the number of ScottishPower ordinary performance shares contingently granted in 1999 which can be earned under the terms of the ScottishPower Long Term Incentive Plan.
(8) Mr. McKennon resigned as Chairman, President and Chief Executive Officer on November 29, 1999.
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(9) Includes $1,322,400 of severance compensation. Mr. O'Brien's 1999 grant of restricted stock awards became fully vested as a consequence of his employment separation in February, 2000. He will receive four additional cash severance payments of $600,000 each on September 1, 2000; March 1, 2001; September 1, 2001; and March 1, 2002.
Option Grants in Last Fiscal Year
Individual Grants(1) | ||||||
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(1) All options are for ScottishPower American Depository Shares ("ADS").
(2) All options become exercisable for one-third of the shares covered by the option on each of the first three anniversaries of the grant date. The grant date for each option shown in the table above was February 16, 2000.
Aggregated Option Exercises in Last Fiscal Year
and FY-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
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Compensation Table, with the exception of Messrs. Richardson, McKennon and O'Brien (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 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 which 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.
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If qualified, 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. O'Brien, 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 Messrs. Richardson, McKennon and O'Brien) 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 in the event of a company-initiated termination.
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 Messrs. Richardson and McKennon), are also eligible to participate in PacifiCorp's non-qualified 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 calendar 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
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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 non-qualified supplemental plan.
The supplemental plan provides executives "involuntarily terminated" during the 24 months following the ScottishPower Merger, or who resign for any reason effective no earlier than 12 months and no later than 14 months after the Merger, with enhanced supplemental retirement benefits. For purposes of the plan, a termination of employment is "involuntary" if the participant is discharged for reasons other than cause or resigns under certain circumstances following a change-in-control. A resignation is treated as an involuntary termination when any of the following occur:
(1) the executive's annualized base salary or target bonus opportunity is decreased;
(2) the executive is reassigned to a position in an office located more than 100 miles from the executive's then-current office or 60 miles from the executive's residence, whichever is greater;
(3) the executive's reporting level in PacifiCorp is changed and is lower after the change than it was before;
(4) there is a material reduction in the scope of the executive's duties or responsibilities; or
(5) there is a material reduction in the executive's authority.
The following table shows the estimated annual retirement benefit payable upon retirement at age 60 as of January 1, 2000. 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) | ||||
Annual Pay at |
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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.
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(2) The number of credited years of service used to compute benefits under the plans for Messrs. O'Brien, Lorenzini, Sickels, Miller and Pittman are 16, 12, 15, 2 and 20, respectively. Messrs. McKennon and Richardson are not participants in this plan.
Mr. Richardson is provided retirement benefits through the main pension scheme of ScottishPower, and through an executive top-up pension plan which 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 base salary in the 12 months prior to leaving the company. 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) 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.
(2) 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.
(3) The transfer value has been calculated on the basis of actuarial advice less contributions.
(4) Transferred in benefits represent pension rights accrued in respect of previous employments.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Not applicable.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Not applicable.
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PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) 1. The list of all financial statements filed as a part of this report is included in ITEM 8.
2. Schedules:*
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*All schedules have been omitted because of the absence of the conditions under which they are required or because the required information is included elsewhere in the financial statements included under ITEM 8.
3. Exhibits:
*(2)a -- Agreement and Plan of Merger, dated as of December 6, 1998, by and among Scottish Power plc, NA General Partnership, Scottish Power NA 1 Limited and Scottish Power NA 2 Limited. (Incorporated by reference to Exhibit 1 to the Form 6-K, dated December 11, 1998, filed by Scottish Power plc, File No. 1-14676).
*(2)b -- Amended and Restated Agreement and Plan of Merger, dated as of December 6, 1998, as amended as of January 29, 1999 and February 9, 1999, and amended and restated as of February 23, 1999, by and among New Scottish Power PLC, Scottish Power plc, NA General Partnership and PacifiCorp (Exhibit (2)b, Form 10-K for fiscal year ended December 31, 1998, File No. 1-5152).
(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.
(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.
(2)e - Asset Purchase Agreement dated as of July 15, 1999, between PacifiCorp and Nor-Cal Electric Authority.
*(3)a -- Third Restated Articles of Incorporation of the Company (Exhibit (3)b, Form 10-K for the fiscal year ended December 31, 1996, File No. 1-5152).
(3)b -- Bylaws of the Company effective November 29, 1999.
*(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,
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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 fiscal year ended December 31, 1994, File No. 1-5152; and Exhibit (4)b, Form 10-K for the fiscal year ended December 31, 1995, File No. 1-5152; Exhibit (4)b, Form 10-K for the fiscal year ended December 31, 1996, File No. 1-5152); and (Exhibit (4)b, Form 10-K for fiscal 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.
*(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 fiscal 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 fiscal year ended December 31, 1994, File No. 1-5152).
(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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(27) -- Financial Data Schedule (filed electronically only).
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*Incorporated herein by reference.
(b) Reports on Form 8-K.
On Form 8-K dated May 3, 2000, under "Item 5. Other Events," the Company filed two news releases. One concerning a transition plan for the Company and the other concerning the sale of the Centralia plant and mine to TransAlta.
(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: June 16, 2000
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED.
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