-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, W1p3hpACVq82JCxjsFW5Uy/WA4KfkeH89EzH9cEeZc1MK5HI/qFqBZ/a2MfjoqTB wkbOPw+HJhApR0ZPqN3vYA== 0001047469-98-012019.txt : 19980330 0001047469-98-012019.hdr.sgml : 19980330 ACCESSION NUMBER: 0001047469-98-012019 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 9 CONFORMED PERIOD OF REPORT: 19971231 FILED AS OF DATE: 19980327 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: PACIFICORP /OR/ CENTRAL INDEX KEY: 0000075594 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 930246090 STATE OF INCORPORATION: OR FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: SEC FILE NUMBER: 001-05152 FILM NUMBER: 98575979 BUSINESS ADDRESS: STREET 1: 700 NE MULTNOMAH STE 1600 CITY: PORTLAND STATE: OR ZIP: 97232 BUSINESS PHONE: 5037312000 FORMER COMPANY: FORMER CONFORMED NAME: PACIFICORP /ME/ DATE OF NAME CHANGE: 19890628 FORMER COMPANY: FORMER CONFORMED NAME: PC/UP&L MERGING CORP DATE OF NAME CHANGE: 19890628 10-K 1 10-K - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 -------------------------- FORM 10-K (MARK ONE) /X/ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 1997 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 of incorporation or organization) No.) 700 N.E. MULTNOMAH, PORTLAND, OREGON 97232-4116 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: (503) 731-2000 Securities registered pursuant to Section 12(b) of the Act:
NAME OF EACH EXCHANGE TITLE OF EACH CLASS ON WHICH REGISTERED - ------------------------------------------------ --------------------------- Common Stock New York Stock Exchange Pacific Stock Exchange 8 3/8% Quarterly Income Debt Securities (Junior New York Stock Exchange Subordinated Deferrable Interest Debentures, Series A) 8.55% Quarterly Income Debt Securities (Junior New York Stock Exchange Subordinated Deferrable Interest Debentures, Series B) 8 1/4% Cumulative Quarterly Income Preferred New York Stock Exchange Securities, Series A, of PacifiCorp Capital I 7.70% Cumulative Quarterly Income Preferred New York Stock Exchange Securities, Series B, of PacifiCorp Capital II
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. / / On March 1, 1998, the aggregate market value of the shares of voting and nonvoting common equity of the Registrant held by nonaffiliates was approximately $7.4 billion. As of March 1, 1998, there were 297,215,100 shares of the Registrant's common stock outstanding. DOCUMENTS INCORPORATED BY REFERENCE Portions of the Annual Report to Shareholders of the Registrant for the year ended December 31, 1997 are incorporated by reference in Parts I and II. Portions of the proxy statement of the Registrant for the 1998 Annual Meeting of Shareholders are incorporated by reference in Part III. - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- TABLE OF CONTENTS
PAGE NO. ----- Definitions................................................................................................ 3 Part I Item 1. Business.................................................................................... 4 The Organization.......................................................................... 4 Domestic Electric Operations.............................................................. 5 Australian Electric Operations............................................................ 14 Unregulated Energy Trading................................................................ 21 Other Operations.......................................................................... 21 Discontinued Operations................................................................... 22 Employees................................................................................. 22 Item 2. Properties.................................................................................. 22 Item 3. Legal Proceedings........................................................................... 25 Item 4. Submission of Matters to a Vote of Security Holders......................................... 26 Item 4A. Executive Officers of the Registrant........................................................ 26 Part II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters....................... 28 Item 6. Selected Financial Data..................................................................... 28 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations....... 28 Item 7A. Quantitative and Qualitative Disclosures about Market Risk.................................. 28 Item 8. Financial Statements and Supplementary Data................................................. 28 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure........ 28 Part III Item 10. Directors and Executive Officers of the Registrant.......................................... 28 Item 11. Executive Compensation...................................................................... 29 Item 12. Security Ownership of Certain Beneficial Owners and Management.............................. 29 Item 13. Certain Relationships and Related Transactions.............................................. 29 Part IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K............................. 29 Signatures................................................................................................. 32 Appendices Statements of Computation of Ratio of Earnings to Fixed Charges Statements of Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends List of Subsidiaries
2 DEFINITIONS When the following terms are used in the text they will have the meanings indicated:
TERM MEANING - ------------------------------------------ --------------------------------------------------------------------- BPA....................................... Bonneville Power Administration Company................................... PacifiCorp, an Oregon corporation FERC...................................... Federal Energy Regulatory Commission Hazelwood................................. Hazelwood Power Partnership, a 19.9% indirectly owned investment of Holdings Holdings.................................. PacifiCorp Group Holdings Company, a wholly owned subsidiary of the Company, formerly named PacifiCorp Holdings, Inc., and its wholly owned subsidiary, PacifiCorp International Group Holdings Company PGC....................................... Pacific Generation Company, a wholly owned subsidiary of Holdings until its sale in November 1997, and its subsidiaries PFS....................................... PacifiCorp Financial Services, Inc., a wholly owned subsidiary of Holdings, and its subsidiaries Pacific Power............................. Pacific Power & Light Company, the assumed business name of the Company under which it conducts a portion of its retail electric operations PPM....................................... PacifiCorp Power Marketing, Inc., a wholly owned subsidiary of Holdings PTI....................................... Pacific Telecom, Inc., a wholly owned subsidiary of Holdings until its sale in December 1997, and its subsidiaries Powercor.................................. Powercor Australia Limited, a wholly owned subsidiary of Holdings, and its immediate parent companies, PacifiCorp Australia Holdings Pty Ltd and PacifiCorp Australia, LLC TPC....................................... TPC Corporation, a wholly owned subsidiary of Holdings, and its subsidiaries Utah Power................................ Utah Power & Light Company, the assumed business name of the Company under which it conducts a portion of its retail electric operations
3 PART I ITEM 1. BUSINESS THE ORGANIZATION The Company is a diversified energy company in the United States and Australia. In the United States, the Company conducts a retail electric utility business through Pacific Power and Utah Power, and engages in power production and sales on a wholesale basis under the name PacifiCorp. The Company formed Holdings in 1984 to hold the stock of the Company's principal subsidiaries and to facilitate the conduct of businesses not regulated as domestic electric utilities. Holdings owns 100% of Powercor, the largest of the five electric distribution companies in Victoria, Australia, and a 19.9% interest in the 1,600 megawatt ("MW"), brown coal-fired thermal Hazelwood power station and adjacent brown coal mine in Victoria. The Company's strategic business plan is to strengthen the domestic and international scope and competitive position of its electric utility operations and to develop and expand its nonregulated, energy-related activities, including its energy marketing and trading businesses. The Company's goal is to become a dominant supplier of energy on a global basis. The Company is also expanding its nonregulated businesses that are engaged in wholesale marketing and aggregating of electricity, plant and fuels management, utilities services and retail energy services. PPM has authorization from the FERC to sell power outside of the western United States at market prices. On April 15, 1997, Holdings acquired 100% of TPC, a natural gas gathering, processing, storage and marketing company. In December 1997, TPC sold its nonstrategic natural gas gathering and processing assets. See "UNREGULATED ENERGY TRADING." Holdings continues to liquidate portions of the loan, leasing, real estate and affordable housing investment portfolio of PFS. PFS presently expects to retain only its tax-advantaged investments in leveraged lease assets (primarily aircraft) and is limiting its pursuit of tax-advantaged investment opportunities to alternative fuels. The Company sold PTI on December 1, 1997 and PGC on November 5, 1997. See "DISCONTINUED OPERATIONS" and "OTHER OPERATIONS--Pacific Generation Company." On June 13, 1997, PacifiCorp announced a cash tender offer for The Energy Group PLC ("TEG"). TEG is a diversified international energy group with operations in the United Kingdom ("UK"), the United States and Australia and includes Eastern Group PLC, one of the leading integrated electricity and gas groups in the UK and Peabody Holding Company, Inc., the world's largest private producer of coal. The Company's initial offer lapsed on August 1, 1997 when it was referred to the Monopolies and Mergers Commission by the President of the Board of Trade in the UK. The proposed acquisition of TEG by PacifiCorp was subsequently cleared by the President of the Board of Trade on December 19, 1997. On February 3, 1998, PacifiCorp announced the terms of a renewed cash tender offer for TEG of 765 pence for each ordinary share. On March 2, 1998, Texas Utilities Company ("TU") announced an offer of 810 pence for each TEG share. Following TU's announcement, PacifiCorp announced an increased cash offer of 820 pence for each TEG share. This increased offer values the transaction at $11.1 billion, including the purchase of 521 million shares and the assumption of $4.1 billion of TEG's debt. The acquisition was to be financed with cash raised through sales of noncore assets of subsidiaries of Holdings and borrowings by subsidiaries of Holdings. PacifiCorp's announcement of the increased offer followed the acquisition on March 2, 1998 by a subsidiary of Holdings of 45,987,079 TEG shares at a price of 820 pence per share. These shares represent approximately 8.8% of the outstanding share capital of TEG. On March 3, 1998, TU announced that it was increasing its offer to 840 pence for each TEG share. TU's offer is subject to clearance by the UK Secretary of State for Trade and Industry and certain other regulatory bodies. TU has also announced that it has acquired approximately 22% of the outstanding share capital of TEG. 4 For the year ended December 31, 1997, 59% of PacifiCorp's revenues from operations were derived from Domestic Electric Operations, Australian Electric Operations contributed 11%, Unregulated Energy Trading contributed 28% and Other Operations contributed 2%. Note 16 to the Company's Consolidated Financial Statements, incorporated herein by reference under Item 8, contains information with respect to the revenue and income from operations contributed by each of the Company's industry segments for the past three years and the identifiable assets attributable to each segment at the end of each of those years; this information is incorporated herein by this reference. From time to time, the Company may issue forward-looking statements that involve a number of risks and uncertainties. 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; wholesale energy trading; unregulated energy trading; environmental, regulatory and tax legislation, including industry restructure and deregulation initiatives; technological developments in the electricity industry; 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 common stock (symbol PPW) is traded on the New York and Pacific Stock Exchanges. 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 PacifiCorp 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 1.4 million retail customers in service territories aggregating about 153,000 square miles in portions of seven western states: Utah, Oregon, Wyoming, Washington, Idaho, California and Montana. The 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 and agribusiness. Agricultural products include potatoes, hay, grain and livestock. The geographical distribution of retail electric operating revenues for the year ended December 31, 1997 was Utah, 36%; Oregon, 33%; Wyoming, 13%; Washington, 9%; Idaho, 4%; California, 3%; and Montana, 2%. 5 CUSTOMERS Electric utility revenues and energy sales, by class of customer, for the three years ended December 31, 1997 were as follows:
1997 1996 1995 ----------------------- ---------------------- --------- Operating Revenues (Dollars in millions): Residential................................................. $ 814.0 22% $ 801.4 27% $ 739.7 Commercial.................................................. 640.9 18 623.3 21 576.9 Industrial.................................................. 709.9 20 719.3 25 708.8 Government, Municipal and Other............................. 31.7 1 32.5 1 29.7 ---------- --- --------- --- --------- Total Retail Sales........................................ 2,196.5 61 2,176.5 74 2,055.1 Wholesale Trading-Firm(1)................................... 1,289.3 35 635.4 22 487.7 Wholesale Trading-Nonfirm(1)................................ 138.7 4 103.4 4 32.3 ---------- --- --------- --- --------- Total Energy Sales........................................ 3,624.5 100% 2,915.3 100% 2,575.1 ---------- --- --------- --- --------- ---------- --- --------- --- --------- Other Revenues(2)........................................... 82.4 76.5 71.0 ---------- --------- --------- Total Operating Revenues.................................. $ 3,706.9 $ 2,991.8 $ 2,646.1 ---------- --------- --------- ---------- --------- --------- Kilowatt-hours Sold (kWh in millions): Residential................................................. 12,902 12% 12,819 17% 12,030 Commercial.................................................. 11,868 11 11,497 15 10,797 Industrial.................................................. 20,674 20 20,332 27 19,748 Government, Municipal and Other............................. 705 1 640 1 592 ---------- --- --------- --- --------- Total Retail Sales........................................ 46,149 44 45,288 60 43,167 Wholesale Trading-Firm(1)................................... 51,857 49 23,189 31 13,946 Wholesale Trading-Nonfirm(1)................................ 7,286 7 6,476 9 2,430 ---------- --- --------- --- --------- Total kWh Sold............................................ 105,292 100% 74,953 100% 59,543 ---------- --- --------- --- --------- ---------- --- --------- --- --------- Operating Revenues (Dollars in millions): Residential................................................. 29% Commercial.................................................. 22 Industrial.................................................. 28 Government, Municipal and Other............................. 1 --- Total Retail Sales........................................ 80 Wholesale Trading-Firm(1)................................... 19 Wholesale Trading-Nonfirm(1)................................ 1 --- Total Energy Sales........................................ 100% --- --- Other Revenues(2)........................................... Total Operating Revenues.................................. Kilowatt-hours Sold (kWh in millions): Residential................................................. 20% Commercial.................................................. 18 Industrial.................................................. 33 Government, Municipal and Other............................. 1 --- Total Retail Sales........................................ 72 Wholesale Trading-Firm(1)................................... 24 Wholesale Trading-Nonfirm(1)................................ 4 --- Total kWh Sold............................................ 100% --- ---
- ------------------------ (1) Wholesale trading referred to here is part of Domestic Electric Operations' regulated activities and is separate from the trading business discussed under "UNREGULATED ENERGY TRADING" below. (2) Includes miscellaneous revenues. The Company's seven-state 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 1997, no single retail customer accounted for more than 1.9% of the Company's retail utility revenues and the 20 largest retail customers accounted for 14.7% of total retail electric revenues. 6 COMPETITION During 1997, Domestic Electric Operations continued to operate as a regulated monopoly within its seven-state franchise service territories. Beginning in April 1998 for California and July 1998 for Montana, retail electric energy sales will be subject to open market competition. The Company's provision of distribution services will continue to be regulated while retail sales of electricity will be unregulated in those states. Competition varies in form and intensity, but is increasing over time, principally as a result of industry restructuring and deregulation, and increased marketing by alternative energy suppliers. In addition, many large industrial customers have the option to build their own generation or cogeneration facilities or to use alternative energy sources, such as natural gas. These competitive pressures enable these customers to negotiate lower prices through special tariffs. Competition has already transformed the electric utility industry at the wholesale level. The Energy Policy Act, passed in 1992, led to opening wholesale competition to energy brokers, independent power producers and power marketers. In 1996, the FERC ordered all investor-owned utilities to allow others access to their transmission systems for wholesale power sales. This access must be provided at the same price and terms the utilities would charge their own wholesale customers. As a result of increased competition and excess capacity, wholesale prices have dropped significantly over the past three years. In addition to these changes in the wholesale market, numerous states have enacted legislation or initiated studies of retail competition or are considering retail competition as part of industry restructuring. See "Regulation." The Company is advocating federal legislation that would require states to give all consumers choice in their energy provider by January 1, 2001. The Company believes that federal legislation is necessary to address barriers to entry and issues of jurisdiction, to preserve the proper role for the states in implementing customer choice and to bring benefits to consumers as quickly as possible. The Company has also formulated strategies to meet these new challenges. The Company is marketing power supply services to other utilities, 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 has adopted rules regulating the nontariffed sale of energy and energy products and services by utilities and their affiliates. The Company has decided to refrain from marketing covered products and services in California until certain organizational issues are resolved, but intends to remain active in the wholesale business selling to utilities and marketers in California and elsewhere. During 1997, a subsidiary of the Company entered into alliances to bring nonregulated energy services and products to customers. In May 1997, the Company and ABB, Inc. formed EnergyPact, LLC. ABB, Inc. is an energy technology company manufacturing and servicing fossil fuel and hydroelectric generating equipment and transmission and distribution equipment. EnergyPact offers a menu of comprehensive energy products and services, including upgrades to generation plant equipment, plant management services, fuel procurement services, risk management and energy trading. In July 1997, a subsidiary of the Company and Northwest Natural Company ("Northwest Natural") announced the formation of an alliance to jointly offer gas commodity and energy services throughout Oregon and Washington. They also offer electricity in the areas of those two states where utilities offer pilot programs that will allow commercial and industrial customers to choose their electricity supplier. Northwest Natural is one of the largest purchasers of natural gas in the Northwest and the largest transporter on the Northwest Pipeline. In January 1997, the Company and KN Energy, Inc. announced the formation of a joint venture called "en-able." En-able offers utilities a single package of energy, communications and "infotainment" home-oriented options under the name "Simple Choice" for marketing to their customers. In 1996, a consortium of utilities, including the Company, signed a memorandum of understanding to create an independent grid operator ("IndeGO") for the high-voltage transmission of electricity in 7 Washington, Oregon, Idaho, Montana, Nevada, Utah and Wyoming. In November 1997, IndeGo's participants released a comprehensive proposal for the formation of IndeGo that was to become the core of filings with FERC and state regulators. After considering public comments and the views of the individual utilities that have withdrawn their support for the proposal, seven of the investor-owned utilities in the consortium, including the Company, concluded that it would not be productive to devote further effort to IndeGo development at this time. CURRENT 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 Pacific Northwest 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 Northwest having low-cost hydroelectric generation and with utilities in California and the Southwest having higher-cost, fossil-fuel generation. In periods of favorable hydro conditions, the Company utilizes lower-cost hydroelectric power to supply a greater portion of its load and attempts to sell its displaced higher-cost thermal generation to other utilities. In periods of less favorable hydro conditions, the Company seeks to sell excess thermal generation to utilities that are more dependent on hydroelectric generation than the Company. During the winter, the Company has been able to purchase power from Southwest utilities, either for its own peak requirements or for resale to other Northwest utilities. During the summer, the Company has been able to sell excess power to Southwest utilities to assist them in meeting their peak requirements. See "Wholesale Trading and Purchased Power." The Company owns or has interests in generating plants with an aggregate nameplate rating of 8,699 MW and plant net capability of 8,282 MW. See "Item 2. Properties." With its present generating facilities, under average water conditions, the Company expects that approximately 5% of its energy requirements for 1998 will be supplied by its hydroelectric plants and 55% by its thermal plants. The balance of 40% is expected to be obtained under long-term purchase contracts, interchange and other purchase arrangements. During 1997, the Company's energy supply came from hydro 5%, thermal 45% and purchased power 50%. Note 12 to the Company's Consolidated Financial Statements, incorporated by reference under Item 8, contains additional details relating to the Company's purchase of power under long-term arrangements. The Company currently purchases 1,100 MW of firm capacity annually from BPA pursuant to a long-term agreement. The purchase amount declines to 925 MW annually beginning in 2000 and continuing through 2011. The Company's current annual payment under this agreement is $74 million. The agreement provides for this amount 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. 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 1997, the Company purchased an average of 114 MW from qualifying facilities, compared to an average of 110 MW in 1996. The Company plans and manages its capacity and energy resources based on critical water conditions. Under critical or better water conditions in the Northwest, the Company believes that it has adequate reserve generation capacity for its requirements. The Company's historical total firm peak load (including both retail and firm wholesale sales) of 10,871 MW occurred on August 22, 1997, and its historical on-system firm peak load of 7,615 MW occurred on February 2, 1996. 8 WHOLESALE TRADING AND PURCHASED POWER Wholesale sales continue to contribute significantly to total revenues. The Company's wholesale sales complement its retail business and enhance the efficient use of its generating capacity. In 1997, wholesale trading revenues increased 93% and energy volume sold increased 99% over the prior year, accounting for 56% of total energy sales and 39% of total energy revenues. In addition to its base of thermal and hydroelectric resources, 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 when prices are favorable. Firm power purchases supplied 37% of the Company's total energy requirements in 1997. Nonfirm purchases supplied 13% of total energy requirements in 1997. PROPOSED ASSET ADDITIONS In accordance with the Company's long-range integrated resource planning process, also referred to as "least-cost planning," the Company considers various future demand and supply options for providing customers with reliable, low-cost energy services. See "Projected Demand." In this connection, the Company also seeks opportunities to acquire existing assets from other utilities. The Company plans to participate in a wind generation project in Wyoming. In May 1996, Kenetech Windpower, the original contractor, filed for bankruptcy. Its rights were assigned to SeaWest Energy in December 1996. The Company plans to own about 32 MW of the project, which is expected to be completed within two years. PROJECTED DEMAND Annual increases in retail kilowatt-hour sales for the Company have averaged 2.1% since 1992. Although the sale of the Sandpoint, Idaho properties and the closure of oil and gas wells in Wyoming have negatively impacted retail sales, the Company has benefited from improved economic conditions in portions of its service territory and the Company's commitment to price stability. Price reductions in many of the Company's service territories have helped sustain sales volume growth. For the period 1998 to 2001, the average annual growth in retail kilowatt-hour sales in the Company's franchised service territory is estimated to be about 2.5%. During this period, the Company may lose energy sales to other suppliers in connection with direct access pilot studies. As the electric industry deregulates, the Company expects to have opportunities to gain market share in areas outside its franchised service territory. Actual results will be determined by a variety of factors, including deregulation in the electric industry, economic and demographic growth, competition and the effectiveness of energy efficiency programs. The Company's base of existing resources, in combination with actions outlined in its integrated resource plan, are expected to be sufficient to meet load growth conditions through 2002. Actions outlined in the integrated resource plan include energy efficiency by customers (demand-side management), efficiency improvements to existing generation, transmission and distribution systems, and investments in cogeneration, single cycle and combined cycle combustion turbines and in renewable resources. See "Proposed Asset Additions." Demand-side management is an element of the Company's diversified portfolio of resources identified in its integrated plan. The use of an energy service charge concept in the Company's demand-side resource programs is intended to allow these resources to be acquired at competitive costs. Under the energy service charge program, the customers receiving the benefits of energy efficiency measures are expected to pay most of the related costs. The Company expended an aggregate of $6 million for demand-side resources in 1997, while acquiring 17.3 average MW of energy efficiency. 9 ENVIRONMENT 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 impact, if any, changes in environmental laws and regulations may have on the Company's future operations and capital expenditure requirements. 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 (SO(2)), nitrogen oxides (NO(x)), particulate matter (currently PM(10)) and opacity. In addition, regional visibility requirements impact the coal-burning plants. Although not presently regulated, emissions of carbon dioxide (CO(2)) and mercury from coal-burning facilities generally are of increasing public concern. Emission controls, low sulfur coal, plant operating practices and continuous emissions monitoring all are utilized to enable coal-burning plants to comply with opacity, visibility and other air quality require- ments. All of the Company's coal-burning plants burn low sulfur coal and are equipped with controls to limit emissions of particulate matter. The majority of the Company's coal-burning plants representing the majority of its installed capacity have been equipped with controls which limit the amount of SO(2) emissions. The SO(2) 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 requirements and expansion plans. In addition, the Company has taken advantage of opportunities to sell surplus allowances to other entities. The Company recorded sales of surplus SO(2) allowances of $21 million in 1997 and $6 million in 1996. The Company did not sell any surplus NO(x) emissions credits in 1997. The Company may have approximately 20,000 to 25,000 tons of surplus SO(2) emission allowances available for sale each year until 2025. The Company has more than 800 tons of surplus NO(x) emissions credits that originated from the retirement of the Hale generating station and emission reductions at the Gadsby thermal generating plant in the state of Utah. Various federal and state agencies, as well as private 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, including the Grand Canyon Visibility Transport Commission study, have been completed or are in the process of completion near Company plants in Colorado, Utah, Washington and Wyoming. To date, no additional emission control requirements 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 any one of the Company's coal-burning plants. During 1997, the EPA also proposed new regulations addressing regional haze. These proposed regulations have the potential to impose significant new control requirements on certain coal-burning plants that are not otherwise subject to strict SO(2) emission limits. CO(2) 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 CO(2). 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 CO(2)). The Kyoto Protocol, if ultimately ratified, has the potential to impose significant new control and operational requirements on the Company's coal-burning plants. The Company voluntarily joined with a group of 44 other investor-owned utilities to sign an agreement with the U.S. Department of Energy addressing CO(2) emissions. Under the agreement, the Company committed to reduce its overall CO(2) emission rate by 10% between 1990 and 2000 and also agreed to spend $1 million on CO(2) offset projects. 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 10 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." The Company-operated Centralia plant, in which the Company owns a 47.5% interest, has been the subject of a series of lawsuits and agency actions regarding emissions and visibility issues. In February 1998, the Southwest Air Pollution Control Authority ("SWAPCA") issued a revised order requiring the plant to meet new SO(2), NO(x), particulate matter and carbon monoxide emission limits. These new limits resulted from the application of the Reasonably Available Control Technology process as mandated by SWAPCA and Washington state air quality requirements. The new emission limits will require the plant to install two scrubbers and low NO(x) burners at a projected cost of $240 million. A private citizen has appealed the SWAPCA decision asserting that it is not stringent enough. It is not known at this time whether the appeal process will impact the schedule or budget for implementing the SWAPCA order. In addition, the Northwest Environmental Advocates, an environmental citizen group, filed a federal lawsuit against SWAPCA, the state of Washington and EPA alleging failure to enforce visibility requirements throughout Washington, including requirements relating to the Centralia plant. Portions of that suit relating to the Centralia plant appear to be resolved, but a final settlement has not been reached. ELECTROMAGNETIC FIELDS. A number of studies have examined 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 has adopted formal rules or programs with respect to EMF or EMF considerations in the siting of electric facilities. In California, the Public Utilities Commission has issued an interim order requiring utilities to implement no cost or low-cost mitigation steps in the design of the new facilities. The Company expects that public concerns about EMF will continue to be an issue in the siting and construction of power lines and substations in the future. 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 transmission and distribution facilities, as well as generating plants. In addition, endangered species issues impact the relicensing of existing hydroelectric generating projects and generally raise the price the Company must pay to purchase wholesale power from hydroelectric facilities owned by others and increase the costs of operating the Company's own hydroelectric resources. ENVIRONMENTAL CLEANUPS. Under the federal Comprehensive Environmental Response, Compensation and Liability Act and comparable 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, PCBs 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 statements. WATER QUALITY. The federal Clean Water Act and individual state clean water regulations require a permit for the discharge of pollutants, 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. 11 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. 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. Prices charged to retail customers are subject to regulation in each of the states the Company serves. Interstate sales of electricity at wholesale prices and interstate wheeling rates are regulated by the FERC. Except in Montana, where the commission is elected, commissioners are appointed by the individual state's governor for varying terms. While regulation varies from state to state, industry analysts consider the overall quality of the regulatory commissions having jurisdiction over the Company to be about average in their treatment of the rate applications of utilities. The Company is currently in the process of relicensing or preparing to relicense 15 separate hydroelectric projects under the Federal Power Act. These projects, some of which are grouped together under a single license, represent 995 MW, or about 93% of the Company's total hydroelectric capacity and about 11% 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 "Environment--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 relicenses for certain projects if the terms of renewal would make the projects uneconomical to operate. A summary of regulatory and legislative developments in the states where the Company conducts its retail electric operations is set forth below. UTAH. On February 12, 1997, the Division of Public Utilities ("DPU") and Committee of Consumer Services ("CCS") in Utah filed a joint petition with the Utah Public Service Commission ("PSC") requesting the PSC to commence proceedings to establish new rates for Utah customers. The petitioners requested an immediate hearing on a $12 million interim rate reduction and a subsequent general rate case, which the petitioners alleged could result in rates being reduced by as much as $54 million annually. On March 4, 1997, the Utah Legislature passed a bill creating a legislative task force to study restructuring issues, including stranded costs and the timing of customer choice. The bill froze rates at January 31, 1997 levels until 60 days following the conclusion of the 1998 legislative general session (approximately May 5, 1998). The PSC is precluded from holding any hearings on rate changes during the freeze period. The Company reduced prices to Utah customers by $12 million annually in April 1997. The Task Force held public meetings from May through November of 1997 on investor-owned utilities issues and addressed such topics as market power, market pricing, stranded costs, public purpose programs, tax impacts from restructuring and independent system operators for transmission systems. In November 1997, the Task Force recommended that further study was needed and that no legislation be proposed in the 1998 session for the deregulation of investor-owned utilities. The Task Force also recommended that the price freeze and rate case moratorium be allowed to expire. During 1997, the PSC did proceed with hearings on the proper methodology to be used in allocating costs among the Company's seven jurisdictions in an effort to establish the costs attributable to Utah customers in the rate case when the rate freeze was lifted. The DPU recommended an allocation method that would reduce prices by $56 million over five years, of which $14 million was included in its original estimate of $54 million. During these hearings, the CCS recommended a method that would reduce prices 12 by $96 million, or $42 million more than the original DPU estimate. The Company advocated a method that would result in a decrease of approximately $3 million per year. An order from the PSC is expected in early 1998. An allocation order by itself will not decrease revenues, but will be incorporated into subsequent rate proceedings to determine the overall change in rates for Utah customers. OREGON. Major restructuring legislation in Oregon was discussed but not enacted in 1997. No session will be held in 1998. The Oregon Public Utility Commission ("OPUC") has initiated a generic stranded cost proceeding. The initial phase of the proceeding is expected to result in an order on conceptual stranded cost issues. A subsequent phase is likely to deal with technical issues, such as those related to calculation of stranded costs. In January 1998, the OPUC proposed modifications to the alternative form of regulation ("AFOR") requested by the Company. The AFOR includes provisions allowing rate changes for distribution costs based on changes in the producer price index, less a productivity adjustment. The OPUC proposes to lower the authorized earnings range for return on equity and increase the financial penalties for the Company's failure to meet service quality standards. The Company has filed an acceptance of the OPUC's proposal conditioned on changes to some of the service quality measures and other terms of the proposal. The OPUC has not responded to the Company's conditional acceptance. In January 1998, the Company filed a proposal for a direct access pilot program with the OPUC. The program will allow residential and small commercial customers in Klamath County to select from a portfolio approach for pricing options for electricity. The filing also includes direct access competitive choice options for schools and large industrial customers throughout the state. WYOMING. A committee of the Wyoming senate held hearings on a draft electric restructuring bill. The committee heard public comment representing a variety of interests, including investor owned utilities, cooperatives, organized labor, large customers, small customers, municipalities, and the Public Service Commission, and voted to reject the bill by a nine to five margin. Discussions continue concerning future direction of restructuring legislation in Wyoming. WASHINGTON. Both unbundling and general restructuring legislation was discussed during the 1997 legislative session in Washington but no legislation was enacted. A shortened session is planned for 1998, and no major restructuring legislation is anticipated. The Washington Utility and Transportation Commission has initiated a proceeding to investigate methods for unbundling electric utility costs. The proceeding is similar to the Idaho investigation discussed below. IDAHO. In 1997, Idaho industrial customers proposed a restructuring bill which was not enacted. The Idaho Legislature did pass an unbundling bill which required electric utilities in Idaho to make filings with the Idaho Public Utility Commission ("IPUC") concerning costs of various services. The IPUC is currently conducting unbundling cases for each of the three electric utilities providing services in the state. The scope of this investigation is currently limited to the separation of the cost components of the current bundled tariff that customers pay. Stranded costs and other restructuring issues are not currently being addressed. CALIFORNIA. In 1996, the California Legislature enacted legislation which required direct access by January 1, 1998. Direct access has been delayed, but is expected to occur by the end of March 1998. Under the new law, utilities may collect generation asset related stranded costs during the transition period ending in 2001 and certain costs, such as costs of above market contracts with qualified facilities ("QFs"), over the life of the contract. Utilities requesting recovery of generation related stranded costs have been required to reduce residential and small commercial rates by 10%. In December 1997, the California Public Utilities Commission issued an order with respect to the Company's proposed transition filing. The order mandates a 10% rate reduction effective January 1, 1998, which would result in a $3.5 million annual reduction in revenues. The Company has filed for a rehearing on this issue. 13 MONTANA. The Montana Legislature enacted a law mandating direct access for large customers by July 1, 1998 and all customers by July 1, 2002. Stranded costs relating to generation assets are limited to the level occurring during the transition period, July 1, 1998 through June 30, 2002. The Company has requested that regulatory assets and above market QF contracts be collected over their normal lives. The Montana Public Service Commission is expected to issue an order on the Company's proposal later in 1998. CONSTRUCTION PROGRAM The following table shows actual construction costs for 1997 and the Company's estimated construction costs for 1998 through 2000, including costs of acquiring demand-side resources. The estimates of construction costs for 1998 through 2000 are subject to continuing review and appropriate revision by the Company. These estimates do not include expected expenditures for purchases of generating assets. See "Proposed Asset Additions" for information concerning proposed additions to the Company's generating assets.
ESTIMATED ------------------------------- TYPE OF FACILITY ACTUAL 1997 1998 1999 2000 - -------------------------------------------------------------- ----------- --------- --------- --------- (DOLLARS IN MILLIONS) Production.................................................... $ 98 $ 130 $ 130 $ 130 Transmission.................................................. 42 35 35 35 Distribution.................................................. 231 160 160 160 Mining........................................................ 25 35 25 25 Other......................................................... 94 145 130 115 ----- --------- --------- --------- Total....................................................... $ 490 $ 505 $ 480 $ 465 ----- --------- --------- --------- ----- --------- --------- ---------
AUSTRALIAN ELECTRIC OPERATIONS POWERCOR GENERAL On December 12, 1995, Holdings completed the acquisition of Powercor from the State of Victoria for approximately $1.6 billion in cash. The acquisition was structured through a series of wholly owned United States and Australian companies. Powercor is the largest electricity distribution company ("Distribution Company") in Victoria 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 550,000 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 and New South Wales. Powercor's distribution service area, the largest distribution service area in Victoria, covers approximately 57,915 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 1996, Victoria accounted for approximately 25% of Australia's total population, approximately 35% 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. 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 14 ("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 1997, the Distribution Business generated 89% 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 number of Powercor's distribution customers and volumes of electricity distributed by Powercor at the dates and for the periods presented.
NUMBER OF DISTRIBUTION BUSINESS AT DECEMBER 31, AT DECEMBER 31, CUSTOMERS CONNECTED 1996 1997 - ------------------------------------------------------------ --------------- --------------- Residential................................................. 453,978 459,780 Commercial.................................................. 48,170 48,646 Industrial.................................................. 8,368 9,182 Other....................................................... 35,899 34,315 ------- ------- Total....................................................... 546,415 551,923 ------- ------- ------- -------
YEAR ENDED YEAR ENDED ELECTRICITY DISTRIBUTED BY THE DECEMBER 31, DECEMBER 31, DISTRIBUTION BUSINESS (GWH) 1996 1997 - ----------------------------------------------------------------- --------------- --------------- Residential...................................................... 2,608 2,679 Commercial....................................................... 1,411 1,550 Industrial....................................................... 2,995 3,273 Other............................................................ 510 537 ----- ----- Total............................................................ 7,524 8,038 ----- ----- ----- -----
Under its distribution license, Powercor's revenues from the Distribution Business consist of the following elements: (i) network tariffs, which include distribution use-of-system costs, use of transmission system fees and connection service charges; (ii) charges for connecting distribution customers to the network, excluding the portion of connection costs recovered through network tariffs; and (iii) fair and reasonable charges for other services. The level of network tariffs is regulated under the Tariff Order (as defined below) through December 31, 2000 pursuant to a price-cap regime that attempts to ensure that the weighted average of distribution charges for each year, within the respective distribution categories, does not exceed the average of the previous year's base prices for each distribution category weighted by the forecasted quantity of electricity to be delivered adjusted for inflation using a consumer-price index formula and for under or over-recovery in previous financial years. After December 31, 2000, the Tariff Order provides that the Office of the Regulator General ("ORG") will regulate the level of network tariffs in a manner that provides Powercor with incentives to increase the volume of electricity distributed and to operate the distribution network efficiently by making appropriate capital and maintenance expenditures. 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 their introduction. 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, 1997, Powercor had not lost any distribution revenues to customers as a result of self-generation, co-generation or the establishment of private distribution networks. Although Powercor believes that it has effective strategies in place to minimize this type of loss of load, there can be no 15 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, are payable to the Victorian Power Exchange ("VPX"), a corporate body established under Victoria's Electricity Industry Act 1993 ("Electricity Act"), and the company that owns and maintains the Grid, Power Net Victoria ("PNV"), respectively, and constitute the VPX's and PNV'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 an 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 ORG's review of distribution tariffs charged by Distribution Companies beginning in 2001, as described under "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. Powercor has an exclusive license to sell electricity to customers with a demand of 750 megawatt-hours ("mWh") per year or less. Powercor has nonexclusive licenses to sell electricity to customers with usage in excess of 750 mWh per year or more in its distribution service area and elsewhere in Victoria, New South Wales and Queensland. Customers with usage of 750 mWh per year or less will incrementally become contestable over the period ending December 31, 2000 in Victoria and Queensland and over the period ended June 30, 1999 in New South Wales depending on their energy usage. In 1997, the Supply Business generated 4% of the Company's operating income. The customer metered sites energy usage and percentages of Powercor's revenues from the Supply Business for franchise customers in Powercor's distribution service area and for contestable customers in Victoria and New South Wales for the year ended December 31, 1997 are set forth below:
CUSTOMER SITES ENERGY USAGE REVENUES -------------------- -------------------- ------------- CUSTOMER SEGMENT NO. % GWH % % - ----------------------------------------------- --------- --------- --------- --- ------------- Franchise Customers............................ 552,959 99.7 4,696 43 62 Contestable Customers.......................... 1,931 0.3 6,348 57 38 --------- --------- --------- --- --- Total.......................................... 554,890 100.0 11,044 100 100 --------- --------- --------- --- --- --------- --------- --------- --- ---
16 The customer metered sites, energy usage and percentages of Powercor's revenues from the Supply Business for residential, commercial, industrial and other customers for the years ended December 31, 1996 and 1997 are set forth below:
CUSTOMER SITES(1) ENERGY USAGE(2) REVENUES(2) -------------------- -------------------- ------------- CUSTOMER CLASS NO. % GWH % % - ------------------------------------------- --------- --------- --------- --------- ------------- Residential Customers December 31, 1996........................ 453,978 83.0 2,608 31.4 38.1 December 31, 1997........................ 459,780 82.8 2,683 24.3 35.0 Commercial Customers December 31, 1996........................ 48,598 8.9 1,926 23.2 26.3 December 31, 1997........................ 49,821 9.0 3,082 27.9 30.4 Industrial Customers December 31, 1996........................ 8,422 1.5 3,282 39.5 28.5 December 31, 1997........................ 9,440 1.7 4,755 43.1 28.1 Other Customers(3) December 31, 1996........................ 35,816 6.6 494 5.9 7.1 December 31, 1997........................ 35,849 6.5 524 4.7 6.5 Total Customers December 31, 1996........................ 546,814 100.0 8,310 100.0 100.0 December 31, 1997........................ 554,890 100.0 11,044 100.0 100.0
- ------------------------ (1) Connection as of the date shown. (2) For the year ended at the date shown. (3) Other customers include farm customers and public lighting and traction customers. Powercor's residential customers accounted for 83% of the total customer sites at December 31, 1997 and 35% of total electricity revenue. Commercial and industrial customers accounted for 30% and 28%, respectively, of revenues in 1997. Electricity 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 2% of Powercor's total revenues in 1997. Powercor purchases all of its power for sale to franchise customers, other than co-generation output, through the competitive wholesale market for electricity in Victoria ("Pool"). 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. 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 from July 1, 1995 to 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. 17 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 an 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. REGULATION THE ORG. In July 1994, 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 Electricity Act. The ORG's functions pursuant to the Electricity Act include granting licenses to generate, transmit, distribute or supply electricity, ensuring compliance with industry codes and Pool rules, administering cross-ownership provisions and administering the Tariff Order. LICENSES. Unless covered by an exemption, the Electricity Act 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 Pool rules. Powercor has an exclusive license to distribute electricity in its distribution service area in Victoria and licenses to supply electricity to all customers in its distribution service area and elsewhere in Victoria, New South Wales and Queensland. See "Supply Business." The Hazelwood Partnership has a license to generate and sell electricity into the wholesale market in Victoria and New South Wales. See "Hazelwood" below. THE TARIFF ORDER. Pursuant to the Electricity Act, the Victorian Electricity Supply Industry Tariff Order (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 designed to provide a level of stability and continuity in tariff regulation. 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 PNV's 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 an incentive-based CPI-X formula, which attempts to ensure that the weighted average of distribution charges for each year, within the respective distribution categories, does not exceed the average of the previous year's base prices for each distribution category weighted by the forecast quantity of electricity to be delivered and adjusted for inflation using a consumer-price index formula and for under and over-recovery in previous financial years. Subsequent to the year 2000, existing network tariffs will be 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 CPI-X price capping and not rate of return regulation and the ORG must consider the need to (x) provide each Distribution Company with incentives to operate efficiently, (y) ensure a fair sharing of benefits achieved through efficiency between customers 18 and Distribution Companies and (z) ensure appropriate incentives for capital expenditures and maintenance of the distribution networks. 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 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 tariffs are adjusted annually by a percentage equal to the movement in Consumer Price Index (All Groups) for Melbourne ("CPI") minus a fixed percentage described in the table below.
LARGE/MEDIUM MEDIUM/SMALL RESIDENTIAL/RURAL YEAR COMMENCING BUSINESSES BUSINESSES CUSTOMERS - ------------------------------------------------------------- ----------------- ----------------- ----------------- July 1, 1997................................................. CPI CPI minus 5% CPI minus 1% July 1, 1998................................................. CPI CPI minus 1% CPI minus 1% July 1, 1999................................................. CPI CPI minus 1% CPI minus 1% July 1, 2000................................................. CPI CPI minus 1% CPI minus 1%
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. The retail contestability timetables for Victoria, New South Wales and Queensland are outlined below.
SITE THRESHOLD VICTORIA NEW SOUTH WALES QUEENSLAND - --------------------------------------------- ---------------------- ---------------------- ----------------- In excess of 750 MWh/yr...................... Already contestable Already contestable -- In excess of 160 Mwh/yr...................... July 1, 1998 July 1, 1998 January 1, 1999 160 Mwh/yr or less........................... January 1, 2001 July 1, 1999 January 1, 2001
PROPERTIES Powercor's electrical distribution network comprises: (i) 66 kilovolts ("kV") and 22 kV subtransmission lines and underground subtransmission cables that transport wholesale energy from 11 terminal stations owned by Power Net Victoria and controlled, under lease, by VPX; (ii) 51 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 V and below) suitable for connection to the majority of the customers. In addition, Powercor leases its principal executive offices at Level 3, 177 Southbank Boulevard Southbank in Victoria under a five-year lease with an option to renew for another five years. 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. 19 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 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 In September 1996, the Hazelwood Power Partnership (the "Hazelwood Partnership") purchased 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 an affiliate of National Power Corporation PLC ("National Power") (71.94%), Hazelwood Pacific Pty Ltd, an indirect subsidiary of Holdings (19.9%, the maximum allowable under current Victorian law) ("Hazelwood Pacific"), 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. With its 19.9% interest in the Hazelwood Partnership (the "Hazelwood Investment"), Australian Electric Operations has a partial strategic hedge in the event that electricity prices rise in the national market. The Hazelwood Partnership financed the acquisition of the Hazelwood Plant and the Hazelwood Mine with approximately $858 million in equity contributions from its partners (including a $157 million contribution for Hazelwood Pacific). Through the year 2000 the investment is expected to contribute only modestly to the Company's net income. Through March 2000, Hazelwood Pacific estimates that its contribution to the capital expenditure commitments of the Hazelwood Plant will range between $6 million and $15 million per annum. The investment is accounted for on an equity basis. Hazelwood Partnership sells its power through a statewide generation pool 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. 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. Six of the Hazelwood Plant's eight generating units underwent major refurbishment or plant life extension projects between 1983 and 1993. Unit 8 returned to service on December 5, 1997 and Unit 7 was returned to service in January 1998. 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 for the 40 years of anticipated plant operation. 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, which licenses are generally issued to the Hazelwood Partnership in the ordinary course and are terminable upon the breach or violation thereof. 20 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 that would permit it to increase such emissions by up to 8% over 1990 emissions levels by 2012. 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. UNREGULATED ENERGY TRADING The Company's Unregulated Energy Trading business became a reportable segment in 1997 with the significant expansion of electric power and natural gas marketing revenues. The segment includes PPM, a wholesale power trading company currently focusing in the Eastern United States, and TPC, a natural gas marketing and storage company acquired by Holdings in April 1997. PPM's initial market has been wholesale entities but it intends to expand into the contestable retail sector as deregulation occurs. The TPC acquisition adds natural gas trading to Holdings' growing energy marketing business in the Eastern United States. Along with its natural gas trading business, TPC integrates its natural gas storage facilities in certain arrangements with natural gas distribution companies. In November 1997, TPC sold its nonstrategic natural gas, gathering and processing systems because they were believed not to be essential to the further growth of its energy marketing and trading business. TPC's gas marketing and Market Hub Partners salt-dome storage operations, headquartered in Houston, have been retained. OTHER OPERATIONS PACIFICORP FINANCIAL SERVICES PFS is a holding company with two principal business segments, Financial Services and Tax-Advantaged Investments. PFS presently expects to retain only its tax-advantaged investments in leveraged lease assets (primarily aircraft). FINANCIAL SERVICES PFS made its last investment in aircraft or loans relating to aircraft in 1992. At December 31, 1997, approximately 90% of aircraft in PFS's portfolio investment were Stage III noise compliant. At December 31, 1997, PFS's Aviation Finance portfolio had total leveraged lease and other financial assets of $323 million (32 aircraft), representing approximately 46% of PFS's consolidated assets. Other financial services activities include centralized credit administration and asset management and tax-advantaged investments in affordable housing. Although no longer originating new business, PFS continues to manage its remaining lending portfolio and other assets. At December 31, 1997, these assets totaled $376 million, or approximately 54% of PFS's consolidated assets. In February 1998, PFS agreed to sell substantially all its real estate assets. TAX-ADVANTAGED INVESTMENTS PFS has entered into a letter of intent with Covol Technologies, Inc. ("Covol") for construction of a plant in the Birmingham, Alabama area to produce a synthetic coal fuel qualifying for tax credits under Section 29 of the Internal Revenue Code ("IRC"). PFS will fund the construction costs and a subsidiary of PFS will purchase the plant upon completion. Another PFS subsidiary, PacifiCorp Syn Fuel ("Syn Fuel"), has entered into a licensing agreement with Covol for up to three additional plants. Syn Fuel is pursuing development of these plants and has entered into construction contracts for these facilities. 21 PFS's participation in the alternative fuels tax credit market is limited by the IRC requirement that qualified facilities must be built in accordance with binding construction contracts entered into on or before December 31, 1996, and in service by June 30, 1998. INTERNATIONAL OPERATIONS Through its subsidiaries, Holdings is engaged in the acquisition or development of electrical power projects or systems internationally. Through its subsidiary PacifiCorp Philippines Development Corporation, Holdings has a 33% interest in the 75 MW Bakun hydroelectric project. Construction of the project began in 1997, and the project is expected to be in commercial operation in 2000. Holdings is participating in consortia negotiating with the Turkish government for operating rights for power projects tendered in 1997 by the government. PACIFIC GENERATION COMPANY PGC acquired, developed and operated independent power production and cogeneration facilities, principally in the United States. On November 5, 1997, Holdings completed the sale of PGC's assets for $151 million in cash. DISCONTINUED OPERATIONS PTI provided local telephone service and access to the long distance network in Alaska, seven other western states and three midwestern states. PTI also operated and managed cellular mobile telephone services in six states and was involved in the operation and maintenance of and sale of capacity in a submarine fiber optic cable between the United States and Japan. In December 1997, Holdings completed the sale of its ownership interest in PTI for $1.5 billion in cash. This business has been reported as a discontinued operation. EMPLOYEES PacifiCorp and its subsidiaries had 10,087 employees on December 31, 1997. Of these employees, 8,732 were employed by PacifiCorp and its mining affiliates, 1,122 were employed by Powercor and 233 were employed by PPM, TPC, PFS and other subsidiaries. Approximately 61% 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. Approximately 74% of Powercor's employees are represented by various unions in Australia, including the Australia Services Union and the Electrical Trades Union. In the Company's judgment, employee relations are satisfactory. ITEM 2. PROPERTIES The Company owns 52 hydroelectric generating plants and has an interest in one additional plant, with an aggregate nameplate rating of 1,078.1 MW and plant net capability of 1,138.6 MW. It also owns or has interests in 17 thermal-electric generating plants with an aggregate nameplate rating of 7,620.5 MW 22 and plant capability of 7,143.6 MW. The following table summarizes the Company's existing generating facilities:
PLANT NET INSTALLATION NAMEPLATE CAPABILITY LOCATION ENERGY SOURCE DATES RATING (MW) (MW) -------------------- ---------------- ----------- ------------ ----------- HYDROELECTRIC PLANTS Swift....................................... Cougar, Washington Lewis River 1958 240.0 265.6 Merwin...................................... Ariel, Washington Lewis River 1931-1958 136.0 144.0 Yale........................................ Amboy, Washington Lewis River 1953 134.0 134.0 Five North Umpqua Plants.................... Toketee Falls, N. Umpqua River 1950-1956 133.5 138.5 Oregon John C. Boyle............................... Keno, Oregon Klamath River 1958 80.0 90.0 Copco Nos. 1 and 2 Plants................... Hornbrook, Klamath River 1918-1925 47.0 54.5 California Clearwater Nos. 1 and 2 Plants.............. Toketee Falls, Clearwater River 1953 41.0 41.0 Oregon Grace....................................... Grace, Idaho Bear River 1914-1923 33.0 33.0 Prospect No. 2.............................. Prospect, Oregon Rogue River 1928 32.0 34.0 Cutler...................................... Collinston, Utah Bear River 1927 30.0 29.1 Oneida...................................... Preston, Idaho Bear River 1915-1920 30.0 28.0 Iron Gate................................... Hornbrook, Klamath River 1962 18.0 20.0 California Soda........................................ Soda Springs, Idaho Bear River 1924 14.0 14.0 Fish Creek.................................. Toketee Falls, Fish Creek 1952 11.0 12.0 Oregon 33 Minor Hydroelectric Plants............... Various Various 1896-1990 98.6* 100.9* ------------ ----------- Subtotal (53 Hydroelectric Plants)........ 1,078.1 1,138.6 THERMAL ELECTRIC PLANTS Jim Bridger................................. Rock Springs, Coal-Fired 1974-1979 1,495.0* 1,386.7* Wyoming Huntington.................................. Huntington, Utah Coal-Fired 1974-1977 892.8 845.0 Dave Johnston............................... Glenrock, Wyoming Coal-Fired 1959-1972 816.7 772.0 Naughton.................................... Kemmerer, Wyoming Coal-Fired 1963-1971 707.2 700.0 Centralia................................... Centralia, Coal-Fired 1972 693.5* 636.5* Washington Hunter 1 and 2.............................. Castle Dale, Utah Coal-Fired 1978-1980 687.7* 639.4* Hunter 3.................................... Castle Dale, Utah Coal-Fired 1983 446.4 395.0 Cholla Unit 4............................... Joseph City, Arizona Coal-Fired 1981 414.0 380.0 Wyodak...................................... Gillette, Wyoming Coal-Fired 1978 289.7* 268.0* Gadsby...................................... Salt Lake City, Utah Gas-Fired 1951-1955 251.6 235.0 Carbon...................................... Castle Gate, Utah Coal-Fired 1954-1957 188.6 175.0 Craig 1 and 2............................... Craig, Colorado Coal-Fired 1979-1980 172.1* 165.0* Colstrip 3 and 4............................ Colstrip, Montana Coal-Fired 1984-1986 155.6* 144.0* Hayden 1 and 2.............................. Hayden, Colorado Coal-Fired 1965-1976 81.3* 78.0* Blundell.................................... Milford, Utah Geothermal 1984 26.1 23.0 Little Mountain............................. Ogden, Utah Gas Turbine 1971 16.0 14.0 Hermiston................................... Hermiston, Oregon Combined Cycle 1996 234.0* 234.0* James River................................. Camas, Washington Black Liquor 1996 52.2 53.0 ------------ ----------- Subtotal (17 Thermal Electric Plants)..... 7,620.5 7,143.6 ------------ ----------- Total Hydro and Thermal Generating Facilities (70)......................... 8,698.6 8,282.2 ------------ ----------- ------------ -----------
- ------------------------------ *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 23 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 others. 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 December 31, 1997. 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 reserves assigned to the Centralia, 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 1997, for their current economically useful lives. The sulfur content of the reserves ranges from 0.43% to 0.84% and the BTU value per pound of the reserves ranges from 7,600 to 11,400. 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.
RECOVERABLE TONS (IN LOCATION PLANT SERVED MILLIONS) - --------------------------------------------------------------- -------------------------- ----------------------- Centralia, Washington.......................................... Centralia 46(1) Craig, Colorado................................................ Craig 70(2) Glenrock, Wyoming.............................................. Dave Johnston 7(1)(5) Emery County, Utah............................................. Huntington and Hunter 87(1)(3) Rock Springs, Wyoming.......................................... Jim Bridger 125(4)
- ------------------------ (1) These reserves are mined by subsidiaries of the Company. (2) These 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 reserves are in underground mines. (4) These 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 expects to cease mining operations at this location in 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 1997, the Company expended $3 million of reclamation costs and accrued $38 million of estimated final mining reclamation costs. Final mine reclamation funds have been established with respect to certain of the Company's mining properties. At December 31, 1997, the Company's pro rata portion of these reclamation funds totaled $43 million and the Company had an accrued reclamation liability of $159 million at December 31, 1997. For a description of Powercor's properties, see "Item 1. Business--Australian Electric Operations-- Properties" above. 24 ITEM 3. LEGAL PROCEEDINGS The Company and its subsidiaries are parties to various legal claims, actions and complaints, certain 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 statements. On March 1, 1996, a purported class action was filed against PacifiCorp alleging negligence, nuisance and trespass by PacifiCorp as a result of the operation of three dams on the Lewis River in the State of Washington during the floods of February 1996 (LARRY AND BARBARA RAINEY, ET AL. V. PACIFICORP, Case No. 96-2-00977-0, Superior Court of Washington for Clark County). Plaintiffs request an unspecified amount of damages on behalf of the alleged class, estimated by plaintiffs to have over 500 members, for injury to their property, diminution of value of the related real estate and improvements, and consequential damages in the form of lost income to businesses operating in the flooded areas. The complaint also seeks injunctive relief compelling PacifiCorp to establish additional warning systems downstream from the dams. PacifiCorp believes that it operated the dams in an appropriate manner. Plaintiff's motion for class certification was denied by the court on July 1, 1997. On March 15, 1996, Utah Associated Municipal Power Systems ("UAMPS") filed an action against PacifiCorp asserting 10 different causes of action, all relating to the ownership interest of UAMPS in the Hunter Steam Electric Generating Unit No. II ("Hunter II") in Emery County, Utah, which is operated by PacifiCorp. (UTAH ASSOCIATED MUNICIPAL POWER SYSTEMS V. PACIFICORP, Civil No. 2:96CV 0240B, U.S. District Court for the District of Utah, Central Division). The complaint alleges, among other things, an illegal tying arrangement in the supply of coal by PacifiCorp to Hunter II, violations of various federal and state antitrust laws, breach of contract and breach of a duty of good faith and fair dealing. The complaint seeks damages in excess of $1,000,000 with respect to each of several of the causes of action and certain declaratory rulings. On April 2, 1996, the Utah Municipal Power Agency and Provo City, Utah served an action against PacifiCorp asserting 13 different causes of action, all relating to the plaintiffs' ownership interest in the Hunter Steam Electric Generating Unit I ("Hunter I") in Emery County, Utah, which is operated by PacifiCorp. (UTAH MUNICIPAL POWER AGENCY AND PROVO CITY, UTAH V. PACIFICORP, Civil No. 2:96CV 0290C, US District Court for the District of Utah, Central Division). The complaint alleged, among other things, an illegal tying arrangement in the supply of coal by PacifiCorp to Hunter I, violations of various federal and state antitrust laws, breach of contract, breach of fiduciary duties and breach of a duty of good faith and fair dealing. The complaint sought damages in amounts to be proven at trial, trebled in the case of the antitrust claims, and certain declaratory rulings. In late 1997, the Company settled the case. 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 percent 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 25 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. A trial date has not yet been set. The Company is unable to predict the level of penalties or other remedies that may be imposed upon the joint owners of the Station or what portion of such liability may ultimately be borne by the Company. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS No information is required to be reported pursuant to this item. ITEM 4A. EXECUTIVE OFFICERS OF THE REGISTRANT The following is a list of all executive officers of the Company. There are no family relationships among the executive officers. Officers are normally elected annually. FREDERICK W. BUCKMAN, BORN MARCH 9, 1946, PRESIDENT AND CHIEF EXECUTIVE OFFICER OF THE COMPANY Mr. Buckman was elected President and Chief Executive Officer of the Company effective February 1, 1994 and became a director of the Company and Holdings in February 1994. He formerly served as President and Chief Executive Officer of Consumers Power Company, Jackson, Michigan, from 1992 to 1994. WILLIAM C. BRAUER, BORN JANUARY 11, 1939, SENIOR VICE PRESIDENT OF THE COMPANY Mr. Brauer was elected Senior Vice President of the Company in May 1996. He served as Vice President from 1992 to 1996 and as Senior Vice President of Electric Operations from 1991 to 1992. JOHN A. BOHLING, BORN JUNE 23, 1943, SENIOR VICE PRESIDENT OF THE COMPANY Mr. Bohling was elected Senior Vice President of the Company in February 1993. He served as Executive Vice President of Pacific Power from September 1991 to February 1993 and as Senior Vice President of Utah Power from February 1990 to September 1991. SHELLEY R. FAIGLE, BORN JUNE 8, 1951, SENIOR VICE PRESIDENT OF THE COMPANY Ms. Faigle was elected Senior Vice President of the Company in November 1993. She served as Vice President from February 1992 to November 1993 and as Vice President of Pacific Power from 1989 to February 1992. PAUL G. LORENZINI, BORN APRIL 16, 1942, SENIOR VICE PRESIDENT OF THE COMPANY Mr. Lorenzini was elected Senior Vice President of the Company in May 1994. He served as President of Pacific Power from January 1992 to May 1994 and as Executive Vice President from January 1989 to January 1992. RICHARD T. O'BRIEN, BORN MARCH 20, 1954, SENIOR VICE PRESIDENT AND CHIEF FINANCIAL OFFICER OF THE COMPANY AND PRESIDENT AND CHIEF EXECUTIVE OFFICER OF HOLDINGS Mr. O'Brien was elected President and Chief Executive Officer of Holdings in January 1998 and Senior Vice President and Chief Financial Officer of the Company in August 1995. He served as Senior Vice President of Holdings from February 1996 to January 1998. He served as Vice President of the Company from August 1993 to August 1995. He served as Senior Vice President, Treasurer and Chief Financial Officer of NERCO, Inc., a former subsidiary of the Company, during 1992 and 1993 and Vice President and Treasurer of NERCO from 1989 to 1992. 26 DANIEL L. SPALDING, BORN DECEMBER 23, 1953, CHAIRMAN AND CHIEF EXECUTIVE OFFICER OF POWERCOR, SENIOR VICE PRESIDENT OF THE COMPANY Mr. Spalding was elected Chairman and Chief Executive Officer of Powercor in December 1995 and was elected Senior Vice President of the Company in February 1992. He served as Vice President from October 1987 to February 1992. DENNIS P. STEINBERG, BORN DECEMBER 5, 1946, SENIOR VICE PRESIDENT OF THE COMPANY Mr. Steinberg was elected Senior Vice President of the Company in August 1994. He served as Vice President of the Company from February 1992 to August 1994 and as Vice President of Electric Operations from August 1990 to February 1992. VERL R. TOPHAM, BORN AUGUST 25, 1934, SENIOR VICE PRESIDENT AND GENERAL COUNSEL OF THE COMPANY AND OF HOLDINGS Mr. Topham was elected Senior Vice President and General Counsel of Holdings in January 1998, Senior Vice President and General Counsel and a director of the Company in May 1994. He served as President of Utah Power from February 1990 to May 1994. JAMES H. HUESGEN, BORN DECEMBER 26, 1949, VICE PRESIDENT AND CONTROLLER OF THE COMPANY AND CONTROLLER OF HOLDINGS Mr. Huesgen was elected Controller of Holdings in January 1998 and Vice President and Controller of the Company in November 1997. He served as Executive Vice President and Chief Financial Officer of Pacific Telecom, Inc. from February 1989 to November 1997. SALLY A. NOFZIGER, BORN JULY 5, 1936, VICE PRESIDENT AND CORPORATE SECRETARY OF THE COMPANY, SECRETARY OF HOLDINGS AND PACIFICORP FINANCIAL SERVICES, INC. Mrs. Nofziger was elected Vice President of the Company in 1989 and has been Corporate Secretary since 1983. WILLIAM E. PERESSINI, BORN MAY 23, 1956, VICE PRESIDENT AND TREASURER OF THE COMPANY AND TREASURER OF HOLDINGS Mr. Peressini was elected Vice President and Treasurer of the Company in May 1996. He had served as Treasurer since January 1994. He has been Treasurer of Holdings since February 1994 and of Pacific Telecom, Inc. from August 1996 to December 1997. He served as Executive Vice President of PacifiCorp Financial Services, Inc. from January 1992 to January 1994 and as Senior Vice President and Chief Financial Officer of that company from 1989 to January 1992. DONALD A. BLOODWORTH, BORN MAY 9, 1956, VICE PRESIDENT OF THE COMPANY Mr. Bloodworth was elected Vice President of the Company in November 1997. He was employed by AirTouch Cellular from April 1997 to November 1997. He served as Controller of the Company from August 1996 until April 1997. He formerly served as Vice President of Revenue Requirements and Controller for Pacific Telecom, Inc. from May 1993 until August 1996. He was Vice President and Treasurer for PacifiCorp Holdings, Inc. and PacifiCorp Financial Services during 1992 and 1993. THOMAS J. IMESON, BORN MARCH 20, 1950, VICE PRESIDENT OF THE COMPANY Mr. Imeson was elected Vice President of the Company in February 1992. He had served as Vice President of Electric Operations from 1990 to February 1992. 27 MICHAEL J. PITTMAN, BORN MARCH 25, 1953, VICE PRESIDENT OF THE COMPANY Mr. Pittman was elected Vice President of the Company in May 1993. He served as Assistant Vice President from 1990 to 1993. PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS (a). The information required by this item is included under "Quarterly Financial Data" on page 65 of the Company's Annual Report to Shareholders and is incorporated herein by this reference. (b). Not applicable. ITEM 6. SELECTED FINANCIAL DATA The information required by this item is included under Note 16 "Selected Financial and Segment Information" on page 60 of the Company's Annual Report to Shareholders and is incorporated herein by this reference. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The information required by this item is included under "Management's Discussion and Analysis" on pages 25 through 40 of the Company's Annual Report to Shareholders and is incorporated herein by this reference. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The information required by this item is included under "Risk Management," "Interest Rate Exposure," "Currency Rate Exposure" and "Commodity Price Exposure" on pages 39 and 40 of the Company's Annual Report to Shareholders and is incorporated herein by this reference. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The information required by this item is incorporated by this reference from the Company's Annual Report to Shareholders or filed with this Report as listed in Item 14 hereof. 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 information required by this item with respect to the Company's directors is incorporated herein by this reference to "Election of Directors" in the Proxy Statement for the 1998 Annual Meeting of Shareholders. The information required by this item with respect to the Company's executive officers is set forth in Part I of this report under Item 4A. The information required by this item with respect to compliance with Section 16(a) of the Securities Exchange Act of 1934 is incorporated herein by this reference to "Section 16(a) Beneficial Ownership Reporting Compliance" in the Proxy Statement for the 1998 Annual Meeting of Shareholders. 28 ITEM 11. EXECUTIVE COMPENSATION The information required by this item is incorporated herein by this reference to "Executive Compensation" in the Proxy Statement for the 1998 Annual Meeting of Shareholders. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The information required by this item is incorporated herein by this reference to "Security Ownership of Certain Beneficial Owners and Management" in the Proxy Statement for the 1998 Annual Meeting of Shareholders. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS The information required by this item is incorporated herein by this reference to "Director Compensation and Certain Transactions" in the Proxy Statement for the 1998 Annual Meeting of Shareholders. PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
PAGE REFERENCES --------------- (a) 1. Index to Consolidated Financial Statements:* Independent Auditors' Report.............................................................. 41 Statements of consolidated income and retained earnings for each of the three years ended December 31, 1997....................................................................... 42 Statements of consolidated cash flows for each of the three years ended December 31, 1997.................................................................................... 43 Consolidated balance sheets at December 31, 1997 and 1996................................. 44 Notes to consolidated financial statements................................................ 46 2. Schedules:**
- ------------------------ * Page references are to the incorporated portion of the Annual Report to Shareholders of the Registrant for the year ended December 31, 1997. **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 incorporated by reference herein. 3. Exhibits: *(2) -- Stock Purchase Agreement, dated as of June 11, 1997, by and among PacifiCorp Holdings, Inc., Pacific Telecom, Inc., Century Telephone Enterprises, Inc. and Century Cellunet, Inc. (Incorporated by reference to Exhibit 2.1 of Century Telephone Enterprises, Inc.'s Current Report on Form 8-K dated June 11, 1997, File No. 1-7784). *(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 (as restated and amended May 10, 1995) (Exhibit (3)b, Form 10-K for the fiscal year ended December 31, 1995, File No. 1-5152).
29 *(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 twelve Supplemental Indentures (Exhibit 4-E, Form 8-B, File No. 1-5152; Exhibit (4)(b), File No. 33-31861; Exhibit (4)(a), Form 8-K dated January 9, 1990, File No. 1-5152; Exhibit 4(a), Form 8-K dated September 11, 1991, File No. 1-5152; Exhibit 4(a), Form 8-K dated January 7, 1992, File No. 1-5152; Exhibit 4(a), Form 10-Q for the quarter ended March 31, 1992, File No. 1-5152; and Exhibit 4(a), Form 10-Q for the quarter ended September 30, 1992, File No. 1-5152; Exhibit 4(a), Form 8-K dated April 1, 1993, File No. 1-5152; Exhibit 4(a), Form 10-Q for the quarter ended September 30, 1993, File No. 1-5152; Exhibit 4(a), Form 10-Q for the quarter ended June 30, 1994, File No. 1-5152; Exhibit (4)b, Form 10-K for the 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). *(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 -- PacifiCorp Deferred Compensation Payment Plan (Exhibit 10-F, Form 10-K for fiscal year ended December 31, 1992, File No. 1-8749) (Exhibit (10)b, Form 10-K for fiscal year ended December 31, 1994, File No. 1-5152). *+(10)b -- PacifiCorp Compensation Reduction Plan dated December 1, 1994, as amended (Exhibit (10)b, Form 10-K for fiscal year ended December 31, 1994, File No. 1-5152). *+(10)c -- PacifiCorp Executive Incentive Program (Exhibit (10)d, Form 10-K for the fiscal year ended December 31, 1996, File No. 1-5152). *+(10)d -- PacifiCorp Non-Employee Directors' Stock Compensation Plan dated August 1, 1985, as amended (Exhibit (10)f, Form 10-K for fiscal year ended December 31, 1994, File No. 1-5152). *+(10)e -- PacifiCorp Long Term Incentive Plan, 1993 Restatement (Exhibit 10G, Form 10-K for the year ended December 31, 1993, File No. 0-873). *+(10)f -- Form of Restricted Stock Agreement under PacifiCorp Long Term Incentive Plan, 1993 Restatement (Exhibit 10H, Form 10-K for the year ended December 31, 1993, File No. 0-873). +(10)g -- PacifiCorp Supplemental Executive Retirement Plan, as amended. *+(10)h -- Incentive Compensation Agreement dated as of February 1, 1994 between PacifiCorp and Frederick W. Buckman (Exhibit (10)k, Form 10-K for the fiscal year ended December 31, 1993, File No. 1-5152). *+(10)i -- Compensation Agreement dated as of February 9, 1994 between PacifiCorp and Keith R. McKennon (Exhibit (10)m, Form 10-K for the fiscal year ended December 31, 1993, File No. 1-5152). *+(10)j -- Amendment No. 1 to Compensation Agreement between PacifiCorp and Keith R. McKennon dated as of February 9, 1995 (Exhibit (10)r, Form 10-K for the fiscal year ended December 31, 1994, File No. 1-5152). *+(10)k -- PacifiCorp Stock Incentive Plan dated August 14, 1996, as amended (Exhibit (10)n, Form 10-K for the fiscal year ended December 31, 1996, File No. 1-5152).
30 *+(10)l -- Form of Restricted Stock Agreement under PacifiCorp Stock Incentive Plan Exhibit (10)o, Form 10-K for the fiscal year ended December 31, 1996, File No. 1-5152). *+(10)m -- PacifiCorp Executive Severance Plan (Exhibit (10)p, Form 10-K for the fiscal year ended December 31, 1996, File No. 1-5152). *(10)n -- 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)o -- 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). (12)a -- Statements of Computation of Ratio of Earnings to Fixed Charges (See page S-1). (12)b -- Statements of Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends (See page S-2). (13) -- Portions of Annual Report to Shareholders of the Registrant for the year ended December 31, 1997 incorporated by reference herein. (21) -- Subsidiaries (See page S-3). (23) -- Consent of Deloitte & Touche LLP with respect to Annual Report on Form 10-K. (24) -- Powers of Attorney. (27) -- Financial Data Schedule (filed electronically only).
- ------------------------ * Incorporated herein by reference. + This exhibit constitutes a management contract or compensatory plan or arrangement. (b) Reports on Form 8-K. On Form 8-K dated December 1, 1997, under "Item 2. Acquisition or Disposition of Assets," the Company announced the completion of the PTI sale to Century Telephone Enterprises, Inc. On Form 8-K dated December 19, 1997, under "Item 5. Other Events," the Company filed a news release reporting the unconditional approval from the U.K. Government that allowed it to make a new bid for The Energy Group. On Form 8-K dated January 12, 1998, under "Item 5. Other Events," the Company filed a news release announcing a work force reduction, Glenrock mine closure and other charges. On Form 8-K dated January 27, 1998, under "Item 5. Other Events," the Company filed a news release reporting its 1997 financial results. On Form 8-K dated February 3, 1998, under "Item 5. Other Events," the Company filed both a news release and joint announcement relating to its offer to purchase all outstanding shares of The Energy Group. On Form 8-K dated March 3, 1998, under "Item 5. Other Events," the Company filed news releases: (a) reporting the proposed cash offer by a subsidiary of the Company of 820 pence per share for all outstanding shares of The Energy Group ("TEG") and (b) an increased offer of 840 pence per share for all outstanding shares of TEG by Texas Utilities Company. The Company also filed the audited, 1997 consolidated financial statements and related footnotes of PacifiCorp and its subsidiaries. (c) See (a) 3. above. (d) See (a) 2. above. 31 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. PACIFICORP BY /s/ FREDERICK W. BUCKMAN ------------------------------------------ Frederick W. Buckman (PRESIDENT)
Date: March 23, 1998 PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED. SIGNATURE TITLE DATE - ---------------------------- ---------------------------- ------------------- /s/ FREDERICK W. BUCKMAN - ---------------------------- President, Chief Executive Frederick W. Buckman Officer and Director March 23, 1998 (PRESIDENT) /s/ RICHARD T. O'BRIEN Senior Vice President (Chief - ---------------------------- Financial Officer and Richard T. O'Brien Principal Accounting March 23, 1998 (SENIOR VICE PRESIDENT) Officer) *W. CHARLES ARMSTRONG - ---------------------------- W. Charles Armstrong *KATHRYN A. BRAUN - ---------------------------- Kathryn A. Braun Director March 23, 1998 *C. TODD CONOVER - ---------------------------- C. Todd Conover *NOLAN E. KARRAS - ---------------------------- Nolan E. Karras 32 SIGNATURE TITLE DATE - ---------------------------- ---------------------------- ------------------- *KEITH R. MCKENNON - ---------------------------- Keith R. McKennon (CHAIRMAN) *ROBERT G. MILLER - ---------------------------- Robert G. Miller *ALAN K. SIMPSON - ---------------------------- Alan K. Simpson Director March 23, 1998 *VERL R. TOPHAM - ---------------------------- Verl R. Topham *DON M. WHEELER - ---------------------------- Don M. Wheeler *NANCY WILGENBUSCH - ---------------------------- Nancy Wilgenbusch *PETER I. WOLD - ---------------------------- Peter I. Wold *By /s/ NANCY WILGENBUSCH ------------------------- Nancy Wilgenbusch (ATTORNEY-IN-FACT) 33 EX-10.G 2 EXHIBIT 10(G) CONFORMED COPY PACIFICORP SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN 1996 RESTATEMENT January 1, 1996 (As Amended by Amendment No. 4) PacifiCorp an Oregon corporation 700 NE Multnomah Portland, Oregon 97232 Company [LETTERHEAD] TABLE OF CONTENTS
PAGE INDEX OF TERMS iii 1. PURPOSE; EMPLOYERS; ADMINISTRATION 1 1.1 Purpose 1 1.2 Affiliates; Employers 1 1.3 Administration 2 2. PARTICIPATION; SERVICE; FORFEITURE 2 2.1 Eligibility; Participants 2 2.2 Service 3 2.3 Vesting 3 2.4 Misconduct Forfeiture 3 2.5 Change in Control; Employer Disposition 4 2.6 Removal from Active Participation 4 3. PARTICIPANTS' RETIREMENT BENEFITS 5 3.1 Entitlement; Retirement Dates 5 3.2 Normal Retirement Benefit 5 3.3 Actuarial Equivalents 8 3.4 Early Retirement Benefit 8 3.5 Termination Benefit 9 3.6 Time and Manner of Payment 9 3.7 Basic Plan Make-Up 10 4. PRERETIREMENT DEATH BENEFITS 10 4.1 Spouse's Benefit 11 4.2 Dependent Child's Benefit 11 5. DISABILITY 11 5.1 Service Continuation 11 5.2 Benefits 12
i 6. CLAIMS PROCEDURE 12 6.1 Original Claim 12 6.2 Denial 12 6.3 Request for Review 12 6.4 Final Decision 12 7. AMENDMENT; TERMINATION 13 7.1 Amendment 13 7.2 Termination 13 8. GENERAL PROVISIONS 14 8.1 Nonassignability 14 8.2 Funding 14 8.3 Trust 14 8.4 Notices 14 8.5 Attorneys' Fees 14 8.6 Indemnity 14 8.7 Applicable Law 15 8.8 Company Obligation 15 8.9 Payment for Individual's Benefit 15 8.10 Not Contract of Employment 16 9. EFFECTIVE DATE 16
ii INDEX OF TERMS
Section Page Accrued Benefit 3.6 9 Actuarial Equivalent 3.3 8 Basic Plan Preamble 1 Benefit Starting Date 3.7 10 Benefit Year 2.2 3 Board 1.3 2 Career Ratio 3.4(b) 9 Change in Control 2.5 4 Chief Executive Officer 2.1 2 Committee 1.3 2 Earliest Normal Retirement Date 3.5 9 Early Retirement Date 3.1(b) 5 Early Retirement Factor 3.4(c) 9 Final Average Pay 3.2(a) 5 Normal Retirement Benefit 3.2 5 Normal Retirement Date 3.1(a) 5 Other Plan Offset 3.2(d) 7 PacifiCorp Primary Insurance Amount 3.2(c) 7 Participant 2.1 2 Performance Benefit 3.2(b) 6 Projected Short Service Factor 3.4(a) 9 Short Service Factor 3.2(b) 6 Year of Participation 2.2 3 Years of Service 2.2 3
iii PACIFICORP SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN 1996 RESTATEMENT JANUARY 1, 1996 (AS AMENDED BY AMENDMENT NO. 4) PACIFICORP AN OREGON CORPORATION 700 NE MULTNOMAH PORTLAND, OREGON 97232 COMPANY The Company adopted this plan effective January 1, 1988 to providing retirement benefits for its executive employees and those of Company Affiliates that adopt the plan with the approval of the Company. The plan is the successor to several nonqualified supplemental retirement plans maintained by the Company and its Affiliates. The benefits provided by the plan are in addition to those provided by the tax qualified defined benefit plans maintained by the Company and its Affiliates (the Basic Plans). In order to base eligibility for participation on annual salary rate, replace a portion of the benefit formula with a Performance Benefit, provide for earlier vesting and an earlier Early Retirement Date, and eliminate the increase in benefits commencing after earliest normal retirement date, the Company adopts this 1996 Restatement. 1. PURPOSE; EMPLOYERS; ADMINISTRATION 1.1 PURPOSE The purpose of this plan is to provide eligible executive officers of the Company and its Affiliates with additional retirement benefits that will help to attract and retain individuals of very high quality. 1.2 AFFILIATES; EMPLOYERS The plan shall apply to the Company and to Affiliates that adopt the plan for their employees with the approval of the Company. Affiliate means a member, with the Company, of a controlled group or group of trades or businesses under common control under sections 414(b) or (c) of the Internal Revenue Code. The term "Employer" refers to the Company and such an adopting Affiliate. Adoption of the plan by an Affiliate shall be by a statement in writing that is signed by the Affiliate and by the Company. The statement shall include the effective date of adoption and any special provisions that are to be applicable to employees of the adopting Affiliate. 1.3 ADMINISTRATION This plan shall be administered by the Personnel Committee (the Committee) of the Company's Board of Directors (the Board). The Committee shall interpret the plan and make determinations about benefits. Any decision by the Committee within its authority shall be final and binding on all parties. The Committee shall consider recommendations from the President of the Company where provided for in this plan and otherwise in its discretion. The Committee may delegate any part of its powers and responsibilities to others. 2. PARTICIPATION; SERVICE; FORFEITURE 2.1 ELIGIBILITY; PARTICIPANTS An individual described in any of the categories in (a) through (f) shall be eligible to accrue benefits under the plan commencing with the first of any month as of which the officer's annual base salary rate exceeds $125,000. If an executive officer receives a lump sum payment in lieu of an increase in annual base salary rate, the executive officer shall be treated as having received such increase during the 12-month period to which the lump sum payment applies for purposes of determining eligibility for the plan. As of July 1 of each year, commencing with July 1, 1996, the $125,000 shall be increased by the percentage increase in salary provided by the Company's nonunion employee merit pool applicable to salary adjustments taking effect in such year. An individual who has benefits accrued under this plan prior to the 1996 Restatement and does not satisfy the eligibility requirement of this 2.1 shall participate in the plan for the limited purpose of receiving prior accrued benefits. An executive officer or other individual who has an accrued benefit under the plan shall be referred to as a participant. (a) An executive officer of PacifiCorp. (b) An officer of Pacific Telecom, Inc. (c) An officer of PacifiCorp Financial Services, Inc. (d) The President of Pacific Generation Company. 2 (e) The President and the Chief Operating Officer of PacifiCorp Power Marketing, Inc. (f) Any other executive employee of an Employer who is recommended for participation by the President of the Company and approved by the Board of the Company. 2.2 SERVICE A participant's Years of Service and Benefit Years for purposes of this plan shall be determined under the rules for such service under the Basic Plan(s) covering the participant, except as follows. Any limitation of the Basic Plan(s) on the length of service counted for periods in which no services are performed shall be disregarded. A participant shall be credited with a Year of Participation under this plan for each calendar year during which the participant satisfied the eligibility requirement of 2.1 and was not removed from active participation under 2.6. A partial Year of Participation shall be credited based on the number of completed calendar months. 2.3 VESTING A participant's right to receive benefits under this plan shall become vested upon any one of the following: (a) When the participant has attained age 50 and has completed five or more Years of Participation. (b) When the participant has completed five or more Years of Service and terminates, either voluntarily or involuntarily, from all employment with the Company and its Affiliates within 24 months after a Change in Control. (c) When the Employer employing the participant has an Employer Disposition and the participant does not become employed by the Company or an Affiliate within 60 days after the Employer Disposition occurs. 2.4 MISCONDUCT FORFEITURE Unless a Change in Control has occurred, the Committee may forfeit the benefit for any participant, or the participant's spouse, beneficiary or contingent annuitant, if: (a) The participant is discharged for any act that is materially inimical to the best interests of the Company and that constitutes, on the 3 part of the participant, common law fraud, felony, or other gross malfeasance of duty; or (b) After retirement, the participant performs services for an organization where there is a major conflict of interest that is materially adverse to the Company as a whole or any of its principal subsidiaries. 2.5 CHANGE IN CONTROL; EMPLOYER DISPOSITION (a) A "Change in Control" shall occur if: (1) Any "person" or "group" (within the meaning of Sections 13(d) and 14(d)(2) of the Securities Exchange Act of 1934, as amended (the Act)) becomes the "beneficial owner" (as defined in Rule 13-d under the Act) of more than 20 percent of the then outstanding voting stock of the Company, otherwise than through a transaction arranged by, or consummated with the prior approval of, the Board; or (2) During any period of two consecutive years, individuals who at the beginning of such period constitute the Board (and any new director whose election by the Board or whose nomination for election by the stockholders of the Company was approved by a vote of at least 2/3 of the directors then still in office who either were directors at the beginning of such period or whose election or nomination for election was previously so approved) cease for any reason to constitute a majority thereof. (b) An "Employer Disposition" shall occur if all the equity ownership of an Employer is disposed of and as a result no part of such equity ownership is held by the Company or an Affiliate. 2.6 REMOVAL FROM ACTIVE PARTICIPATION An individual who previously has qualified for participation under 2.1 shall be removed from active participation as of the first day of any month at which the individual ceases to so qualify. Upon removal the participant shall have an Accrued Benefit determined under 3.5 on the basis of the participant's Final Average Pay, Projected Short Service Factor, Performance Benefit, and Career Ratio, calculated as of the effective date of removal, and on the participant's PacifiCorp Primary Insurance Amount and Other Plan Offset calculated as of 4 the date of benefit commencement. If the participant qualifies for a retirement benefit under 3.1, the Accrued Benefit shall be paid as either a normal retirement benefit or an early retirement benefit depending on whether the participant terminates employment before normal retirement date. If an early retirement benefit is paid, the Early Retirement Factor shall be based on the months by which commencement of the benefit precedes age 60. 3. PARTICIPANTS' RETIREMENT BENEFITS 3.1 ENTITLEMENT; RETIREMENT DATES A participant shall be entitled to retirement benefits under this plan on becoming eligible for benefits under a Basic Plan because of termination of employment after vesting under 2.3 or one of the following retirement dates: (a) Normal retirement - age 65. (b) Early retirement - 5 Years of Participation plus either of the following: (1) Age 55; or (2) Age 50 and 15 Years of Service. 3.2 NORMAL RETIREMENT BENEFIT A participant's normal retirement benefit under this plan shall be a single life annuity for the life of the participant equal to 50 percent of Final Average Pay (FAP) plus the Performance Benefit (PB) times the Short Service Factor (SSF) minus the PacifiCorp Primary Insurance Amount (PPIA) and the Other Plan Offset (OPO) as follows: Benefit = [([50% x FAP] + PB) x SSF] - PPIA - OPO The terms used in this formula are defined as follows: (a) Final Average Pay (FAP) means the amount determined for the participant under the Basic Plan, with the following adjustments: (1) The limit on annual compensation counted for any participant to $200,000 per year through 1993 and to $150,000 per year thereafter (both subject to cost of living adjustments) shall not apply. 5 (2) No reduction shall be made for deferrals elected by the participant under a nonqualified deferred compensation plan maintained by the Company or an Affiliate. (3) No benefit payments under a nonqualified deferred compensation plan shall be counted. (4) No part of long-term incentive, stock bonus or stock option compensation shall be counted. (5) All cash bonuses that are not part of a long-term incentive plan or arrangement shall be counted, without the 10 percent limit of the Basic Plan, except as follows. Cash bonuses paid as an incentive in connection with an acquisition, disposition, or merger of an entity, business, or piece of property shall not be counted, except to the extent designated in writing by the Company. (6) A bonus earned in one calendar year and paid in the following calendar year, including any bonus paid in the year following employment termination, shall be divided evenly among the participant's completed calendar months of employment with Employer during the year the bonus was earned and counted as compensation in those months. (b) Performance Benefit (PB) means an additional 1 percent of Final Average Pay (FAP) for each calendar year of participation, commencing with 1996, for which the Company meets a performance goal set by the Committee for that year and announced to participants. If the participant is employed by Employer for less than a full year, including a partial initial or final year of employment, the 1 percent amount shall be prorated based on the portion of the year worked. The total amount of Performance Benefit payable to a participant shall not exceed 15 percent of the participant's Final Average Pay, minus the number of percentage points, if any, provided to the participant by 9.2(c). 6 (c) Short Service Factor (SSF) means a percentage, not to exceed 100 percent, determined by dividing the participant's Benefit Years by 15. (d) PacifiCorp Primary Insurance Amount (PPIA) means the portion earned while working at PacifiCorp of the participant's primary insurance amount on retirement at or after age 65 under the federal Social Security Act determined as follows: (1) The amount shall be estimated from the regular pay rate under rules established by the Committee assuming a standard pay progression over a full working career. (2) The amount shall not be changed by amendments to the Act or cost of living index adjustments after the participant's actual termination date or attainment of Social Security retirement age, whichever is first. (3) If a participant retires early, the Primary Social Security Benefit shall be the amount that would be received at age 65 assuming no further earnings and no change in the Act. (4) The portion earned at PacifiCorp shall be determined by multiplying the participant's full primary insurance amount by a ratio of the participant's Years of Service divided by 35. (e) Other Plan Offset (OPO) means the sum of the straight life actuarial equivalents of (1) through (4) below, as interpreted under (5) below: (1) Retirement benefits payable under the Basic Plan, including any benefits assumed from the Utah Power & Light Company Deferred Compensation Plan and excess benefits provided by the Utah Power & Light Company Retirement and Death Benefit Plan. 7 (2) Retirement benefits payable under a defined benefit plan or individual retirement benefit agreement, whether or not tax-qualified, on account of service before employment with Employer. (3) Benefits paid or payable under a defined contribution plan on account of service before employment with Employer if the earlier employer maintained no defined benefit plan covering the participant during the period of such service and the aggregate employer contributions to the defined contribution plan were 3 percent or more of the participant's compensation, as defined for determining Final Average Pay under this plan, with the earlier employer. (4) Any amount added to an account of the participant under a nonqualified deferred compensation plan maintained by Employer to compensate for reduction in the Basic Plan benefit on account of compensation deferrals. (5) For purposes of determining whether employer contributions to a defined contribution plan are 3 percent or more of compensation, and for measuring the amount of offset, elective contributions under a 401(k) plan and contributions individually elected by a self-employed person shall be disregarded. 3.3 ACTUARIAL EQUIVALENTS Actuarial equivalents shall be determined on the basis of the actuarial equivalency factors used by the Basic Plan. 3.4 EARLY RETIREMENT BENEFIT A participant's early retirement benefit shall be a single life annuity for the life of the participant equal to 50 percent of Final Average Pay (FAP) plus the Performance Benefit (PB) times the Projected Short Service Factor (PSSF) times the Career Ratio (CR) minus the PacifiCorp Primary Insurance Amount (PPIA) times the Early Retirement Factor (ERF) minus the Other Plan Offset (OPO) as follows: 8 Benefit = ([([(50% x FAP) + PB] x PSSF x CR) - PPIA] x ERF) - OPO The terms Final Average Pay (FAP), Performance Benefit (PB), and PacifiCorp Primary Insurance Amount (PPIA) are defined in 3.2. The term Other Plan Offset (OPO) shall be as defined in 3.2, except the offset for a participant whose Benefit Starting Date is earlier than age 55 shall not apply until the first of the month after age 55. As a result, such a participant shall receive a larger monthly benefit until attainment of age 55 and then a monthly benefit reduced by the amount of the Other Plan Offset. At age 55 the participant's benefit under this plan in the form of a single life annuity shall be offset by the amount of the participant's Other Plan Offset stated in single life annuity form. The remaining benefit shall be adjusted to the same form of benefit the participant had commenced receiving on the previous early retirement based on the factors for actuarial equivalency in effect at the time the adjustment is made and the ages of the participant and any contingent annuitant at such time. The participant shall not be permitted to change to a different form of benefit. If a contingent annuitant dies after the early retirement and before the participant attains age 55, the adjustment shall be based on the age the contingent annuitant would have attained but for such death. If a participant starting benefits before age 55 elects a contingent annuity and dies before age 55, the benefit of the contingent annuitant shall be reduced by the Other Plan Offset when the participant would have attained age 55. The definitions of the remaining terms are as follows: (a) Projected Short Service Factor (PSSF) means the Short Service Factor the participant would have had at age 60 if Benefit Years had continued to that date. If the participant is over age 60 at the time the early retirement benefit is determined, the Projected Short Service Factor shall be the same as the Short Service Factor. As a result, it shall be based on actual Benefit Years as of the date the determination is made. (b) Career Ratio (CR) means the participant's actual Benefit Years, up to a maximum of 30, divided by the participant's projected Benefit Years at age 60, up to a maximum of 30, assuming continuous full-time service to that date. If the participant is earning Benefit Years at or after age 60, the Career Ratio shall be 1.0. (c) Early Retirement Factor (ERF) means a percentage equal to 100 percent minus .25 percent for each month by which the commencement of benefits precedes the end of the month in which the participant will attain age 60. 9 3.5 TERMINATION BENEFIT A participant who terminates employment before early or normal retirement date and after becoming vested shall receive the participant's Accrued Benefit as provided below. The Accrued Benefit is a single life annuity for the life of the participant equal to 50 percent of Final Average Pay (FAP) plus the Performance Benefit (PB) times the Projected Short Service Factor (PSSF) times the Career Ratio (CR) minus the PacifiCorp Primary Insurance Amount (PPIA) times the Early Retirement Factor (ERF) minus the Other Plan Offset (OPO) as follows: Benefit = [([(50% x FAP) + PB] x PSSF x CR) - PPIA) x ERF] - OPO The terms used in this formula are defined in 3.2 and 3.4. 3.6 TIME AND MANNER OF PAYMENT Retirement benefits under 3.2 or 3.4 shall commence as of the first day of the month beginning after a termination of employment that constitutes a retirement under 3.1. Termination benefits under 3.5 shall commence as of the first day of the month after the participant's early retirement date. The date of commencement shall be the participant's Benefit Starting Date. Payment shall be made monthly in one of the forms listed below on the payment schedule maintained for that form by the Basic Plan covering the participant. If the participant is covered by more than one Basic Plan, the payment schedule for the plan with the largest benefit shall apply. The amount paid in the forms provided in (b), (c) or (d) shall be the actuarial equivalent, as determined under 3.3, of the amount paid in the form provided in (a). The form shall be irrevocably elected by the participant on a form provided by the Committee prior to receipt of the first payment, subject to the following. An election by a married participant of a form provided in (a) or (d) shall not be effective unless the spouse consents in the manner provided under the Basic Plan for elections not to receive a joint and survivor annuity. (a) A single life annuity for the life of the participant. (b) A life annuity with payments continuing after the participant's death at 50 percent to a contingent annuitant for life. (c) A life annuity with payments continuing after the participant's death at 100 percent to a contingent annuitant for life. (d) A life annuity with payments continuing to a designated beneficiary for the remainder of the first 120 months if the participant dies before then. 10 3.7 BASIC PLAN MAKE-UP If a participant in this plan has a reduced benefit under the Basic Plan as a result of having elected deferral of pay under a nonqualified deferred compensation plan of Employer for a year in which the participant is removed from participation under 2.5 and such reduction is not otherwise made up by this plan, the amount of such reduction shall be paid as an additional benefit under this plan. The additional benefit provided by this 3.8 shall be paid at the same time and in the same form as it would have been under the Basic Plan if there had been no reduction. 4. PRERETIREMENT DEATH BENEFITS If a participant with a spouse or dependent children dies before the Benefit Starting Date while employed with the Company or an Affiliate, whether or not an adopting Employer, a death benefit shall be paid as provided below. The death benefit shall be a percentage of the participant's Accrued Benefit as of the date of death, based on an Early Retirement Factor of 100 percent. 4.1 SPOUSE'S BENEFIT A surviving spouse shall be paid a benefit as follows: (a) The amount shall be 50 percent of the participant's Accrued Benefit. (b) The form shall be a single life annuity for the life of the spouse starting with the month following the date of death. 4.2 DEPENDENT CHILD'S BENEFIT If the participant is unmarried with one or more dependent children, the benefit shall be paid to such children. A dependent child is one who is age 19 to 22 and enrolled in a full-time program of education at a secondary school or at a college, university or other post-secondary school or who is age 18 or younger. The dependent child's benefit shall be paid as follows: (a) The amount payable to a sole dependent child shall be 25 percent of the participant's Accrued Benefit. (b) The amount payable to two or more dependent children shall be 40 percent of the participant's Accrued Benefit, divided equally among such children. 11 (c) The dependent child's benefit shall be paid monthly starting with the month following the date of death and ending with the month the individual ceases to be a dependent child. If one of two dependent children receiving a share of the amount under (b) ceases to be a dependent child, the remaining dependent child then shall receive the amount under (a). 5. DISABILITY 5.1 SERVICE CONTINUATION A disabled participant shall continue to accrue benefit service under this plan so long as Benefit Hours are accrued for the participant under the Basic Plan. 5.2 BENEFITS A disabled participant continuing to accrue service shall be treated like any other employee until disability ends or retirement or death occurs. In the event of death or retirement after disability, retirement or spouse's death benefits under this plan shall be determined in the same manner as for any participant. 6. CLAIMS PROCEDURE 6.1 ORIGINAL CLAIM Any person whose benefit under this plan is not promptly paid may present a written claim for the benefit to the Committee. The Committee shall respond to the claim in writing as soon as practicable. 6.2 DENIAL If the claim is denied, the written notice of denial shall state: (a) The reasons for denial, with specific reference to the plan provisions on which the denial is based. (b) A description of any additional material or information required and an explanation of why it is necessary. (c) An explanation of the plan's claim review procedure. 12 6.3 REQUEST FOR REVIEW Any person whose claim is denied or who has not received a response within 30 days may request review of the claim by the trustee for the plan appointed under 8.3 by notice given in writing to the trustee. The claim or request shall be reviewed by the trustee which may, but shall not be required to, have the claimant and a representative of the Committee appear before it. On review, the claimant may have representation, examine pertinent documents, and submit issues and comments in writing. 6.4 FINAL DECISION The trustee's decision on review shall normally be made within 60 days. If an extension is required for a hearing or other special circumstances the claimant shall be so notified and the time limit shall be 120 days. The trustee's decision shall be in writing and shall state the reasons and the relevant plan provisions. All decisions on review shall be final and bind all parties concerned. 7. AMENDMENT; TERMINATION 7.1 AMENDMENT The Company may amend this plan at any time so long as the rights preserved on termination under 7.2 are not reduced. No amendment may accelerate the time of payment of benefits to persons participating in the plan at the time of the amendment. 7.2 TERMINATION The Board of Directors of the Company may terminate the plan at any time as follows: (a) Termination shall be by notice to the Committee, which shall notify participants of the termination. The termination date shall not be earlier than the first day of the month in which notice is given. (b) After the effective date of termination no further executive officers shall become participants and no further benefits shall accrue for existing participants. (c) The Accrued Benefit of each existing participant shall be paid under the terms of the plan as in effect before termination. The Accrued Benefit shall be calculated as follows: 13 (1) Final Average Pay, Years of Service, and Years of Participation shall be determined as though the effective date of plan termination were a termination of employment. (2) The PacifiCorp Primary Insurance Amount shall be estimated on the basis of the pay level and the Social Security Act as in existence at the time of plan termination. (3) The Other Plan Offset shall be based on the benefits accrued under the Basic Plan and other qualified plans at the time of plan termination. 8. GENERAL PROVISIONS 8.1 NONASSIGNABILITY The rights of a participant under this plan are personal. No interest of a participant or any beneficiary or representative of a participant may be directly or indirectly transferred, encumbered, seized by legal process or in any other way subjected to the claims of any creditor. 8.2 FUNDING The rights of the participants and beneficiaries under this plan shall be an unfunded, unsecured promise of the Company to make future payments. 8.3 TRUST The Company shall establish a trust with a financial institution for payment of benefits under the plan, which shall be a grantor trust for tax purposes. The trust shall provide that any assets contributed to the Trustee shall be used exclusively for payment of benefits under this plan except in the event the Company becomes insolvent, in which case the trust fund shall be held for payment of the Company's obligations to its general creditors. 8.4 NOTICES A notice under this plan shall be in writing and shall be effective when actually delivered or, if mailed, when deposited postpaid as first class mail. Mail shall be directed to the Company at the address stated in this plan, to the participant at the address shown on the Company's employment records, or to such other address as a party shall specify by notice to the other parties or as the Committee may determine to be appropriate. Notices to the Committee shall be sent to the Company's address. 14 8.5 ATTORNEYS' FEES If suit or action is instituted to enforce any rights under this plan, the prevailing party may recover from the other party reasonable attorneys' fees at trial and on any appeal. 8.6 INDEMNITY The Company shall indemnify and defend any member of the Committee or any officer, director or employee of an Employer from any claim or liability that arises from any action or inaction in connection with the plan subject to the following rules: (a) Coverage shall be limited to actions taken in good faith that the fiduciary reasonably believed were not opposed to the best interests of the plan; (b) Negligence by the fiduciary shall be covered to the fullest extent permitted by law; and (c) Coverage shall be reduced to the extent of any insurance coverage. 8.7 APPLICABLE LAW This plan shall be construed according to the laws of Oregon except as preempted by federal law. 8.8 COMPANY OBLIGATION Benefits payable under this plan shall be an obligation of the Company, which may charge the cost back to the Employer of the participant. If an Employer merges, consolidates, or otherwise reorganizes or if its business or assets are acquired by another entity and it remains an Affiliate of the Company, this plan shall continue with respect to those eligible individuals who continue as employees of the successor company. The transition of Employers shall not be considered a termination of employment for purposes of this plan. If an Employer ceases to be an Affiliate of the Company, a participant employed by that Employer shall cease accruing Years of Service and changes in Final Average Pay. The participant shall receive benefits under this plan on a later termination of employment with Employer if the participant had reached a retirement date or become vested before the affiliation ceased. 15 8.9 PAYMENT FOR INDIVIDUAL'S BENEFIT Payment for a person entitled to benefits shall be made to one of the following if the recipient is court-appointed or the payment is ordered by a court: (a) To a parent or spouse or a child of legal age; (b) To a legal guardian; or (c) To one furnishing maintenance, support, or hospitalization. 8.10 NOT CONTRACT OF EMPLOYMENT Nothing in this plan shall give any employee the right to continue employment. The plan shall not prevent discharge of any employee at any time for any reason. 9. EFFECTIVE DATE 9.1 This Restatement shall be effective January 1, 1996. 9.2 The following transition rules shall apply at the effective date provided in 9.1: (a) The benefit payable to a participant who was covered by the plan before January 1, 1996, or to the surviving spouse or dependent children of such a participant, shall be no less than the participant's Accrued Benefit determined under 3.6 of the plan, as in effect on December 31, 1995, on the basis of the participant's Final Average Pay, Projected Short Service Factor, and Career Ratio calculated as of December 31, 1995 and on a Primary Social Security Benefit and Qualified Plan Offset equal to the participant's PacifiCorp Primary Insurance Amount and Other Plan Offset, respectively, calculated as of the date of benefit commencement. If the participant had attained age 55 on or before December 31, 1995, the participant shall have an Earliest Retirement Date upon attaining age 62 and completing 30 Years of Service. The portion of the normal retirement benefit of such a participant equal to the Accrued Benefit described above shall be increased by one-third of one percent for each month by which the participant's Earliest Retirement Date precedes the participant's actual benefit commencement date. No increase shall be made for a month beginning after the participant's 65th birthday. 16 (b) An individual becoming a participant in the plan as a result of the new eligibility standards in 2.1 of this Restatement shall be credited with Years of Participation for years before 1996 during which the individual was an executive officer of an Employer and had an annual base salary rate of over $125,000. (c) For an individual who was a participant over age 50 on January 1, 1996 the 50 percent amount in the benefit formulas in 3.2, 3.4 and 3.6 shall be increased by one percent for each year of age at nearest birthday above age 50 at January 1, 1996. Adopted: November 8, 1995. 1996 RESTATEMENT EXECUTED AS FOLLOWS EFFECTIVE AS PROVIDED IN ARTICLE 9: - ------------------------------------------------------------------------------- PACIFICORP By FREDERICK W. BUCKMAN ------------------------------------- President Executed: February 23, 1996 AMENDMENT NO. 1 EXECUTED AS FOLLOWS EFFECTIVE AS IF INCLUDED IN THE 1996 RESTATEMENT: - ------------------------------------------------------------------------------- Company PACIFICORP By FREDERICK W. BUCKMAN ------------------------------------- President Executed: July 9, 1996 17 AMENDMENT NO. 2 EXECUTED AS FOLLOWS EFFECTIVE MAY 21, 1997: - ------------------------------------------------------------------------------- Adopted: May 21, 1997 Company PACIFICORP By FREDERICK W. BUCKMAN ------------------------------------- President Executed: August 20, 1997 AMENDMENT NO. 3 EXECUTED AS FOLLOWS EFFECTIVE SEPTEMBER 1, 1997: - ------------------------------------------------------------------------------- Adopted: August 13, 1997 Company PACIFICORP By FREDERICK W. BUCKMAN ------------------------------------- President Executed: October 1, 1997 AMENDMENT NO. 4 EXECUTED AS FOLLOWS EFFECTIVE JANUARY 1, 1997 AS IF INCLUDED IN THE 1996 RESTATEMENT: - ------------------------------------------------------------------------------- Company PACIFICORP By FREDERICK W. BUCKMAN ------------------------------------- Executed: November 19, 1997 18 EX-12.(A) 3 EXHIBIT 12(A) EXHIBIT (12)a PACIFICORP STATEMENTS OF COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
1993 1994 1995 1996 1997 --------- --------- --------- --------- --------- (IN MILLIONS OF DOLLARS) Fixed Charges, as defined:* Interest expense............................................. $ 333.5 $ 302.0 $ 336.4 $ 415.0 $ 439.8 Estimated interest portion of rentals charged to expense..... 4.8 5.6 4.5 4.1 6.6 Preferred dividends of wholly owned subsidiary............... -- -- -- 15.3 33.1 --------- --------- --------- --------- --------- Total fixed charges...................................... $ 338.3 $ 307.6 $ 340.9 $ 434.4 $ 479.5 --------- --------- --------- --------- --------- --------- --------- --------- --------- --------- Earnings, as defined:* Income from continuing operations............................ $ 371.8 $ 397.5 $ 402.0 $ 430.2 $ 225.4 Add (deduct): Provision for income taxes................................. 163.6 209.0 191.8 236.5 109.5 Minority interest.......................................... 2.7 1.3 1.4 1.8 1.9 Undistributed income of less than 50% owned affiliates..... (16.2) (14.7) (15.0) (18.2) (11.1) Fixed charges as above..................................... 338.3 307.6 340.9 434.4 479.5 --------- --------- --------- --------- --------- Total earnings........................................... $ 860.2 $ 900.7 $ 921.1 $ 1,084.7 $ 805.2 --------- --------- --------- --------- --------- --------- --------- --------- --------- --------- Ratio of Earnings to Fixed Charges............................. 2.5x 2.9x 2.7x 2.5x 1.7x --------- --------- --------- --------- --------- --------- --------- --------- --------- ---------
- ------------------------ * "Fixed charges" represent consolidated interest charges, an estimated amount representing the interest factor in rents and preferred dividend requirements of majority-owned subsidiaries. "Earnings" represent the aggregate of (a) income from continuing operations, (b) taxes based on income from continuing operations, (c) minority interest in the income of majority-owned subsidiaries that have fixed charges, (d) fixed charges and (e) undistributed income of less than 50% owned affiliates without loan guarantees. S-1 EX-12.(B) 4 EXHIBIT 12(B) EXHIBIT (12)b PACIFICORP STATEMENTS OF COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS
1993 1994 1995 1996 1997 --------- --------- --------- --------- --------- (IN MILLIONS OF DOLLARS) Fixed Charges, as defined:* Interest expense............................................. $ 333.5 $ 302.0 $ 336.4 $ 415.0 $ 439.8 Estimated interest portion of rentals charged to expense..... 4.8 5.6 4.5 4.1 6.6 Preferred dividends of wholly owned subsidiary............... -- -- -- 15.3 33.1 --------- --------- --------- --------- --------- Total fixed charges...................................... $ 338.3 $ 307.6 $ 340.9 $ 434.4 $ 479.5 Preferred Stock Dividends, as defined:*........................ 56.8 60.8 57.0 46.2 33.9 --------- --------- --------- --------- --------- Total fixed charges and preferred dividends.............. $ 395.1 $ 368.4 $ 397.9 $ 480.6 $ 513.4 --------- --------- --------- --------- --------- --------- --------- --------- --------- --------- Earnings, as defined:* Income from continuing operations............................ $ 371.8 $ 397.5 $ 402.0 $ 430.2 $ 225.4 Add (deduct): Provision for income taxes................................. 163.6 209.0 191.8 236.5 109.5 Minority interest.......................................... 2.7 1.3 1.4 1.8 1.9 Undistributed income of less than 50% owned affiliates..... (16.2) (14.7) (15.0) (18.2) (11.1) Fixed charges as above..................................... 338.3 307.6 340.9 434.4 479.5 --------- --------- --------- --------- --------- Total earnings........................................... $ 860.2 $ 900.7 $ 921.1 $ 1,084.7 $ 805.2 --------- --------- --------- --------- --------- --------- --------- --------- --------- --------- Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends.................................................... 2.2x 2.4x 2.3x 2.3x 1.6x --------- --------- --------- --------- --------- --------- --------- --------- --------- ---------
- ------------------------ * "Fixed charges" represent consolidated interest charges, an estimated amount representing the interest factor in rents and preferred dividend requirements of majority-owned subsidiaries. "Preferred Stock Dividends" represent preferred dividend requirements multiplied by the ratio which pre- tax income from continuing operations bears to income from continuing operations. "Earnings" represent the aggregate of (a) income from continuing operations, (b) taxes based on income from continuing operations, (c) minority interest in the income of majority-owned subsidiaries that have fixed charges, (d) fixed charges and (e) undistributed income of less than 50% owned affiliates without loan guarantees. S-2 EX-13 5 EXHIBIT 13 MANAGEMENT'S DISCUSSION AND ANALYSIS EARNINGS OVERVIEW
MILLIONS OF DOLLARS, EXCEPT PER SHARE INFORMATION 1997 1996 1995 - -------------------------------------------------------------------------------- EARNINGS CONTRIBUTION ON COMMON STOCK Domestic Electric Operations $165.5 $341.5 $276.4 Australian Electric Operations 54.2 31.9 0.7 Unregulated Energy Trading (7.5) (0.1) -- Other Operations (9.6) 27.1 86.2 ------------------------------------ Continuing Operations 202.6 400.4 363.3 Discontinued Operations 454.3 74.7 103.0 Extraordinary item (16.0) -- -- ------------------------------------ $640.9 $475.1 $466.3 ------------------------------------ ------------------------------------ EARNINGS PER COMMON SHARE -- BASIC AND DILUTIVE Continuing Operations $ 0.68 $ 1.37 $ 1.28 Discontinued Operations 1.53 0.25 0.36 Extraordinary item (0.05) -- -- ------------------------------------ $ 2.16 $ 1.62 $ 1.64 ------------------------------------ ------------------------------------ PAGE NO. 1997 - -------------------------------------------------------------------------------- EFFECTS OF ADJUSTMENTS ON EARNINGS PER COMMON SHARE Earnings per common share -- as reported $ 2.16 ADJUSTMENTS Asset sales gains 26 (1.33) Special charges 29 0.36 Extraordinary loss 25 0.05 Foreign currency option losses 26 0.22 Depreciation, uncollectible provisions and SAP charges 29 0.07 Tariff H and other adjustments 32 (0.01) ------------------- $ 1.52 ------------------- -------------------
The global energy business witnessed dramatic changes during 1997 and competition now exists in many parts of the energy marketplace. Significant events included passage of state regulatory legislation, continuation of acquisitions, consolidations or partnering by energy companies both domestically and internationally, and further reductions in electricity product margins. To stay competitive, companies must reduce costs, improve customer service, supplement energy sales with other needed products and services, enhance the reliability of their system (generation, transmission and distribution), and maintain a safe working environment. These factors had direct impacts on PacifiCorp's 1997 results and may significantly impact its near-term performance. During 1997, PacifiCorp sharpened its focus on becoming a dominant global energy provider by selling Pacific Telecom, Inc. ("PTI"), acquiring gas marketing expertise with the purchase of TPC Corporation ("TPC") and making a tender offer for The Energy Group PLC ("TEG"). Industry restructuring continued with certain jurisdictions taking legislative actions approving customer choice, which caused Domestic Electric Operations to write off certain allocated generation regulatory assets. Special charges and other unfavorable adjustments also significantly impacted Domestic Electric Operations' costs in 1997. Management took steps to address increasing operating cost issues and maintain the Company's position as a low-cost energy producer. Earnings on common stock for PacifiCorp and its subsidiaries (the "Company") increased $166 million, or $0.54 per share, compared to 1996. The Company's $641 million of 1997 earnings included asset sale gains of $395 million, or $1.33 per share, relating to sales of the Company's telecommunications subsidiary and independent power business. Domestic Electric Operations recorded $106 million, or $0.36 per share, of special charges relating to an accrual for a coal mine closure, write off of deferred regulatory pension assets and impairment of information technology systems. Additionally, the Company recorded other adjustments that significantly impacted 1997 results, including losses on foreign currency options, depreciation adjustments, process re-engineering expenses and contract adjustments. Excluding the asset sale gains, special charges and other adjustments discussed below, the Company's 1997 earnings on common stock, on a comparable basis to 1996, would have been $451 million, or $1.52 per share, a decrease of $24 million, or $0.10 per share from 1996. 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. As a result, the Company recorded in 1997 an extraordinary charge of $16 million, or $0.05 per share, for the write off of allocable generation regulatory assets in these states. - ------------------------------------------------------------------------------- PACIFICORP P.25 The Company also operates in five other states that are in various stages of addressing deregulation of the electricity industry. At December 31, 1997, the Company's total remaining regulatory assets for these five states was $871 million, of which $382 million is applicable to generation. Potential regulatory or legislative actions in these other states may result in additional write offs and charges. See further discussion in INDUSTRY CHANGES, COMPETITION AND DEREGULATION. Domestic Electric Operations' contribution to earnings on common stock was $165 million in 1997. After adding back to earnings $132 million of special charges and other adjustments, the contribution was $297 million. This $45 million decrease from 1996 earnings was the result of several factors including: higher depreciation; increased outside services costs; increased employee expenses attributable to the expansion of the wholesale power business; and price decreases in Utah. Purchased power expenses continued to grow as increased demand in the wholesale trading and retail markets resulted in the need to acquire power from external sources. This higher demand caused a 99% increase in wholesale energy sales and a 117% increase in purchased power volumes. Australian Electric Operations' earnings contribution increased $22 million, or 70%, due to higher volumes, renegotiations of Tariff H industrial contracts, decreased maintenance costs and lower interest expense. Powercor continued its growth as a marketing and distribution company in Australia and, based on energy sales, currently serves 42% of Victoria's contestable customers and 13% of the New South Wales contestable market, which opened in October 1996. Unregulated Energy Trading became a reportable segment in 1997 with the significant expansion of electricity and gas marketing revenues. This segment includes PacifiCorp Power Marketing, Inc. ("PPM"), engaged in wholesale electricity trading in eastern United States markets, and TPC, a recently acquired natural gas marketing and storage company. This new segment had revenue of $1.7 billion in 1997 compared to $12 million in 1996. The gross margin on sales was $19 million in 1997 compared to $4 million in 1996. However, after start-up and administrative costs, it reported a net loss of $8 million in 1997. Revenues, gross margin and net income in 1997 included $19 million, $14 million and $3 million, respectively, relating to assets of TPC that were sold in December 1997. Other Operations reported net losses of $10 million in 1997, or $0.03 per share, as compared to earnings of $27 million, or $0.09 per share, in 1996. The 1997 results were impacted by an after-tax loss of $65 million associated with closing foreign currency exchange positions and option premium costs relating to the initial tender offer for TEG in June 1997. Additionally, Other Operations included the $30 million gain on sale of Pacific Generation Company ("PGC"), discussed below. The earnings of PacifiCorp Group Holdings Company ("Holdings") and other unregulated businesses in 1997 were comparable with the prior year. 1997 ASSET SALE GAINS
NET CASH PRETAX NET MILLIONS OF DOLLARS FROM SALES(a) GAINS INCOME EPS - ------------------------------------------------------------------------------- PTI sale $1,198 $671.0 $365.1 $1.23 PGC sale 96 56.5 30.0 0.10 -------------------------------------------------- $1,294 $727.5 $395.1 $1.33 -------------------------------------------------- --------------------------------------------------
(a) Cash from asset sales is net of income taxes. On December 1, 1997, the Company completed the sale of PTI for $1.5 billion in cash, plus the assumption of PTI's debt. The Company realized an after-tax gain of $365 million, or $1.23 per share. For the eleven months of 1997, PTI reported net income of $89 million, or $0.30 per share, compared to $75 million, or $0.25 per share, for all of 1996. In November 1997, the Company completed the sale of its independent power subsidiary, PGC, for approximately $150 million in cash, which resulted in a gain of $30 million, or $0.10 per share. Excluding the loss on foreign currency exchange positions and PGC's operating results and gain on sale, the Company's other unregulated businesses and equity investments reported 1997 earnings of $15 million, compared to earnings of $19 million in 1996, a decrease of $4 million. - ------------------------------------------------------------------------------- P. 26 PACIFICORP DOMESTIC ELECTRIC OPERATIONS REVENUES
MILLIONS OF DOLLARS 1997 1996 1995 - ----------------------------------------------------- Wholesale trading(a) $1,428.0 $738.8 $520.0 Residential 814.0 801.4 739.7 Industrial 709.9 719.3 708.8 Commercial 640.9 623.3 576.9 Other 114.1 109.0 100.7 ---------------------------- $3,706.9 $2,991.8 $2,646.1 ---------------------------- ----------------------------
ENERGY SALES
MILLIONS OF KWH 1997 1996 1995 - ----------------------------------------------------- Wholesale trading(a) 59,143 29,665 16,376 Residential 12,902 12,819 12,030 Industrial 20,674 20,332 19,748 Commercial 11,868 11,497 10,797 Other 705 640 592 ----------------------------- 105,292 74,953 59,543 ----------------------------- -----------------------------
(a) Wholesale trading is part of Domestic Electric Operations' regulated activities and is separate from the Unregulated Energy Trading segment discussed hereafter. Domestic Electric Operations' revenue increase of $715 million in 1997 was caused primarily by a 99% increase in wholesale kilowatt hours sold ("kWh") that added $689 million of revenues. Retail energy sales in 1997 were 2% higher than in 1996. Although wholesale trading revenues have grown substantially over the past few years, in 1997 the retail load still represented 61% of total Domestic Electric Operations' revenues. Wholesale trading revenues increased to a record $1.4 billion. Energy volumes of short-term firm and spot market sales increased 28.5 million megawatt hours ("mWh") and added $589 million of revenues and higher prices for these sales added $80 million. Increased long-term firm contract volumes added $14 million to wholesale revenues. As a result of increased competition and excess capacity, wholesale prices overall dropped 25% in the past three years with a 21% drop in 1996 and a 4% decrease in 1997. The average price per mWh for wholesale power in 1997 was $24, as compared to $25 in 1996 and $32 in 1995. This trend in lower average prices is due to a higher percentage of wholesale sales being derived from shorter term contracts. The trend in lower average prices is expected to continue. AVERAGE ANNUAL REVENUE PER CUSTOMER
DOLLARS 1997 1996 - --------------------------------- Residential $ 672 $ 679 Industrial 19,477 18,887 Commercial 3,818 3,810
Residential revenues were up $13 million, or 2%. Growth in the average number of residential customers of 3% added $20 million to revenues. Price increases in Oregon, effective July 1996, added $9 million in 1997, offset in part by price decreases of $4 million in Utah that became effective April 1997 as discussed below. Declines in customer usage, primarily attributable to weather, reduced revenues $14 million in 1997 compared to 1996. Industrial revenues decreased $9 million, or 1%. Total kWh sold was up 2% with increased customer usage adding revenues of $6 million in Eastern Wyoming and $4 million in Oregon. However, these increases were more than offset by reduced revenues of $8 million from lower usage by irrigation customers due to increased rainfall and milder temperatures in 1997 and $6 million of billing adjustments in the first quarter of 1997. Commercial revenues increased $18 million, or 3%, primarily due to customer growth. The Utah service area had 5% growth in the average number of customers and $11 million in increased revenues, and Oregon reported 2% growth in the average number of customers and $4 million in additional revenue. Utah price decreases lowered revenue by $3 million. However, this decrease was offset by higher Oregon prices that increased revenues by the same amount. In early 1997, the Division of Public Utilities (the "DPU") and the Committee of Consumer Services (the "CCS") in Utah filed a joint petition with the Utah Public Service Commission (the "PSC") requesting the PSC to commence proceedings to establish new rates for Utah customers. The DPU indicated that rates could be reduced by approximately $54 million. Subsequently in March 1997, the Utah Legislature passed a bill that created a legislative task force to study electrical restructuring and customer choice issues in the State of Utah. The bill precluded the PSC from holding hearings on rate changes and froze prices at January 31, 1997 levels until May 1998, but allowed for retroactive price changes. The Company agreed to an interim price decrease to Utah customers of $12.4 million annually beginning on April 15, 1997. During the freeze period, the PSC proceeded with hearings on the proper method for cost allocation among PacifiCorp's seven jurisdictions that would be used in the 1998 rate case. The DPU recommended an allocation method that would reduce prices by $56 million over five years, of which $14 million was included in its original estimate of $54 million. During these hearings, the CCS recommended a method that would reduce prices by $96 million, or $42 million more than the original DPU estimate. The Company advocated a method that would result in a decrease of approximately $3 million per year. The PSC held hearings in December and an order is expected - ------------------------------------------------------------------------------- PACIFICORP P. 27 OPERATING EXPENSES
MILLIONS OF DOLLARS 1997 1996 1995 - --------------------------------------------------------------- Fuel $ 454.2 $ 443.0 $ 431.6 Purchased power 1,296.5 618.7 386.7 Other operations and maintenance 470.0 444.2 442.1 Depreciation and amortization 389.1 343.4 320.4 Other 325.4 272.7 264.4 Special charges 170.4 -- -- --------------------------------- $3,105.6 $2,122.0 $1,845.2 --------------------------------- Operating Expenses as a % of Revenue (excluding special charges) 79% 71% 70%
in early 1998. An allocation order by itself will not decrease revenues, but will be incorporated into subsequent rate proceedings which are expected to occur in mid-1998 and will be combined with other cost increases and decreases to determine the overall impact to customer rates. In December 1997, the California Public Utilities Commission issued an order with respect to the Company's filing concerning transition to direct access requirements enacted in that state. The order mandated a 10% rate reduction effective January 1, 1998, which is expected to result in a $3.5 million annual reduction in revenues. 1996 COMPARED TO 1995 -- Revenues rose 13%, or $346 million, primarily due to an 81% increase in kWh sold in the wholesale market. Despite this volume increase, the Company realized only a 42% increase in wholesale revenues in 1996 due to the impact of competition on market prices. Residential and commercial revenues grew a combined 8% in 1996 as a result of increased prices and volumes. Price increases of approximately 4% were approved in Oregon and Wyoming customer jurisdictions in July 1996. In the last half of 1996, these increases contributed an additional $16 million of revenue. Revenues increased an additional $86 million due to weather conditions that increased energy requirements, 2% residential and 3% commercial customer growth and increased customer usage. OPERATING EXPENSES Operating expenses increased $984 million, or 46%, largely as a result of a significant increase in purchased power costs and special charges. Fuel expenses in 1997 increased 3%, or $11 million, primarily due to increased production from higher-cost plants in 1997 as compared to 1996. In July 1996, the Company purchased a 50% ownership interest in the 474 megawatt ("MW") gas-fired, combined cycle, Hermiston Plant and agreed to take 100% of the energy produced under a long-term contract, if the Company chooses to dispatch the power. The Company made the investment in Hermiston primarily to meet growing retail load requirements and to replace expiring long-term purchased power contracts with estimated costs of $30 million. The investment decision was made during a time when existing and projected market prices were significantly higher. During 1997, the Hermiston Plant generated 1.9 million mWh. Assuming all of the power generated by Hermiston was sold at an average short-term market price of $22 per mWh, the investment in Hermiston would have resulted in a pretax loss of $25 million, after considering the impacts of the terminated long-term purchase power contracts. Further, in certain of the states in which the Company operates, the costs in excess of market relating to Hermiston are being recovered in rates. Domestic Electric Operations intends to continue to seek recovery of this excess cost in other states in future regulatory proceedings. PURCHASED POWER
MILLIONS OF MWH 1997 1996 1995 - ------------------------------------------------ Short-term or spot market 45.6 16.9 5.0 Long-term contracts 9.4 8.5 6.0
In addition to base energy 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 was more than double last year, due to growth in the Company's wholesale trading business. Short-term firm and spot market purchases were nearly three times the level of 1996 purchases, adding $570 million to purchased power expense. Short-term firm and spot market purchase prices averaged $19 per mWh in 1997 compared to $13 per mWh in 1996, a 46% increase, adding $76 million to purchased power expense. Net power costs were $6.99 per mWh in 1997, compared to $7.20 per mWh in 1996, a 3% decrease. Net power costs represent the net cost to serve the Company's retail customers on a mWh basis. This cost is measured by the sum of fuel, - ------------------------------------------------------------------------------- P. 28 PACIFICORP - ------------------------------------------------------------------------------- purchased power and wheeling expense, less wholesale power and wheeling revenues. The decrease in net power costs was attributable to increased hydro generation which displaced higher cost resources and higher volumes from short-term and spot market sales, offset in part by increased fuel costs. Other operations and maintenance expense increased $26 million, or 6%, over 1996. The higher expenses included $11 million of increased plant maintenance and tree trimming expense and a $10 million provision for uncollectible accounts resulting from issues relating to new customer billing processes. Depreciation and amortization expense increased $46 million, or 13%. At the end of 1997, the Company completed a depreciation study of its fixed assets and filed with the appropriate regulatory bodies for approval to increase its annual depreciation rates. As a result of the study, depreciation expense increased $17 million to reflect the higher depreciation rates. An additional $26 million in depreciation was attributable to a $377 million increase in average depreciable plant in service, including a full year of a new customer service system and Hermiston Plant operations. Other expenses increased $53 million, a 19% increase over 1996. This increase was the result of higher employee related costs of $20 million, primarily attributable to a significant increase in wholesale marketing activities, higher outside services of $18 million and process re-engineering costs of $10 million relating to the Company's new SAP enterprise-wide software operating environment expected to be fully implemented in 1999. Nonfuel operating costs, excluding special charges, increased 11% in 1997. To stay competitive in this changing energy industry, the Company has announced cost cutting initiatives, including an early retirement and severance program and a reduction in the use of outside consultants. The early retirement and severance program is intended to eliminate approximately 600 positions, or 7% of the work force in the United States, in 1998 and reduce employee related costs. Based upon the current acceptance rate of the voluntary program, the pretax cost is estimated to be $104 million, which will be recorded in the first quarter of 1998. The current acceptance rate has exceeded the Company's original estimate. SPECIAL CHARGES
NET MILLIONS OF DOLLARS PRETAX INCOME EPS - ------------------------------------------------------ Glenrock mine closure $ 64.4 $ 39.9 $0.14 Deferred regulatory pension cost 86.9 53.9 0.18 Impairment charges on IT systems 19.1 11.9 0.04 ------------------------------ $170.4 $105.7 $0.36 ------------------------------ ------------------------------
In 1997, the Company recorded a series of special charges at Domestic Electric Operations. Management concluded that the Glenrock mine was uneconomic to continue to operate under current and expected market conditions due to increased mining stripping ratios, coal quality and related operating costs. Therefore, a $64 million accrual was recorded for costs associated with the write down of asset values and the acceleration of reclamation costs due to early closure of the mine. The Company also determined that recovery of its regulatory assets applicable to deferred pension costs, which related primarily to a deferred compensation plan and early retirement incentive programs in 1987 and 1990, was not probable. As a result, the Company recorded an $87 million charge for these deferred regulatory pension assets since the Company does not intend to seek recovery of these costs. However, the Company will seek recovery for its current and future pension costs. In addition, the Company recorded a $19 million charge for the impairment of certain information systems assets that are directly impacted by the Company's decision to proceed with installation of SAP enterprise-wide software. 1996 COMPARED TO 1995 -- Operating expenses grew 15% in 1996 primarily due to a $232 million increase in purchased power costs. Depreciation and amortization expenses were up 7%, which was attributable to a $410 million increase in average depreciable plant, including the addition of the Hermiston Plant that began operation in July 1996. OTHER INCOME AND EXPENSE Domestic Electric Operations' interest expense increased $27 million, or 9%, to $319 million in 1997. This increase was attributable to higher average debt balances as a result of the Hermiston Plant acquisition in July 1996 and capital contributions to Holdings relating to the acquisition of TPC in April 1997. Other income increased $7 million in 1997 primarily as a result of increased sales of emission allowances. 1996 COMPARED TO 1995 -- Interest expense declined $20 million, or 6%, in 1996. Excluding $28 million of interest cost associated with a tax settlement in 1995, interest expense increased $8 million, or 3%, due to higher debt levels during 1996. The settlement had no effect on consolidated net income, although it had the effect of reducing Domestic Electric Operations' earnings by $32 million and increasing Other Operations' earnings by $32 million in 1995. Other expenses increased $27 million in 1996 as a result of distributions relating to preferred securities of subsidiary trusts issued in 1996, reduced asset sale gains and increased product and business development expense. - ------------------------------------------------------------------------------- PACIFICORP P. 29 - ------------------------------------------------------------------------------- INDUSTRY CHANGES, COMPETITION AND DEREGULATION INDUSTRY CHANGE -- The electric power industry continues to experience rapid change. The key driver for this change is growing public and regulatory 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. Federal laws and regulations have already 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. The question is no longer if there will be competition, but rather how and when the competitive marketplace will develop. COMPETITION -- The Company faces competition from many areas, including other suppliers of electricity and alternative energy sources. In many cases, customers have the option to switch energy sources for heating and air conditioning. In addition, certain of the Company's industrial customers are seeking choice of suppliers, options to build their own generation or cogeneration, or the use of alternative energy sources such as natural gas. When a competitive marketplace exists, customers will make their energy purchasing decision based upon many factors, including price, service and system reliability. To meet these competitive challenges, Domestic Electric Operations is participating in restructuring processes that will determine the shape of future markets, and is pursuing strategies that capitalize on its competitive position, including the development and delivery of innovative products and services. In addition, the Company continues to negotiate long-term and short-term contracts with its existing large volume industrial customers. Although these new agreements have generally resulted in reduced margins, the Company has been successful in retaining many of these customers and extending contract lives. DEREGULATION -- Domestic Electric Operations continues to develop its competitive strategy as legislation, regulation and market opportunities evolve. The Company is advocating federal legislation that would require states to give all consumers choice in their energy provider by January 1, 2001. The Company believes that federal legislation is necessary to address barriers to entry and issues of jurisdiction, to preserve the proper role for the states in implementing customer choice and to bring benefits to consumers as quickly as possible. The move toward an open or competitive marketplace for electric power may result in uneconomic "stranded costs" related 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 will continue to drive retail energy prices down as excess capacity of the existing generation resources persists. This projected price decrease trend is consistent with other commodities and services that have gone through 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. At December 31, 1997, the Company estimates its total stranded costs to range from $1.4 billion to $2.8 billion. This estimate represents the net present value of the difference between the revenues expected under competition and the embedded cost of generating the electricity and providing the service and does not necessarily measure any write off or impairment that would be required. Regulated utilities have historically applied the accounting provisions of Statement of Financial Accounting Standards ("SFAS") 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 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 71, the Company must give consideration to changes in the level of demand or competition during the cost recovery period. In accordance with SFAS 71, Domestic Electric Operations capitalizes certain costs, called regulatory assets, in accordance with regulatory authority whereby those costs will be expensed and recovered in future periods. The Emerging Issues Task Force of the Financial Accounting Standards Board (the "EITF") concluded in 1997 that SFAS 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. In 1996, legislation was passed in California restructuring its electric utility industry. This restructuring is scheduled to begin on March 31, 1998, at which time customers will be able to buy their electricity from sources other than the local utility. The local utility will continue to provide distribution services. Legislation was also passed in Montana in 1997, which established a phased process to introduce price-based competition into the supply of electricity in Montana. As a result - ------------------------------------------------------------------------------- P. 30 PACIFICORP of these legislative actions, prices for the supply of electric generation in California and Montana are, or are expected to be, in transition from cost-based regulated rates to rates determined by competitive market forces. The Company has evaluated its regulatory assets and liabilities related to the generation portion of its business allocable to the states of California and Montana based upon future regulated cash flows. Accordingly, the Company ceased the application of SFAS 71 to its generation business allocable to the states of California and Montana in 1997. Domestic Electric Operations recorded an extraordinary loss of $16 million for the write off of these regulatory assets and liabilities. The Company operates in five other states (Oregon, Utah, Wyoming, Washington and Idaho) which are at various stages of addressing the issue of deregulating the electricity industry. At December 31, 1997, $382 million of the Company's $871 million total regulatory assets was applicable to the generation assets allocable to these five states. The Company intends to seek recovery of its stranded assets, including its $382 million of generation regulatory assets, in Utah, Oregon, Wyoming, Idaho, and Washington. However, due to the current lack of definitive legislation, the Company cannot predict whether it will be successful. Because of the potential regulatory and/or legislative actions in these other state jurisdictions, the Company may have additional 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 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. The Company believes that the regulatory initiatives that are underway in each of the seven states in which it operates will eventually bring competition for the electricity generation services. This change in the regulatory structure may significantly affect the Company's future financial condition and results of operations. ENVIRONMENTAL ISSUES All of the Company's coal burning plants burn low-sulfur coal. Major construction expenditures have already been made at many of these plants to reduce sulfur dioxide ("SO(2)") emissions, but additional expenditures are expected to be required at the Centralia Plant in Washington in which the Company has a 47.5% ownership interest. In late 1997, the Southwest Pollution Control Authority ("SWAPCA") ordered the Centralia Plant to meet new SO(2), nitrogen oxides ("NOx"), carbon dioxide and particulate matter emission limits. These new limits resulted from the application of the Reasonably Available Control Technology process as mandated by SWAPCA and Washington State air quality requirements. The new emission limits will require the plant to install two scrubbers and low NOx burners at a projected cost of $240 million. In addition, the Company and the other joint owners of the Craig Generating Station (the "Station") in Colorado are parties to a lawsuit brought by the Sierra Club alleging violations of the Federal Clean Air Act at the Station, which is operated by the Tri-State Generation and Transmission Association. The Company has a 19.3% interest in Units 1 and 2 of the Station. Actions under the Endangered Species Act with respect to certain salmon and other endangered or threatened species could result in restrictions on the Federal hydropower system and affect regional power supplies and costs. 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. Domestic Electric Operations is currently in the process of relicensing 15 separate hydroelectric projects under the Federal Power Act. These projects, some of which are grouped together under a single license, represent 995 MW, or 93%, of the Company's total hydroelectric capacity. In the new licenses, the Federal Energy Regulatory Commission is expected to impose conditions designed to address the impact of the projects on fish and other environmental concerns. Domestic Electric Operations is unable to predict the impact of imposition of such conditions, but capital expenditures and operating costs are expected to increase in future periods and certain projects may not be economical to operate. Several federal and state environmental cleanup Superfund sites have been identified where Domestic Electric Operations has been, or may be, designated as a potentially responsible party. In such cases, Domestic Electric Operations reviews the circumstances and, where possible, negotiates with other potentially responsible parties to provide funds for clean-up and, if necessary, monitoring activities. 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 these requirements could result in higher expenditures for both capital improvements and operating costs. Future costs associated with the disposition of these matters are not expected to be material to the Company's consolidated financial statements. - ------------------------------------------------------------------------------- PACIFICORP P. 31 AUSTRALIAN ELECTRIC OPERATIONS REVENUES
MILLIONS OF DOLLARS 1997 1996 - ---------------------------------------- Residential $239.2 $239.4 Commercial 207.9 165.5 Industrial 191.8 179.3 Other 77.3 74.6 ------------------ $716.2 $658.8 ------------------ ------------------
ENERGY SALES
MILLIONS OF KWH 1997 1996 - ---------------------------------------- Residential 2,683 2,608 Commercial 3,082 1,926 Industrial 4,755 3,282 Other 524 494 ------------------- 11,044 8,310 ------------------- -------------------
PacifiCorp completed its second successful year of operating Powercor since acquiring the company in December 1995 from the State of Victoria and its first full year of ownership of a 19.9% interest in the Hazelwood Partnership, which owns a 1,600 MW, coal-fired thermal power plant and adjacent coal mine. In 1997, Australian Electric Operations contributed earnings of $54 million, compared to $32 million in 1996. Powercor's expansion of market share in Victoria and the State of New South Wales drove the growth in energy sales and revenues. However, lower market sales prices, partially offset by lower purchased power expense, caused margins on energy sold to decline. CUSTOMERS AND COMPETITION -- POWERCOR Powercor's principal businesses are to purchase electricity supply from a state generation pool, sell electricity to franchise and contestable customers inside and outside its franchise area and 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. Victoria and New South Wales are currently divided between franchised and contestable customers. Customers in both states with annual loads of 750 mWh or more are now contestable and the remaining customers will become contestable over the next few years depending on their energy demand load, with substantially all residential customers remaining franchise customers until 2001. If a Powercor customer chooses a different retailer, Powercor will continue to receive network distribution revenues associated with that customer. At the end of 1997, Powercor had captured contestable market share of 42% in Victoria and 13% in New South Wales, based on energy sold. Additionally, Powercor was granted licenses to sell electricity to customers in the States of Queensland and Australian Capital Territory in early 1998. CURRENCY RISKS Powercor's 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 0.744 in 1997 compared to 0.783 in 1996, a 5% decrease for the year. The effect of the exchange rate fluctuation lowered reported revenues by $33 million and expenses by $31 million in 1997. The currency exchange rate at February 28, 1998 was 0.68. REVENUES -- POWERCOR Powercor reported a $57 million increase in revenues, or 9%, over the prior year. The increase was attributable to a 33% increase in energy sales volumes. Powercor continued to increase market share in the contestable market in Victoria and recorded a 1.5 million kWh increase, or $54 million of higher revenues. In 1997, the first full year of competing in the contestable market in New South Wales, Powercor added 1.4 million kWh and $46 million of revenue. Revenue from inside Powercor's Victorian franchise area decreased $47 million, or 8%, to $539 million. Lower average realized prices reduced revenues by $39 million. Energy volumes decreased 108 million kWh, or $8 million, due to customers lost from the effect of contestability in Powercor's franchise area. Over the last two years, Powercor has lost 185 customers as a result of contestability within its franchise area. Other revenue included $11 million of accelerated amortization of deferred credits associated with the election by certain industrial customers to move from the specified fixed energy price rates under Tariff H to market-based contracts. The deferred credits were recorded at the time of the Powercor acquisition to reflect the anticipated losses associated with the requirements to supply electricity to Tariff H customers. At the end of 1997, Powercor had $4 million of deferred Tariff H credits remaining. - ------------------------------------------------------------------------------- P. 32 PACIFICORP OPERATING EXPENSES -- POWERCOR
MILLIONS OF DOLLARS 1997 1996 - ------------------------------------------------------- Purchased power $308.5 $305.1 Other operations and maintenance 134.0 112.3 Depreciation and amortization 67.1 71.6 Other 56.1 42.4 --------------------- $565.7 $531.4 --------------------- ---------------------
Purchased power expense increased $4 million, or 1%, and represented 55% of Powercor's total operating expenses in 1997. Volumes of purchased power increased 2.7 million kWh, or 33%, adding $101 million to costs, offset in part by lower pool power prices that reduced purchased power expense by $97 million. Purchased power prices averaged $28 per mWh in 1997, compared to $37 per mWh in 1996. Other operations and maintenance expense increased $22 million, or 19%. Increased sales to contestable customers outside Powercor's franchised area resulted in higher network and grid fees of $52 million. This increase was partially offset by higher network revenues of $15 million from customers inside Powercor's franchise area that are serviced by other energy suppliers. A decrease in maintenance expenses of $17 million was attributable to increased productivity and cost reduction efforts. Other expenses increased $14 million, or 32%, due to higher outside services of $10 million and process re-engineering costs of $4 million relating to the new SAP software implementation, completed in 1997. HAZELWOOD For 1997, the Company recorded an after-tax loss of $2 million on its 19.9% ownership interest in the Hazelwood Power Station as compared to an after-tax loss of $1 million in 1996. Hazelwood was purchased in September 1996. REGULATION -- AUSTRALIA 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. Powercor, like each of the other four DBs in the State of Victoria, has been granted an exclusive license to sell electricity to franchise customers whose facilities are in its distribution area and a nonexclusive state-wide license to sell to contestable customers. Hazelwood operates in an area where several large, coal-fired generating facilities are located. It will continue to compete against these plants, as well as others outside the geographic area. Except for power generation and certain contestable accounts, the Australian power industry continues to be a regulated business, albeit a structure that is rapidly changing toward customer choice. Regulation of the Victorian electricity industry is the responsibility of the Office of the Regulator General (the "ORG"), an independent regulatory body. The structure of prices within the Victorian electricity industry reflects the establishment of maximum uniform tariffs that apply to noncontestable customers and some contestable customers. Under applicable regulations, Powercor is required to supply electricity to noncontestable customers at prices that are no greater than the prices specified under the applicable tariffs. The prices specified in the tariffs are all inclusive, including grid charges and energy costs. In general, annual movements in the tariffs for noncontestable customers are based on the Consumer Price Index, a measure of price inflation. Network tariffs include recovery of distribution use of system costs, use of transmission system fees and connection charges. Network tariffs are intended to cover the cost of providing, operating and maintaining the distribution network, except to the extent relevant costs are recoverable through connection charges or other excluded services, and the charges levied for connection to and use of the transmission systems. The first major review of the regulatory arrangements and respective transmission and distribution network charges will be carried out by the ORG, with any changes to apply from January 1, 2001. Any subsequent price control arrangements are required to be in effect for not less than five years. - ------------------------------------------------------------------------------- PACIFICORP P. 33 UNREGULATED ENERGY TRADING(a) REVENUES
MILLIONS OF DOLLARS 1997 1996 - ------------------------------------------------------- TPC $ 815.8 -- PPM 913.2 $11.7 ----------------------- $1,729.0 $11.7 ----------------------- -----------------------
EARNINGS CONTRIBUTION(b)
MILLIONS OF DOLLARS 1997 1996 - ------------------------------------------------------- TPC $(5.9) -- PPM (1.6) $(0.1) ----------------------- $(7.5) $(0.1) ----------------------- -----------------------
(a) Unregulated energy trading excludes Domestic Electric Operations' western wholesale trading. (b) Does not reflect interest expense allocable to investments in this business segment. The Unregulated Energy Trading segment which includes the natural gas and wholesale electricity trading activities of TPC and PPM, respectively, recorded $1.7 billion in revenues, a positive gross margin of $19 million and a net loss of $8 million in 1997. TPC, purchased in April 1997, was anticipated to be dilutive in its first year of operation. For the nine months owned in 1997 it recorded $816 million of revenues, a gross margin of $15 million and a net loss of $6 million. Revenues, gross margin and net income in 1997 included $19 million, $14 million and $3 million, respectively, relating to assets of TPC that were sold in December 1997. PPM continued its expansion in the eastern United States unregulated electricity trading markets with revenues of $913 million and a gross margin of $4 million on electricity sales of 35.8 million kWh. PPM recorded a net loss of $2 million for 1997. Because of the historical and planned increase in trading volumes, revenues and associated working capital requirements, the Company's Board of Directors has set global financial risk limits and net position limits applicable to both regulated and unregulated energy trading. In addition, the Board has delegated routine risk oversight to the Risk Management Oversight Committee (the "RMOC"), which approves trading policies and procedures and portfolio market risk. The Company also has an independent risk manager who monitors market trading risk and reports such risks daily to the RMOC and other key management. - ------------------------------------------------------------------------------- P. 34 PACIFICORP OTHER OPERATIONS EARNINGS CONTRIBUTION
MILLIONS OF DOLLARS 1997 1996 1995 - ----------------------------------------------------------------- PFS $30.2 $34.1 $30.4 PGC 10.4 7.8 5.6 Tax settlement -- -- 32.2 Holdings and other (50.2) (14.8) 18.0 ------------------------------ $(9.6) $27.1 $86.2 ------------------------------ ------------------------------
During 1997, Other Operations included the activities of Holdings, PacifiCorp Financial Services ("PFS"), PGC and several start-up-phase energy ventures. Holdings recorded an after-tax loss of $65 million, or $0.22 per share, in 1997 associated with closing foreign currency options and initial option premium costs relating to the Company's tender offer for TEG, as discussed below. Holdings also recorded an after-tax gain of $30 million, or $0.10 per share, relating to the sale of PGC in November 1997. PGC had ownership interests in numerous independent power production and cogeneration businesses and for the ten months held in 1997, PGC reported net income of $10 million, compared to $8 million for all of 1996. PFS has tax-advantaged investments in affordable housing and leasing operations that consist principally of aircraft leases. For 1997, PFS reported net income of $30 million, a $4 million decrease from 1996. In February 1998, PFS agreed to sell its investments in affordable housing for approximately $81 million and assumption of debt of approximately $161 million. This sale transaction will not have a material impact on 1998 earnings. Holdings and other reported 1997 interest expense of $46 million, a $13 million increase over 1996. This increase was attributable to higher average debt balances due in large part to Holdings' investment in Hazelwood. 1996 COMPARED TO 1995 -- The $59 million decrease in earnings contribution of Other Operations was primarily attributable to the 1995 tax settlement that had the effect of reducing Domestic Electric Operations' earnings by $32 million and increasing Other Operations' earnings by this same amount. The increase in earnings from PFS and PGC were more than offset by a $33 million decrease in the earnings of Holdings and other. This decrease was attributable to $14 million of increased interest expense, as well as expenses incurred by several start- up-phase investments in which investments in personnel and other resources were made. The increased interest expense was attributable in part to Holdings' investment in Powercor. - ------------------------------------------------------------------------------- PACIFICORP P. 35 LIQUIDITY AND CAPITAL RESOURCES CASH FLOW SUMMARY
FORECASTED(a) ACTUAL MILLIONS OF DOLLARS/FOR THE YEAR 2000 1999 1998 1997 1996 1995 - ----------------------------------------------------------------------------------------------------------------------------- NET CASH FLOW FROM CONTINUING OPERATIONS Domestic Electric Operations $727 $718 $ 700 Australian Electric Operations 101 95 10 Unregulated Energy Trading (8) (2) -- Other Operations 4 75 59 ---------------------------------- Total 824 886 769 Cash Dividends Paid 341 346 346 ---------------------------------- NET $550-600 $525-575 $400-450 $483 $540 $ 423 - ------------------------------------------------------------------------------------------------------------------------- CONSTRUCTION Domestic Electric Operations $ 465 $ 480 $ 505 $490 $442 $ 455 Australian Electric Operations 60 55 65 79 80 2 Unregulated Energy Trading -- -- -- 4 -- -- Other Operations -- -- -- 9 7 -- - ------------------------------------------------------------------------------------------------------------------------- Total 525 535 570 582 529 457 ACQUISITIONS AND INVESTMENTS Domestic Electric Operations -- -- 45 -- 154 -- Australian Electric Operations -- 5 15 5 145 1,589 Unregulated Energy Trading -- -- 5 71 -- -- Other Operations 100 100 195(b) 131 49 44 - ------------------------------------------------------------------------------------------------------------------------- Total 100 105 260 207 348 1,633 - ------------------------------------------------------------------------------------------------------------------------- TOTAL CAPITAL SPENDING $ 625 $ 640 $ 830 $789 $877 $2,090 - ------------------------------------------------------------------------------------------------------------------------- MATURITIES OF LONG-TERM DEBT Domestic Electric Operations $ 180 $ 299 $ 197 $208 $182 $ 51 Australian Electric Operations -- -- -- 3 42 -- Other Operations 1 1 169 10 19 29 - ------------------------------------------------------------------------------------------------------------------------- Total $ 181 $ 300 $ 366 $221 $243 $ 80 - ------------------------------------------------------------------------------------------------------------------------- Other Refinancings $699 $ 42 $ 125 - -------------------------------------------------------------------------------------------------------------------------
(a) Does not include forward-looking information with regard to the proposed acquisition of TEG. (b) Assumes international energy investments. - ------------------------------------------------------------------------------- P. 36 PACIFICORP - ------------------------------------------------------------------------------- OPERATING ACTIVITIES Cash flows from continuing operations decreased $62 million from 1996 to 1997. Cash expenditures relating to the proposed acquisition of TEG were the primary cause of the $71 million decrease in operating cash flows from Other Operations. INVESTING ACTIVITIES During 1997, the Company generated $1.8 billion of cash from asset sales. Apart from the asset sales, investing activities were comprised primarily of capital spending to improve and expand existing operations and the acquisition of TPC. In order to sharpen its focus in the energy sector and as part of the financing of the proposed TEG acquisition, the Company sold PTI in December 1997 for $1.5 billion in cash plus the assumption of PTI's debt and, in November 1997, PGC was sold for $150 million in cash, which included settlement of intercompany account balances. On April 15, 1997, the Company expanded into natural gas marketing by acquiring all of the outstanding shares of common stock of TPC, a natural gas gathering, processing, storage and marketing company based in Houston, Texas, for approximately $265 million in cash and assumed debt of approximately $140 million. In December 1997, TPC sold its natural gas gathering and processing systems for $195 million in cash before tax payments of $23 million. During 1997, the Company continued to invest in new, energy-related ventures and expects to continue to do so during 1998. Construction spending for production, transmission, distribution and other purposes at Domestic Electric Operations increased from $442 million in 1996 to $490 million in 1997. The Company believes that its existing and available capital resources are sufficient to meet working capital, dividend and construction needs in 1998. PLANNED EXPANSION The Company continuously explores opportunities for growth in unregulated domestic and international energy markets. The Company believes the experience gained by focusing on the unregulated marketplace will facilitate the conversion of the Company's Domestic Electric Operations to a market driven by customer choice. PROPOSED ACQUISITION On June 13, 1997, PacifiCorp announced a cash tender offer for TEG. TEG is a diversified international energy group with operations in the United Kingdom (the "UK"), the United States and Australia and includes Eastern Group PLC, one of the leading integrated electricity and gas groups in the UK and Peabody Holding Company, Inc., the world's largest private producer of coal. The Company's initial offer lapsed on August 1, 1997 when it was referred to the Monopolies and Mergers Commission (the "MMC") by the President of the Board of Trade in the UK. The proposed acquisition of TEG by PacifiCorp was subsequently cleared by the President of the Board of Trade on December 19, 1997. On February 3, 1998, PacifiCorp announced the terms of a renewed cash tender offer for TEG of 765 pence for each ordinary share. On March 2, 1998, Texas Utilities Company ("TU") announced an offer of 810 pence for each TEG share. Following TU's announcement, PacifiCorp announced an increased cash offer of 820 pence for each TEG share. This increased offer values the transaction at $11.1 billion, including the purchase of 521 million shares and the assumption of $4.1 billion of TEG's debt. The acquisition was to be financed with cash raised through sales of noncore assets of subsidiaries of Holdings (see Notes 3 and 15) and borrowings by subsidiaries of Holdings. PacifiCorp's announcement of the increased offer followed the acquisition on March 2, 1998 by a subsidiary of Holdings of approximately 46 million TEG shares at a price of 820 pence per share. These shares represent approximately 8.8% of the outstanding share capital of TEG. On March 3, 1998, TU announced that it was increasing its offer to 840 pence for each TEG share. TU's offer is subject to clearance by the UK Secretary of State for Trade and Industry and certain other regulatory bodies. TU has also announced that it has acquired approximately 15% of the outstanding share capital of TEG. The Company is required under the rules of the UK takeover code to demonstrate that it has both adequate committed financing and the appropriate amount of sterling to eliminate the risk of exchange rate changes between the offer announcement date and the expected closing date. The Company met these requirements with its acquisition finance facilities and cash resources and by entering into foreign currency exchange contracts. Because the underlying asset has not been acquired, these foreign currency exchange contracts do not meet the criteria for hedge accounting and as a result are required to be marked-to-market in each accounting period while outstanding. The Company estimates that as of December 31, 1997, it had incurred approximately $68 million of pretax costs relating to the TEG transaction for bank commitment and facility fees, legal expenses and other related costs. As a result of the TU offer, there is risk that a transaction with TEG will not occur. If it becomes likely that the transaction will not occur or significant uncertainty arises, the Company will write off these transaction costs as a charge to income. - ------------------------------------------------------------------------------- PACIFICORP P. 37 CAPITALIZATION
MILLIONS OF DOLLARS EXCEPT PERCENTAGES 1997 1996 - -------------------------------------------------------------------------------- Long-term debt $4,239 43% $ 4,653 45% Common equity 4,321 44 4,032 39 Short-term debt 555 5 903 9 Preferred stock 241 2 314 3 Preferred securities of Trusts 340 4 210 2 Quarterly income debt securities 176 2 176 2 ----------------------------------------------- Total Capitalization $9,872 100% $10,288 100% ----------------------------------------------- -----------------------------------------------
VARIABLE RATE LIABILITIES
MILLIONS OF DOLLARS 1997 1996 - ----------------------------------------------------- Domestic Electric Operations $ 760 $1,090 Australian Electric Operations 269 511 Holdings and other 26 202 ------------------- $1,055 $1,803 ------------------- ------------------- Percentage of Total Capitalization 11% 18%
The Company manages its capitalization and liquidity position in a consolidated manner through policies established by senior management and approved by the Finance Committee of the Board of Directors. These policies have resulted from a review of historical and projected practices for businesses and industries that have financial and operating characteristics similar to PacifiCorp and its principal business operations. The Company's policies attempt to balance the interests of its 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 must 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 50% at December 31, 1997 after giving effect to before mentioned asset sales. The Company continually evaluates the advantages of common stock issuances in the context of its current capital structure, financing needs and market price. Depending on this evaluation and events surrounding the TEG acquisition, the Company may offer additional shares of common stock to the public in 1998. EQUITY AND DEBT TRANSACTIONS In August 1997, a wholly owned subsidiary trust (the "Trust") issued, in a public offering, 5.4 million of its 7.70% Preferred Securities, Series B, for net proceeds of $135 million. The sole asset of the Trust is $139 million of Series D Debentures issued by the Company to the Trust. During 1997, the Company also issued 1.8 million shares of its common stock under the dividend reinvestment and stock purchase plan, raising $37 million. In March and September 1997, the Company redeemed all outstanding shares of its $7.12 and $1.98 No Par Serial Preferred Stock, respectively. The aggregate stated value of the shares redeemed was $72 million. In July 1997, the Company issued $300 million of secured medium-term notes in the form of First Mortgage and Collateral Trust Bonds as follows: $175 million of 6.75% notes due July 15, 2004 and $125 million of 7% notes due July 15, 2009. In early 1998, Australian Electric Operations issued $400 million of 6.15% United States denominated notes due 2008. The funds were used to repay Australian bank bill borrowings. AVAILABLE CREDIT FACILITIES At December 31, 1997, PacifiCorp had $700 million of committed bank revolving credit agreements. Regulatory authorities limited PacifiCorp to $1 billion of short-term debt, of which $303 million was outstanding at December 31, 1997. At December 31, 1997, subsidiaries of PacifiCorp had $1 billion of committed bank revolving credit agreements. The Company had $878 million of short-term debt classified as long-term debt at December 31, 1997, as it had the intent and ability to support short-term borrowings through the various revolving credit facilities on a long-term basis. See Notes 6 and 7 to the Consolidated Financial Statements for additional information. LIMITATIONS In addition to the Company's capital structure policies, its debt capacity is also governed by its credit agreements. Based on the Company's most restrictive credit agreements, management believes PacifiCorp and its subsidiaries could have borrowed an additional $2.2 billion of debt at December 31, 1997. PacifiCorp's principal debt limitation is a 60% debt to capitalization test contained in its principal credit agreements. Considering such limitation, an additional $560 million of debt was available to PacifiCorp at December 31, 1997. - ------------------------------------------------------------------------------- P. 38 PACIFICORP - ------------------------------------------------------------------------------- Under the Company's principal credit agreement, it is an event of default if any person or group acquires 35% or more of the Company's common shares or if, during any period of 14 consecutive months, individuals who were directors of the Company 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. RISK MANAGEMENT The risk management process established by the Company is designed to measure both quantitative and qualitative risks in its businesses. Two senior risk management committees have been established to review these risks on a regular basis. The Company is exposed to market risk, including changes in interest rates, currency exchange rates and certain commodity prices. To manage the volatility relating to these exposures, the Company enters into various derivative transactions pursuant to the Company's policies on hedging practices. Derivative positions are monitored using techniques such as market value, sensitivity analysis and a value at risk model. 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 model assumes that financial returns are log normally distributed. Estimates of volatility are drawn from actual historical market volatility calculated over the past 250-day period. The model includes all the Company's debt as well as all interest rate and foreign exchange derivative contracts. The interest rate exposure is primarily related to long-term debt with fixed interest rates. The VAR model is a risk analysis tool which measures 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, nor does it consider the potential effect of favorable changes in market factors. INTEREST RATE EXPOSURE The Company uses interest rate swaps, forwards, futures and collars 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. Based on the Company's overall interest rate exposure, the estimated maximum potential one-day loss in fair value as a result of a near-term change in interest rates, within a 95% confidence level using historical interest rate movements based on the VAR model, was $28 million at December 31, 1997. This interest rate exposure is primarily related to long-term debt with fixed interest rates. CURRENCY RATE EXPOSURE The Company utilizes foreign currency hedging activities to protect against the volatility associated with its net investment in Australian Electric Operations. Corporate policy prescribes the range of allowable foreign currency hedging activity. Results of hedging activities relating to foreign net asset exposure are reflected in the currency translation adjustments section of shareholders' equity, offsetting a portion of the translation of the net assets of Australian Electric Operations. Gains and losses related 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. Based on the Company's overall currency rate exposure at December 31, 1997, including derivative instruments, a near-term change in currency rates within a 95% confidence level based on historical currency rate movements, would not materially affect the consolidated financial position, results of operations, or cash flows of the Company. COMMODITY PRICE EXPOSURE The price of electricity and natural gas commodities are subject to fluctuations due to unpredictable factors, such as weather, which impacts supply and demand. To reduce price risk caused by electricity and natural gas market fluctuations, the Company generally follows a policy of hedging a portion of its purchase and sales commitments. The instruments used are principally readily marketable exchange traded futures contracts which are designated as hedges. The Company has also utilized electricity forward contacts (referred to as "contract 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. The changes in market value of such contracts have a high correlation to the price changes of the hedged commodity. - ------------------------------------------------------------------------------- PACIFICORP P. 39 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 of its derivative position for both natural gas and electricity. The Company's daily commodity derivative position consists of exchange traded contracts and futures contracts that hedge portions of commodity delivery requirements. 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. Market risk is estimated as the potential loss in fair value, earnings or cash flows resulting from a hypothetical 10% adverse change in such prices. Based on the Company's derivative price exposure at December 31, 1997, a near-term adverse change in commodity prices of 10% would have an impact on results of operations and cash flows of approximately $39 million before income taxes. 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. YEAR 2000 PacifiCorp has initiated an enterprise-wide program to assess and mitigate or eliminate the business risk associated with year 2000 issues within PacifiCorp's information technology and communication systems, as well as similar risks related to transactions with other businesses. The systems that could be affected by year 2000 issues have been identified and an implementation plan has been developed. It is not certain whether the Company's year 2000 project will be completed on a timely basis or what the impact of third-party computer system failures might be. The Company estimates that it will incur expenses of approximately $12 million to $20 million for management information technology systems over the next two years on the year 2000 project. The Company has not yet determined the amount of year 2000 project expenses it will incur related to its operations process control systems. NEW ACCOUNTING STANDARDS In June 1997, the Financial Accounting Standards Board (the "FASB") issued SFAS 130, "Reporting Comprehensive Income," and SFAS 131, "Disclosures About Segments of an Enterprise and Related Information." SFAS 130 establishes standards for reporting and display of comprehensive income in financial statements. SFAS 131 requires that companies disclose segment data based on how management makes decisions about allocating resources to segments and measuring performance. In February 1998, the FASB issued SFAS 132, "Employers' Disclosures About Pensions and Other Postretirement Benefits." These standards are effective for fiscal years beginning after December 15, 1997. Adoption of these standards may result in additional financial disclosure but will not have an effect on the Company's financial position or results of operations. 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 factors are among the factors that could cause actual results to differ materially from the forward-looking statements: utility commission practices; regional and international economic conditions; weather variations affecting customer usage; competition in bulk power and natural gas markets and hydroelectric and natural gas production; wholesale energy trading; unregulated energy trading; environmental, regulatory and tax legislation, including industry restructure and deregulation initiatives; technological developments in the electricity industry; and the cost of debt and equity capital. Any forward-looking statements issued by the Company should be considered in light of these factors. - ------------------------------------------------------------------------------- P. 40 PACIFICORP REPORT OF MANAGEMENT The management of PacifiCorp 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 Deloitte & Touche LLP ("Deloitte & Touche"), independent public accountants. Management made available to 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. Deloitte & Touche considered that internal control structure in connection with their audit. Management reviews significant recommendations by the internal auditors and Deloitte & Touche concerning the Company's internal control structure and ensures appropriate cost-effective actions are taken. The Company's "Guide to Business Conduct" is distributed to employees throughout the Company to provide a basis for ethical standards and conduct. The guide addresses, among other things, potential conflicts of interests and compliance with laws, including those relating to financial disclosure and the confidentiality of proprietary information. In early 1998, the Company formed a Business Conduct Group in order to dedicate more resources to business conduct issues, and to provide more consistent and thorough communications and training in legal compliance and ethical conduct. The Audit Committee of the Board of Directors is comprised solely of outside directors. It meets at least quarterly with management, Deloitte & Touche, internal auditors and counsel to review the work of each and ensure the Committee's responsibilities are being properly discharged. Deloitte & Touche and internal auditors have free access to the Committee, without management present, to discuss, among other things, their audit work and their evaluations of the adequacy of the internal control structure and the quality of financial reporting. /s/ Richard T. O'Brien RICHARD T. O'BRIEN Senior Vice President and Chief Financial Officer INDEPENDENT AUDITORS' REPORT TO THE SHAREHOLDERS AND BOARD OF DIRECTORS OF PACIFICORP: We have audited the accompanying consolidated balance sheets of PacifiCorp and subsidiaries as of December 31, 1997 and 1996, and the related statements of consolidated income and retained earnings and of consolidated cash flows for each of the three years in the period ended December 31, 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 generally accepted auditing standards. 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, 1997 and 1996, and the results of their operations and their cash flows for each of three years in the period ended December 31, 1997, in conformity with generally accepted accounting principles. /s/ Deloitte & Touche LLP DELOITTE & TOUCHE LLP Portland, Oregon February 3, 1998 (March 2, 1998 as to Note 2) - ------------------------------------------------------------------------------- PACIFICORP P. 41 STATEMENTS OF CONSOLIDATED INCOME AND RETAINED EARNINGS
MILLIONS OF DOLLARS, EXCEPT PER SHARE AMOUNTS/FOR THE YEAR 1997 1996 1995 - ----------------------------------------------------------------------------------------------- REVENUES $6,278.0 $3,803.7 $2,806.8 ----------------------------------- EXPENSES Operations and maintenance 4,394.0 1,949.3 1,291.6 Administrative and general 334.4 244.8 186.6 Depreciation and amortization 476.9 423.8 333.7 Taxes, other than income taxes 99.8 99.4 104.3 Special charges 170.4 -- -- ----------------------------------- Total 5,475.5 2,717.3 1,916.2 ----------------------------------- INCOME FROM OPERATIONS 802.5 1,086.4 890.6 ----------------------------------- INTEREST EXPENSE AND OTHER Interest expense 439.5 415.0 336.4 Interest capitalized (12.5) (11.4) (14.9) Minority interest and other 40.6 16.2 (24.7) ----------------------------------- Total 467.6 419.8 296.8 ----------------------------------- Income from continuing operations before income taxes 334.9 666.6 593.8 Income tax expense 109.5 236.4 191.8 ----------------------------------- INCOME FROM CONTINUING OPERATIONS BEFORE EXTRAORDINARY ITEM 225.4 430.2 402.0 DISCONTINUED OPERATIONS (less applicable income tax expense: 1997/$363.4, 1996/$47.5 and 1995/$47.0) 454.3 74.7 103.0 EXTRAORDINARY LOSS FROM REGULATORY ASSET IMPAIRMENT (less applicable income tax expense of $9.6) (16.0) -- -- ----------------------------------- NET INCOME 663.7 504.9 505.0 RETAINED EARNINGS, JANUARY 1 782.8 632.4 474.3 Cash dividends declared Preferred stock (20.0) (29.1) (38.4) Common stock per share of $1.08 (320.0) (317.9) (306.6) Preferred stock retired (0.2) (7.5) (1.9) ----------------------------------- RETAINED EARNINGS, DECEMBER 31 $1,106.3 $782.8 $ 632.4 ----------------------------------- EARNINGS ON COMMON STOCK $ 640.9 $475.1 $ 466.3 AVERAGE NUMBER OF COMMON SHARES OUTSTANDING -- basic (Thousands) 296,094 292,424 284,272 EARNINGS PER COMMON SHARE -- BASIC AND DILUTIVE Continuing operations $0.68 $1.37 $ 1.28 Discontinued operations 1.53 0.25 0.36 Extraordinary item (0.05) -- -- ----------------------------------- Total $ 2.16 $ 1.62 $ 1.64 ----------------------------------- -----------------------------------
(See accompanying Notes to Consolidated Financial Statements) - ------------------------------------------------------------------------------- P. 42 PACIFICORP STATEMENTS OF CONSOLIDATED CASH FLOWS
MILLIONS OF DOLLARS/FOR THE YEAR 1997 1996 1995 - ----------------------------------------------------------------------------------------------- CASH FLOWS FROM OPERATING ACTIVITIES Net Income $ 663.7 $ 504.9 $ 505.0 Adjustments to reconcile net income to net cash provided by continuing operations Income from discontinued operations (89.2) (74.7) (103.0) Gain on disposal of discontinued operations (365.1) -- -- Extraordinary loss from regulatory asset impairment 16.0 -- -- Depreciation and amortization 492.2 440.5 372.2 Deferred income taxes and investment tax credits -- net (81.6) 26.1 38.0 Special charges 170.4 -- -- Gain on sale of subsidiary (56.5) -- -- Other 19.0 (27.1) 12.0 Accounts receivable and prepayments (281.6) (158.5) (36.0) Materials, supplies, fuel stock and inventory (3.4) 26.8 (11.2) Accounts payable and accrued liabilities 340.1 148.1 (7.6) --------------------------------------- Net cash provided by continuing operations 824.0 886.1 769.4 Net cash provided by (used in) discontinued operations 10.1 39.6 (94.1) --------------------------------------- Net Cash Provided by Operating Activities 834.1 925.7 675.3 --------------------------------------- CASH FLOWS FROM INVESTING ACTIVITIES Construction (581.7) (528.4) (456.8) Operating companies and assets acquired (135.0) (199.4) (1,633.7) Investments in and advances to affiliated companies -- net (72.3) (148.4) 0.3 Proceeds from sales of assets 1,666.3 49.3 137.9 Proceeds from sales of finance assets and principal payments 103.2 55.8 36.6 Other (58.5) (10.5) (27.4) --------------------------------------- Net Cash Provided by (Used in) Investing Activities 922.0 (781.6) (1,943.1) --------------------------------------- CASH FLOWS FROM FINANCING ACTIVITIES Changes in short-term debt (494.4) (247.6) 499.6 Proceeds from long-term debt 726.4 567.6 1,376.9 Proceeds from issuance of common stock 37.2 221.3 0.4 Proceeds from issuance of preferred securities of Trust holding solely PacifiCorp debentures 130.6 209.6 -- Dividends paid (341.2) (346.4) (346.5) Repayments of long-term debt (919.8) (284.5) (204.4) Redemptions of capital stock (72.2) (221.6) (2.6) Other (89.8) (49.9) (53.2) --------------------------------------- Net Cash Provided by (Used in) Financing Activities (1,023.2) (151.5) 1,270.2 --------------------------------------- Increase/(Decrease) in Cash and Cash Equivalents 732.9 (7.4) 2.4 Cash and Cash Equivalents at Beginning of Year 8.4 15.8 13.4 --------------------------------------- Cash and Cash Equivalents at End of Year $ 741.3 $8.4 $15.8 --------------------------------------- ---------------------------------------
(See accompanying Notes to Consolidated Financial Statements) - ------------------------------------------------------------------------------- PACIFICORP P. 43 CONSOLIDATED BALANCE SHEETS ASSETS
MILLIONS OF DOLLARS/DECEMBER 31 1997 1996 - ------------------------------------------------------------------------------- CURRENT ASSETS Cash and cash equivalents $ 741.3 $ 8.4 Accounts receivable less allowance for doubtful accounts: 1997/$18.8 and 1996/$8.5 919.5 620.9 Materials, supplies and fuel stock at average cost 194.3 181.3 Net assets of discontinued operations -- 779.5 Real estate investments held for sale 272.2 -- Other 55.0 71.8 ------------------------ Total Current Assets 2,182.3 1,661.9 PROPERTY, PLANT AND EQUIPMENT Domestic Electric Operations Production 4,720.6 4,659.2 Transmission 2,087.8 2,069.2 Distribution 3,244.0 3,029.7 Other 1,784.8 1,687.9 Construction work in progress 257.4 252.8 ------------------------ Total Domestic Electric Operations 12,094.6 11,698.8 Australian Electric Operations 1,161.2 1,361.9 Other Operations 56.9 68.8 Accumulated depreciation and amortization (4,242.4) (3,862.4) ------------------------ Total Property, Plant and Equipment -- Net 9,070.3 9,267.1 OTHER ASSETS Investments in and advances to affiliated companies 281.6 253.9 Intangible assets -- net 524.9 480.7 Regulatory assets -- net 871.1 1,022.8 Finance note receivable 211.2 214.6 Finance assets -- net 349.8 425.6 Real estate investments -- 217.0 Deferred charges and other 389.0 268.7 ------------------------ Total Other Assets 2,627.6 2,883.3 ------------------------ TOTAL ASSETS $13,880.2 $13,812.3 ------------------------ ------------------------
(See accompanying Notes to Consolidated Financial Statements) - ------------------------------------------------------------------------------- P. 44 PACIFICORP LIABILITIES AND SHAREHOLDERS' EQUITY
MILLIONS OF DOLLARS/DECEMBER 31 1997 1996 - -------------------------------------------------------------------------------- CURRENT LIABILITIES Long-term debt currently maturing $ 365.5 $ 219.8 Notes payable and commercial paper 189.2 683.5 Accounts payable 630.7 477.5 Taxes, interest and dividends payable 701.2 290.8 Customer deposits and other 218.9 83.7 ------------------------ Total Current Liabilities 2,105.5 1,755.3 DEFERRED CREDITS Income taxes 1,676.1 1,801.0 Investment tax credits 135.2 143.2 Other 646.2 727.9 ------------------------ Total Deferred Credits 2,457.5 2,672.1 LONG-TERM DEBT 4,414.5 4,829.4 COMMITMENTS AND CONTINGENCIES (See Note 12) -- -- GUARANTEED PREFERRED BENEFICIAL INTERESTS IN COMPANY'S JUNIOR SUBORDINATED DEBENTURES 340.4 209.7 PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION 175.0 178.0 PREFERRED STOCK 66.4 135.5 COMMON EQUITY Common shareholders' capital shares authorized 750,000,000; shares outstanding: 1997/296,908,110 and 1996/295,139,753 3,274.2 3,236.8 Retained earnings 1,106.3 782.8 Cumulative currency translation adjustment (59.6) 12.7 ------------------------ Total Common Equity 4,320.9 4,032.3 ------------------------ TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $13,880.2 $13,812.3 ------------------------ ------------------------
(See accompanying Notes to Consolidated Financial Statements) - ------------------------------------------------------------------------------- PACIFICORP P. 45 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995 NOTE 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES BASIS OF PRESENTATION The consolidated financial statements of PacifiCorp (the "Company") include its 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, formerly PacifiCorp Holdings, Inc. ("Holdings"), which holds all of the Company's nonintegrated electric utility investments, including Powercor Australia Limited ("Powercor"), an Australian electricity distributor purchased December 12, 1995; PacifiCorp Financial Services, Inc. ("PFS"), a financial services business; PacifiCorp Power Marketing ("PPM"), engaged in wholesale electricity trading in the eastern United States energy markets; and TPC Corporation ("TPC"), a natural gas marketing and storage company, purchased April 15, 1997. Together these businesses are referred to herein as the Companies. Significant intercompany transactions and balances have been eliminated. 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. The Company sold its wholly owned telecommunications subsidiary, Pacific Telecom, Inc. ("PTI"), on December 1, 1997. See Note 3. 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. In addition, the Company has signed letters of intent to sell the real estate assets held by PFS. See Note 15. 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 majority of 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 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") 71, "Accounting for the Effects of Certain Types of Regulation." See Note 4. 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. Impairment losses on long-lived assets are recognized when book values exceed expected undiscounted future cash flows. If impairment exists, the asset's book value will be written down to its fair value. CASH AND CASH EQUIVALENTS For the purposes of these financial statements, the Company considers all liquid investments with original maturities of three months or less to be cash equivalents. FOREIGN CURRENCY TRANSLATION 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 exchange gains or losses are accumulated in the "cumulative currency translation adjustment" account, a component of common equity. All gains and losses resulting from foreign currency transactions are included in the determination of 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. DEPRECIATION AND AMORTIZATION At December 31, 1997, the average depreciable lives of prop-erty, plant and equipment by category were: Domestic Electric Operations -- Production, 35 years; Transmission, 42 years; Distribution, 31 years; Other, 16 years; and Australian Electric Operations, 20 years. Depreciation and amortization is generally computed by the straight-line method in the following manner: As prescribed by the Company's various regulatory jurisdictions for Domestic Electric Operations' regulated assets; and over the estimated useful lives of the related assets for Domestic Electric Operations' nonregulated generation resource assets and for other nonregulated assets. Provisions for depreciation (excluding amortization of capital leases) in the domestic electric and Australian electric businesses were 3.4%, 3.2% and 3.0% of average depreciable assets in 1997, 1996 and 1995, respectively. - ------------------------------------------------------------------------------- P. 46 PACIFICORP MINE RECLAMATION AND CLOSURE COSTS The Company expenses current mine reclamation costs and accrues for estimated final mine reclamation and closure costs using the units-of-production method. 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 ($393 million and $26 million, respectively, in 1997 and $460 million and $32 million, respectively, in 1996) and excess cost over net assets of businesses acquired ($129 million in 1997). These costs are offset by accumulated amortization ($23 million in 1997 and $11 million in 1996). Licenses and other intangible costs are generally being amortized over 40 years and excess cost over net assets of businesses acquired is being amortized over 30 years. Had Australian Electric Operations' 1996 intangible asset amounts been converted to United States dollars at 1997 rates, 1996 intangible assets-net would have been $73 million lower than reported. 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 allowances for credit losses and accumulated impairment charges of $47 million and $63 million at December 31, 1997 and 1996, respectively. 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 related 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. INTEREST CAPITALIZED Costs of debt and equity applicable to domestic electric utility properties are capitalized during construction. The composite capitalization rates were 5.7% for 1997, 5.6% for 1996 and 6.2% for 1995. 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 4. 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. REVENUE RECOGNITION The Company accrues estimated unbilled revenues for electric services provided after cycle billing to month-end. UNREGULATED ENERGY TRADING ACTIVITIES Revenues and purchased energy expense for the Company's unregulated energy trading businesses are recorded upon delivery or settlement of natural gas and electricity. PREFERRED STOCK RETIRED Amounts paid in excess of the net carrying value of preferred stock retired are amortized in accordance with regulatory orders. STOCK BASED COMPENSATION The Company has elected to follow Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" ("APB 25") and related interpretations in accounting for 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 is recorded. EARNINGS PER SHARE The Company computes Earnings per Share ("EPS") based on SFAS 128, "Earnings per Share," which was issued during 1997. Basic EPS is computed by dividing earnings on common stock by the weighted average number of common shares outstanding. Diluted EPS for the Company is computed by dividing earnings on common stock by the weighted average number of common shares outstanding, including shares that would be outstanding assuming the exercise of granted stock options. The Company's basic and diluted EPS are the same for all periods presented herein. RECLASSIFICATION Certain amounts from prior years have been reclassified to conform with the 1997 method of presentation. These reclassifications had no effect on previously reported consolidated net income. - ------------------------------------------------------------------------------- PACIFICORP P. 47 NOTE 2 PROPOSED ACQUISITION On June 13, 1997, PacifiCorp announced a cash tender offer for The Energy Group PLC ("TEG"). TEG is a diversified international energy group with operations in the United Kingdom (the "UK"), the United States and Australia and includes Eastern Group PLC, one of the leading integrated electricity and gas groups in the UK and Peabody Holding Company, Inc., the world's largest private producer of coal. The Company's initial offer lapsed on August 1, 1997 when it was referred to the Monopolies and Mergers Commission (the "MMC") by the President of the Board of Trade in the UK. The proposed acquisition of TEG by PacifiCorp was subsequently cleared by the President of the Board of Trade on December 19, 1997. On February 3, 1998, PacifiCorp announced the terms of a renewed cash tender offer for TEG of 765 pence for each ordinary share. On March 2, 1998, Texas Utilities Company ("TU") announced an offer of 810 pence for each TEG share. Following TU's announcement, PacifiCorp announced an increased cash offer of 820 pence for each TEG share. This increased offer values the transaction at $11.1 billion, including the purchase of 521 million shares and the assumption of $4.1 billion of TEG's debt. The acquisition was to be financed with cash raised through sales of noncore assets of subsidiaries of Holdings (see Notes 3 and 15) and borrowings by subsidiaries of Holdings. PacifiCorp's announcement of the increased offer followed the acquisition on March 2, 1998 by a subsidiary of Holdings of approximately 46 million TEG shares at a price of 820 pence per share. These shares represent approximately 8.8% of the outstanding share capital of TEG. On March 3, 1998, TU announced that it was increasing its offer to 840 pence for each TEG share. TU's offer is subject to clearance by the UK Secretary of State for Trade and Industry and certain other regulatory bodies. TU has also announced that it has acquired approximately 15% of the outstanding share capital of TEG. 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 MMC 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 an after-tax loss of approximately $65 million, or $0.22 per share, in the third quarter of 1997. Additionally, the Company estimates that as of December 31, 1997, it had incurred approximately $68 million of other pre-tax costs relating to the TEG transaction for bank commitment and facility fees, legal expenses and other related costs. There is risk that a transaction with TEG will not occur. If it becomes likely that the transaction will not occur or significant uncertainty arises, the Company will write off these transaction costs as a charge to income. NOTE 3 DISCONTINUED OPERATIONS On December 1, 1997, Holdings completed the sale of 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, or $1.23 per share. A portion of the proceeds from the sale of PTI were used to 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. Summarized operating results for PTI, excluding gain on sale, were as follows:
ELEVEN MONTHS FOR THE YEARS ENDED NOVEMBER 30 ENDED DECEMBER 31 MILLIONS OF DOLLARS 1997 1996 1995 - ------------------------------------------------------------------------------- Revenues $522.4 $521.1 $640.1 ---------------------------------------- Income before income taxes $146.8 $122.2 $150.0 Income taxes 57.6 47.5 47.0 ---------------------------------------- Net income(a) $89.2 $74.7 $103.0 ---------------------------------------- Earnings per share(a) $0.30 $0.25 $0.36 ----------------------------------------
(a) Results in 1995 included $37 million, or $0.13 per share, relating to the sale of PTI's long-distance telecommunications subsidiary. Net assets of the discontinued operations of PTI consisted of the following:
MILLIONS OF DOLLARS/DECEMBER 31 1996 - --------------------------------------------- Current assets $ 238.5 Noncurrent assets 1,463.4 Notes payable and commercial paper (18.0) Long-term debt currently maturing (15.8) Other current liabilities (136.1) Long-term debt (527.9) Noncurrent liabilities (207.4) Minority interest (17.2) --------- Net Assets of Discontinued Operations $ 779.5 ---------
- ------------------------------------------------------------------------------- P. 48 PACIFICORP NOTE 4 ACCOUNTING FOR THE EFFECTS OF REGULATION Regulated utilities have historically applied the provisions of SFAS 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 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 71, the Company must give consideration to changes in the level of demand or competition during the cost recovery period. In accordance with SFAS 71, Domestic Electric Operations capitalizes certain costs, regulatory assets, in accordance with regulatory authority whereby those costs will be expensed and recovered in future periods. The Emerging Issues Task Force of the Financial Accounting Standards Board (the "EITF") concluded in 1997 that SFAS 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. In 1996, legislation was passed in California restructuring its electric utility industry. The restructuring is scheduled to begin on March 31, 1998, at which time customers will be able to buy their electricity from sources other than the local utility. The local utility will continue to provide distribution services. Legislation was also passed in Montana in 1997 which established a phased process to introduce price-based competition into the supply of electricity in Montana. As a result of these legislative actions, prices for the supply of electric generation in California and Montana are, or are expected to be, in transition from cost-based regulated rates to rates determined by competitive market forces. Regulatory assets-net included the following:
MILLIONS OF DOLLARS/DECEMBER 31 1997 1996 - --------------------------------------------------------------- Deferred taxes - net(a) $650.1 $ 676.0 Deferred pension costs -- 102.9 Demand-side resource costs 108.3 118.8 Unamortized net loss on reacquired debt 60.6 68.4 Unrecovered Trojan Plant and regulatory study costs 23.0 26.8 Various other costs 29.1 29.9 --------------------- Total $871.1 $1,022.8 --------------------- ---------------------
(a) Excludes $135 million of investment tax credit regulatory liabilities. The Company has evaluated its regulatory assets and liabilities related to the generation portion of its business allocable to the states of California and Montana based upon future regulated cash flows. Accordingly, the Company ceased the application of SFAS 71 to its generation business allocable to the states of California and Montana in 1997. Domestic Electric Operations recorded an extraordinary loss of $16 million, or $0.05 per share, for the write off of these regulatory assets and liabilities. The Company operates in five other states (Oregon, Utah, Wyoming, Washington and Idaho) which are at various stages of addressing the issue of deregulating the electricity industry. At December 31, 1997, $382 million of the $871 million total regulatory assets-net was applicable to the generation assets allocable to these five states. Because of the potential regulatory and/or legislative actions in these other state jurisdictions, the Company may have additional regulatory asset write offs and charges for impairment of long-lived assets in future periods relating to the generation portion of its business. Also in 1997, the Company evaluated all its regulatory assets and liabilities applicable to deferred pension costs which relate primarily to a deferred compensation plan and early retirement incentive programs in 1987 and 1990 and determined that recovery of these costs was not probable. As a result, the Company recorded an $87 million write off of its deferred regulatory pension asset, since the Company does not intend to seek recovery of these costs. However, the Company will seek recovery for its current and future pension costs. In early 1997, the Division of Public Utilities (the "DPU") and the Committee of Consumer Services (the "CCS") in Utah filed a joint petition with the Utah Public Service Commission (the "PSC") requesting the PSC to commence proceedings to establish new rates for Utah customers. The DPU indicated that rates could be reduced by approximately $54 million. Subsequently in March 1997, the Utah Legislature passed a bill that created a legislative task force to study electrical restructuring and customer choice issues in the State of Utah. The bill precluded the PSC from holding hearings on rate changes and froze prices at January 31, 1997 levels until May 1998, but allowed for retroactive price changes. The Company agreed to an interim price decrease to Utah customers of $12.4 million annually beginning on April 15, 1997. During the freeze period, the PSC proceeded with hearings on the proper method for cost allocation among PacifiCorp's seven jurisdictions that would be used in the 1998 rate case. The DPU recommended an allocation method that would reduce prices by $56 million over five years, of which $14 million was included in its original estimate of $54 million. During these hearings, the CCS recommended a method that would reduce prices by $96 million, or $42 million more than the original DPU estimate. The Company advocated a method that would result in a decrease of approximately $3 million per year. The PSC held hearings in December and an order is expected in early 1998. An allocation order by itself will not decrease revenues, but will be incorporated into subsequent rate proceedings which are expected to occur in mid-1998 and will be combined with other cost increases and decreases to determine the overall impact to customer rates. - ------------------------------------------------------------------------------- PACIFICORP P. 49 NOTE 5 SPECIAL CHARGES In December 1997, Domestic Electric Operations recorded in operating income special charges of $170 million ($106 million after-tax, or $0.36 per share). The pretax special charges included write off of $87 million of deferred regulatory pension assets (see Note 4), 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 associated with the write down of assets and acceleration of reclamation costs due to the early closure of the Glenrock coal mine. The inability of the mine to remain competitive has caused it to be uneconomic under current and expected market conditions due to increased mining stripping ratios, coal quality and related costs. Also, 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, in 1998. This reduction will be accomplished through a combination of voluntary early retirement and special severance. Employees are not required to finalize their acceptance of offers until March 31, 1998. Based upon the current acceptance rate, the pretax costs are estimated to be $104 million, which will be recorded in the first quarter of 1998. The current acceptance rate has exceeded the Company's original estimate. NOTE 6 SHORT-TERM DEBT AND BORROWING ARRANGEMENTS The Companies' short-term debt and borrowing arrangements were as follows:
AVERAGE INTEREST MILLIONS OF DOLLARS/DECEMBER 31 BALANCE RATE(a) - ---------------------------------------------------------------- 1997 PacifiCorp $182.2 6.5% Subsidiaries 7.0 5.4 1996 PacifiCorp $549.3 5.6% Subsidiaries 134.2 5.6
(a) Computed by dividing the total interest on principal amounts outstanding at the end of the period by the weighted daily principal amounts outstanding. At December 31, 1997, PacifiCorp's commercial paper and bank line borrowings were supported by revolving credit agreements totaling $700 million. At December 31, 1997, subsidiaries had committed bank revolving credit agreements totaling $1 billion. The Companies have the intent and ability to support short-term borrowings through various revolving credit agreements on a long-term basis. At December 31, 1997, PacifiCorp had $121 million and subsidiaries had $757 million of short-term debt classified as long-term. - ------------------------------------------------------------------------------- P. 50 PACIFICORP NOTE 7 LONG-TERM DEBT The Company's long-term debt was as follows:
MILLIONS OF DOLLARS/DECEMBER 31 1997 1996 - --------------------------------------------------------------------- PACIFICORP First mortgage and collateral trust bonds Maturing 1998 through 2002/5.9%-9.5% $ 882.2 $1,074.5 Maturing 2003 through 2007/6.1%-9% 756.1 587.2 Maturing 2008 through 2012/7%-9.2% 267.6 144.9 Maturing 2013 through 2017/7.3%-8.8% 164.9 167.6 Maturing 2018 through 2022/8.1%-8.5% 175.0 175.0 Maturing 2023 through 2026/6.7%-8.6% 286.5 286.5 Guaranty of pollution control revenue bonds 5.6%-5.7% due 2021 through 2023(a) 71.2 71.2 Variable rate due 2013 through 2024(a)(b) 216.5 216.5 Variable rate due 2005 through 2030(b) 450.7 450.7 Funds held by trustees (9.1) (12.1) 8.4%-8.6% Junior subordinated debentures due 2025 through 2035 175.8 175.8 Commercial paper(b)(d) 120.6 123.4 Other 25.1 28.2 ----------------------- Total 3,583.1 3,489.4 Less current maturities 194.9 203.8 ----------------------- Total 3,388.2 3,285.6 ----------------------- SUBSIDIARIES 6.8%-12% Notes due through 2020 266.1 268.8 Australian bank bill borrowings(c)(d) 756.6 922.3 Commercial paper and committed bank lines -- 160.0 Variable rate notes due through 2000(b) 12.1 35.8 4.5%-11% Nonrecourse debt due through 2031 160.7 170.8 Other 1.4 2.1 ----------------------- Total 1,196.9 1,559.8 Less current maturities 170.6 16.0 ----------------------- Total 1,026.3 1,543.8 ----------------------- Total $4,414.5 $4,829.4 ----------------------- -----------------------
(a) Secured by pledged first mortgage and collateral trust bonds generally at the same interest rates, maturity dates and redemption provisions as the secured 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 $494 million was hedged at December 31, 1997 at an average rate of 7.6% and for an average life of 2.6 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 $878 million of short-term debt as long-term debt. In early 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, 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. The funds were used to repay Australian bank bill borrowings. - ------------------------------------------------------------------------------- PACIFICORP P. 51 Approximately $7 billion of the assets of the Companies secure long-term debt. First mortgage and collateral trust bonds of the Company may be issued in amounts limited by Domestic Electric Operations' property, earnings and other provisions of the mortgage indenture. The junior subordinated debentures are unsecured obligations of the Company and are subordinated to the Company's first mortgage and collateral trust bonds, pollution control revenue bonds, commercial paper, bank debt and any future senior indebtedness. Nonrecourse notes are secured by assignment of related real estate assets. The noteholders have no additional recourse to the Company. These long-term nonrecourse notes are classified short-term due to a pending sale of the real estate assets. The annual maturities of long-term debt and redeemable preferred stock outstanding are $366 million, $300 million, $181 million, $386 million and $902 million in 1998 through 2002, respectively. The Company made interest payments, net of capitalized interest, of $416 million, $456 million and $367 million in 1997, 1996 and 1995, respectively. NOTE 8 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, and certain rights under related guarantees by the Company. Preferred Securities outstanding at December 31 were as follows:
THOUSANDS OF PREFERRED SECURITIES/MILLIONS OF DOLLARS 1997 1996 - -------------------------------------------------------------------------------- 8,680 8.25% Cumulative Quarterly Income Preferred Securities, Series A, with Trust assets of $224 million $209.7 $209.7 5,400 7.70% Trust Preferred Securities, Series B, with Trust assets of $139 million 130.7 -- ---------------- TOTAL $340.4 $209.7 ---------------- ----------------
NOTE 9 COMMON AND PREFERRED STOCK
COMMON SHARES SHARES SHARE- COMMON PREFERRED HOLDERS' THOUSANDS OF SHARES/MILLIONS OF DOLLARS STOCK STOCK CAPITAL - ------------------------------------------------------------------------------- AT JANUARY 1, 1995 284,251 10,532 $3,010.6 Sales through Employees' Stock Plans 26 -- 0.4 Junior subordinated debentures exchanged for preferred stock(a) -- (2,233) 1.9 ------------------------------------ AT DECEMBER 31, 1995 284,277 8,299 3,012.9 Sales to public 8,790 -- 177.8 Sales through Dividend Reinvestment and Stock Purchase Plan 2,073 -- 43.2 Redemptions and repurchases -- (2,342) 2.9 ------------------------------------ AT DECEMBER 31, 1996 295,140 5,957 3,236.8 Sales through Dividend Reinvestment and Stock Purchase Plan 1,768 -- 37.4 Redemptions and repurchases -- (2,797) -- ------------------------------------ AT DECEMBER 31, 1997 296,908 3,160 $3,274.2 ------------------------------------
(a) Noncash financing activities in 1995 included the exchange of 8.55% Series Junior Subordinated Debentures due 2025 for 2,233,037 shares of $1.98 No Par Serial Preferred Stock with a value of $56 million. At December 31, 1997, there were 27,126,352 authorized but unissued shares of common stock reserved for issuance under the Dividend Reinvestment and Stock Purchase Plan and the Employee Savings and Stock Ownership Plans and for sales to the public. Eligible employees under the employee plans may direct their pretax elective contributions into the purchase of the Company's common stock. The Company makes matching contributions, equal to a percentage of employee contributions, which are invested in the Company's common stock. Employee contributions eligible for matching contributions are limited to 6% of compensation. In early 1998, the Company registered 11,500,000 shares of its common stock with the Securities and Exchange Commission for issuance under the PacifiCorp Stock Incentive Plan. 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. - ------------------------------------------------------------------------------- P. 52 PACIFICORP PREFERRED STOCK OUTSTANDING
THOUSANDS OF SHARES/MILLIONS OF DOLLARS/DECEMBER 31 1997 1996 SERIES SHARES AMOUNT SHARES AMOUNT - -------------------------------------------------------------------------------------------------- SUBJECT TO MANDATORY REDEMPTION No Par Serial Preferred, $100 stated value, 16,000 Shares authorized $7.12 -- $ -- 30 $ 3.0 7.70 1,000 100.0 1,000 100.0 7.48 750 75.0 750 75.0 -------------------------------------------- Total 1,750 $175.0 1,780 $178.0 -------------------------------------------- NOT SUBJECT TO MANDATORY REDEMPTION No Par Serial Preferred, $25 stated value $1.16 193 $4.8 193 $ 4.8 1.18 420 10.5 420 10.5 1.28 381 9.5 381 9.5 1.98, Series 1992 -- -- 2,767 69.1 Serial Preferred, $100 stated value, 3,500 Shares authorized 4.52% 2 0.2 2 0.2 4.56 85 8.5 85 8.5 4.72 70 7.0 70 7.0 5.00 42 4.2 42 4.2 5.40 66 6.6 66 6.6 6.00 6 0.6 6 0.6 7.00 18 1.8 18 1.8 5% Preferred, $100 stated value, 127 Shares authorized and outstanding 127 12.7 127 12.7 -------------------------------------------- Total 1,410 $66.4 4,177 $135.5 -------------------------------------------- --------------------------------------------
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. - ------------------------------------------------------------------------------- PACIFICORP P. 53 NOTE 10 FINANCIAL INSTRUMENTS AND RISK MANAGEMENT The Company seeks to reduce net income and cash flow exposure to changing interest and currency exchange rates and commodity price risks through the use of derivative financial instruments. The Company's participation in derivative transactions involves instruments that have a close correlation with its portfolio of assets or liabilities, thereby managing its risk. The majority of derivatives have been designed for hedging purposes and are not held or issued for speculative purposes. 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 rating requirements. The Company's credit policy provides that counterparties satisfy established credit ratings. The credit exposure of interest rate, foreign exchange and forward contracts is represented by the fair value of contracts with a positive fair value at the reporting date. INTEREST RATE RISK MANAGEMENT -- The Company enters into various types of interest rate contracts in managing its interest rate risk, as indicated in the following table:
NOTIONAL AMOUNT MILLIONS OF DOLLARS/DECEMBER 31 1997 1996 - ---------------------------------------------------- Interest rate swaps $707.5 $846.4 Interest rate collars purchased 42.3 52.0 Interest rate futures and forwards -- 60.0
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. Additionally, under terms of the variable rate Australian bank bill borrowings, Australian Electric Operations is required to obtain a fixed interest rate, via financial derivatives, on at least 50% of the principal out-standing. The futures and forwards, when used, are accounted for as hedges of the Australian bank bill borrowings. Interest rate collar agreements entitle the Company to receive from the counterparties the amounts, if any, by which the Australian bank bill borrowings interest payments exceed 8.75% and the Company would pay the counterparties if interest payments fall below 6.5%-6.8%. Under the various 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 December 31; these may change significantly, affecting future cash flows. Swap contracts are principally between one and fifteen years in duration.
DECEMBER 31 1997 1996 - ---------------------------------------------------- PAY-FIXED SWAPS Average pay rate 7.7% 7.7% Average receive rate 6.5 5.6
FOREIGN EXCHANGE RISK MANAGEMENT -- At December 31, 1997, Holdings held three combined interest rate and currency swaps that terminate in 2002, with an aggregate notional amount of $268 million to hedge a portion of the exposure to fluctuations in the Australian dollar relating to its investment in Powercor. 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. At December 31, 1997, Hazelwood Australia, Inc. ("HAI"), a subsidiary of Holdings, held a foreign currency forward with a notional amount of $146 million to hedge a portion of its exposure to fluctuations in the Australian dollar relating to its investment in the Hazelwood power station and adjacent coal mine. This position was closed in January 1998 and HAI received $24 million in cash. 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 December 31, 1997, Australian Electric Operations had 211 forward contracts with electricity generation companies on notional quantities amounting to approximately 35.6 million megawatt hours ("mWh") through the year 2007. The average fixed price to be paid by Australian Electric Operations was $19.07 per mWh compared to the average price of similar contracts at December 31, 1997 of $18.66. 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. - ------------------------------------------------------------------------------- P. 54 PACIFICORP At December 31, 1997, Domestic Electric Operations and TPC had open NYMEX futures contracts as follows:
1997 1996 ELECTRICITY GAS ELECTRICITY - --------------------------------------------------- ----------- OPEN CONTRACTS (number) Purchase 489 303 67 Sell 110 1,399 -- NOTIONAL QUANTITIES (mWh/MMBtu) Purchase 359,900 3,030,000 49,300 Sell 81,000 13,990,000 -- FAIR MARKET VALUE (millions of dollars) Purchase $(0.7) $(1.1) $0.2 Sell 0.1 (0.5) --
TRADING ACTIVITIES -- PPM began trading wholesale power in the eastern United States energy markets during 1996. Such transactions involve delivery of electricity, which is accounted for as revenue or purchased power expense. At December 31, 1997, PPM had open purchase positions for approximately $866 million, or 33 million mWh, and open sell positions for approximately $848 million, or 32 million mWh. At December 31, 1997, TPC had open purchase positions involving the delivery of natural gas for approximately $35 million, or 19,000 millions of cubic feet ("MMcf"). In addition, TPC had open sell positions for approximately $17 million or 7,000 MMcf. The fair market values of these open positions at December 31, 1997 for PPM and TPC were $(1) million and $6 million, respectively. NOTE 11 FAIR VALUE OF FINANCIAL INSTRUMENTS
DECEMBER 31, 1997 DECEMBER 31, 1996 --------------------------------------------------- CARRYING FAIR CARRYING FAIR AMOUNT VALUE AMOUNT VALUE - ------------------------------------------------------------------------------- Long-term debt $4,755.3 $4,907.2 $5,026.3 $5,100.8 Preferred Securities 340.4 355.4 209.7 210.9 Preferred stock subject to mandatory redemption 175.0 194.1 178.0 195.8 Derivatives relating to Currency 45.3 45.3 (21.5) (21.5) Interest (9.4) (54.3) (10.8) (52.5)
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 December 31, 1997. 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 12 COMMITMENTS AND CONTINGENCIES The Company is subject to numerous environmental laws including: the Federal Clean Air Act, as enforced by the Envi-ronmental 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 December 31, 1997, 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. 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. 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. This is consistent with industry practices, and the Company believes that it has adequately provided for its reclamation obligations. - ------------------------------------------------------------------------------- PACIFICORP P. 55 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 $830 million for 1998, excluding amounts relating to the proposed acquisition of TEG. As a part of these programs, substantial commitments have been made. LEASES -- The Companies have 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 Companies are also committed to pay all taxes, expenses of operation (other than depreciation) and maintenance applicable to the leased property. Net rent expense for the years ended December 31, 1997, 1996 and 1995 was $20 million, $12 million and $13 million, respectively. Future minimum lease payments under noncancelable operating leases are $8 million, $6 million, $5 million, $5 million and $3 million for 1998 through 2002, respectively. JOINTLY OWNED PLANTS -- At December 31, 1997, Domestic Electric Operations' participation in jointly owned plants was as follows:
ELECTRIC PLANT CONSTRUCTION OPERATIONS' IN ACCUMULATED WORK IN MILLIONS OF DOLLARS SHARE SERVICE DEPRECIATION PROGRESS - ------------------------------------------------------------------------------------ Centralia 47.5% $181.5 $111.1 $ 0.5 Jim Bridger Units 1, 2, 3 and 4 66.7 796.1 320.3 4.5 Trojan(a) 2.5 -- -- -- Colstrip Units 3 and 4 10.0 205.2 68.0 -- Hunter Unit 1 93.8 260.9 107.1 1.4 Hunter Unit 2 60.3 188.6 71.2 10.3 Wyodak 80.0 304.9 102.9 0.4 Craig Station Units 1 and 2 19.3 150.6(b) 59.4 1.1 Hayden Station Unit 1 24.5 18.6(b) 12.0 6.0 Hayden Station Unit 2 12.6 15.6(b) 8.8 3.4 Hermiston(c) 50.0 156.7 10.9 --
(a) Plant, inventory, fuel and decommissioning costs totaling $23 million relating to the Trojan Plant were included in regulatory assets-net at December 31, 1997. (b) Excludes unallocated acquisition adjustments of $114 million at December 31, 1997. (c) Additionally, the Company has contracted to purchase the remaining 50% of the output of the plant. Under the joint agreements, each participating utility is responsible for financing its share of construction, operating and leasing costs. Domestic Electric Operations' portion is recorded in its applicable operations, maintenance and tax accounts. 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 and meet commitments for wholesale sales and retail load growth. The long-term wholesale sales commitments include contracts with minimum sales requirements of $485 million in 1998, $450 million in 1999, $415 million in 2000, $316 million in 2001 and $308 million in 2002. 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 $320 million in 1998, $316 million in 1999, $314 million in 2000, $290 million in 2001 and $299 million in 2002. 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 1997, such purchases approximated 3% of energy requirements. At December 31, 1997, Domestic Electric Operations' share of long-term arrangements with public utility districts was as follows:
GENERATING YEAR CONTRACT CAPACITY PERCENTAGE ANNUAL FACILITY EXPIRES (kW) OF OUTPUT COSTS(a) - -------------------------------------------------------------------------------- Wanapum 2009 155,444 18.7% $ 4.4 Priest Rapids 2005 109,602 13.9 3.5 Rocky Reach 2011 64,297 5.3 2.9 Wells 2018 59,617 7.7 2.0 ------------------------------------------------- Total 388,960 $12.8 ------------------------------------------------- -------------------------------------------------
(a) Annual costs, in millions of dollars, include debt service of $7 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. - ------------------------------------------------------------------------------- P. 56 PACIFICORP FUEL CONTRACTS -- Domestic Electric Operations has take or pay coal and natural gas contracts which require minimum fixed payments of $83 million for 1998 and 1999, $90 million for 2000, $62 million for 2001 and $64 million for 2002. NOTE 13 INCOME TAXES The Company's combined federal and state effective income tax rate from continuing operations was 33% in 1997, 35% in 1996 and 32% in 1995. 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:
MILLIONS OF DOLLARS/FOR THE YEAR 1997 1996 1995 - ------------------------------------------------------------------------------- Computed Federal Income Taxes $117.2 $233.3 $207.8 ------------------------------------ Increase (Reduction) in Tax Resulting from Depreciation differences 14.2 12.8 9.7 Investment tax credits (8.5) (9.3) (9.2) Audit settlement -- 0.5 (16.8) Affordable housing credits (13.4) (10.6) (8.4) Other items capitalized and miscellaneous differences (9.4) (8.4) (7.7) ------------------------------------ Total (17.1) (15.0) (32.4) ------------------------------------ Federal Income Tax 100.1 218.3 175.4 State Income Tax, Net of Federal Income Tax Benefit 9.4 18.1 16.4 ------------------------------------ Total Income Tax Expense $109.5 $236.4 $191.8 ------------------------------------ ------------------------------------
The provision for income taxes is summarized as follows:
MILLIONS OF DOLLARS/FOR THE YEAR 1997 1996 1995 - ------------------------------------------------------------------------------- CURRENT Federal $173.9 $186.3 $135.8 State 17.2 24.0 16.9 Foreign -- -- 1.1 ------------------------------------ Total 191.1 210.3 153.8 ------------------------------------ DEFERRED Federal (70.2) 22.4 37.2 State (2.9) 4.9 9.0 Foreign -- 8.1 1.0 ------------------------------------ Total (73.1) 35.4 47.2 ------------------------------------ INVESTMENT TAX CREDITS (8.5) (9.3) (9.2) ------------------------------------ Total Income Tax Expense $109.5 $236.4 $191.8 ------------------------------------ ------------------------------------
The tax effects of significant items comprising the Company's net deferred tax liability were as follows:
MILLIONS OF DOLLARS/DECEMBER 31 1997 1996 - ----------------------------------------------------------------- DEFERRED TAX LIABILITIES Property, plant and equipment $1,195.0 $1,177.1 Regulatory assets 704.1 733.1 Other deferred liabilities 84.3 77.9 DEFERRED TAX ASSETS Regulatory liabilities (54.0) (57.1) Book reserves not deductible for tax (61.3) (55.0) Foreign net operating loss (47.5) (28.3) Foreign currency adjustment (46.4) 8.0 Pension accrual (39.9) (8.1) Other deferred assets (58.2) (46.6) ------------------------ Net Deferred Tax Liability $1,676.1 $1,801.0 ------------------------ ------------------------
The Company's 1991, 1992 and 1993 federal income tax returns are currently under examination by the Internal Revenue Service (the "IRS"). The Company has received an examination report for 1989 and 1990 proposing adjustments that would increase current income taxes payable by $14 million. The Company filed a protest of certain proposed adjustments on July 30, 1996 and is currently holding discussions with the Appeals Division of the IRS. The Company made income tax payments of $134 million, $208 million and $186 million in 1997, 1996 and 1995, respectively. NOTE 14 EMPLOYMENT BENEFIT PLANS RETIREMENT PLANS -- The Companies have pension plans covering substantially all of their 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 December 31, 1997, plan assets were primarily invested in common stocks, bonds and United States government obligations. - ------------------------------------------------------------------------------- PACIFICORP P. 57 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. At December 31, 1997, Powercor was no longer making contributions to Division B and C funds due to surplus amounts in these funds. During 1997, Powercor contributed to the Division D Fund at rates ranging from 6%-10% of eligible salaries. Net pension cost is summarized as follows:
MILLIONS OF DOLLARS/FOR THE YEAR 1997 1996 1995 - ------------------------------------------------------------------------------- Service cost -- benefits earned $27.2 $31.4 $20.7 Interest cost on projected benefit obligation 81.6 78.3 69.3 Actual gain on plan assets (76.5) (66.3) (120.9) Net amortization and deferral 9.2 8.9 81.5 Regulatory deferral (see Note 4) -- 14.2 29.4 ------------------------------------ Net Pension Cost $41.5 $66.5 $80.0 ------------------------------------ ------------------------------------
The funded status, net pension liability and significant assumptions are as follows:
MILLIONS OF DOLLARS/DECEMBER 31 1997 1996 - ---------------------------------------------------------------- Actuarial present value of benefit obligations Vested benefit obligation $993.5 $913.7 ----------------------- Accumulated benefit obligation 1,052.4 987.6 ----------------------- Projected benefit obligation 1,216.2 1,114.3 Plan assets at fair value 1,003.5 871.0 ----------------------- Projected benefit obligation in excess of plan assets 212.7 243.3 Unrecognized prior service cost (15.2) (13.7) Unrecognized net loss (4.9) (86.7) Unrecognized net obligation (80.0) (10.2) Minimum liability adjustment 5.5 2.9 ----------------------- Net Pension Liability $118.1 $135.6 ----------------------- ----------------------- Discount rate 6.25%-7% 7.25%-7.5% Expected long-term rate of return on assets 7.5%-9.25% 8.5%-9% Rate of increase in compensation levels 4%-5% 4.5%-6%
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, 1993, the Company funds postretirement benefit expense on a pay-as-you-go basis and has an unfunded accrued liability of $58 million at December 31, 1997. For those employees retiring after January 1, 1993, the Company funds postretirement benefit expense through a combination of funding vehicles. The Company funded $16 million and $28 million of postretirement benefit expense during 1997 and 1996, respectively. These funds are invested in common stocks, bonds and United States government obligations. The net periodic postretirement benefit cost is summarized as follows:
MILLIONS OF DOLLARS/FOR THE YEAR 1997 1996 1995 - ------------------------------------------------------------------------------- Service cost -- benefits earned $7.2 $6.9 $6.2 Interest cost on accumulated postretirement benefit obligation 21.8 21.8 26.7 Amortization of transition obligation 11.9 12.6 14.0 Regulatory deferral 6.4 3.4 (4.5) Net asset gain during the period deferred for future recognition 18.9 3.5 2.6 Actual gain on plan assets (31.5) (12.6) (8.8) ------------------------------------- Net Periodic Postretirement Benefit Cost $34.7 $35.6 $36.2 ------------------------------------- -------------------------------------
The accumulated postretirement benefit obligation ("APBO") was as follows:
MILLIONS OF DOLLARS/DECEMBER 31 1997 1996 - ----------------------------------------------------------------- Retirees and dependents $172.2 $168.0 Fully eligible active plan participants 12.0 10.1 Other active plan participants 143.2 131.0 --------------------- APBO 327.4 309.1 Plan assets at fair value 179.8 135.1 --------------------- APBO in excess of plan assets 147.6 174.0 Unrecognized transition obligation (209.3) (223.2) Unrecognized net gain 64.3 51.2 --------------------- Accrued Postretirement Benefit Obligation $2.6 $2.0 --------------------- --------------------- Discount rate 7% 7.5% Estimated long-term rate of return on assets 9.3% 9% Initial health care cost trend rate -- under 65 8.3% 8.8% Initial health care cost trend rate -- over 65 8.3% 8.4% Ultimate health care cost trend rate 4.5% 4.5%
- ------------------------------------------------------------------------------- P. 58 PACIFICORP The assumed health care cost trend rate gradually decreases over eight 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 December 31, 1997 by $29 million, and the annual net periodic postretirement benefit costs by $3 million. POSTEMPLOYMENT BENEFITS -- Domestic Electric Operations provides certain postemployment benefits to former employees and their dependents 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 $13 million and $5 million in 1997 and 1996, respectively. PENDING EARLY RETIREMENT OFFER -- The Company has offered enhanced early retirement to approximately 1,200 employees who have until March 31, 1998 to accept the offer. The cost of the enhancement will have an impact on the funding status of the retirement and other postretirement benefit plans. However, the Company intends to fund a substantial portion of the increase in the accumulated benefit obligation. STOCK INCENTIVE PLAN -- During 1997, the Company formalized a Stock Incentive Plan (the "Plan") under which selected employees, officers and directors and selected nonemployee agents, consultants, advisors and independent contractors may be granted options to purchase the Company's common stock. Options generally become exercisable in three equal installments on each of the first through third anniversaries of the grant date and have a maximum term of ten years. During 1997, options were granted to 193 officers and employees. Under the Plan options for 1,322,500 shares were granted on June 3, 1997 and options for 193,500 shares were granted on August 12, 1997 at exercise prices of $19.75 and $21.25, respectively. The weighted average estimated fair value of options granted was $2.78 per share. These options to purchase the Company's common stock were issued at 100% of market price on the dates the options were granted. None of the options were exercisable as of December 31, 1997. During 1997, options for 19,000 shares relating to the June 3, 1997 grant were forfeited. As permitted by SFAS 123, the Company has elected to account for the Plan under APB 25. Accordingly, no compensation expense has been recognized for the Plan. Had compensation cost for the Plan been determined based on the fair value at the grant date consistent with SFAS 123, there would have been no impact on the Company's net income and earnings per common share. 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: dividend yield of 5.5%, risk-free interest rate of 6.8%, expected life of the options of ten years and volatility of 15%. NOTE 15 ACQUISITIONS AND DISPOSITIONS On April 15, 1997, Holdings, through a subsidiary, acquired all of the outstanding shares of common stock of TPC, a natural gas gathering, processing, storage and marketing company based in Houston, Texas, for approximately $265 million in cash and assumed debt of approximately $140 million. Following completion of a tender offer, TPC became a wholly owned subsidiary of Holdings through a cash merger at the same price. During May 1997, TPC retired $131 million of its outstanding long-term debt. This transaction was funded with capital contributions from PacifiCorp. 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. On November 5, 1997, Holdings completed the sale of PGC for approximately $150 million in cash. An after-tax gain on the sale of $30 million, or $0.10 per share, was recognized in the fourth quarter of 1997. In September 1996, a consortium, known as the Hazelwood Power Partnership, purchased a 1,600 megawatt, coal-fired generating station and associated coal mine in Victoria, Australia for approximately $1.9 billion. The consortium financed the acquisition of the Hazelwood Plant and mine with approximately $858 million in equity contributions from the partners and $1 billion of nonrecourse borrowings at the partnership level. Holdings, which has a 19.9% interest in the partnership, financed its $145 million portion of the equity investment and the associated $12 million advance with long-term borrowings in the United States. On December 12, 1995, Holdings purchased Powercor, an electricity distributor in Australia, for approximately $1.6 billion in cash. Powercor is the largest electricity distribution company in the State of Victoria. The acquisition was accounted for as a purchase and the results of operations of Powercor have been included in the consolidated financial statements since December 12, 1995. In February 1998, PFS agreed to sell its investments in affordable housing for cash proceeds of approximately $81 million and assumption of debt of approximately $161 million. This sale transaction will not have a material impact on 1998 earnings. - ------------------------------------------------------------------------------- PACIFICORP P. 59 NOTE 16 SELECTED FINANCIAL AND SEGMENT INFORMATION
MILLIONS OF DOLLARS, EXCEPT PER SHARE INFORMATION/FOR THE YEAR 1997 1996 1995 1994 1993 REVENUES Domestic Electric Operations $3,706.9 $2,991.8 $2,646.1 $2,686.2 $2,560.8 Australian Electric Operations 716.2 658.8 25.9 -- -- Unregulated Energy Trading(a) 1,729.0 11.7 -- -- -- Other Operations(b) 125.9 141.4 134.8 153.7 196.4 ---------------------------------------------------------- Total $6,278.0 $3,803.7 $2,806.8 $2,839.9 $2,757.2 - ---------------------------------------------------------------------------------------------------------------------------------- INCOME (LOSS) FROM OPERATIONS Domestic Electric Operations $ 601.3 $ 869.8 $ 800.9 $ 819.3 $ 784.3 Australian Electric Operations 150.5 127.4 5.5 -- -- Unregulated Energy Trading(a) (8.2) 0.1 -- -- -- Other Operations(b) 58.9 89.1 84.2 38.3 44.1 ---------------------------------------------------------- Total $ 802.5 $1,086.4 $ 890.6 $ 857.6 $ 828.4 - ---------------------------------------------------------------------------------------------------------------------------------- NET INCOME $ 663.7 $ 504.9 $ 505.0 $ 468.0 $ 479.1 - ---------------------------------------------------------------------------------------------------------------------------------- EARNINGS CONTRIBUTION (LOSS) ON COMMON STOCK Continuing operations Domestic Electric Operations $ 165.5 $ 341.5 $ 276.4 $ 339.8 $ 322.3 Australian Electric Operations 54.2 31.9 0.7 -- -- Unregulated Energy Trading(a) (7.5) (0.1) -- -- -- Other Operations(b) (9.6) 27.1 86.2 18.0 10.2 ---------------------------------------------------------- Total 202.6 400.4 363.3 357.8 332.5 Discontinued operations(c) 454.3 74.7 103.0 70.5 103.3 Extraordinary item(d) (16.0) -- -- -- -- Cumulative effect of change in accounting for income taxes -- -- -- -- 4.0 ---------------------------------------------------------- Total $ 640.9 $ 475.1 $ 466.3 $ 428.3 $ 439.8 - ---------------------------------------------------------------------------------------------------------------------------------- EARNINGS (LOSS) PER SHARE -- BASIC AND DILUTIVE Continuing operations Domestic Electric Operations $ 0.56 $ 1.17 $ 0.97 $ 1.20 $ 1.17 Australian Electric Operations 0.18 0.11 -- -- -- Unregulated Energy Trading(a) (0.03) -- -- -- -- Other Operations(b) (0.03) 0.09 0.31 0.06 0.04 ---------------------------------------------------------- Total 0.68 1.37 1.28 1.26 1.21 Discontinued operations(c) 1.53 0.25 0.36 0.25 0.38 Extraordinary item(d) (0.05) -- -- -- -- Cumulative effect of change in accounting for income taxes -- -- -- -- 0.01 ---------------------------------------------------------- Total $ 2.16 $ 1.62 $ 1.64 $ 1.51 $ 1.60 - ---------------------------------------------------------------------------------------------------------------------------------- CASH DIVIDENDS DECLARED PER COMMON SHARE $ 1.08 $ 1.08 $ 1.08 $ 1.08 $ 1.08 - ---------------------------------------------------------------------------------------------------------------------------------- MARKET PRICE PER COMMON SHARE(e) $27 5/16 $20 1/2 $21 1/8 $18 1/8 $19 1/4 - ---------------------------------------------------------------------------------------------------------------------------------- CAPITALIZATION Short-term debt $ 555 $ 903 $ 1,132 $ 513 $ 668 Long-term debt 4,415 4,829 4,509 3,391 3,497 Preferred securities of Trust 340 210 -- -- -- Redeemable preferred stock 175 178 219 219 219 Preferred stock 66 136 312 367 367 Common equity 4,321 4,032 3,633 3,460 3,263 ---------------------------------------------------------- Total $ 9,872 $10,288 $ 9,805 $ 7,950 $ 8,014 - ---------------------------------------------------------------------------------------------------------------------------------- TOTAL ASSETS $ 13,880 $13,812 $ 13,167 $ 11,000 $11,053 - ---------------------------------------------------------------------------------------------------------------------------------- TOTAL EMPLOYEES(e) 10,087 10,118 10,418 10,083 10,630 - ----------------------------------------------------------------------------------------------------------------------------------
(a) Unregulated Energy Trading includes the natural gas and wholesale electricity trading activities of TPC and PPM, respectively. (b) Other Operations includes the operations of PFS and PGC, as well as the activities of Holdings, including financing costs. (c) Discontinued operations includes the Company's interest in PTI for all periods presented and TRT Communications, Inc. for 1993. (d) Extraordinary item includes a regulatory asset impairment pertaining to generation resources that are allocable to operations in California and Montana. (e) Unaudited. - ------------------------------------------------------------------------------- P. 60 PACIFICORP DOMESTIC ELECTRIC OPERATIONS
5-YEAR 1997 TO 1996 COMPOUND MILLIONS OF DOLLARS, EXCEPT PERCENTAGE ANNUAL AS NOTED/FOR THE YEAR 1997 1996 1995 1994 1993 COMPARISON GROWTH REVENUES Residential $ 814.0 $ 801.4 $ 739.7 $ 746.0 $ 738.8 2% 3% Commercial 640.9 623.3 576.9 571.7 546.1 3 4 Industrial 709.9 719.3 708.8 742.3 708.0 (1) -- Other 31.7 32.5 29.7 30.7 29.8 (2) 1 ---------------------------------------------------------------------------------- Retail sales 2,196.5 2,176.5 2,055.1 2,090.7 2,022.7 1 2 ---------------------------------------------------------------------------------- Wholesale -- firm 1,289.3 635.4 487.7 456.2 422.5 103 29 Wholesale -- nonfirm 138.7 103.4 32.3 76.5 77.3 34 14 ---------------------------------------------------------------------------------- Wholesale trading sales 1,428.0 738.8 520.0 532.7 499.8 93 27 ---------------------------------------------------------------------------------- Other 82.4 76.5 71.0 62.8 38.3 8 21 ---------------------------------------------------------------------------------- Total 3,706.9 2,991.8 2,646.1 2,686.2 2,560.8 24 9 ---------------------------------------------------------------------------------- EXPENSES Fuel 454.2 443.0 431.6 483.0 447.4 3 -- Purchased power 1,296.5 618.7 386.7 394.5 369.0 110 33 Other operations 292.0 276.9 273.7 263.8 265.0 5 2 Maintenance 178.0 167.3 168.4 174.5 172.2 6 1 Administrative and general 227.8 176.3 160.5 142.7 138.2 29 10 Depreciation and amortization 389.1 343.4 320.4 301.6 280.5 13 6 Taxes, other than income taxes 97.6 96.4 103.9 106.8 104.2 1 (2) Special charges 170.4 -- -- -- -- * * ---------------------------------------------------------------------------------- Total 3,105.6 2,122.0 1,845.2 1,866.9 1,776.5 46 12 ---------------------------------------------------------------------------------- INCOME FROM OPERATIONS 601.3 869.8 800.9 819.3 784.3 (31) (2) Interest expense 319.0 291.8 311.9 264.3 270.4 9 3 Interest capitalized (12.2) (11.4) (14.9) (14.5) (13.9) 7 (6) Other (income) expense -- net (5.8) 1.2 (25.3) (30.2) (13.1) * * Income tax expense 112.0 216.9 214.1 220.2 179.3 (48) (7) ---------------------------------------------------------------------------------- NET INCOME 188.3 371.3 315.1 379.5 361.6 (49) (5) PREFERRED DIVIDEND REQUIREMENT 22.8 29.8 38.7 39.7 39.3 (23) (9) ---------------------------------------------------------------------------------- EARNINGS CONTRIBUTION(a) $ 165.5 $ 341.5 $ 276.4 $ 339.8 $ 322.3 (52) (4) ---------------------------------------------------------------------------------- IDENTIFIABLE ASSETS $ 9,863 $ 9,864 $ 9,599 $ 9,372 $ 9,055 -- 4 CAPITAL SPENDING $ 490 $ 596 $ 455 $ 638 $ 637 (18) (11)
* Not a meaningful number. (a) Does not reflect elimination of interest on intercompany borrowing arrangements and includes income taxes on a separate-company basis. - ------------------------------------------------------------------------------- PACIFICORP P. 61 DOMESTIC ELECTRIC OPERATIONS STATISTICS
5-YEAR 1997 TO 1996 COMPOUND MILLIONS OF DOLLARS, EXCEPT PERCENTAGE ANNUAL AS NOTED/FOR THE YEAR 1997 1996 1995 1994 1993 COMPARISON GROWTH ENERGY SALES (Millions of kWh) Residential 12,902 12,819 12,030 12,127 12,055 1% 3% Commercial 11,868 11,497 10,797 10,645 10,085 3 4 Industrial 20,674 20,332 19,748 20,306 19,671 2 1 Other 705 640 592 623 602 10 3 ----------------------------------------------------------------------------------- Retail sales 46,149 45,288 43,167 43,701 42,413 2 2 ----------------------------------------------------------------------------------- Wholesale -- firm 51,857 23,189 13,946 12,418 11,919 124 38 Wholesale -- nonfirm 7,286 6,476 2,430 3,207 3,030 13 20 ----------------------------------------------------------------------------------- Wholesale sales 59,143 29,665 16,376 15,625 14,949 99 35 ----------------------------------------------------------------------------------- Total 105,292 74,953 59,543 59,326 57,362 40 14 ----------------------------------------------------------------------------------- ENERGY SOURCE (%) Coal 43 60 74 79 77 (28) (12) Hydroelectric 5 7 7 5 6 (29) 5 Other 2 1 2 2 1 100 -- Purchase and exchange contracts 50 32 17 14 16 56 31 ----------------------------------------------------------------------------------- NUMBER OF RETAIL CUSTOMERS (Thousands) Residential 1,228 1,194 1,167 1,147 1,126 3 2 Commercial 170 167 160 158 154 2 2 Industrial 36 37 35 34 33 (3) 3 Other 4 4 4 3 4 -- 6 ----------------------------------------------------------------------------------- Total 1,438 1,402 1,366 1,342 1,317 3 2 ----------------------------------------------------------------------------------- RESIDENTIAL CUSTOMERS Average annual usage (kWh) 10,644 10,866 10,395 10,646 10,811 (2) 1 Average annual revenue per customer (Dollars) 672 679 639 655 663 (1) 1 Revenue per kWh (Cents) 6.3 6.3 6.1 6.1 6.1 -- -- MILES OF LINE Transmission 15,000 14,900 14,900 14,900 14,900 1 -- Distribution -- overhead 45,000 45,000 44,900 44,800 44,700 -- -- -- underground 10,000 9,600 9,100 8,800 8,200 4 5 SYSTEM PEAK DEMAND (Megawatts) Net system load(b) -- summer 7,110 7,257 6,855 7,151 6,554 (2) 1 -- winter 7,403 7,615 7,030 7,174 7,268 (3) 1 Total firm load -- summer(c) 10,871 10,572 8,899 8,830 8,390 3 5 -- winter 10,830 10,775 8,904 8,903 8,838 1 5 SYSTEM CAPABILITY (Megawatts)(d) -- summer 12,343 12,115 10,224 10,020 9,757 2 5 -- winter 12,618 12,160 10,994 10,391 9,916 4 5
(a) Unaudited. (b) Excludes off-system sales. (c) Includes firm off-system sales. (d) Generating capability and firm purchases at time of firm peak. - ------------------------------------------------------------------------------- P. 62 PACIFICORP
1997 TO 1996 MILLIONS OF DOLLARS, EXCEPT AS NOTED/ PERCENTAGE FOR THE YEAR 1997 1996 1995 COMPARISON POWERCOR EARNINGS CONTRIBUTION(a) REVENUES Residential $239.2 $239.4 $ 10.5 --% Commercial 207.9 165.5 5.9 26 Industrial 191.8 179.3 6.4 7 Other 44.4 44.4 2.6 -- ------------------------------------------- Energy sales 683.3 628.6 25.4 9 Other 32.9 30.2 0.5 9 ------------------------------------------- Total 716.2 658.8 25.9 9 ------------------------------------------- EXPENSES Purchased power 308.5 305.1 11.0 1 Other operations 100.7 62.3 2.5 62 Maintenance 33.3 50.0 0.3 (33) Administrative and general 54.9 40.7 3.4 35 Depreciation and amortization 67.1 71.6 3.1 (6) Taxes, other than income taxes 1.2 1.7 0.1 (29) ------------------------------------------- Total 565.7 531.4 20.4 6 ------------------------------------------- INCOME FROM OPERATIONS 150.5 127.4 5.5 18 Interest expense 63.5 75.2 3.8 (16) Other (income) expense -- net (1.8) 0.4 0.5 * Income tax expense 32.9 19.1 0.5 72 ------------------------------------------- POWERCOR EARNINGS CONTRIBUTION $ 55.9 $ 32.7 $ 0.7 71 ------------------------------------------- HAZELWOOD EARNINGS CONTRIBUTION(a) $ (1.7) $ (0.8) $ -- (113) ------------------------------------------- IDENTIFIABLE ASSETS $1,786 $2,065 $1,751 (14) CAPITAL SPENDING $84 $ 225 $1,591 (63) ENERGY SALES (Millions of kWh)(b) Residential 2,683 2,608 112 3 Commercial 3,082 1,926 66 60 Industrial 4,755 3,282 152 45 Other 524 494 32 6 ------------------------------------------- Total 11,044 8,310 362 33 ------------------------------------------- NUMBER OF CUSTOMERS(b)(c) Residential 459,780 453,978 448,623 1 Commercial Franchise 48,438 47,918 47,358 1 Contestable 1,383 680 17 103 Industrial Franchise 8,899 8,005 8,422 11 Contestable 541 417 5 30 Other Franchise 35,842 35,808 35,700 -- Contestable 7 8 -- (13) ------------------------------------------- Total 554,890 546,814 540,125 1 -------------------------------------------
* 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) Unaudited. (c) Aggregate number of customers in Powercor's distribution service area, together with contestable customers located outside of Powercor's distribution service area. - ------------------------------------------------------------------------------- PACIFICORP P. 63 UNREGULATED ENERGY TRADING Unregulated Energy Trading includes the natural gas and wholesale electricity trading activities of TPC and PPM, respectively. TPC was purchased on April 15, 1997. Natural gas revenues, gross margin and net income for 1997 include $19 million, $14 million, and $3 million, respectively, relating to the natural gas gathering and processing operations of TPC that were sold in December 1997.
MILLIONS OF DOLLARS/FOR THE YEAR 1997 1996 - ------------------------------------------------------------------- REVENUES Natural gas $815.8 $-- Electricity 913.2 11.7 ------------------- Total 1,729.0 11.7 ------------------- COST OF SALES Natural gas 801.0 -- Purchased electric power 909.3 8.0 ------------------- GROSS MARGIN 18.7 3.7 Depreciation and amortization 10.7 -- Administrative and other 16.2 3.6 ------------------- INCOME (LOSS) FROM OPERATIONS Natural gas (5.8) -- Electricity (2.4) 0.1 ------------------- Total (8.2) 0.1 ------------------- INTEREST EXPENSE 2.8 0.2 ------------------- NET LOSS Natural gas (5.9) -- Electricity (1.6) (0.1) ------------------- Total $ (7.5) $ (0.1) ------------------- ENERGY SALES(a) Natural gas (MMcf)(b) 283,000 -- Electricity (millions of kWh) 35,800 497 IDENTIFIABLE ASSETS $ 478 $7 CAPITAL SPENDING $75 $--
(a) Unaudited. (b) Excludes volumes relating to natural gas gathering and processing activities. OTHER OPERATIONS Other Operations include the operations of PFS, PGC 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 in February 1998 a definitive agreement was reached to sell the real estate assets of PFS.
MILLIONS OF DOLLARS/FOR THE YEAR 1997 1996 1995 1994 1993 - --------------------------------------------------------------------------------------------------------- EARNINGS CONTRIBUTION PFS $30.2 $34.1 $30.4 $3.0 $(3.1) PGC 10.4 7.8 5.6 8.5 6.5 Tax settlement -- -- 32.2 -- -- Holdings and other (50.2) (14.8) 18.0 6.5 6.8 --------------------------------------------------------- Total $(9.6) $27.1 $86.2 $18.0 $10.2 --------------------------------------------------------- IDENTIFIABLE ASSETS PFS 692 708 697 731 1,116 PGC -- 123 116 113 122 Holdings and other(a) 1,061 276 253 252 251 --------------------------------------------------------- Total $1,753 $1,107 $1,066 $1,096 $1,489 --------------------------------------------------------- CAPITAL SPENDING $140 $ 56 $ 44 $ 13 $ 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 3 and 15. - ------------------------------------------------------------------------------- P. 64 PACIFICORP SUPPLEMENTAL INFORMATION QUARTERLY FINANCIAL DATA (UNAUDITED)
MILLIONS OF DOLLARS/EXCEPT PER SHARE MARCH JUNE SEPTEMBER DECEMBER AMOUNTS/QUARTER ENDED 31 30 30 31 - -------------------------------------------------------------------------------------------- 1997 Revenues $1,041.8 $1,220.1 $2,010.6 $2,005.5 Income from operations 261.4 221.9 281.1 38.1 Income from continuing operations 102.7 75.7 46.9 0.1 Discontinued operations 18.3 19.1 27.1 389.8 Extraordinary item -- -- -- (16.0) Net income 121.0 94.8 74.0 373.9 Earnings on common stock 114.9 88.7 68.2 369.1 Earnings per common share: Continuing operations 0.32 0.24 0.14 (0.02) Discontinued operations 0.07 0.06 0.09 1.31 Extraordinary item -- -- -- (0.05) Common dividends paid and declared per share 0.27 0.27 0.27 0.27 Common stock price per share (NYSE) High 21 3/4 22 3/8 23 3/8 27 5/16 Low 20 1/8 19 1/4 20 9/16 21 7/16 1996 Revenues $883.4 $856.6 $1,011.9 $1,051.8 Income from operations 276.9 218.5 297.3 293.7 Income from continuing operations 114.0 81.3 122.6 112.3 Discontinued operations 15.9 17.9 20.3 20.6 Net income 129.9 99.2 142.9 132.9 Earnings on common stock 120.9 90.2 136.6 127.4 Earnings per common share: Continuing operations 0.36 0.25 0.39 0.37 Discontinued operations 0.06 0.06 0.07 0.06 Common dividends paid and declared per share 0.27 0.27 0.27 0.27 Common stock price per share (NYSE) High 22 22 1/2 22 3/8 22 Low 20 1/8 19 1/2 19 1/8 19 7/8
A significant portion of the operations are of a seasonal nature. Previously reported quarterly information has been revised to reflect certain reclassifications. These reclassifications had no effect on previously reported consolidated net income. In the fourth quarter of 1997, the Company recorded after-tax amounts as follows: asset sales gains of $395 million or $1.33 per share, special charges of $106 million, or $0.36 per share, and an extraordinary charge of $16 million, or $0.05 per share. See Notes 4, 5, and 15. Additionally, in the fourth quarter of 1997, the Company recorded after-tax depreciation adjustments of $10 million, or $0.03 per share, and an SAP process reengineering charge of $9 million, or $0.03 per share. See Management's Discussion and Analysis, pages 29 and 33. See Note 3 for information regarding discontinued operations. On March 1, 1998, there were 115,693 common share-holders of record. - ------------------------------------------------------------------------------- PACIFICORP P. 65 EX-21 6 EXHIBIT 21 EXHIBIT (21) SUBSIDIARIES OF THE COMPANY PacifiCorp Group Holdings Company, a wholly-owned subsidiary of the Company and a Delaware corporation, has the following subsidiaries:
APPROXIMATE STATE OR PERCENTAGE JURISDICTION OF OF VOTING INCORPORATION SECURITIES OR NAME OF SUBSIDIARY OWNED ORGANIZATION - ----------------------------------------------------------------------------------- ------------ --------------- PACE GROUP, Inc.................................................................... 100% Oregon PacifiCorp Energy, Inc............................................................. 100% Oregon PacifiCorp Financial Services, Inc................................................. 100% Oregon Pacific Harbor Capital, Inc...................................................... 100% Delaware PacifiCorp Credit, Inc........................................................... 100% Oregon PacifiCorp International Group Holdings Company.................................... 100% Oregon Pan Pacific Global Corporation................................................... 100% Oregon PacifiCorp Australia, LLC...................................................... 80%* Oregon PacifiCorp Australia Holdings Pty. Ltd....................................... 100% Australia Powercor Australia Limited................................................. 100% Australia Hazelwood Australia, Inc..................................................... 100%** Oregon PacifiCorp Kentucky Energy Company................................................. 100% Oregon PacifiCorp Power Marketing, Inc.................................................... 100% Oregon PacifiCorp Trans, Inc.............................................................. 100% Oregon TPC Corporation.................................................................... 100% Delaware
- ------------------------ * Remaining 20% owned by another wholly owned subsidiary of PacifiCorp International Group Holdings Company. ** Owns 19.9% interest in Hazelwood Power Partnership indirectly through two wholly owned subsidiaries. The Company also has the following subsidiaries:
APPROXIMATE STATE OR PERCENTAGE JURISDICTION OF OF VOTING INCORPORATION SECURITIES OR NAME OF SUBSIDIARY OWNED ORGANIZATION - ----------------------------------------------------------------------------------- ------------ --------------- Centralia Mining Company........................................................... 100% Washington Energy West Mining Company......................................................... 100% Utah Glenrock Coal Company.............................................................. 100% Wyoming Interwest Mining Company........................................................... 100% Oregon Pacific Mineral, Inc............................................................... 100% Wyoming Bridger Coal Company, a joint venture............................................ 66.67% Wyoming
S-3 EX-23 7 EXHIBIT 23 Exhibit (23) INDEPENDENT AUDITORS' CONSENT PacifiCorp: We consent to the incorporation by reference in Registration Statement Nos. 33-51277, 33-54169, 33-57043, 33-58461, 333-10885, and 333-45851, all on Form S-8, Registration Statement Nos. 33-62095 and 333-09115 on Form S-3, and Registration Statement No. 33-36239 on Form S-4, of our report dated February 3, 1998 (March 2, 1998 as to Note 2), incorporated by reference in this Annual Report on Form 10-K of PacifiCorp and subsidiaries for the year ended December 31, 1997. /s/ DELOITTE & TOUCHE LLP DELOITTE & TOUCHE LLP Portland, Oregon March 20, 1998 EX-24 8 EXHIBIT 24 POWER OF ATTORNEY KNOW ALL MEN BY THESE PRESENTS that the undersigned constitutes and appoints Kathryn A. Braun, Nolan E. Karras, Alan K. Simpson, Don M. Wheeler, and Nancy Wilgenbusch, and each of them, his or her true and lawful attorneys and agents, with full power of substitution and resubstitution for him or her and in his or her name, place and stead, in any and all capacities, to sign the Annual Report of PacifiCorp on Form 10-K for the year ended December 31, 1997 and any and all amendments thereto, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys and agents, and each of them, full power and authority to do any and all acts and things necessary or advisable to be done, as fully and to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys and agents or any of them, or their or his or her substitute or substitutes, may lawfully do or cause to be done by virtue hereof. Dated: February 11th, 1998. /s/ Keith R. McKennon Keith R. McKennon POWER OF ATTORNEY KNOW ALL MEN BY THESE PRESENTS that the undersigned constitutes and appoints Kathryn A. Braun, Nolan E. Karras, Alan K. Simpson, Don M. Wheeler, and Nancy Wilgenbusch, and each of them, his or her true and lawful attorneys and agents, with full power of substitution and resubstitution for him or her and in his or her name, place and stead, in any and all capacities, to sign the Annual Report of PacifiCorp on Form 10-K for the year ended December 31, 1997 and any and all amendments thereto, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys and agents, and each of them, full power and authority to do any and all acts and things necessary or advisable to be done, as fully and to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys and agents or any of them, or their or his or her substitute or substitutes, may lawfully do or cause to be done by virtue hereof. Dated: February 11th, 1998. /s/ Kathryn R. Braun Kathryn R. Braun POWER OF ATTORNEY KNOW ALL MEN BY THESE PRESENTS that the undersigned constitutes and appoints Kathryn A. Braun, Nolan E. Karras, Alan K. Simpson, Don M. Wheeler, and Nancy Wilgenbusch, and each of them, his or her true and lawful attorneys and agents, with full power of substitution and resubstitution for him or her and in his or her name, place and stead, in any and all capacities, to sign the Annual Report of PacifiCorp on Form 10-K for the year ended December 31, 1997 and any and all amendments thereto, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys and agents, and each of them, full power and authority to do any and all acts and things necessary or advisable to be done, as fully and to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys and agents or any of them, or their or his or her substitute or substitutes, may lawfully do or cause to be done by virtue hereof. Dated: February 11th, 1998. /s/ Frederick W. Buckman Frederick W. Buckman POWER OF ATTORNEY KNOW ALL MEN BY THESE PRESENTS that the undersigned constitutes and appoints Kathryn A. Braun, Nolan E. Karras, Alan K. Simpson, Don M. Wheeler, and Nancy Wilgenbusch, and each of them, his or her true and lawful attorneys and agents, with full power of substitution and resubstitution for him or her and in his or her name, place and stead, in any and all capacities, to sign the Annual Report of PacifiCorp on Form 10-K for the year ended December 31, 1997 and any and all amendments thereto, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys and agents, and each of them, full power and authority to do any and all acts and things necessary or advisable to be done, as fully and to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys and agents or any of them, or their or his or her substitute or substitutes, may lawfully do or cause to be done by virtue hereof. Dated: February 11th, 1998. /s/ C. Todd Conover C. Todd Conover POWER OF ATTORNEY KNOW ALL MEN BY THESE PRESENTS that the undersigned constitutes and appoints Kathryn A. Braun, Nolan E. Karras, Alan K. Simpson, Don M. Wheeler, and Nancy Wilgenbusch, and each of them, his or her true and lawful attorneys and agents, with full power of substitution and resubstitution for him or her and in his or her name, place and stead, in any and all capacities, to sign the Annual Report of PacifiCorp on Form 10-K for the year ended December 31, 1997 and any and all amendments thereto, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys and agents, and each of them, full power and authority to do any and all acts and things necessary or advisable to be done, as fully and to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys and agents or any of them, or their or his or her substitute or substitutes, may lawfully do or cause to be done by virtue hereof. Dated: February 11th, 1998. /s/ Nolan E. Karras Nolan E. Karras POWER OF ATTORNEY KNOW ALL MEN BY THESE PRESENTS that the undersigned constitutes and appoints Kathryn A. Braun, Nolan E. Karras, Alan K. Simpson, Don M. Wheeler, and Nancy Wilgenbusch, and each of them, his or her true and lawful attorneys and agents, with full power of substitution and resubstitution for him or her and in his or her name, place and stead, in any and all capacities, to sign the Annual Report of PacifiCorp on Form 10-K for the year ended December 31, 1997 and any and all amendments thereto, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys and agents, and each of them, full power and authority to do any and all acts and things necessary or advisable to be done, as fully and to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys and agents or any of them, or their or his or her substitute or substitutes, may lawfully do or cause to be done by virtue hereof. Dated: February 14th, 1998. /s/ Robert G. Miller Robert G. Miller POWER OF ATTORNEY KNOW ALL MEN BY THESE PRESENTS that the undersigned constitutes and appoints Kathryn A. Braun, Nolan E. Karras, Alan K. Simpson, Don M. Wheeler, and Nancy Wilgenbusch, and each of them, his or her true and lawful attorneys and agents, with full power of substitution and resubstitution for him or her and in his or her name, place and stead, in any and all capacities, to sign the Annual Report of PacifiCorp on Form 10-K for the year ended December 31, 1997 and any and all amendments thereto, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys and agents, and each of them, full power and authority to do any and all acts and things necessary or advisable to be done, as fully and to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys and agents or any of them, or their or his or her substitute or substitutes, may lawfully do or cause to be done by virtue hereof. Dated: February 11th, 1998. /s/ Verl R. Topham Verl R. Topham POWER OF ATTORNEY KNOW ALL MEN BY THESE PRESENTS that the undersigned constitutes and appoints Kathryn A. Braun, Nolan E. Karras, Alan K. Simpson, Don M. Wheeler, and Nancy Wilgenbusch, and each of them, his or her true and lawful attorneys and agents, with full power of substitution and resubstitution for him or her and in his or her name, place and stead, in any and all capacities, to sign the Annual Report of PacifiCorp on Form 10-K for the year ended December 31, 1997 and any and all amendments thereto, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys and agents, and each of them, full power and authority to do any and all acts and things necessary or advisable to be done, as fully and to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys and agents or any of them, or their or his or her substitute or substitutes, may lawfully do or cause to be done by virtue hereof. Dated: February 11th, 1998. /s/ Don M. Wheeler Don M. Wheeler POWER OF ATTORNEY KNOW ALL MEN BY THESE PRESENTS that the undersigned constitutes and appoints Kathryn A. Braun, Nolan E. Karras, Alan K. Simpson, Don M. Wheeler, and Nancy Wilgenbusch, and each of them, his or her true and lawful attorneys and agents, with full power of substitution and resubstitution for him or her and in his or her name, place and stead, in any and all capacities, to sign the Annual Report of PacifiCorp on Form 10-K for the year ended December 31, 1997 and any and all amendments thereto, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys and agents, and each of them, full power and authority to do any and all acts and things necessary or advisable to be done, as fully and to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys and agents or any of them, or their or his or her substitute or substitutes, may lawfully do or cause to be done by virtue hereof. Dated: February 11th, 1998. /s/ Nancy Wilgenbusch Nancy Wilgenbusch POWER OF ATTORNEY KNOW ALL MEN BY THESE PRESENTS that the undersigned constitutes and appoints Kathryn A. Braun, Nolan E. Karras, Alan K. Simpson, Don M. Wheeler, and Nancy Wilgenbusch, and each of them, his or her true and lawful attorneys and agents, with full power of substitution and resubstitution for him or her and in his or her name, place and stead, in any and all capacities, to sign the Annual Report of PacifiCorp on Form 10-K for the year ended December 31, 1997 and any and all amendments thereto, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys and agents, and each of them, full power and authority to do any and all acts and things necessary or advisable to be done, as fully and to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys and agents or any of them, or their or his or her substitute or substitutes, may lawfully do or cause to be done by virtue hereof. Dated: February 11th, 1998. /s/ Peter I. Wold Peter I. Wold POWER OF ATTORNEY KNOW ALL MEN BY THESE PRESENTS that the undersigned constitutes and appoints Kathryn A. Braun, Nolan E. Karras, Alan K. Simpson, Don M. Wheeler, and Nancy Wilgenbusch, and each of them, his or her true and lawful attorneys and agents, with full power of substitution and resubstitution for him or her and in his or her name, place and stead, in any and all capacities, to sign the Annual Report of PacifiCorp on Form 10-K for the year ended December 31, 1997 and any and all amendments thereto, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys and agents, and each of them, full power and authority to do any and all acts and things necessary or advisable to be done, as fully and to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys and agents or any of them, or their or his or her substitute or substitutes, may lawfully do or cause to be done by virtue hereof. Dated: February 11th, 1998. /s/ Richard T. O'Brien Richard T. O'Brien POWER OF ATTORNEY KNOW ALL MEN BY THESE PRESENTS that the undersigned constitutes and appoints Kathryn A. Braun, Nolan E. Karras, Alan K. Simpson, Don M. Wheeler, and Nancy Wilgenbusch, and each of them, his or her true and lawful attorneys and agents, with full power of substitution and resubstitution for him or her and in his or her name, place and stead, in any and all capacities, to sign the Annual Report of PacifiCorp on Form 10-K for the year ended December 31, 1997 and any and all amendments thereto, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys and agents, and each of them, full power and authority to do any and all acts and things necessary or advisable to be done, as fully and to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys and agents or any of them, or their or his or her substitute or substitutes, may lawfully do or cause to be done by virtue hereof. Dated: February 11th, 1998. /s/ W. Charles Armstrong W. Charles Armstrong POWER OF ATTORNEY KNOW ALL MEN BY THESE PRESENTS that the undersigned constitutes and appoints Kathryn A. Braun, Nolan E. Karras, Alan K. Simpson, Don M. Wheeler, and Nancy Wilgenbusch, and each of them, his or her true and lawful attorneys and agents, with full power of substitution and resubstitution for him or her and in his or her name, place and stead, in any and all capacities, to sign the Annual Report of PacifiCorp on Form 10-K for the year ended December 31, 1997 and any and all amendments thereto, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys and agents, and each of them, full power and authority to do any and all acts and things necessary or advisable to be done, as fully and to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys and agents or any of them, or their or his or her substitute or substitutes, may lawfully do or cause to be done by virtue hereof. Dated: February 17th, 1998. /s/ Alan K. Simpson Alan K. Simpson EX-27 9 EXHIBIT 27
UT THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM PACIFICORP'S FORM 10-K DATED DECEMBER 31, 1997 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 1,000 12-MOS DEC-31-1997 JAN-01-1997 DEC-31-1997 PER-BOOK 7,825,500 2,051,300 2,182,300 389,000 1,432,100 13,880,200 3,214,600 0 1,106,300 4,320,900 175,000 66,400 4,390,700 6,300 0 182,900 364,600 0 23,800 900 4,348,700 13,880,200 6,278,000 109,500 5,475,500 5,585,000 693,000 (28,100) 664,900 439,500 663,700 22,800 640,900 320,000 217,500 834,100 2.16 2.16 NET INCOME AND EARNINGS FOR COMMON INCLUDE INCOME FROM DISCONTINUED OPERATIONS OF $89,200, GAIN ON SALE OF DISCONTINUED OPERATIONS OF $365,100 AND EXTRAORDINARY LOSS FROM REGULATORY ASSET IMPAIRMENT OF $16,000. EPS INCLUDES EARNINGS PER COMMON SHARE FROM DISCONTINUED OPERATIONS OF $0.30, GAIN ON SALE OF DISCONTINUED OPERATIONS OF $1.23 AND EXTRAORDINARY LOSS FROM REGULATORY ASSET IMPAIRMENT OF $0.05.
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