-----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, DYuZwP3Qy3WqL/YICeIZlkWIP+/MQajyL2XPyxbsSnyQhSZE9TrnQ4A7UthXpNcJ 43P5wF5B4n/xxY9GPytKTg== 0000893877-99-000396.txt : 19990608 0000893877-99-000396.hdr.sgml : 19990608 ACCESSION NUMBER: 0000893877-99-000396 CONFORMED SUBMISSION TYPE: DEFA14A PUBLIC DOCUMENT COUNT: 1 FILED AS OF DATE: 19990607 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: DEFA14A SEC ACT: SEC FILE NUMBER: 001-05152 FILM NUMBER: 99641574 BUSINESS ADDRESS: STREET 1: 825 NE MULTNOMAH STE 2000 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 DEFA14A 1 ADDITIONAL PROXY SOLICITING MATERIALS SCHEDULE 14A (Rule 14a-101) INFORMATION REQUIRED IN PROXY STATEMENT SCHEDULE 14A INFORMATION Proxy Statement Pursuant to Section 14(a) of the Securities Exchange Act of 1934 Filed by the Registrant [X] Filed by a Party Other than the Registrant [ ] Check the appropriate box: [ ] Preliminary Proxy Statement [ ] Confidential, for Use of the Commission Only (as permitted by [ ] Definitive Proxy Statement Rule 14a-6(e)(2)) [X] Definitive Additional Materials [ ] Soliciting Material Pursuant to Rule 14a-11(c) or Rule 14a-12 PACIFICORP (Name of Registrant as Specified in Its Charter) Payment of Filing Fee (check the appropriate box): [ ] No fee required. [ ] Fee computed on table below per Exchange Act Rules 14a-6(i)(1) and 0-11. (1) Title of each class of securities to which transaction applies: (2) Aggregate number of securities to which transaction applies: (3) Per unit price or other underlying value of transaction computed pursuant to Exchange Act Rule 0-11 (Set forth the amount on which the filing fee is calculated and state how it was determined): (4) Proposed maximum aggregate value of transaction: (5) Total fee paid: [X] Fee paid previously with preliminary materials. [ ] Check box if any part of the fee is offset as provided by Exchange Act Rule 0-11(a)(2) and identify the filing for which the offsetting fee was paid previously. Identify the previous filing by registration statement number, or the Form or Schedule and the date of its filing. (1) Amount previously paid: (2) Form, Schedule or Registration Statement No.: (3) Filing Party: (4) Date Filed: in many ways, we're back to our roots. we think there is great value in the strategy that has brought us back. here's why. the pacificorp 1998 annual report a winning combination o a word about ScottishPower and the pending merger who is ScottishPower? On December 7, 1998, PacifiCorp announced a definitive agreement to merge with ScottishPower, a leading multi-utility located in the United Kingdom. The combined company, to be called ScottishPower, will have approximately 7 million customers and 23,500 employees worldwide. The headquarters will be in Glasgow, Scotland, with U.S. headquarters remaining in Portland, Oregon. PacifiCorp will continue to operate as Pacific Power and Utah Power in its retail service territories. Under the terms of the agreement, each PacifiCorp shareholder will receive tax-free 0.58 American Depositary Shares (ADSs) or 2.32 ordinary shares of ScottishPower for each share of PacifiCorp. Based on a share price of 650p, the ScottishPower reference share price used in negotiations, the merger terms imply a price of $25 1/8 per PacifiCorp common share, representing a significant premium over the trading value of PacifiCorp stock at that time. Based on the closing price of ScottishPower on December 4, 1998, the last business day prior to the announcement, the merger terms imply a value for the equity of PacifiCorp of $7.9 billion. The premium will depend on the stock prices of ScottishPower and PacifiCorp at the time the merger is final. The merger is subject to approval by the shareholders of both companies, the U.S. Federal Energy Regulatory Commission and the regulatory commissions in certain of the states served by PacifiCorp. The merger already received clearance under the Hart-Scott-Rodino Antitrust Improvements Act and from Australian and U.K. regulatory authorities. As we went to press with this annual report, proxy materials had been mailed to all shareholders, and all regulatory filings had been made. The ScottishPower Group [map depicting ScottishPower territories omitted] ScottishPower and PacifiCorp ScottishPower's ordinary shares will continue to be listed in London and ScottishPower's ADSs, each representing four ordinary shares, will continue to be listed in New York. PacifiCorp shareholders can choose whether they receive ScottishPower ADSs or ordinary shares. We believe this proposed merger offers significant benefits to our customers and delivers good value to our shareholders. Together, we will work to provide enhanced services to customers, utilizing the best practices of each company in the U.S., U.K. and Australia. With ScottishPower, we will be able to pursue more effectively our strategy of concentrating on our core electricity business, improving performance for both customers and shareholders. ScottishPower, a leading multi-utility company in the United Kingdom, has a proven track record of delivering value to shareholders through improving operating efficiencies and integrating acquisitions. ScottishPower serves 5 million customers - about one in five British households. The company's activities span the generation, transmission, distribution and supply of electricity, gas supply, water and wastewater services and telecommunications. ScottishPower is one of the largest companies in the U.K. with a market capitalization of $13.5 billion. Scottish Power has quickly grown from a regional electricity company to one of the 25 largest investor-owned utilities in the world. With a strong financial and operations position, ScottishPower is dedicated to delivering benefits to customers and enhanced returns to shareholders. The transaction is expected to close by the end of 1999.
1998 financial highlights 1998 to 1997 percentage for the year || millions of dollars, except per share amounts 1998 1997 comparison - ---------------------------------------------------------------------------------- ------------ ------------ Operating Results Revenues $ 5,580 $ 4,549 23% Income from Operations 681 811 (16) Income from Continuing Operations 111 233 (52) Discontinued Operations (147) 447 (133) Extraordinary Item - (16) 100 Net Income (Loss) (36) 664 (105) Earnings (Loss) on Common Stock (55) 641 (109) Data per Common Share Earnings Continuing Operations $ 0.30 $ 0.71 (58) Discontinued Operations (0.49) 1.50 (133) Extraordinary Item - (0.05) 100 Total (0.19) 2.16 (109) Dividends Paid 1.08 1.08 - Book Value 13.31 14.55 (9) Stock Price Range 26 3/4 - 18 3/4 27 5/16 - 19 1/4 (23)/a Financial Position at December 31 Assets 12,989 13,627 Capitalization 9,658 9,870 Capital Structure Total Debt 53% 50% Preferred Securities of Trusts 4 4 Preferred Stock 2 2 Common Equity 41 44 Other Statistics Return on Average Common Equity/b (1.3)% 15.7% Market to Book Value (Year End) 158% 188% Cash Flows from Continuing Operations $ 685 $ 836 Common Shares (Average, Thousands) 297,229 296,094 Dividend Payout Ratio/b (610)% 50% /a Based on year end price. /b 1998 includes the effects of the provision for losses on discontinued operations of $105 million, or $0.35 per share, special charges of $77 million, or $0.26 per share, and other adjustments of $132 million, or $0.45 per share. 1997 includes the effect of gains on sales of assets of $395 million, or $1.33 per share, special charges of $106 million, or $0.36 per share, other adjustments of $65 million, or $0.22 per share, and extraordinary item of $16 million, or $0.05 per share. If these items were excluded, the Return on Average Common Equity in 1998 and 1997 would have been 6.2% and 10.6%, respectively. The Dividend Payout Ratio in 1998 and 1997 would have been 124% and 74%, respectively.
[graphic bar chart depicting total investment return omitted] fellow shareholders, - ----------------------------------------------------------- In a difficult year for PacifiCorp, I am pleased that we put into action measures that were in the best interest of our shareholders. In April, we announced the end of our attempt to acquire The Energy Group (TEG). The decision was not easy, but the price of TEG had risen to a level that we believed would not provide acceptable returns for our shareholders. Our regret in the outcome of the TEG transaction was compounded by our poor earnings results. Overall, we reported a net loss for the year of $55 million, or $0.19 per share, and our share price declined 19 percent. [picture of Mr. McKennon omitted] Keith R. McKennon CHAIRMAN, PRESIDENT AND CHIEF EXECUTIVE OFFICER 3. - ----------------------------------------------------------- Such results are unacceptable to me, to your board of directors, and to PacifiCorp's management team. When your board of directors elected me as CEO in September 1998, I was asked to provide a realistic assessment of PacifiCorp and to recommend actions to improve shareholder value. To make my recommendations as meaningful as possible, I met with securities analysts, investors, customers and employees, and the message was clear: the company required a new, fully focused and achievable strategic direction. That strategy is to return to our roots, to the business we know best. In October, we announced that we would focus on our western U.S. electricity business and sell or shut down all unrelated endeavors with the exception of Powercor, our Australian electricity distribution company. We also embarked on an aggressive program to cut costs to address our realization that PacifiCorp must be smaller, leaner and have lower overhead. An early retirement program resulted in a net reduction of more than 700 jobs, and we expect to make more reductions in staff and support areas. 4. But even as we continue to in divesting nonstrategic assets we accomplish two goals: provide additional cash resources while putting all of our attention on our core business. - ----------------------------------------------------------- reduce costs, we remain committed to improved customer service and reinvestment in our electric operations. We also remain committed to the current annual dividend of $1.08 per share, and our goal is to deliver a five percent average annual growth in earnings per share, starting in the year 2000. When our strategic refocus was announced, I also promised to listen to anyone who had a proposal for building shareholder value better and faster. ScottishPower, a leading multi-utility located in the United Kingdom, made such a proposal and, in December 1998 our two companies announced a proposed merger. We believe this merger is in the best interests of our customers and delivers good value to our shareholders. The transaction also creates an opportunity for our shareholders to own a stake in a larger, faster-growing and financially strong company, which has excellent prospects for the future. 5. - ----------------------------------------------------------- With ScottishPower, we will be able to pursue more effectively our strategy of concentrating on our core electricity business in the west. The merger affirms the direction we have chosen and will provide a strong platform for future growth. We believe that the transaction will also enhance our ability to improve our performance and better serve our customers. It is important to note that the merger is subject to the approval of certain federal and state regulatory bodies, including the Federal Energy Regulatory Commission and regulatory commissions in Idaho, Oregon, Utah, Washington, Wyoming and California. Within the framework of our chosen strategy, the people of PacifiCorp have clear direction and purpose: listen to customers; be alert to greater efficiencies; and view these changes as opportunity. Our people possess the knowledge, skills and initiative necessary to successfully execute our new strategy and the merger with ScottishPower. One person we will miss is Don Wheeler, from Salt Lake City. He has been a member of our board of directors for 10 years and has made a substantial contribution to our company. Don retired from the board in February 1999, and I would like to thank him for his dedication to PacifiCorp and its stakeholders. 6. the people of PacifiCorp have clear direction and purpose: listen to customers; be alert to greater efficiencies; and consider these changes as opportunity - ----------------------------------------------------------- The future of your company is bright. PacifiCorp is located in one of the fastest-growing parts of the country. Our fundamentals remain sound with low-cost generation, an extensive transmission grid, knowledgeable employees and more than 85 years of reliable service to customers. We have the opportunity to grow both our regulated and unregulated business in the west, and our success in the west will provide the foundation for building shareholder value. As a fellow shareholder, I'd like to thank you for your continued support. Sincerely, KEITH R. MCKENNON Keith R. McKennon CHAIRMAN, PRESIDENT AND CHIEF EXECUTIVE OFFICER 7. [picture omitted] 8. We began by asking what best serves our shareholders and our customers. With that as a starting point, the decisions we've made are pretty straightforward. o core business o customer focus o cost reductions 9. PacifiCorp began in 1910 as the Pacific Power and Light Company. At the time, we provided electricity to 7,000 rural customers in the states of Oregon and Washington. Today, we are a Fortune 500 company providing electricity and energy services to 1.5 million customers in the western states of California, Idaho, Oregon, Utah, Washington and Wyoming. We also serve 560,000 electricity customers in the Australian states of Victoria and New South Wales through Powercor, our Australian electricity distribution company. We own or have ownership interests in five coal mines, which enables us to mine most of the coal we need for power generation. In 1998 we mined 22 million tons of coal, and though much of it is low-sulfur coal from the Powder River basin in Wyoming, scrubbers are installed on most of our plants to further reduce sulfur dioxide emissions. We have also been recognized by the U.S. Bureau of Surface Mine Reclamation for our award-winning coal mine reclamation efforts, and in a study released in April 1999 by The Mine Safety and Health Administration, our Bridger Coal Mine ranked first among U.S. surface coal mines for safety. Having mine operations next to our power plants helps us to operate some of the lowest-cost generating plants in the U.S., and contributes to our position as one of the lowest-cost electricity suppliers in the country. Our average net retail price is 4.7 cents per kilowatt-hour, compared to the national average of more than 7 cents. ----------------------------------------------------------------------- Our average net retail price is 4.7 cents per kilowatt-hour, compared to the national average of more than 7 cents. ----------------------------------------------------------------------- We own three major hydroelectric systems, and own or have interests in 17 thermal electric generating plants, giving us a total of 8,445 megawatts of low-cost generation. Access to the nation's most extensive transmission network also provides us with low-cost power supply options, in addition to opportunities to sell power. The 15,000 miles of transmission lines 10. give us nearly 150 points of interconnection and enable us to buy and sell power with more than 60 other utilities. All of these factors - low-cost generation, geographically diverse energy resources and an extensive transmission system - benefit our retail customers, and have also helped us develop a highly competitive wholesale energy business: in the western U.S., we are the largest wholesale power marketer among investor-owned utilities. ----------------------------------------------------------------------- In the western U.S., we are the largest wholesale power marketer among investor-owned utilities. ----------------------------------------------------------------------- In October, we embarked on a significant change in our strategic direction, designed to optimize these strengths and to improve our financial performance. That strategy is to focus on our domestic western electricity business and sell or shut down all unrelated businesses except for Powercor, our Australian electricity distribution business. Our commitment to shareholders is to deliver a five percent average annual growth in earnings per share, starting in the year 2000. We also intend to maintain the annual dividend at $1.08 per share. Our strong balance sheet and sustainable cash position allow us to return value to our shareholders via the dividend while we work on improving our earnings. In addition to providing good value to our shareholders, we are equally dedicated to finding new and innovative ways to enhance customer service and system reliability. We have already taken significant steps since October 1998 to improve billing and collections, power outage management, community relationships and business center performance. We are committed to providing the best among utility basics: low-cost, reliable power and exceptional customer service. Of all the strategic options we considered, this approach is clearly focused on what we do best, and with real dedication, it will bring the most value to both our shareholders and customers. 11. [picture omitted] 12. We are committed to providing the best among utility basics: low-cost, reliable power and exceptional customer service. o initiatives o divestitures o improvements 13. Our priority is to improve the operating and financial performance of our core business, and by doing so, enhance value for our shareholders. We intend to do this through cost reductions and by seeking rate increases where necessary. In January 1999 we deferred our request for rate increases for six months in order to place the highest priority on completing our merger with ScottishPower. However, we are determined to earn our authorized rate of return in each of the states where we do business, and will assess the need to seek rate relief later in the year. To reduce costs and improve cash flow from operations, we implemented two aggressive cost reduction programs. An early retirement program announced in January 1998 resulted in a net reduction of more than 700 jobs, and annual pre-tax cost savings of approximately $50 million. In the fourth quarter of 1998 we implemented a second cost reduction program aimed at achieving an additional pre-cost savings of $30 million from our continuing business. ----------------------------------------------------------------------- To reduce costs and improve cash flow from operations, we executed two aggressive cost reduction programs. ----------------------------------------------------------------------- We moved quickly to implement our new strategy, successfully closing or selling the majority of the underperforming assets that detracted from our core business. In the past six months we have: closed the eastern U.S. electricity-trading arm of PacifiCorp Power Marketing; shut down our business development activities in Turkey; agreed in March to the sale of EnergyWorks, our joint venture with Bechtel Enterprises; and in April sold TPC Corporation, our natural gas storage and marketing business for $150 million. The divestiture of other non-core businesses is also progressing, including our energy development activities in the Philippines, our investment in the Hazelwood Power Station in Australia and our investment in enoable, our joint venture with KN Energy. 14. In July 1998 we announced our intention to sell our electric service areas in California and Montana. The following November we finalized the sale of our Montana distribution system to Flathead Electric Cooperative for $92 million, and in April 1999 we announced the signing of a non-binding letter agreement with Nor-Cal Electric Authority for the sale of our California service area. The sale of these properties will allow us to focus on states where we have a larger customer base and more significant investment in assets. Focusing on the needs of our 1.5 million customers is also an integral part of our strategy. We reorganized our service functions in 1998 to be more responsive to our customers and to the communities we serve. ----------------------------------------------------------------------- In 1998 we reorganized our service functions to be more responsive to our customers and to the communities we serve. ----------------------------------------------------------------------- Our customers first point of contact with PacifiCorp is usually through our business centers in Salt Lake City, Utah and Portland, Oregon. To make that contact as pleasant and productive as possible, we are improving service levels at our business centers through employee training programs, the creation of more efficient work shifts and process improvement efforts. To ensure that we continue to provide our customers with reliable service, we intend to have our generation, transmission and distribution systems ready for the year 2000 by July 1999. We began our year 2000 preparations in 1996. Since then, we have dedicated significant time and resources to making sure our systems are performing optimally in the year 2000. These actions mark the beginning of a host of initiatives that will improve our performance, and we are on track to deliver exceptional customer service and better operations efficiency. 15. [picture omitted] 16. It would be easy to undervalue PacifiCorp. Yet, while there is much work to do, we believe that with your continued support, the future for your company is bright. o credibility o accountability o results 17. In 1998 we made solid progress toward implementing a strategic refocus on our domestic western electricity business. We moved quickly to execute our new strategy by selling non-core businesses, implementing a cost reduction program and making changes designed to improve customer service and reliability. These efforts are yielding results. Our recurring earnings for the fourth quarter 1998, the first reporting period following the implementation of our strategy, were in line with expectations, as were first quarter 1999 earnings. Our renewed emphasis on our western electricity business also extends to our environmental efforts and to the communities where we live and work. We achieved two major milestones in these areas in the past year. In April 1999 we began energy production at the Wyoming Wind Energy Project, one of the largest wind plants in the West outside of California. The facility is located on 2,156 acres between Laramie and Rawlins, Wyoming. The 69 wind energy turbines generate up to 41.4 megawatts of electricity, enough renewable power to serve 15-20,000 customers. ----------------------------------------------------------------------- Our new Wyoming wind plant is capable of generating 41.4 megawatts of electricity, enough renewable power to serve 15-20,000 customers. ----------------------------------------------------------------------- We own 80 percent of the $62 million project, and Eugene Water and Electric Board (EWEB) of Eugene, Oregon, owns the balance. Bonneville Power Administration has already committed to buy 15 megawatts of the plant's output. The project benefits a variety of stakeholders: tax revenues from the project will support local schools and community development efforts; consumers have access to an affordable, renewable energy 18. source; and the environment remains largely unaffected by the facility. Only one percent of the land will be removed from local use; local ranchers can use the remaining acreage for grazing livestock. As a result of this project, we were the recipients of Renewable Energy Northwest's Clean Energy Award, and received notice for our efforts in the Senate Congressional Record. A high point was also reached in our efforts to serve our communities. In 1998 we celebrated a decade of community commitment and support through the PacifiCorp Foundation. The Foundation was created in 1988 as a separate, nonprofit entity with a permanent endowment. It is the major philanthropic arm of PacifiCorp, Pacific Power and Utah Power, and helps to promote the health and vitality of our communities. In 10 years we have built the third largest utility foundation endowment in the U.S. and have contributed $25 million through more than 4,000 grants to a variety of organizations. Each year awards are made in four categories: civic and community organizations; education and research; culture and arts; and health and human services - with an emphasis on children, the environment and safety. ----------------------------------------------------------------------- In 10 years we have built the third largest utility foundation in the U.S., and contributed $25 million to our communities. ----------------------------------------------------------------------- We are accountable to many stakeholders, and we have a proud history of commitment and service to customers, shareholders, communities and the environment. We have made solid progress toward implementing a strategy designed to strengthen our core business and our service. While there is still much work to be done, the results we have achieved so far indicate that we are taking the right actions to improve the performance of our company and build credibility with all our stakeholders. 19. 1998 financial review ----------------------------------------------------------------- pg 22: management's discussion and analysis. pg 44: report of management. pg 45: independent auditors' report. pg 46: financial statements. pg 51: notes to consolidated financial statements. ----------------------------------------------------------------- 20. MANAGEMENT'S DISCUSSION AND ANALYSIS OVERVIEW OF 1998 During 1998, PacifiCorp and its subsidiaries (the "Company") took several major steps to redefine its objectives, reduce costs and develop plans for the future. In March, the Company abandoned its attempt to acquire The Energy Group PLC ("TEG") after another United States utility made a higher offer for TEG and the Company elected not to increase its offer. Subsequently, the Company reviewed its strategy and decided to refocus on its electricity businesses in the western United States and Australia and to exit its other domestic and international businesses. The businesses to be exited include the eastern United States electricity trading business of PacifiCorp Power Marketing, Inc. ("PPM"), the natural gas marketing and storage business of TPC Corporation ("TPC") and most of the Company's energy development businesses. On December 6, 1998, PacifiCorp signed an Agreement and Plan of Merger with Scottish Power plc ("ScottishPower") and NA General Partnership. ScottishPower subsequently announced its intention to establish a new holding company for the ScottishPower group pursuant to a court approved reorganization in the U.K. Accordingly, on February 23, 1999, the parties executed an amended and restated merger agreement (the "Agreement") under which PacifiCorp will become an indirect, wholly owned subsidiary of the new holding company, which will be renamed Scottish Power plc ("New ScottishPower"), and ScottishPower will become a sister company to PacifiCorp. The combined company will have seven million customers and 23,500 employees worldwide and will be headquartered in Glasgow, Scotland. PacifiCorp will continue to operate under its current name, and its headquarters will remain in Portland, Oregon. In the merger, each share of PacifiCorp's common stock will be converted into the right to receive 0.58 New ScottishPower American Depositary Shares ("ADS") (each New ScottishPower ADS represents four ordinary shares), which will be listed on the New York Stock Exchange, or, upon the proper election of the holders of PacifiCorp's common stock, 2.32 ordinary shares of New ScottishPower, which will be listed on the London Stock Exchange. Based on the issued and outstanding shares of ScottishPower and PacifiCorp on February 1, 1999, the holders of PacifiCorp's common stock will receive approximately 36% of the total issued share capital of New ScottishPower upon consummation of the merger. Based on the market prices of the ScottishPower ordinary shares and PacifiCorp's common stock on February 26, 1999, holders of PacifiCorp's common stock would receive a premium of approximately 17% over the closing sale price of PacifiCorp's common stock of $18.00. If the proposed reorganization is not completed, the parties will proceed under the original agreement, and PacifiCorp will become an indirect, wholly owned subsidiary of ScottishPower. The merger is not conditional on the reorganization becoming effective nor is the reorganization conditional upon the merger becoming effective. Both companies' boards of directors have approved the Agreement. However, before the transactions under the Agreement can be consummated, a number of conditions must be satisfied, including obtaining approvals and consents from shareholders of both companies, the United States Federal Energy Regulatory Commission ("FERC"), the United States Nuclear Regulatory Commission, the regulatory commissions in certain of the states served by the Company and Australian regulatory authorities. Generally, approval by the state regulatory commission is subject to a finding that the transaction is in the public interest. The commissions may attach conditions to their approval. Hearings on the merger have been scheduled for July and August 1999 by the Oregon, Utah, Wyoming and Idaho commissions. The parties have received early termination of the waiting period under the provisions of the Hart-Scott-Rodino Antitrust Improvement Act. Both companies expect to have shareholder meetings in mid-1999 requesting shareholder approval of the merger. In January 1998, the Company moved to reduce costs through an early retirement offering that resulted in a net decrease of 759 employees. In December 1998, the Company implemented a $30 million annual cost reduction program focused on further work force and overhead expense reductions. On March 4, 1999, the Utah Public Service Commission (the "UPSC") issued an order in a general rate case. In the order, the Company was required to refund $40 million through a credit on customer bills and to reduce annual revenues by $85 million, or 12%, effective March 1, 1999. 21 EARNINGS OVERVIEW OF THE COMPANY
millions of dollars, except per share information 1998 1997 1996 - ----------------------------------------------------------------------------------------------------------------- EARNINGS CONTRIBUTION (LOSS) ON COMMON STOCK Domestic Electric Operations $ 130.5 $ 165.5 $ 341.5 Australian Electric Operations1 3.0 54.2 31.9 Other Operations (52.2) (9.6) 27.1 --------------------------------------- Continuing Operations 91.3 210.1 400.5 Discontinued Operations (146.7) 446.8 74.6 Extraordinary item - (16.0) - --------------------------------------- $ (55.4) $ 640.9 $ 475.1 ======================================= EARNINGS (LOSS) PER COMMON SHARE - BASIC AND DILUTED Continuing Operations $ 0.30 $ 0.71 $ 1.37 Discontinued Operations (0.49) 1.50 0.25 Extraordinary item - (0.05) - --------------------------------------- $ (0.19) $ 2.16 $ 1.62 =======================================
In 1998 and 1997, the Company incurred a series of special charges, discontinued operations of certain businesses and incurred acquisition transaction costs. The table below sets forth the effects of these adjustments to assist the reader, but should not be construed to represent Generally Accepted Accounting Principles. Other than ScottishPower merger costs, the items summarized below are not expected to be recurring. EFFECTS OF ADJUSTMENTS ON EARNINGS (LOSS) PER COMMON SHARE
1998 1997 ----------------------------------------------- millions of dollars, except per share information total per share total per share - ------------------------------------------------------------------------------------------------------------------ Earnings (loss) in total and per common share - as reported $(55.4) $(0.19) $640.9 $ 2.16 REMOVE DISCONTINUED OPERATIONS (Income) loss of discontinued operations 41.7 0.14 (81.7) (0.27) Provision for losses of discontinued operations 105.0 0.35 - - Gain on sale of discontinued operations - - (365.1) (1.23) Remove extraordinary item - - 16.0 0.05 ----------------------------------------------- Earnings from Continuing Operations 91.3 0.30 210.1 0.71 ADJUSTMENTS - DOMESTIC ELECTRIC OPERATIONS Special charges 76.5 0.26 105.7 0.36 ScottishPower merger costs 13.2 0.04 - - Utah rate refund 23.4 0.08 - - ADJUSTMENTS - AUSTRALIAN ELECTRIC OPERATIONS Write down of Hazelwood 17.4 0.06 - - ADJUSTMENTS - OTHER OPERATIONS TEG costs and option losses 55.4 0.19 64.5 0.22 Gain on sale of TEG shares (9.8) (0.03) - - Write down of other energy businesses 32.4 0.11 - - Asset sale gains - - (30.0) (0.10) ----------------------------------------------- Total $299.8 $ 1.01 $350.3 $ 1.19/a =============================================== /a In 1997, the Company reported adjusted earnings per share of $1.52. Included in the calculation of $1.52 were earnings from discontinued operations and adjustments similar to those recorded in 1998 operations.
22 Earnings on common stock for the Company decreased $696 million, or $2.35 per share, compared to 1997. The Company's reported 1998 loss of $55 million, or $0.19 per share, included special charges of $77 million, or $0.26 per share, relating to the Company's early retirement program announced in January 1998 and the additional early retirement offer announced in the fourth quarter of 1998, $23 million, or $0.08 per share, relating to the Utah rate case, $13 million, or $0.04 per share, for ScottishPower merger costs, $54 million, or $0.18 per share, relating to the write off of costs associated with the TEG transaction, $2 million, or $0.01 per share, relating to closing foreign currency options in April 1998 associated with the termination bid for TEG and a $10 million, or $0.03 per share, gain relating to the sale of the TEG shares. In addition, the Company recorded charges in 1998 of $105 million, or $0.35 per share, relating to the provision for losses on disposition of the energy trading segment, $17 million, or $0.06 per share, relating to the write down of the Company's investment in Hazelwood, and $32 million, or $0.11 per share, relating to the provision for losses on disposition of other energy development businesses. The Company's 1997 earnings of $641 million 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 losses of $65 million, or $0.22 per share, relating to foreign currency exchange contracts associated with the bid for TEG and a $16 million, or $0.05 per share, extraordinary charge for the write off of allocable generation regulatory assets in California and Montana. Excluding the asset sale gains, special charges and other adjustments, the Company's 1998 earnings on common stock from continuing operations before extraordinary item would have been $300 million, or $1.01 per share, compared to $350 million, or $1.19 per share, in 1997, a decrease of $50 million, or $0.18 per share. DOMESTIC ELECTRIC OPERATIONS' contribution to earnings on common stock was $131 million, or $0.44 per share, in 1998. After adjusting earnings by $113 million, or $0.38 per share, for special charges, the Utah rate refund and other adjustments, the contribution was $244 million, or $0.82 per share. Domestic Electric Operations' contribution to earnings on common stock in 1997 was $271 million, or $0.92 per share, after adjusting earnings by $106 million, or $0.36 per share, for special charges. This $27 million decrease from 1997 earnings was the result of several factors, including lower wholesale margins in the western United States, less favorable hydroelectric conditions, costs relating to Year 2000 issues and implementation of a new SAP software operating environment. AUSTRALIAN ELECTRIC OPERATIONS' contribution to earnings on common stock was $13 million, or $0.04 per share, in 1998. After adjusting earnings by $17 million, or $0.06 per share, for the write down of the Company's investment in the Hazelwood Power Station and $7 million, or $0.02 per share, for currency exchange rate fluctuations, the contribution was $37 million, or $0.12 per share. The currency exchange rate for converting Australian dollars to United States dollars averaged 0.63 in 1998 compared to 0.74 in 1997, a 15% decrease. The effect of this change in exchange rates lowered United States dollar revenues by $112 million and costs by $105 million in 1998. The 1998 earnings were impacted by increased network fees due to the effects of contestability and a product recall loss. In addition, 1997 results included earnings associated with renegotiating certain Tariff H industrial customer contracts that added $10 million, or $0.03 per share. OTHER OPERATIONS reported net losses of $52 million in 1998, or $0.17 per share, as compared to a loss of $10 million, or $0.03 per share, in 1997. Losses relating to the decision to exit the energy development businesses totaled $32 million, or $0.11 per share. The 1998 results also included $54 million, or $0.18 per share, in costs associated with the Company's terminated bid for TEG, $2 million, or $0.01 per share, relating to closing foreign currency options in April 1998, and a gain of $10 million, or $0.03 per share, relating to the sale of the TEG shares. The 1997 results included a loss of $65 million, or $0.22 per share, associated with closing foreign currency options and initial option premium costs relating to the Company's offer for TEG. Other Operations in 1997 also included a $30 million, or $0.10 per share, gain on the sale of Pacific Generation Company ("PGC"). DISCONTINUED OPERATIONS reported losses of $147 million, or $0.49 per share, in 1998 compared to income in 1997 of $447 million, or $1.50 per share. The 1998 results included $105 million, or $0.35 per share, for the losses anticipated to dispose of TPC and exit the eastern United States energy trading business and a loss of $42 million, or $0.14 per share, relating to these operations prior to discontinuance. The 1997 results included the gain on the sale of the Company's telecommunications operations and the earnings from normal operations until their sale in December 1997. 23
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 Pacific Telecom, Inc. ("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 ended November 30, 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. DOMESTIC ELECTRIC OPERATIONS REVENUES
millions of dollars 1998 1997 1996 - ---------------------------------------------------------------------------------------------------------------- REVENUES Wholesale sales and market trading $ 2,583.6 $ 1,428.0 $ 738.8 Residential 806.6 814.0 801.4 Industrial 705.5 709.9 719.3 Commercial 653.5 640.9 623.3 Other 95.9 114.1 109.0 ------------------------------------ $ 4,845.1 $ 3,706.9 $2,991.8 ====================================
millions of kWh 1998 1997 1996 - ---------------------------------------------------------------------------------------------------------------- ENERGY SALES Wholesale sales and market trading 94,077 59,143 29,665 Residential 12,969 12,902 12,819 Industrial 20,966 20,674 20,332 Commercial 12,299 11,868 11,497 Other 651 705 640 ------------------------------------- 140,962 105,292 74,953 =====================================
Domestic Electric Operations' revenues increased $1.14 billion, or 31%, from 1997 to $4.85 billion in 1998 primarily from an increase in wholesale revenues of $1.16 billion, or 81%. Retail revenues were flat compared to 1997, remaining at $2.20 billion. Although wholesale trading revenues have grown substantially over the past few years, in 1998 the retail load represented 45% of total Domestic Electric Operations' revenues. The active wholesale market led to an increase in revenues of $1.16 billion, or 81%, in 1998 to $2.58 billion. Energy volumes increased 59%, driven by a $917 million increase in short-term firm and spot market sales. Sales prices for short-term firm and spot market sales averaged $26 per megawatt hour ("MWh") in 1998, compared to $20 per MWh in 1997, resulting in $242 million in additional revenues. Decreased long-term firm contract volumes lowered wholesale revenues by $3 million in 1998. The Company expects a reduced level of revenues in 1999 as a result of its decision to scale back short-term wholesale trading activities. 24 Residential revenues were down $7 million, or 1%, to $807 million in 1998. Growth in the average number of residential customers of 2% added $19 million to revenues. The Utah rate order reduced revenues by $16 million. Declines in customer usage, partially attributable to weather, reduced revenues by $13 million in 1998 compared to 1997. Industrial revenues decreased $4 million, or 1%, to $706 million in 1998. The Utah rate order reduced revenues by $8 million. Billing adjustments of $5 million for certain industrial customers reduced revenues in 1997. Commercial revenues increased $13 million, or 2%, to $654 million in 1998. Energy sales volumes increased 4% over the prior year. A 2% growth in the average number of customers added $17 million to revenues, and increased customer usage added $5 million to revenues. The Utah rate order reduced revenues by $13 million. Other revenues decreased by $18 million, or 16%, to $96 million in 1998. The primary cause of this unfavorable variance was revenue adjustments relating to changes in property tax legislation. 1997 COMPARED TO 1996 Revenues rose 24%, or $715 million, in 1997 primarily due to a 99% increase in kilowatt hours ("kWh") sold in the wholesale market. Residential revenues were up $13 million primarily due to a 3% growth in the average number of customers and a price increase in Oregon effective July 1996. Commercial revenues increased $18 million primarily due to customer growth of 2% in Oregon and 5% in Utah. In early 1997, the Utah Division of Public Utilities (the "UDPU") and the Utah Committee of Consumer Services (the "UCCS") filed a joint petition with the UPSC requesting the UPSC to commence proceedings to establish new rates for Utah customers. The UDPU and the UCCS suggested changes to the method for allocating costs among the six states with retail customers served by the Company, the Company's authorized return on equity and certain other accounting adjustments. Subsequently in March 1997, the Utah legislature passed a bill that created a legislative task force to study electric restructuring and customer choice issues in Utah. The bill precluded the UPSC 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. In November 1997, the legislative task force recommended that further study was needed and that no legislation be proposed in the 1998 legislative session for the deregulation of electric utilities. During 1997, the UPSC held hearings on the method used in allocating common (generation, transmission and corporate related) costs among the Company's jurisdictions and issued an order in April 1998. Under the order, differences in allocations associated with the 1989 merger of Pacific Power & Light Company and Utah Power & Light Company were to be eliminated over five years on a straight-line basis. The phase-out of the differences was to be completed by January 1, 2001 and could have reduced Utah customer prices by about $50 to $60 million annually once fully implemented. The ratable impact of this order was to be included in a general rate case thereby combining it with all other cost-of-service items in determining the ultimate impact on customer prices. In 1998, the UPSC commenced a general rate case to consider the impact of the April 1998 allocation order, other cost-of-service issues and the appropriateness of the Company's authorized rate of return on equity. On March 4, 1999, an order was issued by the UPSC in the general rate case. The order requires the Company to reduce revenues in the state of Utah by $85 million, or 12%, annually. The UPSC also ordered that the allocation order be implemented immediately and not phased-in as originally ordered. Additionally, the UPSC ordered a refund to be issued through a credit on customer bills of $40 million. The Company recorded a $38 million reduction in revenues in 1998 and will record $2 million in 1999. The refund covers a period from March 14, 1997 to February 28, 1999. The beginning date is consistent with the timing of Utah legislation imposing a moratorium on rate changes after the UDPU and the UCCS requested a general rate case. The $85 million reduction will commence on March 1, 1999. The order also reduced the Company's authorized rate of return on equity from 12.1% to 10.5%. The Company has asked the UPSC to reconsider issues in the order involving approximately $41 million of the $85 million rate decrease. Among these issues is the method of implementing the April 1998 allocation order. The Company is not seeking reconsideration of the reduction in its authorized return on equity to 10.5% nor the changes in the way costs are allocated among the six states served by the Company. 25 OPERATING EXPENSES
millions of dollars 1998 1997 1996 - ---------------------------------------------------------------------------------------------------------------- Purchased power $2,497.0 $ 1,296.5 $ 618.7 Fuel 477.6 454.2 443.0 Other operations and maintenance 457.3 470.0 444.2 Depreciation and amortization 386.6 389.1 343.4 Administrative, general and taxes-other 331.4 325.4 272.7 Special charges 123.4 170.4 - ------------------------------------- $4,273.3 $ 3,105.6 $ 2,122.0 ===================================== Operating Expenses as a percent of Revenue (excluding special charges) 86% 79% 71%
Operating expenses increased $1.17 billion, or 38%, to $4.27 billion in 1998, as a result of a significant increase in purchased power costs. In addition to base energy and capacity from its thermal and hydroelectric resources, the Company utilizes a mix of long-term, short-term and nonfirm power purchases to meet its own retail load commitments and to make wholesale power sales to other utilities. Purchased power expense increased $1.20 billion, or 93%, to $2.50 billion in 1998. The higher expense was primarily due to a 33.9 million MWh increase in short-term firm and spot market energy purchases, a 74% increase from 1997, which increased purchased power expense by $937 million. Short-term firm and spot market purchase prices averaged $26 per MWh in 1998 versus $19 per MWh in 1997, a 36% increase. The increase in purchase prices added $255 million to costs in 1998. Lower volumes offset by higher prices relating to long-term firm purchased power contracts resulted in a $4 million increase in purchased power costs in 1998. The Company expects a reduced level of power purchases in 1999 as a result of its decision to scale back short-term wholesale trading activities. SHORT-TERM FIRM AND SPOT MARKET SALES AND PURCHASES
1998 1997 1996 - ----------------------------------------------------------------------------------------------------------------- Total sales volume (thousands of MWh) 80,097 44,927 16,394 Average sales price ($/MWh) $ 25.88 $ 20.35 $ 14.94 --------------------------------------- Revenues (millions) $ 2,073 $ 914 $ 245 --------------------------------------- Total purchase volume (thousands of MWh) 79,693 45,772 16,930 Average purchase price ($/MWh) $ 25.88 $ 19.04 $ 13.31 --------------------------------------- Expenses (millions) $ 2,062 $ 871 $ 225 --------------------------------------- Net (millions) $ 11 $ 43 $ 20 =======================================
Fuel expense was up $23 million, or 5%, to $478 million in 1998. Thermal generation increased 6% to 51.9 million MWh. The average cost per MWh increased to $9.37 from $9.29 in the prior year due to increased generation at plants with higher fuel costs. The shift in generation resulted from unscheduled plant outages and higher market prices for energy. Hydroelectric generation decreased 6% compared to 1997 due to lower stream flows. Other operations and maintenance expense decreased $13 million, or 3%, to $457 million in 1998. Employee-related costs decreased $24 million primarily due to the implementation of the early retirement plan initiated in the first quarter of 1998. Partially offsetting this decrease were higher distribution plant maintenance expenses of $6 million and higher customer service expenses of $4 million. Depreciation and amortization expense decreased $3 million, or 1%, to $387 million in 1998. Depreciation in 1997 included a $17 million increase reflecting higher depreciation rates, and increased plant in service in 1998 added $9 million. In July 1998, the Company withdrew its regulatory filings relating to a depreciation study because regulatory approvals to increase depreciation rates based on this study were unlikely. As a result of the decision to withdraw 26 the filings, the Company ceased recording the increased depreciation expense in the third quarter. For the six months ended June 30, 1998, the Company recorded $6 million in additional depreciation as a result of the study. In December 1998, the Company filed applications with the Oregon, Utah and Wyoming regulatory commissions to increase depreciation annually by $77 million. No amounts have been recorded as additional expense pending approval by these commissions. The Company's intention is to seek revenue increases consistent with the higher depreciation expense. Administrative, general and taxes-other expenses increased $6 million, or 2%, to $331 million in 1998. This increase included $6 million of expenses relating to Year 2000 issues, $5 million relating to the ongoing implementation of the Company's new SAP software operating environment and $5 million of employee related costs. Administrative and general expenses in 1997 included process re-engineering costs of $10 million relating to the Company's new SAP software operating environment. SPECIAL CHARGES
net millions of dollars pretax income eps - ----------------------------------------------------------------------------------------------------------------- 1998 Early retirement and cost reduction program $ 123.4 $ 76.5 $ 0.26 ====================================== 1997 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 January 1998, the Company announced a plan to reduce its work force in the United States. This reduction was accomplished through a combination of voluntary early retirement and special severance. The plan anticipated a net reduction of approximately 600 positions, or 7% of the Company's United States work force, from across all areas of Domestic Electric Operations. The actual net work force reduction from this program was 759 positions, with 981 employees accepting the offer and 222 vacated positions being backfilled. The Company recorded a $70 million after-tax charge in 1998 relating to the early retirement program. The actual cost of the early retirement program was approximately equal to the amount accrued. These reductions were expected to result in annual pretax savings to the Company of approximately $50 million. The savings in 1998 totaled approximately $18 million. In the fourth quarter of 1998, the Company initiated a cost reduction program that included involuntary employee severance and enhanced early retirement for employees who met certain age and service criteria and were displaced in conjunction with the cost reduction initiatives. Approximately 167 employees were displaced, with 35 of them eligible for the enhanced early retirement, and the Company recorded a $6 million after-tax charge. It is anticipated that these amounts will be fully paid out in early 1999. In 1997, the Company recorded a series of special charges at Domestic Electric Operations. The Company concluded that the Glenrock Mine was uneconomical to continue to operate under current and expected market conditions due to increased mining stripping ratios, reduced coal quality and related operating costs. Therefore, a $64 million charge was recorded in 1997 to write down asset values by $23 million in property, plant and equipment, $5 million in other assets and to record a liability of $36 million in other deferred credits for acceleration of reclamation cost accruals due to early closure of the mine. The carrying amount of the net assets at December 31, 1998 is $9 million. The reclamation costs were based on an external study and the write downs of property, plant and equipment and other assets were based on weighing the ongoing costs of operating the mine against purchasing coal from third party resources. It is anticipated that reclamation of the mine site will commence in 1999 and is estimated to be completed in 2006. The Company also determined that recovery of its regulatory assets applicable to deferred pension costs included on the balance sheet in regulatory assets, 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 in 1997 for these deferred regulatory assets. 27 In addition, the Company recorded a $19 million charge in 1997 for the impairment of certain information system assets ("IT systems") that were included in its property, plant and equipment balances. These IT systems were retired as a direct result of the Company's installation of SAP enterprise-wide software. 1997 COMPARED TO 1996 Purchased power more than doubled in 1997 due to the growth in the Company's wholesale trading market. 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. In addition, special charges increased $170 million due to the Glenrock mine closure costs of $64 million, the write off of deferred regulatory pension costs of $87 million, and impairment charges on IT systems of $19 million. OTHER INCOME AND EXPENSE Other expenses increased $20 million in 1998, which included $13 million of ScottishPower merger costs and $6 million of higher minority interest expense relating to the issuance of quarterly income preferred securities in August 1997. Income tax expense decreased $9 million, to $103 million, due to the decline in pretax income. See Note 14 of Notes to Consolidated Financial Statements. 1997 COMPARED TO 1996 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. INDUSTRY CHANGE, COMPETITION AND DEREGULATION INDUSTRY CHANGE The electric power industry continues to experience change. The key driver for this change is public, regulatory and governmental support for replacing the traditional cost-of-service regulatory framework with an open market competitive framework where the customers have a choice of energy supplier. The pace at which this change will occur has slowed as regulators and legislators struggle with conversion and implementation issues. However, federal laws and regulations have been amended to provide for open access to transmission systems, and various states have adopted or are considering new regulations to allow open access for all energy suppliers. 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 in extending contract lives. DEREGULATION Domestic Electric Operations continues to develop its competitive strategy as legislation, regulation and market opportunities evolve. The Company supports increased customer choice if the transition to competitive markets takes place under terms and conditions that are equitable to all involved. The Company will support direct access and other restructuring initiatives only when their terms are fair to all customers, the Company and its shareholders. The move toward an open or competitive marketplace for electric power may result in "stranded costs" relating to certain current investments, deferred costs and contractual commitments incurred under regulation that may not be recoverable in a competitive market. The calculation of stranded costs requires certain complex and 28 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 existing generation resources persists. This projected trend in price decreases 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. Based upon a 1997 study, the Company estimated 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 a regulatory order regarding competition is issued. Additionally, the EITF concluded that regulatory assets and liabilities applicable to businesses being deregulated should be written off unless their recovery is provided for through future regulated cash flows. Legislative actions in California and Montana during 1996 and 1997 mandated customer choice of electricity supplier, moving away from cost-based regulation to competitive market rates for the generation portion of the electric business. As a result of these legislative actions, the Company evaluated its generation regulatory assets and liabilities in California and Montana based upon future regulated cash flows and ceased the application of SFAS 71 to its generation business allocable to California and Montana. Domestic Electric Operations recorded an extraordinary loss of $16 million, or $0.05 per share, in 1997 for the write off of regulatory assets in these states. The regulatory assets written off resulted primarily from deferred taxes allocated to California and Montana. The allocation among states was based on plant balances. In 1998, the Company announced its intent to seek buyers for its California and Montana electric distribution assets. This action was in response to the continued decline in earnings on the assets and the changes in the legislative and regulatory environments in these states. The Company issued requests for proposals to interested parties on July 20, 1998. On November 5, 1998, the Company sold its Montana electric distribution assets to Flathead Electric Cooperative, Inc. and received proceeds of $89 million, net of taxes and customer refunds. The Company returned $4 million of the $8 million gain on the sale to Montana customers as negotiated with the Montana Public Service Commission (the "MPSC") and the Montana Consumer Counsel. The Company has received bids for its California electric distribution assets. These bids remain open and the Company is holding discussions with the bidders. In addition, the Company is participating in a docket concerning the transition plan the Company filed in compliance with direct access legislation in Montana. The Company has asserted in that docket that it has significant stranded costs relating to its Montana service territory. However, the Company has stated its willingness to forego recovery of those stranded costs as a result of the sale of the Montana service territory. Other parties in the proceeding believe the Company has stranded benefits, rather than stranded costs, and that those benefits should be returned to customers. The Company believes that the concept of stranded benefits is not addressed by Montana legislation and there is no obligation to return stranded benefits to customers even if the MPSC finds that such benefits exist. The outcome of this proceeding is uncertain. 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 resulted in a $3.5 million annual reduction in revenues. The Company is considering filing a petition for modification of this order. The Oregon Public Utility Commission and the Company have agreed to an Alternate Form of Regulation ("AFOR") for the Company's Oregon distribution business. The AFOR allows for index-related price increases in 29 1998, 1999 and 2000, with an annual cap of 2% of distribution revenues in any one year and an overall cap of 5% over the three-year period. The annual revenue increase in 1999 is approximately $6.2 million. The AFOR also includes incentives to invest in renewable resources and penalties for failure to maintain the service quality levels. As part of the Company's strategy in refocusing its efforts on its core business, the Company intends to seek recovery of all of its prudent costs, including stranded costs in the event of deregulation. However, due to the current lack of definitive legislation, the Company cannot predict whether it will be successful. At December 31, 1998, the Company's remaining regulatory assets for all states totaled $796 million, of which approximately $350 million is applicable to generation. Because of the potential regulatory and/or legislative actions in Utah, Oregon, Wyoming, Idaho and Washington, 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 states may eventually bring competition for the electricity generation services. This change in the regulatory structure may significantly affect the Company's future financial position, results of operations and cash flows. The Company intends to seek regular price increases to the extent it underearns its allowed rate of return. This intention, consistent with the strategic direction implemented in 1998, provides a continued foundation for use of SFAS 71 in its financial statements. However, the Company announced on January 6, 1999 that it does not plan to file for general rate increases in the states it serves for at least the next six months, pending approval of its proposed merger with ScottishPower. 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 ("SO2") 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 Washington Pollution Control Authority ("SWAPCA") ordered the Centralia Plant to meet new SO2, nitrogen oxides ("NOx"), carbon monoxide and particulate matter emission limits. 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. The Company is currently in the process of relicensing 16 separate hydroelectric projects under the Federal Power Act. These projects, some of which are grouped together under a single license, represent approximately 1,000 MW, or 93%, of the Company's total hydroelectric nameplate 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. 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 and certain projects may not be economical to operate. Several federal and state environmental cleanup Superfund sites have been identified where the Company has been, or may be, designated as a potentially responsible party. In such cases, the Company 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 resolution of these matters are not expected to be material to the Company's consolidated financial statements. 30 AUSTRALIAN ELECTRIC OPERATIONS REVENUES
change due operating millions of dollars 1998 1997 to currency variance - ------------------------------------------------------------------------------------------------------------------- REVENUES Powercor area $437.8 $538.6 $ (80.0) $ (20.8) ---------------------------------------------- Outside Powercor area Victoria 79.1 98.7 (14.5) (5.1) New South Wales 71.6 46.0 (13.1) 38.7 Australian Capital Territory 0.6 - - 0.6 Queensland 0.3 - - 0.3 --------------------------------------------- Total Outside Powercor area 151.6 144.7 (27.6) 34.5 Other revenue 25.1 32.9 (4.6) (3.2) --------------------------------------------- $614.5 $716.2 $(112.2) $ 10.5 =============================================
millions of kWh 1998 1997 1996 - ----------------------------------------------------------------------------------------------------- ENERGY SALES Powercor area 7,233 7,410 7,519 Outside Powercor area Victoria 2,396 2,262 791 New South Wales 2,241 1,372 - Australian Capital Territory 12 - - Queensland 6 - - -------------------------------- 11,888 11,044 8,310 ================================
In 1998, Australian Electric Operations contributed earnings of $13 million, or $0.04 per share, compared to $54 million, or $0.18 per share, in 1997. Powercor's expansion of market share in New South Wales ("NSW") drove the growth in energy sales and revenues. However, lower market prices as a result of an increasing level of deregulation, partially offset by lower purchased power expense, caused margins on energy sold to decline. In addition, Australian Electric Operations recorded a $17 million, or $0.06 per share, loss on the write down of its investment in Hazelwood to estimated net realizable value less selling costs. The Company anticipates completing this sale by the end of 1999. CURRENCY RISKS Australian Electric Operations' results of operations and financial position are translated from Australian dollars into United States dollars for consolidation into the Company's financial statements. Changes in the prevailing exchange rate may have a material effect on the Company's consolidated financial statements. The average currency exchange rate for converting Australian dollars to United States dollars was 0.63 in 1998 compared to 0.74 in 1997, a 15% decrease for the year. The effect of the exchange rate fluctuation lowered reported revenues by $112 million and expenses by $105 million in 1998. The currency exchange rate at February 26, 1999 was 0.62. The following discussion excludes the effects of the lower currency exchange rate in 1998. Australia reported 1998 revenues of $615 million, an $11 million, or 1%, increase over the prior year. The increase was attributable to growth in energy sales volumes of 844 million kWh, or 8%. Energy volumes sold to contestable customers outside Powercor's franchise area were up 1,021 million kWh in 1998 and added $39 million to revenues due to customer gains in NSW, $7 million due to customer gains in Victoria and $1 million due to gains in Queensland and the Australian Capital Territory. Lower prices for contestable sales reduced revenues by $12 million in 1998. Inside Powercor's franchise area, revenues declined $13 million primarily due to price decreases for contestable customers and $8 million due to a 177 million kWh decrease in volumes. Other revenues decreased $3 million in 1998, principally because 1997 revenues included $15 million of income associated with renegotiating certain Tariff H industrial customer contracts. This decrease was partially offset by an increase in revenue from construction projects for other distribution businesses in Australia of $6 million and a reduction in energy contract losses of $7 million. 31 1997 COMPARED TO 1996
change due operating millions of dollars 1997 1996 to currency variance - ------------------------------------------------------------------------------------------------------------------- Powercor area $538.6 $583.6 $ (28.6) $ (16.4) Outside Powercor area Victoria 98.7 45.0 (5.2) 58.9 New South Wales 46.0 - - 46.0 --------------------------------------------- Total Outside Powercor area 144.7 45.0 (5.2) 104.9 Other revenue 32.9 30.2 (1.7) 4.4 --------------------------------------------- $716.2 $658.8 $ (35.5) $ 92.9 =============================================
Revenues increased $93 million, or 14%, in 1997 primarily due to a 33% increase in energy sales volumes. Increased market share in the contestable market in Victoria added $59 million in revenues and sales in the newly contestable market in NSW added $46 million in revenues. Revenues within Powercor's Victorian franchise area decreased $16 million due to lower average realized prices and decreased sales volumes. OPERATING EXPENSES
change due operating millions of dollars 1998 1997 to currency variance - ------------------------------------------------------------------------------------------------------------------ Purchased power $255.0 $308.5 $ (46.6) $ (6.9) Other operations and maintenance 140.1 134.0 (25.6) 31.7 Depreciation and amortization 58.2 67.1 (10.6) 1.7 Administrative and general 46.7 56.1 (8.6) (0.8) --------------------------------------------- $500.0 $565.7 $ (91.4) $ 25.7 =============================================
Purchased power expense decreased $7 million, or 2%, in 1998. Lower average prices reduced power costs by $35 million. Prices for purchased power averaged $23 per MWh in 1998 compared to $26 per MWh in 1997. The reduction resulted from competition. The decrease was offset in part by a 9% increase in purchased power volumes that added $28 million to costs in 1998. Other operations and maintenance expenses increased $32 million, or 24%, in 1998. Increased sales to contestable customers outside the Powercor service area resulted in higher network fees of $40 million. This increase was offset in part by higher network revenues of $12 million from customers inside Powercor's franchise area serviced by other energy suppliers. Maintenance increased $4 million primarily due to $6 million in costs transferred to administrative and general expenses upon conversion to SAP in November 1997. Administrative and general expenses decreased $1 million in 1998 primarily due to an $11 million reduction in professional fees and $6 million transferred from maintenance upon conversion to SAP in 1997. These decreases were offset by a $15 million adjustment in 1997 to capitalize new customer connection costs. Interest expense increased $5 million in 1998 to $58 million as a result of higher debt balances, partially offset by declining interest rates. In the fourth quarter of 1998, the Company began soliciting bids and intends to sell its equity interest in the Hazelwood Power Station in connection with its refocus on its electricity business. Other expense increased $33 million primarily due to a pretax loss of $28 million to reduce the carrying value of the Company's investment in the Hazelwood Power Station to its estimated net realizable value less selling costs and $5 million in costs for removal of certain energy efficiency devices in connection with a product recall. Powercor is in the process of seeking recovery from the manufacturer of these devices. Equity losses in Hazelwood were $6 million, an increase of $4 million over 1997 primarily due to increased maintenance costs. Income tax expense decreased $23 million due to a reduction in taxable income. 32 1997 COMPARED TO 1996
change due operating millions of dollars 1997 1996 to currency variance - ------------------------------------------------------------------------------------------------------------------ Purchased power $308.5 $305.1 $ (16.4) $ 19.8 Other operations and maintenance 134.0 112.3 (7.1) 28.8 Depreciation and amortization 67.1 71.6 (3.6) (0.9) Administrative and general 56.1 42.4 (3.0) 16.7 --------------------------------------------- $565.7 $531.4 $ (30.1) $ 64.4 =============================================
Operating expenses increased $64 million, or 12%, in 1997. Increased sales to contestable customers outside Powercor's franchise area resulted in increased purchased power expense of $20 million and higher network and grid fees of $58 million, which was partially offset by higher network revenues of $16 million from customers inside Powercor's franchise area that were serviced by other energy suppliers. CUSTOMERS AND COMPETITION Powercor's principal businesses are to sell electricity to franchise and contestable customers inside and outside its franchise area and to provide electricity distribution services to customers within its regulated network distribution service area. Franchise customers are those customers that cannot yet choose an electricity supplier, while contestable customers have the opportunity to choose suppliers. Powercor purchases all of its electricity supply from a state generation pool. Victoria and NSW are currently divided between franchise and contestable customers. Customers in both states with annual consumption of more than 160 MWh are now contestable 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. Powercor was granted licenses to sell electricity to customers in the States of Queensland and Australian Capital Territory in early 1998. REGULATION Powercor is the largest of the five distribution businesses ("DBs") formed when the Victorian State Government decided to privatize, and eventually deregulate, its electricity industry. As the Victorian market becomes more open to competition and additional customers can choose their energy supplier, Powercor and the other DBs will continue to maintain a monopoly on their individual network areas. These businesses derive much of their revenue from the network fee that is paid for the use of the distribution system. Powercor has an exclusive license to sell electricity to customers in its distribution service area in Victoria with a demand of 160 MWh per year or less. Powercor has nonexclusive licenses to sell electricity to customers with usage in excess of 160 MWh per year in its distribution service area and elsewhere in Victoria and NSW, and to customers in Queensland with annual usage exceeding four million kWh. Customers with usage of 160 MWh per year or less will incrementally become contestable over the period ending December 31, 2000 in Victoria and Queensland and over the period ending June 30, 1999 in NSW depending on their energy usage. 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. 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. 33 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. The outcome of the year 2000 regulatory review is uncertain at this time. OTHER OPERATIONS
millions of dollars 1998 1997 1996 - ------------------------------------------------------------------------------------------------------------------ EARNINGS CONTRIBUTION PFS $ 8.1 $ 30.2 $ 34.1 PGC - 10.4 7.8 Holdings and other: Write down of other energy businesses (32.4) - - TEG costs and option losses (45.6) (64.5) - Gain on sale of PGC - 30.0 - Other 17.7 (15.7) (14.8) -------------------------------- $(52.2) $ (9.6) $ 27.1 ================================
During 1998, Other Operations included the activities of Holdings, PacifiCorp Financial Services, Inc. ("PFS"), and energy development businesses. Losses relating to the decision to shut down or sell its other energy development businesses totaled $32 million, or $0.11 per share in 1998. The 1998 results also included $54 million, or $0.18 per share, in costs associated with the Company's terminated bid for TEG, $2 million, or $0.01 per share, relating to closing foreign currency options in April 1998 associated with the terminated bid for TEG, and a gain of $10 million, or $0.03 per share, relating to the sale of the TEG shares. The 1997 results included a loss of $65 million, or $0.22 per share, associated with closing foreign currency options and initial option premium costs relating to the Company's initial offer for TEG, that subsequently terminated when it was referred to the Monopolies and Mergers Commission (the "MMC") in the United Kingdom. Results from Other Operations in 1998 benefited from a $40 million after-tax increase in interest income and reduced interest expense as the result of cash received from 1997 asset sales. PFS has tax-advantaged investments in leasing operations that consist principally of aircraft leases. For 1998, PFS reported net income of $8 million, a $22 million decrease from 1997. This decrease was primarily attributable to the sale of its affordable housing properties. In May 1998, PFS sold a majority of its investments in affordable housing for $80 million, which approximated book value. The energy development businesses that the Company decided to exit in 1998 are generally wholly owned subsidiaries of the Company or subsidiaries in which the Company has a majority ownership. These businesses are consolidated in the Company's financial statements and are included in Other Operations. The pretax loss associated with exiting the energy development businesses was $52 million in 1998 and was included in "Write down of investments in energy development businesses" on the income statement. This loss consisted of reductions in net intercompany receivables. The remaining values for these businesses were arrived at using cash flow projections and estimated market value for fixed assets. Some of these businesses have been exited through the discontinuance of their operations while others are for sale. The Company believes that the businesses currently for sale can be exited by the end of 1999. Costs relating to exiting these businesses will be expensed as incurred. In addition, the other energy development businesses incurred $19 million of after-tax losses, or $0.06 per share, in 1998 compared to a loss of $16 million, or $0.05 per share, in 1997. On November 5, 1997, the Company completed the sale of its independent power subsidiary, PGC, to NRG Energy, Inc. for approximately $150 million in cash, resulting in a gain of $30 million, or $0.10 per share. PGC contributed income of $10 million in 1997 prior to completing the sale. 1997 COMPARED TO 1996 The $37 million decrease in earnings contribution of Other Operations in 1997 was primarily attributable to an after-tax loss of $65 million, or $0.22 per share, associated with closing foreign exchange positions relating to the Company's terminated bid for TEG. This loss was partially offset by an after-tax gain of $30 million, or $0.10 per share, relating to the sale of PGC in November 1997. 34 DISCONTINUED OPERATIONS Discontinued operations reported losses in 1998 of $147 million, or $0.49 per share, compared to income of $447 million, or $1.50 per share, in 1997. The 1998 results included $105 million, or $0.35 per share, for the loss anticipated to exit the energy trading business and a loss of $42 million, or $0.14 per share, relating to operating losses prior to the decision to exit. The pretax loss associated with exiting the energy trading business was $155 million. This loss consisted of write downs of intangible assets of $83 million and the costs to exit a portion of the business and sell another portion of the business of $72 million. The exiting costs include anticipated severance payments and operating costs to the selling date and selling expenses. The remaining values for these businesses that are on the books of the Company represent the estimated market value of the fixed assets of the companies and the remaining working capital at the expected sale date. Activities in the eastern United States have been discontinued and all forward electricity trading has been closed and is going through settlement. Contracts to manage the power supply of two municipalities will continue, the longest of such contracts will expire in late 1999. Holdings entered into an agreement, dated February 9, 1999, to sell TPC for approximately $133 million. In addition, a working capital adjustment will be calculated and paid following closing of the transaction, which is expected during the first half of 1999. The 1997 results included the gain on the sale of the Company's telecommunications operations and the earnings from normal operations until the sale in December 1997. 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 ended November 30, 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. LIQUIDITY AND CAPITAL RESOURCES
CASH FLOW SUMMARY forecasted actual ------------------------------------------------------------------------- for the year || millions of dollars 2001 2000 1999 1998 1997 1996 - ---------------------------------------------------------------------------------------------------------------- NET CASH FLOW FROM CONTINUING OPERATIONS Domestic Electric Operations $ 692 $ 727 $ 718 Australian Electric Operations 114 101 95 Other Operations (121) 8 75 ---------------------------------- Total 685 836 888 Cash Dividends Paid 337 341 346 ---------------------------------- Net $ 475-525 $475-525 $ 425-475 $ 348 $ 495 $ 542 ========================================================================= CONSTRUCTION Domestic Electric Operations $ 462 $ 414 $ 479 $ 539 $ 490 $ 442 Australian Electric Operations 60 65 60 70 79 80 Other Operations - - - 1 9 7 ------------------------------------------------------------------------- Total 522 479 539 610 578 529 ACQUISITIONS AND INVESTMENTS Domestic Electric Operations - - - - - 154 Australian Electric Operations - - - 5 5 145 Other Operations - - - 52 131 49 ---------------------------------------------------------------------- Total - - - 57 136 348 ---------------------------------------------------------------------- Total Capital Spending $ 522 $ 479 $ 539 $ 667 $ 714 $ 877 ====================================================================== MATURITIES OF LONG-TERM DEBT Domestic Electric Operations $ 138 $ 170 $ 300 $ 196 $ 208 $ 182 Australian Electric Operations - - - 1,339 3 42 Other Operations - - - 169 10 19 ---------------------------------------------------------------------- Total $ 138 $ 170 $ 300 $ 1,704 $ 221 $ 243 ====================================================================== Other Refinancings $ 28 $ 558 $ 42 ===============================
35 OPERATING ACTIVITIES Cash flows from continuing operations decreased $151 million from 1997 to 1998. This decrease was due to cash expenditures in 1998 relating to taxes on 1998 and 1997 asset sales and cash funding of other energy development businesses. INVESTING ACTIVITIES While investing activities in 1997 were dominated by asset sales of $1.8 billion and the acquisition of TPC, investing in 1998 focused on continued capital spending to improve and expand existing operations and disposing of non-strategic assets such as the Montana electric distribution assets and the majority of the tax-advantaged investments in affordable housing owned by PFS. On October 23, 1998, the Company announced its intent to exit its energy trading business in the eastern United States and its other energy development businesses. As a result, the Company recorded an after-tax loss of $137 million for these businesses. In addition, the Company recorded an after-tax loss of $17 million to reduce the Company's carrying value in the Hazelwood Power Station to its net realizable value less selling costs. The utility partners who own the 1,340 MW coal-fired Centralia Power Plant in Washington have hired an investment advisor to pursue the possible sale of the plant and the adjacent Centralia coal mine. The sale of the plant and adjacent mine is being considered by the owners, in part, because of emerging deregulation, competition in the electricity industry and the need for environmental compliance expenditures at the plant. The Company operates the plant and owns a 47.5% share. In addition, the Company owns and operates the adjacent Centralia coal mine. The Company is investigating the effect of a potential sale on the reclamation costs for the Centralia coal mine. Preliminary studies indicate that reclamation costs for the Centralia coal mine could be significantly higher than previous estimates, assuming the mine is closed, with the Company's portion being 47.5% of the final total amount. At December 31, 1998, the Company had approximately $24 million accrued for its share of the Centralia mine reclamation costs. The final amount and timing of any charge for additional reclamation at the mine are dependent upon a number of factors, including the results of the sale process, completion of the preliminary reclamation studies at the mine and the reclamation procedure used. The Company will seek to recover through rates any increase in the reclamation costs for the mine. On July 9, 1998, the Company announced its intent to sell its California and Montana electric distribution assets. This action was in response to the continued decline in earnings on the assets and changes in the legislative and regulatory environments in these states. The Company issued requests for proposals to interested parties on July 20, 1998. The Company has received bids for the California assets. These bids remain open and the Company has taken no action related to the bids. On November 5, 1998, the Company sold its Montana distribution assets to Flathead Electric Cooperative, Inc. and received proceeds of $89 million, net of taxes and customer refunds. The Company returned $4 million of the $8 million gain to Montana customers as negotiated with the MPSC and the Montana Consumer Counsel. In May 1998, PFS sold a majority of its investments in affordable housing for $80 million, which approximated book value. During 1997, the Company generated $1.8 billion of cash from the sale of PTI and PGC. A portion of the proceeds from the sale was 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 PacifiCorp for retirement of short-term debt. In October 1998 Holdings paid a dividend of $500 million to PacifiCorp. PacifiCorp used the proceeds to pay down intercompany debt owed to Holdings. In January 1999, Holdings paid a dividend of $660 million to PacifiCorp. PacifiCorp used the proceeds to pay down short-term debt and intercompany debt and invested the remainder in money market funds. The Company believes that its existing and available capital resources are sufficient to meet working capital, dividend and construction needs in 1999. BID FOR THE ENERGY GROUP During 1997 and 1998, the Company sought to acquire TEG, a diversified international energy group with operations in the United Kingdom, the United States and Australia. The Company made three tender offers for TEG, with the last offer valued at $11.1 billion, including the assumption of $4.1 billion of TEG's debt. In March 1998, another United States utility made a tender offer at a price higher than the Company's offer and, on April 30, 1998, the Company announced that it would not increase its revised offer for TEG. 36 The Company recorded an $86 million pretax charge to first quarter 1998 earnings, included in "TEG costs and option losses," for bank commitment and facility fees, legal expenses and other related costs incurred since the Company's original bid for TEG in June 1997. These costs had been deferred pending the outcome of the transaction. 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 of the transaction 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, in connection with the attempt to acquire TEG, a subsidiary of the Company purchased approximately 46 million shares of TEG stock at a price of 820 pence per share, or $625 million. The Company recorded a $10 million gain on the sale of the TEG shares in June 1998. In addition, the Company incurred a pretax expense of $3 million in April 1998 in connection with closing its foreign currency option contract associated with the bid for TEG. CAPITALIZATION
millions of dollars, except percentages 1998 1997 - --------------------------------------------------------------------------------------------------------- Long-term debt $4,383 45% $ 4,237 43% Common equity 3,957 41 4,321 44 Short-term debt 560 6 555 5 Preferred stock 241 2 241 2 Preferred securities of Trusts 341 4 340 4 Quarterly income debt securities 176 2 176 2 -------------------------------------------------- Total Capitalization $9,658 100% $ 9,870 100% ==================================================
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 the Company 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 are intended to remain sufficiently flexible to allow the Company to respond to these developments. On a consolidated basis, the Company attempts to maintain total debt at 48% to 54% of capitalization. The debt to capitalization ratio was 51% at December 31, 1998. The Company also attempts to maintain a preferred stock ratio, including subordinated debt, at 8% to 12% of capitalization. The preferred stock ratio was 8% at December 31, 1998. The Company's announced plan to repurchase up to $750 million in common shares has been postponed pending the outcome of the proposed ScottishPower merger. EQUITY AND DEBT TRANSACTIONS In January 1998, PacifiCorp Australia LLC ("PALLC") issued $400 million of 6.15% Notes due 2008. At the same time, in order to mitigate foreign currency exchange risk, PALLC entered into a series of currency exchange agreements in the same amount and for the same duration as the underlying United States denominated notes. The proceeds of the Notes were used to repay Australian bank bill borrowings. On May 12, 1998, the Company issued $200 million of 6.375% secured medium-term notes due May 15, 2008 in the form of First Mortgage Bonds. Proceeds were used to repay short-term debt. On November 6, 1998, the Company issued $200 million of its 5.65% Series of First Mortgage Bonds due November 1, 2006. Proceeds were used to repay short-term debt. 37 VARIABLE RATE LIABILITIES millions of dollars 1998 1997 - ------------------------------------------------------------------------------- Domestic Electric Operations $ 830 $ 760 Australian Electric Operations 278 269 Holdings and other 12 26 ------------------------ $ 1,120 $ 1,055 ======================== Percentage of Total Capitalization 12% 11% The Company's capitalization policy targets consolidated variable rate liabilities at between 10% and 25% of total capitalization. AVAILABLE CREDIT FACILITIES At December 31, 1998, PacifiCorp had $700 million of committed bank revolving credit agreements. Regulatory authorities limited PacifiCorp to $1 billion of short-term debt, of which $370 million was outstanding at December 31, 1998. At December 31, 1998, subsidiaries of PacifiCorp had $826 million of committed bank revolving credit agreements. The Company had $532 million of short-term debt classified as long-term debt at December 31, 1998, as it had the intent and ability to support such short-term borrowings through the various revolving credit facilities on a long-term basis. See Notes 7 and 8 of Notes to Consolidated Financial Statements for additional information. LIMITATIONS In addition to the Company's capital structure policies, its debt capacity is also governed by its credit agreements. PacifiCorp's principal debt limitation is a 60% debt to capitalization test contained in its principal credit agreements. Based on the Company's most restrictive credit agreements, management believes PacifiCorp and its subsidiaries could have borrowed an additional $2.5 billion of debt at December 31, 1998. Under PacifiCorp's principal credit agreement, it is an event of default if any person or group acquires 35% or more of PacifiCorp's common shares or if, during any period of 14 consecutive months, individuals who were directors of PacifiCorp on the first day of such period (and any new directors whose election or nomination was approved by such individuals and directors) cease to constitute a majority of the Board of Directors. PacifiCorp has obtained a waiver of this provision in $200 million of its credit facilities and expects to contact the remaining parties of the principal credit facilities requesting a waiver of this provision in anticipation of the ScottishPower merger. RISK MANAGEMENT Risk is an inherent part of the Company's business and activities. The risk management process established by the Company is designed to identify, assess, monitor and manage each of the various types of risk involved in its business and activities. Central to its risk management process, the Company has established a senior risk management committee with overall responsibility for establishing and reviewing the Company's policies and procedures for controlling and managing its risks. The senior risk management committee relies on the Company's treasury department and its operating units to carry out its risk management directives and execute various hedging and energy trading strategies. The policies and procedures that guide the Company's risk management activities are contained in the Company's derivative policy. The risk management process established by the Company is designed to measure quantitative market risk exposure and identify qualitative market risk exposure in its businesses. To assist in managing the volatility relating to these exposures, the Company enters into various derivative transactions consistent with the Company's derivative policy. That policy, which was originally established in 1994, governs the Company's use of derivative instruments and its energy trading practices and contains the Company's credit policy and management information systems required to effectively monitor such derivative use. The Company's derivative policy provides for the use of only those instruments that have a close correlation with its portfolio of assets, liabilities or anticipated transactions. The derivative policy includes as its objective that interest rates and foreign exchange derivative 38 instruments will be used for hedging and not for speculation. The derivative policy also governs the energy trading activities and is generally designed for hedging the Company's existing energy exposures but does provide for limited speculation activities within defined risk limits. RISK MEASUREMENT VALUE AT RISK ANALYSIS The tests discussed below for exposure to interest rate and currency exchange rate fluctuations are based on a Value at Risk ("VAR") approach using a one-year horizon and a 95% confidence level and assuming a one-day holding period in normal market conditions. With the Company's energy trading activities, a 99.9% confidence level is used. The higher confidence level results from a more active management of the risk. The VAR model is a risk analysis tool that attempts to measure the potential losses in fair value, earnings or cash flow from changes in market conditions and does not purport to represent actual losses in fair value that may be incurred by the Company. The VAR model also calculates the potential gain in fair market value or improvement in earnings and cash flow associated with favorable market price movements. SENSITIVITY ANALYSIS The Company measures its market risk related to its commodities price exposure positions by utilizing a sensitivity analysis. This sensitivity analysis measures the potential loss or gain in fair value, earnings or cash flow based on a hypothetical immediate 10% change (increase or decrease) in prices for its commodity derivatives. The fair value of such positions are a summation of the fair values calculated for each commodity derivative by valuing each position at quoted futures prices or assumed forward prices. EXPOSURE ANALYSIS INTEREST RATE EXPOSURE The Company's market risk to interest rate changes is primarily related to long-term debt with fixed interest rates. The Company uses interest rate swaps, forwards, futures and collars to adjust the characteristics of its liability portfolio. This strategy is consistent with the Company's capital structure policy which provides guidance on overall debt to equity and variable rate debt as a percent of capitalization levels for both the consolidated organization and its principal subsidiaries. The table below shows the potential loss in fair market value of the Company's interest rate sensitive positions as of December 31, 1997 and December 31, 1998, as well as the Company's quarterly high and low potential losses.
1998 1998 confidence time quarterly quarterly millions of dollars interval horizon 12/31/97 high low 12/31/98 - ---------------------------------------------------------------------------------------------------------------- Interest Rate Sensitive Portfolio - FMV 95% 1 day $(21.1) $(22.4) $(18.4) $(18.4)
Because of the size of the Company's fixed rate portfolio and lower levels of short-term debt as a result of asset sales, the significant majority of this average daily exposure is a noncash fair market value exposure and generally not a cash or current interest expense exposure. CURRENCY RATE EXPOSURE The Company's market risk to currency rate changes is primarily related to its investment in the Australian Electric Operations. The Company uses currency swaps, currency forwards and futures to hedge its foreign activities and, where use is governed by the derivative policy, the Company utilizes Australian dollar denominated borrowings to hedge the majority of the foreign exchange risks associated with Australian Electric Operations. Results of hedging activities relating to foreign net asset exposure are reflected in the accumulated other comprehensive income section of shareholders' equity, offsetting a portion of the translation of the net assets of Australian Electric Operations. Gains and losses relating to qualifying hedges of foreign currency firm commitments (or anticipated transactions) are deferred on the balance sheet and are included in the basis of the underlying transactions. To the extent that a qualifying hedge is terminated or ceases to be effective as a hedge, any deferred gains and losses up to that point continue to be deferred and are included in the basis of the underlying transaction. To the extent that anticipated transactions are no longer likely to occur, the related hedges are closed with gains or losses charged to earnings on a current basis. 39 In addition to the foreign currency exposure related to its investment in Australian Electric Operations, the Company also includes in the currency rate exposure VAR analysis the mark-to-market risk associated with its energy supply related contracts for differences supporting its commitment to the customers of Australian Electric Operations. The table below shows the potential loss in pre-tax cash flow of the Company's currency rate sensitive positions as of December 31, 1997 and December 31, 1998, as well as the Company's quarterly high and low potential losses.
1998 1998 confidence time quarterly quarterly millions of dollars interval horizon 12/31/97 high low 12/31/98 - ---------------------------------------------------------------------------------------------------------------- Currency Rate Exposure - Cash Flow 95% 1 day $(2.3) $(2.1) $(0.9) $(0.9)
The December 1997 amounts have been restated to include Australian Electric Operations contracts for differences. COMMODITY PRICE EXPOSURE The Company's market risk to commodity price change is primarily related to its electricity and natural gas commodities which are subject to fluctuations due to unpredictable factors, such as weather, which impacts supply and demand. The Company's energy trading activities are governed by the derivative policy and the risk levels established as part of that policy. The Company's energy commodity price exposure arises principally from its electric supply obligation in the United States and Australia. In the United States, the Company manages this risk principally through the operation of its 8,445 MW generation and transmission system in the western Unites States and through its wholesale energy trading activities. Derivative instruments are not significantly utilized in the management of the Unites States electricity position. In Australia, the Victorian government currently limits the amount of generation that can be owned by an electric supply company and, as a result, the risk associated with Australian Electric Operations energy supply obligations is managed through the use of electricity forward contracts (referred to as "contracts for differences") with Victorian generators. Under these forward contracts, the Company receives or makes payment based on a differential between a contracted price and the actual spot market of electricity. Additionally, electricity futures contracts are utilized to hedge Domestic Electric Operations' excess or shortage of net electricity for future months. The changes in market value of such contracts have had a high correlation to the price changes of the hedged commodity. Derivative instruments, other than contracts for differences, are not significantly utilized in Australian Electric Operations' risk management process. Gains and losses relating to qualifying hedges of firm commitments or anticipated inventory transactions are deferred on the balance sheet and included in the basis of the underlying transactions. A sensitivity analysis has been prepared to estimate the Company's exposure to market risk related to commodity price exposure of its derivative positions for both natural gas and electricity. Based on the Company's derivative price exposure at December 31, 1998 and 1997, a near-term adverse change in commodity prices of 10% would negatively impact pre-tax earnings by $16 million and $12 million, respectively. 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 The Company's Year 2000 project has been underway since mid-1996. A standard methodology of inventory, assessment, remediation and testing of hardware, software and equipment has been implemented. The main areas of risk are in: power supply (generating plant and system controls); information technology (computer software and hardware); business disruption; and supply chain disruption. The first two areas of risk are within the Company's own business operations. The others are areas of risk the Company might face from interaction with other companies, such as critical suppliers and customers. The Company's plan is to have successfully identified, corrected and tested its existing critical systems by July 1, 1999. The Company requires that all new hardware or software be vendor certified Year 2000 ready before it is installed. 40 A summary of the Company's progress to date in areas affected by Year 2000 issues is set forth in the following table:
remediation percent completed inventory assessment and testing - ----------------------------------------------------------------------------------------------- Electric Systems 100% 89% 49% COMPUTER SYSTEMS Central Applications To Correct 100 100 100 Central Applications To Replace 100 100 75 Desktop 100 100 30
The Company's ability to maintain normal operations into the year 2000 will also be affected by Year 2000 readiness of third parties from whom the Company purchases products and services or with whom the Company exchanges information. As of January 25, 1999, the Company believes it had identified 100% of its critical third-party supplier relationships and requested that these parties report their Year 2000 readiness. At March 10, 1999, the critical third parties reported they would be Year 2000 ready on or before the dates in the table below:
readiness target dates, on or before percent of all critical third parties ready - ---------------------------------------------------------------------------------------------------- December 31, 1998 22% March 31, 1999 33 June 30, 1999 77 September 30, 1999 91 December 31, 1999 97 (no Readiness Target Date reported) 3
The Company is in contact with these third parties and their Year 2000 readiness information is updated as required. The Company is also in the process of identifying third parties that are "super critical." An elevated Year 2000 readiness assessment, which includes a site visit, will be performed for each of them. To date, one super critical vendor has been identified. That vendor supplies chemical reagents used in air emission control equipment at some generating plants. One week's supply can be maintained. The plants would be able to generate power, but after a week may not be able to meet air quality regulations. That vendor has advised the Company that it will be Year 2000 ready by September 30, 1999. An on-site assessment has been scheduled. The Company plans to identify all remaining "super critical" third parties by mid-April 1999. The Company has no single retail customer that accounts for more than 1.7% of its retail utility revenues and the 20 largest retail customers account for 13.9% of total retail electric revenues. The Company has not performed a formal assessment of its customers' Year 2000 readiness. The Company's mining operations contingency plan calls for increased stockpiles of fuel to be available to supply the generating plants. The Company, the North American Electric Reliability Council ("NERC") and the Western Systems Coordinating Council ("WSCC") are working closely together to ensure the integrity of the interconnected electrical distribution and transmission system in the Company's service area and the western United States. NERC coordinates the efforts of the ten regional electric reliability councils throughout the United States while WSCC is focused on reliable electric service in the western United States. These agencies require Year 2000 readiness for all interconnected electric utilities by July 1, 1999. The Company has submitted its draft contingency plans to the WSCC as required by NERC. The Company will participate in the NERC sponsored industry preparedness drill on April 9, 1999. 41 The Company's worst case planning scenario assumes the following: 1. The public telecommunication system is not available or not functioning reliably for up to a week. 2. At midnight on December 31, 1999, there is a near simultaneous loss of multiple generating units resulting in transmission system instability and regional black outs. Restoration of service will start immediately, but some areas may not be fully restored and stable for twenty-four hours. 3. Temporary loss of automated transmission system monitoring and control systems. These functions must be performed manually during restoration. 4. Temporary loss of customer billing system. Customers on billing cycles in the early part of the month may receive an estimated billing that will be adjusted the following month. 5. Temporary loss of receivables processing system. 6. Temporary loss of automated payroll system. Employees will be paid, but some automated functions must be performed manually. 7. Temporary loss of automated shareholder services systems. Information must be available to be accessed manually while automated systems are being restored. To address this potential scenario and in cooperation with efforts by NERC and WSCC, the Company plans to establish a precautionary posture for its system leading into December 31, 1999. This is similar to the posture taken when severe winter weather is anticipated in areas of its service territory. Regional connections would be deliberately disconnected only during, or immediately following, a system disturbance in order to prevent further cascading outages and to facilitate restoration. Additional personnel will be on hand at control centers. Facilities such as power plants and key major substations will also have additional personnel standing by. Backup systems will be serviced and tested, as appropriate, prior to the transition period. Additional generation will be brought on line for the transition period as needed. The Company is continuing to expand its extensive microwave network in 1999. Because this system is self-controlled and has been undergoing extensive analysis for Year 2000 readiness, the Company considers this a reliable alternative to the public telephone network if needed. Emergency power systems will be tested and made ready. In addition to the microwave system, the Company has an extensive radio network. Through integration of the Company's radio and microwave, Company personnel can effectively "dial-up" telephones throughout the Company's area. Radio units will be deployed at key locations during the transition period. The Company is also planning to station satellite telephones at system dispatching facilities and key power plants. The Company's payment processing system has been certified by the vendor as Year 2000 compliant. An emergency backup plan is being developed for deployment by the third quarter of 1999 to enable third party off-site processing of payments. Check issuance has been outsourced to a vendor who has represented that it will be Year 2000 ready by the end of March 1999. To the extent possible, accounts payable checks and wire transfers will be processed early in December. Arrangements are expected to be made with the Company's banks to cover critical payment obligations for up to seventy-two hours should wire transfers be disrupted. The Company uses two systems to maintain shareholder records, transfer stock, issue 1099 dividend statements and process dividend payments. One system is certified compliant now, and the other is expected to be Year 2000 ready by June 30, 1999. The Company has incurred $12.7 million in costs relating to the Year 2000 project through December 31, 1998. The majority of these costs have been incurred to repair software problems. Estimates of the total cost of the Year 2000 project are approximately $30 million, which will be principally funded from operating cash flows. This estimate does not include the cost of system replacements that will be Year 2000 compliant, but are not being installed primarily to resolve Year 2000 problems. Year 2000 information technology ("IT") remediation costs 42 amount to approximately 5% of IT's budget. The Company has not delayed any IT projects that are critical to its operations as a result of Year 2000 remediation work. No independent verification of risk and cost estimates has been undertaken to date. The dates on which the Company believes the Year 2000 project will be completed and the expected costs and other impacts of the Year 2000 issues are based on management's best estimates, which were derived utilizing numerous assumptions concerning future events, including the availability of certain resources, the completion of third-party modification plans and other factors. There can be no assurance that these estimates will be achieved, or that there will not be a delay in, or increased costs associated with, the Company's implementation of its Year 2000 project. NEW ACCOUNTING STANDARDS In June 1998, the Financial Accounting Standards Board issued SFAS 133, "Accounting for Derivative Instruments and Hedging Activities." This statement, which is effective for fiscal years beginning after June 15, 1999, requires an entity to recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. Adoption of this standard will have an effect on the Company's financial position and results of operations; however, the magnitude of the effect will be determined by the hedges and derivatives that the Company has in place at the date of adoption of the standard. The effects in future periods will be dependent upon the derivatives and hedges in place at the end of each period. In December 1998, the EITF reached a consensus on Issue No. 98-10. "Accounting for Contracts Involved in Energy Trading and Risk Management Activities," ("EITF 98-10"). EITF 98-10, which is effective for fiscal years beginning after December 15, 1998, requires energy trading contracts to be recorded at fair market value on the balance sheet, with the change in fair market value included in earnings for the period of the change. The Company anticipates that the cumulative effect of the adoption of EITF 98-10 at January 1, 1999 will be immaterial on the Company's financial position, results of operations and cash flows. Restatement of prior period financial statements for the adoption of EITF 98-10 is not permitted. 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; energy trading activities; environmental, regulatory and tax legislation, including industry restructure and deregulation initiatives; technological developments in the electricity industry; foreign exchange rates; the pending ScottishPower merger; proposed asset dispositions; and the cost of debt and equity capital. Any forward-looking statements issued by the Company should be considered in light of these factors. 43 REPORT OF MANAGEMENT The management of PacifiCorp and its subsidiaries (the "Company") is responsible for preparing the accompanying consolidated financial statements and for their integrity and objectivity. The statements were prepared in accordance with generally accepted accounting principles. The financial statements include amounts that are based on management's best estimates and judgments. Management also prepared the other information in the annual report and is responsible for its accuracy and consistency with the financial statements. The Company's financial statements were audited by 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. (signatures) KEITH R. MCKENNON ROBERT R. DALLEY Keith R. McKennon Robert R. Dalley CHAIRMAN, PRESIDENT AND CONTROLLER AND CHIEF EXECUTIVE OFFICER CHIEF ACCOUNTING OFFICER 44 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, 1998 and 1997, and the related statements of consolidated income, consolidated changes in common shareholders' equity and consolidated cash flows for each of the three years in the period ended December 31, 1998. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with 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, 1998 and 1997, and the results of their operations and their cash flows for each of three years in the period ended December 31, 1998, in conformity with generally accepted accounting principles. (SIGNATURE) Portland, Oregon March 5, 1999 45
STATEMENTS OF CONSOLIDATED INCOME for the year || millions of dollars, except per share amounts 1998 1997 1996 - --------------------------------------------------------------------------------------------------------------- Revenues $5,580.4 $4,548.9 $3,792.0 Expenses Purchased power 2,821.5 1,605.0 923.9 Other operations and maintenance 1,081.9 1,078.8 1,017.4 Administrative and general 322.9 319.0 241.3 Depreciation and amortization 451.2 466.1 423.8 Taxes, other than income taxes 98.7 98.9 99.3 Special charges 123.4 170.4 - -------------------------------- Total 4,899.6 3,738.2 2,705.7 -------------------------------- Income from Operations 680.8 810.7 1,086.3 -------------------------------- Interest Expense and Other Interest expense 371.6 437.8 415.0 Interest capitalized (14.5) (12.2) (11.4) Losses from equity investments 13.9 12.8 4.1 TEG costs and option losses 73.0 105.6 - Write down of investments in energy development companies 79.5 - - Gain on sale of PGC - (56.5) - Minority interest and other (12.4) (21.5) 11.8 -------------------------------- Total 511.1 466.0 419.5 -------------------------------- Income from continuing operations before income taxes 169.7 344.7 666.8 Income tax expense 59.1 111.8 236.5 -------------------------------- Income from continuing operations before extraordinary item 110.6 232.9 430.3 Discontinued operations (less applicable income tax expense/(benefit): 1998/$(74.3), 1997/$361.1 and 1996/$47.4) (146.7) 446.8 74.6 Extraordinary loss from regulatory asset impairment (less applicable income tax benefit of $9.6) - (16.0) - -------------------------------- Net Income (Loss) $ (36.1) $ 663.7 $ 504.9 -------------------------------- Earnings (Loss) on Common Stock $ (55.4) $ 640.9 $ 475.1 Average number of common shares outstanding - basic and diluted (Thousands) 297,229 296,094 292,424 Earnings (Loss) per Common Share - Basic and Diluted Continuing operations $ 0.30 $ 0.71 $ 1.37 Discontinued operations (0.49) 1.50 0.25 Extraordinary item - (0.05) - -------------------------------- Total $ (0.19) $ 2.16 $ 1.62 ================================ (See accompanying Notes to Consolidated Financial Statements)
46
STATEMENTS OF CONSOLIDATED CASH FLOWS for the year || millions of dollars 1998 1997 1996 - ------------------------------------------------------------------------------------------------------------------------ Cash Flows from Operating Activities Net Income (Loss) $ (36.1) $ 663.7 $ 504.9 Adjustments to reconcile net income (loss) to net cash provided by continuing operations Losses (income) from discontinued operations 146.7 (81.7) (74.6) Gain on disposal of discontinued operations - (365.1) - Extraordinary loss from regulatory asset impairment - 16.0 - Write down of investments in energy development companies 79.5 - - Depreciation and amortization 460.1 481.5 440.5 Deferred income taxes and investment tax credits - net (47.9) (55.5) 26.1 Special charges 123.4 170.4 - Gain on sale of subsidiary and assets (11.0) (56.5) - Other 23.0 46.0 (25.6) Accounts receivable and prepayments (34.2) (135.5) (154.1) Materials, supplies, fuel stock and inventory 6.2 (6.5) 26.8 Accounts payable and accrued liabilities (24.8) 159.1 144.4 ---------------------------------------- Net cash provided by continuing operations 684.9 835.9 888.4 Net cash provided by (used in) discontinued operations (433.7) (217.3) 37.0 ---------------------------------------- Net Cash Provided by Operating Activities 251.2 618.6 925.4 ---------------------------------------- Cash Flows from Investing Activities Construction (609.9) (577.7) (528.1) Operating companies and assets acquired (44.8) (65.6) (199.4) Investments in and advances to affiliated companies - net (11.9) (70.9) (148.4) Proceeds from sales of assets 111.0 1,666.3 49.3 Proceeds from sales of finance assets and principal payments 311.7 103.2 55.8 Other (31.8) (58.5) (10.5) ---------------------------------------- Net Cash Provided by (Used in) Investing Activities (275.7) 996.8 (781.3) ---------------------------------------- Cash Flows from Financing Activities Changes in short-term debt 71.5 (494.4) (247.6) Proceeds from long-term debt 1,829.0 726.4 567.6 Proceeds from issuance of common stock 10.8 37.4 223.9 Proceeds from issuance of preferred securities of Trust holding solely PacifiCorp debentures - 130.6 209.6 Dividends paid (337.3) (341.2) (346.4) Repayments of long-term debt (1,731.6) (779.6) (284.5) Redemptions of capital stock - (72.2) (221.6) Other 24.4 (90.0) (52.5) ---------------------------------------- Net Cash Used in Financing Activities (133.2) (883.0) (151.5) ---------------------------------------- Increase/(Decrease) in Cash and Cash Equivalents (157.7) 732.4 (7.4) Cash and Cash Equivalents at Beginning of Year 740.8 8.4 15.8 ---------------------------------------- Cash and Cash Equivalents at End of Year $ 583.1 $ 740.8 $ 8.4 ======================================== (See accompanying Notes to Consolidated Financial Statements)
47
CONSOLIDATED BALANCE SHEETS ASSETS December 31 || millions of dollars 1998 1997 - --------------------------------------------------------------------------------------------------------------------- Current Assets Cash and cash equivalents $ 583.1 $ 740.8 Accounts receivable less allowance for doubtful accounts: 1998/$18.0 and 1997/$17.7 703.2 723.9 Materials, supplies and fuel stock at average cost 175.8 181.9 Net assets of discontinued operations and assets held for sale 192.4 223.4 Real estate investments held for sale - 272.2 Other 87.9 55.1 -------------------------- Total Current Assets 1,742.4 2,197.3 Property, Plant and Equipment Domestic Electric Operations Production 4,844.2 4,720.6 Transmission 2,102.3 2,087.8 Distribution 3,319.7 3,244.0 Other 1,947.0 1,784.8 Construction work in progress 246.8 257.4 Total Domestic Electric Operations 12,460.0 12,094.6 Australian Electric Operations 1,140.4 1,161.2 Other Operations 22.2 31.0 Accumulated depreciation and amortization (4,553.2) (4,240.0) -------------------------- Total Property, Plant and Equipment - net 9,069.4 9,046.8 Other Assets Investments in and advances to affiliated companies 114.9 166.1 Intangible assets - net 369.4 399.0 Regulatory assets - net 795.5 871.1 Finance note receivable 204.9 211.2 Finance assets - net 313.7 349.8 Deferred charges and other 378.3 385.7 -------------------------- Total Other Assets 2,176.7 2,382.9 Total Assets $ 12,988.5 $ 13,627.0 ========================== 48 LIABILITIES AND SHAREHOLDERS' EQUITY Current Liabilities Long-term debt currently maturing $ 299.5 $ 365.4 Notes payable and commercial paper 260.6 189.2 Accounts payable 566.2 546.7 Taxes, interest and dividends payable 282.7 677.4 Customer deposits and other 168.0 84.9 Total Current Liabilities 1,577.0 1,863.6 Deferred Credits Income taxes 1,542.6 1,666.2 Investment tax credits 125.3 135.2 Other 646.1 646.3 Total Deferred Credits 2,314.0 2,447.7 Long-Term Debt 4,559.3 4,413.0 Commitments and Contingencies (See Note 13) - - Guaranteed Preferred Beneficial Interests in Company's Junior Subordinated Debentures 340.5 340.4 Preferred Stock Subject to Mandatory Redemption 175.0 175.0 Preferred Stock 66.4 66.4 Common Equity Common shareholders' capital shares authorized 750,000,000; shares outstanding: 1998/297,343,422 and 1997/296,908,110 3,285.0 3,274.2 Retained earnings 732.0 1,106.3 Accumulated other comprehensive income (60.7) (59.6) -------------------------- Total Common Equity 3,956.3 4,320.9 -------------------------- Total Liabilities and Shareholders' Equity $ 12,988.5 $ 13,627.0 ========================== (See accompanying Notes to Consolidated Financial Statements)
49 STATEMENTS OF CONSOLIDATED CHANGES IN COMMON SHAREHOLDERS' EQUITY
common accumulated shareholders' other total capital retained comprehensive comprehensive millions of dollars || thousands of shares shares amount earnings income income (loss) - ---------------------------------------------------------------------------------------------------------------------- Balance, January 1, 1996 284,277 $3,012.9 $ 632.4 $ - $ - Comprehensive income Net income - - 504.9 - 504.9 Other comprehensive income Foreign currency translation adjustment, net of tax of $8.0 - - - 12.7 12.7 Cash dividends declared Preferred stock - - (29.1) - - Common stock ($1.08 per share) - - (317.9) - - Preferred stock retired - - (7.5) - - Sales to public 8,790 177.8 - - - Sales through Dividend Reinvestment and Stock Purchase Plan 2,073 43.2 - - - Redemptions and repurchases - 2.9 - - - ------------------------------------------------------------------- Balance, December 31, 1996 295,140 3,236.8 782.8 12.7 $ 517.6 =================================================================== Comprehensive income Net income - - 663.7 - $ 663.7 Other comprehensive income Foreign currency translation adjustment, net of tax of $46.9 - - - (72.3) (72.3) Cash dividends declared Preferred stock - - (20.0) - - Common stock ($1.08 per share) - - (320.0) - - Preferred stock retired - - (0.2) - - Sales through Dividend Reinvestment and Stock Purchase Plan 1,768 37.4 - - - ------------------------------------------------------------------- Balance, December 31, 1997 296,908 3,274.2 1,106.3 (59.6) $ 591.4 =================================================================== Comprehensive income (loss) Net loss - - (36.1) - $ (36.1) Other comprehensive income (loss) Unrealized gain on available-for-sale securities, net of tax of $3.8 - - - 6.2 6.2 Foreign currency translation adjustment, net of tax of $4.0 - - - (7.3) (7.3) Cash dividends declared Preferred stock - - (17.2) - - Common stock ($1.08 per share) - - (321.0) - - Sales through Dividend Reinvestment and Stock Purchase Plan 346 9.1 - - - Stock options exercised 89 1.7 - - - ------------------------------------------------------------------- Balance, December 31, 1998 297,343 $3,285.0 $ 732.0 $ (60.7) $ (37.2) =================================================================== (See accompanying Notes to Consolidated Financial Statements)
50 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Years ended December 31, 1998, 1997 and 1996 NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES BASIS OF PRESENTATION The consolidated financial statements of PacifiCorp include its integrated domestic electric utility operating divisions of Pacific Power and Utah Power and its wholly owned and majority owned subsidiaries (the "Company" or "Companies"). Major subsidiaries, all of which are wholly owned, are: PacifiCorp Group Holdings Company ("Holdings"), which holds directly or through its wholly owned subsidiary, PacifiCorp International Group Holdings Company, all of the Company's nonintegrated electric utility investments, including Powercor Australia Limited ("Powercor"), an Australian electricity distributor, and PacifiCorp Financial Services, Inc. ("PFS"), a financial services business. 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. During October 1998, the Company decided to exit its energy trading business, which consists of TPC Corporation ("TPC") and PacifiCorp Power Marketing ("PPM"). See Note 4. The Company sold its wholly owned telecommunications subsidiary, Pacific Telecom, Inc. ("PTI"), on December 1, 1997. See Note 4. The Company sold Pacific Generation Company ("PGC") on November 5, 1997, and the natural gas gathering and processing assets of TPC on December 1, 1997. During May 1998, the Company sold a majority of the real estate assets held by PFS. See Note 16. The Company has also decided to exit the majority of its other energy development businesses and has recorded them at estimated net realizable value less selling costs. See Note 16. 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 domestic electric utility business operates. The Company prepares its financial statements as they relate to Domestic Electric Operations in accordance with Statement of Financial Accounting Standards ("SFAS") 71, "Accounting for the Effects of Certain Types of Regulation." See Note 5. ASSET IMPAIRMENTS Long-lived assets and certain identifiable intangibles to be held and used by the Company are reviewed for impairment when events or circumstances indicate costs may not be recoverable. Such reviews are done in accordance with SFAS No. 121. The impacts of regulation on cash flows are considered when determining impairment. Impairment losses on long-lived assets are recognized when book values exceed expected undiscounted future cash flows. 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 maturities of three months or less at the time of acquisition to be cash equivalents. FOREIGN CURRENCY Financial statements for foreign subsidiaries are translated into United States dollars at end of period exchange rates as to assets and liabilities and weighted average exchange rates as to revenues and expenses. The resulting translation gains or losses are accumulated in the "accumulated other comprehensive income" account, a component of common equity and comprehensive income. All gains and losses resulting from foreign currency transactions are included in the determination of net income. PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment are stated at original cost of contracted services, direct labor and materials, interest capitalized during construction and indirect charges for engineering, supervision and similar overhead items. The cost of depreciable domestic electric utility properties retired, including the cost of removal, less salvage, is charged to accumulated depreciation. 51 DEPRECIATION AND AMORTIZATION At December 31, 1998, the average depreciable lives of property, plant and equipment by category were: Domestic Electric Operations - Production, 37 years; Transmission, 42 years; Distribution, 30 years; Other, 16 years; and Australian Electric Operations, 23 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 3.3%, 3.4% and 3.2% of average depreciable assets in 1998, 1997 and 1996, respectively. 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 ($375 million and $24 million, respectively, in 1998 and $393 million and $26 million, respectively, in 1997). These costs are offset by accumulated amortization ($30 million in 1998 and $20 million in 1997). Licenses and other intangible costs are generally being amortized over 40 years. Intangible assets decreased $18 million in 1998 due to lower foreign currency exchange rates. FINANCE ASSETS Finance assets consist of finance receivables, leveraged leases and operating leases and are not significant to the Company in terms of revenue, net income or assets. The Company's leasing operations consist principally of leveraged aircraft leases. Investments in finance assets are net of allowances for credit losses and accumulated impairment charges of $27 million and $47 million at December 31, 1998 and 1997, 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 applicable to domestic electric utility properties are capitalized during construction. The composite capitalization rates were 5.7% for 1998 and 1997 and 5.6% for 1996. 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 14. 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. COMPREHENSIVE INCOME Effective January 1, 1998, the Company adopted SFAS 130, "Reporting Comprehensive Income." This statement requires items reported as a component of common equity be more prominently reported in a separate financial statement as a component of comprehensive income. As permitted by SFAS 130, the Company has not included a statement of comprehensive income. Instead the Company included the amounts on the Statement of Consolidated Changes in Common Shareholders' Equity. 52 ENERGY TRADING Revenues and purchased energy expense for the Company's energy trading and marketing activities are recorded upon delivery of electricity. Beginning January 1, 1999, the Company will apply marked-to-market accounting for all energy trading activities and present the net margin. PREFERRED STOCK RETIRED Amounts paid in excess of the net carrying value of preferred stock retired are amortized over five years in accordance with regulatory orders. STOCK BASED COMPENSATION As permitted by SFAS 123, "Accounting for Stock Based Compensation," the Company has elected to follow Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" ("APB 25") and related interpretations in accounting for 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 COMMON SHARE The Company computes Earnings per Common Share ("EPS") based on SFAS 128, "Earnings per Share." 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. NEW ACCOUNTING STANDARDS In June 1998, the Financial Accounting Standards Board ("FASB") issued SFAS 133, "Accounting for Derivative Instruments and Hedging Activities." This statement, which is effective for fiscal years beginning after June 15, 1999, requires an entity to recognize all derivatives as either assets or liabilities in the statement of financial position and to measure those instruments at fair value. Adoption of this standard will have an effect on the Company's financial position and results of operations. The magnitude of the effect will be determined by the hedges and derivatives that the Company has in place at the adoption of the standard. The effects in future periods will be dependent upon the derivatives and hedges in place at the end of each period. In December 1998, the Emerging Issues Task Force (the "EITF") reached a consensus on Issue No. 98-10. "Accounting for Contracts Involved in Energy Trading and Risk Management Activities," ("EITF 98-10"). EITF 98-10, which is effective for fiscal years beginning after December 15, 1998, requires energy trading contracts to be recorded at fair market value on the balance sheet, with the change in fair market value included in earnings for the period of the change. The Company anticipates that the cumulative effect of the adoption of EITF 98-10 at January 1, 1999 will be immaterial on the Company's financial position, results of operation and cash flows. Restatement of prior period financial statements for the adoption of EITF 98-10 is not permitted. RECLASSIFICATION Certain amounts from prior years have been reclassified to conform with the 1998 method of presentation. These reclassifications had no effect on previously reported consolidated net income. NOTE 2. PROPOSED SCOTTISHPOWER MERGER On December 6, 1998, PacifiCorp signed an Agreement and Plan of Merger with Scottish Power plc ("ScottishPower") and NA General Partnership. ScottishPower subsequently announced its intention to establish a new holding company for the ScottishPower group pursuant to a court approved reorganization in the U.K. Accordingly, on February 23, 1999, the parties executed an amended and restated merger agreement (the "Agreement") under which PacifiCorp will become an indirect, wholly owned subsidiary of the new holding company, which will be renamed Scottish Power plc ("New ScottishPower"), and ScottishPower will become a sister company to PacifiCorp. PacifiCorp will continue to operate under its current name, and its headquarters will remain in Portland, Oregon. In the merger, each share of PacifiCorp's common stock will be converted into the right to receive 0.58 New ScottishPower American Depositary Shares ("ADS") (each New ScottishPower ADS represents four ordinary shares), which will be listed on the New York Stock Exchange, or, upon the proper election of the holders of PacifiCorp's common stock, 2.32 ordinary shares of New ScottishPower, which will be listed on the London Stock Exchange. If the proposed reorganization is not completed, the parties will proceed under the original agreement, and PacifiCorp will become an indirect, wholly owned subsidiary of ScottishPower. The merger is not conditional on the reorganization becoming effective nor is the reorganization conditional upon the merger becoming effective. 53 Both companies' boards of directors have approved the Agreement. However, before the transactions under the Agreement can be consummated, a number of conditions must be satisfied, including obtaining approvals and consents from shareholders of both companies, the Federal Energy Regulatory Commission ("FERC"), the Nuclear Regulatory Commission, the regulatory commissions in certain of the states served by the Company and Australian regulatory authorities. The parties have received early termination of the waiting period under the provisions of the Hart-Scott-Rodino Antitrust Improvement Act. Hearings on the merger have been scheduled for July and August 1999 by the Oregon, Utah, Wyoming and Idaho commissions. Both companies expect to have shareholder meetings in mid-1999 requesting shareholder approval of the merger. The Agreement requires that the Company pay a $250 million termination fee to New ScottishPower under certain circumstances following a bona fide proposal by a third party to acquire the Company. The Agreement requires New ScottishPower to pay a $250 million termination fee to the Company if the Company terminates the Agreement upon a change in control of New ScottishPower. In addition, the Agreement requires each party to pay a $10 million termination fee if, under certain circumstances, its shareholder approval is not obtained and the other party's shareholder approval is obtained. During 1998, the Company incurred $13 million in costs associated with the proposed ScottishPower merger. NOTE 3. BID FOR THE ENERGY GROUP During 1997 and 1998, the Company sought to acquire The Energy Group PLC ("TEG"), a diversified international energy group with operations in the United Kingdom, the United States and Australia. The Company made three tender offers for TEG. The last offer was valued at $11.1 billion, including the assumption of $4.1 billion of TEG's debt. In March 1998, another United States utility made a tender offer at a price higher than the Company's offer and on April 30, 1998, the Company announced that it would not increase its revised offer for TEG. The Company recorded an $86 million pretax charge ($54 million after-tax, or $0.18 per share) to first quarter 1998 earnings, included in "TEG costs and option losses," for bank commitment and facility fees, legal expenses and other related costs incurred since the Company's original bid for TEG in June of 1997. These costs had been deferred pending the outcome of the transaction. The Company incurred a pretax expense of $3 million ($2 million after-tax, or $0.01 per share) in April 1998 in connection with closing its foreign currency option contract associated with the bid for TEG. Additionally, in connection with the attempt to acquire TEG, a subsidiary of the Company purchased approximately 46 million shares of TEG at a price of 820 pence per share, or $625 million. The Company recorded a pretax gain on the TEG shares of $16 million ($10 million after-tax, or $0.03 per share) when they were sold on June 2, 1998. Upon initiation of the original tender offer in June 1997, the Company also entered into foreign currency exchange contracts. The financing facilities associated with the June 1997 offer for TEG terminated upon referral to the Monopolies and Mergers Commission and the Company initiated steps to unwind its foreign currency exchange positions consistent with its policies on derivatives. As a result of the termination of these positions and initial option costs, the Company realized a pretax loss of approximately $106 million ($65 million after-tax, or $0.22 per share) in the third quarter of 1997. NOTE 4. DISCONTINUED OPERATIONS In October 1998, the Company decided to exit its energy trading business by offering for sale TPC, and ceasing the operations of PPM, which conducted electricity trading in the eastern United States. PPM's activities in the eastern United States have been discontinued and all forward electricity trading has been closed and is going through settlement. PPM will continue to honor contracts to manage the power supply of two municipalities, the longest of such contracts will expire in late 1999. Holdings entered into an agreement, dated February 9, 1999, to sell TPC for approximately $133 million. In addition, a working capital adjustment will be calculated and paid following closing of the TPC transaction, which is expected during the first half of 1999. As a result of the pending sale agreement for TPC and the results of discontinued operations from September 30 to December 31, the Company adjusted its losses from discontinued operations as of the end of 1998. The following table sets forth the changes in the write down of the energy trading segment value and the anticipated losses to the sale or exit of those operations. 54
at at September 30 December 31 millions of dollars 1998 1998 - -------------------------------------------------------------------------------------------- Write down of segment net assets $ 138.5 $ 83.5 Estimated operating losses to disposal date 20.0 52.3 Estimated employee related costs 14.0 9.0 Estimated facilities related costs 2.2 3.4 Estimated selling and other costs 3.5 6.8 ----------------------- Total $ 178.2 $ 155.0 =======================
Operating losses from September 30 through December 31, 1998 amounted to $37.9 million and represented cash contributions to the energy trading segment. A majority of the remaining anticipated losses of this segment are expected to be incurred in the first half of 1999. 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. The net assets, operating results and cash flows of the energy trading segment and PTI have been classified as discontinued operations for all periods presented in the consolidated financial statements and notes. Summarized operating results for unregulated energy trading were as follows:
for the year ended December 31 || millions of dollars 1998 1997 1996 - ------------------------------------------------------------------------------------------------------------------ Revenues $2,961.4 $1,729.0 $ 11.7 ---------------------------------- Loss from discontinued operations (less applicable income tax benefit: 1998/$24.3, 1997/$2.3, 1996/$-) $ (41.7) $ (7.5) $ (0.1) Loss on disposal, including provision of $52.3 for operating losses during phase-out period (less applicable income tax benefit $50.0) (105.0) - - ---------------------------------- Net loss $ (146.7) $ (7.5) $ (0.1) ----------------------------------
Summarized operating results for PTI were as follows:
for the eleven for the year ended months ended year ended December 31 November 30 December 31 millions of dollars 1998 1997 1996 - --------------------------------------------------------------------------------------------------------------------- Revenues $ - $ 522.4 $ 521.1 ------------------------------------- Income from discontinued operations (less applicable income tax expense: 1997/$57.6 and 1996/$47.4) $ - $ 89.2 $ 74.7 Gain on disposal (less applicable income tax expense of $305.8) - 365.1 - ------------------------------------- Net income $ - $ 454.3 $ 74.7 Total income (loss) from discontinued operations $ (146.7) $ 446.8 $ 74.6 =====================================
55 Net assets of the discontinued operations of the energy trading segment and assets held for sale consisted of the following:
December 31 || millions of dollars 1998 1997 - ----------------------------------------------------------------------------------------------------- Current assets $ 148.5 $ 208.5 Noncurrent assets 152.7 269.5 Current liabilities (96.0) (241.9) Long-term debt (1.3) (1.5) Noncurrent liabilities (28.9) (11.2) Assets held for sale 17.4 - --------------------- Net Assets of Discontinued Operations and Assets Held for Sale $ 192.4 $ 223.4 =====================
In 1998, Holdings recorded $34 million of additional liabilities in "Customer deposits and other" relating to the sale of the discontinued operations. NOTE 5. ACCOUNTING FOR THE EFFECTS OF REGULATION Regulated utilities have historically applied the provisions of SFAS 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 as regulatory assets in accordance with regulatory authority whereby those costs will be expensed and recovered in future periods. The EITF of the FASB concluded in 1997 that SFAS 71 should be discontinued when detailed legislation or regulatory order regarding competition is issued. Additionally, the EITF concluded that regulatory assets and liabilities applicable to businesses being deregulated should be written off unless their recovery is provided for through future regulated cash flows. Legislative actions in California and Montana during 1996 and 1997 mandated customer choice of electricity supplier, moving away from cost-based regulation to competitive market rates for the generation portion of the electric business. As a result of these legislative actions, the Company evaluated its generation regulatory assets and liabilities in California and Montana based upon future regulated cash flows and ceased the application of SFAS 71 to its generation business allocable to California and Montana. Domestic Electric Operations recorded an extraordinary loss of $16 million, or $0.05 per share, in 1997 for the write off of regulatory assets in these states. The regulatory assets written off resulted primarily from deferred taxes allocated to California and Montana. The allocation among the states was based on plant balances. In 1998, the Company announced its intent to sell its California and Montana electric distribution assets. This action was in response to the continued decline in earnings on the assets and the changes in the legislative and regulatory environments in these states. The Company issued requests for proposals to interested parties on July 20, 1998. On November 5, 1998, the Company sold its Montana electric distribution assets to Flathead Electric Cooperative, Inc. and received proceeds of $89 million, net of taxes and customer refunds. The Company returned $4 million of the $8 million gain on the sale to Montana customers as negotiated with the Montana Public Service Commission and the Montana Consumer Counsel. The Company has received bids for its California electric distribution assets. These bids remain open and the Company is holding discussions with the bidders. 56 Regulatory assets-net included the following:
December 31 || millions of dollars 1998 1997 - ---------------------------------------------------------------------------------------------- Deferred taxes - net/a $ 602.9 $ 650.1 Demand-side resource costs 96.9 108.3 Unamortized net loss on reacquired debt 53.4 60.6 Unrecovered Trojan Plant and regulatory study costs 22.2 23.0 Various other costs 20.1 29.1 -------------------- Total $ 795.5 $ 871.1 ==================== /a Excludes $125 million in 1998 and $135 million in 1997 of investment tax credit regulatory liabilities.
The Company operates in five other states (Oregon, Utah, Wyoming, Washington and Idaho) that are in various stages of addressing deregulation of the electricity industry. At December 31, 1998, approximately $350 million of the $796 million total regulatory assets - net was applicable to generation. Potential regulatory or legislative actions in the states may result in additional write offs and charges. The Company evaluates the recovery of all their regulatory assets annually. The evaluation includes the probability of recovery as well as changes in the regulatory environment. The regulatory assets associated with pensions are substantially comprised of prior work force reductions and a deferred compensation plan whose preexisting liabilities were transferred to the Company's pension plan. In late 1997, because of the legislative actions taken by California and Montana relating to the process of deregulation coupled with the Company's belief that other regulatory bodies would proceed with deregulation, the Company evaluated its regulatory assets for potential impairment. This evaluation revealed that the deferred regulatory pension asset was the least likely of the regulatory assets to be recovered and the Company at that time decided not to seek recovery of this regulatory asset. As a result of the evaluation and decision, the Company recorded an $87 million write off of its deferred regulatory pension asset in 1997. During 1998, evolution toward deregulation continued, albeit at a slower pace. Accordingly, the Company is evaluating its position with respect to seeking recovery of these costs through rates. The probability of such recovery cannot presently be determined. During 1997, the Utah Public Service Commission (the "UPSC") held hearings on the method used in allocating common (generation, transmission and corporate related) costs among the Company's jurisdictions and issued an order in April 1998. Under the order, differences in allocations associated with the 1989 merger of Pacific Power & Light Company and Utah Power & Light Company were to be eliminated over five years on a straight-line basis. The phase-out of the differences was to be completed by January 1, 2001 and could have reduced Utah customer prices by about $50 to $60 million annually once fully implemented. The ratable impact of this order was to be included in a general rate case thereby combining it with all other cost-of-service items in determining the ultimate impact on customer prices. In 1998, the UPSC commenced a general rate case to consider the impact of the April 1998 allocation order, other cost-of-service issues and the appropriateness of the Company's authorized rate of return on equity. On March 4, 1999, an order was issued by the UPSC in the general rate case. The order requires the Company to reduce revenues in the state of Utah by $85 million, or 12%, annually. The UPSC also ordered that the allocation order be implemented immediately and not phased-in as originally ordered. Additionally, the UPSC ordered a refund to be issued through a credit on customer bills of $40 million. The Company recorded a $38 million reduction in revenues in 1998 and will record $2 million in 1999. The refund covers a period from March 14, 1997 to February 28, 1999. The beginning date is consistent with the timing of Utah legislation imposing a moratorium on rate changes after the Utah Division of Public Utilities and the Utah Committee of Consumer Services requested a general rate case. The $85 million reduction will commence on March 1, 1999. The order also reduced the Company's authorized rate of return on equity from 12.1% to 10.5%. The Company has asked the UPSC to reconsider issues in the order involving approximately $41 million of the $85 million rate decrease. Among these issues is the method of implementing the April 1998 allocation order. The Company is not seeking reconsideration of the reduction in its authorized return on equity to 10.5% nor the changes in the way costs are allocated among the six states served by the Company. 57 NOTE 6. SPECIAL CHARGES In January 1998, the Company announced a plan to reduce its work force in the United States by approximately 600 positions, or 7% of the work force in the United States. The Company offered enhanced early retirement to approximately 1,200 employees. The actual net work force reduction from this program was 759 positions, with 981 employees accepting the offer and 222 vacated positions backfilled. The pretax cost of $113 million ($70 million after-tax, or $0.24 per share) was recorded in the first quarter of 1998. In the fourth quarter of 1998, the Company initiated a cost reduction program that included involuntary employee severance and enhanced early retirement for employees who met certain age and service criteria and were displaced in conjunction with the cost reduction initiatives. Approximately 167 employees were displaced, with 35 of them eligible for the enhanced early retirement, and the Company recorded a $10 million ($6 million after-tax, or $0.02 per share) expense in special charges. It is anticipated that these amounts will be paid out in early 1999. Below is a summary of the accrual recorded and payments made related to the work force reduction initiatives described above.
retirement severance millions of dollars total benefits and other - -------------------------------------------------------------------------------------------------------------- Accruals recorded $ 123.4 $ 108.7 $ 14.7 Payments (9.8) - (9.8) ADDITIONS TO ACCRUED PENSION COSTS: Termination benefits (110.9) (110.9) - Net recognized gain 22.3 22.3 - ADDITIONS TO POSTRETIREMENT BENEFIT COSTS: Termination benefits (11.0) (11.0) - Net recognized loss (3.6) (3.6) - Adjustments 0.5 (1.4) 1.9 ----------------------------------- Ending accrual $ 10.9 $ 4.1 $ 6.8 ===================================
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 the write off of $87 million of deferred regulatory pension assets (see Note 5), 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 caused it to be uneconomical to continue to operate under current and expected market conditions due to increased mining stripping ratios, reduced coal quality and related costs. As of December 31, 1998, no cash had been paid out for reclamation. Reclamation is anticipated to begin in 1999. NOTE 7. SHORT-TERM DEBT AND BORROWING ARRANGEMENTS The Companies' short-term debt and borrowing arrangements were as follows:
average December 31 || millions of dollars balance interest rate/a - ------------------------------------------------------------------------------------ 1998 PacifiCorp $ 253.0 5.2% Subsidiaries 7.6 5.4 1997 PacifiCorp $ 182.2 6.5% Subsidiaries 7.0 5.4 /a Computed by dividing the total interest on principal amounts outstanding at the end of the period by the weighted daily principal amounts outstanding.
58 At December 31, 1998, PacifiCorp's commercial paper and bank line borrowings were supported by revolving credit agreements totaling $700 million. At December 31, 1998, subsidiaries had committed bank revolving credit agreements totaling $826 million. The Companies have the intent and ability to support short-term borrowings on a long-term basis through various revolving credit agreements, the earliest of which expires in 2002. At December 31, 1998, PacifiCorp had $117 million and subsidiaries had $414 million of short-term debt classified as long-term. See Note 8. NOTE 8. LONG-TERM DEBT The Company's long-term debt was as follows:
December 31 || millions of dollars 1998 1997 - ---------------------------------------------------------------------------------------------------------- PACIFICORP First mortgage and collateral trust bonds Maturing 1999 through 2003/ 5.9%-9.5% $ 816.4 $ 1,005.6 Maturing 2004 through 2008/ 5.7%-7.9% 1,032.7 632.7 Maturing 2009 through 2013/ 7%-9.2% 328.6 331.6 Maturing 2014 through 2018/ 8.3%-8.7% 98.4 100.9 Maturing 2019 through 2023/ 6.5%-8.5% 341.5 341.5 Maturing 2024 through 2026/ 6.7%-8.6% 120.0 120.0 Guaranty of pollution control revenue bonds 5.6%-5.7% due 2021 through 2023/a 71.2 71.2 Variable rate due 2009 through 2013/a, b 40.7 40.7 Variable rate due 2014 through 2024/a, b 175.8 175.8 Variable rate due 2005 through 2030/b 450.7 450.7 Funds held by trustees (7.4) (9.1) 8.4%-8.6% Junior subordinated debentures due 2025 through 2035 175.8 175.8 Commercial paper/b, d 116.8 120.6 Other 21.9 25.1 -------------------------- Total 3,783.1 3,583.1 Less current maturities 297.6 194.9 -------------------------- Total 3,485.5 3,388.2 -------------------------- SUBSIDIARIES 6.1%-12.0% Notes due through 2020 649.8 264.5 Australian bank bill borrowings and commercial paper/c, d 414.3 756.6 Variable rate notes due through 2000/b 11.6 12.1 4.5%-11% Nonrecourse debt - 160.7 Other - 1.4 -------------------------- Total 1,075.7 1,195.3 Less current maturities 1.9 170.5 -------------------------- Total 1,073.8 1,024.8 -------------------------- Total $ 4,559.3 $ 4,413.0 ========================== /a Secured by pledged first mortgage and collateral trust bonds generally at the same interest rates, maturity dates and redemption provisions as the pollution control revenue bonds. /b Interest rates fluctuate based on various rates, primarily on certificate of deposit rates, interbank borrowing rates, prime rates or other short-term market rates. /c Interest rates fluctuate based on Australian Bank Bill Acceptance Rates. A revolving loan agreement requires that at least 50% of the borrowings must be hedged against variations in interest rates. Approximately $414 million was hedged at December 31, 1998 at an average rate of 7.2% and for an average life of 5.3 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 $531 million of short-term debt as long-term debt.
59 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. Approximately $7 billion of the assets of the Companies secure long-term debt. 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. The annual maturities of long-term debt and redeemable preferred stock outstanding are $300 million, $181 million, $387 million, $449 million and $122 million in 1999 through 2003, respectively. The Company made interest payments, net of capitalized interest, of $444 million, $414 million and $456 million in 1998, 1997 and 1996, respectively. NOTE 9. GUARANTEED PREFERRED BENEFICIAL INTERESTS IN COMPANY'S JUNIOR SUBORDINATED DEBENTURES Wholly owned subsidiary trusts of the Company (the "Trusts") have issued, in public offerings, redeemable preferred securities ("Preferred Securities") representing preferred undivided beneficial interests in the assets of the Trusts, with liquidation amounts of $25 per Preferred Security. The sole assets of the Trusts are Junior Subordinated Deferrable Interest Debentures of the Company that bear interest at the same rates as the Preferred Securities to which they relate, and certain rights under related guarantees by the Company. Preferred Securities outstanding at December 31 were as follows:
thousands of preferred securities || millions of dollars 1998 1997 - ---------------------------------------------------------------------------------------------------------------- 8,680 8.25% Cumulative Quarterly Income Preferred Securities, Series A, with Trust assets of $224 million $ 209.9 $ 209.7 5,400 7.70% Trust Preferred Securities, Series B, with Trust assets of$139 million 130.6 130.7 --------------------- Total $ 340.5 $ 340.4 =====================
NOTE 10. COMMON AND PREFERRED STOCK COMMON STOCK At December 31, 1998, there were 26,773,426 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. STOCK OPTION INCENTIVE PLAN During 1997, the Company adopted a Stock Option Incentive Plan (the "Plan"). Under the terms of the Plan, the exercise price of any option may not be less that 100% of the fair market value of the common stock on the date of the grant. Stock options generally become exercisable in two or three equal installments on each of the first through third anniversaries of the grant date. The maximum exercise period under the Plan is ten years. In early 1998, the Company registered 11,500,000 shares of its common stock with the Securities and Exchange Commission for issuance under the PacifiCorp Stock Incentive Plan. At December 31, 1998, there were 11,410,839 authorized but unissued shares available. 60 The table below summarizes the stock option activity under the Plan.
weighted number average price of shares - -------------------------------------------------------------------------------------------- OUTSTANDING OPTIONS DECEMBER 31, 1996 - - Granted $ 19.94 1,516,000 Forfeited 19.75 (19,000) --------- OUTSTANDING OPTIONS DECEMBER 31, 1997 19.94 1,497,000 Granted 23.79 3,469,961 Exercised 19.75 (89,161) Forfeited 23.03 (807,628) --------- OUTSTANDING OPTIONS DECEMBER 31, 1998 4,070,172 =========
At December 31, 1998, 591,201 shares were exercisable with a weighted average exercise price of $20.18 per share. No options were exercisable as of December 31, 1997. The weighted average life of the options outstanding at December 31, 1998 was nine years. As permitted by SFAS 123, the Company has elected to account for these options under APB 25. Accordingly, no compensation expense has been recognized for these options. Had the Company determined compensation cost based on the fair value at the grant date for its stock options under SFAS 123, the Company's net income and earnings per share would have been reduced to the pro forma amounts below:
for the year || millions of dollars 1998 1997 - ---------------------------------------------------------------------------------------------------- Net income (loss) as reported $ (36.1) $ 663.7 Pro forma (39.6) 663.2 Earnings (loss) per common share as reported (0.19) 2.16 Pro forma (0.20) 2.16
The weighted average fair value of options granted during the year was $3.94 and $2.78 in 1998 and 1997, respectively. The fair value of each option grant was estimated on the date of grant using the Black-Scholes option-pricing model with the following assumptions used:
for the year 1998 1997 - ---------------------------------------------------------------------------------------------------- Dividend yield 5.0% 5.5% Risk-free interest rate 5.6% 6.8% Volatility 20% 15% Expected life of the options (years) 10 10
61 PREFERRED STOCK
thousands of shares - ---------------------------------------------------------------------------------------------------- At January 1, 1996 8,299 Redemptions and repurchases (2,342) -------- At December 31, 1996 5,957 Redemptions and repurchases (2,797) -------- At December 31, 1997 3,160 Redemptions and repurchases - -------- At December 31, 1998 3,160 ========
Generally, preferred stock is redeemable at stipulated prices plus accrued dividends, subject to certain restrictions. Upon involuntary liquidation, all preferred stock is entitled to stated value or a specified preference amount per share plus accrued dividends. Any premium paid on redemptions of preferred stock is capitalized, and recovery is sought through future rates. PREFERRED STOCK OUTSTANDING
thousands of shares || millions of dollars December 31, 1998 and 1997 || series shares amount - ----------------------------------------------------------------------------------------------------------------- Subject to Mandatory Redemption No Par Serial Preferred, $100 stated value, 6,000 Shares authorized $7.70 1,000 $ 100.0 7.48 750 75.0 Total 1,750 $ 175.0 ----------------------- Not Subject to Mandatory Redemption No Par Serial Preferred, $25 stated value $1.16 193 $ 4.8 1.18 420 10.5 1.28 381 9.5 Serial Preferred, $100 stated value, 3,500 Shares authorized 4.52% 2 0.2 4.56 85 8.5 4.72 70 7.0 5.00 42 4.2 5.40 66 6.6 6.00 6 0.6 7.00 18 1.8 5% Preferred, $100 stated value, 127 Shares authorized and outstanding 127 12.7 ----------------------- 1,410 $ 66.4 ----------------------- Total 3,160 $ 241.4 -----------------------
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. 62 NOTE 11. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT Through the application of its capital structure policies that governs the use of equity and debt, including duration, maturity and repricing intervals, the Company seeks to reduce its net income and cash flow exposure to changing interest and other commodity price risks. The Company utilizes derivative instruments to modify or eliminate its exposure from adverse movements in interest and foreign currency rates. The use of these derivative instruments is governed by the Company's derivative policy and includes as its objective that interest rates and foreign exchange derivative instruments will be used for hedging and not for speculation. As such, only those instruments that have a high correlation with the Company's underlying commodity exposure can be utilized. The derivative policy also governs energy trading activities and is generally designed for hedging the Company's existing energy exposures but does provide for limited speculative activities within defined risk limits. NOTIONAL AMOUNTS AND CREDIT EXPOSURE OF DERIVATIVES The notional amounts of derivatives summarized below do not represent amounts exchanged and, therefore, are not a measure of the exposure of the Company through its use of derivatives. The amounts exchanged are calculated on the basis of the notional amounts and other terms of the derivatives, which relate to interest rates, exchange rates or other indexes. The Company is exposed to credit-related losses in the event of nonperformance by counterparties to financial instruments, but it does not expect any counterparties to fail to meet their obligations given their high credit rating requirements. The Company's derivative policy provides that counterparties must satisfy established credit ratings and currently a majority of the Company's counterparties are rated "A" or better. The credit exposure of interest rate, foreign exchange and forward contracts is represented by the fair value of contracts with a positive fair value at the reporting date. INTEREST RATE RISK MANAGEMENT The Company enters into various types of interest rate contracts to assist in managing its interest rate risk, as indicated in the following table:
notional amount -------------------- December 31 || millions of dollars 1998 1997 - ------------------------------------------------------------------------------------------------------------------ Interest rate swaps $ 759.4 $ 707.5 Interest rate collars purchased 39.7 42.3 Interest rate futures and forwards 351.4 -
The Company uses interest rate swaps, collars, futures and forwards to adjust the characteristics of its liability portfolio, allowing the Company to establish a mix of fixed or variable interest rates on its outstanding debt within the Company's overall capital structure guidelines for leverage and variable interest rate risk. The use of interest rate collars, futures and forwards has been limited to use in the Australian Electric Operations. The futures and forwards, when used, are accounted for as hedges of the Australian bank bill borrowings. Interest rate collar agreements entitle Australian Electric Operations to receive from the counterparties the amounts, if any, by which the Australian bank bill borrowings interest payments exceed 8.75% and Australian Electric Operations would pay the counterparties if interest payments fall below 6.5%-6.8%. Under the various interest rate swap agreements, the Company agrees with other parties to exchange, at specified intervals, the difference between fixed-rate and variable-rate interest amounts calculated by reference to an agreed notional principal amount. The following table indicates the weighted-average interest rates of the swaps. Average variable rates are based on rates implied in the yield curve at December 31; these may change significantly, affecting future cash flows. Swap contracts are principally between one and fifteen years in duration.
December 31 1998 1997 - ------------------------------------------------------------------------------------------------ PAY-FIXED SWAPS Average pay rate 7.3% 7.7% Average receive rate 4.9 6.5
63 FOREIGN EXCHANGE RISK MANAGEMENT The Company's principal foreign exchange exposure relates to its investment in its Australian Electric Operations. The Company has hedged its exposure through both Australian-dollar denominated bank borrowings, which hedge approximately 55% to 60% of its total exposure, and through a series of amortizing currency swaps, which hedge approximately half of the remaining exposure. In January 1998, Australian Electric Operations issued $400 million of 6.15% Notes due 2008. At the same time, in order to mitigate foreign currency exchange risk and consistent with the directives in the Company's derivative policy, Australian Electric Operations entered into a series of cross currency swaps in the same amount and for the same duration as the underlying United States denominated notes. At December 31, 1998, Holdings held three combined interest rate and currency swaps that terminate in 2002, with an aggregate notional amount of $240 million to hedge a portion of its net investment in Powercor to fluctuations in the Australian dollar. The interest rate portions of these three swaps were effectively offset in 1997 by the purchase of an overlay swap transaction with approximately the same terms. The net amounts of these swaps have not had a significant impact on net income. At December 31, 1997, Hazelwood Australia, Inc. ("HAI"), an indirect 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 hedge was closed in January 1998 and HAI received $24 million in cash, as a result of the favorable market rate at the termination date. 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, 1998, Australian Electric Operations had 290 forward contracts with electricity generation companies on notional quantities amounting to approximately 34.4 million megawatt hours ("MWh") through the year 2007. The average fixed price to be paid by Australian Electric Operations was $17.99 per MWh compared to the average price of similar contracts at December 31, 1998 of $22.20. At December 31, 1997, Australian Electric Operations had 211 forward contracts with electricity generation companies on notional quantities amounting to approximately 35.6 million MWh. 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. The Company had open NYMEX futures contracts as follows:
December 31 1998 1997 - --------------------------------------------------------------------------------------------------- OPEN CONTRACTS (NUMBER) Purchase 215 110 Sell 275 489 NOTIONAL QUANTITIES (MWH) Purchase 158,200 81,000 Sell 202,400 359,900 FAIR MARKET VALUE (MILLIONS OF DOLLARS) Purchase $ - $ 0.1 Sell 0.2 (0.7)
64 TRADING ACTIVITIES The fair market values of open positions at December 31, 1998 was $(1) million. Such transactions involve delivery of electricity, which is accounted for as revenue or purchased power expense. At December 31, 1998, the Company had open purchase positions with a notional amount of approximately $72.9 million, or 3.0 million MWh, and open sell positions for approximately $66.3 million, or 2.8 million MWh. NOTE 12. FAIR VALUE OF FINANCIAL INSTRUMENTS
December 31, 1998 December 31, 1997 ---------------------- ---------------------- carrying fair carrying fair millions of dollars amount value amount value - ---------------------------------------------------------------------------------------------------------------------- Long-term debt $ 4,835.0 $ 5,127.5 $ 4,753.7 $ 4,905.6 Preferred Securities 340.5 363.9 340.4 355.4 Preferred stock subject to mandatory redemption 175.0 195.7 175.0 194.1 DERIVATIVES RELATING TO Currency 35.1 35.2 45.3 45.3 Interest (8.5) (65.8) (9.4) (54.3)
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, 1998 and 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 13. COMMITMENTS AND CONTINGENCIES The Company is subject to numerous environmental laws including: the Federal Clean Air Act, as enforced by the Environmental Protection Agency and various state agencies; the 1990 Clean Air Act Amendments; the Endangered Species Act as it relates to certain potentially endangered species of salmon; the Comprehensive Environmental Response, Compensation and Liability Act, relating to environmental cleanups; along with the Federal Resource Conservation and Recovery Act and the Clean Water Act relating to water quality. These laws could potentially impact future operations. For those contingencies identified at December 31, 1998, 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, assuming ongoing operations of its mines. 65 The utility partners who own the 1,340 MW coal-fired Centralia Power Plant in Washington have hired an investment advisor to pursue the possible sale of the plant and the adjacent Centralia coal mine. The sale of the plant and adjacent mine is being considered by the owners, in part, because of emerging deregulation, competition in the electricity industry and the need for environmental compliance expenditures at the plant. The Company operates the plant and owns a 47.5% share. In addition, the Company owns and operates the adjacent Centralia coal mine. The Company is investigating the effect of a potential sale on the reclamation costs for the Centralia coal mine. Preliminary studies indicate that reclamation costs for the Centralia coal mine could be significantly higher than previous estimates, assuming the mine is closed, with the Company's portion being 47.5% of the final total amount. At December 31, 1998, the Company had approximately $24 million accrued for its share of the Centralia mine reclamation costs. The final amount and timing of any charge for additional reclamation at the mine are dependent upon a number of factors, including the results of the sale process, completion of the preliminary reclamation studies at the mine and the reclamation procedure used. The Company will seek to recover through rates any increase in the reclamation costs for the mine. See Note 2, Proposed ScottishPower Merger, for information concerning termination fees that are payable in certain circumstances if the merger agreement is terminated. 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 $539 million for 1999. 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, 1998, 1997 and 1996 was $17 million, $15 million and $12 million, respectively. Future minimum lease payments under noncancelable operating leases are $6 million, $5 million, $5 million, $4 million and $3 million for 1999 through 2003, respectively. 66 JOINTLY OWNED FACILITIES At December 31, 1998, Domestic Electric Operations' participation in jointly owned facilities was as follows:
electric construction operations' plant in accumulated work in millions of dollars share service depreciation progress - --------------------------------------------------------------------------------------------------------------------- Centralia/a 47.5% $ 183.2 $ 115.6 $ 0.5 Jim Bridger Units 1, 2, 3 and 4/a 66.7 811.2 336.6 0.3 Trojan/b 2.5 - - - Colstrip Units 3 and 4/a 10.0 233.0 83.3 0.3 Hunter Unit 1 93.8 261.5 112.4 5.3 Hunter Unit 2 60.3 198.0 74.9 0.4 Wyodak 80.0 305.4 111.2 0.4 Craig Station Units 1 and 2 19.3 151.4/c 62.0 0.4 Hayden Station Unit 1 24.5 30.6/c 12.3 3.2 Hayden Station Unit 2 12.6 18.1/c 9.1 5.7 Hermiston/d 50.0 156.5 17.2 0.2 Foote Creek/a 78.8 55.7 2.5 - Other KV lines and substations Various 82.3 10.1 - /a Includes KV lines and substations. /b Plant, inventory, fuel and decommissioning costs totaling $22 million relating to the Trojan Plant were included in regulatory assets-net at December 31, 1998. /c Excludes unallocated acquisition adjustments of $110 million at December 31, 1998, that represents for regulatory accounting the excess of the cost of the acquired interest in the facilities over their original cost net of accumulated depreciation. /d Additionally, the Company has contracted to purchase the remaining 50% of the output of the plant.
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 $461 million, $427 million, $328 million, $317 million and $305 million for 1999 through 2003, respectively. As part of its energy resource portfolio, Domestic Electric Operations acquires a portion of its power through long-term purchases and/or exchange agreements which require minimum fixed payments of $316 million, $310 million, $286 million, $294 million and $260 million for 1999 through 2003, respectively. The purchase contracts include agreements with the Bonneville Power Administration, the Hermiston Plant and a number of cogenerating facilities. 67 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 1998, such purchases approximated 2% of energy requirements. At December 31, 1998, Domestic Electric Operations' share of long-term arrangements with public utility districts was as follows:
year contract capacity percentage annual generating facility expires (kW) of output costs/a - ------------------------------------------------------------------------------------------------------------------- Wanapum 2009 155,444 18.7% $ 5.2 Priest Rapids 2005 109,602 13.9 3.3 Rocky Reach 2011 64,297 5.3 3.0 Wells 2018 59,617 7.7 2.0 --------- ------- Total 388,960 $ 13.5 ========= ======= /a Annual costs, in millions of dollars, include debt service of $7.6 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. FUEL CONTRACTS Domestic Electric Operations has take or pay coal and natural gas contracts which require minimum fixed payments of $108 million, $114 million, $98 million, $99 million and $101 million for 1999 through 2003, respectively. NOTE 14. INCOME TAXES The Company's combined federal and state effective income tax rate from continuing operations was 35% in 1998, 32% in 1997 and 35% in 1996. 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 kWh 1998 1997 1996 - ----------------------------------------------------------------------------------------------------- ENERGY SALES Powercor area 7,233 7,410 7,519 Outside Powercor area
for the year || millions of dollars 1998 1997 1996 - ----------------------------------------------------------------------------------------------------- Computed Federal Income Taxes $ 59.4 $ 120.6 $ 233.4 -------------------------------- INCREASE (REDUCTION) IN TAX RESULTING FROM Depreciation differences 17.4 14.3 12.8 Investment tax credits (8.8) (8.5) (9.3) Audit settlement - - 0.5 Affordable housing and alternative fuel credits (5.9) (13.4) (10.6) Other items capitalized and miscellaneous differences (9.7) (10.7) (8.4) -------------------------------- Total (7.0) (18.3) (15.0) -------------------------------- Federal Income Tax 52.4 102.3 218.4 State Income Tax, Net of Federal Income Tax Benefit 6.7 9.5 18.1 -------------------------------- Total Income Tax Expense $ 59.1 $ 111.8 $ 236.5 ================================
68 The provision for income taxes is summarized as follows:
for the year || millions of dollars 1998 1997 1996 - ----------------------------------------------------------------------------------------------------- CURRENT Federal $ 89.1 $ 150.1 $ 186.3 State 17.9 17.2 24.1 -------------------------------- Total 107.0 167.3 210.4 -------------------------------- DEFERRED Federal (31.5) (44.3) 22.4 State (7.6) (2.7) 4.9 Foreign - - 8.1 -------------------------------- Total (39.1) (47.0) 35.4 -------------------------------- Investment Tax Credits (8.8) (8.5) (9.3) -------------------------------- Total Income Tax Expense $ 59.1 $ 111.8 $ 236.5 ================================
The tax effects of significant items comprising the Company's net deferred tax liability were as follows:
December 31 || millions of dollars 1998 1997 - ----------------------------------------------------------------------------------------------------- DEFERRED TAX LIABILITIES Property, plant and equipment $ 1,246.0 $ 1,178.8 Regulatory assets 653.7 704.1 Other deferred liabilities 37.2 84.3 ---------------------- 1,936.9 1,967.2 DEFERRED TAX ASSETS Regulatory liabilities (50.8) (54.0) Book reserves not currently deductible for tax (138.4) (56.6) Foreign net operating loss (28.9) (45.9) Foreign currency adjustment (53.2) (46.4) Pension accrual (72.7) (39.9) Safe harbor lease (31.1) (28.4) Other deferred assets (19.2) (29.8) ---------------------- (394.3) (301.0) Net Deferred Tax Liability $ 1,542.6 $ 1,666.2 ======================
The Company has received an Internal Revenue Service ("IRS") examination report for 1991, 1992 and 1993, proposing adjustments that would increase current taxes payable by $97 million. The Company filed a protest of many of these proposed adjustments on December 30, 1998. Discussions with the Appeals Division of the IRS will commence during 1999. During 1998, the Company completed its discussions with the Appeals Division for the protest of the 1989 and 1990 examinations. The Company paid $10 million in additional tax for these years for agreed issues. The Company will be filing for relief in the Tax Court with respect to two remaining issues. The additional tax in dispute for these issues is $4 million. The Company expects the IRS to commence audit of 1994 through 1997 during 1999. The Company made income tax payments of $504 million, $134 million and $208 million in 1998, 1997 and 1996, respectively. The significant increase in tax payments during 1998 was the result of taxes paid on assets sold during 1997, including PTI. 69 NOTE 15. 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, 1998, plan assets were primarily invested in common stocks, bonds and United States government obligations. All permanent employees of Powercor engaged prior to October 4, 1994 are members of Division B or C of the Superannuation Fund (the "Fund") which provides defined benefits in the form of pensions (Division B) or lump sums (Division C). Both defined benefit Funds are closed to new members. Members who choose to contribute do so at rates of 3% or 6% of eligible salaries. Powercor employees engaged after October 4, 1994 are members of Division D of the Fund, which is a defined contribution fund in which members may contribute up to 20% of eligible salaries. During the year ended December 31, 1998, Powercor made no contributions to Division B and C funds due to surplus amounts in these funds and contributed to the Division D Fund at rates ranging from 6%-10% of eligible salaries. The net periodic pension cost and significant assumptions are summarized as follows:
for the year || millions of dollars 1998 1997 1996 - ----------------------------------------------------------------------------------------------------- Service cost $ 25.6 $ 27.6 $ 31.5 Interest cost 82.0 82.1 78.8 Expected return on plan assets (89.4) (76.7) (65.8) Amortization of unrecognized net obligation 6.9 7.2 7.2 Recognized prior service cost 3.0 2.2 2.0 Recognized (gain) loss (0.3) 0.1 0.2 Regulatory deferral - - 14.2 --------------------------------- Net periodic pension cost $ 27.8 $ 42.5 $ 68.1 ================================= Discount rate 6.3%-6.8% 6.3%-7% 7.3%-7.5% Expected long-term rate of return on assets 7.5%-9.3% 7.5%-9.3% 8.5%-9% Rate of increase in compensation levels 4%-5% 4%-5% 4.5%-6%
70 The change in the projected benefit obligation, change in plan assets and funded status are as follows:
for the year || millions of dollars 1998 1997 - ----------------------------------------------------------------------------------------------------- CHANGE IN PROJECTED BENEFIT OBLIGATION Projected benefit obligation - beginning of year $ 1,216.3 $ 1,125.8 Service cost 25.6 27.6 Interest cost 82.0 82.1 Foreign currency exchange rate changes (4.3) (15.2) Plan participant contributions 1.5 1.2 Plan amendments 11.7 1.6 Curtailment gain (9.0) - Special termination benefit loss 110.9 - Actuarial loss 38.2 65.3 Benefits paid (202.7) (72.1) ----------------------- Projected benefit obligation - end of year $ 1,270.2 $ 1,216.3 ======================= CHANGE IN PLAN ASSETS Plan assets at fair value - beginning of year $ 1,003.5 $ 871.5 Foreign currency exchange rate changes (4.4) (14.7) Actual return on plan assets 154.5 148.0 Plan participant contributions 1.5 1.2 Company contributions 96.6 69.6 Benefits paid (202.7) (72.1) ----------------------- Plan assets at fair value - end of year $ 1,049.0 $ 1,003.5 ======================= RECONCILIATION OF ACCRUED PENSION COST AND TOTAL AMOUNT RECOGNIZED Funded status of the plan $ (221.2) $ (212.7) Unrecognized net (gain) loss (5.0) 4.9 Unrecognized prior service cost 22.5 15.2 Unrecognized net transition obligation 67.7 80.0 Accrued pension cost (136.0) (112.6) ----------------------- Accrued benefit liability (138.5) (118.2) Intangible asset 2.5 5.6 ----------------------- Accrued pension cost $ (136.0) $ (112.6) =======================
EMPLOYEE SAVINGS AND STOCK OWNERSHIP PLAN The Company has an employee savings and stock ownership plan that qualifies as a tax-deferred arrangement under Section 401(k), 401(a), 409, 501 and 4975(e)(7) of the Internal Revenue Code. Participating United States employees may defer up to 16% of their compensation, subject to certain regulatory limitations. The Company matches a portion of employee contributions with common stock, vesting that portion over five years. The Company makes an additional contribution of common stock to qualifying employees equal to a percentage of the employee's eligible earnings. These contributions are immediately vested. Company contributions to the savings plan were $18 million, $20 million and $17 million for the years ended 1998, 1997 and 1996, respectively. OTHER POSTRETIREMENT BENEFITS Domestic Electric Operations provides health care and life insurance benefits through various plans for eligible retirees on a basis substantially similar to those who are active employees. The cost of postretirement benefits is accrued over the active service period of employees. The transition obligation represents the unrecognized prior service cost and is being amortized over a period of 20 years. For those employees retired at January 1, 1993, the Company funds postretirement benefit expense on a pay-as-you-go basis and has an unfunded accrued liability of $65 million at December 31, 1998. For those employees retiring after January 1, 1993, the Company funds postretirement benefit expense through a combination of funding vehicles. The Company 71 funded $27 million and $18 million of postretirement benefits during 1998 and 1997, respectively. These funds are invested in common stocks, bonds and United States government obligations. The net periodic postretirement benefit cost and significant assumptions are summarized as follows:
for the year || millions of dollars 1998 1997 1996 - ----------------------------------------------------------------------------------------------------- Service cost $ 7.2 $ 7.2 $ 6.9 Interest cost 24.5 21.8 21.8 Expected return on plan assets (17.2) (12.5) (9.1) Amortization of unrecognized net obligation 13.8 13.9 14.0 Recognized gain (2.0) (2.1) (1.4) Regulatory deferral 1.9 6.4 3.4 ---------------------------------- Net periodic postretirement benefit cost $ 28.2 $ 34.7 $ 35.6 ================================== Discount rate 6.8% 7% 7.5% Estimated long-term rate of return on assets 9.3% 9.3% 9% Initial health care cost trend rate - under 65 7.8% 8.3% 8.8% Initial health care cost trend rate - over 65 7.8% 8.3% 8.4% Ultimate health care cost trend rate 4.5% 4.5% 4.5%
The change in the accumulated postretirement benefit obligation, change in plan assets and funded status are as follows:
for the year || millions of dollars 1998 1997 - ----------------------------------------------------------------------------------------------------- CHANGE IN ACCUMULATED POSTRETIREMENT BENEFIT OBLIGATION Accumulated postretirement benefit obligation - beginning of year $ 327.4 $ 316.2 Service cost 7.2 7.2 Interest cost 24.5 21.8 Plan participant contributions 2.8 1.1 Curtailment loss 18.1 - Special termination benefit loss 11.0 - Actuarial (gain) loss 22.4 (4.9) Benefits paid (16.8) (14.0) --------------------- Accumulated postretirement benefit obligation - end of year $ 396.6 $ 327.4 ===================== CHANGE IN PLAN ASSETS Plan assets at fair value - beginning of year $ 179.8 $ 139.7 Actual return on plan assets 36.4 26.6 Company contributions 37.9 28.9 Benefits paid (14.0) (12.9) Other disbursements - (2.5) --------------------- Plan assets at fair value - end of year $ 240.1 $ 179.8 ===================== RECONCILIATION OF ACCRUED POSTRETIREMENT COSTS AND TOTAL AMOUNT RECOGNIZED Funded status of the plan $ (156.5) $ (147.6) Unrecognized net gain (40.7) (64.3) Unrecognized net transition obligation 191.5 209.3 --------------------- Accrued postretirement benefit cost, before adjustment (5.7) (2.6) Deferred loss (0.4) - --------------------- Accrued postretirement benefit cost after adjustment $ (6.1) $ (2.6) =====================
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 72 percentage point would have increased the accumulated postretirement benefit obligation (the "APBO") as of December 31, 1998 by $36 million, and the annual net periodic postretirement benefit costs by $3 million. Decreasing the assumed health care cost trend rate by one percentage point would have reduced the APBO as of December 31, 1998 by $38 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 $8 million and $13 million in 1998 and 1997, respectively. EARLY RETIREMENT OFFER See Note 6 for details on the early retirement offering in 1998. NOTE 16. ACQUISITIONS AND DISPOSITIONS On November 5, 1998, the Company sold its Montana distribution assets to Flathead Electric Cooperative, Inc. and received proceeds of $89 million, net of taxes and customer refunds. The Company returned $4 million of the $8 million gain to Montana customers. In October 1998, the Company decided to exit the majority of its other energy development businesses as a result of its refocus on the western United States and Australian electricity businesses. These energy development businesses are generally wholly owned subsidiaries of the Company or subsidiaries in which the Company has a majority ownership. These businesses are consolidated in the Company's financial statements and are included in Other Operations. The pretax loss associated with exiting the energy development businesses was $52 million ($32 million after-tax, or $0.11 per share) and is included in "Write down of investment in energy development businesses" on the income statement. This loss consisted of reductions in net intercompany receivables. The remaining values for these businesses were arrived at using cash flow projections and estimated market value for fixed assets. Some of these businesses have been exited through the discontinuance of their operations while others are for sale. The Company believes that the businesses currently for sale can be exited by the end of 1999. Through September 1998, these businesses recorded pretax losses of $18 million ($13 million after-tax, or $0.04 per share). From October 1, 1998 through December 31, 1998, Holdings recorded a pretax expense of $5 million ($3 million after-tax, or $0.01 per share) relating to these operations. During May 1998, PFS received approximately $80 million in cash proceeds for the sale of a majority of its real estate assets, which approximated book value. On 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 parent. On December 1, 1997, TPC sold all of the capital stock of three subsidiaries that hold its natural gas gathering and processing systems for $195 million in cash, before tax payments of $23 million. No gain or loss was recognized on the sale. In October 1998, the Company announced its intention to sell the remaining business of TPC. See Note 4. On November 5, 1997, Holdings completed the sale of PGC for approximately $150 million in cash. A pretax gain on the sale of $57 million ($30 million after-tax, 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. In October 1998, the Company announced its intention to sell its interest in Hazelwood as a result of its refocus on the western United States and Australian electricity businesses. Hazelwood is an equity investment included in the Company's financial statements as part of Australian Electric Operations. The Company recorded a pretax loss of $28 million ($17 million 73 after-tax, or $0.06 per share), which is included in "Write down of investment in energy development businesses" on the income statement, to reduce its carrying value in the Hazelwood Power Station to estimated net realizable value less selling costs. This write down was arrived at using cash flow projections. For the year ended December 31, 1998, Hazelwood recorded a pretax loss of $7 million ($5 million after-tax, or $0.02 per share). NOTE 17. SEGMENT INFORMATION The Company operates in two business segments (excluding other and discontinued operations): Domestic Electric Operations and Australian Electric Operations. The Company identified the segments based on management responsibility within the United States and Australia. Domestic Electric Operations includes the regulated retail and wholesale electric operations in the six western states in which it operates. Australian Electric Operations includes the deregulated electric operations in Australia. Other Operations consists of PFS, the western energy trading activities and other energy development businesses, as well as the activities of Holdings, including financing costs. None of the businesses within Other Operations are significant enough for segment treatment.
domestic Australian other total electric electric discontinued operations & millions of dollars company operations operations operations eliminations - ------------------------------------------------------------------------------------------------------------------------- 1998 Net sales and revenue (all external) $ 5,580.4 $ 4,845.1 $ 614.5 $ - $ 120.8 Depreciation and amortization 451.2 386.6 58.2 - 6.4 Interest expense 371.6 319.1 57.9 - (5.4) Losses of nonconsolidated affiliates (13.9) - (5.5) - (8.4) Income tax expense (benefit) 59.1 102.9 7.7 - (51.5) Extraordinary item - - - - - Income (loss) from continuing operations 110.6 149.8 13.0 - (52.2) Loss from discontinued operations (146.7) - - (146.7) - Identifiable assets 12,988.5 9,834.6 1,660.8 175.0 1,318.1 Investments in nonconsolidated affiliates 114.9 6.1 100.9 - 7.9 Capital spending 667.0 539.0 75.0 - 53.0 1997 Net sales and revenue (all external) $ 4,548.9 $ 3,706.9 $ 716.2 $ - $ 125.8 Depreciation and amortization 466.1 389.1 67.1 - 9.9 Interest expense (benefit) 437.8 319.0 63.5 - 55.3 Losses of nonconsolidated affiliates (12.8) - (2.9) - (9.9) Income tax expense 111.8 112.0 32.3 - (32.5) Extraordinary item (16.0) (16.0) - - - Income (loss) from continuing operations 232.9 188.3 47.9 - (3.3) Income from discontinued operations 446.8 - - 446.8 - Identifiable assets 13,627.0 9,862.7 1,786.3 223.4 1,754.6 Investments in nonconsolidated affiliates 166.1 6.1 123.7 - 36.3 Capital spending 714.0 490.0 84.0 - 140.0 1996 Net sales and revenue (all external) $ 3,792.0 $ 2,991.8 $ 658.8 $ - $ 141.4 Depreciation and amortization 423.8 343.4 71.6 - 8.8 Interest expense 415.0 291.8 75.2 - 48.0 Losses of nonconsolidated affiliates (4.1) - (1.3) - (2.8) Income tax expense 236.5 216.9 18.7 - 0.9 Income from continuing operations 430.3 371.3 30.1 - 28.9 Income from discontinued operations 74.6 - - 74.6 - Identifiable assets 13,809.0 9,864.0 2,065.0 783.0 1,097.0 Investments in nonconsolidated affiliates 253.9 6.1 145.7 - 102.1 Capital spending 877.0 596.0 225.0 - 56.0
74 SELECTED FINANCIAL INFORMATION (UNAUDITED)
for the year || millions of dollars, except per share information 1998 1997 1996 1995 1994 - ----------------------------------------------------------------------------------------------------------------------------------- Revenues Domestic Electric Operations $ 4,845.1 $ 3,706.9 $ 2,991.8 $ 2,646.1 $ 2,686.2 Australian Electric Operations 614.5 716.2 658.8 25.9 - Other Operations/a 120.8 125.8 141.4 134.8 153.7 ---------------------------------------------------------- Total $ 5,580.4 $ 4,548.9 $ 3,792.0 $ 2,806.8 $ 2,839.9 ========================================================== Income (Loss) from Operations Domestic Electric Operations $ 571.8 $ 601.3 $ 869.8 $ 800.9 $ 819.3 Australian Electric Operations 114.5 150.5 127.4 5.5 - Other Operations/a (5.5) 58.9 89.1 84.2 38.3 ---------------------------------------------------------- Total $ 680.8 $ 810.7 $ 1,086.3 $ 890.6 $ 857.6 ========================================================== Net Income $ (36.1) $ 663.7 $ 504.9 $ 505.0 $ 468.0 ========================================================== Earnings Contribution (Loss) on Common Stock Continuing operations Domestic Electric Operations $ 130.5 $ 165.5 $ 341.5 $ 276.4 $ 339.8 Australian Electric Operations 13.0 54.2 31.9 0.7 - Other Operations/a (52.2) (9.6) 27.1 86.2 18.0 ---------------------------------------------------------- Total 91.3 210.1 400.5 363.3 357.8 Discontinued operations/b (146.7) 446.8 74.6 103.0 70.5 Extraordinary item/c - (16.0) - - - ---------------------------------------------------------- Total $ (55.4) $ 640.9 $ 475.1 $ 466.3 $ 428.3 ========================================================== Earnings (Loss) per Share - Basic and Diluted Continuing operations Domestic Electric Operations $ 0.44 $ 0.56 $ 1.17 $ 0.97 $ 1.20 Australian Electric Operations 0.04 0.18 0.11 - - Other Operations/a (0.18) (0.03) 0.09 0.31 0.06 ----------------------------------------------------- Total 0.30 0.71 1.37 1.28 1.26 Discontinued operations/b (0.49) 1.50 0.25 0.36 0.25 Extraordinary item/c - (0.05) - - - ---------------------------------------------------------- Total $ (0.19) $ 2.16 $ 1.62 $ 1.64 $ 1.51 ========================================================== Cash Dividends Declared per Common Share $ 1.08 $ 1.08 $ 1.08 $ 1.08 $ 1.08 ========================================================== Market Price per Common Share $ 21 1/16 $ 27 5/16 $ 20 1/2 $ 21 1/8 $ 18 1/8 ========================================================== Capitalization Short-term debt $ 560 $ 555 $ 903 $ 1,132 $ 513 Long-term debt 4,559 4,413 4,829 4,509 3,391 Preferred securities of Trusts 341 340 210 - - Redeemable preferred stock 175 175 178 219 219 Preferred stock 66 66 136 312 367 Common equity 3,957 4,321 4,032 3,633 3,460 ---------------------------------------------------------- Total $ 9,658 $ 9,870 $ 10,288 $ 9,805 $ 7,950 ========================================================== Total Assets $ 12,989 $ 13,627 $ 13,809 $ 13,167 $ 11,000 ========================================================== Total Employees 9,120 10,087 10,118 10,418 10,083 ========================================================== /a Other Operations includes the operations of PFS, PGC, the western United States wholesale trading activities, as well as the activities of Holdings, including financing costs, and elimination entries. /b Discontinued operations includes the Company's interest in PTI, TPC and the eastern energy trading business of PPM. /c Extraordinary item includes a regulatory asset impairment pertaining to generation resources that are allocable to operations in California and Montana.
75 DOMESTIC ELECTRIC OPERATIONS (UNAUDITED)
5-year 1998 to 1997 compound for the year percentage annual millions of dollars, except as noted 1998 1997 1996 1995 1994 comparison growth - ----------------------------------------------------------------------------------------------------------------------------- Revenues Residential $ 806.6 $ 814.0 $ 801.4 $ 739.7 $ 746.0 (1)% 2% Commercial 653.5 640.9 623.3 576.9 571.7 2 4 Industrial 705.5 709.9 719.3 708.8 742.3 (1) - Other 30.2 31.7 32.5 29.7 30.7 (5) - --------------------------------------------------------- Retail sales 2,195.8 2,196.5 2,176.5 2,055.1 2,090.7 - 2 Wholesale sales and market trading 2,583.6 1,428.0 738.8 520.0 532.7 81 39 Other 65.7 82.4 76.5 71.0 62.8 (20) 11 --------------------------------------------------------- Total 4,845.1 3,706.9 2,991.8 2,646.1 2,686.2 31 14 --------------------------------------------------------- Expenses Fuel 477.6 454.2 443.0 431.6 483.0 5 1 Purchased power 2,497.0 1,296.5 618.7 386.7 394.5 93 47 Other operations 292.4 292.0 276.9 273.7 263.8 - 2 Maintenance 164.9 178.0 167.3 168.4 174.5 (7) (1) Administrative and general 233.9 227.8 176.3 160.5 142.7 3 11 Depreciation and amortization 386.6 389.1 343.4 320.4 301.6 (1) 7 Taxes, other than income taxes 97.5 97.6 96.4 103.9 106.8 - (1) Special charges 123.4 170.4 - - - (28) - --------------------------------------------------------- Total 4,273.3 3,105.6 2,122.0 1,845.2 1,866.9 38 19 --------------------------------------------------------- Income from Operations 571.8 601.3 869.8 800.9 819.3 (5) (6) Interest expense 319.1 319.0 291.8 311.9 264.3 - 3 Interest capitalized (14.5) (12.2) (11.4) (14.9) (14.5) 19 1 Other (income) expense - net 14.5 (5.8) 1.2 (25.3) (30.2) * * Income tax expense 102.9 112.0 216.9 214.1 220.2 (8) (11) --------------------------------------------------------- Net Income 149.8 188.3 371.3 315.1 379.5 (20) (16) Preferred Dividend Requirement 19.3 22.8 29.8 38.7 39.7 (16) (13) --------------------------------------------------------- Earnings Contribution/a $ 130.5 $ 165.5 $ 341.5 $ 276.4 $ 339.8 (21) (17) ========================================================= Identifiable assets $ 9,835 $ 9,863 $ 9,864 $ 9,599 $ 9,372 - 2 Capital spending $ 539 $ 490 $ 596 $ 455 $ 638 10 (3) * Not a meaningful number. /a Does not reflect elimination of interest on intercompany borrowing arrangements and includes income taxes on a separate-company basis.
76 DOMESTIC ELECTRIC OPERATIONS STATISTICS (UNAUDITED)
5-year 1998 to 1997 compound millions of dollars, except as noted 1998 1997 1996 1995 1994 comparison growth - ----------------------------------------------------------------------------------------------------------------------------- Energy Sales (millions of kWh) Residential 12,969 12,902 12,819 12,030 12,127 1% 1% Commercial 12,299 11,868 11,497 10,797 10,645 4 4 Industrial 20,966 20,674 20,332 19,748 20,306 1 1 Other 651 705 640 592 623 (8) 2 --------------------------------------------------------- Retail sales 46,885 46,149 45,288 43,167 43,701 2 2 Wholesale sales and market trading 94,077 59,143 29,665 16,376 15,625 59 44 --------------------------------------------------------- Total 140,962 105,292 74,953 59,543 59,326 34 20 ========================================================= Energy Source (%) Coal 51 43 60 74 79 19 (8) Hydroelectric 6 5 7 7 5 20 - Other 2 2 1 2 2 - 15 Purchase and exchange contracts 41 50 32 17 14 (18) 21 ========================================================= Number of Retail Customers (thousands) Residential 1,255 1,228 1,194 1,167 1,147 2 2 Commercial 174 170 167 160 158 2 2 Industrial 36 36 37 35 34 - 2 Other 5 4 4 4 3 25 5 --------------------------------------------------------- Total 1,470 1,438 1,402 1,366 1,342 2 2 ========================================================= Residential Customers Average annual usage (kWh) 10,443 10,644 10,866 10,395 10,646 (2) (1) Average annual revenue per customer (Dollars) 650 672 679 639 655 (1) - Revenue per kWh (Cents) 6.2 6.3 6.3 6.1 6.1 - - Miles of Line Transmission 15,000 15,000 14,900 14,900 14,900 - - Distribution - - overhead 45,000 45,000 45,000 44,900 44,800 - - - - underground 10,000 10,000 9,600 9,100 8,800 - 4 System Peak Demand (Megawatts) Net system load/a - - summer 7,666 7,110 7,257 6,855 7,151 8 3 - - winter 7,909 7,403 7,615 7,030 7,174 7 2 Total Firm Load - - summer/b 11,629 10,871 10,572 8,899 8,830 7 7 - - winter 12,301 10,830 10,775 8,904 8,903 14 7 System Capability (Megawatts)/c - - summer 12,632 12,343 12,115 10,224 10,020 2 5 - - winter 13,427 12,618 12,160 10,994 10,391 6 6 /a Excludes off-system sales. /b Includes firm off-system sales. /c Generating capability and firm purchases at time of firm peak.
77 AUSTRALIAN ELECTRIC OPERATIONS (UNAUDITED)/a
1998 to 1997 Percentage for the year || millions of dollars, except as noted 1998 1997 1996 1995 Comparison/b - --------------------------------------------------------------------------------------------------------------------------- Revenues Powercor area $ 437.8 $ 538.6 $ 583.6 $ 25.4 (19)% Outside Powercor area Victoria 79.1 98.7 45.0 - (20) New South Wales 71.6 46.0 - - 56 Australian Capital Territory 0.6 - - - * Queensland 0.3 - - - * ----------------------------------------------- Energy sales 589.4 683.3 628.6 25.4 (14) Other 25.1 32.9 30.2 0.5 (24) ----------------------------------------------- Total 614.5 716.2 658.8 25.9 (14) ----------------------------------------------- Expenses Purchased power 255.0 308.5 305.1 11.0 (17) Other operations 108.7 100.7 62.3 2.5 8 Maintenance 31.4 33.3 50.0 0.3 (6) Administrative and general 45.7 54.9 40.7 3.4 (17) Depreciation and amortization 58.2 67.1 71.6 3.1 (13) Taxes, other than income taxes 1.0 1.2 1.7 0.1 (17) ----------------------------------------------- Total 500.0 565.7 531.4 20.4 (12) ----------------------------------------------- Income from Operations 114.5 150.5 127.4 5.5 (24) Interest expense 57.9 63.5 75.2 3.8 (9) Equity in losses of Hazelwood/a 5.5 2.9 1.3 - 90 Other (income) expense - net 30.4 (2.4) 0.3 0.5 * Income tax expense 7.7 32.3 18.7 0.5 (76) ----------------------------------------------- Earnings Contribution $ 13.0 $ 54.2 $ 31.9 $ 0.7 (76) =============================================== Identifiable assets $ 1,661 $ 1,786 $ 2,065 $ 1,751 (7) Capital spending $ 75 $ 84 $ 225 $ 1,591 (11) Energy Sales (millions of kWh) Powercor area 7,233 7,410 7,519 362 (2) Outside Powercor area Victoria 2,396 2,262 791 - 6 New South Wales 2,241 1,372 - - 63 Australian Capital Territory 12 - - - * Queensland 6 - - - * ----------------------------------------------- Total 11,888 11,044 8,310 362 8 =============================================== Number of Customers Powercor area 562,394 553,457 546,247 540,125 2 Outside Powercor area Victoria 1,102 622 567 - 77 New South Wales 1,189 811 - - 47 Australian Capital Territory 23 - - - * Queensland 4 - - - * ----------------------------------------------- Total 564,712 554,890 546,814 540,125 2 =============================================== * Not a meaningful number. /a Results of operations are included since dates of acquisition, December 12, 1995 for Powercor and September 13, 1996 for Hazelwood. /b Comparison done without consideration of the changes in currency exchange rates.
78 OTHER OPERATIONS (UNAUDITED) Other Operations include the operations of PFS, PGC, the western United States energy trading activities and several start-up-phase ventures, as well as the activities of Holdings, including financing costs. PGC assets were sold on November 5, 1997 and a majority of the real estate assets of PFS were sold during May 1998.
for the year || millions of dollars 1998 1997 1996 1995 1994 - ------------------------------------------------------------------------------------------------------------------ Earnings Contribution PFS $ 8.1 $ 30.2 $ 34.1 $ 30.4 $ 3.0 PGC - 10.4 7.8 5.6 8.5 Tax settlement - - - 32.2 - Holdings and other (60.3) (50.2) (14.8) 18.0 6.5 -------------------------------------------------------- Total $ (52.2) $ (9.6) $ 27.1 $ 86.2 $ 18.0 ======================================================== Identifiable Assets PFS 422 692 708 697 731 PGC - - 123 116 113 Holdings and other/a 896 1,063 266 246 252 -------------------------------------------------------- Total $ 1,318 $ 1,755 $ 1,097 $ 1,059 $ 1,096 ======================================================== Capital spending $ 53 $ 140 $ 56 $ 44 $ 13 /a During 1997, the Company generated $1.8 billion of cash, excluding $370 million of current income tax liabilities, from sales of assets with carrying values of $822 million. See Notes 4 and 16.
79 SUPPLEMENTAL INFORMATION
quarterly financial data (unaudited) quarter ended || millions of dollars, except per share amounts March 31 June 30 September 30 December 31 - ----------------------------------------------------------------------------------------------------------------------- 1998 Revenues $ 1,260.2 $ 1,202.2 $ 1,918.2 $ 1,199.8 Income from operations 140.2 194.3 190.4 155.9 Income (loss) from continuing operations (14.6) 78.9 34.6 11.7 Discontinued operations (0.5) (38.1) (122.2) 14.1 Net income (loss) (15.1) 40.8 (87.6) 25.8 Earnings (loss) on common stock (19.9) 36.0 (92.4) 20.9 Earnings (loss) per common share: Continuing operations (0.07) 0.25 0.10 0.02 Discontinued operations - (0.13) (0.41) 0.05 Common dividends declared and paid per share 0.27 0.27 0.27 0.27 Common stock price per share (NYSE) High 26 3/4 24 7/16 23 1/8 22 5/16 Low 22 13/16 21 13/16 18 7/8 18 3/4 1997 Revenues $ 1,002.8 $ 998.1 $ 1,207.7 $ 1,340.3 Income from operations 262.8 223.2 279.1 45.6 Income from continuing operations 103.6 77.7 46.3 5.3 Discontinued operations 17.4 17.1 27.7 384.6 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 (loss) per common share: Continuing operations 0.33 0.24 0.14 - Discontinued operations 0.06 0.06 0.09 1.29 Extraordinary item - - - (0.05) Common dividends declared and paid per share 0.27 0.2 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
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 first quarter of 1998, the Company recorded an after-tax charge of $54 million, or $0.18 per share, relating to the write off of TEG transaction costs and $70 million, or $0.24 per share, relating to the early retirement offer. See Notes 3 and 6. In the third quarter 1998, the Company recorded an after-tax charge of $119 million, or $0.40 per share, relating to the provision for losses anticipated in the disposition of PPM and TPC. In addition, the Company recorded an after-tax charge of $32 million, or $0.11 per share, relating to the provision for losses anticipated in the disposition of the Company's other energy businesses. See Notes 4 and 16. In the fourth quarter of 1998, the Company recorded an after-tax adjustment of $23 million, or $0.08 per share, relating to the Utah rate case, $13 million, or $0.04 per share, relating to ScottishPower merger costs, $17 million, or $0.06 per share, relating to the write down of its investment in Hazelwood and $14 million, or $0.05 per share, of income relating to revised losses for discontinued operations due to the pending sale of TPC for $133 million plus a working capital adjustment at closing. See Notes 2, 4, 5 and 16. 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. See Note 4 for information regarding discontinued operations. On March 1, 1999, there were 105,133 common shareholders of record. 80 PACIFICORP OFFICERS Keith R. McKennon, 65 Donald N. Furman, 42 Chairman, President and Vice President, Transmission Chief Executive Officer 1994 1990 (Year joined the company) Thomas J. Imeson, 48 Richard T. O'Brien, 44 Vice President, Public Affairs Executive Vice President and and Communications Chief Operating Officer 1985 1983 Craig N. Longfield, 53 John A. Bohling, 55 Vice President, Senior Vice President Corporate Development and 1966 Investment Analysis 1989 William C. Brauer, 60 Senior Vice President, Lenore M. Martin, 53 Power Supply Corporate Secretary 1975 1986 Paul G. Lorenzini, 56 Timothy E. Meier, 46 Senior Vice President, Vice President, PacifiCorp Chairman and Chief Chief Information Officer Executive Officer, 1997 Powercor Australia Limited 1987 William E. Peressini, 42 Vice President and Treasurer Daniel L. Spalding, 45 1984 Senior Vice President 1981 Michael J. Pittman, 46 Vice President, Human Resources Dennis P. Steinberg, 52 1979 Senior Vice President 1978 Brian D. Sickels, 53 Vice President Dan R. Baker, 49 1984 Vice President, Mining 1977 A. Richard Walje, 47 Vice President, Distribution Donald A. Bloodworth, 42 1986 Vice President, Business Systems Integration Ernest E. Wessman, 51 1983 Vice President, Business Centers 1979 Barry G. Cunningham, 54 Vice President, Generation Richard D. Westerberg, 49 1977 Vice President, Customer Operations Robert R. Dalley, 44 1978 Controller and Chief Accounting Officer 1978 Anne E. Eakin, 48 Vice President, Regulation 1981 81
PACIFICORP BOARD OF DIRECTORS name W. Charles C. Todd Conover, Keith R. Robert G. Verl R. Topham, Nancy Armstrong, 54 59 McKennon, 65 Miller, 55 64 Wilgenbusch, 51 - ---------------- ------------------ ------------------ ----------------- ------------------ ------------------ ------------------ title Consultant, Managing Chairman, Vice Chairman Retired Senior President, Former Chairman Director, President and and Chief Vice President Marylhurst and Chief Starmont Chief Executive Executive and General University, Executive Asset Officer, Officer, Fred Counsel, Marylhurst, Officer, Bank of Management, PacifiCorp, Meyer, Inc., PacifiCorp, Oregon America, LLC, San Portland, Portland, Salt Lake Oregon, East Francisco Oregon Oregon City, Utah Sound, Washington California - ---------------- ------------------ ------------------ ----------------- ------------------ ------------------ ------------------ year elected 1996 1991 1990 1994 1994 1986 - ---------------- ------------------ ------------------ ----------------- ------------------ ------------------ ------------------ 82 name Kathryn Braun Nolan E. Karras, Alan K. Simpson, Don M. Wheeler*, Peter I. Wold, Lewis, 47 54 67 70 51 - ---------------- ------------------ ------------------ ----------------- ------------------ ------------------ title Retired, Former Investment Former U.S. Chairman and Partner, President and Advisor, Senator, Chief Wold Oil & Gas Chief Operating The Karras Cody, Executive Officer, Company, Officer, Personal Company, Roy, Wyoming CM Equipment Casper, Storage Division Utah Company, Salt Wyoming Western Digital Lake City, Utah Corporation Irving, California - ---------------- ------------------ ------------------ ----------------- ------------------ ------------------ year elected 1994 1993 1997 1989 1995 - ---------------- ------------------ ------------------ ----------------- ------------------ ------------------
83 PACIFICORP INVESTOR INFORMATION STOCK EXCHANGE LISTINGS PacifiCorp's common stock is listed on the New York Stock Exchange and the Pacific Stock Exchange under the symbol PPW. The company has three other securities which are listed and traded on the New York Stock Exchange. issue symbol - ----------------------------------------- 8.375% Quarterly Income Debt Securities PCQ 8.55% Quarterly Income Debt Securities PCX 7.70% Trust Preferred Securities, Series B PPW B Pfd Daily quotes on the common stock and other listed securities can be obtained by checking the New York Stock Exchange composite transactions listed in local newspapers. The company's first mortgage bonds and most preferred stock series are infrequently traded in the over-the-counter market. INVESTOR RELATIONS Financial analysts, stockbrokers, interested investors and financial media desiring information about PacifiCorp should contact Investor Relations at (503) 813-7220. SHAREHOLDER SERVICES AND INFORMATION For questions regarding PacifiCorp stock ownership, Shareholder Services may be reached from all U.S. long distance call locations at (800) 233-5453. Portland-area callers can dial 813-7000. The toll-free telephone number is answered between 7 a.m. and 5 p.m. Pacific Time Monday-Thursday, and 7 a.m. to 4 p.m. on Friday. Shareholders' written correspondence may be submitted to: PacifiCorp Shareholder Services P.O. Box 14740 Portland, Oregon 97293-0740 TRANSFER AGENT PacifiCorp maintains shareholder records and acts as Transfer Agent and Registrar for the company's common and preferred stock issues. DIVIDEND REINVESTMENT AND STOCK PURCHASE PacifiCorp's dividend reinvestment plan allows interested investors to purchase common shares directly from the company, with an initial minimum investment of $250. The plan is also a convenient way for existing shareholders to increase their investment in the company, by reinvesting all or a portion of their quarterly dividends to acquire additional shares of common stock. Plan participants may make optional cash purchases ($25 minimum each investment and $100,000 maximum per year) of common stock as frequently as twice per month. Shareholders wishing to terminate their plan account may sell these shares through the company, provided their plan balance is less than 100 shares. If not, a stock certificate may be requested in lieu of a sale. For a plan prospectus, enrollment form or other information, please call or write the Shareholder Services Department at the numbers listed above. BONDHOLDER INFORMATION Direct inquires concerning lost bonds, interest payments, changes of address and other matters relating to ownership to: Chase Manhattan Bank Corporate Trust Services - Communications 1201 Main Street - 17 OMP Dallas, Texas 75202 General inquiries: (800) 648-8380 Form 1099 and tax inquires: (800) 298-6805 ANNUAL MEETING The 1999 Annual Meeting of PacifiCorp Shareholders takes place: Thursday, June 17, 1999 1:30 p.m. Mountain Daylight Time Salt Lake Hilton Hotel 150 West 500 South Salt Lake City, Utah FORM 10-K A copy of the company's 1998 10-k, filed with the Securities and Exchange Commission, may be obtained by contacting Investor Relations at the corporate headquarters address. It is also available via PacifiCorp's web site through an Internet link to the SEC EDGAR Database. DIVIDEND PAYMENT Dividends on the company's common and preferred stock in 1999 are expected to be paid on or about: February 16 May 17 August 16 November 15 CORPORATE ADDRESSES PACIFICORP Corporate Headquarters 825 NE Multnomah Street, 20th floor Portland, Oregon 97232-4116 (503) 813-5000 POWERCOR AUSTRALIA LIMITED Head Office 40 Market Street South Melbourne Victoria, Australia 3005 03-9679-4444 (within Australia) 011-613-9679-4444 (from U.S.) INTERNET ADDRESS http://www.pacificorp.com COUNSEL Stoel Rives LLP INDEPENDENT AUDITORS Deloitte & Touche LLP 84 [Additional Proxy Soliciting Materials] --------------------------------------- Understanding the Merger Proxy Process PacifiCorp shareholders - and that includes most employees - are being reminded by the Company's proxy solicitor, Innisfree M & A, Inc., to return their proxy cards. These cards have been mailed by Innisfree to homes at least twice in packets of information about the pending merger with ScottishPower. Innisfree is an independent third party handling the proxy voting process. Reminders - including possible telephone calls - will continue for those who have not yet returned their proxy. All votes are important because approval of the merger requires a favorable vote of both a majority of the Company's common shares outstanding as well as a majority of the Company's preferred stock. If returned by mail, the proxy cards need to be sent soon so that Innisfree will have time to process them prior to the June 17 PacifiCorp annual meeting in Salt Lake City. Proxies can also be submitted in person at the annual meeting. The proxies are tabulated by computer and individual votes are confidential. PacifiCorp and ScottishPower will receive just the final tally from Innisfree. -----END PRIVACY-ENHANCED MESSAGE-----