-----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, Ghxg0ou1zpW3LoHTe2AsxbOPn+FlG3x7VT4Qdrqb7YnXHvwLo2fNfxiuYTprJfFv bxo1W4cO5yVjzNEp1IeNhQ== 0000075594-98-000042.txt : 19981113 0000075594-98-000042.hdr.sgml : 19981113 ACCESSION NUMBER: 0000075594-98-000042 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 16 CONFORMED PERIOD OF REPORT: 19980930 FILED AS OF DATE: 19981112 FILER: COMPANY DATA: COMPANY CONFORMED NAME: PACIFICORP /OR/ CENTRAL INDEX KEY: 0000075594 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 930246090 STATE OF INCORPORATION: OR FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: SEC FILE NUMBER: 001-05152 FILM NUMBER: 98745133 BUSINESS ADDRESS: STREET 1: 700 NE MULTNOMAH STE 1600 CITY: PORTLAND STATE: OR ZIP: 97232 BUSINESS PHONE: 5037312000 FORMER COMPANY: FORMER CONFORMED NAME: PACIFICORP /ME/ DATE OF NAME CHANGE: 19890628 FORMER COMPANY: FORMER CONFORMED NAME: PC/UP&L MERGING CORP DATE OF NAME CHANGE: 19890628 10-Q 1 UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-Q /X/ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended September 30, 1998 __________________ OR / / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from _______________ to _______________ Commission file number 1-5152 ______ PACIFICORP (Exact name of registrant as specified in its charter) STATE OF OREGON 93-0246090 (State or other jurisdiction (I.R.S. Employer of incorporation or organization) Identification No.) 700 N.E. Multnomah Suite 1600 Portland, Oregon 97232-4116 (Address of principal executive offices) (Zip code) 503-813-7200 (Registrant's telephone number) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding twelve months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for at least the past 90 days. YES X NO _____ _____ At October 31, 1998, there were 297,334,589 shares of registrant's common stock outstanding. 1 PACIFICORP
Page No. ________ PART I. FINANCIAL INFORMATION Item 1. Financial Statements Condensed Consolidated Statements of Income and Retained Earnings 2 Condensed Consolidated Statements of Cash Flows 3 Condensed Consolidated Balance Sheets 4 Notes to Condensed Consolidated Financial Statements 6 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations 13 PART II. OTHER INFORMATION Item 1. Legal Proceedings 35 Item 6. Exhibits and Reports on Form 8-K 35 Signature 36
2 PART I. FINANCIAL INFORMATION Item 1. Financial Statements PACIFICORP CONDENSED CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS (Millions of Dollars, except per share amounts) (Unaudited)
Three Months Ended Nine Months Ended September 30, September 30, ___________________ _________________ 1998 1997 1998 1997 ______ ______ ______ ______ REVENUES $1,918.2 $1,207.7 $4,380.6 $3,208.6 _______ _______ _______ _______ EXPENSES Purchased power 1,220.6 429.2 2,237.2 971.6 Other operations and maintenance 291.6 292.5 848.1 848.7 Depreciation and amortization 110.1 111.2 340.8 331.2 Administrative and general 81.6 70.0 239.8 212.8 Taxes, other than income taxes 23.9 25.7 76.7 79.2 Special charges - - 113.1 - _______ _______ _______ _______ TOTAL 1,727.8 928.6 3,855.7 2,443.5 _______ _______ _______ _______ INCOME FROM OPERATIONS 190.4 279.1 524.9 765.1 _______ _______ _______ _______ INTEREST EXPENSE AND OTHER Interest expense 92.5 112.8 280.8 330.0 Interest capitalized (4.4) (3.3) (11.4) (9.5) Other expense - net 48.2 108.8 114.3 104.4 _______ _______ _______ _______ TOTAL 136.3 218.3 383.7 424.9 _______ _______ _______ _______ Income from continuing operations before income taxes 54.1 60.8 141.2 340.2 Income tax expense 19.5 14.5 42.3 112.6 _______ _______ _______ _______ Income from continuing operations 34.6 46.3 98.9 227.6 Discontinued Operations (less applicable income tax expense: 1998/$60.2 and $83.4, 1997/$17.8 and $41.7) (122.2) 27.7 (160.8) 62.2 _______ _______ _______ _______ NET INCOME (LOSS) (87.6) 74.0 (61.9) 289.8 RETAINED EARNINGS BEGINNING OF PERIOD 962.8 827.7 1,106.3 782.8 Cash dividends declared Preferred stock (4.2) (5.5) (12.8) (16.6) Common stock per share of $0.27 and $0.81 (80.1) (80.1) (240.7) (239.9) _______ _______ _______ _______ RETAINED EARNINGS END OF PERIOD $ 790.9 $ 816.1 $ 790.9 $ 816.1 ======= ======= ======= ======= EARNINGS (LOSS) ON COMMON STOCK $ (92.4) $ 68.2 $ (76.3) $ 271.8 Average number of common shares outstanding - Basic (Thousands) 297,272 296,347 297,197 295,884 Dilutive (Thousands) 297,322 296,350 297,224 295,899 EARNINGS (LOSS) PER COMMON SHARE - Basic and dilutive Continuing operations $ 0.10 $ 0.14 $ 0.28 $ 0.71 Discontinued operations (0.41) 0.09 (0.54) 0.21 _______ _______ _______ _______ TOTAL $ (0.31) $ 0.23 $ (0.26) $ 0.92 ======= ======= ======= ======= See accompanying Notes to Condensed Consolidated Financial Statements
3 PACIFICORP CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Millions of Dollars) (Unaudited)
Nine Months Ended September 30, ______________________ 1998 1997 ______ ______ CASH FLOWS FROM OPERATING ACTIVITIES Net income $ (61.9) $ 289.8 Adjustments to reconcile net income to net cash provided by operating activities Loss (income) from discontinued operations 160.8 (62.2) Write off of exited operations 52.0 - Depreciation and amortization 347.4 343.8 Deferred income taxes and investment tax credits - net (61.0) 21.1 Special charges 113.1 - Other 82.3 19.8 Accounts receivable and prepayments (296.4) (46.3) Materials, supplies and fuel stock (5.6) - Accounts payable and accrued liabilities 327.9 24.7 ________ ______ Net cash provided by continuing operations 658.6 590.7 Net cash used in discontinued operations (390.2) (386.2) ________ ______ NET CASH PROVIDED BY OPERATING ACTIVITIES 268.4 204.5 ________ ______ CASH FLOWS FROM INVESTING ACTIVITIES Construction (429.5) (440.6) Investments in and advances to affiliated companies - net (25.1) (45.6) Operating companies and assets acquired (40.3) (30.5) Proceeds from sales of finance assets, real estate investments and principal payments 316.8 52.6 Other 3.9 (34.7) ________ ______ NET CASH USED IN INVESTING ACTIVITIES (174.2) (498.8) ________ ______ CASH FLOWS FROM FINANCING ACTIVITIES Changes in short-term debt 144.4 23.8 Proceeds from long-term debt 1,066.2 742.4 Proceeds from issuance of common stock 8.9 29.1 Proceeds from issuance of Trusts holding solely PacifiCorp debentures preferred securities - 130.7 Dividends paid (259.6) (256.0) Repayments of long-term debt (1,155.0) (233.2) Redemptions of preferred stock - (72.2) Other 39.4 (62.5) ________ ______ NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES (155.7) 302.1 ________ ______ INCREASE IN CASH AND CASH EQUIVALENTS 61.5 7.8 CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 740.8 8.4 ________ ______ CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 679.3 $ 16.2 ======== ====== SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION Cash paid during the period for Interest (net of amount capitalized) $ 330.9 $ 381.2 Income taxes 485.0 115.2 See accompanying Notes to Condensed Consolidated Financial Statements
4 PACIFICORP CONDENSED CONSOLIDATED BALANCE SHEETS (Millions of Dollars) (Unaudited) ASSETS
September 30, December 31, 1998 1997 ____________ ____________ CURRENT ASSETS Cash and cash equivalents $ 679.3 $ 740.8 Accounts receivable less allowance for doubtful accounts: 1998/$12.4 and 1997/$17.7 947.9 723.9 Materials, supplies and fuel stock at average cost 193.3 181.9 Real estate investments held for sale - 272.2 Net assets of discontinued operations 120.0 223.4 Other 38.3 55.0 ________ ________ TOTAL CURRENT ASSETS 1,978.8 2,197.2 PROPERTY, PLANT AND EQUIPMENT Domestic Electric Operations 12,402.2 12,094.6 Australian Electric Operations 1,090.4 1,161.2 Other Operations 30.4 31.1 Accumulated depreciation and amortization (4,508.2) (4,240.0) ________ ________ TOTAL PROPERTY, PLANT AND EQUIPMENT - NET 9,014.8 9,046.9 OTHER ASSETS Investments in and advances to affiliated companies 131.9 166.1 Intangible assets - net 366.1 399.0 Regulatory assets - net 849.6 871.1 Finance note receivable 207.3 211.2 Finance and real estate assets - net 377.5 349.8 Deferred charges and other 272.6 385.7 ________ ________ TOTAL OTHER ASSETS 2,205.0 2,382.9 ________ ________ TOTAL ASSETS $13,198.6 $13,627.0 ======== ======== See accompanying Notes to Condensed Consolidated Financial Statements
5 PACIFICORP CONDENSED CONSOLIDATED BALANCE SHEETS (Millions of Dollars) (Unaudited) LIABILITIES AND SHAREHOLDERS' EQUITY
September 30, December 31, 1998 1997 ____________ ____________ CURRENT LIABILITIES Long-term debt currently maturing $ 299.0 $ 365.4 Notes payable and commercial paper 333.6 189.2 Accounts payable 842.6 546.7 Taxes, interest and dividends payable 348.7 677.5 Customer deposits and other 125.6 84.9 ________ ________ TOTAL CURRENT LIABILITIES 1,949.5 1,863.7 DEFERRED CREDITS Income taxes 1,494.4 1,666.2 Investment tax credits 129.2 135.2 Other 685.7 646.2 ________ ________ TOTAL DEFERRED CREDITS 2,309.3 2,447.6 LONG-TERM DEBT 4,354.3 4,413.0 COMMITMENTS AND CONTINGENCIES (See Notes 4 and 5) - 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: 1998/297,279,589 and 1997/296,908,110 3,283.6 3,274.2 Retained earnings 790.9 1,106.3 Accumulated other comprehensive loss (70.9) (59.6) ________ ________ TOTAL COMMON EQUITY 4,003.6 4,320.9 ________ ________ TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $13,198.6 $13,627.0 ======== ======== See accompanying Notes to Condensed Consolidated Financial Statements
6 NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) September 30, 1998 1. FINANCIAL STATEMENTS The accompanying unaudited condensed consolidated financial statements as of September 30, 1998 and December 31, 1997 and for the periods ended September 30, 1998 and 1997, in the opinion of management, include all adjustments, constituting only normal recording of accruals, necessary for a fair presentation of financial position, results of operations and cash flows for such periods. A significant part of the business of PacifiCorp (the "Company") is of a seasonal nature; therefore, results of operations for the periods ended September 30, 1998 and 1997 are not necessarily indicative of the results for a full year. These condensed consolidated financial statements should be read in conjunction with the financial statements and related notes incorporated by reference in the Company's 1997 Annual Report on Form 10-K. The condensed consolidated financial statements of the Company include the integrated domestic electric utility operations of Pacific Power and Utah Power and its wholly owned and majority owned subsidiaries. Major subsidiaries, all of which are wholly owned, are: PacifiCorp Group Holdings Company ("Holdings"), which holds directly or through its wholly owned subsidiary, PacifiCorp International Group Holdings Company, Powercor Australia Limited ("Powercor"), an Australian electricity distributor, and PacifiCorp Financial Services, Inc. ("PFS"), a financial services business. Together these businesses are referred to herein as the Companies. Significant intercompany transactions and balances have been eliminated. The Company has decided to exit the unregulated energy trading business and dispose of TPC Corporation ("TPC"), a natural gas marketing and storage company and the eastern U.S. electricity trading business of PacifiCorp Power Marketing, Inc. ("PPM"). See Note 3. The Company sold its wholly owned telecommunications subsidiary, Pacific Telecom, Inc. ("PTI"), on December 1, 1997. See Note 3. The Company sold Pacific Generation Company ("PGC") on November 5, 1997, and the natural gas gathering and processing assets of TPC on December 1, 1997. During May 1998, a majority of the real estate assets held by PFS were sold. The Company has also decided to exit the majority of its other unregulated energy development businesses and has recorded them at estimated net realizable value less selling costs. Investments in and advances to affiliated companies represent investments in unconsolidated affiliated companies carried on the equity basis, which approximates the Company's equity in their underlying net book value. Certain amounts have been reclassified to conform with the 1998 method of presentation. These reclassifications had no effect on previously reported consolidated net income. 7 2. 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, Texas Utilities Company made a tender offer at a higher price. 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 to first quarter 1998 earnings, included in "Other expense-net," 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 loss of $3 million in April 1998 in connection with closing its foreign currency option contract associated with the bid for TEG. Total pretax costs incurred in 1997 and 1998 were $199 million. 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 when they were sold on June 2, 1998. 3. DISCONTINUED OPERATIONS The Company has decided to exit the unregulated energy trading business and offer for sale TPC and the eastern U.S. electricity trading business of PPM. The Company will continue its wholesale power marketing activities in the West, where it can provide physical delivery of energy. The Company anticipates completing these transactions within the next twelve months. On December 1, 1997, Holdings completed the sale of PTI for $1.5 billion in cash plus the assumption of PTI's debt of $713 million. 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 unregulated energy trading segment and PTI have been classified as discontinued operations for all periods presented in the condensed financial statements and notes. 8 Summarized operating results for unregulated energy trading were as follows:
Three-Month Nine-Month Periods Ended Periods Ended September 30, September 30, _________________ _________________ 1998 1997 1998 1997 ______ ______ ______ ______ (Dollars in Millions) Revenues $1,424.7 $ 802.1 $2,961.4 $1,062.5 _______ _______ _______ _______ Income (loss) from discontinued operations (less applicable income tax expense/(benefit): 1998/$(1.1) and $(24.3), 1997/$1.2 and ($0.1)) $ (3.1) $ 0.6 $ (41.7) $ (2.3) Loss on disposal, including provision of $20.0 for operating losses during phase-out period (less applicable income tax benefit $59.1) (119.1) - (119.1) - _______ _______ _______ _______ Net income (loss) $ (122.2) $ 0.6 $ (160.8) $ (2.3)
Summarized operating results for PTI were as follows:
Three-Month Nine-Month Period Ended Period Ended September 30, September 30, _________________ _________________ 1998 1997 1998 1997 ______ ______ ______ ______ (Dollars in Millions) Revenues $ - $154.0 $ - $416.2 ______ _____ ______ _____ Income before income taxes $ - $ 43.7 $ - $106.3 Income taxes - 16.6 41.8 ______ _____ ______ _____ Net income $ - $ 27.1 $ - $ 64.5 ______ _____ ______ _____ Total income (loss) from discontinued operations $(122.2) $ 27.7 $(160.8) $ 62.2 ====== ===== ====== =====
9 Net assets of the discontinued operations of Unregulated Energy Trading consisted of the following:
September 30, December 31, 1998 1997 _____________ ____________ (Dollars in Millions) Current assets $ 220.0 $ 208.5 Noncurrent assets 262.6 269.5 Current liabilities (186.3) (241.9) Long-term debt (1.4) (1.5) Noncurrent liabilities (24.8) (11.2) Write down of assets (150.1) - _______ _______ Net Assets of Discontinued Operations $ 120.0 $ 223.4 ======= =======
4. ACCOUNTING FOR THE EFFECTS OF REGULATION Domestic Electric Operations prepares its financial statements in accordance with Statement of Financial Accounting Standards ("SFAS") 71, "Accounting for the Effects of Certain Types of Regulations." Under this statement, the Company may defer certain costs as regulatory assets and certain obligations as regulatory liabilities. Regulatory assets and liabilities represent probable future revenues that will be recovered from, or refunded to, customers through the ratemaking process. The Emerging Issues Task Force of the Financial Accounting Standards Board (the "EITF") concluded in 1997 that SFAS 71 should be discontinued when detailed legislation or regulatory orders regarding competition are issued. Additionally, the EITF concluded that regulatory assets and liabilities applicable to businesses being deregulated should be written off unless their recovery is provided for through future regulated cash flows. Recoverability of regulatory assets is assessed at each reporting period. During 1997, the Utah Public Service Commission (the "PSC") held hearings on the proper method to be used in allocating costs among the Company's seven jurisdictions that resulted in an order issued on April 16, 1998. Under the order, differences in allocations associated with the merger of Pacific Power and Utah Power will be eliminated over five years on a straight-line basis. The phase-out of the differences is to be completed by January 1, 2001 and could reduce Utah prices by approximately $50 million to $60 million per year once fully implemented. The order itself will not decrease revenues, but is being included in a general rate case for the overall determination of revenue requirement by the PSC and will be combined with other cost increases and decreases to determine the overall impact to customer rates. In the pending Utah rate case, the Utah Division of Public Utilities (the "DPU") proposed adjustments that could result in a $57 million annualized reduction in customer prices. This includes approximately $21 million of the allocation phase-in. The Committee of Consumer Services proposed adjustments in the rate case that could reduce customer prices annually by $79 million, including $21 million relating to the allocation phase-in. The Company originally requested no change in customer prices and proposed a new authorized rate of return on equity of 11.25%. The Company subsequently settled certain issues with the other parties and is now requesting an $18 million decrease. Any 10 required adjustment to customer prices could be retroactive to February 1997, the date a petition was filed by the DPU with the PSC requesting a general rate case. If the PSC approved the DPU proposal in December 1998 and ordered the adjustment to be retroactive to February 1997, the Company would have collected approximately $110 million of revenues subject to refund. An adjustment to 1998 earnings of approximately $70 million, excluding any interest imposed, would be required when the order was issued and the amount was determinable. Hearings for the case are currently in process, with a final order expected by year end. The Company has announced it will not appeal the Utah allocation order. On July 9, 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 changes in the legislative and regulatory environments, including fixing prices, in these states where the Company has few distribution properties. 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 September 16, 1998, the Company entered into a Letter of Agreement with Flathead Electric Cooperative for the Montana distribution assets. On November 5, 1998, the Company completed the sale and received after-tax proceeds of $92 million. The Company will return $4 million of the $8 million gain to Montana customers as negotiated with the Montana Public Service Commission (the "MPSC") and the Montana Consumer Counsel. 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 related 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 would result in a $3.5 million annual reduction in revenues. The Company has requested a rehearing of this issue. 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 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 estimated revenue increase in 1998 is approximately $6.9 million. The AFOR also includes incentives to invest in renewable resources and penalties for failure to maintain the service quality levels. 11 The Company continues to evaluate the impact of all changes in regulation and legislation. Changes in regulatory environment may significantly affect the Company's future financial condition, results of operations and cash flows. 5. CONTINGENT LIABILITIES 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. 6. COMPREHENSIVE INCOME Effective January 1, 1998, the Company adopted SFAS No. 130, "Reporting Comprehensive Income." This statement requires items previously reported as a component of common equity be more prominently reported in a separate financial statement as a component of comprehensive income. The components of comprehensive income are as follows:
Three-Month Nine-Month Periods Ended Periods Ended September 30, September 30, _________________ ________________ 1998 1997 1998 1997 ______ ______ ______ ______ (Dollars in Millions) Net income $(87.6) $ 74.0 $(61.9) $289.8 Other comprehensive income Foreign currency translation adjustment, net of taxes: 1998/$0.7 and $(11.1), 1997/$(3.3) and $(22.0) 1.1 (5.4) (18.4) (34.6) Unrealized gain on available- for-sale securities, net of taxes: 1998/$4.3 - - 7.1 - _____ _____ _____ _____ Total comprehensive income $(86.5) $ 68.6 $(73.2) $255.2 ===== ===== ===== =====
7. NEW ACCOUNTING STANDARDS In June 1997, the Financial Accounting Standards Board (the "FASB") issued SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information." SFAS No. 131 requires that companies disclose segment data based on how management makes decisions about allocating resources to segments and measuring performance. This standard is effective for fiscal years beginning after December 15, 1997. Adoption of this standard may result in additional financial disclosure but will not have an effect on the Company's financial position or results of operations. In February 1998, the FASB issued SFAS No. 132, "Employers' Disclosures About Pensions and Other Postretirement Benefits." This statement, which is 12 effective for fiscal years beginning after December 15, 1997, revises employers' disclosures about pension and other postretirement benefit plans. Adoption of this standard will not change the measurement of the liability nor recognition of expense of these plans. In June 1998, the FASB issued SFAS No. 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. 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. 13 Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS SUMMARY RESULTS OF OPERATIONS This report includes forward-looking statements that involve a number of risks and uncertainties that may influence the financial performance and earnings of the Company and its subsidiaries, including the factors identified in the Company's 1997 Annual Report on Form 10-K. Such forward-looking statements should be considered in light of those factors. Comparison of the three-month periods ended September 30, 1998 and 1997 _______________________________________________________________________
% 1998 1997 Change Change ____ ____ ______ ______ (Dollars in Millions) Earnings contribution (loss) on common stock (1) Domestic Electric Operations $ 49.9 $ 87.5 $ (37.6) (43) Australian Electric Operations 6.5 15.8 (9.3) (59) Other Operations (26.6) (62.8) 36.2 58 ______ _____ ______ Continuing Operations 29.8 40.5 (10.7) (26) Discontinued Operations (2) (122.2) 27.7 (149.9) * ______ _____ ______ Total $ (92.4) $ 68.2 $(160.6) * ====== ===== ====== Earnings (loss) per common share - Basic and dilutive Continuing Operations $ 0.10 $ 0.14 $ (0.04) (29) Discontinued Operations (2) (0.41) 0.09 (0.50) * _____ _____ ______ Total $(0.31) $ 0.23 $ (0.54) * ===== ===== ====== *Not a meaningful number. (1) Earnings contribution (loss) on common stock by segment: (a) does not reflect elimination for interest on intercompany borrowing arrangements; (b) includes income taxes on a separate company basis, with any benefit or detriment of consolidation reflected in Other Operations; (c) amounts are net of preferred dividend requirements and minority interest. (2) Represents the discontinued operations of PTI and the unregulated energy trading business.
The Company recorded losses on common stock of $92 million, or $0.31 per share, in the third quarter of 1998 compared to income of $68 million, or $0.23 per share, reported in 1997. Third quarter 1998 results included losses of $151 million, or $0.51 per share, relating to unregulated energy businesses that the Company has decided to exit. Third quarter 1997 results included a loss of $65 million, or $0.22 per share, associated with closing foreign exchange positions relating to the Company's offer for TEG and income of $27 million, or $0.09 per share, from the Company's telecommunications operations that were sold in December of 1997. 14 Domestic Electric Operations earnings contribution was $50 million, or $0.17 per share, as compared to $88 million, or $0.30 per share, in the third quarter of 1997. Income from operations declined $57 million, or 25%, to $172 million. Operating income declined in the quarter primarily due to lower wholesale margins in the West and less favorable hydroelectric conditions. Earnings from the Company's Australian Electric Operations were $7 million, or $0.02 per share, in the third quarter of 1998, compared to $16 million, or $0.05 per share, in the same quarter last year. Earnings declined primarily as a result of lower sales margins and increased administrative and general expenses. In addition, earnings were reduced by $2 million as the result of unfavorable fluctuations in the currency exchange rate. Other operations reported losses of $27 million, or $0.09 per share, in the quarter compared to losses of $63 million, or $0.21 per share, in the third quarter 1997. The Company evaluated the unregulated energy development businesses and recorded an impairment of $32 million in the third quarter of 1998. Third quarter 1997 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. Discontinued operations reported losses of $122 million, or $0.41 per share, in the quarter as compared to income of $28 million, or $0.09 per share, in the third quarter of 1997. Third quarter 1998 results included $119 million, or $0.40 per share, relating to the loss anticipated to exit the unregulated energy trading business and a loss of $3 million, or $0.01 per share, relating to normal operations. Third quarter 1997 results included income of $27 million, or $0.09 per share, from the Company's telecommunications operations that were sold in December of 1997. Comparison of the nine-month periods ended September 30, 1998 and 1997 ______________________________________________________________________
% 1998 1997 Change Change ____ ____ ______ ______ (Dollars in Millions) Earnings contribution (loss) on common stock Domestic Electric Operations $ 108.4 $224.3 $(115.9) (52) Australian Electric Operations 27.2 44.9 (17.7) (39) Other Operations (51.1) (59.6) 8.5 14 ______ _____ ______ Continuing Operations 84.5 209.6 (125.1) (60) Discontinued Operations (160.8) 62.2 (223.0) * ______ _____ ______ Total $ (76.3) $271.8 $(348.1) (128) ====== ===== ====== Earnings (loss) per common share - Basic and dilutive Continuing Operations $ 0.28 $ 0.71 $ (0.43) (61) Discontinued Operations (0.54) 0.21 (0.75) * _____ _____ ______ Total $(0.26) $ 0.92 $ (1.18) (128) ===== ===== ====== *Not a meaningful number.
15 The Company recorded losses on common stock of $76 million, or $0.26 per share, in 1998 compared to income of $272 million, or $0.92 per share, reported in 1997. The 1998 results included losses of $151 million, or $0.51 per share, relating to unregulated energy businesses that the Company has decided to exit, a charge of $70 million, or $0.24 per share, associated with the Company's work force reduction in the United States and a charge of $54 million, or $0.18 per share, associated with the Company's terminated bid for TEG. The 1997 results included a loss of $65 million, or $0.22 per share, associated with closing foreign exchange positions relating to the Company's offer for TEG and income of $65 million, or $0.22 per share, from the Company's telecommunications operations that were sold in December of 1997. Domestic Electric Operations earnings contribution was $108 million, or $0.37 per share. Excluding the $70 million charge relating to the work force reduction, the earnings contribution would have been $178 compared to $224 million in 1997. Lower wholesale margins in the West, less favorable hydroelectric conditions, higher depreciation and costs relating to the Year 2000 issues and implementation of a new SAP software operating environment contributed to the decrease in operating income. Earnings from the Company's Australian Electric Operations were $27 million, or $0.09 per share, in 1998, compared to $45 million, or $0.15 per share, in 1997. Earnings declined primarily as a result of lower sales margins, increased administrative and general expenses and a reduction in Tariff H revenue. In addition, earnings were reduced by $6 million as the result of unfavorable fluctuations in the currency exchange rate. Other operations reported losses of $51 million, or $0.18 per share, compared to losses of $60 million, or $0.20 per share, in 1997. The Company evaluated the unregulated energy development businesses and recorded an impairment of $32 million in 1998. In addition, 1998 earnings included a charge of $54 million for costs associated with the Company's terminated bid for TEG, partially offset by a gain of $10 million on the sale of TEG shares acquired in March 1998. The 1997 earnings 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. Discontinued operations reported losses of $161 million, or $0.54 per share, compared to income of $62 million, or $0.21 per share, in 1997. The 1998 results included $119 million, or $0.40 per share, for the loss anticipated to exit the unregulated energy trading business and a loss of $42 million, or $0.14 per share, relating to normal operations. The 1997 results included income of $65 million, or $0.22 per share, from the Company's telecommunications operations that were sold in December of 1997. 16 RESULTS OF OPERATIONS Domestic Electric Operations ____________________________ Comparison of the three-month periods ended September 30, 1998 and 1997 _______________________________________________________________________
% 1998 1997 Change Change ____ ____ ______ ______ (Dollars in Millions) Revenues Residential $ 191.8 $ 184.1 $ 7.7 4 Commercial 173.6 168.7 4.9 3 Industrial 203.5 201.6 1.9 1 Other 8.4 8.1 0.3 4 _______ _______ ______ Retail sales 577.3 562.5 14.8 3 Wholesale sales and market trading 1,164.0 409.7 754.3 * Other 17.6 20.7 (3.1) (15) _______ _______ ______ Total 1,758.9 992.9 766.0 77 Operating expenses 1,587.4 764.9 822.5 108 _______ _______ ______ Income from operations 171.5 228.0 (56.5) (25) Interest expense 82.9 81.5 1.4 2 Minority interest and other 0.4 (0.3) 0.7 * Income taxes 33.5 53.5 (20.0) (37) _______ _______ ______ Net income 54.7 93.3 (38.6) (41) Preferred dividend requirement 4.8 5.8 (1.0) (17) _______ _______ ______ Earnings contribution $ 49.9 $ 87.5 $ (37.6) (43) ======= ======= ====== Energy sales (millions of kWh) Residential 2,929 2,832 97 3 Commercial 3,250 3,189 61 2 Industrial 5,831 5,572 259 5 Other 181 184 (3) (2) ______ ______ ______ Retail sales 12,191 11,777 414 4 Wholesale sales and market trading 34,227 15,354 18,873 123 ______ ______ ______ Total 46,418 27,131 19,287 71 ====== ====== ====== Residential average usage (kWh) 2,356 2,331 25 1 Total retail customers (end of period) 1,459,029 1,427,289 31,740 2
Revenues Domestic Electric Operations revenues increased $766 million, or 77%. This increase was primarily attributable to a $754 million increase in wholesale revenues. Wholesale volumes continued to expand with the active markets. The $754 million increase in revenues was driven by energy volumes that more than doubled in 1998 to 34.2 million MWh. Higher short-term and spot market wholesale energy volumes increased revenues by $639 million. Related energy prices averaged $34 per MWh 17 in the quarter, a 44% increase over the prior year. The higher prices for these sales added $120 million to revenues in the quarter. Residential revenues and energy volumes were up $8 million and 3%, respectively. Growth in the average number of residential customers of 2% added $4 million to revenues. Warmer weather and other customer usage changes added $3 million to residential revenues. Third quarter 1998 temperatures averaged 4 degrees warmer in July and 2 degrees warmer in September. Commercial revenues were up $5 million, or 3%. Energy sales volumes increased 2% over the prior year. Growth in the average number of customers of 2% added $5 million to revenues. Industrial revenues increased $2 million, or 1%. Warmer, drier weather resulted in increased irrigation, which added $3 million to industrial revenues. Hearings in the Company's general rate case in Utah are currently in process, with a final order expected by year end. Parties in the case have proposed adjustments that would result in significant reductions in prices and could require a material reduction to 1998 earnings for revenues collected subject to refund. Regulatory changes have also occurred in other states in which the Company operates. See Note 4 to the Condensed Consolidated Financial Statements for additional information concerning pending regulatory proceedings and developments. The Company continues to evaluate the accounting impact of all changes in regulation. Changes in regulatory structure may significantly affect the Company's future financial condition and results of operations. Operating Expenses Total operating expenses increased $823 million, or 108%. This increase was primarily attributable to increased purchased power expense to serve the expanding wholesale market. Purchased power expense increased $809 million, to $1.18 billion. The higher expense was primarily due to a 19.6 million MWh increase in short-term firm and spot market energy purchases, more than double the amount of purchases in the same period of 1997, which increased purchased power expense $665 million. Short-term firm and spot market purchase prices averaged $34 per MWh in the quarter versus $22 per MWh in 1997, a 56% increase. The increase in purchase prices added $145 million to costs. Lower volumes partially offset by higher prices relating to long-term firm purchased power contracts resulted in a $3 million decrease in purchased power costs. 18 SHORT-TERM AND SPOT MARKET SALES AND PURCHASES ______________________________________________
1998 1997 ________ ________ Total sales volume (thousands of MWh) 30,512 11,485 Average sales price ($/MWh) $ 33.71 $ 23.46 ______ ______ Revenues ($, millions) $ 1,029 $ 269 Total purchase volume (thousands of MWh) 31,410 11,830 Average purchase price ($/MWh) $ 33.99 $ 21.77 ______ ______ Expenses ($, millions) $ 1,068 $ 258 ______ ______ Net ($, millions) $ (39) $ 11 ====== ======
Fuel expense was up $9 million, or 7%, to $135 million. Thermal generation increased 4% to 13.6 million MWh. The average cost per MWh increased to $9.93 from $9.58 due to increased generation at plants with higher fuel costs. This shift in generation resulted from unscheduled plant outages and higher market prices for generation. Hydroelectric generation decreased 3% compared to the third quarter of last year due to lower stream flows. Depreciation and amortization expense increased $3 million, or 3%, to $95 million. Increased plant in service added $2 million. In July 1998, the Company withdrew its filings with regulatory bodies of a depreciation study filed in 1997 because in its view regulatory approvals to increase depreciation rates were unlikely. As a result of the decision to withdraw the filing, the Company ceased recording the increased depreciation expense in the third quarter. During the first six months of 1998, the Company had recorded $9 million in additional depreciation as a result of the study. The Company is preparing a revised depreciation study that will be submitted to the regulatory commission in the fourth quarter of 1998. Administrative and general expenses increased $2 million, or 2%, to $78 million. This increase includes $1 million of expenses relating to Year 2000 issues and $1 million relating to the ongoing implementation of the Company's new SAP software operating environment. Other Income and Expense Income tax expense decreased $20 million, to $34 million, due to the decline in pretax income. 19 Comparison of the nine-month periods ended September 30, 1998 and 1997 ______________________________________________________________________
% 1998 1997 Change Change ____ ____ ______ ______ (Dollars in Millions) Revenues Residential $ 598.3 $ 588.6 $ 9.7 2 Commercial 495.4 474.9 20.5 4 Industrial 542.2 537.5 4.7 1 Other 23.7 24.1 (0.4) (2) _______ _______ _______ Retail sales 1,659.6 1,625.1 34.5 2 Wholesale sales and market trading 2,158.8 893.8 1,265.0 142 Other 49.1 58.6 (9.5) (16) _______ _______ _______ Total 3,867.5 2,577.5 1,290.0 50 Operating expenses 3,432.2 1,968.9 1,463.3 74 _______ _______ _______ Income from operations 435.3 608.6 (173.3) (28) Interest expense 244.7 235.7 9.0 4 Minority interest and other (6.5) (13.4) 6.9 (51) Income taxes 74.3 144.0 (69.7) (48) _______ _______ _______ Net income 122.8 242.3 (119.5) (49) Preferred dividend requirement 14.4 18.0 (3.6) (20) _______ _______ _______ Earnings contribution $ 108.4 $ 224.3 $ (115.9) (52) ======= ======= ======= Energy sales (millions of kWh) Residential 9,385 9,294 91 1 Commercial 9,166 8,811 355 4 Industrial 15,808 15,472 336 2 Other 500 546 (46) (8) _______ ______ ______ Retail sales 34,859 34,123 736 2 Wholesale sales and market trading 79,019 37,456 41,563 111 _______ ______ ______ Total 113,878 71,579 42,299 59 ======= ====== ====== Residential average usage (kWh) 7,579 7,694 (115) (2) Total retail customers (end of period) 1,459,029 1,427,289 31,740 2
Revenues Total Domestic Electric Operations revenues increased $1.29 billion, or 50%. This increase was primarily attributable to a $1.27 billion increase in wholesale revenues. The $1.27 billion increase in wholesale revenues was driven by energy volumes that more than doubled in 1998 to a total of 79.0 million MWh. Higher short-term and spot market wholesale energy volumes increased revenues by $1.07 billion. Related energy prices averaged $26 per MWh, a 37% increase over the prior year. The higher prices for these sales added $186 million to revenues. Higher long-term prices partially offset by lower long-term volumes added $5 million to revenues. 20 Residential revenues were up $10 million. Growth in the average number of residential customers of 3% added $14 million to revenues. This increase was partially offset by volume decreases due to decreased customer usage, which lowered revenues by $4 million. Commercial revenues were up $21 million, or 4%. Energy sales volumes increased 4% over the prior year. Growth in the average number of customers of 2% added $12 million to revenues, and increased customer usage added $7 million to revenues. Industrial revenues increased $5 million, or 1%. A 2% increase in energy sales increased revenues $3 million. Mild weather and planting conditions reduced irrigation revenues by $1 million. Revenues in 1997 were reduced by billing adjustments of $3 million for certain industrial customers. Operating Expenses Total operating expenses increased $1.46 billion, or 74%. This increase was primarily attributable to increased purchased power expense to serve the expanding wholesale market and the $113 million pretax cost of the work force reduction. Purchased power expense increased $1.31 billion, to $2.1 billion. The higher expense was primarily due to a 40.8 million MWh increase in short term firm and spot market energy purchases, more than double the amount of purchases in the same period of 1997, which increased purchased power expense $1.11 billion. Short-term firm and spot market purchase prices averaged $26 per MWh in 1998 versus $17 per MWh in 1997, a 52% increase. The increase in purchase prices added $193 million to costs. Higher volumes and prices relating to long-term firm purchased power contracts added $6 million to purchased power costs. SHORT-TERM AND SPOT MARKET SALES AND PURCHASES ______________________________________________
1998 1997 ________ ________ Total sales volume (thousands of MWh) 68,690 27,334 Average sales price ($/MWh) $ 25.83 $ 18.83 ______ ______ Revenues ($, millions) $ 1,774 $ 515 Total purchase volume (thousands of MWh) 68,966 28,196 Average purchase price ($/MWh) $ 25.85 $ 16.99 ______ ______ Expenses ($, millions) $ 1,783 $ 479 ______ ______ Net ($, millions) $ (9) $ 36 ====== ======
Fuel expense was up $17 million, or 5%, to $356 million. Thermal generation increased 6% to 38.0 million MWh, resulting in a decrease of 1% in the average cost per MWh to $9.37. Hydroelectric generation decreased 7% due to less favorable water conditions. Other operations and maintenance expense decreased $15 million, or 4%, to $330 million. Pension expense decreased $13 million due to amortization cost decreases relating to deferred regulatory pension assets that were written off in December 1997 and the implementation of the early retirement plan initiated 21 in the first quarter of 1998. Steam plant maintenance expense decreased $4 million due to overhaul timing differences. Depreciation and amortization expense increased $20 million, or 7%, to $292 million. Higher depreciation rates that were implemented in the fourth quarter of 1997 added $9 million to expense and increased plant in service added $11 million. Administrative and general expenses increased $15 million, or 7%, to $241 million. This increase included $5 million of expenses relating to Year 2000 issues, $3 million relating to the Company's new SAP software operating environment and $8 million of employee related costs. Other Income and Expense Interest expense increased $9 million to $245 million as a result of higher debt balances. Income tax expense decreased $70 million due to the decline in pretax income. 22 Australian Electric Operations ______________________________ Comparison of the three-month periods ended September 30, 1998 and 1997 _______________________________________________________________________
Change Due Change % Change to Currency Due to Due to 1998 1997 Translation Operations Operations ____ ____ ___________ __________ __________ (Dollars in Millions) Powercor Earnings Contribution Revenues Powercor area $108.3 $139.0 $(24.6) $ (6.1) (4) Outside Powercor area Victoria 19.3 26.4 (4.4) (2.7) (10) New South Wales 15.8 14.4 (3.6) 5.0 35 Australia Capital Territory 0.3 - - 0.3 * _____ _____ _____ _____ 143.7 179.8 (32.6) (3.5) (2) Other 5.8 5.6 (1.3) 1.5 27 _____ _____ _____ _____ Total 149.5 185.4 (33.9) (2.0) (1) Operating expenses 126.0 147.3 (28.6) 7.3 5 _____ _____ _____ _____ Income from operations 23.5 38.1 (5.3) (9.3) (24) Interest expense 13.6 15.5 (3.1) 1.2 8 Equity in (income)/losses of Hazelwood (0.4) (0.5) 0.1 - - Other (income)/expense 0.1 (1.3) - 1.4 108 Income taxes 3.7 8.6 (0.8) (4.1) (48) _____ _____ _____ _____ Earnings contribution $ 6.5 $ 15.8 $ (1.5) $ (7.8) (49) ===== ===== ===== ===== Powercor energy sales (millions of kWh) Powercor area 1,885 1,906 (21) (1) Outside Powercor area Victoria 596 591 5 1 New South Wales 560 449 111 25 Australia Capital Territory 6 - 6 * _____ _____ _____ Total 3,047 2,946 101 3 ===== ===== ===== *Not a meaningful number.
Currency Exchange Rates The currency exchange rate for converting Australian dollars to U. S. dollars was 0.60 in the third quarter of 1998 as compared to 0.74 in 1997, a 19% decrease. The effect of this change in exchange rates lowered revenues by $34 million and costs by $32 million in the third quarter of 1998. The following discussion does not include the effects of the lower currency exchange rates in 1998. Revenue Australia's revenues decreased $2 million, or 1%. The decrease was primarily attributable to declining prices that reduced revenues by $10 million, partially offset by increased energy sales volumes of 100 million kWh, or 3%, which added $6 million to revenues. 23 Energy volumes sold to contestable customers outside Powercor's franchise area were up 121 million kWh and added $6 million to revenues due to customer gains in New South Wales and $1 million due to customer gains in Victoria. Lower prices for contestable sales reduced revenues by $4 million in 1998. Inside Powercor's franchise area, revenues declined $5 million primarily due to price decreases for contestable customers and $1 million due to decreased volumes of 21 million kWh. Operating Expenses Purchased power expense decreased $5 million, or 6%, to $63 million. Lower average prices reduced power costs by $8 million. Prices for purchased power averaged $23 per MWh in the third quarter of 1998 compared to $25 per MWh in the third quarter of 1997. The reduction resulted from competition. The decrease was offset in part by a 4% increase in purchased power volumes that added $3 million to costs. Other operating expenses increased $12 million, or 25%, to $49 million. Increased sales to contestable customers outside the Powercor service area resulted in higher network fees of $9 million. This increase was offset in part by higher network revenues of $3 million from customers inside Powercor's franchise area serviced by other energy suppliers. Maintenance decreased $2 million due to the outsourcing of various functions. Administrative and general expenses increased $8 million primarily due to a $4 million adjustment to capitalize new customer connection costs and $2 million of costs capitalized for SAP system development in the third quarter of 1997. Other Income and Expense Income tax expense decreased due to a reduction in taxable income. 24 Comparison of the nine-month periods ended September 30, 1998 and 1997 ______________________________________________________________________
Change Due Change % Change to Currency Due to Due to 1998 1997 Translation Operations Operations ____ ____ ___________ __________ __________ (Dollars in Millions) Powercor Earnings Contribution Revenues Powercor area $337.1 $417.7 $(70.0) $(10.6) (3) Outside Powercor area Victoria 60.2 75.7 (12.5) (3.0) (4) New South Wales 52.9 24.1 (11.0) 39.8 * Australia Capital Territory 0.3 - - 0.3 * _____ _____ _____ _____ 450.5 517.5 (93.5) 26.5 5 Other 18.6 29.4 (3.9) (6.9) (23) _____ _____ _____ _____ Total 469.1 546.9 (97.4) 19.6 4 Operating expenses 375.3 426.6 (78.0) 26.7 6 _____ _____ _____ _____ Income from operations 93.8 120.3 (19.4) (7.1) (6) Interest expense 43.8 49.9 (9.1) 3.0 6 Equity in losses of Hazelwood 3.9 2.0 (0.8) 2.7 135 Other (income)/expense 3.0 (1.6) (0.6) 5.2 * Income taxes 15.9 25.1 (3.3) (5.9) (24) _____ _____ _____ _____ Earnings contribution $ 27.2 $ 44.9 $ (5.6) $(12.1) (27) ===== ===== ===== ===== Powercor energy sales (millions of kWh) Powercor area 5,549 5,576 (27) - Outside Powercor area Victoria 1,786 1,632 154 9 New South Wales 1,643 765 878 115 Australia Capital Territory 6 - 6 * _____ _____ _____ Total 8,984 7,973 1,011 13 ===== ===== ===== *Not a meaningful number.
Currency Exchange Rates The currency exchange rate for converting Australian dollars to U.S. dollars was 0.63 in 1998 as compared to 0.76 in 1997, a 17% decrease. The effect of this change in exchange rates lowered revenues by $98 million and costs by $92 million. The following discussion does not include the effects of the lower currency exchange rate in 1998. Revenue Australia's revenues increased $20 million, or 4%. The increase was attributable to increased energy sales volumes of 1,011 million kWh, or 13%, which added $48 million to revenues. Declining prices reduced revenues by $21 million. Energy volumes sold to contestable customers outside Powercor's franchise area were up 1,038 million kWh and added $40 million to revenues due to customer gains in New South Wales and $7 million due to customer gains in Victoria. Lower 25 prices for these sales reduced revenues by $10 million in 1998. Inside Powercor's franchise area, revenues decreased $11 million primarily due to a decline in prices. Other revenues decreased $7 million primarily as a result of less Tariff H contract renegotiations revenue in 1998 than in 1997. Operating Expenses Purchased power expense decreased $8 million, or 3%, to $189 million. Lower average prices reduced power costs by $38 million. Prices for purchased power averaged $23 per MWh compared to $27 per MWh in 1997. The decrease, which was due to competition, was offset in part by an 13% increase in purchased power volumes that added $30 million to costs. In addition, purchased power expense increased as the result of a contractual dispute with a third party, who did not supply power as agreed, causing Powercor to pay a higher price for power. Other operating expenses increased $35 million, or 25%, to $144 million. Increased sales to contestable customers outside the Powercor service area resulted in higher network fees of $36 million. This increase was offset in part by higher network revenues of $8 million from customers inside Powercor's franchise area serviced by other energy suppliers. Maintenance decreased $2 million due to the outsourcing of various functions. Administrative and general expenses increased $8 million primarily due to a $4 million adjustment to capitalize new customer connection costs and $2 million of costs capitalized for SAP system development in the third quarter of 1997. Other Income and Expense Interest expense increased $3 million as a result of higher debt balances, partially offset by declining interest rates. Other expense increased $5 million primarily due to a reserve relating to a product recall. Powercor is in the process of negotiating recovery from the manufacturer. Equity losses in Hazelwood increased $3 million over 1997 primarily due to a planned outage and increased maintenance costs for one of the power station units during April and May of 1998. Income taxes decreased $6 million primarily due to a decrease in taxable income. 26 Discontinued Operations _______________________ Comparison of the three-month periods ended September 30, 1998 and 1997 _______________________________________________________________________
% 1998 1997 Change Change ____ ____ ______ ______ Unregulated Energy Trading __________________________ Revenues $1,424.7 $802.1 $ 622.6 78 Cost of sales 1,421.6 792.1 629.5 79 _______ _____ ______ Gross margin 3.1 10.0 (6.9) (69) Depreciation and amortization 1.5 3.9 (2.4) (62) Administrative and other 5.4 5.0 0.4 8 _______ _____ ______ Loss from operations (3.8) 1.1 (4.9) * Interest expense 1.3 0.6 0.7 117 Other expense/(income) - net 177.3 (1.3) 178.6 * Income tax expense/(benefit) (60.2) 1.2 (61.4) * _______ _____ ______ Earnings contribution (loss) $ (122.2) $ 0.6 $(122.8) * _______ _____ ______ Telecommunications __________________ Revenues $ - $154.0 $(154.0) (100) Operating expenses - 102.9 (102.9) (100) _______ _____ ______ Income from operations - 51.1 (51.1) (100) Interest expense - 10.2 (10.2) (100) Other income - net - (2.8) 2.8 100 Income taxes - 16.6 (16.6) (100) _______ _____ ______ Earnings contribution $ - $ 27.1 $ (27.1) (100) _______ _____ ______ Total discontinued operations Earnings contribution (loss) $ (122.2) $ 27.7 $(149.9) * ======= ===== ====== *Not a meaningful number.
Unregulated Energy Trading __________________________ Unregulated energy trading gross margin declined $7 million primarily as a result of the sale of TPC's gas gathering and processing assets in December 1997. Other Income and Expense Other expense increased $179 million primarily due to a $178 million loss taken to exit the unregulated energy trading business. Income tax expense decreased $61 million due to the reduction in taxable income. Telecommunications __________________ Earnings contribution from telecommunications declined due to the sale of PTI in December 1997. 27 Comparison of the nine-month periods ended September 30, 1998 and 1997 ______________________________________________________________________
% 1998 1997 Change Change ____ ____ ______ ______ Unregulated Energy Trading __________________________ Revenues $2,961.4 $1,062.5 $1,898.9 * Cost of sales 3,008.2 1,044.3 1,963.9 * _______ _______ _______ Gross margin (46.8) 18.2 (65.0) * Depreciation and amortization 4.5 7.8 (3.3) (42) Administrative and other 14.8 12.6 2.2 17 _______ _______ _______ Loss from operations (66.1) (2.2) (63.9) * Interest expense 2.1 2.4 (0.3) (13) Other expense/(income) - net 176.0 (2.2) 178.2 * Income tax expense/(benefit) (83.4) (0.1) (83.3) * _______ _______ _______ Earnings contribution (loss) $ (160.8) $ (2.3) $ (158.5) * _______ _______ _______ Telecommunications __________________ Revenues $ - $ 416.2 $ (416.2) (100) Operating expenses - 283.0 (283.0) (100) _______ _______ _______ Income from operations - 133.2 (133.2) (100) Interest expense - 30.4 (30.4) (100) Other income - net - (3.5) 3.5 100 Income taxes - 41.8 (41.8) (100) _______ _______ _______ Earnings contribution $ - $ 64.5 $ (64.5) (100) _______ _______ _______ Total discontinued operations Earnings contribution (loss) $ (160.8) $ 62.2 $ (223.0) * ======= ======= ======= *Not a meaningful number.
Unregulated Energy Trading __________________________ Unregulated energy trading gross margin declined $65 million. In the second quarter of 1998, a credit reserve of $32 million pretax was recorded as a result of a default by a supplier of power on a commitment to deliver power and an additional $10 million pretax charge was recorded for known and probable future trading losses. In addition, gross margin decreased $19 million as a result of the sale of the Company's gas gathering and processing assets in December 1997. Other Income and Expense Other expense increased $178 million primarily due to a $178 million loss taken to exit the unregulated energy trading business. Income tax expense decreased $83 million due to the reduction in taxable income. Telecommunications __________________ Earnings contribution from telecommunications declined due to the sale of PTI in December 1997. 28 Other Operations ________________ Comparison of the three-month periods ended September 30, 1998 and 1997 _______________________________________________________________________
% 1998 1997 Change Change ____ ____ ______ ______ (Dollars in Millions) Earnings contribution (loss) PFS $ (1.0) $ 5.3 $ (6.3) (119) PGC - 3.0 (3.0) (100) Holdings and other (25.6) (71.1) 45.5 64 _____ _____ _____ Total $(26.6) $(62.8) $ 36.2 58 ===== ===== =====
Other operations reported losses of $27 million in the quarter compared to a loss of $63 million in the same period a year ago. Losses relating to the decision to exit the unregulated energy development businesses totaled $32 million, or $0.11 per share. Third quarter 1997 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. Results from other operations were benefited by a $14 million after tax increase in interest income and reduced interest expense as the result of cash received from asset sales in 1997. Earnings from PFS were down $6 million primarily due to the sale of affordable housing properties. In addition, the other unregulated energy development businesses incurred $7 million of after tax losses, or $0.02 per share, compared to a loss of $2 million, or $0.01 per share, in the third quarter of 1997. 29 Comparison of the nine-month periods ended September 30, 1998 and 1997 ______________________________________________________________________
% 1998 1997 Change Change ____ ____ ______ ______ (Dollars in Millions) Earnings contribution (loss) PFS $ 6.5 $ 14.8 $ (8.3) (56) PGC - 7.0 (7.0) (100) Holdings and other (57.6) (81.4) 23.8 29 _____ _____ _____ Total $(51.1) $(59.6) $ 8.5 14 ===== ===== =====
Other operations reported losses of $51 million in 1998 compared to a loss of $60 million in the same period a year ago. Losses relating to the decision to exit the unregulated energy development businesses totaled $32 million, or $0.11 per share, and losses relating to the costs associated with the Company's terminated bid for TEG totaled $54 million, or $0.18 per share. Third quarter 1997 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. On March 2, 1998, a subsidiary of Holdings purchased approximately 46 million TEG shares at a price of 820 pence per share, or $625 million, utilizing a portion of the cash proceeds from asset sales. On June 2, 1998, the subsidiary sold the shares and recorded an after-tax gain of $10 million. Results from other operations were benefited by a $37 million after tax increase in interest income and reduced interest expense as the result of cash received from asset sales in 1997. During May 1998, PFS received approximately $80 million in cash proceeds for the sale of a majority of its real estate assets. Earnings from PFS were down $8 million primarily due to the sale of affordable housing properties. In addition, the other unregulated energy development businesses incurred $18 million of after tax losses, or $0.06 per share, compared to a loss of $4 million, or $0.01 per share, in 1997. 30 FINANCIAL CONDITION - For the nine months ended September 30, 1998: OPERATING ACTIVITIES Net cash flows provided by continuing operations were $659 million during the period compared to $591 million in the first nine months of 1997. The $68 million increase in operating cash flows was primarily attributable to decreased working capital requirements. Net cash used in discontinued operations represents payment of income taxes of $304 million associated with a $671 million pretax gain recorded in December 1997 on the sale of PTI and cash flows of $86 million related to unregulated energy trading. INVESTING ACTIVITIES Capital spending totaled $429 million in 1998 compared with $441 million in 1997. Disposition of Assets On October 23, 1998, the Company announced its intent to exit its unregulated energy trading business and its other unregulated energy development businesses. As a result, the Company recorded a $151 million loss for these businesses. Management of the eight investor and publicly-owned utility partners who own the 1,340 megawatt coal-fired Centralia Power Project in Washington have hired an investment advisor to pursue the possible sale of the plant and the adjacent Centralia Mine. The sale of the plant is being considered by the owners, in part, because of emerging deregulation and competition in the electricity industry. The Company operates the plant and owns a 47.5 percent share. The Company owns and operates the adjacent Centralia Mine. The Company is investigating the effect of a potential sale on the reclamation costs for the Centralia Mine. The 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 certain reclamation studies at the mine and the regulatory treatment of these costs. On July 9, 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 changes in the legislative and regulatory environments, including fixing prices, in these states where the Company has few distribution properties. 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 September 16, 1998, the Company entered into a Letter of Agreement with Flathead Electric Cooperative for the Montana distribution assets. On November 5, 1998, the Company closed the sale and received after-tax proceeds of $92 million. The Company will return $4 million of the $8 million gain to Montana customers as negotiated with the MPSC and the Montana Consumer Counsel. 31 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 related 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. 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. The last offer was valued at $11.1 billion, including the assumption of $4.1 billion of TEG's debt. In February 1998, Texas Utilities Company also made a tender offer at a higher price. 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 to first quarter 1998 earnings, included in "Other expense-net," 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 loss of $3 million in April 1998 in connection with closing its foreign currency option contract associated with the bid for TEG. Total pretax costs incurred in 1997 and 1998 were $199 million. 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 when they were sold on June 2, 1998. CAPITALIZATION At September 30, 1998, the Company had approximately $445 million of commercial paper outstanding at a weighted average rate of 5.6%. These borrowings are supported by $700 million of revolving credit agreements. At September 30, 1998, the consolidated subsidiaries had access to $825 million of short-term funds through committed bank revolving credit agreements. Subsidiaries had $413 million outstanding under bank revolving credit facilities. At September 30, 1998, the Companies had $531 million of short- term debt classified as long-term debt as they have the intent and ability to support short-term borrowings through the various revolving credit facilities on a long-term basis. The Company and its subsidiaries have intercompany borrowing arrangements providing for temporary loans of funds between parties at short-term market rates. At September 30, 1998, Holdings had loaned $651 million to PacifiCorp. 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, Australian Electric Operations entered into a series of currency exchange agreements in the same amount and for the same duration as the underlying United 32 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. 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. The Company's plan is to have successfully identified, corrected and tested its existing critical systems by July 1, 1999. All new hardware or software must be certified Year 2000 ready before it is installed. A summary of the Company's progress to date in areas affected by Year 2000 issues is set forth in the following table:
Remediation Inventory Assessment and Testing _________ __________ ___________ (% Completed) Electric Systems 98 65 23 Computer Systems Central Applications to Correct 100 100 42 Central Applications to Replace 100 100 65 Desktop 100 100 20
The Company's ability to maintain normal operations into the year 2000 will be affected by Year 2000 readiness of third parties from whom the Company purchases products and services or with whom the Company exchanges information. At October 30, 1998, the Company had identified 100% of its critical third-party relationships and assessed the Year 2000 readiness of 75% of these parties. Assessment of the readiness of the remaining critical third parties is estimated to be completed by the end of November 1998. 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 33 in the western United States. These agencies require Year 2000 readiness for all interconnected electric utilities by July 1, 1999. In compliance with NERC guidelines, the Company is in the process of developing Year 2000 contingency plans. The first draft of these plans is due by the end of 1998. The Company has incurred $8.9 million in costs relating to the Year 2000 project through September 30, 1998. Estimates of the total cost of the Year 2000 project are approximately $30 million. 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. 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. ______________________________________________________________________________ The condensed consolidated financial statements as of September 30, 1998 and December 31, 1997 and for the three-and nine-month periods ended September 30, 1998 and 1997 have been reviewed by Deloitte & Touche LLP, independent accountants, in accordance with standards established by the American Institute of Certified Public Accountants. A copy of their report is included herein. 34 Deloitte & Touche LLP _____________________ _____________________________________________________ Suite 3900 Telephone:(503)222-1341 111 S.W. Fifth Avenue Facsimile:(503)224-2172 Portland, Oregon 97204-3698 INDEPENDENT ACCOUNTANTS' REPORT PacifiCorp: We have reviewed the accompanying condensed consolidated balance sheet of PacifiCorp and subsidiaries as of September 30, 1998, and the related condensed consolidated statements of income and retained earnings for the three- and nine-month periods ended September 30, 1998 and 1997 and of cash flows for the nine-month periods ended September 30, 1998 and 1997. These financial statements are the responsibility of the Company's management. We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures to financial data and of making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with generally accepted auditing standards, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion. Based on our review, we are not aware of any material modifications that should be made to such condensed consolidated financial statements for them to be in conformity with generally accepted accounting principles. We have previously audited, in accordance with generally accepted auditing standards, the consolidated balance sheet of PacifiCorp and subsidiaries as of December 31, 1997, and the related consolidated statements of income and retained earnings and of cash flows for the year then ended (not presented herein); and in our report dated February 3, 1998 (March 2, 1998 as to Note 2), we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 1997 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived. DELOITTE & TOUCHE LLP October 22, 1998 35 PART II. OTHER INFORMATION Item 1. Legal Proceedings ______ _________________ The Company has settled the Utah Associated Municipal Power Systems _______________________________________ v. PacifiCorp case (see "Item 3. Legal Proceedings" at page 25 of _____________ the Company's Annual Report on Form 10-K for the year ended December 31, 1997). Item 6. Exhibits and Reports on Form 8-K ______ ________________________________ (a) Exhibits. Exhibit 12(a): Statements of Computation of Ratio of Earnings to Fixed Charges. Exhibit 12(b): Statements of Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends. Exhibit 15: Letter re unaudited interim financial information of awareness of incorporation by reference. Exhibit 27: Financial Data Schedule for the quarter ended September 30, 1998, restated Financial Data Schedules for June 30, 1998, March 31, 1998, all quarters ended in 1997 and 1996 and for the quarter ended December 31, 1995 (filed electronically only). (b) Reports on Form 8-K. On Form 8-K, dated August 26, 1998, under Item 5. "Other Events," the Company filed a news release reporting the appointment of Keith McKennon as Chief Executive Officer. On Form 8-K, dated September 16, 1998, under Item 5. "Other Events," the Company filed a news release concerning the expected earnings shortfall for the third quarter of 1998. On Form 8-K, dated October 23, 1998, under Item 5. "Other Events," the Company filed news releases concerning the Company's third quarter earnings and the Company's strategic plan. 36 SIGNATURE Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. PACIFICORP Date November 12, 1998 By ROBERT R. DALLEY ___________________________ ___________________________________ Robert R. Dalley Controller (Chief Accounting Officer) INDEX TO EXHIBITS
EXHIBIT DESCRIPTION PAGE _______ ___________ ____ Exhibit 12(a): Statements of Computation of Ratio of Earnings to Fixed Charges. Exhibit 12(b): Statements of Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends. Exhibit 15: Letter re unaudited interim financial information of awareness of incorporation by reference. Exhibit 27: Financial Data Schedule for the quarter ended September 30, 1998, restated Financial Data Schedules for June 30, 1998, March 31, 1998, all quarters ended in 1997 and 1996 and for the quarter ended December 31, 1995 (filed electronically only).
EX-12 2 EXHIBIT (12)(a) PACIFICORP STATEMENTS OF COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
Nine Months ______________________________________________ Ended 1993 1994 1995 1996 1997 Sept. 30, 1998 ____ ____ ____ ____ ____ ______________ (In Millions of Dollars) Fixed Charges, as defined:* Interest expense..................... $ 333.5 $ 302.0 $ 336.4 $ 415.0 $ 438.1 $280.9 Estimated interest portion of rentals charged to expense......... 4.8 5.6 4.5 4.1 6.6 7.0 Preferred dividends of wholly owned subsidiary............ - - - 15.3 32.9 30.1 _______ _______ _______ _______ _______ _____ Total fixed charges.............. $ 338.3 $ 307.6 $ 340.9 $ 434.4 $ 477.6 $318.0 ======= ======= ======= ======= ======= ===== Earnings, as defined:* Income from continuing operations.... $ 371.8 $ 397.5 $ 402.4 $ 430.3 $ 232.8 $141.3 Add (deduct): Provision for income taxes......... 163.6 209.0 192.1 236.5 111.8 42.3 Minority interest.................. 2.7 1.3 1.4 1.8 1.9 (0.8) Undistributed income of less than 50% owned affiliates........ (16.2) (14.7) (15.0) (18.2) (11.1) 8.7 Fixed charges as above............. 338.3 307.6 340.9 434.4 477.6 318.0 _______ _______ _______ _______ _______ _____ Total earnings................... $ 860.2 $ 900.7 $ 921.8 $1,084.8 $ 813.0 $509.5 ======= ======= ======= ======= ======= ===== Ratio of Earnings to Fixed Charges..... 2.5x 2.9x 2.7x 2.5x 1.7x 1.6x ==== ==== ==== ==== ==== ==== *"Fixed charges" represent consolidated interest charges, an estimated amount representing the interest factor in rents and preferred dividend requirements of majority-owned subsidiaries. "Earnings" represent the aggregate of (a) income from continuing operations, (b) taxes based on income from continuing operations, (c) minority interest in the income of majority-owned subsidiaries that have fixed charges, (d) fixed charges and (e) undistributed income of less than 50% owned affiliates without loan guarantees.
EX-12 3 EXHIBIT (12)(b) PACIFICORP STATEMENTS OF COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS
Nine Months ______________________________________________ Ended 1993 1994 1995 1996 1997 Sept. 30, 1998 ____ ____ ____ ____ ____ ______________ (In Millions of Dollars) Fixed Charges, as defined:* Interest expense..................... $ 333.5 $ 302.0 $ 336.4 $ 415.0 $ 438.1 $280.9 Estimated interest portion of rentals charged to expense...... 4.8 5.6 4.5 4.1 6.6 7.0 Preferred dividends of wholly owned subsidiary............ - - - 15.3 32.9 30.1 _______ _______ _______ _______ _______ _____ Total fixed charges.............. $ 338.3 $ 307.6 $ 340.9 $ 434.4 $ 477.6 $318.0 Preferred Stock Dividends, as defined:*....................... 56.8 60.8 57.2 46.2 33.8 20.6 _______ _______ _______ _______ _______ _____ Total fixed charges and preferred dividends............ $ 395.1 $ 368.4 $ 398.1 $ 480.6 $ 511.4 $338.6 ======= ======= ======= ======= ======= ===== Earnings, as defined:* Income from continuing operations.... $ 371.8 $ 397.5 $ 402.4 $ 430.3 $ 232.8 $141.3 Add (deduct): Provision for income taxes......... 163.6 209.0 192.1 236.5 111.8 42.3 Minority interest.................. 2.7 1.3 1.4 1.8 1.9 (0.8) Undistributed income of less than 50% owned affiliates............. (16.2) (14.7) (15.0) (18.2) (11.1) 8.7 Fixed charges as above............. 338.3 307.6 340.9 434.4 477.6 318.0 _______ _______ _______ _______ _______ _____ Total earnings................... $ 860.2 $ 900.7 $ 921.8 $1,084.8 $ 813.0 $509.5 ======= ======= ======= ======= ======= ===== Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends.. 2.2x 2.4x 2.3x 2.3x 1.6x 1.5x ==== ==== ==== ==== ==== ==== *"Fixed charges" represent consolidated interest charges, an estimated amount representing the interest factor in rents and preferred dividend requirements of majority-owned subsidiaries. "Preferred Stock Dividends" represent preferred dividend requirements multiplied by the ratio which pre-tax income from continuing operations bears to income from continuing operations. "Earnings" represent the aggregate of (a) income from continuing operations, (b) taxes based on income from continuing operations, (c) minority interest in the income of majority-owned subsidiaries that have fixed charges, (d) fixed charges and (e) undistributed income of less than 50% owned affiliates without loan guarantees.
EX-15 4 Deloitte & Touche LLP ___________ _____________________________________________________ Suite 3900 Telephone:(503)222-1341 111 S.W. Fifth Avenue Facsimile:(503)224-2172 Portland, Oregon 97204-3642 EXHIBIT 15 November 12, 1998 PacifiCorp 700 N.E. Multnomah Portland, Oregon We have made a review, in accordance with standards established by the American Institute of Certified Public Accountants, of the unaudited interim financial information of PacifiCorp and subsidiaries for the periods ended September 30, 1998 and 1997, as indicated in our report dated October 22, 1998; because we did not perform an audit, we expressed no opinion on that information. We are aware that our report referred to above, which is included in your Quarterly Report on Form 10-Q for the quarter ended September 30, 1998, is incorporated by reference in Registration Statement Nos. 33-51277, 33-54169, 33-57043, 33-58461, 333-10885, and 333-45851, all on Form S-8; Registration Statement No. 33-36239 on Form S-4; and Registration Statement Nos. 33-62095 and 333-09115 on Form S-3. We also are aware that the aforementioned report, pursuant to Rule 436(c) under the Securities Act of 1933, is not considered a part of the Registration Statement prepared or certified by an accountant or a report prepared or certified by an accountant within the meaning of Sections 7 and 11 of that Act. DELOITTE & TOUCHE LLP EX-27 5 EXHIBIT 27
UT THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM PACIFICORP'S FORM 10-Q DATED SEPTEMBER 30, 1998 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 0000075594 PACIFICORP 1,000 9-MOS DEC-31-1998 JAN-01-1998 SEP-30-1998 PER-BOOK 7886100 1626700 1978800 272600 1434400 13198600 3212800 0 790900 4003700 175000 66400 4331400 7600 0 326000 298000 0 22900 1000 3966600 13198600 4380600 42300 3855700 3898000 482600 (102900) 379700 280800 (61900) 14400 (76300) 247200 222700 268400 (0.26) (0.26) CURRENT ASSETS INCLUDE NET ASSETS OF DISCONTINUED OPERATIONS OF $120,000. NET INCOME AND EARNINGS AVAILABLE FOR COMMON INCLUDE LOSS FROM DISCONTINUED OPERATIONS OF $160,800. EPS INCLUDES LOSS PER COMMON SHARE FROM DISCONTINUED OPERATIONS OF $0.54. EX-27.(B) 6 EXHIBIT 27 (B)
UT THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM PACIFICORP'S FORM 10-Q DATED JUNE 30, 1998 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 0000075594 PACIFICORP 1,000 6-MOS DEC-31-1998 JAN-01-1998 JUN-30-1998 PER-BOOK 7855000 1672900 1761400 301900 1441700 13032900 3211100 0 962800 4173900 175000 66400 4412600 16900 0 206900 312800 0 23300 1000 3644100 13032900 2462400 22800 2127900 2150700 311700 (59100) 252600 188300 25700 9600 16100 160200 222200 34700 0.05 0.05 CURRENT ASSETS INCLUDE NET ASSETS OF DISCONTINUED OPERATIONS OF $205,100. NET INCOME AND EARNINGS AVAILABLE FOR COMMON INCLUDE LOSS FROM DISCONTINUED OPERATIONS OF $38,600. EPS INCLUDES LOSS PER COMMON SHARE FROM DISCONTINUED OPERATIONS OF $0.13. EX-27.(C) 7 EXHIBIT 27 (C)
UT THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM PACIFICORP'S FORM 10-K DATED DECEMBER 31, 1997 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 0000075594 PACIFICORP 1,000 3-MOS DEC-31-1998 JAN-01-1998 MAR-31-1998 PER-BOOK 7814100 1803600 2180200 291600 1407600 13497100 3242900 0 1006600 4249500 175000 66400 4400200 7100 0 290800 426300 0 23400 900 3857500 13497100 1260100 (15400) 1119900 1104500 155600 (75900) 79700 94300 (15100) 4800 (19900) 80300 219400 (79600) (0.07) (0.07) CURRENT ASSETS INCLUDE NET ASSETS OF DISCONTINUED OPERATIONS OF $214,600. NET INCOME AND EARNINGS AVAILABLE FOR COMMON INCLUDE LOSS FROM DISCONTINUED OPERATIONS OF $500. EX-27.(D) 8 EXHIBIT 27 (D)
UT THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM PACIFICORP'S FORM 10-K DATED DECEMBER 31, 1997 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 0000075594 PACIFICORP 1,000 12-MOS DEC-31-1997 JAN-01-1997 DEC-31-1997 PER-BOOK 7825500 1786400 2197300 385700 1432100 13627000 3214600 0 1106300 4320900 175000 66400 4389200 6300 0 182900 364500 0 23800 900 4097100 13627000 4548900 111800 3738300 3850100 698800 (28200) 670600 437800 663700 22800 640900 320000 217500 618600 2.16 2.16 CURRENT ASSETS INCLUDE NET ASSETS OF DISCONTINUED OPERATIONS OF $223,400. NET INCOME AND EARNINGS AVAILABLE FOR COMMON INCLUDE INCOME FROM DISCONTINUED OPERATIONS OF $81,800, GAIN ON SALE OF DISCONTINUED OPERATIONS OF $365,100 AND EXTRAORDINARY LOSS FROM REGULATORY ASSET IMPAIRMENT OF $16,000. EPS INCLUDES EARNINGS PER COMMON SHARE FROM DISCONTINUED OPERATIONS OF $0.28, GAIN ON SALE OF DISCONTINUED OPERATIONS OF $1.23 AND EXTRAORDINARY LOSS FROM REGULATORY ASSET IMPAIRMENT OF $0.05.
EX-27.(E) 9 EXHIBIT 27(E)
UT THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM PACIFICORP'S FORM 10-Q DATED SEPTEMBER 30, 1997 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 0000075594 PACIFICORP 1,000 9-MOS DEC-31-1997 JAN-01-1997 SEP-30-1997 PER-BOOK 7894600 2064600 2086800 320500 1914800 14281300 3244200 0 816100 4060300 175000 66400 4834200 148300 0 559100 626800 0 23900 900 3786400 14281300 3208600 112600 2443500 2556100 652500 (94900) 557600 330000 289800 18000 271800 239300 213800 204500 .92 .92 CURRENT ASSETS INCLUDE NET ASSETS OF DISCONTINUED OPERATIONS OF $1,184,600. NET INCOME AND EARNINGS AVAILABLE FOR COMMON INCLUDE INCOME FROM DISCONTINUED OPERATIONS OF $62,200. EPS INCLUDES EARNINGS PER COMMON SHARE FROM DISCONTINUED OPERATIONS OF $0.21.
EX-27.(F) 10 EXHIBIT 27(F)
UT THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM PACIFICORP'S FORM 10-Q DATED JUNE 30, 1997 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 0000075594 PACIFICORP 1,000 6-MOS DEC-31-1997 JAN-01-1997 JUN-30-1997 PER-BOOK 7865600 2108000 2047400 288000 1922300 14231300 3241200 0 827700 4068900 175000 135500 5335200 166900 0 432200 271700 0 24300 900 3620700 14231300 2000900 98100 1514900 1613000 387900 10600 398500 217100 215800 12200 203600 159400 213100 200 .69 .69 CURRENT ASSETS INCLUDE NET ASSETS OF DISCONTINUED OPERATIONS OF $1,208,700. NET INCOME AND EARNINGS AVAILABLE FOR COMMON INCLUDE INCOME FROM DISCONTINUED OPERATIONS OF $34,400. EPS INCLUDES EARNINGS PER COMMON SHARE FROM DISCONTINUED OPERATIONS OF $0.12.
EX-27.(G) 11 EXHIBIT 27(G)
UT THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM PACIFICORP'S FORM 10-Q DATED MARCH 31, 1997 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 0000075594 PACIFICORP 1,000 3-MOS DEC-31-1997 JAN-01-1997 MAR-31-1997 PER-BOOK 7832500 2165300 1554900 231900 1910700 13695300 3257000 0 818400 4075400 175000 135500 4713600 32800 0 675500 246800 0 24300 900 3615500 13695300 1002800 56700 740000 796700 206100 3600 209700 106000 121000 6100 114900 79600 215700 260800 .39 .39 CURRENT ASSETS INCLUDE NET ASSETS OF DISCONTINUED OPERATIONS OF $788,200. NET INCOME AND EARNINGS AVAILABLE FOR COMMON INCLUDE INCOME FROM DISCONTINUED OPERATIONS OF $17,300. EPS INCLUDES EARNINGS PER COMMON SHARE FROM DISCONTINUED OPERATIONS OF $0.06.
EX-27.(H) 12 EXHIBIT 27(H)
UT THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM PACIFICORPS FORM 10-K ANNUAL REPORT AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS 0000075594 PACIFICORP 1,000 12-MOS DEC-31-1996 JAN-01-1996 DEC-31-1996 PER-BOOK 7825100 2176300 1660900 233100 1913500 13808900 3249500 0 782800 4032300 178000 135500 4804700 89200 0 594300 218900 0 24700 900 3730400 13808900 3792000 236500 2705800 2942300 849700 (4400) 845300 415000 504900 29800 475100 315000 218000 925400 1.62 1.62 CURRENT ASSETS INCLUDE NET ASSETS OF DISCONTINUED OPERATIONS OF $782,900. NET INCOME AND EARNINGS AVAILABLE FOR COMMON INCLUDE INCOME FROM DISCONTINUED OPERATIONS OF $74,600. EPS INCLUDES EARNINGS PER COMMON SHARE FROM DISCONTINUED OPERATIONS OF $0.26.
EX-27.(I) 13 EXHIBIT 27(I)
UT THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM PACIFICORP'S FORM 10-Q DATED SEPTEMBER 30, 1996 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 0000075594 PACIFICORP 1,000 9-MOS DEC-31-1996 JAN-01-1996 SEP-30-1996 PER-BOOK 7785500 2155700 1579500 268500 1976500 13765700 3223400 0 735200 3958600 178000 135500 4715600 142800 0 587700 206300 0 24900 1300 3815000 13765700 2748200 174200 1955400 2129600 618600 8300 626900 308800 372000 24300 347700 235500 218100 745700 1.19 1.19 CURRENT ASSETS INCLUDE NET ASSETS OF DISCONTINUED OPERATIONS OF $774,800. NET INCOME AND EARNINGS AVAILABLE FOR COMMON INCLUDE INCOME FROM DISCONTINUED OPERATIONS OF $53,900. EPS INCLUDES EARNINGS PER COMMON SHARE FROM DISCONTINUED OPERATIONS OF $0.19.
EX-27.(J) 14 EXHIBIT 27(J)
UT THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM PACIFICORP'S FORM 10-Q DATED JUNE 30, 1996 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 0000075594 PACIFICORP 1,000 6-MOS DEC-31-1996 JAN-01-1996 JUN-30-1996 PER-BOOK 7606000 1964700 1574600 257300 1949900 13352500 3207000 0 685000 3892000 311500 219000 4644300 30900 0 325800 266700 0 25300 700 3636300 13352500 1739600 104900 1241400 1346300 393300 9700 403000 205900 229100 18000 211100 156000 216700 488200 .73 .73 CURRENT ASSETS INCLUDE NET ASSETS OF DISCONTINUED OPERATIONS OF $766,200. NET INCOME AND EARNINGS AVAILABLE FOR COMMON INCLUDE INCOME FROM DISCONTINUED OPERATIONS OF $32,000. EPS INCLUDES EARNINGS PER COMMON SHARE FROM DISCONTINUED OPERATIONS OF $0.11.
EX-27.(K) 15 EXHIBIT 27(K)
UT THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM PACIFICORP'S MARCH 31, 1996 FORM 10-Q AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS 0000075594 PACIFICORP 1,000 3-MOS DEC-31-1996 JAN-01-1996 MAR-31-1996 PER-BOOK 7582300 1964200 1496000 274400 1928300 13245200 3186600 0 674200 3860800 311500 219000 4436500 109800 0 582300 228900 0 25400 1400 3469600 13245200 883500 65400 604700 670100 213400 9300 222700 107500 129900 9000 120900 76700 214800 327100 .42 .42 CURRENT ASSETS INCLUDE NET ASSETS OF DISCONTINUED OPERATIONS OF $761,000. NET INCOME AND EARNINGS AVAILABLE FOR COMMON INCLUDE INCOME FROM DISCONTINUED OPERATIONS OF $14,700. EPS INCLUDES EARNINGS PER COMMON SHARE FROM DISCONTINUED OPERATIONS OF $0.05.
EX-27.(L) 16 EXHIBIT 27(L)
UT THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM PACIFICORP'S DECEMBER 31, 1995 ANNUAL REPORT FORM 10-K AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS 0000075594 PACIFICORP 1,000 12-MOS DEC-31-1995 JAN-01-1995 DEC-31-1995 PER-BOOK 7580200 1874000 1505200 282900 1924600 13166900 3000700 0 632400 3633100 311500 219000 4482900 277000 0 654100 199100 0 25800 1500 3362900 13166900 2814900 192100 1923700 2115800 699100 39700 738800 336400 505000 38700 466300 307100 212800 675200 1.64 1.64 CURRENT ASSETS INCLUDE NET ASSETS OF DISCONTINUED OPERATIONS OF $758,000. NET INCOME AND EARNINGS AVAILABLE FOR COMMON INCLUDE INCOME FROM DISCONTINUED OPERATIONS OF $102,600. EPS INCLUDES EARNINGS PER COMMON SHARE FROM DISCONTINUED OPERATIONS OF $0.36.
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