EX-13 2 ex1310qt10k01.txt 10K MARCH 31, 2001 EXHIBIT 13 UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-QT / / QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 OR /X/ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from January 1, 1999 to March 31, 1999 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.) 825 N.E. Multnomah Suite 2000 Portland, Oregon 97232 (Address of principal executive offices) (Zip code) 503-813-5000 (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 November 29, 1999, there were 297,324,604 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 12 PART II. OTHER INFORMATION Item 6. Exhibits and Reports on Form 8-K 25 Signature 26
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 March 31, ____________________ 1999 1998 ____ ____ REVENUES $ 959.8 $1,260.2 _______ _______ EXPENSES Purchased power 268.7 516.5 Other operations and maintenance 259.8 272.7 Administrative and general 64.3 74.9 Depreciation and amortization 113.2 115.2 Taxes, other than income taxes 26.3 27.6 Special charges - 113.1 _______ _______ TOTAL 732.3 1,120.0 _______ _______ INCOME FROM OPERATIONS 227.5 140.2 _______ _______ INTEREST EXPENSE AND OTHER Interest expense 88.0 94.3 Interest capitalized (3.4) (3.3) TEG costs - 86.3 Other income - net (6.3) (7.0) _______ _______ TOTAL 78.3 170.3 _______ _______ Income (loss) from continuing operations before income taxes 149.2 (30.1) Income tax expense/(benefit) 57.9 (15.5) _______ _______ Income (loss) from continuing operations 91.3 (14.6) Discontinued Operations (less applicable income tax expense: 1998/$0.3 - (0.5) _______ _______ NET INCOME (LOSS) 91.3 (15.1) RETAINED EARNINGS BEGINNING OF PERIOD 732.0 1,106.3 Cash dividends declared Preferred stock (4.2) (4.3) Common stock per share of $0.27 (80.3) (80.3) _______ _______ RETAINED EARNINGS END OF PERIOD $ 738.8 $1,006.6 ======= ======= EARNINGS (LOSS) ON COMMON STOCK $ 86.5 $ (19.9) Average number of common shares outstanding - Basic and dilutive (Thousands) 297,334 297,059 EARNINGS (LOSS) PER COMMON SHARE - Basic and dilutive Continuing operations $ 0.29 $ (0.07) Discontinued operations - - _______ ________ TOTAL $ 0.29 $ (0.07) ======= ======== See accompanying Notes to Condensed Consolidated Financial Statements
3 PACIFICORP CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Millions of Dollars) (Unaudited)
Three Months Ended March 31, ____________________ 1999 1998 ____ ____ CASH FLOWS FROM OPERATING ACTIVITIES Net income (loss) $ 91.3 $ (15.1) Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities Loss on discontinued operations - 0.5 Depreciation and amortization 115.1 118.6 Deferred income taxes and investment tax credits - net 27.5 (40.6) Special charges - 113.1 Gain on sale of assets (8.6) (3.6) Other (10.2) 27.6 Accounts receivable and prepayments 169.9 37.7 Materials, supplies and fuel stock (4.3) (2.3) Accounts payable and accrued liabilities (107.0) (19.9) ______ ______ Net cash provided by continuing operations 273.7 216.0 Net cash provided by (used in) discontinued operations 26.1 (295.6) ______ ______ NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES 299.8 (79.6) ______ ______ CASH FLOWS FROM INVESTING ACTIVITIES Construction (116.4) (110.5) Investments in and advances to affiliated companies - net (0.5) (21.0) Assets and operating companies acquired (0.2) (6.9) Proceeds from asset sales 14.2 - Proceeds from sales of finance assets and principal payments 36.2 46.2 Investment in shares of The Energy Group PLC - (625.5) Other 10.9 6.2 ______ ______ NET CASH USED IN INVESTING ACTIVITIES (55.8) (711.5) ______ ______ CASH FLOWS FROM FINANCING ACTIVITIES Changes in short-term debt (180.4) 108.7 Proceeds from long-term debt 400.8 417.5 Proceeds from issuance of common stock - 7.9 Dividends paid (84.5) (84.1) Repayments of long-term debt (548.5) (369.2) Other 1.7 20.0 ______ ______ NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES (410.9) 100.8 ______ ______ DECREASE IN CASH AND CASH EQUIVALENTS (166.9) (690.3) CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 583.1 740.8 ______ ______ CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 416.2 $ 50.5 ====== ====== SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION Cash paid during the period for Interest (net of amount capitalized) $ 116.3 $ 135.7 Income taxes (refunds)/paid (2.4) 367.3 See accompanying Notes to Condensed Consolidated Financial Statements
4 PACIFICORP CONDENSED CONSOLIDATED BALANCE SHEETS (Millions of Dollars) (Unaudited) ASSETS
March 31, December 31, 1999 1998 _________ _____________ CURRENT ASSETS Cash and cash equivalents $ 416.2 $ 583.1 Accounts receivable less allowance for doubtful accounts: 1999/$17.9 and 1998/$18.0 522.6 703.2 Materials, supplies and fuel stock at average cost 180.4 175.8 Net assets of discontinued operations and assets held for sale 192.4 192.4 Other 69.2 87.9 ________ ________ TOTAL CURRENT ASSETS 1,380.8 1,742.4 PROPERTY, PLANT AND EQUIPMENT Domestic Electric Operations 12,527.6 12,460.0 Australian Electric Operations 1,180.3 1,140.4 Other Operations 20.5 22.2 Accumulated depreciation and amortization (4,641.3) (4,553.2) ________ ________ TOTAL PROPERTY, PLANT AND EQUIPMENT - NET 9,087.1 9,069.4 OTHER ASSETS Investments in and advances to affiliated companies 114.3 114.9 Intangible assets - net 373.7 369.4 Regulatory assets - net 780.7 795.5 Finance note receivable 203.1 204.9 Finance assets - net 309.1 313.7 Deferred charges and other 393.4 378.3 ________ ________ TOTAL OTHER ASSETS 2,174.3 2,176.7 ________ ________ TOTAL ASSETS $12,642.2 $12,988.5 ======== ======== See accompanying Notes to Condensed Consolidated Financial Statements
5 PACIFICORP CONDENSED CONSOLIDATED BALANCE SHEETS (Millions of Dollars) (Unaudited) LIABILITIES AND SHAREHOLDERS' EQUITY
March 31, December 31, 1999 1998 _________ ____________ CURRENT LIABILITIES Long-term debt currently maturing $ 236.1 $ 299.5 Notes payable and commercial paper 80.3 260.6 Accounts payable 410.0 566.2 Taxes, interest and dividends payable 343.4 282.7 Customer deposits and other 163.1 168.0 ________ ________ TOTAL CURRENT LIABILITIES 1,232.9 1,577.0 DEFERRED CREDITS Income taxes 1,565.3 1,542.6 Investment tax credits 123.3 125.3 Other 651.3 646.1 ________ ________ TOTAL DEFERRED CREDITS 2,339.9 2,314.0 LONG-TERM DEBT 4,519.0 4,559.3 COMMITMENTS AND CONTINGENCIES (See Note 6) - - GUARANTEED PREFERRED BENEFICIAL INTERESTS IN COMPANY'S JUNIOR SUBORDINATED DEBENTURES 340.6 340.5 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: 1999/297,331,433 and 1998/297,343,422 3,284.3 3,285.0 Retained earnings 738.8 732.0 Accumulated other comprehensive income (54.7) (60.7) ________ ________ TOTAL COMMON EQUITY 3,968.4 3,956.3 ________ ________ TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $12,642.2 $12,988.5 ======== ======== See accompanying Notes to Condensed Consolidated Financial Statements
6 NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) March 31, 1999 1. FINANCIAL STATEMENTS The accompanying unaudited condensed consolidated financial statements as of March 31, 1999 and December 31, 1998 and for the periods ended March 31, 1999 and 1998, 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 March 31, 1999 and 1998 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 in the Company's 1998 Annual Report on Form 10-K/A Amendment No. 1. 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, all of the Company's nonintegrated electric utility investments, including Powercor Australia Limited ("Powercor"), an Australian electricity distributor, and PacifiCorp Financial Services, Inc. ("PFS"), a financial services business. Together these businesses are referred to herein as the Companies. Significant intercompany transactions and balances have been eliminated. During October 1998, the Company decided to exit its energy trading business, which consisted of TPC Corporation ("TPC") and PacifiCorp Power Marketing ("PPM"). See Note 4. During May 1998, the Company sold a majority of the real estate assets held by PFS. The Company has also decided to exit the majority of its other energy development businesses and has recorded them at estimated net realizable value less selling costs. 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. 2. CHANGE IN FISCAL YEAR Effective November 30, 1999, the Company changed its fiscal year end from December 31 to March 31, which is the fiscal year end for Scottish Power PLC ("ScottishPower"). See Note 3. A three-month transition period from January 1, 1999 through March 31, 1999 is covered by this report. 3. SCOTTISHPOWER MERGER On November 29, 1999, the Company and ScottishPower completed their proposed merger under which the Company became an indirect subsidiary of 7 ScottishPower. The Company will continue to operate under its current name, and its headquarters will remain in Portland, Oregon. Each share of the Company's stock was converted tax-free into a right to receive 0.58 American Depositary Shares (each ADS represents four ordinary shares) or 2.32 ordinary shares of ScottishPower. Cash will be paid in lieu of fractional shares. 4. DISCONTINUED OPERATIONS In October 1998, the Company decided to exit its energy trading business by offering for sale TPC, and ceasing the operations of PPM, which conducted electricity trading in the eastern United States. PPM's activities in the eastern United States have been discontinued and all forward electricity trading has been closed and is going through settlement. On April 1, 1999, Holdings sold TPC to NIPSCO Industries, Inc. for $150 million. This activity resulted in an after-tax gain of $1 million in June 1999. The net assets, operating results and cash flows of the energy trading segment have been classified as discontinued operations for all periods presented in the consolidated financial statements and notes. Summarized operating results were as follows:
Three-Month Period Ended March 31, _____________ 1998 ____ (Dollars in Millions) Revenues $816.0 ===== Net loss from discontinued operations (less applicable income tax expense of $0.4) $ (0.5) =====
Net assets of the discontinued operations of the energy trading segment and assets held for sale consisted of the following:
March 31, December 31, 1999 1998 ________ ____________ (Dollars in Millions) Current assets $107.1 $148.5 Noncurrent assets 176.7 152.7 Current liabilities (78.6) (96.0) Long-term debt (1.3) (1.3) Noncurrent liabilities (28.9) (28.9) Assets held for sale 17.4 17.4 _____ _____ Net Assets of Discontinued Operations and Assets Held for Sale $192.4 $192.4 ===== =====
Holdings had $45 million and $34 million as of March 31, 1999 and December 31, 1998, respectively, of liabilities in "Customer deposits and other" relating to the sale of the discontinued operations. 8 5. 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. On March 4, 1999, the Utah Public Service Commission (the "UPSC") ordered the Company to reduce customer prices by 12%, or $85 million annually effective March 1, 1999, and to make a one-time refund of $40 million to customers. Approximately $38 million of the refund relating to 1997 and 1998 was recorded in December 1998. The remaining $2 million was recorded in the three months ended March 31, 1999. The ordered rate reduction is the culmination of a general rate case in Utah that began in 1997. On September 20, 1999, the Company filed for a rate increase before the UPSC. The Company is asking for an annual increase of $67 million, or 9.9%, based on a test year ended December 31, 1998. The Company's effective date for this tariff increase is expected to be in May 2000. On November 24, 1999, the UPSC approved the merger. As part of the approval, the Company offered a merger credit for retail tariff customers of $12 million per year for four years beginning in 2000. The credit can be wholly or partially eliminated in years three and four to the extent that merger savings are reflected in prices. In 1998, the Company announced its intent to sell its California electric distribution assets. This action was in response to the continued decline in earnings on the assets and the changes in the legislative and regulatory environments in California. On April 9, 1999, the Company announced it had entered into a letter of intent with Nor-Cal Electric Authority for the sale of the assets to Nor-Cal for $178 million. A definitive agreement was signed on July 15, 1999. On August 16, 1999, the Company filed an application with the California Public Utility Commission (the "CPUC") for approval of the sale. On November 15, 1999, the Company filed an application for approval with the Federal Energy Regulatory Commission ("FERC"). The sale is expected to close early in 2000. On April 30, 1999, the Company filed for changes in the prices it charges Oregon customers. The filing is required as part of a 1998 Oregon Public Utility Commission (the "OPUC") order which uses set formulas to moderate the impact of cost fluctuations on customer prices, while assuring 9 high-quality service. The filing also contained a request to increase the revenues collected under its system benefits charge. These changes were approved by the OPUC in June 1999, and became effective July 1, 1999. This resulted in a price increase of approximately 1.3%, or $9 million annually, in Oregon. On November 5, 1999, the Company filed for a rate increase before the OPUC. This rate increase contains two phases. In the first phase, the Company is asking for an annual increase of $61.8 million, or 8.5%. The Company's effective date for this phase of the tariff increase is expected to be in the fall of 2000. In the second phase, the Company is asking for an annual increase of up to $26.4 million, or 3.4%, to be effective at the end of the term of the current Alternative Form of Regulation on July 1, 2001. During 1999, legislation was enacted in Oregon that requires competition for industrial and large commercial customers of both the Company and Portland General Electric by October 1, 2001. Residential customers will receive a portfolio of commodity service options. The law exempts publicly-owned utilities and Idaho Power's Oregon service territory. The law defers to the OPUC decisions on a variety of important issues, including the method for valuation of stranded costs/benefits, consumer protections, marketer certification, environmental issues, and competitive services. The legislation also calls for the functional separation of certain assets and the establishment of a code-of-conduct for electric companies and their affiliates to protect consumers against anti-competitive practices. The legislation also directs the investor-owned utilities to collect a 3% public benefit tax from regulated customers. The Company will be participating in the OPUC proceedings over the next two years that establish the rules and procedures that will implement the new law. The Company will continue to evaluate the finance and accounting impacts, including the continued propriety of applying SFAS 71, as the OPUC proceedings progress. The impacts, if any, are uncertain. On October 6, 1999, the OPUC issued an order approving the merger. As part of this approval, the Company has agreed to implement a merger credit to Oregon customers of $12 million per year for three years beginning in 2001 and $15 million in 2004. In years three and four, $9 million and $12 million, respectively, of the credit can be partially or wholly eliminated to the extent that merger savings are reflected in prices. On April 30, 1999, the Company filed documents with the Idaho Public Utilities Commission (the "IPUC") to implement the next step in the gradual retirement of a federal energy credit. The proposed reduction in the credit would increase electric prices for Utah Power residential and irrigation customers in southeastern Idaho. The filing, once approved by IPUC, would reduce the credits from the federal Bonneville Power Administration (the "BPA") and increase residential prices 3.35%, or $1 million, and irrigation prices 4%, or $1 million. These price increases are not expected to have a material impact on earnings. Congress created the federal credit in 1980 to share the benefits of federally owned hydroelectric plants with customers of investor-owned utilities in the Columbia River drainage area. When Congress recommended in 1995 that the current exchange method be phased out by June 2001, the Company worked out a settlement with BPA in 1997 to implement the order of Congress. 10 Without the settlement, prices would have increased more than 30% in two years. The settlement provided credits of $48 million over five years for the Company's customers, $6 million more than without the settlement. The additional money is being used to lessen the impact of price increases as the BPA exchange credit is phased out. On November 15, 1999, the IPUC approved the merger. In Idaho, the Company offered a $1.6 million per year merger credit to retail tariff customers for four years beginning on January 1, 2000. The credit could be wholly or partially eliminated in years three and four to the extent that merger savings are reflected in prices. On July 26, 1999, the Company filed for a rate increase before the Wyoming Public Service Commission (the "WPSC"). The Company is asking for an annual increase of $12 million, or 4.9%, based on a test year ended December 31, 1998. The effective date for this tariff increase is expected to be in the spring of 2000. On October 5, 1999, the WPSC announced it has decided to approve the merger and issued a final written order on November 22, 1999. The companies agreed to make a filing guaranteeing a minimum of $4 million per year in cost savings that will be reflected in future rate cases. On October 14, 1999, the Washington Utilities and Transportation Commission (the "WUTC") approved the merger. Washington retail customers will receive a merger credit of $3 million per year for four years beginning in 2001. The credit can be wholly or partially eliminated in all years to the extent that merger savings are reflected in prices. On August 6, 1999, the Company filed applications with the OPUC, the WUTC, the UPSC, the WPSC and the IPUC seeking orders approving the sale of the Company's interests in the Centralia plant and mine. A similar application was filed with the CPUC on August 27, 1999. The Company's applications also seek Commission orders adopting the Company's proposed treatment of the gain from the sale. 6. 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. 11 7. COMPREHENSIVE INCOME The components of comprehensive income are as follows:
Millions of dollars/For three months ended March 31 1999 1998 ________________________________________________________________________ Net income (loss) $ 91.3 $(15.1) Other comprehensive income Foreign currency translation adjustment, net of taxes 1999/$3.9 and 1998/$9.1 6.1 13.0 Unrealized gain on available-for-sale securities, net of taxes: 1999/$- (0.1) - Unrealized gain on shares of The Energy Group PLC, net of taxes of $4.6 - 7.2 _____ _____ Total comprehensive income $ 97.3 $ 5.1 ===== =====
8. SEGMENT INFORMATION Selected information regarding the Company's operating segments, Domestic Electric Operations, Australian Electric Operations and Other Operations are as follows:
Domestic Australian Other Total Electric Electric Discontinued Operations & Millions of dollars Company Operations Operations Operations Eliminations ___________________ _______ __________ __________ __________ ____________ For the three months ended: March 31, 1999 Net sales and revenues (all external) $ 959.8 $ 807.2 $147.0 $ - $ 5.6 Income from continuing operations 91.3 80.2 10.4 - 0.7 March 31, 1998 Net sales and revenues (all external) $1,260.2 $1,077.0 $162.5 $ - $20.7 Income (loss) from continuing operations (14.6) 10.4 14.1 - (39.1) Loss from discontinued operations (0.5) - - (0.5) -
12 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 1998 Annual Report on Form 10-K/A Amendment No. 1. Such forward- looking statements should be considered in light of those factors. Comparison of the three-month periods ended March 31, 1999 and 1998 ___________________________________________________________________
% 1999 1998 Change Change ____ ____ ______ ______ (Dollars in Millions) Earnings contribution (loss) on common stock (1) Domestic Electric Operations $ 75.4 $ 5.6 $ 69.8 * Australian Electric Operations 10.4 14.1 (3.7) (26) Other Operations 0.7 (39.1) 39.8 102 _____ _____ _____ Continuing Operations 86.5 (19.4) 105.9 * Discontinued Operations (2) - (0.5) 0.5 100 _____ _____ _____ Total $ 86.5 $(19.9) $106.4 * ===== ===== ===== Earnings (loss) per common share - Basic and dilutive Continuing Operations $ 0.29 $ (0.7) $ 0.36 * Discontinued Operations (2) - - - - _____ _____ _____ Total $ 0.29 $ (0.7) $ 0.36 * ===== ===== ===== *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) is net of preferred dividend requirements and minority interest. (2) Represents the discontinued operations of TPC and PPM.
The Company recorded earnings on common stock of $87 million, or $0.29 per share, compared to a loss of $20 million, or $0.07 per share in 1998. The 1998 results included an after-tax charge of $70 million, or $0.24 per share, associated with the Company's work force reduction in the United States and an after-tax charge of $54 million, or $0.18 per share, associated with the Company's terminated bid for The Energy Group plc ("TEG"). 13 Domestic electric operations earnings contribution was $75 million, or $0.25 per share, in the three months ended March 31, 1999 compared to $6 million, or $0.02 per share, in 1998. Excluding the $70 million charge relating to the work force reduction, the earnings contribution in 1998 would have been $76 million, or $0.26 per share. The Utah rate order received in March 1999 reduced earnings for the three months ended March 31, 1999 by $6 million, or $0.02 per share. This decrease was offset by lower interest expense and increased interest income totaling $11 million, or $0.04 per share, due to funds received by domestic electric operations as intercompany dividends from Holdings of $500 million and $660 million in October 1998 and January 1999, respectively. Non-fuel operations and maintenance and administrative and general costs declined 2% in the three months ended March 31, 1999, consistent with the Company's recent actions to reduce these costs. The earnings contribution for the three months ended March 31, 1999 from the Company's Australian electric operations totaled $10 million, or $0.04 per share, compared to $14 million, or $0.05 per share, in 1998. The decreased earnings contribution from Australian operations was primarily attributable to an increase in purchased power expense. Other operations reported income of $1 million for the three months ended March 31, 1999 compared to losses of $39 million in the same period a year ago. The increase in earnings was primarily due the $54 million after-tax charge for costs associated with the Company's terminated bid for TEG in 1998. This increase was partially offset by decreased earnings from PFS and Holdings. 14 RESULTS OF OPERATIONS Domestic Electric Operations ____________________________ Comparison of the three-month periods ended March 31, 1999 and 1998 ___________________________________________________________________
% 1999 1998 Change Change ____ ____ ______ ______ (Dollars in Millions) Revenues Residential $ 231.2 $ 231.8 $ (0.6) - Commercial 159.0 161.4 (2.4) (1) Industrial 151.8 162.7 (10.9) (7) Other 7.2 7.6 (0.4) (5) _______ _______ _______ Retail sales 549.2 563.5 (14.3) (3) Wholesale sales 240.0 499.1 (259.1) (52) Other 18.0 14.4 3.6 25 _______ _______ _______ Total 807.2 1,077.0 (269.8) (25) Operating expenses 611.6 981.2 (369.6) (38) _______ _______ _______ Income from operations 195.6 95.8 99.8 104 Interest expense 67.6 80.0 (12.4) (16) Minority interest and other (6.0) (2.7) 3.3 122 Income taxes 53.8 8.1 45.7 * _______ _______ _______ Net income 80.2 10.4 69.8 * Preferred dividend requirement 4.8 4.8 - - _______ _______ _______ Earnings contribution $ 75.4 $ 5.6 $ 69.8 * ======= ======= ======= Energy sales (millions of kWh) Residential 3,773 3,751 22 1 Commercial 2,993 2,992 1 - Industrial 4,628 4,891 (263) (5) Other 153 159 (6) (4) ______ ______ _______ Retail sales 11,547 11,793 (246) (2) Wholesale sales 9,636 22,443 (12,807) (57) ______ ______ _______ Total 21,183 34,236 (13,053) (38) ====== ====== ======= Residential average usage (kWh) 3,064 3,042 22 1 Total customers (end of period) 1,442,195 1,445,900 (3,705) - *Not a meaningful number.
Revenues Domestic electric operations revenues decreased $270 million, or 25%. This decrease was primarily attributable to a $259 million decrease in wholesale revenues. The sale of the Company's Montana service area in November 1998 decreased revenues by $12 million and the Utah rate order reduced revenues by $10 million. Wholesale sales decreased $259 million. The decrease in revenues was driven by a 57% decline in energy volumes. Lower short-term and spot market wholesale energy volumes decreased revenues by $264 million. Related energy prices 15 averaged $20 per MWh in the three months ended March 31, 1999, a 3% increase over the prior year. The higher prices for these sales added $7 million to revenues in the three months ended March 31, 1999. This decline in energy volumes is consistent with the Company's decision to scale back short-term wholesale sales. Residential revenues were down $1 million. Excluding the impact of the sale of Montana, residential revenues were up $5 million, energy volumes were up 4% and customer growth was 2%. Growth in the average number of residential customers added $5 million to revenues. Volume increases primarily due to colder weather added $3 million to revenues. The Utah rate order reduced residential revenues by $4 million. Commercial revenues were down $2 million, or 1%. Excluding the impact of the sale of Montana, commercial revenues were up $1 million. Increased commercial customers added $5 million to revenues. The Utah rate order reduced commercial revenues by $4 million. Industrial revenues decreased $11 million, or 7%. Excluding the impact of the sale of Montana, industrial revenues were down $8 million, energy volumes were down 4% and average customers were down 4%. Decreased energy volumes due to the cyclical nature of industrial customer usage drove a $6 million decrease in revenues. The Utah rate order reduced industrial revenues by $2 million. Other revenue increased $4 million due to increased wheeling revenues. See Note 5 regarding regulation of domestic electric operations' utility properties. Operating Expenses Total operating expenses decreased $370 million, or 38%. This decrease was primarily attributable to decreased purchased power expense due to the decline in wholesale sales and the $113 million pretax special charge in 1998 for the work force reduction that occurred in the same period in 1998. Purchased power expense decreased $249 million, to $210 million. The lower expense was primarily due to a 12.5 million MWh decrease in short-term firm and spot market energy purchases which decreased purchased power expense $243 million. Short-term firm and spot market purchase prices averaged $19 per MWh in the three months ended March 31, 1999 versus $20 per MWh in 1998, a 5% decrease. The decrease in purchase prices reduced costs $9 million. Higher volumes relating to long-term firm purchased power contracts added $3 million to purchased power costs. 16
Short-Term Firm and Spot Market Sales and Purchases ___________________________________________________ 1999 1998 ____ ____ Total sales volume (thousands of MWh) 5,719 18,900 Average sales price ($/MWh) $ 20.32 $ 19.77 _______ _______ Revenues (millions) $ 116 $ 374 Total purchase volume (thousands of MWh) 5,111 17,635 Average purchase price ($/MWh) $ 18.61 $ 19.70 _______ _______ Expenses (millions) $ 95 $ 347 _______ _______ Net (millions) $ 21 $ 27 ======= =======
Fuel expense was down $3 million, or 3%, to $120 million in 1999. Thermal generation was down 4% to 12.8 million MWh. The average cost per MWh increased to $9.31 from $9.17 in the prior year due to increased generation at plants with higher fuel costs. The shift in generation resulted from unscheduled plant outages. Hydroelectric generation increased 13% compared to the three months ended March 31, 1998 due to favorable water conditions. Other operations and maintenance expense increased $2 million, or 2%, to $113 million. Increased tree trimming added $3 million to expenses, which was partially offset by a reduction in labor costs of $1 million. Administrative and general expenses decreased $5 million, or 7%, to $73 million primarily due to a reduction in labor and employee related costs of $12 million. This decrease was partially offset by a $6 million increase in costs relating to the ongoing implementation of the Company's new SAP software operating environment and increased outside services of $2 million. Other Income and Expense Domestic electric operations' interest expense was down $12 million to $68 million as a result of lower debt balances. The lower debt balances were due to dividends received from Holdings in October 1998 and January 1999 that were used to pay down intercompany debt owed to Holdings and some external debt. Interest income increased $5 million as a result of the dividends received from Holdings, some of which was invested in interest bearing instruments. Income tax expense increased $46 million, to $54 million, due to the increase in pretax income. 17 Australian Electric Operations ______________________________ Comparison of the three-month periods ended March 31, 1999 and 1998 ___________________________________________________________________
Change Due Change % Change to Currency Due to Due to 1999 1998 Translation Operations Operations ____ ____ ___________ __________ __________ (Dollars in Millions) Powercor Earnings Contribution Revenues Powercor area $103.2 $116.5 $(5.5) $(7.8) (7) Outside Powercor area Victoria 18.1 20.9 (0.9) (1.9) (9) New South Wales 19.4 20.2 (0.9) 0.1 - Queensland 0.5 - - 0.5 * Australian Capital Territory 0.4 - - 0.4 * _____ _____ ____ ____ 141.6 157.6 (7.3) (8.7) (6) Other 5.4 4.9 (0.3) 0.8 16 _____ _____ ____ ____ Total 147.0 162.5 (7.6) (7.9) (5) Operating expenses 112.2 121.7 (5.8) (3.7) (3) _____ _____ ____ ____ Income from operations 34.8 40.8 (1.8) (4.2) (10) Interest expense 14.4 15.8 (0.7) (0.7) (4) Equity in losses of Hazelwood 3.7 3.0 (0.2) 0.9 30 Other (income)/expense (0.1) (0.4) - 0.3 (75) Income taxes 6.4 8.3 (0.3) (1.6) (19) _____ _____ ____ ____ Earnings contribution $ 10.4 $ 14.1 $(0.6) $(3.1) (22) ===== ===== ==== ==== Powercor energy sales (millions of kWh) Powercor area 1,666 1,797 (131) (7) Outside Powercor area Victoria 586 600 (14) (2) New South Wales 579 575 4 1 Queensland 13 - 13 * Australian Capital Territory 8 - 8 * _____ _____ ____ Total 2,852 2,972 (120) (4) ===== ===== ==== *Not a meaningful number.
Currency Exchange Rates The currency exchange rate for converting Australian dollars to U.S. dollars was 0.63 for the three months ended March 31, 1999 as compared to 0.67 in 1998, a 6% decrease in the quarter. The effect of this change in exchange rates lowered revenues by $8 million and costs by $7 million in 1999. The following discussion excludes the effects of the lower currency exchange rate in 1999. 18 Revenues Australian electric operations' revenues decreased $8 million, or 5%. This decrease was attributable to a decline in energy volumes sold of 120 million kWh, or 4%. Energy volumes sold to contestable customers outside Powercor's franchise area were up 11 million kWh and added $1 million to revenues due to customer gains in Queensland and Australian Capital Territory. Inside Powercor's franchise area, revenues decreased $8 million due to a 131 million kWh decrease in energy sold. Volumes are down due to the loss of a few large contestable customers. Other revenues increased $1 million largely as a result of an increase in revenue from construction projects for customers who own their own distribution assets, some of whom are other distribution businesses in Australia. Operating Expenses Purchased power expense increased $4 million, or 7%, to $59 million. Higher average prices increased power costs by $6 million. Prices for purchased power averaged $22 per MWh for the three months ended March 31, 1999 compared to $19 per MWh in 1998. This price increase was the result of a contract dispute Powercor is having with a power supplier in Australia. The power supplier did not meet its contractual obligation to deliver power to Powercor at the agreed upon rate, which forced Powercor to purchase power on the open market at a rate higher than it paid last year. This increase was offset in part by a 4% decrease in purchased power volumes that reduced costs $2 million. As of September 30, 1999, the contract dispute with the power supplier had resulted in $15 million of higher purchased power costs and $3 million in legal fees. Powercor brought suit to enforce the contract and recover its damages. On November 17, 1999, the Supreme Court of Victoria upheld the validity of these contracts. On December 14, 1999, the Court ordered specific performance on the remaining contracts and payment for failure to perform in the past. This order is still subject to appeal. Other operating expenses decreased $8 million, or 28%, to $19 million. Decreased rates resulted in lower network fees of $2 million and an increase in customers inside Powercor's franchise area serviced by other energy suppliers resulted in higher network revenues of $6 million. Administrative and general costs decreased $1 million, or 7%, to $12 million due to the outsourcing of certain functions in the information technology department. Other Income and Expense The Company recorded losses in 1999 of $4 million compared to losses of $3 million in 1998 on its equity investment in the Hazelwood power station. Income tax expense was down $2 million, or 19%, due to a decrease in taxable income. 19 Other Operations Comparison of the three-month periods ended March 31, 1999 and 1998 ___________________________________________________________________
% 1999 1998 Change Change ____ ____ ______ ______ (Dollars in Millions) Earnings contribution (loss) PFS $(0.4) $ 6.6 $(7.0) (107) Holdings and other TEG costs - (53.5) 53.5 100 Other 1.1 7.8 (6.7) (86) ____ _____ ____ $ 0.7 $(39.1) $39.8 (102) ==== ===== ====
Other operations reported income of $1 million in the three months ended March 31, 1999 compared to losses of $39 million in the same period a year ago. The increase in earnings was primarily due to an $86 million pretax ($54 million after-tax) charge in 1998 for costs associated with the Company's terminated bid for TEG. Results from other operations for the three months ended March 31, 1999 were reduced by approximately $11 million, or $0.04 per share, in decreased interest income as the result of cash dividends of $500 million paid in October 1998 and $660 million paid in January 1999 by Holdings to domestic electric operations. This cash had been invested by Holdings in interest bearing instruments prior to the dividends. For 1999, PFS reported break even results, a $7 million decrease from 1998. This decrease was primarily attributable to the sale of its affordable housing properties and operating leases that reduced income $6 million. In May 1998, PFS sold a majority of its investments in affordable housing for $80 million, which approximated book value. In addition, PFS incurred a $1 million loss relating to sales of synthetic coal fuel by its subsidiaries. Other energy development businesses recorded no earnings or losses in 1999 compared to a loss of $5 million, or $0.02 per share, in 1998. This reduction in losses was the result of the decision to exit these development businesses in October 1998. 20 FINANCIAL CONDITION - For the three months ended March 31, 1999: OPERATING ACTIVITIES Net cash flows provided by continuing operations were $274 million during the period compared to $216 million in 1998. The $58 million increase in operating cash flows was primarily attributable to decreased working capital requirements. Net cash used in discontinued operations in 1998 represents payment of income taxes in early 1998 associated with a $671 million pretax gain recorded in December 1997 on the sale of PTI. Net cash provided by discontinued operations in 1999 represents payments received from TPC on its intercompany note payable to Holdings. INVESTING ACTIVITIES Capital spending totaled $117 million in 1999 compared with $138 million in 1998. Investments in and advances to affiliated companies-net is down $21 million because the three months ended March 31, 1998 included the construction of synthetic coal fuel plants by subsidiaries of PFS. On May 10, 1999, the utility partners who own the 1,340 MW coal-fired Centralia Power Plant announced their intention to sell the plant and the adjacent coal mine owned by the Company to TransAlta for $554 million. The sale is subject to regulatory approval and is expected to close during the first half of 2000. The Company operates the plant and owns a 47.5% share. The Company expects to realize a gain on the sale, but the amount will not be determined until the regulatory approval process has been completed. CAPITALIZATION At September 30, 1999, PacifiCorp had approximately $147 million of commercial paper and uncommitted bank borrowings outstanding at a weighted average rate of 6.3%. These borrowings are supported by $700 million of revolving credit agreements. At September 30, 1999, the consolidated subsidiaries had access to $722 million of short-term funds through committed bank revolving credit agreements. Subsidiaries had $415 million outstanding under bank revolving credit facilities. At September 30, 1999, the Company and its subsidiaries had $529 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. INTEREST RATE EXPOSURE The Company's market risk to interest rate change is primarily related to long-term debt with fixed interest rates. The Company uses interest rate swaps, forwards, futures and collars to adjust the characteristics of its liability portfolio. This strategy is consistent with the Company's capital structure policy that provides guidance on overall debt to equity and variable 21 rate debt as a percent of capitalization levels for both the consolidated organization and its principal subsidiaries. Based on the Company's overall interest rate exposure, the estimated potential one-day loss in fair value as a result of near-term change in interest rates, within a 95% confidence level using historical interest rate movements based on the VAR model, was $23 million at September 30, 1999. YEAR 2000 This Year 2000 disclosure reflects the status of the Company's preparedness through December 31, 1999. This disclosure is consistent with those given previously by the Company. As of January 13, 2000, the Company has experienced some minor Year 2000 related problems with its business systems that were quickly identified and corrected. Due to the nature of Year 2000 problems, it is still too early to determine whether additional problems will occur. While the Company does not anticipate any major Year 2000 problems to occur, it is continuing to monitor systems for any latent Year 2000 issues. 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 was implemented. The main areas of risk are in: power supply (generating plant and system controls); information technology (computer software and hardware); business disruption; and supply chain disruption. The first two areas of risk are within the Company's own business operations. The others are areas of risk the Company might face from interaction with other companies, such as critical suppliers and customers. The Company's plan was to successfully identify, correct and test its existing critical systems by July 1, 1999, and to require all new hardware or software acquired by the Company to be vendor certified Year 2000 ready before it is installed. The Company completed its testing and remediation on all critical systems and met the July 1, 1999 milestone to be ready for the year 2000. Following months of preparation and testing, the Company has finished advancing the system clocks in all thermal generating units and substations to dates beyond March 1, 2000. The Company will reset the dates on equipment during the second quarter of 2000. By operating in the year 2000 now, the Company is demonstrating confidence in its Year 2000 preparation and plans to conduct business as usual on January 1, 2000. This also reduces any risks inherent in the end-of-year and leap year date turnovers to producing and delivering electric power. The Company's Year 2000 project office continues to coordinate all Year 2000 activities throughout the corporation, as well as with suppliers and business partners. This work will continue well into early 2000 with full-time employees and contractors completing the final wrap-up of the project. The 22 following summarizes the status of the Year 2000 project as of December 1, 1999. Areas complete (as of December 1, 1999) _______________________________________ Computer Systems - Correct and Test Computer Systems - Applications to replace Electric Systems - Inventory Electric Systems - Assessment Electric Systems - Correct and Test Initial Contingency planning Computer Systems - Desktop Non-Critical Systems - Enterprise wide Continued compliance testing Contingency exercises As the Company finalizes its Year 2000 readiness, the focus will shift to a management program to maintain its Year 2000-ready status. This strategy includes Year 2000 testing of all system modifications and qualifying all new equipment as Year 2000 ready before it is purchased and installed. The Company is actively working with its suppliers of products and services to determine the extent to which the suppliers' operations, and the products and services they provide, are Year 2000 ready. The Company believes it has identified and assessed 100% of its critical third-party suppliers. The Company's critical third-party vendors reported they would be Year 2000 ready on or before the dates below: Readiness Target Dates Percent of all Critical Third (on or before) Parties Ready 12/31/1998 14% 03/31/1999 18% 06/30/1999 44% 09/30/1999 79% 12/31/1999 100% The Company is in contact with these third parties, and their Year 2000 readiness information is updated as required. To the extent that these parties are considered mission-critical to the business and experience Year 2000 problems in their systems, the mission- critical business functions may be adversely affected. The Company plans to mitigate this risk by developing and testing contingency plans throughout 1999. As of December 31, 1998, the Company had no single retail customer that accounted for more than 1.7% of its retail utility revenues and the 20 largest retail customers accounted for 13.9% of total retail electric revenues. The Company has not performed a formal assessment of its customers' Year 2000 readiness. The Company's mining operations contingency plan calls for increased stockpiles of fuel to be available to supply the generating plants. 23 The Company, the North American Electric Reliability Council ("NERC") and the Western Systems Coordinating Council ("WSCC") are working closely together to ensure the integrity of the interconnected electrical distribution and transmission system in the Company's service area and the western United States. NERC coordinates the efforts of the ten regional electric reliability councils throughout the United States, while WSCC is focused on reliable electric service in the western United States. These agencies required Year 2000 readiness for all interconnected electric utilities by July 1, 1999. The Company has submitted its draft contingency plans to the WSCC as required by NERC. The Company participated in the NERC sponsored industry preparedness drills on April 9, 1999 and September 9, 1999. The Company's worst case planning scenario assumes the following: 1. The public telecommunication system is not available or not functioning reliably for as long as a week. 2. At midnight on December 31, 1999, there is a near simultaneous loss of multiple generating units resulting in transmission system instability and regional black outs. Restoration of service will start immediately, but some areas may not be fully restored and stable for twenty-four hours. 3. Temporary loss of automated transmission system monitoring and control systems. These functions must be performed manually during restoration. 4. Temporary loss of customer billing system. Customers on billing cycles in the early part of the month may receive an estimated billing that will be adjusted the following month. 5. Temporary loss of receivables processing system. 6. Temporary loss of automated payroll system. Employees will be paid, but some automated functions must be performed manually. 7. Temporary loss of automated shareholder services systems. Information must be available to be accessed manually while automated systems are being restored. To address this potential scenario and in cooperation with efforts by NERC and WSCC, the Company plans to establish a precautionary posture for its system leading into December 31, 1999. This is similar to the posture taken when severe winter weather is anticipated in areas of its service territory. Regional connections would be deliberately disconnected only during, or immediately following, a system disturbance in order to prevent further cascading outages and to facilitate restoration. Additional personnel will be on hand at control centers. Facilities such as power plants and key major substations will also have additional personnel standing by. Backup systems will be serviced and tested, as appropriate, prior to the transition period. Additional generation will be brought on line for the transition period as needed. 24 The Company is continuing to expand its extensive microwave network in 1999. Because this system is self-controlled and has been undergoing extensive analysis for Year 2000 readiness, the Company considers this a reliable alternative to the public telephone network if needed. Emergency power systems will be tested and made ready. In addition to the microwave system, the Company has an extensive radio network. Through integration of the Company's radio and microwave facilities, Company personnel can effectively "dial-up" telephones throughout the Company's area. Radio units will be deployed at key locations during the transition period. The Company is also planning to station satellite telephones at system dispatching facilities and key power plants. The Company's payment processing system has been certified by the vendor as Year 2000 ready. Check issuance has been outsourced to a vendor who is Year 2000 ready. To the extent possible, accounts payable checks and wire transfers will be processed early in December. Arrangements are expected to be made with the Company's banks to cover critical payment obligations for up to seventy- two hours should wire transfers be disrupted. The Company's systems to maintain shareholder records, transfer stock, issue 1099 dividend statements and process dividend payments are certified Year 2000 ready. Powercor ________ Powercor implemented its Customer Service System in October 1999, and upgrades to its large customer billing system were installed in November 1999. The Operations Management System was replaced in November 1999. All of these systems are Year 2000 ready. Mining ______ Few Year 2000 impacts have been identified within the mining subsidiaries. The Year 2000 project completed its activities in October 1999. The Company has incurred $25.4 million in costs relating to the Year 2000 project through November 30, 1999. The majority of these costs have been incurred to repair software problems. The total cost of the Year 2000 project is estimated at $26 to $30 million, which will be principally funded from operating cash flows. This estimate does not include the cost of system replacements that will be Year 2000 ready, but are not being installed primarily to resolve Year 2000 problems. Year 2000 information technology ("IT") remediation costs amount to approximately 5% of IT's budget. The Company has not delayed any IT projects that are critical to its operations as a result of Year 2000 remediation work. No independent verification of risk and cost estimates has been undertaken to date. The dates on which the Company believes the Year 2000 project will be completed and the expected costs and other impacts of the Year 2000 issues are based on management's best estimates, which were derived utilizing numerous assumptions concerning future events, including the availability of certain resources, the completion of third-party modification plans and other factors. There can be no assurance that these estimates will be achieved, or that there will not be a delay in, or increased costs associated with, the Company's implementation of its Year 2000 project. ______________________________________________________________________________ 25 PART II. OTHER INFORMATION Item 6. Exhibits and Reports on Form 8-K ______ ________________________________ (a) Exhibits. Exhibit 12(a): Statements of Computation of Ratio of Earnings to Fixed Charges. (Incorporated by reference to Exhibit 12(a) to Form 10-Q for the quarter ended March 31, 1999, dated May 12, 1999, File No. 1-5152.) Exhibit 12(b): Statements of Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends. (Incorporated by reference to Exhibit 12(b) to Form 10-Q for the quarter ended March 31, 1999, dated May 12, 1999, File No. 1- 5152.) Exhibit 15: Letter re unaudited interim financial information of awareness of incorporation by reference. (Incorporated by reference to Exhibit 15 to Form 10-Q for the quarter ended March 31, 1999, dated May 12, 1999, File No. 1-5152.) Exhibit 27: Financial Data Schedule for the quarter ended March 31, 1999 (filed electronically only). (Incorporated by reference to Exhibit 27 to Form 10-Q for the quarter ended March 31, 1999, dated May 12, 1999, File No. 1-5152.) (b) Reports on Form 8-K. On Form 8-K, dated November 29, 1999, the Company reported "Item 1. Change in Control of Registrant," "Item 4. Changes in Registrant's Certifying Accountant" and "Item 8. Change in Fiscal Year." 26 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 January 13, 2000 By ROBERT R. DALLEY _________________________ _________________________________ Robert R. Dalley Controller and Chief Accounting Officer INDEX TO EXHIBITS
EXHIBIT DESCRIPTION PAGE _______ ___________ ____ Exhibit 12(a): Statements of Computation of Ratio of Earnings to Fixed Charges. (Incorporated by reference to Exhibit 12(a) to Form 10-Q for the quarter ended March 31, 1999, dated May 12, 1999, File No. 1-5152.) Exhibit 12(b): Statements of Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends. (Incorporated by reference to Exhibit 12(b) to Form 10-Q for the quarter ended March 31, 1999, dated May 12, 1999, File No. 1-5152.) Exhibit 15: Letter re unaudited interim financial information of awareness of incorporation by reference. (Incorporated by reference to Exhibit 15 to Form 10-Q for the quarter ended March 31, 1999, dated May 12, 1999, File No. 1-5152.) Exhibit 27: Financial Data Schedule for the quarter ended March 31, 1999 (filed electronically only). (Incorporated by reference to Exhibit 27 to Form 10-Q for the quarter ended March 31, 1999, dated May 12, 1999, File No. 1-5152.)