-----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, L+d7afmmSOibtPeNLNdxgLQJxyiql2kCfRBTE4Tje7W1hv72b+outnEyJUk6ZNpM o1mhdsTNlxyGOqUrxLpJVg== 0000950159-00-000134.txt : 20000407 0000950159-00-000134.hdr.sgml : 20000407 ACCESSION NUMBER: 0000950159-00-000134 CONFORMED SUBMISSION TYPE: 10-Q/A PUBLIC DOCUMENT COUNT: 2 CONFORMED PERIOD OF REPORT: 19990630 FILED AS OF DATE: 20000406 FILER: COMPANY DATA: COMPANY CONFORMED NAME: PECO ENERGY CO CENTRAL INDEX KEY: 0000078100 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 230970240 STATE OF INCORPORATION: PA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q/A SEC ACT: SEC FILE NUMBER: 001-01401 FILM NUMBER: 595078 BUSINESS ADDRESS: STREET 1: 2301 MARKET ST STREET 2: P O BOX 8699 CITY: PHILADELPHIA STATE: PA ZIP: 19101 BUSINESS PHONE: 2158414000 FORMER COMPANY: FORMER CONFORMED NAME: PHILADELPHIA ELECTRIC CO DATE OF NAME CHANGE: 19920703 10-Q/A 1 UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, DC 20549 FORM 10-Q/A Amendment No. 1 [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended June 30, 1999 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Commission file number: 1-1401 PECO Energy Company (Exact name of registrant as specified in its charter) Pennsylvania 23-0970240 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 2301 Market Street, Philadelphia, PA 19103 (Address of principal executive offices) (Zip Code) (215) 841-4000 (Registrant's telephone number, including area code) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No ___ Indicate the number of shares outstanding of each of the issuer's classes of common stock as of the latest practicable date: The Company had 186,603,406 shares of common stock outstanding on August 6, 1999. PART I. FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited) (Millions of Dollars, Except Per Share Data)
Three Months Ended June 30, Six Months Ended June 30, 1999 1998 1999 1998 ----------- ----------- ------------ ------------ OPERATING REVENUES Electric $ 1,105.4 1,131.8 2,144.3 2,134.8 Gas 89.0 83.4 306.5 270.6 ----------- ----------- ------------ ------------ TOTAL OPERATING REVENUES 1,194.4 1,215.2 2,450.8 2,405.4 ----------- ----------- ------------ ------------ OPERATING EXPENSES Fuel and Energy Interchange 500.3 360.2 953.6 743.2 Operating and Maintenance 338.9 256.0 627.6 539.2 Depreciation and Amortization 57.6 160.9 113.9 315.6 Taxes Other Than Income 45.2 71.8 120.5 153.9 ----------- ----------- ------------ ------------ 942.0 848.9 1,815.6 1,751.9 ----------- ----------- ------------ ------------ OPERATING INCOME 252.4 366.3 635.2 653.5 ----------- ----------- ------------ ------------ OTHER INCOME AND DEDUCTIONS Interest Expense (113.5) (86.0) (187.8) (171.0) Company Obligated Mandatorily Redeemable Preferred Securities of a Partnership (7.4) (8.2) (14.8) (15.9) Allowance for Funds Used During Construction 1.7 0.7 2.1 1.3 Other, Net 9.8 (26.9) (32.2) (39.7) ----------- ----------- ------------ ------------ TOTAL OTHER INCOME AND DEDUCTIONS (109.4) (120.4) (232.7) (225.3) ----------- ----------- ------------ ------------ INCOME BEFORE INCOME TAXES AND EXTRAORDINARY ITEM 143.0 245.9 402.5 428.2 INCOME TAXES 46.9 94.4 149.7 163.1 ----------- ----------- ------------ ------------ INCOME BEFORE EXTRAORDINARY ITEM 96.1 151.5 252.8 265.1 EXTRAORDINARY ITEM - NET OF INCOME TAXES (26.7) -- (26.7) -- ----------- ----------- ------------ ------------ NET INCOME 69.4 151.5 226.1 265.1 PREFERRED STOCK DIVIDENDS 3.3 3.3 6.6 6.6 ----------- ----------- ------------ ------------ EARNINGS APPLICABLE TO COMMON STOCK $ 66.1 $ 148.2 $ 219.5 $ 258.5 =========== =========== ============ ============ AVERAGE SHARES OF COMMON STOCK OUTSTANDING (Millions) 192.0 222.7 207.6 222.6 =========== =========== ============ ============ BASIC AND DILUTIVE EARNINGS PER AVERAGE COMMON SHARES BEFORE EXTRAORDINARY ITEM $ 0.48 $ 0.66 $ 1.19 $ 1.16 EXTRAORDINARY ITEM (0.14) -- (0.13) -- ----------- ----------- ------------ ------------ BASIC EARNINGS PER AVERAGE COMMON SHARE $ 0.34 $ 0.66 $ 1.06 $ 1.16 =========== =========== ============ ============ DIVIDENDS PER AVERAGE COMMON SHARE $ 0.25 $ 0.25 $ 0.50 $ 0.50 =========== =========== ============ ============
See Notes to Condensed Consolidated Financial Statements. 2 PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES CONDENSED CONSOLIDATED BALANCE SHEETS (Millions of Dollars)
June 30, December 31, 1999 1998 ---------- ---------- (Unaudited) ASSETS UTILITY PLANT Electric - Transmission & Distribution $ 3,890.8 $ 3,833.8 Electric - Generation 1,732.3 1,713.4 Gas 1,141.2 1,132.0 Common 409.3 407.3 ---------- ---------- 7,173.6 7,086.5 Less Accumulated Provision for Depreciation 3,007.6 2,891.3 ---------- ---------- 4,166.0 4,195.2 Nuclear Fuel, net 296.7 141.9 Construction Work in Progress 375.0 272.6 Leased Property, net 0.5 154.3 ---------- ---------- 4,838.2 4,764.0 ---------- ---------- CURRENT ASSETS Cash and Temporary Cash Investments 914.0 48.1 Accounts Receivable, net Customer 213.1 97.5 Other 376.2 213.2 Inventories, at average cost Fossil Fuel 62.9 92.3 Materials and Supplies 108.8 82.1 Deferred Income Taxes 7.7 (14.1) Other 109.0 19.0 ---------- ---------- 1,791.7 538.1 ---------- ---------- DEFERRED DEBITS AND OTHER ASSETS Competitive Transition Charge 5,274.6 5,274.6 Recoverable Deferred Income Taxes 609.2 614.4 Deferred Non-Pension Postretirement Benefits Costs 87.7 90.9 Investments 554.8 538.1 Loss on Reacquired Debt 73.9 77.2 Other 131.0 107.1 ---------- ---------- 6,731.2 6,702.3 ---------- ---------- TOTAL $ 13,361.1 $ 12,004.4 ========== ==========
See Notes to Condensed Consolidated Financial Statements. (continued on next page) 3 PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES CONDENSED CONSOLIDATED BALANCE SHEETS (Millions of Dollars) (continued)
June 30, December 31, 1999 1998 ---------- ---------- (Unaudited) CAPITALIZATION AND LIABILITIES CAPITALIZATION Common Shareholders' Equity Common Stock (No Par) $ 3,616.7 $ 3,589.0 Other Paid-In Capital 1.2 1.2 Accumulated Deficit (407.0) (532.9) Treasury Stock (1,507.3) -- Preferred and Preference Stock Without Mandatory Redemption 137.5 137.5 With Mandatory Redemption 92.7 92.7 Company Obligated Mandatorily Redeemable Preferred Securities of a Partnership 340.4 349.4 Long-Term Debt 6,092.2 2,919.6 ---------- ---------- 8,366.4 6,556.5 ---------- ---------- CURRENT LIABILITIES Notes Payable, Bank 226.0 525.0 Long-Term Debt Due Within One Year 146.1 361.5 Capital Lease Obligations Due Within One Year -- 69.0 Accounts Payable 357.5 316.2 Taxes Accrued 198.1 170.5 Interest Accrued 104.9 61.5 Deferred Energy Costs - Gas 26.3 (29.9) Other 223.8 217.4 ---------- ---------- 1,282.7 1,691.2 ---------- ---------- DEFERRED CREDITS AND OTHER LIABILITIES Capital Lease Obligations 0.5 85.3 Deferred Income Taxes 2,355.3 2,376.9 Unamortized Investment Tax Credits 292.8 300.0 Pension Obligation 219.3 219.3 Non-Pension Postretirement Benefits Obligation 436.1 421.1 Other 408.0 354.1 ---------- ---------- 3,712.0 3,756.7 ---------- ---------- COMMITMENTS AND CONTINGENCIES (NOTE 8) TOTAL $ 13,361.1 $ 12,004.4 =========== ==========
See Notes to Condensed Consolidated Financial Statements. 4 PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (Millions of Dollars)
Six Months Ended June 30, 1999 1998 ---------- -------- CASH FLOWS FROM OPERATING ACTIVITIES NET INCOME $ 226.1 $ 265.1 EXTRAORDINARY ITEM, NET OF INCOME TAXES 26.7 -- ---------- -------- INCOME BEFORE EXTRAORDINARY ITEM 252.8 265.1 Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities: Depreciation and Amortization 149.4 343.0 Deferred Income Taxes (38.2) (29.3) Amortization of Investment Tax Credits (7.2) (9.0) Deferred Energy Costs 56.1 27.1 Changes in Working Capital: Accounts Receivable (278.5) (87.1) Inventories 2.7 9.0 Accounts Payable 41.3 (11.3) Other Current Assets and Liabilities 13.3 (68.8) Other Items Affecting Operations 74.4 71.3 ---------- -------- CASH FLOWS PROVIDED BY OPERATING ACTIVITIES 266.1 510.0 ---------- -------- CASH FLOWS FROM INVESTING ACTIVITIES Investment in Plant (244.4) (229.1) Increase in Investments (35.0) (35.8) ---------- -------- NET CASH FLOWS USED IN INVESTING ACTIVITIES (279.4) (264.9) ---------- -------- CASH FLOWS FROM FINANCING ACTIVITIES Issuance of Long-Term Debt 4,000.0 6.4 Common Stock Repurchase (1,507.3) -- Debt Repayments (1,202.5) (96.8) Change in Short-Term Debt (299.0) (55.5) Dividends on Preferred and Common Stock (109.9) (117.8) Issuance of Company Obligated Mandatorily Redeemable Preferred Securities of a Partnership -- 78.1 Issuance of Common Stock 14.0 9.3 Other Items Affecting Financing (16.1) 3.1 ---------- -------- NET CASH FLOWS PROVIDED BY (USED IN) FINANCING ACTIVITIES 879.2 (173.2) ---------- -------- INCREASE IN CASH AND CASH EQUIVALENTS 865.9 71.9 ---------- -------- CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 48.1 33.4 ---------- -------- CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 914.0 $ 105.3 ========== ========
See Notes to Condensed Consolidated Financial Statements. 5 PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 1. BASIS OF PRESENTATION The accompanying condensed consolidated financial statements as of June 30, 1999 and for the three and six months then ended are unaudited, but include all adjustments that PECO Energy Company (Company) considers necessary for a fair presentation of such financial statements. All adjustments are of a normal, recurring nature. The year-end condensed consolidated balance sheet data were derived from audited financial statements but do not include all disclosures required by generally accepted accounting principles. Certain prior-year amounts have been reclassified for comparative purposes. These notes should be read in conjunction with the Notes to Consolidated Financial Statements in the Company's 1998 Annual Report to Shareholders, which are incorporated by reference in the Company's Annual Report on Form 10-K for the year ended December 31, 1998. 2. TRANSITION BONDS On March 25, 1999, PECO Energy Transition Trust (PETT), an independent statutory business trust organized under the laws of Delaware and a wholly owned subsidiary of the Company, issued $4 billion aggregate principal amount of Transition Bonds (Transition Bonds) to securitize a portion of the Company's authorized stranded cost recovery. The Transition Bonds are solely obligations of PETT, secured by Intangible Transition Property sold by the Company to PETT concurrently with the issuance of the Transition Bonds and certain other collateral related thereto. The terms of the Transition Bonds are as follows:
Approximate Face Amount Bond Expected Final Class (millions) Rates Maturity Maturity A-1 $244.5 5.48% March 1, 2001 March 1, 2003 A-2 $275.4 5.63% March 1, 2003 March 1, 2005 A-3 $667.0 5.18% (a) March 1, 2004 March 1, 2006 A-4 $458.5 5.80% March 1, 2005 March 1, 2007 A-5 $464.6 5.26% (a) September 1, 2007 March 1, 2009 A-6 $993.4 6.05% March 1, 2007 March 1, 2009 A-7 $896.7 6.13% September 1, 2008 March 1, 2009
(a) The Class A-3 and A-5 Transition Bonds earn interest at a floating rate. The rates provided for each such class above are as of June 30, 1999. 6 The Company entered into treasury forwards and forward starting interest rate swaps to manage interest rate exposure associated with the anticipated issuance of Transition Bonds. On March 18, 1999, these instruments were settled with net proceeds to the Company of approximately $80 million which were deferred and are being amortized over the life of the Transition Bonds as a reduction of interest expense, consistent with the Company's hedge accounting policy. The Company has entered into interest rate swaps to manage interest rate exposure associated with the issuance of two floating rate series of Transition Bonds. At June 30, 1999, the fair value of these instruments was $52 million based on the present value difference between the contracted rate (i.e., hedged rate) and the market rates at that date. A hypothetical 50 basis point increase or decrease in the spot yield at June 30, 1999 would have resulted in an aggregate fair value of these interest rate swaps of $91.2 million or $10.7 million, respectively. If the derivative instruments had been terminated at June 30, 1999, these estimated fair values represent the amount to be paid by the counterparties to the Company. The net proceeds to the Company from the securitization of a portion of its allowed stranded cost recovery, after payment of fees and expenses and the capitalization of PETT, were approximately $3.95 billion. In accordance with the provisions of the Pennsylvania Electricity Generation Customer Choice and Competition Act, the Company is utilizing these proceeds principally to reduce its stranded costs and related capitalization. Through June 30, 1999, the Company utilized the net proceeds to repurchase 38.7 million shares of Common Stock for an aggregate purchase price of $1.507 billion; to retire: $811 million of First Mortgage Bonds, a $400 million term loan, $208 million of commercial paper, $150 million of accounts receivable financing and a $139 million capital lease obligation; to repurchase $9 million of Company Obligated Mandatorily Redeemable Preferred Securities of a Partnership (COMRPS); and to pay $25 million of debt issuance costs. The remaining proceeds of approximately $750 million are included in cash at June 30, 1999. In addition, on July 30, 1999, the Company redeemed $212 million of COMRPS. On August 2, 1999, the Company retired $37 million of Mandatorily Redeemable Preferred Stock pursuant to the sinking fund requirements of those securities. In the second quarter of 1999, the Company incurred an extraordinary charge of $26.7 million, net of tax, consisting of prepayment premiums and the write-off of unamortized deferred financing costs associated with the early retirement of debt. 3. SEGMENT INFORMATION The Company is primarily a vertically integrated public utility that provides retail electric and natural gas service to the public in its traditional service territory and retail electric generation service throughout Pennsylvania pursuant to Pennsylvania's Customer Choice Program. The Company's management has historically managed the Company as a vertically integrated entity by analyzing its results of operations on a consolidated basis with an emphasis on electric and gas operations. During the first quarter of 1999, the Company completed the redesign of its internal reporting structure to separate its distribution, generation, 7 and ventures operations into business units and provide financial and operational data on the same basis to senior management. The Company's distribution business unit includes its electric transmission and distribution services, regulated retail sales of generation services and retail gas businesses. The Company's generation business unit includes the operation of its generation assets and its power marketing group. The Company's ventures business unit includes its unregulated retail energy supplier, infrastructure services business and its telecommunications equity investments. During the second quarter of 1999, the Company further revised the internal reporting structure to include its unregulated retail energy supplier with the generation business unit to more efficiently manage the Company's overall energy supply requirements. Accordingly, the results of operations and assets of the unregulated retail energy supplier are included in the generation business unit for all periods presented. The Company's segment information as of and for the three and six months ended June 30, 1999 as compared to the same 1998 period is as follows (in millions of dollars): Quarter Ended June 30, 1999 as compared to the quarter ended June 30, 1998
Intersegment Distribution Generation Ventures Corporate Revenues Consolidated ------------ ---------- -------- --------- -------- ------------ Revenues: 1999 $734.0 $653.2 $ .6 $ - $(193.4) $1,194.4 1998 $905.5 $547.7 $ .7 $ - $(238.7) $1,215.2 EBIT (a): 1999 $310.9 $ 11.1 $( 15.1) $( 44.7) $ 262.2 1998 $356.0 $ 61.0 $( 35.8) $( 41.1) $ 340.1 Six Months Ended June 30, 1999 as compared to six months ended June 30, 1998 Revenues: 1999 $1,646.5 $1,197.9 $ 1.2 $ - $(394.8) $2,450.8 1998 $1,854.3 $1,029.6 $ 1.3 $ - $(479.8) $2,405.4 EBIT (a): 1999 $668.0 $ 52.8(b) $( 36.0) $( 81.8) $ 603.0 1998 $663.5 $ 99.0 $( 59.5) $( 87.9) $ 615.1 Total Assets: 1999 $10,825.2(c) $1,868.5 $240.2 $427.2 $13,361.1 1998 $ 9,723.6 $1,680.6 $216.1 $384.1 $12,004.4 (a) EBIT - Earnings Before Interest and Income Taxes. (b) Includes $14.6 million related to the write-off of the investment in Grays Ferry in connection with the settlement of litigation. (c) Includes $750 million of proceeds from securitization of stranded costs.
8 4. EARNINGS PER SHARE Diluted earnings per average common share is calculated by dividing earnings applicable to common stock by the average shares of common stock outstanding after giving effect to stock options, issuable under the Company's stock option plans, considered to be dilutive common stock equivalents. The following table shows the effect of the stock options issuable under the Company's stock option plans on the average number of shares used in calculating diluted earnings per average common share (in millions of shares):
Three Months Ended Six Months Ended June 30, June 30, 1999 1998 1999 1998 ----- ----- ----- ----- Average Common Shares Outstanding 192.0 222.7 207.6 222.6 Assumed Conversion of Stock Options 1.5 .7 1.5 .7 ----- ----- ----- ----- Potential Average Dilutive Common Shares Outstanding 193.5 223.4 209.1 223.3 ===== ===== ===== =====
5. SALES OF ACCOUNTS RECEIVABLE The Company is party to an agreement with a financial institution, under which it can sell or finance with limited recourse an undivided interest, adjusted daily, in up to $275 million of designated accounts receivable until November 2000. At June 30, 1999, the Company had sold a $275 million interest in accounts receivable, consisting of a $232 million interest in accounts receivable which the Company accounts for as a sale under Statement of Financial Accounting Standards (SFAS) No. 125, "Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities," and a $43 million interest in special agreement accounts receivable which are accounted for as a long-term note payable. The Company retains the servicing responsibility for these receivables. The agreement requires the Company to maintain the $275 million interest, which, if not met, requires the Company to deposit cash in order to satisfy such requirements. The Company, at June 30, 1999, met such requirements. At June 30, 1999, the average annual service-charge rate, computed on a daily basis on the portion of the accounts receivable sold but not yet collected, was 4.90%. 6. AMERGEN ENERGY COMPANY On April 15, 1999, AmerGen Energy Company, LLC (AmerGen), the joint venture between the Company and British Energy, plc (British Energy), announced an interim agreement to purchase the Clinton Nuclear Power Station (Clinton) from Illinois Power (IP), a subsidiary of Illinova Corporation. On June 30, 1999, AmerGen and British Energy signed a definitive agreement to purchase Clinton from IP. AmerGen has entered into agreements to purchase Three Mile Island Unit No.1 Nuclear Generating Facility, Nine Mile Point Unit 1 Nuclear Generating Facility and 59% of Nine Mile Point Unit 2 Nuclear Generating Facility. In addition, the Company and IP amended the January 15, 1998 Management Agreement, providing for the provision of certain management services by the Company to IP in support of Clinton's outage recovery efforts and operations. 9 7. CLINTON NUCLEAR POWER STATION Under the Amended Management Agreement, effective April 1, 1999, the Company is responsible for the payment of all direct operating and maintenance (O&M) costs and direct capital costs incurred by IP and allocable to the operation of Clinton. IP will continue to pay indirect costs such as pension benefits, payroll taxes and property taxes. Following the restart of Clinton, which occurred on June 2, 1999, and through December 31, 1999, the Company is selling 80% of the output of Clinton to IP. The remaining output is being sold by the Company in the wholesale market. Under a separate agreement with the Company, British Energy has agreed to share 50% of the costs and revenues associated with the Amended Management Agreement. In the second quarter of 1999, the Company recognized $14 million of revenue from sales to IP and $25 million of O&M expenses related to Clinton. 8. COMMITMENTS AND CONTINGENCIES For information regarding the Company's capital commitments, nuclear insurance, nuclear decommissioning and spent fuel storage, energy commitments, environmental issues and litigation, see note 5 of Notes to Consolidated Financial Statements for the year ended December 31, 1998. At June 30, 1999, the Company had entered into long-term agreements with unaffiliated utilities to purchase transmission rights. These purchase commitments result in obligations of approximately $50 million in 1999, $88 million in 2000, $51 million in 2001, and $41 million in 2002, $36 million in 2003 and $97 million thereafter. The Company has identified 28 sites where former manufactured gas plant (MGP) activities have or may have resulted in actual site contamination. As of June 30, 1999, the Company had accrued $59 million for environmental investigation and remediation costs, including $33 million for MGP investigation and remediation that currently can be reasonably estimated. The Company cannot predict whether it will incur other significant liabilities for additional investigation and remediation costs at these or additional sites identified by the Company, environmental agencies or others, or whether all such costs will be recoverable from third parties. On April 23, 1999, the Company and Grays Ferry Cogeneration Partnership (Grays Ferry) entered into a final settlement of litigation, subject to the resolution of certain issues. The settlement required the Company to contribute its interest in the partnership to the remaining partners. Accordingly, the Company recorded a charge to earnings of $14.6 million for the transfer of its partnership interest. The charge for the partnership interest transfer is recorded in Other Income and Deductions on the Company's Statement of Income for the six months ended June 30, 1999. The settlement also resolved the litigation with Westinghouse Power Generation and The Chase Manhattan Bank. 10 9. NEW ACCOUNTING PRONOUNCEMENTS In June 1998, the Financial Accounting Standards Board (FASB) issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," (SFAS No. 133) to establish accounting and reporting standards for derivatives. The new standard requires recognizing all derivatives as either assets or liabilities on the balance sheet at their fair value and specifies the accounting for changes in fair value depending upon the intended use of the derivative. In June 1999, the FASB issued SFAS No. 137 "Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of FASB Statement No. 133," (SFAS No. 137) which delayed the effective date for SFAS No. 133 until fiscal years beginning after June 15, 2000. The Company expects to adopt SFAS No. 133 in the first quarter of 2001. The Company is in the process of evaluating the impact of SFAS No. 133 on its financial statements. In November 1998, the FASB's Emerging Issues Task Force (EITF) issued EITF 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities." EITF 98-10 outlines attributes that may be indicative of an energy trading operation and gives further guidance on the accounting for contracts entered into by an energy trading operation. This accounting guidance requires mark-to-market accounting for contracts considered to be a trading activity. EITF 98-10 is applicable for fiscal years beginning after December 15, 1998 with any impact recorded as a cumulative effect adjustment through retained earnings at the date of adoption. The Company's wholesale marketing operations enter into long-term and short-term commitments to purchase and sell energy and energy-related products with the intent and ability to deliver or take delivery. The objective of the long-term commitments is to establish a generation base that allows the Company to meet the physical supply and demand requirements of a national wholesale electric marketplace through scheduled, real-time delivery of electricity. The Company utilizes short-term energy commitments and contracts, entered into in the over-the-counter market, to economically hedge seasonal and operational risks associated with peak demand periods and generation plant outages. The Company reviewed the criteria indicative of an energy trading operation as outlined in EITF 98-10 against the objectives and intent of the Company's wholesale marketing operation's activities. The Company concluded that none of the activities of its marketing operation are trading activities and therefore these activities are not subject to EITF 98-10 or mark-to-market accounting. The Company records revenues and expenses associated with the energy commitments at the time the underlying physical transaction closes. Additionally, the Company evaluates its energy commitments for impairment based on the lower of cost or market. At June 30, 1999, the Company concluded that no energy commitments were impaired. 11 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS GENERAL Retail competition for electric generation services began in Pennsylvania on January 1, 1999. As of January 2, 1999, two-thirds of each class of the Company's retail electric customers in its traditional service territory have a right to choose their generation suppliers. Effective January 2, 2000, all of the Company's retail electric customers in its traditional service territory will have the right to choose their generation suppliers. At June 30, 1999, approximately 239,000 customers representing 15% of the Company's residential customers, 25% of its commercial customers and 58% of its industrial customers had selected an alternate energy supplier. As of that date, Exelon Energy, the Company's alternative energy supplier, was providing electric generation service to approximately 141,000 business and residential customers located throughout Pennsylvania. Effective January 1, 1999, the Company reduced its retail electric rates for all customers by 8%. On that date, the Company began recovering its stranded costs through the collection of competitive transition charges from all customers. On March 25, 1999, PECO Energy Transition Trust (PETT), a wholly owned subsidiary of the Company, issued $4 billion of PECO Energy Transition Trust Transition Bonds to securitize a portion of the Company's stranded cost recovery. In accordance with the terms of the Competition Act, the Company is utilizing the proceeds from the issuance of the Transition Bonds principally to reduce stranded costs and capitalization. The Company currently estimates that the impact of additional interest expense associated with the Transition Bonds partially offset by interest savings related to higher cost debt retired with Transition Bond proceeds, combined with the anticipated reduction in common equity, will result in earnings per share benefits of approximately $.15 and $.50 in 1999 and 2000, respectively. These estimated earnings per share could change and are largely dependent upon the timing and price of common stock repurchases and anticipated net income available to common stock. The Company expects that competition for both retail and wholesale generation services will substantially affect its future results of operations. See "Management's Discussion and Analysis of Financial Condition and Results of Operations - Outlook," incorporated by reference in the Company's Annual Report on Form 10-K for the year ended December 31, 1998. The Company's internal reporting structure consists of its distribution, generation, and ventures operations. The Company's distribution business unit includes its electric transmission and distribution services, regulated retail sales of generation services and retail gas businesses. The Company's generation business unit includes the operation of its generation assets, its power marketing group and its unregulated retail energy supplier. The Company's ventures business unit includes its infrastructure services business and its telecommunications equity investments. 12 RESULTS OF OPERATIONS The Company's Condensed Consolidated Statements of Income for the three and six months ended June 30, 1998 reflect the reclassification of the results of operations of Exelon Energy, from Other Income and Deductions. Under its Amended Management Agreement with Illinois Power (IP), effective April 1, 1999, the Company is responsible for the payment of all direct operating and maintenance (O&M) costs and direct capital costs incurred by IP and allocable to the operation of Clinton Nuclear Power Station (Clinton). IP will continue to pay indirect costs such as pension benefits, payroll taxes and property taxes. Following the restart of Clinton, which occurred on June 2,1999, and through December 31, 1999, the Company is selling 80% of the output of Clinton to IP. The remaining output is being sold by the Company in the wholesale market. Under a separate agreement with the Company, British Energy has agreed to share 50% of the costs and revenues associated with the Amended Management Agreement.
Revenue and Expense Items as a Percentage of Total Operating Revenues Percentage Dollar Changes 1999 vs. 1998 Quarter Six Months Quarter Six Months Ended Ended Ended Ended June 30, June 30, June 30, June 30, 1999 1998 1999 1998 93% 93% 87% 89% Electric (2%) --% 7% 7% 13% 11% Gas 7% 13% ---- ---- ---- ---- 100% 100% 100% 100% Total Operating Revenues (2%) 2% ---- ---- ---- ---- 42% 30% 39% 31% Fuel and Energy Interchange 39% 30% 28% 21% 26% 22% Operating and Maintenance 32% 16% 5% 13% 5% 13% Depreciation and Amortization (64%) (64%) 4% 6% 5% 6% Taxes Other Than Income (37%) (22%) ---- ---- ---- ---- 79% 70% 75% 72% Total Operating Expenses 11% 4% ---- ---- ---- ---- 21% 30% 25% 28% Operating Income (31%) (5%) ---- ---- ---- ---- (10%) (8%) (8%) (8%) Interest Charges 28% 8% 1% (2%) (1%) (2%) Other Income and Deductions 136% 19% ---- ---- ---- ---- Income Before Income Taxes and 12% 20% 16% 18% Extraordinary Item (42%) (6%) 4% 8% 6% 7% Income Taxes (50%) (8%) ---- ---- ---- ---- 8% 12% 10% 11% Income Before Extraordinary Item (2%) -- (1%) -- Extraordinary Item 100% --% ---- ---- ---- ---- 6% 12% 9% 11% Net Income (54%) (15%) ==== ==== ==== ====
13 Second Quarter 1999 Compared To Second Quarter 1998 Operating Revenues Electric revenues decreased $26 million, or 2%, for the quarter ended June 30, 1999 compared to the same 1998 period. The decrease was primarily attributable to lower revenues from the distribution business unit of $176 million partially offset by higher revenues from the generation business unit of $150 million. The decrease from the distribution business unit was attributable to $136 million as a result of lower volume associated with the effects of competition, $65 million related to the 8% across-the-board rate reduction mandated by the Final Restructuring Order and $12 million related to decreased sales volume from milder weather conditions as compared to the prior year comparable period. These decreases were partially offset by $37 million of PJM Interconnection, LLC (PJM) network transmission service revenue which commenced April 1, 1998. PJM network transmission service revenues and charges were recorded in the generation business unit in 1998 but are being recognized by the distribution business unit in 1999 as a result of the Federal Energy Regulatory Commission approval of the PJM Regional Transmission Owners' rate case settlements. Stranded cost recovery is included in the Company's retail electric rates beginning January 1, 1999. The increase from the generation business unit was attributable to $117 million from increased volume in Pennsylvania resulting from the sale of competitive electric generation services by Exelon Energy, increased wholesale revenues of $58 million from the marketing of excess generation capacity as a result of retail competition and $14 million from the sale of generation from Clinton to IP, partially offset by $39 million of PJM network transmission service revenue in the comparable period. Gas revenues increased $6 million, or 7%, for the quarter ended June 30, 1999 compared to the same 1998 period. The increase was primarily attributable to $4 million from increased volume as a result of cooler weather conditions in the beginning of the quarter and $2 million from increased volume from new and existing customers. Fuel and Energy Interchange Expense Fuel and energy interchange expense increased $140 million, or 39%, for the quarter ended June 30, 1999 compared to the same 1998 period. As a percentage of revenue, fuel and interchange expenses were 42% as compared to 30% in the comparable prior year period. These increases were attributable to higher fuel and energy interchange expenses associated with the generation business unit of $83 million and the distribution business unit of $57 million. The increase from the generation business unit was primarily attributable to $129 million related to increased volume from Exelon Energy sales, partially offset by lower PJM network transmission service charges of $39 million and $3 million of fuel savings associated with the full return to service of the Salem Generating Station (Salem) in April 1998 which decreased the need to purchase power to replace the output from these units. The increase from the distribution business unit was attributable to $24 million of PJM network transmission service charges, $46 million of purchases in the spot market and $10 million of additional gas purchases as a result of higher volume associated with cooler weather early in the quarter and additional volume to new and existing customers. These increases were partially offset by $23 million of lower fuel costs primarily as a result of lower volume associated with Customer Choice. 14 Operating and Maintenance Expense Operating and maintenance (O&M) expense increased $83 million, or 32% for the quarter ended June 30, 1999 compared to the same 1998 period. As a percentage of revenue, operating and maintenance expenses were 28% as compared to 21% in the comparable prior year period. The generation business unit's O&M expenses increased $58 million as a result of $25 million related to the revised Clinton management agreement, $8 million associated with the Salem inventory write-off for excess and obsolete inventory, $7 million related to the true-up of 1998 reimbursement of joint-owner expenses and $15 million related to the growth of unregulated retail sales of electricity. The distribution unit's O&M expenses increased approximately $22 million as a result of additional marketing expenses and expenses associated with Customer Choice. In addition, the Company incurred additional costs of approximately $11 million related to nuclear property insurance and $4 million associated with Year 2000 remediation expenditures, partially offset by $10 million of pension credits as a result of the performance of the investments in the Company's pension plan. Depreciation and Amortization Expense Depreciation and amortization expense decreased $103 million, or 64%, for the quarter ended June 30, 1999 compared to the same 1998 period. As a percentage of revenue, depreciation and amortization expense was 5% as compared to 13% in the comparable prior year period. The decrease was associated with the December 1997 restructuring charge through which the Company wrote down a significant portion of its generating plant and regulatory assets. In connection with this restructuring charge, the Company reduced generation-related assets by $8.4 billion, established a regulatory asset, Deferred Generation Costs Recoverable in Current Rates of $424 million, which was fully amortized in 1998, and established an additional regulatory asset, Competitive Transition Charge (CTC) of $5.26 billion which will begin to be amortized in accordance with the terms of the Final Restructuring Order in 2000. For additional information, see "PART I, ITEM 1. - BUSINESS - Deregulation and Rate Matters," in the Company's 1998 Annual Report on Form 10-K. Taxes Other Than Income Taxes other than income decreased $27 million, or 37%, for the quarter ended June 30, 1999 compared to the same 1998 period. As a percentage of revenue, taxes other than income were 4%, as compared to 6%, in the comparable prior year period. The decrease was primarily attributable to a $26 million credit related to an adjustment to the Company's Pennsylvania capital stock tax base as a result of the 1997 restructuring charge and lower gross receipts tax of $3 million associated with lower retail electric and gas sales. Interest Charges Interest charges consist of interest expense, distributions on Company Obligated Mandatorily Redeemable Preferred Securities of a Partnership (COMPRS) and Allowance for Funds Used During Construction (AFUDC). Interest charges increased $26 million, or 28%, for the quarter ended June 30, 1999 compared to the same 1998 period. As a percentage of revenue, interest charges were 10% as compared to 8% in the comparable prior year period. The increase was primarily attributable to interest on the Transition Bonds of $60 million, partially offset by the Company's ongoing program to reduce and/or refinance higher cost, long-term debt, including the use of a portion of the proceeds from the issuance of Transition Bonds, which reduced interest charges by $34 million. 15 Other Income and Deductions Other income and deductions excluding interest charges was a gain of $10 million for the quarter ended June 30, 1999 as compared to a loss of $27 million in the same 1998 period. The decrease of $37 million was primarily attributable to a $10 milion write-off of a non-regulated business venture in the prior year period, a $5 million improvement in the performances of the Company's equity investments in telecommunications and interest income of $14 million earned on the unused portion of the transition bond proceeds. Income Taxes The effective tax rate was 32.8% for the quarter ended June 30, 1999 as compared to 38.4% in the same 1998 period. The decrease in the effective tax rate was a result of tax benefits associated with the implementation of state tax planning strategies, partially offset by the non-recognition for state income tax purposes of certain operating losses. In addition, the disproportionate relationship of regulated plant tax adjustments to income before income taxes and extraordinary item contributed to the decrease in the effective tax rate. Extraordinary Item During the second quarter of 1999, the Company incurred an extraordinary charge of $26.7 million, net of tax, consisting of prepayment premiums and the write-off of unamortized deferred financing costs associated with the early retirement of debt with a portion of the proceeds from the issuance of Transition Bonds. Preferred Stock Dividends Preferred stock dividends for the quarter ended June 30, 1999 were consistent with the same 1998 period. Six Months Ended June 30, 1999 Compared to Six Months Ended June 30, 1998 Operating Revenues Electric revenues increased $10 million for the six months ended June 30, 1999 compared to the same 1998 period. The increase was primarily attributable to higher revenues from the generation business unit of $256 million partially offset by lower revenues from the distribution business unit of $246 million. The increase from the generation business unit was attributable to $204 million from increased volume in Pennsylvania resulting from the sale of competitive electric generation services by Exelon Energy, increased wholesale revenues of $77 million from the marketing of excess generation capacity as a result of retail competition and $14 million from the sale of generation from Clinton to IP, partially offset by $39 million of PJM network transmission service revenue in the comparable 1998 period. The decrease from the distribution business unit was attributable to $205 million as a result of lower volume associated with the effects of retail competition and $120 million related to the 8% across-the-board rate reduction mandated by the Final Restructuring Order. These decreases were partially offset by $74 million of PJM network transmission service revenue and $5 million related to increased sales volume as a result of colder weather conditions in the first quarter of 1999 partially offset by milder weather conditions in the second quarter of 1999 as compared to the prior year periods. 16 Gas revenues increased $36 million, or 13%, for the six months ended June 30, 1999 compared to the same 1998 period. The increase was primarily attributable to $24 million from increased volume as a result of cooler weather conditions in the beginning of the period as compared to the prior year period and $12 million from increased volume from new and existing customers. Fuel and Energy Interchange Expense Fuel and energy interchange expense increased $210 million, or 28%, for the six months ended June 30, 1999 compared to the same 1998 period. As a percentage of revenue, fuel and interchange expenses were 39% as compared to 31% in the comparable prior year period. These increases were attributable to higher fuel and energy interchange expenses associated with the distribution business unit of $119 million and the generation business unit of $91 million. The increase from the distribution business unit was primarily attributable to $51 million of PJM network transmission service charges, $99 million of purchases in the spot market and $21 million of additional gas purchases as a result of higher volume associated with cooler weather early in the period and additional volume to new and existing customers. These increase were partially offset by $55 million of lower fuel costs as a result of lower volume associated with Customer Choice. The increase from the generation business unit was primarily attributable to $200 million related to increased volume from Exelon Energy sales, partially offset by $45 million of lower fuel costs as a result of lower volume, lower PJM network transmission service charges of $39 million, and $19 million of fuel savings associated with the full return to service of the Salem Generating Station (Salem) in April 1998 which decreased the need to purchase power to replace the output from these units. Operating and Maintenance Expense O&M expense increased $88 million, or 16% for the six months ended June 30, 1999 compared to the same 1998 period. As a percentage of revenue, operating and maintenance expenses were 26% as compared to 22% in the comparable prior year period. The generation business unit's O&M expenses increased $50 million as a result of $25 million related to the revised Clinton management agreement, $8 million associated with the Salem inventory write-off for excess and obsolete inventory, $7 million related to the true-up of 1998 reimbursement of joint-owner expenses and $10 million related to the growth of unregulated retail sales of electricity, partially offset by $10 million of lower O&M expenses as a result of the full return to service of Salem in April 1998. The distribution unit's O&M expenses increased approximately $22 million as a result of additional marketing expenses and expenses associated with Customer Choice. In addition, the Company incurred additional costs of approximately $11 million related to nuclear property insurance and $16 million associated with Year 2000 remediation expenditures, partially offset by $10 million of pension credits as a result of the performance of the investments in the Company's pension plan. Depreciation and Amortization Expense Depreciation and amortization expense decreased $202 million, or 64%, for the six months ended June 30, 1999 compared to the same 1998 period. As a percentage of revenue, depreciation and amortization expense was 5% as compared to 13% in the comparable prior year period. The decrease was associated with the December 1997 restructuring charge through which the Company wrote down a significant portion of its generating plant and regulatory assets. 17 Taxes Other Than Income Taxes other than income decreased $33 million, or 22%, for the six months ended June 30, 1999 compared to the same 1998 period. As a percentage of revenue, taxes other than income were 5%, as compared to 6%, in the comparable prior year period. The decrease was primarily attributable to a $30 million credit related to an adjustment to the Company's Pennsylvania capital stock tax base as a result of the 1997 restructuring charge and lower gross receipts tax of $6 million associated with lower retail electric and gas sales. Interest Charges Interest charges increased $15 million, or 8%, for the six months ended June 30, 1999 compared to the same 1998 period. As a percentage of revenue, interest charges were comparable to the prior year period at 8%. The increase was primarily attributable to interest on the Transition Bonds of $60 million, partially offset by the Company's ongoing program to reduce and/or refinance higher cost, long-term debt, including the use of a portion of the proceeds from the issuance of Transition Bonds, which reduced interest charges by $45 million. Other Income and Deductions Other income and deductions excluding interest charges was a loss of $32 million for the six months ended June 30, 1999 as compared to a loss of $40 million in the same 1998 period. The decrease of $8 million was primarily attributable a $10 million write-off of a non-regulated business venture in the prior year period, a $3 million improvement in the performance of the Company's equity investments in telecommunications ventures and interest income of $14 million earned on the unused portion of the transition bond proceeds, partially offset by a $15 million write-off of the investment in Grays Ferry in connection with the settlement of litigation and a charge related to the abandonment of an investment system of $7 million. Income Taxes The effective tax rate was 37% for the six months ended June 30, 1999 as compared to 38% in the same 1998 period. The decrease in the effective tax rate was a result of tax benefits associated with the implementation of state tax planning strategies, partially offset by the non-recognition for state income tax purposes of certain operating losses. In addition, the disproportionate relationship of regulated plant tax adjustments to income before income taxes and extraordinary item contributed to the decrease in the effective tax rate. Extraordinary Item During the second quarter of 1999, the Company incurred an extraordinary charge of $26.7 million, net of tax, consisting of prepayment premiums and the write-off of unamortized deferred financing costs associated with the early retirement of debt with a portion of the proceeds from the issuance of Transition Bonds. Preferred Stock Dividends Preferred stock dividends for the six months ended June 30, 1999 were consistent with the same 1998 period. 18 DISCUSSION OF LIQUIDITY AND CAPITAL RESOURCES Cash flows provided by operating activities decreased $244 million to $266 million for the six months ended June 30, 1999 as compared to $510 million in the same 1998 period. The decrease was primarily attributable to less cash generated by operations of $192 million and changes in working capital of $63 million, principally related to accounts receivable from unregulated energy sales. Cash flows used by investing activities were $279 million for the six months ended June 30, 1999 as compared to $265 million in the comparable 1998 period and consisted primarily of capital expenditures for plant. Cash flows provided by financing activities were $879 million for the six months ended June 30, 1999, as compared to cash used in financing activities of $173 million in the comparable prior year period. The increase was attributable to the issuance of $4 billion of Transition Bonds by PETT partially offset by the repayment of short-term and long-term debt aggregating $1.5 billion and the application of $1.5 billion of Transition Bond proceeds to the repurchase of common stock, including the settlement of the Company's common stock forward purchase contract. On March 25, 1999, PETT issued $4 billion of its Transition Bonds to securitize a portion of the Company's authorized stranded cost recovery. The Transition Bonds are solely obligations of PETT, secured by the Intangible Transition Property (ITP) sold by the Company to PETT. Upon issuance of the Transition Bonds, a portion of the competitive transition charges to be collected by the Company to recover stranded costs was designated as Intangible Transition Charges (ITC). The ITC is an irrevocable non-bypassable usage based charge that is calculated to allow for the recovery of debt service and costs related to the issuance of the Transition Bonds. The ITC will be allocated from CTC and variable distribution charges (both of which are usage based charges). PETT used the $3.95 billion of proceeds of the Transition Bonds to purchase the ITP from the Company. Although the Transition Bonds are solely obligations of PETT, they are included in the consolidated long-term debt of the Company. In accordance with the terms of the Competition Act, the Company is utilizing the proceeds principally to reduce stranded costs and capitalization. The Company currently plans to reduce its capitalization in the following proportions: fixed and floating-rate debt, 50%; preferred securities, 7%; common equity, 43%. Through June 30, 1999, the Company utilized the net proceeds to repurchase 38.7 million shares of Common Stock for an aggregate purchase price of $1.507 billion; to retire: $811 million of First Mortgage Bonds, a $400 million term loan, $208 million of commercial paper, $150 million of accounts receivable financing and a $139 million capital lease obligation; to repurchase $9 million of Company Obligated Mandatorily Redeemable Preferred Securities of a Partnership (COMRPS); and to pay $25 million of debt issuance costs. The remaining proceeds of approximately $750 million are included in cash at June 30, 1999. In addition, on July 30, 1999, the Company redeemed $212 million of COMRPS. On August 2, 1999, the Company retired $37 million of Mandatorily Redeemable Preferred Stock pursuant to the sinking fund requirements of those securities. The Company currently anticipates that it will complete the repurchase of common equity through open market purchases from time to time in compliance with Securities and Exchange Commission rules. The number of shares purchased and the timing and manner or purchases are dependent upon market conditions. 19 Although the Company has sold the ITP to PETT, the ITC revenue, as well as all interest expense and amortization expense associated with the Transition Bonds, is reflected on the Company's Consolidated Statement of Income. The combined schedule for amortization of the CTC and ITC assets is in accordance with the amortization schedule set forth in the Final Restructuring Order. As a result of the issuance of the Transition Bonds and the on-going capital reduction by the Company, the Company expects its debt-to-total capital ratio to be 60%, exclusive of the Transition Bonds, upon completion of the application of the proceeds from securitization. The Company completed the majority of the targeted debt and preferred security reductions by August 2, 1999, and expects that the remaining reductions will be completed by December 31, 1999. The weighted average cost of debt and preferred securities to be retired is approximately 6.8%. The additional interest expense associated with the Transition Bonds, which have an effective interest rate of approximately 5.8%, will be partially offset by the anticipated interest savings associated with the debt and preferred securities that will be retired. The Company currently estimates that the impact of this additional expense, combined with the anticipated reduction in common equity, will result in earnings per share benefits of approximately $.15 and $.50 in 1999 and 2000, respectively. These estimated earnings per share could change and are largely dependent upon the timing and price of common stock repurchases and anticipated net income available to common stock. At June 30, 1999, the Company had outstanding $226 million of notes payable, all of which were commercial paper. In addition, at June 30, 1999, the Company had formal and informal lines of bank credit aggregating $100 million. At June 30, 1999, the Company had no short-term investments. On May 3, 1999, Standard & Poor's upgraded its ratings on the Company's overall corporate credit to "A-" from "BBB+", first and refunding mortgage bonds and collateralized medium-term notes to "A" from "BBB+", hybrid preferred securities, capital trust securities and preferred stock to "BBB" from "BBB-". As of June 30, 1999, the Company paid $20 million of separation benefits pursuant to its Early Retirement and Separation Program initiated in 1998. Retirement benefits are being paid to the retirees over their lives. Of the 1,157 employees, 306 were eligible for and have taken the retirement incentive program and 346 employees were terminated with the enhanced severance benefit program. The remaining employees are scheduled for termination through June 2000. YEAR 2000 READINESS DISCLOSURE The Year 2000 Project (Y2K Project) is addressing the issue resulting from computer programs using two digits rather than four to define the applicable year and other programming techniques that constrain date calculations or assign special meanings to certain dates. Any of the Company's computer systems that have date-sensitive software or microprocessors may recognize a date using "00" as the year 1900 rather than the year 2000. This could result in a system failure or miscalculations causing disruptions of operations, including, a temporary inability to process transactions, send bills, operate generating stations, or engage in similar normal business activities. Due to the severity of the potential impact of the Year 2000 Issue (Y2K Issue) on the electric utility industry, the Company adopted a comprehensive schedule to achieve Y2K readiness by the time specified by the Nuclear Regulatory Commission (NRC). The Company has dedicated extensive resources to the Project and believes it is progressing on schedule. 20 The Company determined that it was required to modify, convert or replace significant portions of its software and a subset of its system hardware and embedded technology so that its computer systems will properly utilize dates beyond December 31, 1999. The Company presently believes that with these modifications, conversions and replacements the effect of the Y2K Issue on the Company can be mitigated. If such modifications, conversions and replacements are not made, or are not completed in a timely manner, the Y2K Issue could have a material impact on the operations and financial condition of the Company. The costs associated with this potential impact are not presently quantifiable. The Company is utilizing both internal and external resources to reprogram, or replace and test software and computer systems for the Project. The Project was scheduled for completion by July 1, 1999, except for a small number of modifications, conversions or replacements that are impacted by PUC changes, vendor dates and/or are being incorporated into scheduled plant outages between July and November 1999. The scheduled Project completion date was met, with the limited anticipated exceptions noted above. The Project is divided into four major sections - Information Technology Systems (IT Systems), Embedded Technology (devices used to control, monitor or assist the operation of equipment, machinery or plant), Supply Chain (third-party suppliers and customers), and Contingency Planning. The general phases common to the first two sections are: (1) inventorying Y2K items; (2) assigning priorities to identified items; (3) assessing the Y2K readiness of items determined to be material to the Company; (4) converting material items that are determined not to be Y2K ready; (5) testing material items; and (6) designing and implementing contingency plans for each critical Company process. Material items are those believed by the Company to have a risk involving the safety of individuals, may cause damage to property or the environment, or affect revenues. The IT Systems section includes both the conversion of applications software that is not Y2K ready and the replacement of software when available from the supplier. The Project has identified 363 critical systems of which 234 are IT Systems and 129 Embedded Systems. The current readiness status of IT Systems is set forth below: Number of Systems Progress Status 233 Systems Y2K Ready 1 System In Testing Contingency planning for IT Systems has been completed. The remaining 129 systems are the Embedded Systems consisting of hardware and systems software other than IT Systems. The current readiness status of those systems is set forth below: Number of Systems Progress Status 120 Systems Y2K Ready 9 Systems In Progress Contingency planning for Embedded Technology has been completed. 21 The Supply Chain section includes the process of identifying and prioritizing critical suppliers and communicating with them about their plans and progress in addressing the Y2K Issue. The process of evaluating critical suppliers was completed on March 31, 1999. The Company has completed contingency plans for all critical suppliers. In addition to addressing contingency plans with key suppliers, the Company is currently developing contingency plans to address how to respond to internal events which may disrupt normal operations. These plans address Y2K risk scenarios that cross departments and business units. Emergency plans already exist that cover various aspects of the Company's business. These plans are being reviewed and updated to address the Y2K Issue. The Company is also participating in industry contingency planning efforts. The estimated total cost of the Project is $75 million, the majority of which is attributable to testing. This estimate includes the Company's share of Y2K costs for jointly owned facilities. The total amount expended on the Project through June 30, 1999 was $44 million. The Company expects to fund the Project from operating cash flows. The Company's failure to become Y2K ready could result in an interruption in or a failure of certain normal business activities or operations. In addition, there can be no assurance that the systems of other companies on which the Company's systems rely or with which they communicate will be converted in a timely manner, or that a failure to convert by another company, or a conversion that is incompatible with the Company's systems, will not have a material adverse effect on the Company. Such failures could materially and adversely affect the Company's results of operations, liquidity and financial condition. The Company is currently developing contingency plans to address how to respond to events that may disrupt normal operations, including activities with PJM. The costs of the Project and the date on which the Company plans to complete the Y2K modifications are based on estimates, that were derived utilizing numerous assumptions of future events, including the continued availability of certain resources, third-party modification plans and other factors, such as regulatory requirements that impact key systems. There can be no assurance that these estimates will be achieved. Actual results could differ materially from the projections. Specific factors that might cause a material change include, but are not limited to, the availability and cost of trained personnel, the ability to locate and correct all relevant computer programs and microprocessors. The Project is expected to significantly reduce the Company's level of uncertainty about the Y2K Issue. The Company believes that the completion of the Project, as scheduled, minimizes the possibility of significant interruptions of normal operations. On July 17, 1998, an order was entered by the PUC instituting a formal investigation by the Office of Administrative Law on Year 2000 compliance by jurisdictional fixed utilities and mission-critical service providers such as the PJM (the Investigation). The order requires, (1) a written response to a list of compliance program questions by August 6, 1998 and, (2) all jurisdictional fixed utilities be Year 2000 compliant by March 31, 1999 or, if a utility determines that mission-critical systems cannot be Year 2000 compliant on or before March 31, 1999, the utility is required to file a detailed contingency plan. The PUC adopted the federal government's definition for Year 2000 compliance and further defined Year 2000 compliance as a jurisdictional 22 utility having all mission-critical Year 2000 hardware and software updates and/or replacements installed and tested on or before March 31, 1999. On August 6, 1998, the Company filed its written response, in which the Company stated that with a few carefully-assessed and closely-managed exceptions, the Company will have all mission-critical systems Year 2000 ready by June 1999. Pursuant to the formal investigation on Year 2000 compliance, the Company presented testimony before the PUC on November 20, 1998. On February 19, 1999, the PUC issued a Secretarial Letter notifying the Company that it had hired a consultant to perform an assessment of the Company and thirteen other utilities to evaluate the accuracy of their responses to the compliance program questions and testimony provided before the PUC. The Company complied with the PUC's directive in the Secretarial Letter to file updated written responses to compliance questions by March 8, 1999, and to meet with the consultant during a one-day on-site review session on March 8, 1999. On March 31, 1999, the Company filed contingency plans with the PUC for its mission-critical systems scheduled to be ready after the March 31, 1999 deadline. On April 8, 1999, the PUC issued an order requiring the Office of Administrative Law Judge to identify (i) utilities which have complied with the PUC's order of July 17, 1998 (the Order); (ii) utilities which have demonstrated good cause for an extension of time within which they will fully comply with the Order; and (iii) those utilities which have not complied with the Order and have not shown good cause for an extension. The PUC required that this information be posted to the PUC internet website and periodically updated. The PUC further ordered that the Investigation with respect to utilities who have demonstrated good cause for an extension of time remain open and under the jurisdiction of the Office of Administrative Law Judge until compliance is achieved or enforcement is warranted. PECO Energy has been identified by the PUC as a utility which has demonstrated good cause for an extension of time within which it will fully comply with the Order. Additional reporting dates to the Administrative Law Judge include July 1, 1999 and October 1, 1999. On May 11, 1998, the NRC issued a generic letter requiring all nuclear plant operators to provide the NRC with the following information concerning the operators' programs, planned or implemented, to address Year 2000 computer and system issues at its facilities: (1) submission of a written response within 90 days, indicating whether the operator has pursued and continues to pursue implementation of Year 2000 programs and addressing the program's scope, assessment process, plans for corrective actions, quality assurance measures, contingency plans and regulatory compliance, and (2) submission of a written response, no later than July 1, 1999, confirming that such facilities are Year 2000 ready, or will be Year 2000 ready, by the year 2000 with regard to compliance with the terms and conditions of the license(s) and NRC regulations. On July 30, 1998, the Company filed its 90-day required written response indicating that the Company has pursued and is continuing to pursue a Year 2000 program which is similar to that outlined in Nuclear Utility Year 2000 Readiness, NEI/NUSMG 97.07. From November 3 to November 5, 1998, members of the NRC staff conducted an audit of the Company's Year 2000 Program for the Limerick Generating Station, Units No. 1 and No. 2. Some of the observations of the audit team included in their written report issued on December 18, 1998, were that (1) the Company's readiness program is comprehensive and based on the guidance contained in 23 NEI/NUSMG 97.07, (2) the program is receiving proper management support and oversight, and (3) project schedules are being aggressively pursued. On April 28, 1999, the NRC issued Information Notice 99-12 advising nuclear power plant licensees that NRC staff would be conducting additional Year 2000 readiness and contingency planning site-specific reviews at all commercial nuclear power plants. The NRC performed its site-specific review of Peach Bottom from May 24 to May 28, 1999, and its review of Limerick from June 7 to June 10, 1999. On June 30, 1999, PECO Energy filed its completed response to Generic Letter 98-01. In the response, PECO Energy confirmed that with the exception of five non-safety plant systems, its Peach Bottom Atomic Power Station and Limerick Generating Stations are Year 2000 ready. The Company advised the NRC that remediation for three of the remaining systems is scheduled for completion by September 30, 1999, and remediation for the other two systems is scheduled to occur during planned plant outages in September 1999. For additional information regarding the Year 2000 Readiness Disclosure see "Management's Discussion and Analysis of Financial Condition and Results of Operations" in the Company's Annual Report to Shareholders for the year 1998. FORWARD-LOOKING STATEMENTS Except for the historical information contained herein, certain of the matters discussed in this Report are forward-looking statements, including the estimated earnings per share benefits of the application of the Transition Bond proceeds for 1999 and 2000, and accordingly, are subject to risks and uncertainties. The factors that could cause actual results to differ materially include those discussed herein as well as those listed in notes 2, 8 and 9 of Notes to Condensed Consolidated Financial Statements and other factors discussed in the Company's filings with the SEC. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this Report. The Company undertakes no obligation to publicly release any revision to these forward-looking statements to reflect events or circumstances after the date of this Report. ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK The Company has entered into interest rate swaps to manage interest rate exposure associated with the issuance of two floating rate series of Transition Bonds. At June 30, 1999, the fair value of these instruments was $52 million based on the present value difference between the contracted rate (i.e., hedged rate) and the market rates at that date. A hypothetical 50 basis point increase or decrease in the spot yield at June 30, 1999 would have resulted in an aggregate fair value of these interest rate swaps of $91.2 million or $10.7 million, respectively. If the derivative instruments had been terminated at June 30, 1999, these estimated fair values represent the amount to be paid by the counterparties to the Company. 24 The Company's growing market share in the retail and wholesale electric marketplace increases the Company's reliance on the efficient operation of its generating units. The Company's ability to fully capitalize on volatile wholesale market prices is also dependent on the performance of the Company's generating units. 25 PART II - OTHER INFORMATION ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS Information regarding the submission of matters to a vote of security holders is presented in the March 31, 1999 Form 10-Q. ITEM 5. OTHER INFORMATION As previously reported in the 1998 Form 10-K, the NRC issued a confirmatory order modifying the license for Limerick Generating Station (Limerick) Units No. 1 and No. 2 requiring that the Company complete final implementation of corrective actions on the Thermo-Lag 330 issue by completion of the April 1999 refueling outage of Limerick Unit No. 2. By letter dated May 3, 1999, the NRC approved the Company's request to extend the completion of Thermo-lag corrective actions at Limerick until September 30, 1999. As previously reported in the 1998 Form 10-K, in October 1990, General Electric Company (GE) reported that crack indications were discovered near the seam welds of the core shroud assembly in a GE Boiling Water Reactor (BWR) located outside the United States. As a result, GE issued a letter requesting that the owners of GE BWRs take interim corrective actions, including a review of fabrication records and visual examinations of accessible areas of the core shroud seam welds. Each of the reactors at Limerick and Peach Bottom is a GE BWR. In accordance with industry experience and guidance, initial examination of Limerick Unit No. 2 was completed during the April 1999 refueling outage. Although crack indications were identified, the results of the inspections and evaluations conclude that the condition of the Limerick Unit No. 2 core shroud, projected through at least the next operating cycle, will support the required safety margins, specified in the ASME code and reinforced by industry recommendations. As previously reported in the 1998 Form 10-K, as a result of several BWRs experiencing clogging of some emergency core cooling system suction strainers, which are part of the water supply system for emergency cooling of the reactor core, the NRC issued a Bulletin in May 1996 to operators of BWRs requesting that measures be taken to minimize the potential for clogging. The NRC proposed three resolution options, including the installation of large capacity passive strainers, with a request that actions be completed by the end of the unit's first refueling outage after January 1997. Strainers were installed at Peach Bottom Unit No. 3 during the October 1997 refueling outage. Strainers were installed at Peach Bottom Unit No. 2 and Limerick Unit No. 1 during their refueling outages in October 1998 and April 1998, respectively. Strainers were installed at Limerick Unit No. 2 during the April 1999 refueling outage. The Company cannot predict what other actions, if any, the NRC may take in this matter. On June 22, 1999, Pennsylvania Governor Tom Ridge signed into law the Natural Gas Choice and Competition Act ("Act") which expands choice of gas suppliers to residential and small commercial customers and eliminates the five percent gross receipts tax on gas distribution companies' sales of gas. Large commercial and industrial customers have been able to choose their suppliers since 1984. Currently, approximately one-third of the Company's total yearly throughput is supplied by third parties. 26 The Act permits gas distribution companies to continue to make regulated sales of gas to their customers. The Act does not deregulate the transportation service provided by gas distribution companies which remains subject to rate regulation. Gas distribution companies will continue to provide billing, metering, installation, maintenance and emergency response services. In compliance with the schedule ordered by the Public Utility Commission ("PUC"), the Company must file with the PUC by December 2, 1999 a restructuring plan for the implementation of gas deregulation and customer choice of gas service suppliers in its service territory (Restructuring Plan). The Company expects gas to flow on its system pursuant to customer choice on July 1, 2000. The Company is currently analyzing the impact of the Act on its operations. The Company believes the impact on the Company would not be material because of the PUC's existing requirement that gas distribution companies cannot collect more than the actual cost of gas from customers, and the Act's requirement that suppliers must accept assignment or release, at contract rates, the portion of the gas distribution company's firm interstate pipeline contracts required to serve the suppliers' customers. ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (a) Exhibits: 27 - Financial Data Schedule. (b) Reports on Form 8-K filed during the reporting period: Report, dated April 15, 1999 reporting information under "ITEM 5. OTHER EVENTS" regarding AmerGen Energy Company, LLC, the joint venture between the Company and British Energy, Inc., signing an interim agreement to purchase the Clinton Nuclear Power Station from Illinois Power (IP), a subsidiary of Illinova Corporation. Report, dated June 24, 1999 reporting information under "ITEM 5. OTHER EVENTS" regarding AmerGen's signing a definitive agreement to purchase the Nine Mile Point Unit 1 Nuclear Generating Facility from Niagara Mohawk Power Corporation (NIMO), a subsidiary of Niagara Mohawk Holdings, Inc. AmerGen has also entered into an agreement to purchase NIMO's 41% ownership interest in Nine Mile Point Unit 2 Nuclear Generating Facility (NMP-2) and New York State Electric and Gas Corp.'s (NYSEG) 18% interest in NMP-2. NYSEG is a wholly owned subsidiary of Energy East, Inc. Reports on Form 8-K filed subsequent to the reporting period: Report, dated July 1, 1999 reporting information under "ITEM 5. OTHER EVENTS" regarding AmerGen's signing a definitive asset purchase agreement to purchase Clinton. 27 Signatures Pursuant to 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. PECO ENERGY COMPANY /s/ Michael J. Egan MICHAEL J. EGAN Vice President and Senior Vice President and Chief Financial Officer (Chief Accounting Officer) Date: April 6, 2000 28 EX-27 2
UT 1,000,000 6-MOS DEC-31-1999 JUN-30-1999 PER-BOOK 4,838 555 1,792 5,972 205 13,361 2,109 1 (407) 1,703 93 138 6,092 0 0 226 146 0 1 0 4,968 13,361 2,451 155 1,816 1,966 485 (32) 453 203 226 7 220 103 188 266 1.06 1.06
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