-----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, SVv0t+1dyITTOOFqzE6tdx6rQk+2FmQIxFId3fUMCS4Hmk2bw68M2Rf/kxeHy17n 6y2dGTSpmUNFLCJmT+HFqg== 0000950132-99-001001.txt : 19991117 0000950132-99-001001.hdr.sgml : 19991117 ACCESSION NUMBER: 0000950132-99-001001 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 4 CONFORMED PERIOD OF REPORT: 19990930 FILED AS OF DATE: 19991115 FILER: COMPANY DATA: COMPANY CONFORMED NAME: DQE INC CENTRAL INDEX KEY: 0000846930 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 251598483 STATE OF INCORPORATION: PA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: SEC FILE NUMBER: 001-10290 FILM NUMBER: 99752357 BUSINESS ADDRESS: STREET 1: CHERRINGTON CORPORATE CENTER SUITE 100 STREET 2: 500 CHERRINGTON PARKWAY CITY: CORAOPOLIS STATE: PA ZIP: 15108-3184 BUSINESS PHONE: 4122624700 MAIL ADDRESS: STREET 1: CHERRINGTON CORPORATE CENTER SUITE 100 STREET 2: 500 CHERRINGTON PARKWAY CITY: CORAOPOLIS STATE: PA ZIP: 15108-3184 10-Q 1 QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, DC 20549 FORM 10-Q [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Quarterly Period Ended September 30, 1999 ---------------------- [_] Transition Report Pursuant to Section 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Transition Period From to ------------------ ------------------ Commission File Number ---------------------- 1-10290 DQE, Inc. --------- (Exact name of registrant as specified in its charter) Pennsylvania 25-1598483 ------------ ---------- (State or other jurisdiction of (I.R.S. Employer Identification No.) incorporation or organization) Cherrington Corporate Center, Suite 100 500 Cherrington Parkway, Coraopolis, Pennsylvania 15108-3184 ------------------------------------------------------------- (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: (412) 269-0700 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 report), 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: DQE Common Stock, no par value - 75,313,376 shares outstanding as of September 30, 1999 and 73,905,219 shares outstanding as of October 31, 1999. PART I. FINANCIAL INFORMATION Item 1. Financial Statements DQE CONDENSED STATEMENT OF CONSOLIDATED INCOME (Thousands, Except Per Share Amounts) (Unaudited)
Three Months Ended Nine Months Ended September 30, September 30, ------------------------------- ---------------------------------- 1999 1998 1999 1998 ------------ ------------ ------------ ------------- Operating Revenues Sales of Electricity $ 321,967 $ 313,346 $ 842,889 $ 862,661 Other 76,278 41,352 209,012 94,322 ------------ ------------ ------------ ------------ Total Operating Revenues 398,245 354,698 1,051,901 956,983 ------------ ------------ ------------ ------------ Operating Expenses Fuel and purchased power 84,341 85,335 180,921 216,443 Other operating 125,874 92,633 344,186 246,651 Maintenance 18,426 23,321 62,197 59,273 Depreciation and amortization 65,086 37,644 175,972 152,478 Taxes other than income taxes 25,280 21,095 71,200 60,702 Total Operating Expenses 319,007 260,028 834,476 735,547 ------------ ------------ ------------ ------------ OPERATING INCOME 79,238 94,670 217,425 221,436 ------------ ------------ ------------ ------------ Other Income 36,681 20,145 109,015 79,692 ------------ ------------ ------------ ------------ Interest and Other Charges 40,526 27,609 115,244 82,540 ------------ ------------ ------------ ------------ INCOME Before Income Taxes And Extraordinary Item 75,393 87,206 211,196 218,588 ------------ ------------ ------------ ------------ Income Taxes 26,176 25,137 71,908 71,185 ------------ ------------ ------------ ------------ INCOME Before Extraordinary Item 49,217 62,069 139,288 147,403 Extraordinary Item (Net of Tax) -- -- -- (82,548) ------------ ------------ ------------ ------------ NET INCOME After Extraordinary Item $ 49,217 $ 62,069 $ 139,288 $ 64,855 ============ ============ ============ ============ DIVIDENDS ON PREFERRED STOCK 425 -- 1,153 -- ------------ ------------ ------------ ------------ EARNINGS AVAILABLE FOR COMMON STOCK $ 48,792 $ 62,069 $ 138,135 $ 64,855 ============ ============ ============ ============ AVERAGE NUMBER OF COMMON SHARES OUTSTANDING 75,356 77,743 76,110 77,716 ============ ============ ============ ============ BASIC EARNINGS (LOSS) PER SHARE OF COMMON STOCK: Before Extraordinary Item $ 0.64 $ 0.80 $ 1.81 $ 1.90 ============ ============ ============ ============ Extraordinary Item $ -- $ -- $ -- $ (1.06) ============ ============ ============ ============ After Extraordinary Item $ 0.64 $ 0.80 $ 1.81 $ 0.84 ============ ============ ============ ============ DILUTED EARNINGS (LOSS) PER SHARE OF COMMON STOCK: Before Extraordinary Item $ 0.63 $ 0.78 $ 1.77 $ 1.86 ============ ============ ============ ============ Extraordinary Item $ -- $ -- $ -- $ (1.04) ============ ============ ============ ============ After Extraordinary Item $ 0.63 $ 0.78 $ 1.77 $ 0.82 ============ ============ ============ ============ DIVIDENDS DECLARED PER SHARE OF COMMON STOCK $ 0.38 $ 0.36 $ 1.14 $ 1.08 ============ ============ ============ ============
See notes to condensed consolidated financial statements. 2 DQE CONDENSED CONSOLIDATED BALANCE SHEET (Thousands of Dollars) (Unaudited)
September 30, December 31, 1999 1998 ----------------- ------------------- ASSETS Current assets: Cash and temporary cash investments $ 99,248 $ 108,790 Receivables 147,733 165,794 Other current assets, principally materials and supplies 172,331 100,168 ---------------- ---------------- Total current assets 419,312 374,752 ---------------- ---------------- Long-term investments 732,813 750,796 ---------------- ---------------- Property, plant and equipment 4,902,264 4,884,138 Less: Accumulated depreciation and amortization (3,146,913) (3,167,328) ---------------- ---------------- Property, plant and equipment - net 1,755,351 1,716,810 ---------------- ---------------- Other non-current assets: Transition costs 1,977,305 2,132,980 Regulatory assets 61,031 64,568 Other 351,293 207,657 ---------------- ---------------- Total other non-current assets 2,389,629 2,405,205 ---------------- ---------------- TOTAL ASSETS $ 5,297,105 $ 5,247,563 ================ ================ LIABILITIES AND CAPITALIZATION Notes payable and current maturities $ 280,199 $ 100,822 ---------------- ---------------- Other current liabilities 162,717 253,442 ---------------- ---------------- Deferred income taxes - net 813,516 777,017 ---------------- ---------------- Deferred income 138,390 156,579 ---------------- ---------------- Beaver Valley lease liability 475,570 475,570 ---------------- ---------------- Other non-current liabilities 334,537 371,653 ---------------- ---------------- Commitments and contingencies (Note 4) Capitalization: Long-term debt 1,367,072 1,364,879 ---------------- ---------------- Preferred and preference stock of subsidiaries 229,237 228,282 ---------------- ---------------- Preferred stock 43,786 35,274 ---------------- ---------------- Common shareholders' equity: Common stock - no par value (authorized - 187,500,000 shares; issued - 109,679,154 shares) 994,965 994,996 Retained earnings 921,156 869,671 Less treasury stock (at cost) (34,365,778 and 32,305,726 shares, respectively) (469,391) (385,976) Accumulated other comprehensive income 5,351 5,354 ---------------- ---------------- Total common shareholders' equity 1,452,081 1,484,045 ---------------- ---------------- Total capitalization 3,092,176 3,112,480 ---------------- ---------------- TOTAL LIABILITIES AND CAPITALIZATION $ 5,297,105 $ 5,247,563 ================ ================
See notes to condensed consolidated financial statements. 3 DQE CONDENSED STATEMENT OF CONSOLIDATED CASH FLOWS (Thousands of Dollars) (Unaudited)
Nine Months Ended September 30, ---------------------------------------- 1999 1998 -------------- -------------- Cash Flows From Operating Activities Operations $ 332,694 $ 364,610 Purchase of nuclear fuel (40,109) -- Changes in working capital other than cash (6,970) (119,450) Increase in ECR -- (19,219) Other (3,883) 17,519 -------------- -------------- Net Cash Provided By Operating Activities 281,732 243,460 -------------- -------------- Cash Flows From Investing Activities Acquisition of water companies (142,496) (40,961) Capital expenditures (102,768) (118,955) Long-term investments (25,500) (50,862) Acquisition of propane companies (17,315) -- Payment of funding obligations (14,057) -- Proceeds from the sale of investments 49,297 -- Proceeds from the sale of property 31,863 1,063 Other (24,871) (28,740) -------------- -------------- Net Cash Used in Investing Activities (245,847) (238,455) -------------- -------------- Cash Flows From Financing Activities Dividends on common stock (86,650) (83,929) Repurchase of common stock (83,415) -- Reductions of long term obligations - net (70,946) (36,732) Increase in notes payable 226,233 4,375 Other (30,649) (7,690) -------------- -------------- Net Cash Used in Financing Activities (45,427) (123,976) -------------- -------------- Net decrease in cash and temporary cash investments (9,542) (118,971) Cash and temporary cash investments at beginning of period 108,790 356,412 -------------- -------------- Cash and temporary cash investments at end of period $ 99,248 $ 237,441 ============== ============== Non-Cash Investing and Financing Activities Preferred stock issued in conjunction with long-term investments $ 8,634 $ 25,056 ============== ============== Capital lease obligations recorded $ 6,470 $ 5,011 ============== ============== Equity funding obligations recorded $ 812 $ -- ============== ==============
See notes to condensed consolidated financial statements. 4 DQE STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME (Thousands of Dollars) (Unaudited)
Three Months Ended Nine Months Ended September 30, September 30, 1999 1998 1999 1998 ------------ ------------- ------------ ------------- NET INCOME AFTER EXTRAORDINARY ITEM $ 49,217 $ 62,069 $ 139,288 $ 64,855 Other Comprehensive (Loss) Income: Unrealized holding (losses) gains net of tax of $(208), $(1,396), $994 and $(2,114), respectively (294) (1,930) 1,401 (2,980) Less: reclassification adjustment for gains included in net income, net of tax of $0, $0, $756 and $0, respectively -- -- (1,404) -- ------------ ------------- ------------ ------------- Total Other Comprehensive (Loss) Income (294) (1,930) (3) (2,980) ------------ ------------- ------------ ------------- Comprehensive Income $ 48,923 $ 60,139 $ 139,285 $ 61,875 ============ ============= ============ =============
See notes to condensed consolidated financial statements. NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) 1. CONSOLIDATION, RECLASSIFICATIONS AND ACCOUNTING POLICIES DQE, Inc. (DQE) is a multi-utility delivery and services company. Its subsidiaries are Duquesne Light Company (Duquesne); AquaSource, Inc. (AquaSource); DQE Capital Corporation (DQE Capital); DQE Energy Services, Inc. (DES); DQEnergy Partners, Inc. (DQEnergy); Duquesne Enterprises, Inc. (DE); and Montauk, Inc. (Montauk). DQE and its subsidiaries are collectively referred to as "the Company." The Company's largest subsidiary, Duquesne, is an electric utility engaged in the generation, transmission, distribution and sale of electric energy. The Company's expanded business lines offer a wide range of energy-related technologies, industrial and commercial energy services, telecommunications and other complementary services. The expanded business lines' initiatives also include a water resource management company that acquires, develops and manages water and wastewater utilities, energy facility development and operation, domestic and international independent power production, the production and distribution of landfill gas, propane and synthetic fuels, investments in communications systems and electronic commerce, and long-term investments. DQE Capital provides financing for the expanded business lines. The Company plans to divest itself of its generation assets through the pending exchange of certain power station assets with FirstEnergy Corporation (FirstEnergy) and the pending sale of generation assets to Orion Power Holdings, Inc. (Orion). Final agreements governing the sale to Orion must be approved by various regulatory agencies, including the Pennsylvania Public Utility Commission (PUC). The Company currently expects these transactions to close in December 1999 and the second quarter of 2000, respectively. (See "Rate Matters", Note 2, on page 7.) All material intercompany balances and transactions have been eliminated in the preparation of the condensed consolidated financial statements. 5 In the opinion of management, the unaudited condensed consolidated financial statements included in this report reflect all adjustments that are necessary for a fair presentation of the results of interim periods and are normal, recurring adjustments. Prior periods have been reclassified to conform with current accounting presentations. These statements should be read with the financial statements and notes included in the Annual Report on Form 10-K filed with the Securities and Exchange Commission (SEC) for the year ended December 31, 1998. The results of operations for the three and nine months ended September 30, 1999, are not necessarily indicative of the results that may be expected for the full year. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements. The reported amounts of revenues and expenses during the reporting period may also be affected by the estimates and assumptions management is required to make. Actual results could differ from those estimates. The Company is subject to the accounting and reporting requirements of the SEC. In addition, the Company's electric utility operations are subject to regulation by the PUC, including regulation under the Pennsylvania Electricity Generation Customer Choice and Competition Act (Customer Choice Act), and the Federal Energy Regulatory Commission (FERC) under the Federal Power Act with respect to rates for interstate sales, transmission of electric power, accounting and other matters. The Company's water utility operations are subject to regulation by the utility regulatory bodies in their respective states. As a result of the PUC's May 29, 1998, final order regarding the Company's restructuring plan under the Customer Choice Act (see "Rate Matters," Note 2, on page 7), the electricity generation portion of the Company's business does not meet the criteria of Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation (SFAS No. 71). Accordingly, fixed assets related to the generation portion of the Company's business are evaluated in accordance with SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of (SFAS No. 121). Pursuant to the PUC's final restructuring order, certain of the Company's generation-related regulatory assets are being recovered through a competitive transition charge (CTC) collected in connection with providing transmission and distribution services (the electricity delivery business segment), and have been reclassified accordingly. Additionally, pursuant to the PUC's final restructuring order, the Company is recovering its above-market investment in generation assets through the CTC, subject to receipt of the proceeds from the generation asset auction. The electricity delivery business segment continues to meet SFAS No. 71 criteria and accordingly reflects regulatory assets and liabilities consistent with cost-based ratemaking regulations. The regulatory assets represent probable future revenue to the Company, because provisions for these costs are currently included, or are expected to be included, in charges to electric utility customers through the ratemaking process. (See "Rate Matters," Note 2, on page 7.) Through the Energy Cost Rate Adjustment Clause (ECR), the Company previously recovered (to the extent that such amounts were not included in base rates) nuclear fuel, fossil fuel and purchased power expenses. Also through the ECR, the Company passed to its customers the profits from short-term power sales to other utilities (collectively, ECR energy costs). As a consequence of the PUC's final order regarding the Company's restructuring plan (see "Rate Matters," Note 2, on page 7), such costs are no longer recoverable through the ECR. Instead, effective May 29, 1998 (the date of the PUC's final restructuring order), such costs are expensed as incurred and thus impact net income. (See "Restructuring Plan" discussion, Note 2, on page 8.) 6 The Company's long-term investments include assets of nuclear decommissioning trusts and marketable securities accounted for in accordance with SFAS No. 115, Accounting for Certain Investments in Debt and Equity Securities. These investments are classified as available-for-sale and are stated at market value. The amounts of unrealized holding gains related to marketable securities were $9.1 million ($5.4 million, net of tax) at September 30, 1999, and $8.9 million ($5.4 million, net of tax) at December 31, 1998. (See "Power Station Exchange" discussion, Note 2, on page 8.) 2. RATE MATTERS Competition and the Customer Choice Act Under historical ratemaking practice, regulated electric utilities were granted exclusive geographic franchises to sell electricity, in exchange for making investments and incurring obligations to serve customers under the then- existing regulatory framework. Through the ratemaking process, those prudently incurred costs were recovered from customers, along with a return on the investment. Additionally, certain operating costs were approved for deferral for future recovery from customers (regulatory assets). As a result of this process, utilities had assets recorded on their balance sheets at above-market costs, thus creating transition costs. In Pennsylvania, the Customer Choice Act went into effect on January 1, 1997. The Customer Choice Act enables Pennsylvania's electric utility customers to purchase electricity at market prices from a variety of electric generation suppliers (customer choice). Although the Customer Choice Act will give customers their choice of electric generation suppliers, the existing, franchised local distribution utility is still responsible for delivering electricity from the generation supplier to the customer. The local distribution utility is also required to serve as the provider of last resort for all customers in its service territory, unless other arrangements are approved by the PUC. The provider of last resort must provide electricity for any customer who cannot or does not choose an alternative electric generation supplier, or whose supplier fails to deliver. The Customer Choice Act provides that the existing franchised utility may recover, through a CTC, an amount of transition costs that are determined by the PUC to be just and reasonable. Pennsylvania's electric utility restructuring is being accomplished through a two-stage process consisting of an initial customer choice pilot period (which ended in December 1998) and a phase-in to competition period (which began in January 1999). Phase-In to Competition Currently 66 percent of customers are eligible to participate in customer choice (including customers covered by the pilot program); all customers will have customer choice in January 2000. As of September 30, 1999, approximately 17 percent of the Company's customers had chosen alternative generation suppliers, representing approximately 22 percent of the Company's non-coincident peak load. Customers that have chosen an electricity generation supplier other than the Company pay that supplier for generation charges, and pay the Company the CTC (discussed below) and charges for transmission and distribution. Customers that continue to buy their generation from the Company pay for their service at current regulated tariff rates divided into generation, transmission and distribution charges, and the CTC. Under the Customer Choice Act, an electric distribution company, such as Duquesne, remains a regulated utility and may only offer PUC-approved rates, including generation rates. Also under the Customer Choice Act, electricity delivery (including transmission, distribution and customer service) remains regulated in substantially the same manner as under historical regulation. In an effort to "jumpstart" competition, Duquesne had made 600 megawatts (MW) of power available through the first six months of 1999 to licensed electric generation suppliers, to be used to supply electricity to Duquesne's customers who had chosen alternative generation suppliers. 7 Rate Cap An overall four-and-one-half-year rate cap from January 1, 1997, was originally imposed on the transmission and distribution charges of Pennsylvania electric utility companies under the Customer Choice Act. As part of a settlement regarding recovery of deferred fuel costs (discussed below), the Company has agreed to extend this rate cap for an additional six months through the end of 2001. Additionally, electric utility companies may not increase the generation price component of rates as long as transition costs are being recovered, with certain exceptions. Restructuring Plan In its May 29, 1998, final restructuring order, the PUC determined that the Company should recover most of the above-market costs of the generation assets, including plant and regulatory assets through the collection of the CTC from electric utility customers. The $1.49 billion, net of tax, of transition costs was originally to be recovered over a seven-year period ending in 2005. However, by applying expected net proceeds of the generation asset auction (discussed below) to reduce transition costs, the Company currently anticipates early termination of the CTC collection period in 2001 for most major rate classes. In addition, the transition costs as reflected on the consolidated balance sheet are being amortized over the same period that the CTC revenues are being recognized. The Company is allowed to earn an 11 percent pre-tax return on the unrecovered, net of tax balance of transition costs, as adjusted following the generation asset auction. As part of its restructuring plan filing, the Company requested recovery of $11.5 million ($6.7 million, net of tax) through the CTC for energy costs previously deferred under the ECR. Recovery of this amount was approved in the PUC's final restructuring order. The Company also requested recovery of an additional $31.2 million ($18.2 million, net of tax) in deferred fuel costs. On December 18, 1998, the PUC denied recovery of this additional amount. The Company appealed the PUC's denial of recovery to the Pennsylvania Commonwealth Court. On October 26, 1999, the Company and the Pennsylvania Office of the Consumer Advocate reached a settlement on this issue which would permit recovery of the entire $42.7 million ($24.9 million, net of tax) in deferred fuel costs. The PUC's decision on this settlement is pending. Auction Plan. On December 18, 1998, the PUC approved Duquesne's auction plan, including a purchased power agreement covering Duquesne's obligations for its provider of last resort service, as well as an agreement in principle to exchange certain generation assets with FirstEnergy. On September 24, 1999, Duquesne and the winning auction bidder, Orion, entered into definitive agreements pursuant to which Orion will purchase Duquesne's wholly owned Cheswick, Elrama, Phillips and Brunot Island power stations, and the stations to be received from FirstEnergy in the power station exchange described below, for approximately $1.71 billion. Under the purchased power agreement, Orion will supply all of the electric energy requirements for Duquesne's customers who have not chosen an alternative generation supplier (provider of last resort service). This agreement, which expires upon Duquesne's final collection of the CTC, effectively transfers to Orion all of the financial risks and rewards associated with electricity supply. The purchase must be approved by various regulatory agencies, including the PUC, the FERC, and the Federal Trade Commission. Duquesne currently expects the sale to close in the second quarter of 2000. Although Duquesne expects to apply the net auction proceeds to reduce transition costs, until the divestiture is complete, Duquesne has been ordered to use an interim CTC and price to compare for each rate class based on the methodology approved in its pilot program (on average, approximately 2.9 cents per kilowatt hour (KWH) for the CTC and approximately 3.8 cents per KWH for the price to compare). Power Station Exchange. Pursuant to the definitive agreements entered into on March 25, 1999, Duquesne and FirstEnergy will exchange ownership interests in certain power stations. Duquesne will receive 100 percent ownership rights in three fossil-fired power plants located in Avon Lake and Niles, Ohio and New Castle, Pennsylvania (totaling approximately 1,300 MW), which the Company plans to sell as part of the auction of generation assets. FirstEnergy will acquire Duquesne's interests in Beaver Valley Unit 1 (BV Unit 1), Beaver Valley Unit 2 (BV Unit 2), Perry Unit 1, Sammis Unit 7, Eastlake Unit 5 and Bruce Mansfield Units 1, 2 and 3 (totaling approximately 8 1,400 MW). In connection with the power station exchange, the Company anticipates terminating the BV Unit 2 lease in the fourth quarter of 1999. (See "Financing" discussion on page 23.) Pursuant to the December 18, 1998, PUC order and subject to final approval, the proceeds from the sale to Orion of the power stations received in the exchange will be used to offset the transition costs associated with Duquesne's currently-held generation assets and costs associated with completing the exchange. Benefits of this exchange include the resolution of all joint ownership issues, and other ongoing risks and costs associated with the jointly-owned units. The Federal Trade Commission approved the exchange on June 30, 1999. The PUC approved the definitive exchange agreement on July 15, 1999, having found the exchange to be in the public interest. On September 15, 1999, the FERC approved the exchange. On September 30, 1999, the NRC approved the transfer of the BV Unit 1 and BV Unit 2 operating licenses, as well as Duquesne's ownership interest in Perry, to FirstEnergy. The Public Utilities Commission of Ohio approved the exchange agreement on October 28, 1999. The power station exchange is expected to occur in December 1999. (See "Legal Proceedings" on page 31.) Termination of the AYE Merger On October 5, 1998, the Company announced its unilateral termination of the merger agreement with Allegheny Energy, Inc. (AYE). The Company believes that AYE suffered a material adverse effect as a result of the PUC's final restructuring order regarding AYE's utility subsidiary, West Penn Power Company. AYE filed suit in the United States District Court for the Western District of Pennsylvania, seeking to compel the Company to proceed with the merger and seeking a temporary restraining order and preliminary injunction to prevent the Company from certain actions pending a trial, or in the alternative seeking an unspecified amount of money damages. Trial was held from October 20 through 28, 1999. Post-trial pleadings were filed November 10, 1999, and closing arguments are scheduled for November 23, 1999. The Company expects the judge's decision prior to the scheduled closing of the power station exchange in December. (See "Legal Proceedings" on page 31.) In a letter dated February 24, 1999, the PUC informed the Company that the merger application was deemed withdrawn and the docket was closed. 3. RECEIVABLES The components of receivables for the periods indicated are as follows:
September 30, September 30, December 31, 1999 1998 1998 (Amounts in Thousands of Dollars) - --------------------------------------------------------------------------------------------------------------- Electric customer accounts receivable $ 97,005 $ 99,608 $ 87,262 Water customer accounts receivable 28,364 3,328 10,591 Other utility receivables 27,733 28,306 25,412 Other receivables 54,581 50,398 51,944 Less: Allowance for uncollectible accounts (9,950) (15,281) (9,415) - --------------------------------------------------------------------------------------------------------------- Receivables less allowance for uncollectible accounts 197,733 166,359 165,794 Less: Receivables sold (electric customer accounts) (50,000) -- -- =============================================================================================================== Total Receivables $147,733 $166,359 $165,794 ===============================================================================================================
The Company and an unaffiliated corporation have an agreement that entitles the Company to sell and the corporation to purchase, on an ongoing basis, up to $50 million of accounts receivable. The accounts receivable sales agreement, the expiration of which has been extended until February 2000, is one of many sources of funds available to the Company. The Company currently anticipates further extending the agreement or replacing it with a similar arrangement upon expiration. At September 30, 1999, the Company had sold $50 million of receivables. At September 30 and December 31, 1998, the Company had not sold any receivables. 9 4. COMMITMENTS AND CONTINGENCIES The Company anticipates divesting itself of its generation assets, through the power station exchange with FirstEnergy in December 1999 and the sale to Orion in the second quarter of 2000 and, depending on the regulatory approvals of the final agreements regarding the divestiture, expects certain obligations related to the divested assets will be transferred to the future owners. (See "Restructuring Plan" discussion, Note 2, on page 8.) Construction The Company currently estimates that during 1999 it will spend, excluding the Allowance for Funds Used During Construction and nuclear fuel, approximately $110 million for electric utility construction, including $30 million for generation, and approximately $35 million for water utility construction. Nuclear-Related Matters The Company has an interest in three nuclear units, two of which it operates. The operation of a nuclear facility involves special risks, potential liabilities, and specific regulatory and safety requirements. Specific information about risk management and potential liabilities is discussed below. Nuclear Decommissioning. As part of the power station exchange, FirstEnergy has agreed to assume the decommissioning liability for each of the nuclear plants in exchange for the balance in the decommissioning trust funds described below, plus the decommissioning costs to be collected through the CTC, as approved by the PUC. The Company expects BV Unit 1, BV Unit 2 and Perry Unit 1 will be decommissioned no earlier than the expiration of each plant's operating license in 2016, 2027 and 2026, respectively. At the end of its operating life, BV Unit 1 may be placed in safe storage until BV Unit 2 is ready to be decommissioned, at which time the units may be decommissioned together. Based on site-specific studies conducted in 1997 for BV Unit 1 and BV Unit 2, and a 1997 update of the 1994 study for Perry Unit 1, the Company's approximate share of the total estimated decommissioning costs, including removal and decontamination costs, would be $170 million, $55 million and $90 million, respectively. The amount currently used to determine the Company's cost of service related to decommissioning all three nuclear units is $224 million. Funding for nuclear decommissioning costs is deposited in external, segregated trust accounts and invested in a portfolio of corporate common stock and debt securities, municipal bonds, certificates of deposit and United States government securities. The market value of the aggregate trust fund balances at September 30, 1999, totaled approximately $69.8 million. Nuclear Insurance. The Price-Anderson Amendments to the Atomic Energy Act of 1954 limit public liability from a single incident at a nuclear plant to $9.7 billion. The maximum available private primary insurance of $200 million has been purchased by the Company. Additional protection of $9.5 billion would be provided by an assessment of up to $88.1 million per incident on each licensed nuclear unit in the United States. The Company's maximum total possible assessment, $66.1 million, which is based on its ownership or leasehold interests in three nuclear generating units, would be limited to a maximum of $7.5 million per incident per year. This assessment is subject to indexing for inflation and may be subject to state premium taxes. If assessments from the nuclear industry prove insufficient to pay claims, the United States Congress could impose other revenue-raising measures on the industry. The Company's share of insurance coverage for property damage, decommissioning and decontamination liability is $1.2 billion. The Company would be responsible for its share of any damages in excess of insurance coverage. In addition, if the property damage reserves of Nuclear Electric Insurance Limited (NEIL), an industry mutual insurance company that provides a portion of this coverage, are inadequate to cover claims arising from an incident at any United States nuclear site covered by that insurer, the Company could be assessed retrospective premiums totaling a maximum of $7.9 million. The Company also participates in a NEIL program that provides insurance for the increased cost of generation and/or purchased power resulting from an accidental outage of a nuclear unit. Subject to the policy deductible, terms and limit, the coverage provides for a 10 weekly indemnity of the estimated incremental costs during a period of approximately three years, starting 12 weeks after an accident, with no coverage thereafter. If NEIL's losses for this program ever exceed its reserves, the Company could be assessed retrospective premiums totaling a maximum of $2.9 million. Beaver Valley Power Station (BVPS). BVPS's two units are equipped with steam generators designed and built by Westinghouse Electric Corporation (Westinghouse). Similar to other Westinghouse nuclear plants, outside diameter stress corrosion cracking (ODSCC) has occurred in the steam generator tubes of both units. BV Unit 1, which was placed in service in 1976, has removed approximately 17 percent of its steam generator tubes from service through a process called "plugging." However, BV Unit 1 still has the capability to operate at 100 percent reactor power and has the ability to return tubes to service by repairing them through a process called "sleeving." No tubes at either BV Unit 1 or BV Unit 2 have been sleeved to date. BV Unit 2, which was placed in service 11 years after BV Unit 1, has not yet exhibited the degree of ODSCC experienced at BV Unit 1. Approximately 3 percent of BV Unit 2's tubes are plugged; however, it is too early in the life of the unit to determine the extent to which ODSCC may become a problem at that unit. The Company has undertaken certain measures, such as increased inspections, water chemistry control and tube plugging, to minimize the operational impact of and reduce susceptibility to ODSCC. Although the Company has taken these steps to allay the effects of ODSCC, the inherent potential for future ODSCC in steam generator tubes of the Westinghouse design still exists. Material acceleration in the rate of ODSCC could lead to a loss of plant efficiency, significant repairs or the possible replacement of the BV Unit 1 steam generators. The total replacement cost of the BV Unit 1 steam generators is currently estimated at $125 million. Based on its current ownership interest in BV Unit 1, the Company would be responsible for $59 million of this total, which includes the cost of equipment removal and replacement steam generators, but excludes replacement power costs. The earliest that the BV Unit 1 steam generators could be replaced during a currently scheduled refueling outage is the spring of 2003. Spent Nuclear Fuel Disposal. The Nuclear Waste Policy Act of 1982 established a federal policy for handling and disposing of spent nuclear fuel and a policy requiring the establishment of a final repository to accept spent nuclear fuel. Electric utility companies have entered into contracts with the United States Department of Energy (DOE) for the permanent disposal of spent nuclear fuel and high-level radioactive waste in compliance with this legislation. The DOE has indicated that its repository under these contracts will not be available for acceptance of spent nuclear fuel before 2010. The DOE has not yet established an interim or permanent storage facility, despite a ruling by the United States Court of Appeals for the District of Columbia Circuit that the DOE was legally obligated to begin acceptance of spent nuclear fuel for disposal by January 31, 1998. Existing on-site spent nuclear fuel storage capacities at BV Unit 1, BV Unit 2 and Perry Unit 1 are expected to be sufficient until 2018, 2012 and 2011, respectively. In early 1997, the Company joined 35 other electric utilities and 46 states, state agencies and regulatory commissions in filing suit in the United States Court of Appeals for the District of Columbia Circuit against the DOE. The parties requested the court to suspend the utilities' payments into the Nuclear Waste Fund and to place future payments into an escrow account until the DOE fulfills its obligation to accept spent nuclear fuel. The DOE had requested that the court delay litigation while it pursued alternative dispute resolution under the terms of its contracts with the utilities. The court ruling, issued November 14, 1997, and affirmed on rehearing May 5, 1998, denied the relief requested by the utilities and states and permitted the DOE to pursue alternative dispute resolution, but prohibited the DOE from using its lack of a spent fuel repository as a defense. The United States Supreme Court declined to review the decision. The utilities' remaining remedies are to sue the DOE in federal court for money damages caused by the DOE's delay in fulfilling its obligations, or to pursue an equitable contract adjustment before the DOE contracting officer. Duquesne has elected not to participate in further litigation regarding this matter. Pursuant to the power station exchange, FirstEnergy will assume responsibility for disposal of the spent fuel. 11 Uranium Enrichment Obligations. Nuclear reactor licensees in the United States are assessed annually for the decontamination and decommissioning of DOE uranium enrichment facilities. Assessments are based on the amount of uranium a utility had processed for enrichment prior to enactment of the National Energy Policy Act of 1992, and are to be paid by such utilities over a 15-year period. At September 30, 1999, the Company's liability for contributions is being recovered through the CTC as part of transition costs. Guarantees The Company and the other owners of Bruce Mansfield Power Station (Bruce Mansfield) have guaranteed certain debt and lease obligations related to a coal supply contract for Bruce Mansfield. At September 30, 1999, the Company's share of these guarantees was $4.5 million. These guarantees expire in January 2000. As part of the Company's investment portfolio in affordable housing, the Company has received fees in exchange for guaranteeing a minimum defined yield to third-party investors. A portion of the fees received has been deferred to absorb any required payments with respect to these transactions. Based on an evaluation of and recent experience with the underlying housing projects, the Company believes that such deferrals are ample for this purpose. Environmental Matters Various Federal and state authorities regulate the Company concerning air and water quality and other environmental matters. With respect to its electric utility operations and non-water related expanded business lines, the Company believes it is in current compliance with all material applicable environmental regulations. On November 3, 1999, the Environmental Protection Agency and the Department of Justice filed suit against seven electric utility companies, including FirstEnergy. The suit alleges that the companies made illegal modifications to certain power plants, including Sammis, which is operated by FirstEnergy. Although not a party to the suit, Duquesne is currently a partial owner of Sammis Unit 7 (one of the interests to be acquired by FirstEnergy in the power station exchange). The ultimate outcome of this suit, and any potential impact it may have on Duquesne, cannot be determined at this time. With respect to Federal water regulations, AquaSource recently met the water quality reporting requirement under the Safe Drinking Water Act by timely providing reports to all of its customers. In connection with its acquisition strategy, AquaSource is aware of various compliance issues at its water and wastewater facilities, and is communicating and working closely with the appropriate regulators to correct those issues in a timely manner. The Company does not believe that any of these compliance issues will have a material effect on its financial position, results of operations or cash flows. Employees As previously reported, in connection with the anticipated divestiture, Duquesne has developed early retirement programs and enhanced separation packages. To date, approximately 250 eligible employees have elected to participate in early retirement. Other The Company is involved in various other legal proceedings and environmental matters. The Company believes that such proceedings and matters, in total, will not have a materially adverse effect on its financial position, results of operations or cash flows. 12 5. Business Segments and Related Information Historically, Duquesne has been treated as a single integrated business segment due to its regulated operating environment. The PUC authorized a combined rate for supplying and delivering electricity to customers which was cost-based and was designed to recover the Company's operating expenses and investment in electric utility assets and to provide a return on the investment. As a result of the Customer Choice Act, generation of electricity is deregulated and charged at a separate rate from the delivery of electricity beginning in 1999. For the purposes of complying with SFAS No. 131, Disclosures about Segments of an Enterprise and Related Information (SFAS No. 131), the Company is required to disclose information about its business segments separately. Accordingly, the Company has used the PUC-approved separate rates for 1999 to develop the financial information of the business segments for the three and nine months ended September 30, 1998 (or as of December 31, 1998, with respect to assets). Beginning in 1999, the Company has three principal business segments (determined by products, services and regulatory environment) which consist of the transmission and distribution by Duquesne of electricity (electricity delivery business segment); the generation by Duquesne of electricity (electricity generation business segment); and the collection of transition costs (CTC business segment). To comply with SFAS No. 131, the Company has reported the results for 1999 by these business segments and an "all other" category. The all other category in the following table includes the expanded business lines and Duquesne investments below the quantitative threshold for separate disclosure. These expanded business lines include water utilities, energy products and services, electronic commerce, and other activities. Intercompany eliminations primarily relate to intercompany sales of electricity, property rental, management fees and dividends. However, as the Company was not yet collecting transition costs prior to 1999, the 1998 results are reported by the electricity delivery and electricity generation business segments. Financial data for business segments is provided as follows: 13 Business Segments for the Three Months Ended
September 30, 1999 (Thousands of Dollars) - ------------------------------------------------------------------------------------------------------------------------------ Electricity Electricity All Elimina- Delivery Generation CTC Other tions Consolidated ------------------------------------------------------------------------------------------------- Operating revenues $ 95,848 $ 129,742 $ 107,840 $ 65,868 $ (1,053) $ 398,245 Operating expenses 41,812 139,656 4,745 70,853 (3,145) 253,921 Depreciation and amortization expense 7,830 2,466 46,075 8,715 -- 65,086 - ------------------------------------------------------------------------------------------------------------------------------ Operating income (loss) 46,206 (12,380) 57,020 (13,700) 2,092 79,238 Other income (loss) 512 942 -- 40,525 (5,298) 36,681 Interest and other charges 9,065 11,772 11,908 10,399 (2,618) 40,526 - ------------------------------------------------------------------------------------------------------------------------------ Income (loss) before taxes 37,653 (23,210) 45,112 16,426 (588) 75,393 Income taxes 13,660 (11,631) 18,721 5,426 -- 26,176 - ------------------------------------------------------------------------------------------------------------------------------ Net income (loss) $ 23,993 $ (11,579) $ 26,391 $ 11,000 $ (588) $ 49,217 ============================================================================================================================== Assets $ 1,297,693 $ 561,111 $ 1,977,305 $ 1,460,996 $ -- $ 5,297,105 ============================================================================================================================== Capital expenditures $ 10,446 $ 6,748 $ -- $ 14,219 $ -- $ 31,413 ==============================================================================================================================
September 30, 1998 (Thousands of Dollars) - --------------------------------------------------------------------------------------------------------------------- Electricity Electricity All Elimina- Delivery Generation Other tions Consolidated ----------------------------------------------------------------------------------- Operating revenues $ 89,250 $ 237,724 $ 30,679 $ (2,955) $ 354,698 Operating expenses 41,195 158,302 26,314 (3,427) 222,384 Depreciation and amortization expense 14,265 21,347 2,032 -- 37,644 - --------------------------------------------------------------------------------------------------------------------- Operating income 33,790 58,075 2,333 472 94,670 Other income (loss) 1,310 2,306 17,928 (1,399) 20,145 Interest and other charges 9,332 14,505 4,128 (356) 27,609 - --------------------------------------------------------------------------------------------------------------------- Income (loss) before taxes 25,768 45,876 16,133 (571) 87,206 Income taxes 10,063 18,103 (3,029) -- 25,137 - --------------------------------------------------------------------------------------------------------------------- Net income (loss) $ 15,705 $ 27,773 $ 19,162 $ (571) $ 62,069 ===================================================================================================================== Assets (1) $ 1,314,266 $ 2,711,533 $ 1,221,764 $ -- $ 5,247,563 ===================================================================================================================== Capital expenditures $ 21,509 $ 12,920 $ 15,821 $ -- $ 50,250 =====================================================================================================================
(1) Relates to assets as of December 31, 1998. 14 Business Segments for the Nine Months Ended
September 30, 1999 (Thousands of Dollars) - ------------------------------------------------------------------------------------------------------------------------------ Electricity Electricity All Elimina- Delivery Generation CTC Other tions Consolidated ------------------------------------------------------------------------------------------------- Operating revenues $ 259,246 $ 339,155 $ 290,244 $ 173,058 $ (9,802) $ 1,051,901 Operating expenses 122,653 359,007 12,771 179,626 (15,553) 658,504 Depreciation and amortization expense 43,076 12,953 101,138 18,805 -- 175,972 - ------------------------------------------------------------------------------------------------------------------------------ Operating income (loss) 93,517 (32,805) 176,335 (25,373) 5,751 217,425 Other income (loss) 3,107 6,407 -- 112,489 (12,988) 109,015 Interest and other charges 27,108 35,294 35,623 22,681 (5,462) 115,244 - ------------------------------------------------------------------------------------------------------------------------------ Income (loss) before taxes 69,516 (61,692) 140,712 64,435 (1,775) 211,196 Income taxes 25,693 (29,569) 58,396 17,388 -- 71,908 - ------------------------------------------------------------------------------------------------------------------------------ Net income (loss) $ 43,823 $ (32,123) $ 82,316 $ 47,047 $ (1,775) $ 139,288 ============================================================================================================================== Assets $ 1,297,693 $ 561,111 $ 1,977,305 $ 1,460,996 $ -- $ 5,297,105 ============================================================================================================================== Capital expenditures $ 39,090 $ 18,864 $ -- $ 44,814 $ -- $ 102,768 ==============================================================================================================================
September 30, 1998 (Thousands of Dollars) - --------------------------------------------------------------------------------------------------------------------- Electricity Electricity All Elimina- Delivery Generation Other tions Consolidated ----------------------------------------------------------------------------------- Operating revenues $ 244,547 $ 654,620 $ 66,970 $ (9,154) $ 956,983 Operating expenses 116,846 417,503 60,500 (11,780) 583,069 Depreciation and amortization expense 39,122 109,171 4,185 -- 152,478 - --------------------------------------------------------------------------------------------------------------------- Operating income 88,579 127,946 2,285 2,626 221,436 Other income (loss) 4,153 7,169 73,798 (5,428) 79,692 Interest and other charges 28,364 44,086 10,528 (438) 82,540 - --------------------------------------------------------------------------------------------------------------------- Income (loss) before taxes 64,368 91,029 65,555 (2,364) 218,588 Income taxes 26,737 37,471 6,977 -- 71,185 - --------------------------------------------------------------------------------------------------------------------- Net income (loss) before extraordinary item $ 37,631 $ 53,558 $ 58,578 $ (2,364) $ 147,403 Extraordinary item, net of tax -- (82,548) -- -- (82,548) - --------------------------------------------------------------------------------------------------------------------- Net income (loss) after extraordinary item $ 37,631 $ (28,990) $ 58,578 $ (2,364) $ 64,855 ===================================================================================================================== Assets (1) $ 1,314,266 $ 2,711,533 $ 1,221,764 $ -- $ 5,247,563 ===================================================================================================================== Capital expenditures $ 40,620 $ 28,430 $ 49,905 $ -- $ 118,955 =====================================================================================================================
(1) Relates to assets as of December 31, 1998. 15 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations Part I, Item 2 of this Quarterly Report on Form 10-Q should be read in conjunction with DQE, Inc. and its subsidiaries' Annual Report on Form 10-K filed with the Securities and Exchange Commission (SEC) for the year ended December 31, 1998 and the condensed consolidated financial statements, which are set forth on pages 2 through 15 in Part I, Item 1 of this Report. General - -------------------------------------------------------------------------------- DQE, Inc. (DQE) is a multi-utility delivery and services company. Its subsidiaries are Duquesne Light Company (Duquesne); AquaSource, Inc. (AquaSource); DQE Capital Corporation (DQE Capital); DQE Energy Services, Inc. (DES); DQEnergy Partners, Inc. (DQEnergy); Duquesne Enterprises, Inc. (DE); and Montauk, Inc. (Montauk). DQE and its subsidiaries are collectively referred to as "the Company." The Company's largest subsidiary, Duquesne, is an electric utility engaged in the generation, transmission, distribution and sale of electric energy. The Company's expanded business lines offer a wide range of energy-related technologies, industrial and commercial energy services, telecommunications, and other complementary services. The expanded business lines' initiatives also include a water resource management company that acquires, develops and manages water and wastewater utilities, energy facility development and operation, domestic and international independent power production, the production and distribution of landfill gas, propane and synthetic fuels, investments in communications systems and electronic commerce, and long-term investments. DQE Capital provides financing for the expanded business lines. The Company plans to divest itself of its generation assets through the pending exchange of certain power station assets with FirstEnergy Corporation (FirstEnergy) and the pending sale of generation assets to Orion Power Holdings, Inc. (Orion). Final agreements governing the sale to Orion must be approved by various regulatory agencies, including the Pennsylvania Public Utility Commission (PUC). The Company currently expects these transactions to close in December 1999 and the second quarter of 2000, respectively. (See "Rate Matters" on page 25.) The Company's Service Areas The Company's electric utility operations provide service to customers in Allegheny County (including the City of Pittsburgh), Beaver County and, to a limited extent, Westmoreland County. (See "Rate Matters" on page 25.) This territory represents approximately 800 square miles in southwestern Pennsylvania. In addition to serving approximately 580,000 direct customers, the Company's utility operations also sell electricity to other utilities. The Company's water operations currently provide service to more than 300,000 water and wastewater customer connections and commercial bottled water customers in 13 states and Canada. Regulation The Company is subject to the accounting and reporting requirements of the SEC. In addition, the Company's electric utility operations are subject to regulation by the PUC, including regulation under the Pennsylvania Electricity Generation Customer Choice and Competition Act (Customer Choice Act), and the Federal Energy Regulatory Commission (FERC) under the Federal Power Act with respect to rates for interstate sales, transmission of electric power, accounting and other matters. (See "Rate Matters" on page 25.) The Company's electric utility operations are also subject to regulation by the Nuclear Regulatory Commission (NRC) under the Atomic Energy Act of 1954, as amended, with respect to the operation of its jointly owned/leased nuclear power plants, Beaver Valley Unit 1 (BV Unit 1), Beaver Valley Unit 2 (BV Unit 2) and Perry Unit 1. 16 The Company's water utility operations are subject to regulation by the utility regulatory bodies in their respective states. As a result of the PUC's May 29, 1998, final order regarding the Company's restructuring plan under the Customer Choice Act (see "Rate Matters" on page 25), the electricity generation portion of the Company's business does not meet the criteria of Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation (SFAS No. 71). Accordingly, fixed assets related to the generation portion of the Company's business are evaluated in accordance with SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of (SFAS No. 121). Pursuant to the PUC's final restructuring order, certain of the Company's generation-related regulatory assets are being recovered through a competitive transition charge (CTC) collected in connection with providing transmission and distribution services (the electricity delivery business segment), and have been reclassified accordingly. Additionally, pursuant to the PUC's final restructuring order, the Company is recovering its above-market investment in generation assets through the CTC, subject to receipt of the proceeds from the generation asset auction. The electricity delivery business segment continues to meet SFAS No. 71 criteria, and accordingly reflects regulatory assets and liabilities consistent with cost-based ratemaking regulations. The regulatory assets represent probable future revenue to the Company, because provisions for these costs are currently included, or are expected to be included, in charges to electric utility customers through the ratemaking process. (See "Rate Matters" on page 25.) Results of Operations - -------------------------------------------------------------------------------- Overall Performance In the second quarter of 1998, the PUC issued an order related to the Company's plan to recover its transition costs from electric utility customers. As a result of the order, the Company recorded an extraordinary charge against earnings of $82.5 million, or $1.06 per share. The following discussion of results of operations excludes the impact of such charge. Comparison of Three Months Ended September 30, 1999, and September 30, 1998. Basic earnings per share decreased 20 percent in the third quarter of 1999, to $0.64. This decline resulted from a 21 percent decrease in earnings available for common stock, partially offset by a 2.4 million share reduction in average shares of common stock outstanding. The net income contribution from Duquesne decreased $11.2 million. During the latter part of July 1999, a prolonged, wide-spread heat wave in the eastern half of the United States, combined with regional capacity constraints, resulted in unexpected net purchased power costs of approximately $24 million. As a result of these unprecedented purchased power prices, Duquesne's net revenues did not increase enough to offset the anticipated increased depreciation and amortization expense due to amortization of the CTC. The net income contribution from the Company's expanded business lines decreased by $2.0 million, as a result of decreased investment income due to the previous disposition of certain of the Company's investments, and less income from the Company's landfill gas investments. Partially offsetting these decreases were the Company's continuing water aggregation strategy and a gain on the sale of certain real estate investments. Comparison of Nine Months Ended September 30, 1999, and September 30, 1998. Basic earnings per share decreased 4.7 percent for the nine months ended September 30, 1999, to $1.81. This decline resulted from a 6.3 percent decrease in earnings available for common stock slightly offset by a 1.6 million share reduction in average shares of common stock outstanding. Duquesne's net income contribution decreased $10.8 million, while the Company's expanded business lines contributed $1.5 million more to net income in 1999 than in 1998. Duquesne's earnings were impacted by the unprecedented July purchased power prices. The expanded business line results reflect an increased level of gains from investment dispositions. 17 Results by Business Segment Historically, Duquesne has been treated as a single integrated business segment due to its regulated operating environment. The PUC authorized a combined rate for supplying and delivering electricity to customers which was cost-based and was designed to recover the Company's operating expenses and investment in electric utility assets and to provide a return on the investment. As a result of the Customer Choice Act, generation of electricity is deregulated and charged at a separate rate from the delivery of electricity beginning in 1999. For the purposes of complying with SFAS No. 131, Disclosures about Segments of an Enterprise and Related Information (SFAS No. 131), the Company is required to disclose information about its business segments separately. Accordingly, the Company has used the PUC-approved separate rates for 1999 to develop the financial information of the business segments for 1998. Beginning in 1999, the Company has three principal business segments (determined by products, services and regulatory environment): (1) the transmission and distribution by Duquesne of electricity (electricity delivery business segment), (2) the generation by Duquesne of electricity (electricity generation business segment), and (3) the collection of transition costs (CTC business segment). The Company has reported the results for 1999 by these business segments and an "all other" category. The all other category includes the Company's expanded business lines and Duquesne investments. These expanded business lines include water utilities, energy products and services and other activities. Intercompany transactions primarily relate to borrowings, sales of electricity, property rental, management fees and dividends. However, as the Company was not yet collecting transition costs prior to 1999, the 1998 results are reported by the electricity delivery and electricity generation business segments. (Additional information regarding the Company's business segments is set forth in "Business Segments and Related Information," Note 5 to the condensed consolidated financial statements on page 13.) In accordance with Accounting Principles Board Opinion No. 30, Reporting the Results of Operations - Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions (APB 30), a segment of a company's business is reported as discontinued operations if a formal disposition plan has been approved and the disposition is expected within 12 months. The Company believes that its electricity generation business segment will meet the criteria of APB 30 for discontinued operations upon completion of the power station exchange with FirstEnergy. The allocation of certain costs to the electricity generation business segment under APB 30 will differ from those allocations presented in Note 5, Business Segments and Related Information. Electricity Delivery Business Segment Comparison of Three Months Ended September 30, 1999, and September 30, 1998. The electricity delivery business segment contributed $24.0 million to net income in the third quarter of 1999 compared to $15.7 million in the third quarter of 1998, an increase of 52.9 percent. Operating revenues for this business segment are primarily derived from the Company's delivery of electricity and services provided to electric generation suppliers. Sales to residential and commercial customers are influenced by weather conditions. Warmer summer and colder winter seasons lead to increased customer use of electricity for cooling and heating. Commercial sales are also affected by regional development. Sales to industrial customers are influenced by national and global economic conditions. Operating revenues increased by $6.6 million or 7.4 percent in the third quarter of 1999 due to an increase in electricity usage by customers of 5.5 percent and due to revenues from services provided to electric generation suppliers. The increased sales are driven primarily by the warm weather experienced in Duquesne's service territory during July. The following table sets forth KWH delivered to electric utility customers during the third quarter: 18
- ------------------------------------------------------------------------------------------------ KWH Delivered ----------------------------------------------- (In Millions) ----------------------------------------------- Three Months Ended September 30, 1999 1998 Change - ------------------------------------------------------------------------------------------------ Residential 1,104.5 1,018.5 8.4% Commercial 1,720.8 1,664.8 3.4% Industrial 893.3 842.8 6.0% - -------------------------------------------------------------------------------- Sales to Electric Utility Customers 3,718.6 3,526.1 5.5% ================================================================================================
Operating expenses for the electricity delivery business segment are primarily made up of costs to operate and maintain the transmission and distribution system; meter reading and billing costs; customer service; collection; allocated administrative expenses; and non-income taxes, such as property and payroll taxes. Operating expenses increased $0.6 million or 1.5 percent in the third quarter of 1999. Depreciation and amortization expense decreased $6.4 million due to less amortization of a regulatory tax receivable and due to an adjustment recorded in the third quarter related to new depreciation rates resulting from a life service study effective January 1, 1999. Interest and other charges include interest on long-term debt, other interest and preferred stock dividends of Duquesne. In the third quarter of 1999, there was $0.3 million or 2.9 percent less in interest and other charges compared to the third quarter of 1998. The decrease was the result of the refinancing of long-term debt at lower interest rates and the maturity of approximately $75 million of long-term debt during 1998. Comparison of Nine Months Ended September 30, 1999, and September 30, 1998. The electricity delivery business segment contributed $43.8 million to net income in the first nine months of 1999 compared to $37.6 million in the first nine months of 1998, an increase of 16.5 percent. Operating revenues increased by $14.7 million or 6.0 percent in the first nine months of 1999 due to a 3.2 percent increase in electricity usage by customers and to services provided to electric generation suppliers. Sales to residential and commercial customers increased due to weather conditions, while industrial sales were relatively consistent between periods. The following table sets forth KWH delivered to electric utility customers during the first nine months of 1999 and 1998:
- ------------------------------------------------------------------------------------------------ KWH Delivered ----------------------------------------------- (In Millions) ----------------------------------------------- Nine Months Ended September 30, 1999 1998 Change - ------------------------------------------------------------------------------------------------ Residential 2,772.9 2,617.8 5.9% Commercial 4,618.5 4,478.7 3.1% Industrial 2,617.1 2,597.1 0.8% - --------------------------------------------------------------------------------- Sales to Electric Utility Customers 10,008.5 9,693.6 3.2% ===================================================================================================
Operating expenses for the electricity delivery business segment increased $5.8 million or 5.0 percent in the first nine months of 1999, primarily due to the timing of non-recurring charges related to meter reading in both 1999 and 1998. Depreciation and amortization expense increased $4.0 million or 10.1 percent in the first nine months of 1999 due to additions to the plant and equipment. Other income is primarily comprised of interest and dividend income. A decrease of $1.0 million or 25.2 percent was the result of lower interest income from a smaller amount of cash available for investing in the first nine months of 1999. 19 In the first nine months of 1999, there was $1.3 million or 4.4 percent less in interest and other charges compared to the first nine months of 1998. The decrease was the result of the refinancing of long-term debt at lower interest rates and the maturity of approximately $75 million of long-term debt during 1998. Electricity Generation and CTC Business Segments Comparison of Three Months Ended September 30, 1999, and September 30, 1998. In the third quarter of 1999, the electricity generation and CTC business segments reported net income of $14.8 million compared to $27.8 million for the third quarter of 1998, a decrease of 46.8 percent. During 1998, five percent of the Company's electric utility customers participated in the customer choice pilot program under the Customer Choice Act, and purchased electricity from alternative generation suppliers. Beginning in 1999, up to 66 percent of the Company's electric utility customers are eligible to participate in customer choice. As of September 30, 1999, approximately 17 percent of the Company's customers are purchasing electricity from alternative generation suppliers. For the electricity generation and CTC business segments, operating revenues are primarily derived from the Company's supply of electricity for delivery to retail customers, the supply of electricity to wholesale customers and, beginning in 1999, the collection of generation-related transition costs from electricity delivery customers. Under fuel cost recovery provisions effective through May 29, 1998, fuel revenues generally equaled fuel expense, as costs were recoverable from customers through the Energy Cost Rate Adjustment Clause (ECR), including the fuel component of purchased power, and did not affect net income. In 1999, due to the PUC's final restructuring order, fuel costs are expensed as incurred, and impact net income to the extent fuel costs exceed amounts included in Duquesne's authorized generation rates. (See "Rate Matters" on page 25.) Energy requirements for electric utility customers are reduced as more customers participate in customer choice. Energy requirements for residential and commercial customers are also influenced by weather conditions. Warmer summer and colder winter seasons lead to increased customer use of electricity for cooling and heating. Commercial energy requirements are also affected by regional development. Energy requirements for industrial customers are also influenced by national and global economic conditions. Short-term sales to other utilities are made at market rates. Fluctuations in electricity sales to other utilities are related to the Company's customer energy requirements, the energy market and transmission conditions, and the availability of the Company's generating stations. Future levels of short-term sales to other utilities will be affected by market rates, the level of participation in customer choice, and the Company's divestiture of its generation assets. (See "Rate Matters" on page 25.) Operating revenues decreased by $0.1 million or 0.1 percent in the third quarter of 1999. The decrease in revenues can be attributed to a decrease in energy supplied to electric utility customers due to increased participation in customer choice, partially offset by an 80.1 percent increase in energy supplied to other utilities. As of September 30, 1999, 17.0 percent of residential non- coincident peak load, 31.0 percent of commercial load, and 9.8 percent of industrial load have selected alternative generation suppliers. The increase in energy supplied to other utilities is due to increased capacity available to sell as a result of participation in customer choice and improved generating station availability. The following table sets forth KWH supplied for customers who have not chosen an alternative generation supplier and sales to other utilities: 20
- ----------------------------------------------------------------------------------------------------- KWH Supplied ----------------------------------------------------- (In Millions) Three Months Ended September 30, 1999 1998 Change - ----------------------------------------------------------------------------------------------------- Residential 911.9 956.5 (4.7)% Commercial 1,241.7 1,575.4 (21.2)% Industrial 866.9 827.0 4.8 % - --------------------------------------------------------------------------------- Sales to Electric Utility Customers 3,020.5 3,358.9 (10.1)% - --------------------------------------------------------------------------------- Sales to Other Utilities 919.1 510.2 80.1 % - --------------------------------------------------------------------------------- Total Sales 3,939.6 3,869.1 1.8 % =====================================================================================================
Operating expenses for the electricity generation and CTC business segments are primarily made up of energy costs; costs to operate and maintain the power stations; allocated administrative expenses; and non-income taxes, such as property and payroll taxes. Fluctuations in energy costs generally result from changes in the cost of fuel, the mix between coal and nuclear generation, total KWH supplied, and generating station availability. Because of the ECR, changes in fuel and purchased power costs did not impact earnings for the first five months of 1998. Operating and maintenance expenses decreased $13.9 million or 8.8 percent in the third quarter of 1999 as a result of the reclassification of the interest component of Beaver Valley lease costs to interest expense and decreased maintenance costs. In the third quarter of 1999, fuel and purchased power expense decreased by $1.0 million or 1.2 percent compared to the third quarter of 1998. During the third quarter of 1998, Duquesne's BV Units 1 and 2 were undergoing outages and the purchased power volumes were unusually large. The anticipated reduction in energy costs in 1999 did not occur due to power market conditions during late July. While purchased power volumes decreased substantially, unprecedented prices prevented a decline in costs. Depreciation and amortization expense includes the depreciation of the power stations' plant and equipment, accrued nuclear decommissioning costs and the amortization of transition costs. An increase of $27.2 million or 127.4 percent in the third quarter of 1999 was primarily the result of amortization of transition costs. In 1999, the Company began to recover transition costs through an interim CTC. The total transition costs to be recovered was $1.49 billion, net of tax, over a seven-year period, as may be adjusted to account for the proceeds of the generation asset auction (see "Rate Matters" on page 25). The Company records amortization expense for transition costs reflected on the consolidated balance sheet over the same period as the CTC revenues are being recognized. Interest and other charges include interest on long-term debt, other interest and preferred stock dividends of Duquesne. In the third quarter of 1999 there was a $9.2 million or 63.2 percent increase in interest and other charges compared third quarter of 1998. The increase reflected the reclassification of the interest component of Beaver Valley lease costs to interest expense, partially offset by refinancing of long-term debt at lower interest rates and the maturity of approximately $75 million of long-term debt during 1998. (See "Financing" discussion on page 23.) Comparison of Nine Months Ended September 30, 1999, and September 30, 1998. In the first nine months of 1999, the electricity generation and CTC business segments reported net income of $50.2 million compared to $53.6 million for the first nine months of 1998, a decrease of 6.3 percent. Operating revenues decreased by $25.2 million or 3.9 percent in the first nine months of 1999. The decrease in revenues can be attributed to a decrease in energy supplied to electric utility customers due to increased participation in customer choice and the 1998 recognition of $23.3 million of revenues related to deferred energy costs. Partially offsetting this decrease was a 91.7 percent 21 increase in energy supplied to other utilities in the first nine months of 1999, due to the Company's decision to make 600 MW available during the first six months of 1999 to licensed generation suppliers to stimulate competition, and increased capacity available to sell as a result of participation in customer choice. The following table sets forth KWH supplied for customers who have not chosen an alternative generation supplier and sales to other utilities:
- ----------------------------------------------------------------------------------------------------- KWH Supplied ----------------------------------------------------- (In Millions) Nine Months Ended September 30, 1999 1998 Change - ----------------------------------------------------------------------------------------------------- Residential 2,368.6 2,470.1 (4.1)% Commercial 3,381.1 4,241.0 (20.3)% Industrial 2,527.0 2,555.9 (1.1)% - --------------------------------------------------------------------------------- Sales to Electric Utility Customers 8,276.7 9,267.0 (10.7)% - --------------------------------------------------------------------------------- Sales to Other Utilities 2,369.6 1,236.1 91.7 % - --------------------------------------------------------------------------------- Total Sales 10,646.3 10,503.1 1.4 % =====================================================================================================
Operating expenses decreased $45.7 million or 11.0 percent in the first nine months of 1999 as a result of decreased energy costs and the reclassification of the interest component of Beaver Valley lease costs to interest expense. In the first nine months of 1999, fuel and purchased power expense decreased by $35.5 million or 16.4 percent compared to the first nine months of 1998, primarily as a result of decreased purchased power volumes and a favorable power supply mix. An increase in depreciation and amortization expense of $4.9 million or 4.5 percent in the first nine months of 1999 was the result of the amortization of transition costs. The total of transition costs to be recovered was $1.49 billion, net of tax, over a seven-year period, as may be adjusted to account for the proceeds of the generation asset auction (see "Rate Matters" on page 25). The Company records amortization expense for transition costs reflected on the consolidated balance sheet over the same period as the CTC revenues are being recognized. In the first nine months of 1999 there was a $26.8 million or 60.9 percent increase in interest and other charges compared to the first nine months of 1998. The increase reflected the reclassification of the interest component of Beaver Valley lease costs to interest expense, partially offset by the refinancing of long-term debt at lower interest rates and the maturity of approximately $75 million of long-term debt during 1998. All Other Comparison of Three Months Ended September 30, 1999, and September 30, 1998. The all other category contributed $11.0 million to net income in the third quarter of 1999 compared to $19.2 million in the third quarter of 1998, a decrease of 42.6 percent, as a result of decreased investment income due to the previous disposition of certain of the Company's investments, and less income from certain of the Company's alternative energy investments. Partially offsetting these decreases were income from continuing water aggregation strategy and gains on the sale of certain real estate and other investments. Operating revenues primarily include revenues from operating activities of the expanded business lines. Operating revenues increased in the third quarter of 1999 by $35.2 million to more than double the level in the third quarter of 1998. This increase was primarily the result of increased revenues from AquaSource and Control Solutions (a subsidiary of DE). 22 Operating expenses include expenses from operating activities of the expanded business lines and Duquesne investments. In the third quarter of 1999, operating expenses increased $44.5 million to more than double the level in the third quarter of 1998. The growth of the expanded business lines' start-up and developmental activities and acquisitions accounted for most of the increase. Depreciation and amortization expense primarily includes the depreciation of plant and equipment of the expanded business lines and amortization of certain investments. In the third quarter of 1999, depreciation and amortization expense increased by $6.7 million, primarily due to the depreciation and amortization associated with the acquisitions of water and water-related companies by AquaSource throughout 1998 and 1999. Other income primarily includes long-term investment income, gains from asset dispositions, and interest and dividend income related to the expanded business lines and Duquesne investments. Other income in the third quarter of 1999 was $22.6 million or 126.0 percent higher than in the third quarter of 1998. Approximately $15 million of this increase was the result of the gains recognized on the disposition of certain of the Company's real estate and other investments. Interest and other charges are made up of interest on long-term debt, other interest, intercompany interest on borrowings, and preferred stock dividends of the expanded business lines, and Duquesne investments. An increase of $6.3 million or 151.9 percent in the third quarter of 1999 was the result of higher expense associated with higher average borrowings outstanding; approximately $3 million of the increase was intercompany interest. Comparison of Nine Months Ended September 30, 1999, and September 30, 1998. The all other category contributed $47.0 million to net income in the first nine months of 1999 compared to $58.6 million in the first nine months of 1998, a decrease of 19.7 percent. Operating revenues increased in the first nine months of 1999 by $106.1 million or 158.4% in the first nine months of 1998. This increase was primarily the result of increased revenues from AquaSource and Control Solutions. In the first nine months of 1999, operating expenses increased $119.1 million or almost triple the level in the first nine months of 1998. The growth of the expanded business lines' start-up and developmental activities and acquisitions accounted for most of the increase. In the first nine months of 1999, depreciation and amortization expense increased by $14.6 million, primarily due to the depreciation and amortization associated with the acquisitions of water and water-related companies by AquaSource throughout 1998 and 1999. Other income in the first nine months of 1999 was $38.7 million or 52.4 percent higher than in the first nine months of 1998. This increase was the result of new investments made by the expanded business lines throughout 1998 and 1999 and gains recognized on the disposition of certain of the Company's real estate and affordable housing investments. An increase in interest and other charges of $12.2 million or 115.4 percent in the first nine months of 1999 was the result of higher long-term debt expense associated with higher average borrowings outstanding. In addition, approximately $6 million of the increase was intercompany interest. Liquidity and Capital Resources - -------------------------------------------------------------------------------- Financing The Company expects to meet its current obligations and debt maturities through the year 2003 with funds generated from operations, through new financings and short-term borrowings, and through the proceeds from the sale of generation assets to Orion. To the extent that acquisition and long-term investment opportunities prior to the generation divestiture exceed current expectations, the Company may explore various financing alternatives. At September 30, 1999, the Company was in compliance with all of its debt covenants. 23 Mortgage bonds in the amount of $75 million matured in July 1999, and were retired using available cash and short term borrowings. As discussed previously, the Company has entered into an agreement to sell its generation assets to Orion for approximately $1.71 billion. The Company anticipates using the net proceeds from this sale (currently estimated to be $1.1 billion) to recapitalize the Company and for general corporate purposes. In connection with the power station exchange with FirstEnergy, the Company anticipates terminating the BV Unit 2 lease in the fourth quarter of 1999; the lease liability recorded on the consolidated balance sheet would be eliminated, however the underlying collateralized lease bonds ($370.7 million at September 30, 1999, and anticipated to be $359.2 million upon lease termination) would become obligations of the Company and be recorded on the consolidated balance sheet as debt. The Company anticipates redeeming the bonds on December 1, 2002 (the first redemption date), using funds generated from operations, the generation asset auction proceeds, the CTC, and/or through new financings. The Company would also pay approximately $230 million in termination costs, which the Company expects to recover through the proceeds of the generation asset auction and the CTC. (See "Power Station Exchange" discussion on page 27.) In connection with customer choice, customer revenues from Duquesne's operations will be reduced by an amount equal to the generation rate applicable to those customers choosing alternative generation suppliers (currently approximately 17 percent of customers). This reduction is expected to be offset by reduced cash requirements associated with supplying energy. A further impact is anticipated when the purchased power agreement with Orion takes effect, and all customers will be buying generation either directly from alternative suppliers or indirectly from Orion. An additional impact on customer revenues is expected to occur when the CTC has been fully collected, which is currently expected to occur in 2001 for most major rate classes. The foregoing statements are forward-looking regarding the impact on cash flows of customer choice and Duquesne's divestiture. Actual results could materially differ from those implied by such statements due to known and unknown risks and uncertainties, including, but not limited to, the timing of the receipt of sale proceeds. (See "Restructuring Plan" on page 26.) As of September 30, 1999, 436,902 shares of Preferred Stock, Series A (Convertible), $100 liquidation preference per share (DQE Preferred Stock), were outstanding, including 51,060 shares issued in the third quarter of 1999. The Company and an unaffiliated corporation have an agreement that entitles the Company to sell and the corporation to purchase, on an ongoing basis, up to $50 million of accounts receivable. The Company currently anticipates extending or replacing the accounts receivable sale arrangement upon its expiration, recently extended to February 2000. At September 30, 1999, the Company had sold $50 million of receivables. In September 1999, DQE Capital issued $100 million of 8 3/8% medium term notes, due in September 2039 and unconditionally guaranteed by DQE. DQE Capital maintains a $250 million revolving credit agreement unconditionally guaranteed by DQE, with a 364 day term, convertible at DQE Capital's option into a term loan facility for an additional year for any amounts then outstanding upon expiration of the revolving credit period. As guarantor, DQE is subject to financial covenants requiring certain cash coverage and debt to capital ratios. At September 30, 1999, $63 million was outstanding. Interest rates can, in accordance with the option selected at the time of the borrowing, be based on prime or Eurodollar rates. DQE Capital initiated a $250 million commercial paper program during the fourth quarter of 1999, also unconditionally guaranteed by DQE. The Company also maintains a $225 million extendible revolving credit facility which expires in September 2000. At September 30, 1999, no amounts were outstanding. Interest rates can, in accordance with the option selected at the time of the borrowing, be based on prime, Eurodollar or certificate of deposit rates. Facility fees are based on the amount of the commitments. The facility contains a two-year repayment period for any amounts outstanding at the expiration of the revolving 24 credit period. The Company also has an aggregate of $150 million in bank term loans outstanding at September 30, 1999, with $65 million maturing in 2000 and $85 million maturing in 2001. At September 30, 1999, the Company had $66 million of commercial paper borrowings outstanding. During the third quarter the maximum amount of such borrowings was $126 million, the average daily borrowings was $87.2 million and the weighted average daily interest rate was 5.34 percent. The Company repurchased shares of its common stock on the open market during the third quarter of 1999. Investments and Acquisitions - -------------------------------------------------------------------------------- The Company has historically made long-term investments in leases, affordable housing, gas reserves and energy solutions. The Company continues to restructure its investment portfolio, and is currently divesting significant portions of its portfolio of affordable housing investments. Investing activities during the first nine months of 1999 and 1998 totaled approximately $26 million and $51 million, respectively. The Company currently estimates that during 1999 it will spend, excluding the Allowance for Funds Used During Construction and nuclear fuel, approximately $110 million for electric utility construction, including $30 million for generation, and approximately $35 million for water utility construction. During the first nine months of 1999, the Company has spent approximately $103 million on capital expenditures, which consist of approximately $58 million at Duquesne, $26 million at AquaSource and the remaining $19 million on other. In the first nine months of 1999 the Company issued 86,337 shares of DQE Preferred Stock, as part of a total investment of approximately $151 million in water companies. During the third quarter of 1999, the Company invested approximately $7.8 million to acquire seven propane distribution businesses in Texas and Pennsylvania. The Company expects to implement an aggregation strategy similar to that used in acquiring the water-related companies to develop this expanded business line. Rate Matters - -------------------------------------------------------------------------------- Competition and the Customer Choice Act Under historical ratemaking practice, regulated electric utilities were granted exclusive geographic franchises to sell electricity, in exchange for making investments and incurring obligations to serve customers under the then- existing regulatory framework. Through the ratemaking process, those prudently incurred costs were recovered from customers, along with a return on the investment. Additionally, certain operating costs were approved for deferral for future recovery from customers (regulatory assets). As a result of this process, utilities had assets recorded on their balance sheets at above-market costs, thus creating transition costs. In Pennsylvania, the Customer Choice Act went into effect on January 1, 1997. The Customer Choice Act enables Pennsylvania's electric utility customers to purchase electricity at market prices from a variety of electric generation suppliers (customer choice). Although the Customer Choice Act will give customers their choice of electric generation suppliers, the existing, franchised local distribution utility is still responsible for delivering electricity from the generation supplier to the customer. The local distribution utility is also required to serve as the provider of last resort for all customers in its service territory, unless other arrangements are approved by the PUC. The provider of last resort must provide electricity for any customer who cannot or does not choose an alternative electric generation supplier, or whose supplier fails to deliver. The Customer Choice Act provides that the existing franchised utility may recover, through a CTC, an amount of transition costs that are determined by the PUC to be just and reasonable. Pennsylvania's electric utility restructuring is being 25 accomplished through a two-stage process consisting of an initial customer choice pilot period (which ended in December 1998) and a phase-in to competition period (which began in January 1999). Phase-In to Competition Currently 66 percent of customers are eligible to participate in customer choice (including customers covered by the pilot program); all customers will have customer choice in January 2000. As of September 30, 1999, approximately 17 percent of the Company's customers had chosen alternative generation suppliers, representing approximately 22 percent of the Company's non-coincident peak load. Customers that have chosen an electricity generation supplier other than the Company pay that supplier for generation charges, and pay the Company the CTC (discussed below) and charges for transmission and distribution. Customers that continue to buy their generation from the Company pay for their service at current regulated tariff rates divided into generation, transmission and distribution charges, and the CTC. Under the Customer Choice Act, an electric distribution company, such as Duquesne, remains a regulated utility and may only offer PUC-approved rates, including generation rates. Also under the Customer Choice Act, electricity delivery (including transmission, distribution and customer service) remains regulated in substantially the same manner as under historical regulation. In an effort to "jumpstart" competition, Duquesne had made 600 megawatts (MW) of power available through the first six months of 1999 to licensed electric generation suppliers, to be used to supply electricity to Duquesne's customers who had chosen alternative generation suppliers. Rate Cap An overall four-and-one-half-year rate cap from January 1, 1997, was originally imposed on the transmission and distribution charges of Pennsylvania electric utility companies under the Customer Choice Act. As part of a settlement regarding recovery of deferred fuel costs (discussed below), the Company has agreed to extend this rate cap for an additional six months through the end of 2001. Additionally, electric utility companies may not increase the generation price component of rates as long as transition costs are being recovered, with certain exceptions. Restructuring Plan In its May 29, 1998, final restructuring order, the PUC determined that the Company should recover most of the above-market costs of the generation assets, including plant and regulatory assets through the collection of the CTC from electric utility customers. The $1.49 billion, net of tax, of transition costs was originally to be recovered over a seven-year period ending in 2005. However, by applying proceeds of the generation asset auction (discussed below) to reduce transition costs, the Company currently anticipates early termination of the CTC collection period in 2001 for most major rate classes. In addition, the transition costs as reflected on the consolidated balance sheet are being amortized over the same period that the CTC revenues are being recognized. The Company is allowed to earn an 11 percent pre-tax return on the unrecovered, net of tax balance of transition costs, as adjusted following the generation asset auction. As part of its restructuring plan filing, the Company requested recovery of $11.5 million ($6.7 million, net of tax) through the CTC for energy costs previously deferred under the ECR. Recovery of this amount was approved in the PUC's final restructuring order. The Company also requested recovery of an additional $31.2 million ($18.2 million, net of tax) in deferred fuel costs. On December 18, 1998, the PUC denied recovery of this additional amount. The Company appealed the PUC's denial of recovery to the Pennsylvania Commonwealth Court. On October 26, 1999, the Company and the Pennsylvania Office of the Consumer Advocate reached a settlement on this issue which would permit recovery of the entire $42.7 million ($24.9 million, net of tax) in deferred fuel costs. The PUC's decision on this settlement is pending. Auction Plan. On December 18, 1998, the PUC approved Duquesne's auction plan, including a purchased power agreement covering Duquesne's obligations for its provider of last resort service, as well as an agreement in principle to exchange certain generation assets with FirstEnergy. On September 24, 1999, Duquesne and the winning auction bidder, Orion, entered into definitive 26 agreements pursuant to which Orion will purchase Duquesne's wholly owned Cheswick, Elrama, Phillips and Brunot Island power stations, and the stations to be received from FirstEnergy in the power station exchange described below, for approximately $1.71 billion. Under the purchased power agreement, Orion will supply all of the electric energy requirements for Duquesne's customers who have not chosen an alternative generation supplier (provider of last resort service). This agreement, which expires upon Duquesne's final collection of the CTC, effectively transfers to Orion all of the financial risks and rewards associated with electricity supply. The purchase must be approved by various regulatory agencies, including the PUC, the FERC, and the Federal Trade Commission. Duquesne currently expects the sale to close in the second quarter of 2000. Although Duquesne expects to apply the net auction proceeds to reduce transition costs, until the divestiture is complete, Duquesne has been ordered to use an interim CTC and price to compare for each rate class based on the methodology approved in its pilot program (on average, approximately 2.9 cents per kilowatt hour (KWH) for the CTC and approximately 3.8 cents per KWH for the price to compare). Power Station Exchange. Pursuant to the definitive agreements entered into on March 25, 1999, Duquesne and FirstEnergy will exchange ownership interests in certain power stations. Duquesne will receive 100 percent ownership rights in three fossil-fired power plants located in Avon Lake and Niles, Ohio and New Castle, Pennsylvania (totaling approximately 1,300 MW), which the Company plans to sell as part of the auction of generation assets. FirstEnergy will acquire Duquesne's interests in Beaver Valley Unit 1 (BV Unit 1), Beaver Valley Unit 2 (BV Unit 2), Perry Unit 1, Sammis Unit 7, Eastlake Unit 5 and Bruce Mansfield Units 1, 2 and 3 (totaling approximately 1,400 MW). In connection with the power station exchange, the Company anticipates terminating the BV Unit 2 lease in the fourth quarter of 1999. (See "Financing," discussion on page 23.) Pursuant to the December 18, 1998, PUC order and subject to final approval, the proceeds from the sale to Orion of the power stations received in the exchange will be used to offset the transition costs associated with Duquesne's currently-held generation assets and costs associated with completing the exchange. Benefits of this exchange include the resolution of all joint ownership issues, and other ongoing risks and costs associated with the jointly-owned units. The Federal Trade Commission approved the exchange on June 30, 1999. The PUC approved the definitive exchange agreement on July 15, 1999, having found the exchange to be in the public interest. On September 15, 1999, the FERC approved the exchange. On September 30, 1999, the NRC approved the transfer of the BV Unit 1 and BV Unit 2 operating licenses, as well as Duquesne's ownership interest in Perry, to FirstEnergy. The Public Utilities Commission of Ohio approved the exchange agreement on October 28, 1999. The power station exchange is expected to occur in December 1999. (See "Legal Proceedings" on page 31.) Termination of the AYE Merger On October 5, 1998, the Company announced its unilateral termination of the merger agreement with Allegheny Energy, Inc. (AYE). The Company believes that AYE suffered a material adverse effect as a result of the PUC's final restructuring order regarding AYE's utility subsidiary, West Penn Power Company. AYE filed suit in the United States District Court for the Western District of Pennsylvania, seeking to compel the Company to proceed with the merger and seeking a temporary restraining order and preliminary injunction to prevent the Company from certain actions pending a trial, or in the alternative seeking an unspecified amount of money damages. Trial was held from October 20 through 28, 1999. Post-trial pleadings were filed November 10, 1999, and closing arguments are scheduled for November 23, 1999. The Company expects the judge's decision prior to the scheduled closing of the power station exchange in December. (See "Legal Proceedings" on page 31.) In a letter dated February 24, 1999, the PUC informed the Company that the merger application was deemed withdrawn and the docket was closed. 27 Year 2000 - -------------------------------------------------------------------------------- The Company has taken aggressive and comprehensive steps to ensure a smooth transition into the Year 2000. The transition to the Year 2000 became an issue because many existing computer programs and embedded microprocessors use only two digits to identify a year (for example, "99" is used to represent "1999"). Such programs read "00" as the year 1900, and thus may not recognize dates beginning with the Year 2000, or may otherwise produce erroneous results or cease processing when dates after 1999 are encountered. Year 2000 Plan. Since 1994, the Company has been planning for the Year 2000 with an aggressive strategy to identify information needs, replace or upgrade equipment and coordinate resources to anticipate the new millennium. Based on the success to date of the Year 2000 program, the Company fully expects normal operations into the Year 2000 and beyond. The Company assembled a Year 2000 team, comprised of management representatives from all functional areas of the Company. The goal of the Company's Year 2000 program is that all components and services that in any material manner contribute to the operational reliability, customer relations, safety, revenue, regulatory compliance and reputation of the company be Year 2000 ready. Special emphasis has been focused on mission critical systems that support the Company's ability to provide reliable services to customers. The next priority has been on business critical systems that support the day-to-day internal operations of the Company. The Year 2000 team has focused on all three aspects of the Year 2000 issue: computer software and hardware systems used to support day-to-day operations; embedded microprocessors which are small electronic devices found in a wide range of equipment and devices (such as plant components, substation equipment, elevators, and heating and cooling systems); and potential related issues that may originate with third parties with whom the Company does business. To support the planning, organization and management of its efforts, the team has retained Year 2000 consultants. In general, the Company's overall strategy to address the Year 2000 issue is comprised of four phases that, in some cases, are performed simultaneously. These phases are inventory, assessment, remediation, and testing and implementation. Inventory consists of identifying the various components, equipment, hardware, and software used in the Company's operations that may potentially be faced with Year 2000 issues. The inventory process involved reviewing existing listings and subsequent verification through physical inspections and walk- downs. Assessment consists of evaluating all inventoried items for Year 2000 compliance or readiness. This was accomplished by contacting the vendors and manufacturers, inspecting software and code, researching the results of other companies' assessment of like components, and various other means. Remediation, the third step in the process, addresses the activities necessary to fix or replace those components that have Year 2000 issues that will adversely affect the Company's operations. Remediation is in addition to previously planned improvements to the Company's systems with benefits beyond Year 2000 solutions, such as total system replacements discussed below. Testing and implementation, the final step, consists of placing renovated processes, systems, equipment, and other items into use within the Company's operations. Testing is performed on all mission critical processes, whether or not remediation activities were involved in the process. As of June 30, 1999, Duquesne's mission critical systems that support the generation of electricity as well as transmission and delivery of power to customers are Year 2000 ready. As of September 30, 1999, Duquesne's business critical systems are also Year 2000 ready. For existing AquaSource facilities, inventory, assessment, remediation and testing and implementation for mission critical systems were substantially completed as of September 30, 1999. The Company's Year 2000 program is routinely being incorporated into all new AquaSource acquisitions. 28 Year 2000 readiness related to mission critical and business critical systems at the Company's other expanded business lines was essentially complete as of June 30, 1999. Regulatory Review. Throughout the execution of its Year 2000 plan, the Company has been providing and will continue to provide information on its activities to regulatory agencies including the PUC, the Florida Public Service Commission (PSC), the Indiana Utility Regulatory Commission (URC), the New Jersey Board of Public Utilities (BPU), the Virginia State Corporation Commission (SCC), the NRC and the North American Electric Reliability Council (NERC). In addition to complying with all regulatory requirements (discussed below), Duquesne has undergone third party audits of mission critical systems. These independent assessments have confirmed that Duquesne's Year 2000 program appropriately addresses Year 2000 issues related to its systems and equipment. . Following eight months of formal proceedings by the PUC during which all Pennsylvania utilities, including Duquesne, were required to demonstrate that they were ready for the Year 2000, the PUC "investigation concludes that the lights will stay on..." (Motion of PUC Chairman John M. Quain on Docket No. I-00980076, March 31, 1999) . Duquesne has complied with the NRC's compliance guidelines and has verified with the NRC that all systems related to power production, safety and security are ready for Year 2000. In addition, the NRC conducted a Year 2000 audit of the nuclear power station safety and operations systems in May 1999. . NERC, which coordinates the interconnection of all utilities across the country, has been requested by the DOE to conduct a detailed review of the national electric power production and delivery infrastructure to ensure a reliable power supply during the Year 2000 transition period. The Company has provided monthly status reports to NERC. The Company's June 30, 1999 report confirmed the Year 2000 readiness of all its generation, transmission, and distribution systems. In addition, the Company participated in the industry-wide NERC communication drills conducted on April 9 and September 9, 1999. All of the Company's communications exercised in these drills performed as expected. . The Company's water and wastewater businesses also are being reviewed by regulatory agencies in the various states where AquaSource has facilities. The Company will continue to provide Year 2000 information to these agencies as well as to any additional agencies in locations where new facilities may be acquired. Risks and Contingency Plans. The Company currently believes that implementation of its plan will minimize the Year 2000 issues relating to its systems and equipment. The Company understands that many variables outside the control of the Company may have an adverse affect on the ability of the Company to perform its mission critical processes. Management believes that the most reasonably likely worst case scenario would be a temporary disruption of service to customers caused by potential disruptions in the operations of critical suppliers. In the event such a scenario occurs, it is not anticipated that the Company would incur a material adverse impact on its financial position or the consolidated results of operations. In the normal course of business the Company has developed contingency plans to minimize the risk of interrupted operations. As part of the Year 2000 program, the Company has reviewed these plans in terms of Year 2000 related risks, and either refined the existing plans or developed new contingency plans for all mission critical and business critical processes. These contingency plans incorporate numerous mitigation strategies, such as the most appropriate allocation of staffing resources, the need for additional equipment and facilities, and special operating procedures, including manual operations and use of non-computer dependent back-up equipment and procedures. The Company continues to review its operations and its critical external suppliers and service providers, in order to determine any adverse scenarios it could face as a result of Year 2000 problems. To date, nothing has been found that would prevent the Company from generating or providing electricity to the public. 29 Costs. The estimated total cost of implementing the Company's Year 2000 plan is approximately $49 million, which includes costs related to total system replacements (i.e., the Year 2000 solution comprises only a portion of the benefit resulting from such replacements). These costs to date, primarily incurred as a result of software and system changes and upgrades by DQE, have been approximately $44 million. Of this amount, approximately $35 million are capital costs attributable to the licensing and installation of new software for total system replacements. The remaining $9 million has been expensed as incurred. Funds for the Company's Year 2000 plan have come from the Company's operating and capital budgets. Approximately $4 million of the amount expensed has come from the $10 million budgeted for 1999 to address Year 2000 issues. The Company does not anticipate that Year 2000 issues and related costs will be material to the Company's operations, financial condition and results of operations. The foregoing paragraphs contain forward-looking statements regarding the timetable, effectiveness and ultimate cost of the Company's Year 2000 strategy. Actual results could materially differ from those implied by such statements due to known and unknown risks and uncertainties, including, but not limited to, the possibility that changes and upgrades are not timely completed, that corrections to the systems of other companies on which the Company's systems rely may not be timely completed, and that such changes and upgrades may be incompatible with the Company's systems; the availability and cost of trained personnel; and the ability to locate and correct all relevant computer code and microprocessors. Item 3. Quantitative and Qualitative Disclosures About Market Risk Funding for nuclear decommissioning costs is deposited by the Company in external, segregated trust accounts and invested in a portfolio of corporate common stock and debt securities, municipal bonds, certificates of deposit and United States government securities. The market value of the aggregate trust fund balances at September 30, 1999 totaled approximately $69.8 million. The amount funded into the trusts is based on estimated returns which, if not achieved as projected, could require additional unanticipated funding requirements. ------------------------------ Except for historical information contained herein, the matters discussed in this Quarterly Report on Form 10-Q are forward-looking statements that involve known and unknown risks, uncertainties and other factors that may cause the actual results, performance or achievements of the Company to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. Such factors may affect the Company's operations, markets, products, services and prices, and include, among others, the following: the Company's decision not to consummate the merger with AYE; the related lawsuit initiated by AYE; Duquesne's plan to sell its generating assets; the power station exchange; general and economic and business conditions; industry capacity; changes in technology; changes in political, social and economic conditions; the loss of any significant customers; and changes in business strategy or development plans. 30 PART II. OTHER INFORMATION Item 1. Legal Proceedings Eastlake Unit 5 In September 1995, the Company commenced arbitration against The Cleveland Electric Illuminating Company (CEI), seeking damages, termination of the operating agreement for Eastlake Unit 5 (Eastlake) and partition of the parties' interests in Eastlake through a sale and division of the proceeds. The arbitration demand alleged, among other things, the improper allocation by CEI of fuel and related costs; the mismanagement of the administration of the Saginaw coal contract in connection with the closing of the Saginaw mine, which historically supplied coal to Eastlake; and the concealment by CEI of material information. CEI also seeks monetary damages from the Company for alleged unpaid joint costs in connection with the operation of Eastlake. The Company removed the action to the United States District Court for the Northern District of Ohio, Eastern Division, where it is now pending (Eastlake Litigation). Pursuant to the agreement regarding the power station exchange between Duquesne and FirstEnergy, the parties have jointly sought and received a court order staying all proceedings in the Eastlake Litigation pending the closing of the exchange. Upon closing, the parties will enter into a settlement agreement dismissing the Eastlake Litigation. (See "Power Station Exchange" discussion on page 27.) Termination of the AYE Merger On October 5, 1998, the Company announced its unilateral termination of the merger agreement with AYE. More information regarding this termination is set forth in the Company's Current Report on Form 8-K dated October 5, 1998. AYE promptly filed suit in the United States District Court for the Western District of Pennsylvania, seeking to compel the Company to proceed with the merger and seeking a temporary restraining order and preliminary injunction to prevent the Company from certain actions pending a trial, or in the alternative seeking an unspecified amount of money damages. On October 28, 1998, the judge denied AYE's motion for the temporary restraining order and preliminary injunction. AYE appealed to the United States Court of Appeals for the Third Circuit, asking for an injunction pending the appeal and expedited treatment of the appeal. On November 6, 1998, the Third Circuit denied the motion for an injunction and granted the motion to expedite the appeal. On March 11, 1999, the Third Circuit vacated the October 28, 1998, denial of a preliminary injunction. The Third Circuit remanded the case to the District Court for further proceedings to address certain issues, including whether AYE could demonstrate a reasonable likelihood of success on the merits, before determining whether any injunctive relief is warranted. On March 12, 1999, AYE filed a motion for a temporary restraining order with the district court, and a hearing was held that same day. On March 16, 1999, AYE and DQE entered into a consent agreement, which was approved by the district court on March 18. Pursuant to the consent agreement, AYE and DQE have agreed, among other things, that pending the consolidated hearing on AYE's application for a preliminary injunction and/or an expedited trial on the merits, both parties will give each other 10 business days' notice before taking or omitting to take any action which would prevent the merger from qualifying for "pooling of interests" accounting treatment. This would not prevent either party from entering into any agreement, but would require the 10 business days' notice prior to closing any transaction which prevents pooling. The consent agreement, originally scheduled to terminate on September 16, 1999, was extended by mutual agreement for the duration of the trial. On March 25, 1999, the Company petitioned the Third Circuit for rehearing; this petition was denied on June 14, 1999. On June 1, 1999, AYE informed the PUC that, given the procedural posture of the merger litigation, it would seek a Federal court order enjoining the closing of the power station exchange with FirstEnergy because, in its view, such a closing would prevent the merger from qualifying for "pooling of interests" accounting. 31 The Company's motion for summary judgment, originally filed December 18, 1998, was denied on October 19, 1999. The Company will continue to defend itself vigorously against AYE's claims and intends to pursue a prompt resolution of the litigation. The ultimate outcome of this suit cannot be determined at this time. Trial was held from October 20 through 28, 1999. Post-trial pleadings were filed November 10, 1999, and closing arguments are scheduled for November 23, 1999. The Company expects the judge's decision prior to the scheduled closing of the power station exchange in December. Item 6. Exhibits and Reports on Form 8-K a. Exhibits: EXHIBIT 10.1 - Severance Agreement and Release between James D. Mitchell and DQE. EXHIBIT 12.1 - Calculation of Ratio of Earnings to Fixed Charges and Preferred and Preference Stock Dividend Requirements. EXHIBIT 27.1 - Financial Data Schedule b. A report on Form 8-K was filed September 29, 1999, to report the execution of agreements to sell Duquesne's power plants and provider of last resort service. No financial statements were field with this report. ----------------------------- 32 SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant identified below has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. DQE, Inc. -------------------------------------- (Registrant) Date November 15, 1999 /s/ Gary L. Schwass --------------------- -------------------------------------- (Signature) Gary L. Schwass Executive Vice President and Chief Financial Officer Date November 15, 1999 /s/ James E. Wilson --------------------- ----------------------------------------- (Signature) James E. Wilson Controller (Principal Accounting Officer) 33 EX-10.1 2 SEVERANCE AGREEMENT Exhibit 10.1 CONFIDENTIAL SEVERANCE AGREEMENT AND RELEASE -------------------------------------------- This Confidential Severance Agreement and Release ("Agreement"), dated as of August 23, 1999, is made between James D. Mitchell ("Employee"), the undersigned employee, and DQE, Inc. ("the Company") for the purpose of forever releasing the Company and all "Released Parties" as defined herein from any and all possible liability to Employee. The parties, intending to be legally bound hereby, enter into this Agreement as follows: 1. Employee has voluntarily elected to resign from employment with the Company and its subsidiaries and affiliates and from all officer, board and committee positions at the Company and its subsidiaries and affiliates, including without limitation the positions set forth in Exhibit A, in exchange for the benefits provided herein. The Company's employment records will reflect that Employee's employment with the Company will end effective August 23, 1999 (the "Termination Date"). 2. The Company, on its behalf, and on behalf of the Released Parties as defined herein, has agreed to provide to Employee, and Employee has expressly agreed to accept, the following, in full settlement, release and discharge of all possible claims, known or unknown, which Employee might have or might have claimed for any reason: a. As soon as practicable after the Termination Date, Employee shall receive a lump sum cash payment of his accrued vacation pay and the unpaid amount of sold vacation time. b. Employee shall be entitled to receive all benefits accrued by him as of the Termination Date under all qualified and nonqualified pension and 401(k) plans of the Company and its affiliates in such manner and at such time as are provided under the terms of such plans. c. On the next regularly scheduled payday following the later of (i) the Termination Date or the (ii) the execution of this Agreement, the Company will pay to Employee the first of twenty-four (24) semi-monthly payments, less standard deductions and tax withholdings, the total of all being an amount equal to twelve (12) months of base salary at Employee's most recent rate of pay. By signing this Agreement, Employee acknowledges that his resignation would not ordinarily entitle him to this separation allowance, that this separation allowance is intended by the parties to constitute separation pay and not actual continuation of salary and that he is being awarded this allowance in consideration for signing this Agreement. d. Health, dental, long-term disability and accidental death and dismemberment insurance benefits will be provided to Employee for the length of his salary continuance of the same kind and at the same cost to Employee as if still employed by the Company. If Employee becomes employed during the period of time he is on salary continuance, he must notify the Company by contacting in writing Victor A. Roque, Executive Vice President and General Counsel of the Company at 411 Seventh Avenue - 16/th/ Floor, Pittsburgh, Pennsylvania 15219. The benefits Employee is receiving from the Company will then cease if he is eligible to receive from his new employer benefits that the Company reasonably determines to be comparable to the benefits Employee is receiving from the Company. Severance pay will, however, continue to be paid. 2 e. For the length of Employee's salary continuance, the Company shall pay the cost, in an aggregate amount not to exceed $15,000, for outplacement services to be provided to Employee by the Bizet Group. f. As soon as practicable after the Termination Date, Employee will receive a lump sum amount equal to the actuarial equivalent of the additional benefits Employee would have accrued under the Retirement Plan, the Supplemental Plan and the Pension Service Supplement Plan (PSSP) if Employee had continued to be employed by the Company for the period of his salary continuance under this Agreement and if his covered compensation for such period had continued at as rate equal to his rate of covered compensation for the twelve (12) full calendar months immediately preceding the calendar month in which the Termination Date occurred (for purposes of the foregoing, actuarial equivalence shall be determined in accordance with the terms of the Retirement Plan, the Supplemental Plan and the Pension Service Supplement Plan (PSSP), as applicable. g. On July 22, 1997, Employee was granted a stock option (the "1997 Three-Year Option") in respect of an aggregate of 22,500 shares of the Company's Common Stock pursuant to the 1997 three-year stock option program under the terms of the Company's Long-Term Incentive Plan. In 1997, the first tranche of the 1997 Three-Year Option, in respect of 6,750 shares, was awarded to Employee by the Compensation Committee (the "Committee") of the Company's Board of Directors. In July 1999, the Committee awarded a second tranche of the 1997 Three-Year Option, in respect of 6,750 shares. The third and final tranche, 3 in respect of 9,000 shares, has not yet been awarded. The parties agree that the second and third tranches of the 1997 Three-Year Option, as well as the 1999 annual stock option in respect of an aggregate of 18,129 shares of Company Common Stock granted to Employee as of December 18, 1998 but not yet awarded, shall be forfeited by Employee as of the Termination Date and shall not be exercisable by Employee or any other person on or after the Termination Date. All other stock options granted to Employee prior to the Termination Date under the terms of the Company's Long-Term Incentive Plan and not heretofore exercised by Employee, as described in Exhibit B hereto, shall, upon execution of this Agreement, remain exercisable in accordance with their respective terms for one year after the Termination Date at which time any unexercised portion of such options shall expire and no longer be exercisable. Employee acknowledges and agrees that his resignation would not ordinarily entitle him to the continued ability to exercise such stock options and that he is being given this ability in consideration for signing this Agreement. h. For the length of his salary continuance, Employee shall have the right, at the Company's expense, to continue to use the financial planning and counseling services offered to Company executives by AYCO in accordance with the guidelines established by the Company for such services. Except as expressly provided above, Employee waives any compensation, benefits or rights that may have accrued in his capacity as an employee or otherwise prior to the date of this Agreement and shall not be entitled to receive any salary or benefits or participate in any compensation plans, programs or arrangements of the Company and its affiliates after the 4 Termination Date. 3. In consideration for the payments and benefits that Employee shall be provided under this Agreement, Employee on behalf of himself and his dependents, heirs, administrators, representatives, executors, successors, assigns and any other person or entity, including any government agency seeking to assert a claim on his behalf, hereby releases and forever discharges the Company and its agents, servants, officers, directors, employees, parents, subsidiaries, divisions, affiliates, predecessors, successors and assigns, all its employee benefit plans and their administrators, trustees and other fiduciaries (severally and collectively called "the Released Parties") from any and all injuries, causes of actions, claims and demands whatsoever, and from all debts and liabilities whatsoever, whether known or unknown, asserted or unasserted or any that Employee or any person or entity acting for Employee now have or hereafter may have against any of the Released Parties for any acts, practices or events up to and including the effective date of this Agreement and the continuing effects thereof, it being Employee's intention to effect a general release of all claims. This release includes, without in any way limiting the generality of the foregoing, any claims for attorneys' fees, any claims for costs arising out of or relating to Employee's employment by the Company, and any claims arising from any alleged violation by any of the Released Parties of any federal, state or local statute, ordinance, rule, Executive Order or regulation, including, but not limited to, Title VII of the Civil Rights Act of 1964, as amended, the Rehabilitation Act of 1973, the Pennsylvania Worker's Compensation Act, the Americans with Disabilities Act, the Employee Retirement Income Security Act of 1974, as amended, the Pennsylvania Human Relations Act, the Civil Rights Act of 1991, the Americans with Disabilities Act and the Age Discrimination in Employment Act, as amended; provided, however, that the foregoing release shall not adversely 5 affect Employee's COBRA rights or his rights to benefits under the Company's 401(k) Plan for Management Employees or its tax-qualified Retirement Plan and Supplemental Retirement Plan. 4. Nothing in this Release is intended as a waiver of, or to interfere with, Employee's right to file a charge under, or to testify, assist or participate in any manner in any investigation, hearing or proceeding under any statute over which the Equal Employment Opportunity Commission has jurisdiction; provided, however, that Employee agrees that the waiver and release in Paragraph 3 bars him from receiving any personal financial recovery or other personal remedy as a result of, or in connection with, any such charge, investigation, hearing or proceeding. 5. The Company and Employee agree to refrain from making any disparaging remarks about each other or otherwise acting or commenting in a way which reflects adversely upon the Company's business or personnel or Employee's work performance. 6. The terms of this Agreement shall remain strictly confidential. Employee agrees that he will not, unless compelled by law or judicial process to do so, disclose or discuss, directly or indirectly, its terms with anyone other than his spouse, attorney, financial advisors, and prospective employers who have specifically requested a copy hereof. 7. Notwithstanding the foregoing, all of the confidentiality, non- competition and other obligations of Employee under that certain Employee Non- Competition and Confidentiality Agreement between Employee and the Company dated December 13, 1996 (the "Non-Competition Agreement"), which is incorporated herein by reference, shall remain in full force and effect as set forth in the Non-Competition Agreement, but the provisions of the Non-Competition Agreement regarding severance pay shall be deemed terminated and of no force or effect. Without limiting the scope of his obligations under the Non-Competition Agreement, 6 Employee acknowledges and agrees that the Company's confidential and proprietary information includes, but is not limited to, all proprietary information and trade secrets of the Company and its affiliates, such as all information disclosed to Employee or known by him about (1) any matters relating to the participation of the Company and/or an affiliate in certain lease transactions wherein the Company and/or an affiliate acquired interests in certain portfolios of equipment and a power facility (collectively the "Assets") and the ongoing administration of such property interests including, without limitation, any agreements or arrangements relating to the sale or release of any of the Assets; (2) any agreements or arrangements between the Company and/or an affiliate and Computer Leasing Inc. or any affiliate thereof including, without limitation, any remarketing arrangements and any matters relating to the acquisition by the Company and/or an affiliate of beneficial ownership of certain equipment trusts that participated in the leasehold transactions referenced in (1) above; (3) any matters relating to the participation of the Company and/or an affiliate in domestic sale/leaseback transactions; (4) any matters relating to the participation of the Company and/or an affiliate in certain offshore lease/leaseback transactions; (5) any matters relating to the participation of the Company and/or an affiliate in investments in landfill gas recovery operations, as well as investments in limited partnership holding oil and gas well investments; and (6) any matters relating to the participation of the Company and/or an affiliate in investments in limited partnerships which invest in affordable housing projects. It will be presumed that information supplied to the Company and/or any affiliate from outside sources is confidential information unless and until it is designated otherwise. Before making any legally required disclosure of the Company's confidential or proprietary information, Employee shall give the Company as much advance written notice as possible. 7 8. Employee agrees to deliver to the Company on or before the Termination Date, all confidential or proprietary information, equipment, documents, files, lists or other written, graphic or electronic records relating to the Company's business, and all copies of such materials, which are or have been in Employee's possession, or under his control. 9. In addition to any other remedy herein set forth or available to the Company at law or in equity, in the event that Employee breaches or otherwise fails to observe any and all of the covenants, agreements or duties herein set forth above, as determined by a court or other body of competent jurisdiction, the Company may, in its discretion, terminate this Agreement and shall thereafter be released from performing under any other arrangement set forth herein. 10. It is expressly understood and agreed that by entering into this Agreement, the Company does not admit in any way that it has treated Employee unlawfully or wrongfully. To the contrary, the Company expressly denies that it has violated any of Employee rights or harmed him in any way. 11. Employee acknowledges that he has carefully read and fully understands all the provisions and effects of this Agreement; that he has had the opportunity to consult and thoroughly discuss all aspects of it with an attorney; that he is voluntarily entering into this Agreement; and that neither the Company nor its agents or attorneys made any representations or promises concerning the terms or effects of this Agreement other than those contained herein. Employee understands and acknowledges that he is bound by the terms of the Non-Competition Agreement, the terms and conditions of which are incorporated herein by reference. 12. Employee acknowledges that he has been given no less than twenty-one days to consider this Agreement before executing it. Employee acknowledges that he has been 8 advised orally and by this writing to consult with an Attorney prior to signing this Agreement. He further acknowledges that he may revoke this Agreement for a period of seven (7) days from the date he executes it (the "Revocation Period"), by notifying in writing, Victor A. Roque, Executive Vice President and General Counsel of the Company at 411 Seventh Avenue, 16th Floor, Pittsburgh, Pennsylvania 15219. 13. This Agreement shall be construed under the laws of the United States and of the Commonwealth of Pennsylvania. The provisions hereof are severable, except the provisions of Paragraph 3 are not severable from the consideration provided in Paragraph 2. If any term, condition, clause or provision of this Agreement shall be deemed unenforceable, it shall have no effect on the enforceability of the other provisions hereof. 14. Nothing in this Agreement is intended to, nor shall it be deemed to, constitute a waiver or release of any claim under the Age Discrimination in Employment Act which arises after this Agreement is executed by the parties. 15. This Agreement and the Non-Competition Agreement (as modified in Section 7 hereof) represent the entire agreement of the parties and any amendments hereto shall not be effective unless they are in writing signed by all parties and/or their duly authorized representatives. Without limiting the generality of the foregoing, the Severance Agreement, dated as of April 4, 1997, between Employee and the Company is deemed terminated in its entirety and shall be of no further force or effect. 16. By signing this Agreement, Employee has made the following representation: "I HAVE READ THIS AGREEMENT, AND HAVE HAD AN OPPORTUNITY TO CONSULT WITH AN ATTORNEY OF MY CHOOSING ABOUT IT. I HAVE BEEN GIVEN THE NECESSARY TIME TO CONSIDER ITS CONTENTS AND I 9 FULLY UNDERSTAND ALL OF ITS TERMS. I AM SIGNING THIS AGREEMENT VOLUNTARILY." This Agreement is made this 3/rd/ day of October, 1999 effective as of the Termination Date. /s/ Sharon A. Mitchell /s/ James D. Mitchell - ----------------------------------- ---------------------------------- Witness James D. Mitchell Attest: DQE, INC. /s/ Amy M. Parker By: /s/ Victor A. Roque - ----------------------------------- ---------------------------------- Victor A. Roque /s/ Diane S. Eismont Executive Vice President - ----------------------------------- and General Counsel 10 EXHIBIT A --------- BOARD POSITIONS: Allegheny Development Corp. Duquesne Enterprises, Inc. AquaSource, Inc. Duquesne Light Company Bushton Company EnviroGas Recovery, Inc. Diemen-Flevo Co. Monongahela Light and Power Co. DQE Capital Corporation Montauk, Inc. DQE Communications, Inc. Monticello Corporation DQE Energy Services, Inc. Property Ventures, Ltd. DQEnergy Partners, Inc. OFFICER POSITIONS: Company Name Title ------------ ----- Bushton Company President DQE Capital Corporation Vice President DQE, Inc. Vice President - Finance Montauk, Inc. President Waste Energy Technology, LLC Manager EXHIBIT B OF CONFIDENTIAL SEVERANCE AGREEMENT AND RELEASE LONG TERM INCENTIVE PLAN SUMMARY NAME: JAMES D. MITCHELL DATE: AUGUST 23, 1999
Shares Option Shares Exercise Shares Unexercisable Date Awarded Price SAR's DEA's Exercisable Until 11/12/99 ---- ------- ----- ----- ----- ----------- -------------- 11/11/96 1015 $29.9375 YES YES 1015 0 05/08/97 2396 28.5625 YES YES 2396 0 07/22/97 3159 30.9375 NO YES 3159 0 11/10/97 2954 30.7188 YES YES 2954 0 11/10/97 2962 30.7188 YES YES 2962 0 01/26/98 11774 33.1250 YES NO 11774 0 08/04/98 3268 35.0625 YES YES 3268 0 11/11/98 1219 40.5625 YES YES 1219 0 11/11/98 2096 40.5625 YES YES 2096 0 02/08/99 1619 39.5938 YES YES 1619 0 05/11/99 682 41.0000 YES YES 0 682 05/11/99 3193 41.0000 YES YES 0 3193
Memo: All options expire one (1) year after date of termination. 2 EX-12.1 3 CALCULATION OF RATIO OF EARNINGS TO FIXED CHARGES Exhibit 12.1 DQE, Inc. and Subsidiaries Calculation of Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Stock Dividend Requirements (Thousands of Dollars)
Year Ended December 31, Nine Months Ended ---------------------------------------------------------------- September 30, 1999 1998 1997 1996 1995 1994 ------------------ -------- -------- --------- --------- -------- FIXED CHARGES: Interest on long-term debt $ 53,970 $ 81,076 $ 87,420 $ 88,478 $ 95,391 $101,027 Other interest 21,259 14,556 13,823 10,926 7,033 4,050 Portion of lease payments representing an interest factor 35,755 44,146 44,208 44,357 44,386 44,839 Dividend requirement 12,173 15,612 21,649 14,385 7,374 9,355 ----------- ------------ ---------- ---------- ----------- --------- Total Fixed Charges $123,157 $155,390 $167,100 $158,146 $154,184 $159,271 ----------- ------------ ---------- ---------- ----------- --------- EARNINGS: Income from continuing operations $139,288 $196,688 $199,101 $179,138 $170,563 $156,816 Income taxes 71,909* 100,982* 95,805* 87,388* 96,661* 92,973 Fixed Charges as above 123,157 155,390 167,100 158,146 154,184 159,271 ----------- ------------ ---------- ---------- ----------- --------- Total Earnings $334,354 $453,060 $462,006 $424,672 $421,408 $409,060 ----------- ------------ ---------- ---------- ----------- --------- RATIO OF EARNINGS TO FIXED CHARGES 2.71 2.92 2.76 2.69 2.73 2.57 =========== ============ ========== ========== =========== =========
The Company's share of the fixed charges of an unaffiliated coal supplier, which amounted to approximately $1.8 million for the nine months ended September 30, 1999, has been excluded from the ratio. *Earnings related to income taxes reflect a $3.0 million decrease for the nine months ended September 30, 1999, a $12 million, $17 million, $12 million, $13.5 million and $13.5 million decrease for the twelve months ended December 31, 1998, 1997, 1996, 1995 and 1994, respectively, due to a financial statement reclassification related to Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes. The ratio of earnings to fixed charges, absent this reclassification, equals 2.74 for the nine months ended September 30, 1999, and 2.99, 2.87, 2.76, 2.82 and 2.65 for the twelve months ended December 31, 1998, 1997, 1996, 1995 and 1994, respectively. EX-27 4 FINANCIAL DATA SCHEDULE
UT 1,000 9-MOS DEC-31-1999 JAN-01-1999 SEP-30-1999 PER-BOOK 1,424,216 1,063,948 419,312 2,389,629 0 5,297,105 73,119 927,197 921,156 1,452,081 4,500 268,523 1,367,072 0 134,100 0 145,435 0 16,937 664 1,907,793 5,297,105 1,051,901 71,908 834,476 834,476 217,425 109,015 326,440 115,244 139,288 1,153 138,135 86,650 55,878 281,732 1.81 1.77 Includes $(469,391) of Treasury Stock at cost. Includes $14,129 of Preference Stock. Non-operating expense. Includes $12,510 of Preferred and Preference stock dividends.
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