UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 10-Q/A
Amendment No. 1
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31,September 30, 1999
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Commission file number: 1-1401
PECO Energy Company
(Exact name of registrant as specified in its charter)
Pennsylvania 23-0970240
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
2301 Market Street, Philadelphia, PA 19103
(Address of principal executive offices) (Zip Code)
(215) 841-4000
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period
that the registrant was required to file such reports), and (2) has
been subject to such filing requirements for the past 90 days.
Yes _X_X No ___
Indicate the number of shares outstanding of each of the issuer's
classes of common stock as of the latest practicable date:
The Company had 191,812,306185,786,206 shares of common stock outstanding on
May 7,November 5, 1999.
1
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
(Millions of Dollars, Except Per Share Data)
Three Months Ended Nine Months Ended
September 30, September 30,
1999 1998 1999 1998
OPERATING REVENUES
Electric $ 1,681.9 $ 1,736.3 $ 3,826.2 $ 3,871.1
Gas 49.9 49.2 356.4 319.8
----------- ----------- ----------- -----------
TOTAL OPERATING REVENUES 1,731.8 1,785.5 4,182.6 4,190.9
----------- ----------- ----------- -----------
OPERATING EXPENSES
Fuel and Energy Interchange 786.0 732.9 1,739.6 1,476.1
Operating and Maintenance 329.3 298.3 963.7 837.5
Depreciation and Amortization 57.1 153.2 171.0 468.8
Taxes Other Than Income 75.3 52.3 195.8 206.2
----------- ----------- ----------- -----------
1,247.7 1,236.7 3,070.1 2,988.6
----------- ----------- ----------- -----------
OPERATING INCOME 484.1 548.8 1,112.5 1,202.3
----------- ----------- ----------- -----------
OTHER INCOME AND DEDUCTIONS
Interest Expense (108.3) (81.9) (296.1) (252.9)
Company Obligated Mandatorily Redeemable
Preferred Securities of a Partnership (3.9) (7.4) (18.7) (23.3)
Allowance for Funds Used During Construction (0.3) 0.9 1.8 2.2
Equity in Losses of Unconsolidated Affiliates (5.5) (14.5) (28.4) (40.2)
Other, Net 1.9 2.4 (0.6) (11.6)
----------- ----------- ----------- -----------
TOTAL OTHER INCOME AND DEDUCTIONS (116.1) (100.5) (342.0) (325.8)
----------- ----------- ----------- -----------
INCOME BEFORE INCOME TAXES AND
EXTRAORDINARY ITEM 368.0 448.3 770.5 876.5
INCOME TAXES 137.2 174.6 286.9 337.7
----------- ----------- ----------- -----------
INCOME BEFORE EXTRAORDINARY ITEM 230.8 273.7 483.6 538.8
EXTRAORDINARY ITEM - NET OF INCOME TAXES -- -- (26.7) --
----------- ----------- ----------- -----------
NET INCOME 230.8 273.7 456.9 538.8
PREFERRED STOCK DIVIDENDS 2.9 3.2 9.5 9.8
----------- ----------- ----------- -----------
EARNINGS APPLICABLE TO COMMON STOCK $ 227.9 $ 270.5 $ 447.4 $ 529.0
=========== =========== =========== ===========
AVERAGE SHARES OF COMMON STOCK
OUTSTANDING (Millions) 186.6 223.1 200.5 222.8
=========== =========== =========== ===========
EARNINGS PER AVERAGE COMMON SHARE:
BASIC:
Income Before Extraordinary Item $ 1.22 $ 1.21 $ 2.36 $ 2.37
Extraordinary Item -- -- (0.13) --
----------- ----------- ----------- -----------
Net Income $ 1.22 $ 1.21 $ 2.23 $ 2.37
=========== =========== =========== ===========
DILUTED:
Income Before Extraordinary Item $ 1.21 $ 1.20 $ 2.34 $ 2.36
Extraordinary Item -- -- (0.13) --
----------- ----------- ----------- -----------
Net Income $ 1.21 $ 1.20 $ 2.21 $ 2.36
=========== =========== =========== ===========
DIVIDENDS PER AVERAGE COMMON SHARE $ 0.25 $ 0.25 $ 0.75 $ 0.75
=========== ============ =========== ===========
See Notes to Condensed Consolidated Financial Statements.
2
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Millions of Dollars)
September 30, December 31,
1999 1998
(Unaudited)
ASSETS
UTILITY PLANT
Electric - Transmission & Distribution $ 3,912.1 $ 3,833.8
Electric - Generation 1,748.5 1,713.4
Gas 1,161.5 1,132.0
Common 403.4 407.3
----------- -----------
7,225.5 7,086.5
Less Accumulated Provision for Depreciation 3,062.7 2,891.3
----------- -----------
4,162.8 4,195.2
Nuclear Fuel, net 285.7 141.9
Construction Work in Progress 396.8 272.6
Leased Property, net 0.5 154.3
----------- -----------
4,845.8 4,764.0
----------- -----------
CURRENT ASSETS
Cash and Cash Equivalents 664.2 48.1
Accounts Receivable, net
Customer 216.6 97.5
Other 415.5 213.2
Inventories, at average cost
Fossil Fuel 81.0 92.3
Materials and Supplies 99.7 82.1
Other 70.8 19.0
----------- -----------
1,547.8 552.2
----------- -----------
DEFERRED DEBITS AND OTHER ASSETS
Competitive Transition Charge 5,274.6 5,274.6
Recoverable Deferred Income Taxes 623.0 614.4
Deferred Non-Pension Postretirement Benefits Costs 86.0 90.9
Investments 604.5 538.1
Loss on Reacquired Debt 72.3 77.2
Other 131.9 107.1
----------- -----------
6,792.3 6,702.3
----------- -----------
TOTAL $ 13,185.9 $ 12,018.5
=========== ===========
See Notes to Condensed Consolidated Financial Statements.
(continued on next page)
3
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Millions of Dollars)
(continued)
September 30, December 31,
1999 1998
(Unaudited)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION
Common Shareholders' Equity:
Common Stock (No Par) $ 3,617.7 $ 3,589.0
Other Paid-In Capital 1.2 1.2
Accumulated Deficit (225.6) (532.9)
Treasury Stock (1,507.3) --
Preferred and Preference Stock:
Without Mandatory Redemption 137.5 137.5
With Mandatory Redemption 55.6 92.7
Company Obligated Mandatorily Redeemable
Preferred Securities of a Partnership 128.1 349.4
Long-Term Debt 6,051.3 2,919.6
-------------- --------------
8,258.5 6,556.5
-------------- --------------
CURRENT LIABILITIES
Notes Payable, Bank 121.8 525.0
Long-Term Debt Due Within One Year 146.2 361.5
Capital Lease Obligations Due Within One Year -- 69.0
Accounts Payable 373.4 316.2
Taxes Accrued 263.5 170.5
Interest Accrued 70.2 61.5
Deferred Income Taxes 2.8 14.1
Deferred Energy Costs - Gas 13.5 (29.9)
Other 196.0 217.4
-------------- --------------
1,187.4 1,705.3
-------------- --------------
DEFERRED CREDITS AND OTHER LIABILITIES
Capital Lease Obligations 0.5 85.3
Deferred Income Taxes 2,382.6 2,376.9
Unamortized Investment Tax Credits 289.3 300.0
Pension Obligation 220.1 219.3
Non-Pension Postretirement Benefits Obligation 442.8 421.1
Other 404.7 354.1
-------------- --------------
3,740.0 3,756.7
-------------- --------------
COMMITMENTS AND CONTINGENCIES (NOTE 9)
TOTAL $ 13,185.9 $ 12,018.5
============== ==============
See Notes to Condensed Consolidated Financial Statements.
4
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(Millions of Dollars)
Nine Months Ended September 30,
1999 1998
CASH FLOWS FROM OPERATING ACTIVITIES
NET INCOME $ 456.9 $ 538.8
EXTRAORDINARY ITEM, NET OF INCOME TAXES 26.7 --
---------- ----------
INCOME BEFORE EXTRAORDINARY ITEM 483.6 538.8
Adjustments to Reconcile Net Income to Net Cash
Provided by Operating Activities:
Depreciation and Amortization 245.6 514.2
Deferred Income Taxes (14.5) (55.8)
Amortization of Investment Tax Credits (10.7) (13.6)
Deferred Energy Costs 43.3 17.7
Amortization of Debt Discount/Premium 2.8 --
Changes in Working Capital:
Accounts Receivable (313.8) (154.1)
Inventories (6.3) 4.2
Accounts Payable 57.1 (18.8)
Other Current Assets and Liabilities 50.8 120.1
Other Items Affecting Operations 103.6 96.4
---------- ----------
CASH FLOWS PROVIDED BY OPERATING ACTIVITIES 641.5 1,049.1
---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES
Investment in Plant (361.5) (316.9)
Increase in Investments (80.1) (40.0)
---------- ----------
NET CASH FLOWS USED IN INVESTING ACTIVITIES (441.6) (356.9)
---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of Long-Term Debt 3,996.8 9.8
Common Stock Repurchase (1,507.3) --
Debt Repayments (1,236.4) (265.8)
Change in Short-Term Debt (403.2) (285.5)
Dividends on Preferred and Common Stock (159.5) (176.9)
Issuance of COMRPS -- 78.1
Retirement of COMRPS (221.3) (80.9)
Retirement of Mandatorily Redeemable Preferred Stock (37.1) --
Issuance of Common Stock 13.9 46.4
Other Items Affecting Financing (29.7) (6.9)
---------- ----------
NET CASH FLOWS PROVIDED BY (USED IN) FINANCING ACTIVITIES 416.2 (681.7)
---------- ----------
INCREASE IN CASH AND CASH EQUIVALENTS 616.1 10.5
---------- ----------
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 48.1 33.4
---------- ----------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 664.2 $ 43.9
========== ==========
See Notes to Condensed Consolidated Financial Statements.
5
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
1. BASIS OF PRESENTATION
The accompanying condensed consolidated financial statements as of
September 30, 1999 and for the three and nine months then ended are unaudited,
but include all adjustments that PECO Energy Company (Company) considers
necessary for a fair presentation of such financial statements. All adjustments
are of a normal, recurring nature. The year-end condensed consolidated balance
sheet data were derived from audited financial statements but do not include all
disclosures required by generally accepted accounting principles. Certain
prior-year amounts have been reclassified for comparative purposes. These notes
should be read in conjunction with the Notes to Consolidated Financial
Statements in the Company's 1998 Annual Report to Shareholders, which are
incorporated by reference in the Company's Annual Report on Form 10-K for the
year ended December 31, 1998.
2. MERGER WITH UNICOM CORPORATION
On September 22, 1999, the Company along with its wholly owned
subsidiary (Newco) and Unicom Corporation (Unicom) entered into an Agreement and
Plan of Exchange and Merger (Merger Agreement) providing for a merger of equals.
The Merger Agreement has been unanimously approved by both companies' Boards of
Directors. The transaction will be accounted for as a purchase with the Company
as acquiror.
The Merger Agreement was filed by the Company with the Securities and
Exchange Commission (SEC) as an exhibit to the Form 8-K filed September 29,
1999. The following description of the Merger Agreement does not purport to be
complete and is qualified in its entirety by reference to the provisions of the
Merger Agreement.
The Merger Agreement provides for (a) the mandatory exchange of the
outstanding common stock, no par value, of the Company for common stock of Newco
(Newco Common Stock) or cash (the Share Exchange) and (b) the merger of Unicom
with and into Newco (the Merger and together with the Share Exchange, the Merger
Transaction). In the Merger, holders of the outstanding common stock, no par
value, of Unicom (Unicom Common Stock) will exchange their shares for Newco
Common Stock or cash. The cash consideration option available to the
shareholders of the Company and Unicom is limited to $750 million for each
companies' common stock. As a result of the Share Exchange, the Company will
become a wholly owned subsidiary of Newco. As a result of the Merger, Unicom
will cease to exist and its subsidiaries, including Commonwealth Edison Company,
an Illinois corporation (ComEd), will become subsidiaries of Newco. Thus,
following the Merger Transaction, Newco will be a holding company with two
principal utility subsidiaries, ComEd and the Company.
The Merger Transaction is conditioned, among other things, upon the
approvals of the common shareholders of both companies and the completion of
regulatory procedures with the appropriate regulatory agencies. The companies
intend to register Newco as a holding company with the SEC under the Public
Utility Holding Company Act of 1935.
6
3. TRANSITION BONDS
On March 25, 1999, PECO Energy Transition Trust (PETT), an independent
statutory business trust organized under the laws of Delaware and a wholly owned
subsidiary of the Company, issued $4 billion aggregate principal amount of
Transition Bonds (Transition Bonds) to securitize a portion of the Company's
authorized stranded cost recovery. The Transition Bonds are solely obligations
of PETT, secured by Intangible Transition Property sold by the Company to PETT
concurrently with the issuance of the Transition Bonds and certain other
collateral related thereto.
The terms of the Transition Bonds are as follows:
Approximate
Face Amount Bond Expected Final
Class (millions) Rates Maturity Maturity
A-1 $244.5 5.48% March 1, 2001 March 1, 2003
A-2 $275.4 5.63% March 1, 2003 March 1, 2005
A-3 $667.0 6.02% (a) March 1, 2004 March 1, 2006
A-4 $458.5 5.80% March 1, 2005 March 1, 2007
A-5 $464.6 6.10% (a) September 1, 2007 March 1, 2009
A-6 $993.4 6.05% March 1, 2007 March 1, 2009
A-7 $896.6 6.13% September 1, 2008 March 1, 2009
(a) The Class A-3 and A-5 Transition Bonds bear interest at floating
rates. The rates provided for each such class above are as of September
30, 1999.
The Company entered into treasury forwards and forward starting
interest rate swaps to manage interest rate exposure associated with the
anticipated issuance of Transition Bonds. On March 18, 1999, these instruments
were settled with net proceeds to the Company of approximately $80 million which
were deferred and are being amortized over the life of the Transition Bonds as a
reduction of interest expense, consistent with the Company's hedge accounting
policy.
The Company has entered into interest rate swaps to manage interest
rate exposure associated with the issuance of two floating rate series of
Transition Bonds. At September 30, 1999, the fair value of these instruments was
$75 million based on the present value difference between the contracted rate
(i.e., hedged rate) and the market rates at that date. A hypothetical 50 basis
point increase or decrease in the spot yield at September 30, 1999 would have
resulted in an aggregate fair value of these interest rate swaps of $111 million
or $36 million, respectively. If the derivative instruments had been terminated
at September 30, 1999, these estimated fair values represent the amount to be
paid by the counterparties to the Company.
The net proceeds to the Company from the securitization of a portion of
its allowed stranded cost recovery, after payment of fees and expenses and the
capitalization of PETT, were approximately $3.95 billion. In accordance with the
provisions of the Pennsylvania Electricity
7
Generation Customer Choice and Competition Act, the Company is utilizing these
proceeds principally to reduce its stranded costs and related capitalization.
Through September 30, 1999, the Company utilized the net proceeds to repurchase
38.7 million shares of Common Stock for an aggregate purchase price of $1.507
billion; to retire: $811 million of First Mortgage Bonds, a $400 million term
loan, $208 million of commercial paper, $150 million of accounts receivable
financing, a $139 million capital lease obligation and $37 million of
Mandatorily Redeemable Preferred Stock; to redeem $221 million of Company
Obligated Mandatorily Redeemable Preferred Securities of a Partnership (COMRPS);
and to pay $25 million of debt issuance costs. The remaining proceeds of
approximately $450 million are included in cash and cash equivalents at
September 30, 1999.
In the second quarter of 1999, the Company incurred an extraordinary
charge of $26.7 million, net of tax, consisting of prepayment premiums and the
write-off of unamortized deferred financing costs associated with the early
retirement of debt.
4. SEGMENT INFORMATION
The Company is primarily a vertically integrated public utility that
provides retail electric and natural gas service to the public in its
traditional service territory and retail electric generation service throughout
Pennsylvania pursuant to Pennsylvania's Customer Choice Program. The Company's
management has historically managed the Company as a vertically integrated
entity by analyzing its results of operations on a consolidated basis with an
emphasis on electric and gas operations.
In 1999, the Company completed the redesign of its internal reporting
structure to separate its distribution, generation, and ventures operations into
business units and provide financial and operational data on the same basis to
senior management. The Company's distribution business unit consists of its
electric transmission and distribution services, regulated retail sales of
generation services and retail gas sales and services. The Company's generation
business unit consists of the operation of its generation assets, its power
marketing group and its unregulated retail energy supplier. The Company's
ventures business unit consists of its infrastructure services business and its
telecommunications equity investments.
The Company's segment information as of and for the three and nine
months ended September 30, 1999 as compared to the same 1998 period is as
follows (in millions of dollars):
8
Quarter Ended September 30, 1999 as compared to the Quarter Ended
September 30, 1998
Intersegment
Distribution Generation Ventures Corporate Revenues Consolidated
------------ ---------- -------- --------- -------- ------------
Revenues:
1999 $ 882.1 $1,084.9 $ 13.7 $ -- $(248.9) $1,731.8
1998 $1,075.5 $ 993.0 $ -- $ -- $(283.1) $1,785.5
EBIT (a):
1999 $390.3 $ 139.8 $( 9.4) $ ( 40.2) $ 480.5
1998 $500.9 $ 121.3 $( 34.6) $ ( 50.9) $ 536.7
Nine Months Ended September 30, 1999 as compared to Nine Months Ended
September 30, 1998
Revenues:
1999 $2,528.6 $2,267.6 $ 15.0 $ -- $(628.6) $4,182.6
1998 $2,931.2 $2,022.6 $ -- $ -- $(762.9) $4,190.9
EBIT (a):
1999 $1,055.3 $ 197.1 $( 46.2) $( 122.7) $1,083.5
1998 $1,171.2 $ 212.4 $( 93.3) $( 139.8) $1,150.5
Total Assets:
1999 $10,664.5(b) $1,857.9 $238.9 $424.6 $13,185.9
1998 $10,001.9 $1,728.7 $222.3 $395.1 $12,348.0
(a) EBIT - Earnings Before Interest and Income Taxes.
(b) Includes $450 million of proceeds from securitization of stranded costs.
5. EARNINGS PER SHARE
Diluted earnings per average common share is calculated by dividing
earnings applicable to common stock by the average number of shares of common
stock outstanding after giving effect to stock options issuable under the
Company's stock option plans which are considered to be dilutive common stock
equivalents. The following table shows the effect of the stock options issuable
under the Company's stock option plans on the average number of shares used in
calculating diluted earnings per average common share (in millions of shares):
Three Months Ended Nine Months Ended
September 30, September 30,
-------------- --------------
1999 1998 1999 1998
----- ----- ----- -----
Average Common Shares Outstanding 186.6 223.1 200.5 222.8
Assumed Exercise of Stock Options 1.5 1.9 1.5 1.7
----- ----- ----- -----
Potential Average Dilutive
Common Shares Outstanding 188.1 225.0 202.0 224.5
===== ===== ===== =====
9
6. SALES OF ACCOUNTS RECEIVABLE
The Company is party to an agreement with a financial institution under
which it can sell or finance with limited recourse an undivided interest,
adjusted daily, in up to $275 million of designated accounts receivable until
November 2000. At September 30, 1999, the Company had sold a $275 million
interest in accounts receivable, consisting of a $226 million interest in
accounts receivable which the Company accounts for as a sale under Statement of
Financial Accounting Standards (SFAS) No. 125, "Accounting for Transfers and
Servicing of Financial Assets and Extinguishment of Liabilities," and a $49
million interest in special agreement accounts receivable which are accounted
for as a long-term note payable. The Company retains the servicing
responsibility for these receivables. The agreement requires the Company to
maintain the $275 million interest, which, if not met, requires the Company to
deposit cash in order to satisfy such requirements. The Company, at September
30, 1999, met such requirements. At September 30, 1999, the average annual
service rate charged to the Company, computed on a daily basis on the portion of
the accounts receivable sold but not yet collected, was 5.22%.
7. AMERGEN ENERGY COMPANY
AmerGen Energy Company, LLC (AmerGen), the joint venture between the
Company and British Energy, plc (British Energy), has entered into agreements to
purchase Three Mile Island Unit No. 1 Nuclear Generating Facility, Nine Mile
Point Unit 1 Nuclear Generating Facility, a 59% undivided interest in Nine Mile
Point Unit 2 Nuclear Generating Facility, Clinton Nuclear Power Station
(Clinton) and Oyster Creek Nuclear Generating Facility.
8. CLINTON NUCLEAR POWER STATION
Under the Amended Management Agreement, effective April 1, 1999 between
the Company and Illinois Power (IP) providing for the provision of certain
management services by the Company to IP in support of Clinton's outage recovery
efforts and operations, the Company is responsible for the payment of all direct
operating and maintenance (O&M) costs and direct capital costs incurred by IP
and allocable to the operation of Clinton. These costs are reflected in the
Company's O&M expenses. IP will continue to pay indirect costs such as pension
benefits, payroll taxes and property taxes. Following the restart of Clinton on
June 2, 1999, and through December 31, 1999, the Company has agreed to sell 80%
of the output of Clinton to IP. The remaining output is being sold by the
Company in the wholesale market. Under a separate agreement with the Company,
British Energy has agreed to share 50% of the costs and revenues associated with
the Amended Management Agreement. In the third quarter and for the nine months
ended September 30, 1999, the Company recognized revenue from sales to IP of $47
million and $62 million, respectively, and O&M expenses related to Clinton of
$23 million and $48 million, respectively.
9. COMMITMENTS AND CONTINGENCIES
For information regarding the Company's capital commitments, nuclear
insurance, nuclear decommissioning and spent fuel storage, energy commitments,
environmental issues and
10
litigation, see Note 5 of Notes to Consolidated Financial Statements for the
year ended December 31, 1998.
At September 30, 1999, the Company had entered into long-term
agreements with unaffiliated utilities to purchase transmission rights. These
purchase commitments result in obligations of approximately $3 million in 1999,
$88 million in 2000, $47 million in 2001, $17 million in 2002, $10 million in
2003 and $18 million thereafter.
The Company has identified 28 sites where former manufactured gas plant
(MGP) activities have or may have resulted in actual site contamination. As of
September 30, 1999, the Company had accrued $58 million for environmental
investigation and remediation costs, including $32 million for MGP investigation
and remediation that currently can be reasonably estimated. The Company cannot
predict whether it will incur other significant liabilities for additional
investigation and remediation costs at these or additional sites identified by
the Company, environmental agencies or others, or whether all such costs will be
recoverable from third parties.
In November 1997, the Company signed an agreement with the
Massachusetts Health and Education Facilities Authority (HEFA) to provide power
to HEFA's members and employees in anticipation of deregulation of the
electricity industry in Massachusetts. In the third quarter of 1999, the Company
determined that based upon anticipated prices of energy in Massachusetts through
the remaining life of the HEFA contract that it had incurred a loss of
approximately $36 million.
On April 23, 1999, the Company and Grays Ferry Cogeneration Partnership
(Grays Ferry) entered into a final settlement of litigation, subject to the
resolution of certain issues. The settlement resulted in a restructuring of the
power purchase agreements between the Company and Grays Ferry. The settlement
also required the Company to contribute its partnership interest in Grays Ferry
to the remaining partners. Accordingly, in the first quarter, the Company
recorded a charge to earnings of $14.6 million for the transfer of its
partnership interest. The charge for the partnership interest transfer is
recorded in Other Income and Deductions on the Company's Consolidated Statements
of Income. The settlement also resolved the litigation with Westinghouse Power
Generation and the Chase Manhatten Bank.
During the third quarter of 1999, the Company revised its estimate for
losses associated with the Grays Ferry power purchase agreements and reversed
approximately $26 million of reserves, which consisted of the remaining balance
of the reserve recognized in 1997.
At December 31, 1998, the Company incurred a charge of $125 million for
its Early Retirement and Separation Program relating to 1,157 employees. The
reserve for separation benefits was approximately $47 million, of which $24
million was paid through September 30, 1999. Retirement benefits are being paid
to the retirees over their lives. Of the 1,157 employees,
11
343 were eligible for and have taken the retirement incentive program and 374
employees were terminated with the enhanced severance benefit program. The
remaining employees are scheduled for termination through the end of June 2000.
10. NEW ACCOUNTING PRONOUNCEMENTS
In June 1998, the Financial Accounting Standards Board (FASB) issued
SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities,"
(SFAS No. 133) to establish accounting and reporting standards for derivatives.
The new standard requires recognizing all derivatives as either assets or
liabilities on the balance sheet at their fair value and specifies the
accounting for changes in fair value depending upon the intended use of the
derivative. In June 1999, the FASB issued SFAS No. 137 "Accounting for
Derivative Instruments and Hedging Activities - Deferral of the Effective Date
of FASB Statement No. 133," (SFAS No. 137) which delayed the effective date for
SFAS No. 133 until fiscal years beginning after June 15, 2000. The Company
expects to adopt SFAS No. 133 in the first quarter of 2001. The Company is in
the process of evaluating the impact of SFAS No. 133 on its financial
statements.
In November 1998, the FASB's Emerging Issues Task Force (EITF) issued
EITF 98-10, "Accounting for Contracts Involved in Energy Trading and Risk
Management Activities." EITF 98-10 outlines attributes that may be indicative of
an energy trading operation and gives further guidance on the accounting for
contracts entered into by an energy trading operation. This accounting guidance
requires mark-to-market accounting for contracts considered to be a trading
activity. EITF 98-10 is applicable for fiscal years beginning after December 15,
1998 with any impact recorded as a cumulative effect adjustment through retained
earnings at the date of adoption.
As part of its wholesale marketing operations, the Company enters into
long-term and short-term commitments to purchase and sell energy and
energy-related products with the intent and ability to deliver or take delivery.
The objective of the long-term commitments is to establish a generation base
that allows the Company to meet the physical supply and demand requirements of a
national wholesale electric marketplace through scheduled, real-time delivery of
electricity. The Company utilizes short-term energy commitments and contracts,
entered into in the over-the-counter market, to economically hedge seasonal and
operational risks associated with peak demand periods and generation plant
outages.
The Company reviewed the criteria indicative of an energy trading
operation as outlined in EITF 98-10 against the objectives and intent of the
Company's wholesale marketing operation's activities. The Company concluded that
none of the activities of its marketing operation are trading activities and
therefore these activities are not subject to EITF 98-10.
The Company records revenues and expenses associated with the energy
commitments at the time the underlying physical transaction closes.
Additionally, the Company evaluates its portfolio of energy commitments for
impairment based on the lower of cost or market. At September 30, 1999, the
Company concluded that no energy commitments were impaired other than the HEFA
and Grays Ferry power purchase agreements as described above.
12
11. SUBSEQUENT EVENTS
Exelon Infrastructure Services, Inc. Acquisitions
In October 1999, Exelon Infrastructure Services, Inc. (EIS), an
unregulated subsidiary of the Company, acquired the stock or assets of six
utility service contracting companies for an aggregate purchase price of
approximately $240 million, including stock of EIS. The acquisitions were
accounted for using the purchase method of accounting. The preliminary estimate
of the excess of purchase price over the fair value of net assets acquired was
approximately $160 million.
Debt Refinancing
On October 14, 1999, the Company refinanced $156.4 million of pollution
control notes with a weighted average interest rate of 7.1% with new pollution
control notes in the same aggregate amount with a weighted average interest rate
of 5.2%. The Company incurred $16.5 million of costs associated with the
refinancing which consisted of $11.2 million for prepayment premiums and $5.3
million in unamortized debt discount, deferred financing fees and tender offer
costs associated with the original pollution control notes. These costs will be
reflected as an extraordinary item in the fourth quarter of 1999.
13
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
GENERAL
On September 22, 1999, the Company along with its wholly owned
subsidiary (Newco) and Unicom Corporation (Unicom) entered into an Agreement and
Plan of Exchange and Merger (Merger Agreement) providing for a merger of equals.
The Merger Agreement has been unanimously approved by both companies' Boards of
Directors. The transaction will be accounted for as a purchase with the Company
as acquiror.
The Merger Agreement was filed by the Company with the Securities and
Exchange Commission (SEC) as an exhibit to the Form 8-K filed September 29,
1999. The following description of the Merger Agreement does not purport to be
complete and is qualified in its entirety by reference to the provisions of the
Merger Agreement.
The Merger Agreement provides for (a) the mandatory exchange of the
outstanding common stock, no par value, of the Company for common stock of Newco
(Newco Common Stock) or cash (the Share Exchange) and (b) the merger of Unicom
with and into Newco (the Merger and together with the Share Exchange, the Merger
Transaction). In the Merger, holders of the outstanding common stock, no par
value, of Unicom (Unicom Common Stock) will exchange their shares for Newco
Common Stock or cash. The cash consideration option available to the
shareholders of the Company and Unicom is limited to $750 million for each
companies' common stock. As a result of the Share Exchange, the Company will
become a wholly owned subsidiary of Newco. As a result of the Merger, Unicom
will cease to exist and its subsidiaries, including Commonwealth Edison Company,
an Illinois corporation (ComEd), will become subsidiaries of Newco. Thus,
following the Merger Transaction, Newco will be a holding company with two
principal utility subsidiaries, ComEd and the Company.
The Merger Transaction is conditioned, among other things, upon the
approvals of the common shareholders of both companies and the completion of
regulatory procedures with the appropriate regulatory agencies. The companies
intend to register Newco as a holding company with the SEC under the Public
Utility Holding Company Act of 1935.
Retail competition for electric generation services began in
Pennsylvania on January 1, 1999. As of January 2, 1999, two-thirds of each class
of the Company's retail electric customers in its traditional service territory
have a right to choose their generation suppliers. Effective January 2, 2000,
all of the Company's retail electric customers in its traditional service
territory will have the right to choose their generation suppliers. At September
30, 1999, approximately 234,000 customers representing 15% of the Company's
residential customers, 26% of its commercial customers and 59% of its industrial
customers had selected an alternate energy supplier. As of that date, Exelon
Energy, the Company's alternative energy supplier, was providing electric
generation service to approximately 140,000 business and residential customers
located throughout Pennsylvania.
14
Effective January 1, 1999, the Company reduced its retail electric
rates for all customers by 8%. On that date, the Company began recovering its
stranded costs through the collection of competitive transition charges from all
customers. On March 25, 1999, PECO Energy Transition Trust (PETT), a wholly
owned subsidiary of the Company, issued $4 billion of PETT Transition Bonds to
securitize a portion of the Company's stranded cost recovery. In accordance with
the terms of the Competition Act, the Company is utilizing the proceeds from the
issuance of the Transition Bonds principally to reduce stranded costs and
capitalization.
The Company currently estimates that the impact of additional interest
expense associated with the Transition Bonds partially offset by interest
savings related to higher cost debt retired with Transition Bond proceeds,
combined with the anticipated reduction in common equity, will result in
earnings per share benefits of approximately $0.15 and $0.50 in 1999 and 2000,
respectively. These estimated earnings per share benefits could change and are
largely dependent upon the timing and price of common stock repurchases and
anticipated net income available to common stock.
The Company expects that competition for both retail and wholesale
generation services will substantially affect its future results of operations.
See "Management's Discussion and Analysis of Financial Condition and Results of
Operations - Outlook," incorporated by reference in the Company's Annual Report
on Form 10-K for the year ended December 31, 1998.
The Company's internal reporting structure includes its distribution,
generation, and ventures operations. The Company's distribution business unit
consists of its electric transmission and distribution services, regulated
retail sales of generation services and retail gas sales and services. The
Company's generation business unit consists of the operation of its generation
assets, its power marketing group and its unregulated retail energy supplier.
The Company's ventures business unit consists of its infrastructure services
business and its telecommunications equity investments.
RESULTS OF OPERATIONS
The Company's Condensed Consolidated Statements of Income for the three
and nine months ended September 30, 1998 reflect the reclassification of the
results of operations of Exelon Energy from Other Income and Deductions.
In the third quarter of 1999, the Company reclassified the results of
operations of its infrastructure services business, Exelon Infrastructure
Services, Inc. (EIS), in its Condensed Consolidated Statement of Operations from
Other Income and Deductions. EIS provides infrastructure services including
infrastructure construction, operation management and maintenance services to
owners of electric, gas and telecommunications systems, including industrial and
commercial customers, utilities and municipalities.
15
Under its Amended Management Agreement with Illinois Power (IP),
effective April 1, 1999, the Company is responsible for the payment of all
direct operating and maintenance (O&M) costs and direct capital costs incurred
by IP and allocable to the operation of Clinton Nuclear Power Station (Clinton).
These costs are reflected in the Company's O&M expenses. IP is responsible for
indirect costs such as pension benefits, payroll taxes and property taxes.
Following the restart of Clinton on June 2, 1999, and through December 31, 1999,
the Company has agreed to sell 80% of the output of Clinton to IP. The remaining
output is being sold by the Company in the wholesale market. Under a separate
agreement with the Company, British Energy has agreed to share 50% of the costs
and revenues associated with the Amended Management Agreement.
Revenue and Expense Items as a
Percentage of Total Operating
Revenues Percentage Dollar Changes
1999 vs. 1998
Quarter Nine Months Quarter Nine Months
Ended Ended Ended Ended
September 30, September 30, September 30, September 30,
1999 1998 1999 1998
---- ---- ---- ----
97% 97% 91% 92% Electric (3%) (1%)
3% 3% 9% 8% Gas 1% 11%
---- ---- ---- ----
100% 100% 100% 100% Total Operating Revenues (3%) --
---- ---- ---- ----
45% 41% 41% 35% Fuel and Energy Interchange 6% 18%
19% 17% 23% 20% Operating and Maintenance 10% 15%
3% 8% 4% 11% Depreciation and Amortization (63%) (64%)
4% 3% 5% 5% Taxes Other Than Income 44% (5%)
---- ---- ---- ----
71% 69% 73% 71% Total Operating Expenses (1%) 3%
---- ---- ---- ----
29% 31% 27% 29% Operating Income (10%) (7%)
---- ---- ---- ----
(7%) (5%) (7%) (6%) Interest Charges 27% 14%
Equity in Losses of
-- (1%) (1%) (1%) Unconsolidated Affiliates (62%) (29%)
(1%) -- (1%) (1%) Other Income and Deductions 263% 95%
---- ---- ---- ----
Income Before Income Taxes and
21% 25% 18% 21% Extraordinary Item (18%) (12%)
8% 10% 6% 8% Income Taxes (21%) (15%)
---- ---- ---- ----
13% 15% 12% 13% Income Before Extraordinary Item (16%) (10%)
-- -- (1%) -- Extraordinary Item -- --
---- ---- ---- ----
13% 15% 11% 13% Net Income (16%) (15%)
==== ==== ==== ====
Third Quarter 1999 Compared To Third Quarter 1998
Operating Revenues
Electric revenues decreased $54 million, or 3%, for the quarter ended
September 30, 1999 compared to the same 1998 period. The decrease was
attributable to lower revenues from the distribution business unit of $194
million partially offset by higher revenues from the generation
16
business unit of $125 million and the ventures business unit of $15 million. The
decrease from the distribution business unit was primarily attributable to $171
million as a result of lower volume associated with the effects of competition,
$71 million related to the 8% across-the-board rate reduction mandated by the
Final Restructuring Order and $42 million related to decreased volume from
existing customers. These decreases were partially offset by $51 million of
increased volume due to warmer weather conditions as compared to the same 1998
period and $37 million of PJM Interconnection, LLC (PJM) network transmission
service revenue which commenced April 1, 1998. PJM network transmission service
revenues and charges were recorded in the generation business unit in 1998 but
are being recognized by the distribution business unit in 1999 as a result of
the Federal Energy Regulatory Commission approval of the PJM Regional
Transmission Owners' rate case settlements. Stranded cost recovery is included
in the Company's retail electric rates beginning January 1, 1999. The increase
from the generation business unit was primarily attributable to $136 million
from increased volume in Pennsylvania resulting from the sale of competitive
electric generation services by Exelon Energy and $47 million from the sale of
generation from Clinton to IP, partially offset by decreased wholesale revenues
of $21 million as a result of lower volume and $39 million of PJM network
transmission service revenue in the same 1998 period. The increase in revenues
from the ventures business unit is attributable to infrastructure service
revenues.
Gas revenues increased $1 million, or 1%, for the quarter ended
September 30, 1999 compared to the same 1998 period. The increase was primarily
attributable to increased volume from new and existing customers.
Fuel and Energy Interchange Expense
Fuel and energy interchange expense increased $53 million, or 6%, for
the quarter ended September 30, 1999 compared to the same 1998 period. As a
percentage of revenue, fuel and interchange expenses were 45% as compared to 41%
in the comparable prior year period. The increase was attributable to higher
fuel and energy interchange expenses associated with the distribution business
unit of $40 million and the generation business unit of $13 million. The
increase from the distribution business unit was attributable to $24 million of
PJM network transmission service charges and $16 million of purchases in the
spot market. The increase from the generation business unit was primarily
attributable to $259 million related to increased volume from Exelon Energy
sales, offset by $219 million of fuel savings from wholesale operations as a
result of lower volume and efficient operation of the Company's generating
assets and lower PJM network transmission service charges of $39 million and the
reversal of $27 million in reserves associated with the Grays Ferry Cogeneration
Partnership (Grays Ferry) in connection with the final settlement of litigation
and expected prices of electricity over the remaining life of the power purchase
agreements.
Operating and Maintenance Expense
O&M expense increased $31 million, or 10% for the quarter ended
September 30, 1999 compared to the same 1998 period. As a percentage of revenue,
operating and maintenance expenses were 19% as compared to 17% in the comparable
prior year period. The generation business unit's O&M expenses increased $34
million primarily as a result of $23 million related to the revised Clinton
management agreement, $8 million for the abandonment of a billing system and $6
million related to the growth of unregulated retail sales of electricity. The
distribution business unit's O&M expenses increased approximately $1 million
primarily as a result of additional expenses of $11 million resulting from
restoration efforts related to Hurricane Floyd offset by
17
lower customer expenses, transmission and distribution expenses and regulatory
commissions aggregating $10 million. The ventures business unit's O&M expenses
increased $15 million related to the infrastructure services business. In
addition, the Company experienced lower administrative and general expense of
$18 million and lower pension expense of $7 million as a result of the
performance of the investments in the Company's pension plan. These decreases
were partially offset by $4 million associated with Year 2000 remediation
expenditures.
Depreciation and Amortization Expense
Depreciation and amortization expense decreased $96 million, or 63%,
for the quarter ended September 30, 1999 compared to the same 1998 period. As a
percentage of revenue, depreciation and amortization expense was 3% as compared
to 8% in the comparable prior year period. The decrease was associated with the
December 1997 restructuring charge through which the Company wrote down a
significant portion of its generating plant and regulatory assets. In connection
with this restructuring charge, the Company reduced generation-related assets by
$8.4 billion, established a regulatory asset, Deferred Generation Costs
Recoverable in Current Rates of $424 million, which was fully amortized in 1998,
and established an additional regulatory asset, Competitive Transition Charge
(CTC) of $5.26 billion which will begin to be amortized in accordance with the
terms of the Final Restructuring Order in 2000. For additional information, see
"PART I, ITEM 1. - BUSINESS - Deregulation and Rate Matters," in the Company's
1998 Annual Report on Form 10-Q/A, hereby10-K.
Taxes Other Than Income
Taxes other than income increased $23 million, or 44%, for the quarter
ended September 30, 1999 compared to the same 1998 period. As a percentage of
revenue, taxes other than income were 4%, as compared to 3%, in the comparable
prior year period. The increase was primarily attributable to a refund of the
Company's Pennsylvania gross receipts tax in September 1998.
Interest Charges
Interest charges consist of interest expense, distributions on Company
Obligated Mandatorily Redeemable Preferred Securities of a Partnership (COMRPS)
and Allowance for Funds Used During Construction (AFUDC). Interest charges
increased $24 million, or 27%, for the quarter ended September 30, 1999 compared
to the same 1998 period. As a percentage of revenue, interest charges were 7% as
compared to 5% in the comparable prior year period. The increase was primarily
attributable to interest on the Transition Bonds of $66 million, partially
offset by the Company's reduction and/or refinancing of higher cost, long-term
debt, including the use of a portion of the proceeds from the issuance of
Transition Bonds, which reduced interest charges by $42 million.
Equity in Losses of Unconsolidated Affiliates
Equity in losses of unconsolidated affiliates was $6 million for the
quarter ended September 30, 1999 as compared to $15 million in the same 1998
period. The lower losses represent a 62% improvement in the Company's equity
investments in telecommunications as a result of customer base growth.
18
Other Income and Deductions
Other income and deductions excluding interest charges and equity in
losses of unconsolidated affiliates was $2 million for the quarter ended
September 30, 1999 which is consistent with the same 1998 period. The quarter
ended September 1999 includes interest income earned on the unused portion of
the transition bond proceeds of $8 million offset by a settlement of a purchase
power agreement in the third quarter of 1998.
Income Taxes
The effective tax rate was 37.3% for the quarter ended September 30,
1999 as compared to 38.9% in the same 1998 period. The decrease in the effective
tax rate was primarily attributable to an income tax benefit of approximately
$11 million related to the favorable resolution of certain outstanding issues in
connection with the settlement of an Internal Revenue Service audit and tax
benefits associated with the implementation of state tax planning strategies,
partially offset by the non-recognition for state income tax purposes of certain
operating losses.
Preferred Stock Dividends
Preferred stock dividends for the quarter ended September 30, 1999
decreased $0.3 million or 9% as compared to the same 1998 period. The decrease
was attributable to the retirement of $37 million of Mandatorily Redeemable
Preferred Stock in August 1999 with a portion of the proceeds from the issuance
of Transition Bonds.
Nine Months Ended September 30, 1999 Compared to Nine Months Ended
September 30, 1998
Operating Revenues
Electric revenues decreased $45 million, or 1%, for the nine months
ended September 30, 1999 compared to the same 1998 period. The decrease was
primarily attributable to lower revenues from the distribution business unit of
$441 million partially offset by higher revenues from the generation business
unit of $380 million and $15 million from the ventures business unit. The
decrease from the distribution business unit was primarily attributable to $393
million as a result of lower volume associated with the effects of retail
competition and $249 million related to the 8% across-the-board rate reduction
mandated by the Final Restructuring Order. These decreases were partially offset
by $111 million of PJM network transmission service revenue and $83 million
related to increased volume as a result of colder weather conditions in the
first quarter of 1999, warmer weather conditions in the third quarter of 1999,
and additional volume related to new and existing customers as compared to the
same 1998 periods. The increase from the generation business unit was primarily
attributable to $341 million from increased volume in Pennsylvania resulting
from the sale of competitive electric generation services by Exelon Energy,
increased wholesale revenues of $56 million from the marketing of excess
generation capacity as a result of retail competition and revenues of $62
million from the sale of generation from Clinton to IP, partially offset by $78
million of PJM network transmission service revenue in the same 1998 period. The
increase in revenues from the ventures business unit is primarily attributable
to infrastructure service revenues.
Gas revenues increased $37 million, or 11%, for the nine months ended
September 30, 1999 compared to the same 1998 period. The increase was primarily
attributable to $24 million
19
from increased volume as a result of cooler weather conditions in the beginning
of the period as compared to the same 1998 period and $13 million from increased
volume from new and existing customers.
Fuel and Energy Interchange Expense
Fuel and energy interchange expense increased $264 million, or 18%, for
the nine months ended September 30, 1999 compared to the same 1998 period. As a
percentage of revenue, fuel and interchange expenses were 41% as compared to 35%
in the comparable prior year period. The increase was attributable to higher
fuel and energy interchange expenses associated with the distribution business
unit of $160 million and the generation business unit of $104 million. The
increase from the distribution business unit was attributable to $75 million of
PJM network transmission service charges, $64 million of purchases in the spot
market and $21 million of additional volume related to new and existing
customers. The increase from the generation business unit was primarily
attributable to $453 million related to increased volume from Exelon Energy
sales, partially offset by $252 million of fuel savings from wholesale
operations as a result of lower volume and efficient operation of the Company's
generating assets, lower PJM network transmission service charges of $78
million, and $19 million of fuel savings associated with the full return to
service of the Salem Generating Station (Salem) in April 1998 which decreased
the need to purchase power to replace the output from these units and the
reversal of $27 million in reserves associated with Grays Ferry in connection
with the final settlement of litigation and expected prices of electricity over
the remaining life of the power purchase agreements.
Operating and Maintenance Expense
O&M expense increased $126 million, or 15% for the nine months ended
September 30, 1999 compared to the same 1998 period. As a percentage of revenue,
operating and maintenance expenses were 23% as compared to 20% in the comparable
prior year period. The generation business unit's O&M expenses increased $89
million primarily as a result of $48 million related to the revised Clinton
management agreement, $8 million associated with the Salem inventory write-off
for excess and obsolete inventory, $7 million related to the true-up of 1998
reimbursement of joint-owner expenses, $15 million of charges related to the
abandonment of two information systems and $17 million related to the growth of
unregulated retail sales of electricity. These decreases were partially offset
by $10 million of lower O&M expenses as a result of the full return to service
of Salem in April 1998. The distribution business unit's O&M expenses increased
$15 million primarily as a result of $11 million of additional expenses related
to restoration activities as a result of Hurricane Floyd. The ventures business
unit's O&M expenses increased $15 million related to the infrastructure services
business. In addition, the Company incurred additional costs of $20 million
associated with Year 2000 remediation expenditures and $12 million related to
nuclear property insurance, partially offset by $17 million of lower pension
expense as a result of the performance of the investments in the Company's
pension plan and lower administrative and general expenses of $10 million.
Depreciation and Amortization Expense
Depreciation and amortization expense decreased $298 million, or 64%,
for the nine months ended September 30, 1999 compared to the same 1998 period.
As a percentage of revenue, depreciation and amortization expense was 4% as
compared to 11% in the comparable prior year period. The decrease was associated
with the December 1997 restructuring charge through which the Company wrote down
a significant portion of its generating plant and regulatory assets. In
connection with this restructuring charge, the Company reduced
generation-
20
related assets by $8.4 billion, established a regulatory asset, Deferred
Generation Costs Recoverable in Current Rates of $424 million, which was fully
amortized in 1998, and established an additional regulatory asset, Competitive
Transition Charge (CTC) of $5.26 billion which will begin to be amortized in
accordance with the terms of the Final Restructuring Order in 2000. For
additional information, see "PART I, ITEM 1. - BUSINESS - Deregulation and Rate
Matters," in the Company's 1998 Annual Report on Form 10-K.
Taxes Other Than Income
Taxes other than income decreased $10 million, or 5%, for the nine
months ended September 30, 1999 compared to the same 1998 period. As a
percentage of revenue, taxes other than income were 5%, which was consistent
with the comparable prior year period. The decrease was primarily attributable
to a $34 million credit related to an adjustment to the Company's Pennsylvania
capital stock tax base as a result of the 1997 restructuring charge partially
offset by a $22 million refund of the Company's Pennsylvania gross receipts tax
in September 1998.
Interest Charges
Interest charges increased $39 million, or 14%, for the nine months
ended September 30, 1999 compared to the same 1998 period. As a percentage of
revenue, interest charges were 7% as compared to 6% in the comparable prior year
period. The increase was primarily attributable to interest on the Transition
Bonds of $130 million, partially offset by the Company's reduction and/or
refinancing of higher cost, long-term debt from the use of a portion of the
proceeds from the issuance of Transition Bonds, which reduced interest charges
by $91 million.
Equity in Losses of Unconsolidated Affiliates
Equity in losses of unconsolidated affiliates was $28 million for the
nine months ended September 30, 1999 as compared to $40 million in the same 1998
period. The lower losses represent a 29% improvement in the Company's equity
investments in telecommunications as a result of customer base growth.
Other Income and Deductions
Other income and deductions excluding interest charges and equity in
earnings of unconsolidated affiliates was a loss of $1 million for the nine
months ended September 30, 1999 as compared to a loss of $12 million in the same
1998 period. The decrease of $11 million was primarily attributable to a $10
million write-off of a non-regulated business venture in the prior year period
and interest income of $22 million earned on the unused portion of the
transition bond proceeds, partially offset by a $15 million write-off of the
investment in Grays Ferry in connection with the settlement of litigation and a
settlement of a power purchase agreement in the third quarter of 1998.
Income Taxes
The effective tax rate was 37.2% for the nine months ended September
30, 1999 as compared to 38.5% in the same 1998 period. The decrease in the
effective tax rate was primarily attributable to an income tax benefit of
approximately $11 million related to the favorable resolution of certain
outstanding issues in connection with the settlement of an Internal Revenue
Service audit and tax benefits associated with the implementation of state tax
planning strategies, partially offset by the non-recognition for state income
tax purposes of certain operating losses.
21
Preferred Stock Dividends
Preferred stock dividends for the nine months ended September 30, 1999
decreased $0.3 million or 3% as compared to the same 1998 period. The decrease
was attributable to the retirement of $37 million of Mandatorily Redeemable
Preferred Stock in August 1999 with a portion of the proceeds from the issuance
of the Transition Bonds.
DISCUSSION OF LIQUIDITY AND CAPITAL RESOURCES
Cash flows provided by operating activities decreased $407 million to
$642 million for the nine months ended September 30, 1999 as compared to $1,049
million in the same 1998 period. The decrease was primarily attributable to less
cash generated by operations of $264 million and changes in working capital of
$164 million, principally related to accounts receivable from unregulated energy
sales.
Cash flows used by investing activities were $442 million for the signatorynine
months ended September 30, 1999 as compared to $357 million in the same 1998
period. The increase was attributable to capital expenditures and investments in
infrastructure services businesses and other ventures business unit investments.
Cash flows provided by financing activities were $416 million for the
nine months ended September 30, 1999, as compared to cash used in financing
activities of $682 million in the same 1998 period. The increase was
attributable to the issuance of $4 billion of PETT Transition Bonds, partially
offset by the use of Transition Bond proceeds to: repay short-term and long-term
debt aggregating $1.6 billion, repurchase $1.5 billion of common stock,
including the settlement of the Company's common stock forward purchase
contract, redemption $221 million of COMRPS and retire $37 million of
Mandatorily Redeemable Preferred Stock.
On March 25, 1999, PETT issued $4 billion of its Transition Bonds to
securitize a portion of the Company's authorized stranded cost recovery. The
Transition Bonds are solely obligations of PETT, secured by the Intangible
Transition Property (ITP) sold by the Company to PETT. Upon issuance of the
Transition Bonds, a portion of the CTCs to be collected by the Company to
recover stranded costs was designated as Intangible Transition Charges (ITC).
The ITC is an irrevocable non-bypassable usage based charge that is calculated
to allow for the recovery of debt service and costs related to the issuance of
the Transition Bonds. The ITC will be allocated from CTC and variable
distribution charges (both of which are usage based charges).
PETT used the $3.95 billion of proceeds of the Transition Bonds to
purchase the ITP from the Company. Although the Transition Bonds are solely
obligations of PETT, they are included in the consolidated long-term debt of the
Company. In accordance with the terms of the Competition Act, the Company is
utilizing the proceeds principally to reduce stranded costs and capitalization.
The Company currently plans to reduce its capitalization by applying the
proceeds in the following proportions: debt, 50%; preferred securities, 7%;
common equity, 43%. Through September 30, 1999, the Company utilized the net
proceeds to repurchase 38.7 million
22
shares of Common Stock for an aggregate purchase price of $1.507 billion; to
retire: $811 million of First Mortgage Bonds, a $400 million term loan, $208
million of commercial paper, $150 million of accounts receivable financing, a
$139 million capital lease obligation and $37 million of Mandatorily Redeemable
Preferred Stock; to redeem $221 million of COMRPS; and to pay $25 million of
debt issuance costs. The remaining proceeds of approximately $450 million are
included in cash and cash equivalents at September 30, 1999. The Company
currently anticipates that it will complete the repurchase of common equity
through open market purchases from time to time in compliance with SEC rules.
The number of shares purchased and the timing and manner of purchases are
dependent upon market conditions.
Although the Company has sold the ITP to PETT, the ITC revenue, as well
as all interest expense and amortization expense associated with the Transition
Bonds, is reflected on the Company's Consolidated Statement of Income. The
combined schedule for amortization of the CTC and ITC assets is in accordance
with the amortization schedule set forth in the Final Restructuring Order. The
Company completed the majority of the targeted debt and preferred security
reductions by August 2, 1999, and expects the application of proceeds to be
substantially completed by December 31, 1999. The weighted average cost of debt
and preferred securities that have been retired is approximately 6.8%. The
additional interest expense associated with the Transition Bonds, which
currently have an effective interest rate of approximately 5.8%, will be
partially offset by the interest savings associated with the debt and preferred
securities that have been retired. The Company currently estimates that the
impact of this additional expense, combined with the anticipated reduction in
common equity, will result in earnings per share benefits of approximately $0.15
and $0.50 in 1999 and 2000, respectively. These estimated earnings per share
could change and are largely dependent upon the timing and price of common stock
repurchases and anticipated net income available to common stock.
At September 30, 1999, the Company had outstanding $122 million of
notes payable, all of which were commercial paper. In addition, at September 30,
1999, the Company had available formal and informal lines of bank credit
aggregating $100 million and available revolving credit facilities aggregating
$900 million which support its commercial paper program. At September 30, 1999,
the Company had no short-term investments.
On October 14, 1999, the Company refinanced $156.4 million of pollution
control notes with a weighted average interest rate of 7.1% with new pollution
control notes in the same aggregate amount with a weighted average interest rate
of 5.2%. The Company incurred $16.5 million of costs associated with the
refinancing which consisted of $11.2 million for prepayment premiums and $5.3
million in unamortized debt discount, deferred financing fees and tender offer
costs associated with the original pollution control notes. These costs will be
reflected as an extraordinary item in the fourth quarter of 1999.
On May 3, 1999, Standard & Poor's upgraded its ratings on the Company's
overall corporate credit to "A-" from "BBB+", first and refunding mortgage bonds
and collateralized medium-term notes to "A" from "BBB+", hybrid preferred
securities, capital trust securities and
23
preferred stock to "BBB" from "BBB-". On September 24, 1999, Standard & Poor's
placed the Company's long-term ratings on CreditWatch with negative
implications.
YEAR 2000 READINESS DISCLOSURE
The Year 2000 Project (Y2K Project) is addressing the issue resulting
from computer programs using two digits rather than four to define the
applicable year and other programming techniques that constrain date
calculations or assign special meanings to certain dates. Any of the Company's
computer systems that have date-sensitive software or microprocessors may
recognize a date using "00" as the year 1900 rather than the year 2000. This
could result in a system failure or miscalculations causing disruptions of
operations, including a temporary inability to process transactions, send bills,
operate generating stations, or engage in similar normal business activities.
Due to the severity of the potential impact of the Year 2000 Issue (Y2K Issue)
on the electric utility industry, the Company adopted a comprehensive schedule
to achieve Y2K readiness by the time specified by the Nuclear Regulatory
Commission (NRC). The Company has dedicated extensive resources to the Y2K
Project and has achieved readiness as of November 5, 1999, as planned.
The Company determined that it was required to modify, convert or
replace significant portions of its software and a subset of its system hardware
and embedded technology so that its computer systems will properly utilize dates
beyond December 31, 1999. The Company presently believes that with these
modifications, conversions and replacements the effect of the Y2K Issue on the
Company has been mitigated. If such modifications, conversions and replacements
had not been made, or had not been completed in a timely manner, the Y2K Issue
could have had a material impact on the operations and financial condition of
the Company. The costs associated with this potential impact are not presently
quantifiable. The Company has utilized both internal and external resources to
reprogram, or replace and test software and computer systems for the Y2K
Project. These systems were scheduled for completion by July 1, 1999, except for
a small number of modifications, conversions or replacements that were impacted
by PUC changes, vendor dates and/or were being incorporated into scheduled plant
outages between July and November 1999. All systems are now Y2K ready.
The Y2K Project was divided into four major sections - Information
Technology Systems (IT Systems), Embedded Technology (devices used to control,
monitor or assist the operation of equipment, machinery or plant), Supply Chain
(third-party suppliers and customers), and Contingency Planning. The general
phases common to the first two sections were: (1) inventorying Y2K items; (2)
assigning priorities to identified items; (3) assessing the Y2K readiness of
items determined to be material to the Company; (4) converting material items
that are determined not to be Y2K ready; (5) testing material items; and (6)
designing and implementing contingency plans for each critical Company process.
Material items are those believed by the Company to have a risk involving the
safety of individuals, may cause damage to property or the environment, or
affect revenues.
24
The IT Systems section included both the conversion of applications software
that was not Y2K ready and the replacement of software when available from the
supplier. The Y2K Project has identified 363 critical systems of which 234 are
IT Systems and 129 are Embedded Systems. As of November 5, 1999, all of these
systems are Y2K ready. In addition, contingency planning for IT Systems and
Embedded systems has been completed.
The Supply Chain section included the process of identifying and
prioritizing critical suppliers and communicating with them about their plans
and progress in addressing the Y2K Issue. The process of evaluating critical
suppliers was completed on March 31, 1999. The Company has completed contingency
plans for all critical suppliers.
In addition to addressing contingency plans with key suppliers,
contingency plans have been developed to address operations that may
inadvertently have a Y2K related disruption. These plans address Y2K risk
scenarios that cross departments and business units. Emergency plans already
exist that cover various aspects of the Company's business. These plans have
been reviewed and updated to address the Y2K Issue. The Company is also
participating in industry contingency planning efforts.
The current estimated total cost of the Y2K Project is $70 million, the
majority of which is attributable to testing. This represents a $5 million
reduction of the previously estimated total cost of the Y2K Project. This
estimate includes the Company's share of Y2K costs for jointly owned facilities.
The total amount expended on the Y2K Project through September 30, 1999 was $50
million. The Company is funding the Y2K Project from operating cash flows. The
Company's failure to become Y2K ready could result in an interruption in or a
failure of certain normal business activities or operations. In addition, there
can be no assurance that the systems of other companies on which the Company's
systems rely or with which they communicate will be converted in a timely
manner, or that a failure to convert by another company, or a conversion that is
incompatible with the Company's systems, will not have a material adverse effect
on the Company. Such failures could materially and adversely affect the
Company's results of operations, liquidity and financial condition. The Company
has developed contingency plans to address how to respond to events that may
disrupt normal operations, including activities with PJM. The total costs of the
Y2K Project are based on estimates, that were derived utilizing numerous
assumptions of future events, including the continued availability of certain
resources, the execution of contingency plans, and other factors, such as
regulatory requirements that impact key systems. There can be no assurance that
these estimates will be achieved. Actual results could differ materially from
the projections. Specific factors that might cause a material change include,
but are not limited to, the availability and cost of trained personnel and the
need to execute contingency plans.
The Y2K Project significantly reduced the Company's level of
uncertainty about the Y2K Issue. The Company believes that the completion of the
Y2K Project, as scheduled, minimizes the possibility of significant
interruptions of normal operations.
On July 17, 1998, an order was entered by the PUC instituting a formal
investigation by the Office of Administrative Law on Y2K compliance by
jurisdictional fixed utilities and
25
mission-critical service providers such as the PJM (the Investigation). The
order required (1) a written response to a list of compliance program questions
by August 6, 1998 and, (2) all jurisdictional fixed utilities be Y2K compliant
by March 31, 1999 or, if a utility determines that mission-critical systems
cannot be Y2K compliant on or before March 31, 1999, the utility is required to
file a detailed contingency plan. The PUC adopted the federal government's
definition for Y2K compliance and further defined Y2K compliance as a
jurisdictional utility having all mission-critical Y2K hardware and software
updates and/or replacements installed and tested on or before March 31, 1999. On
August 6, 1998, the Company filed its written response, in which the Company
stated that with a few carefully-assessed and closely-managed exceptions, the
Company would have all mission-critical systems Y2K ready by June 1999. Pursuant
to the formal investigation on Y2K compliance, the Company presented testimony
before the PUC on November 20, 1998.
On February 19, 1999, the PUC issued a Secretarial Letter notifying the
Company that it had hired a consultant to perform an assessment of the Company
and thirteen other utilities to evaluate the accuracy of their responses to the
compliance program questions and testimony provided before the PUC. The Company
complied with the PUC's directive in the Secretarial Letter to file updated
written responses to compliance questions by March 8, 1999, and to meet with the
consultant during a one-day on-site review session on March 8, 1999. On March
31, 1999, the Company filed contingency plans with the PUC for its
mission-critical systems scheduled to be ready after the March 31, 1999
deadline.
On April 8, 1999, the PUC issued an order requiring the Office of
Administrative Law Judge to identify (1) utilities which have complied with the
PUC's order of July 17, 1998 (the Order); (2) utilities which have demonstrated
good cause for an extension of time within which they will fully comply with the
Order; and (3) those utilities which have not complied with the Order and have
not shown good cause for an extension. The PUC required that this information be
posted to the PUC internet website and periodically updated. The PUC further
ordered that the Investigation with respect to utilities who have demonstrated
good cause for an extension of time remain open and under the jurisdiction of
the Office of Administrative Law Judge until compliance is achieved or
enforcement is warranted. The Company has been identified by the PUC as a
utility which has demonstrated good cause for an extension of time within which
it will fully comply with the Order. Additional reporting dates to the
Administrative Law Judge included July 1, 1999 and October 1, 1999. A final
report was sent to the PUC on November 9, 1999 stating that all mission critical
systems were Y2K ready.
On May 11, 1998, the NRC issued a generic letter requiring all nuclear
plant operators to provide the NRC with the following information concerning the
operators' programs, planned or implemented, to address Y2K computer and system
issues at its facilities: (1) submission of a written response within 90 days,
indicating whether the operator has pursued and continues to pursue
implementation of Y2K programs and addressing the program's scope, assessment
process, plans for corrective actions, quality assurance measures, contingency
plans and regulatory compliance, and (2) submission of a written response, no
later than July 1, 1999, confirming that such facilities are Y2K ready, or will
be Y2K ready, by January 1, 2000 with regard to compliance with the terms and
conditions of the license(s) and NRC regulations. On
26
July 30, 1998, the Company filed its 90-day required written response indicating
that the Company has pursued and is continuing to pursue a Y2K program which is
similar to that outlined in Nuclear Utility Y2K Readiness, NEI/NUSMG 97.07.
From November 3 to November 5, 1998, members of the NRC staff conducted
an audit of the Company's Y2K Program for the Limerick Generating Station
(Limerick), Units No. 1 and No. 2. Some of the observations of the audit team
included in their written report issued on December 18, 1998, were that (1) the
Company's readiness program is comprehensive and based on the guidance contained
in NEI/NUSMG 97.07, (2) the program is receiving proper management support and
oversight, and (3) project schedules are being aggressively pursued.
On April 28, 1999, the NRC issued Information Notice 99-12 advising
nuclear power plant licensees that NRC staff would be conducting additional Y2K
readiness and contingency planning site-specific reviews at all commercial
nuclear power plants. The NRC performed its site-specific review of Peach Bottom
Atomic Power Station (Peach Bottom) from May 24 to May 28, 1999, and its review
of Limerick from June 7 to June 10, 1999.
On June 30, 1999, the Company filed its completed response to Generic
Letter 98-01. In the response, the Company confirmed that with the exception of
five non-safety plant systems, its Peach Bottom and Limerick are Y2K ready. The
Company advised the NRC that remediation for three of the remaining systems was
scheduled for completion by the conclusion of the fall outage at Peach Bottom.
On October 27, 1999, the Company reported to the NRC that all remaining systems
were Y2K ready.
For additional information regarding the Y2K Readiness Disclosure see
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" in the Company's Annual Report to Shareholders for the year 1998.
FORWARD-LOOKING STATEMENTS
Except for the historical information contained herein, certain of the
matters discussed in this Report are forward-looking statements, including the
estimated earnings per share benefits of the application of the Transition Bond
proceeds for 1999 and 2000, and accordingly, are subject to risks and
uncertainties. The factors that could cause actual results to differ materially
include those discussed herein as well as those listed in notes 3, 9 and 10 of
Notes to Condensed Consolidated Financial Statements and other factors discussed
in the Company's filings with the SEC. Readers are cautioned not to place undue
reliance on these forward-looking statements, which speak only as of the date of
this Report. The Company undertakes no obligation to publicly release any
revision to these forward-looking statements to reflect events or circumstances
after the date of this Report.
27
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
The Company has entered into interest rate swaps to manage interest
rate exposure associated with the issuance of two floating rate series of
Transition Bonds. At September 30, 1999, the fair value of these instruments was
$75 million based on the present value difference between the contracted rate
(i.e., hedged rate) and the market rates at that date. A hypothetical 50 basis
point increase or decrease in the spot yield at September 30, 1999 would have
resulted in an aggregate fair value of these interest rate swaps of $111 million
or $36 million, respectively. If the derivative instruments had been terminated
at September 30, 1999, these estimated fair values represent the amount to be
paid by the counterparties to the Company.
The Company's participation in the retail and wholesale electric
marketplace increases the Company's reliance on the efficient operation of its
generating units. The Company's ability to fully capitalize on volatile
wholesale market prices is also dependent on the performance of the Company's
generating units.
28
PART II - OTHER INFORMATION
ITEM 5. OTHER INFORMATION
As previously reported in the 1998 Form 10-K, the Nuclear Regulatory
Commission (NRC) issued a confirmatory order modifying the license for Limerick
Generating Station (Limerick) Units No. 1 and No. 2 requiring that the Company
complete final implementation of corrective actions on the Thermo-Lag 330 issue
by completion of the April 1999 refueling outage of Limerick Unit No. 2. By
letter dated May 3, 1999, the NRC approved the Company's request to extend the
completion of Thermo-Lag corrective actions at Limerick until September 30,
1999. By letters dated September 17, 1999, and October 13, 1999, the Company
notified the NRC of the completion of the Thermo-Lag 330 fire barrier corrective
actions.
As previously reported in the 1999 Form 10-Q for the quarter ended June
30, 1999, the Company filed its completed response to Generic Letter 98-01 on
June 30, 1999. In the response, the Company confirmed that with the exception of
five non-safety plant systems, its Peach Bottom Atomic Power Station and
Limerick were year 2000 ready. On October 27, 1999, the Company reported to the
NRC that all remaining systems were Y2K ready.
On September 8, 1999, the Company was notified by the National Labor
Relations Board (NLRB) that the Utility Workers Union of America (UWUA) had
filed a petition for a representation election. The UWUA is seeking to represent
selected production and maintenance employees in the PECO Energy Distribution
division (PED). Approximately 1,250 employees in the Operations, Contractor and
Supply Management, Customer and Marketing Services, Gas Supply and
Transportation sections of the PED were eligible to vote.
On November 9, 1999, the employees voted not to be represented by the
UWUA in secret balloting conducted by the NLRB. The PED employees cast 712 votes
for "no union" and 488 votes for UWUA representation. The Company and the UWUA
have seven days to file objections to the election. Absent any objections, at
the end of the seven days, the NLRB will certify the results.
As previously reported in the 1998 Form 10-K, by notice issued in
September 1985, the Environmental Protection Agency (EPA) notified the Company
that it had been identified as a Potentially Responsible Party (PRP) for the
costs associated with the cleanup of a site (Berks Associates/Douglassville
site) where waste oils generated from Jean H. Gibson, Vice PresidentCompany operations were transported,
treated, stored and Controller,disposed. In August 1991, the EPA filed suit in the Eastern
District Court against 36 named PRP's, not including the Company, seeking a
declaration that these PRP's are jointly and severally liable for cleanup of the
Berks Associates/Douglassville site and for costs already expended by the EPA on
the site. Simultaneously, the EPA issued an Administrative Order against the
same named defendants, not including the Company, which requires the PRP's named
in the Administrative Order to Michael J.
Egan, Senior Vice Presidentcommence cleanup of a portion of the site. On
September 29, 1992, the Company and Chief169 other parties were served with a third
party complaint joining these parties as additional defendants. Subsequently, an
additional 150 parties
29
were joined as defendants. A group of approximately 100 PRP's with allocated
shares of less than 1%, including the Company, formed a negotiating committee to
negotiate a settlement offer with the EPA. In December 1994, the EPA proposed a
de minimus PRP settlement which would have required the Company to pay
approximately $992,000 in exchange for the EPA agreeing not to sue.
Subsequently, the non-de minimus parties successfully challenged the Record of
Decision (ROD) remedy. A ROD amendment was finalized and, on October 27, 1998,
the EPA settled with the de minimus parties. Under the provisions of the
settlement, the Company would be required to pay approximately $522,000 for
liabilities resulting from the government's past and potential future costs. The
Department of Justice approved the settlement and on September 3, 1999 the
Company made the required payment.
As previously reported in the 1998 Form 10-K, on November 18, 1996, the
Company received a notice from the EPA that the Company is a PRP at the Malvern
TCE Superfund Site, located in Malvern, Pennsylvania. In April 1998, the Company
was notified of a de minimus settlement under which the Company was allocated a
total cost of $16,085 for EPA past and future costs. On October 6, 1999, the
Company paid $16,085 as its share of the settlement.
On September 30, 1999, Conectiv, Inc. (Conectiv) announced that it
subsidiaries Atlantic City Electric Company (ACE) and Delmarva Power & Light
Company (DPL) had each agreed to sell one-half of their respective 7.51%
interest in Peach Bottom Units 2 and 3, representing an aggregate of 164 MW of
capacity to the Company. At closing, ACE and DPL will each receive $5.10 million
plus 7.51% of the net book value of the nuclear fuel for their interests in
Peach Bottom. The sales are subject to federal and state regulatory approvals.
On the same day, Conectiv also announced that ACE and DPL had agreed to sell the
other half of their interests in Peach Bottom and all of their interests in the
Salem Generating Station to Public Service Electric and Gas Company.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits:
27 - Financial Officer.Data Schedule.
(b) Reports on Form 8-K filed during the reporting period:
Report, dated July 1, 1999 reporting information under "ITEM 5. OTHER
EVENTS" regarding AmerGen's signing a definitive asset
purchase agreement to purchase Clinton.
Report, dated September 14, 1999 reporting information under "ITEM 5.
OTHER EVENTS" regarding AmerGen's signing an agreement in
principle to acquire Oyster Creek Nuclear Generating Facility
from GPU, Inc.
30
Report, dated September 23, 1999 reporting information under "ITEM 5.
OTHER EVENTS" regarding the joint press release announcing the
Company and Unicom entering into a definitive agreement for a
merger of equals.
Report, dated September 23, 1999 reporting information under "ITEM 5.
OTHER EVENTS" regarding the Company's Agreement and Plan of
Exchange and Merger with Unicom and Newholdco Corporation
(Newholdco), a wholly owned subsidiary of the Company and
"ITEM 7. FINANCIAL STATEMENTS, PRO FORMA FINANCIAL INFORMATION
AND EXHIBITS" including the Agreement and Plan of Exchange and
Merger among the Company, Newholdco and Unicom.
Report, dated September 24, 1999 reporting information under "ITEM 5.
OTHER EVENTS" regarding presentation to investors regarding
the merger transaction between the Company and Unicom and
"ITEM 7. FINANCIAL STATEMENTS, PRO FORMA FINANCIAL INFORMATION
AND EXHIBITS" regarding the presentation to investors.
Reports on Form 8-K filed subsequent to the reporting period:
Report, dated September 22, 1999 reporting information under "ITEM 5.
OTHER EVENTS" and "ITEM 7. FINANCIAL STATEMENTS, PRO FORMA
FINANCIAL INFORMATION AND EXHIBITS" regarding pro forma
financial information.
Report, dated October 19, 1999 reporting information under "ITEM 5.
OTHER EVENTS" regarding Exelon Infrastructure Services, Inc.,
a subsidiary of the Company, announcing the acquisition of
five utility service companies.
Report, dated October 19, 1999 reporting information under "ITEM 5.
OTHER EVENTS" regarding AmerGen's accepted bid to acquire
Vermont Yankee Nuclear Power Station from Vermont Yankee
Nuclear Power Corporation.
31
Signatures
Pursuant to requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
PECO ENERGY COMPANY
/s/ Michael J. Egan
---------------------------------------------
MICHAEL J. EGAN
Vice President and
Senior Vice President and
Chief Financial Officer
(Principal Financial and(Chief Accounting Officer)
Date: May 18, 1999
April 6, 2000
32