UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 10-Q/A
Amendment No. 2
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 1999
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Commission file number: 1-1401
PECO Energy Company
(Exact name of registrant as specified in its charter)
Pennsylvania 23-0970240
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
2301 Market Street, Philadelphia, PA 19103
(Address of principal executive offices) (Zip Code)
(215) 841-4000
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes _X_ No ___
Indicate the number of shares outstanding of each of the issuer's classes of
common stock as of the latest practicable date:
The Company had 191,812,306 shares of common stock outstanding on May 7, 1999.
<PAGE>
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
(Millions of Dollars)
<TABLE>
<CAPTION>
Three Months Ended
March 31,
--------------------------
1999 1998
----------- -----------
<S> <C> <C>
OPERATING REVENUES
Electric $ 1,038.9 $ 1,003.0
Gas 217.5 187.2
----------- -----------
TOTAL OPERATING REVENUES 1,256.4 1,190.2
----------- -----------
OPERATING EXPENSES
Fuel and Energy Interchange 453.3 383.0
Operating and Maintenance 288.7 283.2
Depreciation and Amortization 56.3 154.7
Taxes Other Than Income Taxes 75.3 82.1
----------- -----------
TOTAL OPERATING EXPENSES 873.6 903.0
----------- -----------
OPERATING INCOME 382.8 287.2
----------- -----------
OTHER INCOME AND DEDUCTIONS
Interest Expense (74.3) (85.0)
Company Obligated Mandatorily Redeemable
Preferred Securities of a Partnership (7.4) (7.7)
Allowance for Funds Used During Construction 0.4 0.6
Other, Net (42.0) (12.8)
----------- -----------
TOTAL OTHER INCOME AND DEDUCTIONS (123.3) (104.9)
----------- -----------
INCOME BEFORE INCOME TAXES 259.5 182.3
INCOME TAXES 102.8 68.7
----------- -----------
NET INCOME 156.7 113.6
PREFERRED STOCK DIVIDENDS 3.3 3.3
----------- -----------
EARNINGS APPLICABLE TO COMMON STOCK $ 153.4 $ 110.3
=========== ===========
AVERAGE SHARES OF COMMON STOCK
OUTSTANDING (Millions) 223.4 222.5
=========== ===========
BASIC EARNINGS PER AVERAGE
COMMON SHARE (Dollars) $ 0.69 $ 0.50
=========== ===========
DILUTIVE EARNINGS PER AVERAGE
COMMON SHARE (Dollars) $ 0.68 $ 0.50
=========== ===========
DIVIDENDS PER AVERAGE COMMON SHARE (Dollars) $ 0.25 $ 0.25
=========== ===========
BOOK VALUE PER COMMON SHARE (Dollars) $ 12.18 $ 12.49
=========== ===========
</TABLE>
See Notes to Condensed Consolidated Financial Statements.
2
<PAGE>
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Millions of Dollars)
<TABLE>
<CAPTION>
March 31, December 31,
1999 1998
----------- -----------
(Unaudited)
<S> <C> <C>
ASSETS
UTILITY PLANT
Electric - Transmission & Distribution $ 3,870.8 $ 3,833.8
Electric - Generation 1,722.0 1,713.4
Gas 1,138.2 1,132.0
Common 408.7 407.3
----------- -----------
7,139.7 7,086.5
Less Accumulated Provision for Depreciation 2,950.7 2,891.3
----------- -----------
4,189.0 4,195.2
Nuclear Fuel, net 128.0 141.9
Construction Work in Progress 290.1 272.6
Leased Property, net 138.3 154.3
----------- -----------
4,745.4 4,764.0
----------- -----------
CURRENT ASSETS
Cash and Temporary Cash Investments 2,702.8 48.1
Accounts Receivable, net
Customer 183.0 97.5
Other 262.5 213.2
Inventories, at average cost
Fossil Fuel 84.9 92.3
Materials and Supplies 83.1 82.1
Deferred Energy Costs - Gas 0.8 29.9
Other 188.7 19.0
----------- -----------
3,505.8 582.1
----------- -----------
DEFERRED DEBITS AND OTHER ASSETS
Competitive Transition Charge 5,274.6 5,274.6
Recoverable Deferred Income Taxes 613.9 614.4
Deferred Non-Pension Postretirement Benefits Costs 89.3 90.9
Investments 534.0 538.1
Loss on Reacquired Debt 75.6 77.2
Other 132.7 107.1
----------- -----------
6,720.1 6,702.3
----------- -----------
TOTAL $ 14,971.3 $ 12,048.4
=========== ===========
</TABLE>
See Notes to Condensed Consolidated Financial Statements.
(continued on next page)
3
<PAGE>
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Millions of Dollars)
(continued)
<TABLE>
<CAPTION>
March 31, December 31,
1999 1998
----------- -----------
(Unaudited)
<S> <C> <C>
CAPITALIZATION AND LIABILITIES
CAPITALIZATION
Common Shareholders' Equity
Common Stock (No Par) $ 3,602.6 $ 3,589.0
Other Paid-In Capital 1.2 1.2
Accumulated Deficit (422.3) (532.9)
Treasury Stock (695.9) --
Preferred and Preference Stock
Without Mandatory Redemption 137.5 137.5
With Mandatory Redemption 92.7 92.7
Company Obligated Mandatorily Redeemable
Preferred Securities of a Partnership 349.4 349.4
Long-Term Debt 6,084.0 2,919.6
----------- -----------
9,149.2 6,556.5
----------- -----------
CURRENT LIABILITIES
Notes Payable, Bank 68.0 525.0
Long-Term Debt Due Within One Year 939.4 361.5
Capital Lease Obligations Due Within One Year 68.8 69.0
Accounts Payable 276.9 316.2
Taxes Accrued 346.8 170.5
Interest Accrued 67.1 61.5
Deferred Income Taxes 4.0 14.1
Other 224.8 217.4
----------- -----------
1,995.8 1,735.2
----------- -----------
DEFERRED CREDITS AND OTHER LIABILITIES
Capital Lease Obligations 69.5 85.3
Deferred Income Taxes 2,362.5 2,376.9
Unamortized Investment Tax Credits 296.4 300.0
Pension Obligation 219.3 219.3
Non-Pension Postretirement Benefits Obligation 428.6 421.1
Other 450.0 354.1
----------- -----------
3,826.3 3,756.7
----------- -----------
COMMITMENTS AND CONTINGENCIES (NOTE 6)
TOTAL $ 14,971.3 $ 12,048.4
=========== ===========
</TABLE>
See Notes to Condensed Consolidated Financial Statements.
4
<PAGE>
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(Millions of Dollars)
<TABLE>
<CAPTION>
Three Months Ended
March 31,
----------------------
1999 1998
---------- --------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
NET INCOME $ 156.7 $ 113.6
Adjustments to Reconcile Net Income to Net Cash
Provided by Operating Activities:
Depreciation and Amortization 73.9 170.9
Deferred Income Taxes (23.0) (6.8)
Amortization of Investment Tax Credits (3.6) (4.5)
Deferred Energy Costs 29.0 19.0
Changes in Working Capital:
Accounts Receivable (134.7) 24.9
Inventories 6.4 17.7
Accounts Payable (39.3) (74.4)
Other Current Assets and Liabilities 28.6 (45.5)
Other Items Affecting Operations 88.4 16.2
---------- --------
CASH FLOWS PROVIDED BY OPERATING ACTIVITIES 182.4 231.1
---------- --------
CASH FLOWS FROM INVESTING ACTIVITIES
Investment in Plant (76.9) (116.5)
Increase in Investments (5.3) (11.1)
---------- --------
NET CASH FLOWS USED IN INVESTING ACTIVITIES (82.2) (127.6)
---------- --------
CASH FLOWS FROM FINANCING ACTIVITIES
Change in Short-Term Debt (457.0) (17.0)
Issuance of Long-Term Debt 4,009.6 (5.5)
Retirement of Long-Term Debt (263.0) --
Common Stock Repurchase (695.9) --
Loss on Reacquired Debt 1.6 1.8
Dividends on Preferred and Common Stock (59.5) (58.9)
Other Items Affecting Financing 18.7 (2.3)
---------- --------
NET CASH FLOWS PROVIDED BY (USED IN) FINANCING ACTIVITIES 2,554.5 (81.9)
---------- --------
INCREASE IN CASH AND CASH EQUIVALENTS 2,654.7 21.6
---------- --------
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 48.1 33.4
---------- --------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 2,702.8 $ 55.0
========== ========
</TABLE>
See Notes to Condensed Consolidated Financial Statements.
5
<PAGE>
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
1. BASIS OF PRESENTATION
The accompanying condensed consolidated financial statements as of March
31, 1999 and for the three 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 (1998
Form 10-K).
2. TRANSITION BONDS
On March 25, 1999, PECO Energy Transition Trust (PETT), an independent
statutory business trust organized under the laws of Delaware and a wholly owned
subsidiary of the Company, issued $4 billion aggregate principal amount of
Transition Bonds (Transition Bonds) to securitize a portion of the Company's
authorized stranded cost recovery. The Transition Bonds are solely obligations
of PETT, secured by Intangible Transition Property sold by the Company to PETT
concurrently with the issuance of the Transition Bonds and certain other
collateral related thereto.
The terms of the Transition Bonds are as follows:
<TABLE>
<CAPTION>
Approximate
Face Amount Bond Expected Final
Class (millions) Rates Maturity Maturity
----- ---------- ----- -------- --------
<S> <C> <C> <C> <C>
A-1 $244.5 5.48% March 1, 2001 March 1, 2003
A-2 $275.4 5.63% March 1, 2003 March 1, 2005
A-3 $667.0 5.18% (a) March 1, 2004 March 1, 2006
A-4 $458.5 5.80% March 1, 2005 March 1, 2007
A-5 $464.6 5.26% (a) September 1, 2007 March 1, 2009
A-6 $993.4 6.05% March 1, 2007 March 1, 2009
A-7 $896.7 6.13% September 1, 2008 March 1, 2009
<FN>
(a) The Class A-3 and A-5 Transition Bonds earn interest at a floating
rate. The rates provided for each such class above are as of March 31,
1999.
</FN>
</TABLE>
6
<PAGE>
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 will be 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. The fair value of $5 million was based on the present value difference
between the contracted rate (i.e., hedged rate) and the market rates at March
31, 1999.
The aggregate change in fair value of the Transition Bond derivative
instruments that would have resulted from a hypothetical 50 basis point decrease
in the spot yield at March 31, 1999 is estimated to be $38.2 million. If the
derivative instruments had been terminated at March 31, 1999, this estimated
fair value represents the amount to be paid by the Company to the
counterparties.
The aggregate change in fair value of these derivative instruments that
would have resulted from a hypothetical 50 basis point increase in the spot
yield at March 31, 1999 is estimated to be $45.9 million. If the derivative
instruments had been terminated at March 31, 1999, this estimated fair value
represents 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 $3.9 billion. In accordance with the
provisions of the Pennsylvania Electricity Generation Customer Choice and
Competition Act, the Company is utilizing these proceeds principally to reduce
its stranded costs and related capitalization. On March 26, 1999, the Company
settled the forward purchase agreements relating to its Common Stock resulting
in the purchase by the Company of 21.5 million shares of Common Stock for an
aggregate purchase price of $696 million. In addition, the Company repaid a $400
million term loan, $208 million of commercial paper, $48 million of accounts
receivable financing and paid $21 million of debt issuance costs. The remaining
proceeds of $2.6 billion are included in cash at March 31, 1999. On March 26,
1999, the Company called for redemption four series of its First Mortgage Bonds,
7.75% Series due 2023, 7.25% Series due 2024, 7.125% Series due 2023 and 7.75%
Series 2 due 2023, totaling $775 million.
3. SEGMENT INFORMATION
The Company is primarily a vertically integrated public utility that
provides retail electric and natural gas service to the public in its
traditional service territory and retail electric generation service throughout
Pennsylvania pursuant to Pennsylvania's Customer Choice Program. The Company's
management has historically managed the Company as a vertically integrated
entity by analyzing its results of operations on a consolidated basis with an
emphasis on electric and gas operations.
7
<PAGE>
During the first quarter of 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 includes its electric transmission and distribution services, regulated
retail sales of generation services and retail gas businesses. The Company's
generation business unit includes the operation of its generating assets and its
power marketing group. The Company's ventures business unit includes its
unregulated retail energy supplier, infrastructure services business and its
telecommunications equity investments.
The Company's segment information as of and for the three months ended
March 31, 1999 as compared to the same 1998 period is as follows (in millions of
dollars):
<TABLE>
<CAPTION>
Intersegment
Distribution Generation Ventures Corporate Revenues Consolidated
------------ ---------- -------- --------- -------- ------------
<S> <C> <C> <C> <C> <C> <C>
Revenues:
1999 $910.1 $443.9 $103.8 $ - $(201.4) $1,256.4
1998 $949.5 $465.0 $ 17.0 $ - $(241.3) $1,190.2
EBIT (a):
1999 $354.7 $ 58.8 $( 30.6)(b) $(41.6) $ 340.8
1998 $307.3 $ 41.4 $( 27.5) $(46.8) $ 274.4
Total Assets:
1999 $12,366.3(c) $1,919.5 $246.7 $438.8 $14,971.3
1998 $ 9,759.2 $1,686.8 $216.9 $385.5 $12,048.4
<FN>
(a) EBIT - Earnings Before Interest and Income Taxes.
(b) Includes $14.6 million related to the write-off of the investment in Grays
Ferry in connection with the settlement of litigation.
(c) Includes $2.6 billion of proceeds from securitization of stranded costs.
</FN>
</TABLE>
4. EARNINGS PER SHARE
Diluted earnings per average common share is calculated by dividing
earnings applicable to common stock by the average shares of common stock
outstanding after giving effect to stock options, issuable under the Company's
stock option plans, considered to be dilutive common stock equivalents. The
following table shows the effect of the stock options issuable under the
Company's stock option plans on the average number of shares used in calculating
diluted earnings per average common share:
8
<PAGE>
Three Months Ended
March 31,
------------------
1999 1998
------- -------
(Millions of shares)
Average Common Shares Outstanding 223.4 222.5
Assumed Conversion of Stock Options 1.3 --
------- -------
Potential Average Dilutive
Common Shares Outstanding 224.7 222.5
======= =======
5. SALES OF ACCOUNTS RECEIVABLE
The Company is party to an agreement with a financial institution, under
which it can sell or finance with limited recourse an undivided interest,
adjusted daily, in up to $353 million of designated accounts receivable until
November 2000. At March 31, 1999, the Company had sold a $353 million interest
in accounts receivable, consisting of a $289 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 $64 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 $353 million
interest, which, if not met, requires the Company to deposit cash in order to
satisfy such requirements. The Company, at March 31, 1999, met such
requirements. At March 31, 1999, the average annual service-charge rate,
computed on a daily basis on the portion of the accounts receivable sold but not
yet collected, was 5.05%.
6. COMMITMENTS AND CONTINGENCIES
For information regarding the Company's capital commitments, nuclear
insurance, nuclear decommissioning and spent fuel storage, energy commitments,
environmental issues and litigation, see note 5 of Notes to Consolidated
Financial Statements for the year ended December 31, 1998.
At March 31, 1999, the Company had entered into long-term agreements with
unaffiliated utilities to purchase transmission rights. These purchase
commitments result in obligations of approximately $47 million in 1999, $88
million in 2000, $22 million in 2001, and $10 million per year in 2002 through
2005.
The Company has identified 28 sites where former manufactured gas plant
(MGP) activities have or may have resulted in actual site contamination. As of
March 31, 1999, the Company had accrued $59 million for environmental
investigation and remediation costs, including $33 million for MGP investigation
and remediation that currently can be reasonably estimated. The Company cannot
predict whether it will incur other significant liabilities for additional
investigation and remediation costs at these or additional sites identified by
the Company, environmental agencies or others, or whether all such costs will be
recoverable from third parties.
On April 23, 1999, the Company and Grays Ferry Cogeneration Partnership
(Grays Ferry) entered into a final settlement of litigation, subject to the
resolution of certain issues. The settlement provides for the transfer of the
Company's interest in the partnership to the remaining partners. Accordingly,
the
9
<PAGE>
Company recorded a charge to earnings of $14.6 million for the transfer of its
partnership interest. The charge for the partnership interest transfer is
recorded in Other Income and Deductions on the Company's Statement of Income for
the three months ended March 31, 1999. The settlement also resolves the
litigation with Westinghouse Power Generation and The Chase Manhattan Bank.
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 $15 million
million was paid through March 31, 1999. Retirement benefits are being paid to
the retirees over their lives. Of the 1,157 employees, 197 were eligible for and
have taken the retirement incentive program and 279 employees were terminated
with the enhanced severance benefit program. The remaining employees are
scheduled for termination through the end of June 2000.
7. 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. The new standard will be effective for fiscal years beginning after
June 15, 1999. The Company expects to adopt SFAS No. 133 in the first quarter of
2000. The Company is in the process of evaluating the impact of SFAS No. 133 on
its financial statements.
In November 1998, the FASB's Emerging Issues Task Force (EITF) issued EITF
98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management
Activities." EITF 98-10 outlines attributes that may be indicative of an energy
trading operation and gives further guidance on the accounting for contracts
entered into by an energy trading operation. This accounting guidance requires
mark-to-market accounting for contracts considered to be a trading activity.
EITF 98-10 is applicable for fiscal years beginning after December 15, 1998 with
any impact recorded as a cumulative effect adjustment through retained earnings
at the date of adoption.
The Company's wholesale marketing operations enter into long-term and
short-term commitments to purchase and sell energy and energy-related products
with the intent and ability to deliver or take delivery. The objective of the
long-term commitments is to establish a generation base that allows the Company
to meet the physical supply and demand requirements of a national wholesale
electric marketplace through scheduled, real-time delivery of electricity. The
Company utilizes short-term energy commitments and contracts entered into in the
over-the-counter market to economically hedge seasonal and operational risks
associated with peak demand periods and generation plant outages.
At March 31, 1999, 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 not subject to EITF 98-10 or mark-to-market accounting.
10
<PAGE>
The Company records revenues and expenses with the energy commitments
consistent with when the underlying physical transaction closes. Additionally,
the Company evaluates its energy commitments for impairment based on the lower
of cost or market. At March 31, 1998, the Company concluded that no energy
commitments were impaired.
11
<PAGE>
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
GENERAL
Retail competition for electric generation services began in Pennsylvania
on January 1, 1999. During 1999, two-thirds of each class of the Company's
retail electric customers in its traditional service territory will 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 March 31, 1999
approximately 13% of the Company's residential customers, approximately 22% of
its commercial customers and approximately 56% 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 138,000 business and residential customers throughout
Pennsylvania.
Effective January 1, 1999, the Company reduced its retail electric rates
for all customers by 8%. On that date, the Company began recovering its stranded
costs through the collection of competitive transition charges from all
customers. On March 25, 1999, PECO Energy Transition Trust (PETT), a wholly
owned subsidiary of the Company, issued $4 billion of PECO Energy Transition
Trust Transition Bonds to securitize a portion of the Company's stranded cost
recovery.
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.
During the first quarter of 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 includes its electric transmission and distribution services, regulated
retail sales of generation services and retail gas businesses. The Company's
generation business unit includes the operation of its generating assets and its
power marketing group. The Company's ventures business unit includes its
unregulated retail energy supplier, infrastructure services business and its
telecommunications equity investments.
RESULTS OF OPERATIONS
The Company's Statements of Income for the three months ended March 31,
1998 reflect the reclassification of the results of operations of Exelon Energy,
from Other Income and Deductions.
12
<PAGE>
Revenue and Expense Items as a
Percentage of Total Operating
Revenues Percentage Dollar Changes
1999 1998 1999-1998
---- ---- ---------
83% 84% Electric 4%
17% 16% Gas 16%
---- ----
100% 100% Total Operating Revenues 6%
---- ----
36% 32% Fuel and Energy Interchange 18%
23% 24% Operating and Maintenance (2%)
5% 13% Depreciation and Amortization (64%)
6% 7% Taxes Other Than Income (8%)
---- ----
70% 76% Total Operating Expenses (3%)
---- ----
30% 24% Operating Income 33%
---- ----
(7%) (8%) Interest Expense (12%)
(3%) (1%) Other Income and Deductions (241%)
---- ----
20% 15% Income Before Income Taxes 42%
8% 6% Income Taxes 50%
---- ----
12% 9% Net Income 38%
---- ----
Operating Revenues
Electric revenues increased $36 million, or 4%, for the three months ended
March 31, 1999 compared to the same 1998 period. The increase was attributable
to higher revenues from the ventures business unit of $88 million and the
generation business unit of $19 million, partially offset by lower revenues at
the distribution business unit of $71 million. The increase from the ventures
business unit was primarily from increased volume in Pennsylvania resulting from
the commencement of the sale of competitive electric generation services by
Exelon Energy. The increase from the generation business unit was attributable
to the marketing of excess generation capacity as a result of lower native load
requirements as a result of competition. The decrease from the distribution
business unit was attributable to $68 million as a result of lower volume
associated with the effects of competition and $56 million related to the 8%
across-the-board rate reduction mandated by the Final Restructuring Order. These
decreases were partially offset by $36 million of PJM Interconnection LLC (PJM)
network transmission service revenue which commenced April 1, 1998 and $17
million related to increased sales volume from colder weather conditions.
Stranded cost recovery is included in the Company's retail electric rates
beginning January 1, 1999.
Gas revenues increased $30 million, or 16%, for the three months ended
March 31, 1999 compared to the same 1998 period. The increase was primarily
attributable to increased volume as a result of colder weather conditions of $20
million and increased volume from new customers of $10 million.
13
<PAGE>
Fuel and Energy Interchange Expense
Fuel and energy interchange expense increased $70 million, or 18%, for the
three months ended March 31, 1999 compared to the same 1998 period. As a
percentage of revenue, fuel and interchange expenses were 36% as compared to 32%
in the comparable prior year period. These increases were attributable to higher
fuel and energy interchange expenses from the ventures business unit of $69
million and the distribution business unit of $63 million, partially offset by
lower fuel and energy interchange expenses of $62 million at the generation
business unit. The increase from the ventures business unit was primarily from
increased volume related to Exelon Energy sales. The increase from the
distribution business unit was primarily attributable to $27 million of PJM
network transmission service fees which commenced April 1, 1998, $26 million of
purchases in the spot market and $10 million of additional gas purchases as a
result of higher volume associated with colder weather. The decrease from the
generation business unit was primarily attributable to $78 million of lower fuel
purchases as a result of the effects of competition experienced by the
distribution business unit. This increase was partially offset by fuel savings
of $16 million from the full return to service of the Salem Generating Station
(Salem) in April 1998 which decreased the need to purchase power to replace the
output from these units.
Operating and Maintenance Expense
Operating and maintenance expense increased $6 million, or 2% for the three
months ended March 31, 1999 compared to the same 1998 period. The increase was
primarily attributable to increased information technology expenses related to
Year 2000 remediation of $12 million partially offset by lower expenses at the
generation business unit of $8 million as a result of the full return to service
of Salem in April 1998. As a percentage of revenue, operating and maintenance
expenses were 23% as compared to 24% in the comparable prior year period.
Depreciation and Amortization Expense
Depreciation and amortization expense decreased $98 million, or 64%, for
the three months ended March 31, 1999 compared to the same 1998 period. As a
percentage of revenue, depreciation and amortization expense was 5% as compared
to 13% in the comparable prior year period. The decrease was associated with the
December 1997 restructuring charge through which the Company wrote down a
significant portion of its generating plant and regulatory assets. In connection
with this restructuring charge, the Company established a regulatory asset,
Deferred Generation Costs Recoverable in Current Rates of $424 million, which
was fully amortized in 1998, and 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 $7 million, or 8%, for the three months
ended March 31, 1999 compared to the same 1998 period. As a percentage of
revenue, taxes other than income were 6%, as compared to 7%, in the comparable
prior year period. The decrease was attributable to lower gross receipts tax of
$3 million and lower capital stock tax of $4 million.
14
<PAGE>
Interest Charges
Interest charges consist of interest expense, distributions on Company
Obligated Mandatorily Redeemable Preferred Securities of a Partnership (COMPRS)
and Allowance for Funds Used During Construction (AFUDC). Interest charges
decreased $11 million, or 12%, for the three months ended March 31, 1999
compared to the same 1998 period. As a percentage of revenue, interest charges
were 7% as compared to 8% in the comparable prior year period. The Company's
ongoing program to reduce and/or refinance higher cost, long-term debt reduced
interest charges by $16 million. This decrease was partially offset by interest
on the Transition Bonds of $5 million.
Other Income and Deductions
Other income and deductions excluding interest charges was a loss of $42
million for the three months ended March 31, 1999 as compared to a loss of $13
million in the same 1998 period. The decrease of $29 million was primarily
attributable to the write-off of the investment in Grays Ferry in connection
with the settlement of litigation of $15 million, the abandonment of an
information system of $7 million and additional losses from equity investments
in telecommunications ventures and non-utility operations of $7 million. As a
percentage of revenue, other income and deductions were 3% as compared to 1% in
the comparable prior year period.
Income Taxes
The effective tax rate was 39.6% rate for the three months ended March 31,
1999 as compared to 37.7% in the same 1998 period. The effective tax rate for
the three months ended March 31, 1998 was disproportionate to the statutory rate
as a result of the full normalization of deferred taxes associated with
deregulated generation plant and amortization of investment tax credits.
Preferred Stock Dividends
Preferred stock dividends for the three months ended March 31, 1999 were
consistent with the same 1998 period.
DISCUSSION OF LIQUIDITY AND CAPITAL RESOURCES
Cash flows provided by operating activities decreased $49 million to $182
million for the three months ended March 31, 1999 as compared to $231 million in
the same 1998 period. The decrease was primarily attributable to less cash
generated by operations of $66 million, changes in working capital of $62
million principally related to the timing of gross receipts tax, partially
offset by other items affecting operations of $72 million, principally
consisting of the deferred gain on the unwinding of interest rate swaps
associated with the issuance of Transition Bonds.
Cash flows used by investing activities were $82 million for the three
months ended March 31, 1999 as compared to $128 million in the comparable 1998
period. Expenditures under the Company's construction program decreased to $77
million in the current period.
15
<PAGE>
Cash flows provided by financing activities were $2,555 million as compared
to cash used in financing activities of $82 million in the comparable prior year
period. The increase was attributable to the issuance of $4 billion of
Transition Bonds by PETT partially offset by the repayment of short-term and
long-term debt aggregating $720 million and the settlement of the Company's
common stock forward purchase contract for $696 million.
On March 25, 1999, PETT issued $4 billion of its Transition Bonds to
securitize a portion of the Company's authorized stranded cost recovery. The
Transition Bonds are solely obligations of PETT, secured by the Intangible
Transition Property (ITP) sold by the Company to PETT. Upon issuance of the
Transition Bonds, a portion of the competitive transition charges to be
collected by the Company to recover stranded costs was designated as Intangible
Transition Charges (ITC). The ITC is an irrevocable non-bypassable usage based
charge that is calculated to allow for the recovery of debt service and costs
related to the issuance of the Transition Bonds. The ITC will be allocated from
CTC and from variable distribution charges (both of which are usage-based
charges).
PETT used the $3.99 billion of proceeds of the Transition Bonds to purchase
the ITP from the Company. Although the Transition Bonds are solely obligations
of PETT, they are included in the consolidated long-term debt of the Company. In
accordance with the terms of the Competition Act, the Company is utilizing the
proceeds principally to reduce stranded costs and capitalization. The Company
currently plans to reduce its capitalization in the following proportions: fixed
and floating-rate debt, 50%; preferred securities, 7%; common equity, 43%.
Concurrently with the issuance of the Transition Bonds, the Company repaid a
$400 million term loan, $208 million of commercial paper and $48 million of
accounts receivable financing and repurchased 21.5 shares of common stock
pursuant to forward repurchase arrangements for an aggregate purchase price of
$696 million. The Company also called for redemption $ 775 million of its First
Mortgage Bonds as follows: 7.75% Series due 2023, 7.25% Series due 2024 and
7.125% Series due 2023 on April 26, 1999 and 7.75% Series 2 due 2023 on May 3,
1999. The Company also plans to call for redemption its COMRPS 9% Series due
2043 on August 1, 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 Securities and Exchange Commission rules. The number of
shares purchased and the timing and manner or 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, will be reflected on the Company's Consolidated Statement of Income. The
combined schedule for amortization of the CTC and ITC assets will be in
accordance with the amortization schedule set forth in the Final Restructuring
Order. As a result of the issuance of the Transition Bonds and the proposed
capital reduction by the Company, the Company expects its debt-to-total capital
ratio to be 60% upon completion of the application of the proceeds from the
securitization. The Company currently projects that it will complete the
majority of the targeted debt and preferred security reductions by August 1,
1999. The weighted average cost of debt and preferred securities to be retired
is approximately 6.8%. The additional interest expense associated with the
Transition Bonds, which have an effective interest rate of approximately 5.8%,
will be partially offset by the anticipated interest savings associated with the
debt and preferred securities that will be retired. The Company currently
estimates that the impact of additional expense, combined with the anticipated
16
<PAGE>
reduction in common equity, will result in earnings per share benefits of
approximately $.15 and $.50 in 1999 and 2000, respectively. These estimated
earnings per share could change and are largely dependent upon the timing and
price of common stock repurchases.
At March 31, 1999, the Company had outstanding $68 million of notes
payable, all of which were commercial paper. In addition, at March 31, 1999, the
Company had formal and informal lines of bank credit aggregating $100 million.
At March 31, 1999, the Company had no short-term investments.
On May 3, 1999, Standard & Poor's upgraded its ratings on the Company's
overall corporate credit to "A-" from "BBB+", first and refunding mortgage bonds
and collateralized medium-term notes to "A" from "BBB+", hybrid preferred
securities, capital trust securities and preferred stock to "BBB" from "BBB-".
YEAR 2000 READINESS DISCLOSURE
Due to the severity of the potential impact of the Year 2000 Issue (Y2K
Issue) on the electric utility industry, the Company has adopted a comprehensive
schedule to achieve Y2K readiness by the time specified by the NRC. The Company
has dedicated extensive resources to its Y2K Project (Project) and believes the
Project is progressing on schedule. The 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.
The Company has determined that it will be required to modify, convert or
replace significant portions of its software and a subset of its system hardware
and embedded technology so that its computer systems will properly utilize dates
beyond December 31, 1999. The Company presently believes that with these
modifications, conversions and replacements the effect of the Y2K Issue on the
Company can be mitigated. If such modifications, conversions and replacements
are not made, or are not completed in a timely manner, the Y2K Issue could have
a material impact on the operations and financial condition of the Company. The
costs associated with this potential impact are not presently quantifiable. The
Company is utilizing both internal and external resources to reprogram, or
replace and test software and computer systems for the Project. The Project is
scheduled for completion by July 1, 1999, except for a small number of
modifications, conversions or replacements that are impacted by PUC changes,
vendor dates and/or are being incorporated into scheduled plant outages between
July and November 1999.
The Project is divided into four major sections - Information Technology
Systems (IT Systems), Embedded Technology (devices used to control, monitor or
assist the operation of equipment, machinery or plant), Supply Chain
(third-party suppliers and customers), and Contingency Planning. The general
phases common to all sections are: (1) inventorying Y2K items; (2) assigning
priorities to identified items; (3) assessing the Y2K readiness of items
17
<PAGE>
determined to be material to the Company; (4) converting material items that are
determined not to be Y2K ready; (5) testing material items; and (6) designing
and implementing contingency plans for each critical Company process. Material
items are those believed by the Company to have a risk involving the safety of
individuals, may cause damage to property or the environment, or affect
revenues.
The IT Systems section includes both the conversion of applications
software that is not Y2K ready and the replacement of software when available
from the supplier. The Project has identified 363 critical systems of which 226
are IT Systems. The current readiness status of IT Systems is set forth below:
Number of Systems Progress Status
- ----------------- ---------------
151 Systems Y2K Ready
49 Systems In Testing
26 Systems In Active Code Modification, or
Package Upgrading
The Company has been experiencing slippage in delivery dates of vendor
supplied products which may have a minor impact on the July 1, 1999 target
completion date. Contingency planning for IT Systems is scheduled to be
completed by July 1, 1999.
The remaining 137 systems are the Embedded Systems consisting of hardware
and systems software other than IT Systems. The current readiness status of
those systems is set forth below:
Number of Systems Progress Status
- ----------------- ---------------
78 Systems Y2K Ready
25 Systems In Final Quality Review
29 Systems In Progress
5 Systems Not Started
Contingency planning for Embedded Technology is scheduled to be completed by
July 1, 1999.
The Supply Chain section includes the process of identifying and
prioritizing critical suppliers and communicating with them about their plans
and progress in addressing the Y2K Issue. The process of evaluating critical
suppliers was completed on March 31, 1999. The Company is currently working with
critical suppliers on contingency plans which are scheduled to be completed by
July 1, 1999.
In addition to addressing contingency plans with key suppliers, the Company
is currently developing contingency plans to address how to respond to internal
events which may disrupt normal operations. These plans address Y2K risk
scenarios that cross departments and business units. Emergency plans already
exist that cover various aspects of the Company's business. These plans are
being reviewed and updated to address the Y2K Issue. The Company is also
participating in industry contingency planning efforts.
18
<PAGE>
The estimated total cost of the Project is $75 million, the majority of
which will be incurred during testing. This estimate includes the Company's
share of Y2K costs for jointly owned facilities. The total amount expended on
the Project through March 31, 1999 was $33 million. The Company expects to fund
the Project from operating cash flows. The Company's failure to become Y2K ready
could result in an interruption in or a failure of certain normal business
activities or operations. In addition, there can be no assurance that the
systems of other companies on which the Company's systems rely or with which
they communicate will be converted in a timely manner, or that a failure to
convert by another company, or a conversion that is incompatible with the
Company's systems, will not have a material adverse effect on the Company. Such
failures could materially and adversely affect the Company's results of
operations, liquidity and financial condition. The Company is currently
developing contingency plans to address how to respond to events that may
disrupt normal operations, including activities with PJM. The costs of the
Project and the date on which the Company plans to complete the Y2K
modifications are based on estimates, that were derived utilizing numerous
assumptions of future events, including the continued availability of certain
resources, third-party modification plans and other factors, such as regulatory
requirements that impact key systems. There can be no assurance that these
estimates will be achieved. Actual results could differ materially from the
projections. Specific factors that might cause a material change include, but
are not limited to, the availability and cost of trained personnel, the ability
to locate and correct all relevant computer programs and microprocessors.
The Project is expected to significantly reduce the Company's level of
uncertainty about the Y2K Issue. The Company believes that the completion of the
Project, as scheduled, minimizes the possibility of significant interruptions of
normal operations.
On July 17, 1998, an order was entered by the PUC instituting a formal
investigation by the Office of Administrative Law on Year 2000 compliance by
jurisdictional fixed utilities and mission-critical service providers such as
the PJM. The order requires, (1) a written response to a list of compliance
program questions by August 6, 1998 and, (2) all jurisdictional fixed utilities
be Year 2000 compliant by March 31, 1999 or, if a utility determines that
mission-critical systems cannot be Year 2000 compliant on or before March 31,
1999, the utility is required to file a detailed contingency plan. The PUC
adopted the federal government's definition for Year 2000 compliance and further
defined Year 2000 compliance as a jurisdictional utility having all
mission-critical Year 2000 hardware and software updates and/or replacements
installed and tested on or before March 31, 1999. On August 6, 1998, the Company
filed its written response, in which the Company stated that with a few
carefully-assessed and closely-managed exceptions, the Company will have all
mission-critical systems Year 2000 ready by June 1999. Pursuant to the formal
investigation on Year 2000 compliance, the Company presented testimony before
the PUC on November 20, 1998.
On February 19, 1999, the PUC issued a Secretarial Letter notifying the
Company that it had hired a consultant to perform an assessment of the Company
and thirteen other utilities to evaluate the accuracy of their responses to the
compliance program questions and testimony provided before the PUC. The Company
complied with the PUC's directive in the Secretarial
19
<PAGE>
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 May 11, 1998, the NRC issued a generic letter requiring all nuclear
plant operators to provide the NRC with the following information concerning the
operators' programs, planned or implemented, to address Year 2000 computer and
system issues at its facilities: (1) submission of a written response within 90
days, indicating whether the operator has pursued and continues to pursue
implementation of Year 2000 programs and addressing the program's scope,
assessment process, plans for corrective actions, quality assurance measures,
contingency plans and regulatory compliance, and (2) submission of a written
response, no later than July 1, 1999, confirming that such facilities are Year
2000 ready, or will be Year 2000 ready, by the year 2000 with regard to
compliance with the terms and conditions of the license(s) and NRC regulations.
On July 30, 1998, the Company filed its 90-day required written response
indicating that the Company has pursued and is continuing to pursue a Year 2000
program which is similar to that outlined in Nuclear Utility Year 2000
Readiness, NEI/NUSMG 97.07.
From November 3 to November 5, 1998, members of the NRC staff conducted an
audit of the Company's Year 2000 Program for the Limerick Generating Station,
Units No. 1 and No. 2. Some of the observations of the audit team included in
their written report issued on December 18, 1998, were that (1) the Company's
readiness program is comprehensive and based on the guidance contained in
NEI/NUSMG 97.07, (2) the program is receiving proper management support and
oversight, and (3) project schedules are being aggressively pursued.
For additional information regarding the Year 2000 Readiness Disclosure see
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" in the Company's Annual Report to Shareholders for the year 1998.
FORWARD-LOOKING STATEMENTS
Except for the historical information contained herein, certain of the
matters discussed in this Report are forward-looking statements, including the
estimated earnings per share benefits of the application of the Transition Bond
proceeds for 1999 and 2000, and accordingly, are subject to risks and
uncertainties. The factors that could cause actual results to differ materially
include those discussed herein as well as those listed in notes 2, 6 and 7 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.
20
<PAGE>
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. The fair value of $5 million was based on the present value difference
between the contracted rate (i.e., hedged rate) and the market rates at March
31, 1999.
The aggregate change in fair value of these derivative instruments that
would have resulted from a hypothetical 50 basis point decrease in the spot
yield at March 31, 1999 is estimated to be $ 38.2 million. If the derivative
instruments had been terminated at March 31, 1999, this estimated fair value
represents the amount to be paid by the Company to the counterparties.
The aggregate change in fair value of the Transition Bond derivative
instruments that would have resulted from a hypothetical 50 basis point increase
in the spot yield at March 31, 1999 is estimated to be $45.9 million. If the
derivative instruments had been terminated at March 31, 1999, this estimated
fair value represents the amount to be paid by the counterparties to the
Company.
The Company's growing market share in the retail and wholesale electric
marketplace increases the Company's reliance on the efficient operation of its
generating units. The Company's ability to fully capitalize on volatile
wholesale market prices is also dependent on the performance of the Company's
generating units.
21
<PAGE>
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
As previously reported, on April 9, 1998, Grays Ferry Cogeneration
Partnership (Grays Ferry), two of three partners of Grays Ferry and
Trigen-Philadelphia Energy Corporation, filed a complaint in Philadelphia County
Court of Common Pleas against the Company arising out of the Company's
termination of two power purchase agreements that the Company had entered into
with Grays Ferry.
On April 23, 1999, the Company and Grays Ferry entered into a final
settlement of the litigation, subject to the resolution of certain issues. The
settlement provides for the transfer of the Company's interest in the
partnership to the remaining partners. Accordingly, the Company recorded a
charge to earnings of $14.6 million for the transfer of its partnership
interest. The settlement also resolves the litigation with Westinghouse Power
Generation and The Chase Manhattan Bank.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
On April 27, 1999, the Company held its 1999 Annual Meeting of
Shareholders.
The following Class III directors of the Company were re-elected for terms
expiring in 2002:
Votes For Votes Withheld
--------- --------------
Daniel L. Cooper 180,230,306 1,936,445
M. Walter D'Alessio 180,150,467 2,096,123
Ronald Rubin 180,162,063 2,072,931
The incumbent Class II directors, with terms expiring in 2001, are Susan W.
Catherwood, G. Fred DiBona, Jr., R. Keith Elliott, John M. Palms and Joseph F.
Paquette, Jr. The incumbent Class I directors with terms expiring in 2000, are
Richard H. Glanton, Rosemarie B. Greco, Corbin A. McNeill, Jr. And Robert Subin.
Other items voted on by holders of common stock at the Annual Meeting were as
follows:
(1) The appointment of the firm PricewaterhouseCoopers, LLP, independent
certified public accountants, as auditors of the Company for 1999, was
approved with 180,396,466 common shares (80.2% of common shares
outstanding) voting for; 650,651 common shares (0.3% of common shares
outstanding) voting against; and 1,019,788 common shares (0.5% of common
shares outstanding) abstaining;
(2) A shareholder proposal requesting the Company to establish a firm policy to
refuse to use mixed-oxide fuel in the Company's nuclear reactors was
defeated with 7,482,482 common shares (3.3% of common shares outstanding)
voting for; 129,078,299 common shares (57.4% of common shares outstanding)
voting against; 10,074,011 common shares (4.5% of common shares
outstanding) abstaining; and 35,432,113 common shares (15.8% of common
shares outstanding) broker votes.
22
<PAGE>
ITEM 5. OTHER INFORMATION
As previously reported in the 1998 Form 10-K, the NRC issued a confirmatory
order modifying the license for Limerick Generating Station (Limerick) Units No.
1 and No. 2 requiring that the Company complete final implementation of
corrective actions on the Thermo-Lag 330 issue by completion of the April 1999
refueling outage of Limerick Unit No. 2. By letter dated May 3, 1999, the NRC
approved the Company's request to extend the completion of thermo-lag corrective
actions at Limerick until September 30, 1999.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits:
27 - Financial Data Schedule.
(b) Reports on Form 8-K filed during the reporting period:
Report, dated March 8, 1999 reporting information under "ITEM 5. OTHER
EVENTS" regarding the denial of an intervenor's petition for certiorari
by the United States Supreme Court.
Report, dated March 25, 1999 reporting information under "ITEM 5. OTHER
EVENTS" regarding the securitization of $4 billion of the Company's
recoverable stranded costs through the issuance of $4 billion of
Transition Bonds by PECO Energy Transition Trust, an independent
special purpose entity formed by the Company.
Reports on Form 8-K filed subsequent to the reporting period:
Report, dated April 15, 1999 reporting information under "ITEM 5. OTHER
EVENTS" regarding AmerGen Energy Company, LLC, the joint venture
between the Company and British Energy, Inc., signing an interim
agreement to purchase the Clinton Nuclear Power Station from Illinois
Power (IP), a subsidiary of Illinova Corporation.
23
<PAGE>
Signatures
Pursuant to requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
PECO ENERGY COMPANY
/s/ Michael J. Egan
--------------------
MICHAEL J. EGAN
Vice President and
Senior Vice President and
Chief Financial Officer
(Chief Accounting Officer)
Date: April 6, 2000
24
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