UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 1999
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Commission file number: 1-1401
PECO Energy Company
(Exact name of registrant as specified in its charter)
Pennsylvania 23-0970240
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
2301 Market Street, Philadelphia, PA 19103
(Address of principal executive offices) (Zip Code)
(215) 841-4000
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period
that the registrant was required to file such reports), and (2) has
been subject to such filing requirements for the past 90 days.
Yes X No ___
Indicate the number of shares outstanding of each of the issuer's
classes of common stock as of the latest practicable date:
The Company had 186,603,406 shares of common stock outstanding on
August 6, 1999.
<PAGE>
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)
<TABLE>
<CAPTION>
Three Months Ended June 30, Six Months Ended June 30,
1999 1998 1999 1998
----------- ----------- ------------ ------------
OPERATING REVENUES
<S> <C> <C> <C> <C>
Electric $ 1,105.4 1,131.8 2,144.3 2,134.8
Gas 89.0 83.4 306.5 270.6
----------- ----------- ------------ ------------
TOTAL OPERATING REVENUES 1,194.4 1,215.2 2,450.8 2,405.4
----------- ----------- ------------ ------------
OPERATING EXPENSES
Fuel and Energy Interchange 500.3 360.2 965.4 743.2
Operating and Maintenance 338.9 256.0 627.6 539.2
Depreciation and Amortization 57.6 160.9 113.9 315.6
Taxes Other Than Income 45.2 71.8 120.5 153.9
----------- ----------- ------------ ------------
942.0 848.9 1,827.4 1,751.9
----------- ----------- ------------ ------------
OPERATING INCOME 252.4 366.3 623.4 653.5
----------- ----------- ------------ ------------
OTHER INCOME AND DEDUCTIONS
Interest Expense (113.5) (86.0) (187.8) (171.0)
Company Obligated Mandatorily Redeemable
Preferred Securities of a Partnership (7.4) (8.2) (14.8) (15.9)
Allowance for Funds Used During Construction 1.7 0.7 2.1 1.3
Other, Net (4.6) (26.9) (46.6) (39.7)
----------- ----------- ------------ ------------
TOTAL OTHER INCOME AND DEDUCTIONS (123.8) (120.4) (247.1) (225.3)
----------- ----------- ------------ ------------
INCOME BEFORE INCOME TAXES AND
EXTRAORDINARY ITEM 128.6 245.9 376.3 428.2
INCOME TAXES 41.0 94.4 139.0 163.1
----------- ----------- ------------ ------------
INCOME BEFORE EXTRAORDINARY ITEM 87.6 151.5 237.3 265.1
EXTRAORDINARY ITEM - NET OF INCOME TAXES (26.7) -- (26.7) --
----------- ----------- ------------ ------------
NET INCOME 60.9 151.5 210.6 265.1
PREFERRED STOCK DIVIDENDS 3.3 3.3 6.6 6.6
----------- ----------- ------------ ------------
EARNINGS APPLICABLE TO COMMON STOCK $ 57.6 $ 148.2 $ 204.0 $ 258.5
=========== =========== ============ ============
AVERAGE SHARES OF COMMON STOCK
OUTSTANDING (Millions) 192.0 222.7 207.6 222.6
=========== =========== ============ ============
BASIC AND DILUTIVE EARNINGS PER
AVERAGE COMMON SHARES BEFORE EXTRAORDINARY ITEM $ 0.44 $ 0.66 $ 1.11 $ 1.16
EXTRAORDINARY ITEM (0.14) -- (0.13) --
----------- ----------- ------------ ------------
BASIC EARNINGS PER AVERAGE COMMON SHARE $ 0.30 $ 0.66 $ 0.98 $ 1.16
=========== =========== ============ ============
DIVIDENDS PER AVERAGE COMMON SHARE $ 0.25 $ 0.25 $ 0.50 $ 0.50
=========== =========== ============ ============
</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>
June 30, December 31,
1999 1998
---------- ----------
(Unaudited)
ASSETS
UTILITY PLANT
<S> <C> <C>
Electric - Transmission & Distribution $ 3,890.8 $ 3,833.8
Electric - Generation 1,732.3 1,713.4
Gas 1,141.2 1,132.0
Common 409.3 407.3
---------- ----------
7,173.6 7,086.5
Less Accumulated Provision for Depreciation 3,007.6 2,891.3
---------- ----------
4,166.0 4,195.2
Nuclear Fuel, net 296.7 141.9
Construction Work in Progress 375.0 272.6
Leased Property, net 0.5 154.3
---------- ----------
4,838.2 4,764.0
---------- ----------
CURRENT ASSETS
Cash and Temporary Cash Investments 899.6 48.1
Accounts Receivable, net
Customer 213.1 97.5
Other 376.2 213.2
Inventories, at average cost
Fossil Fuel 62.9 92.3
Materials and Supplies 108.8 82.1
Deferred Income Taxes 7.7 (14.1)
Other 109.0 19.0
---------- ----------
1,777.3 538.1
---------- ----------
DEFERRED DEBITS AND OTHER ASSETS
Competitive Transition Charge 5,274.6 5,274.6
Recoverable Deferred Income Taxes 609.2 614.4
Deferred Non-Pension Postretirement Benefits Costs 87.7 90.9
Investments 554.8 538.1
Loss on Reacquired Debt 73.9 77.2
Other 131.0 107.1
---------- ----------
6,731.2 6,702.3
---------- ----------
TOTAL $ 13,346.7 $ 12,004.4
========== ==========
</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>
June 30, December 31,
1999 1998
---------- ----------
(Unaudited)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION
Common Shareholders' Equity
<S> <C> <C>
Common Stock (No Par) $ 3,616.7 $ 3,589.0
Other Paid-In Capital 1.2 1.2
Accumulated Deficit (422.5) (532.9)
Treasury Stock (1,507.3) --
Preferred and Preference Stock
Without Mandatory Redemption 137.5 137.5
With Mandatory Redemption 92.7 92.7
Company Obligated Mandatorily Redeemable
Preferred Securities of a Partnership 340.4 349.4
Long-Term Debt 6,092.2 2,919.6
---------- ----------
8,350.9 6,556.5
---------- ----------
CURRENT LIABILITIES
Notes Payable, Bank 226.0 525.0
Long-Term Debt Due Within One Year 146.1 361.5
Capital Lease Obligations Due Within One Year -- 69.0
Accounts Payable 357.5 316.2
Taxes Accrued 187.4 170.5
Interest Accrued 104.9 61.5
Deferred Energy Costs - Gas 26.3 (29.9)
Other 235.6 217.4
---------- ----------
1,283.8 1,691.2
---------- ----------
DEFERRED CREDITS AND OTHER LIABILITIES
Capital Lease Obligations 0.5 85.3
Deferred Income Taxes 2,355.3 2,376.9
Unamortized Investment Tax Credits 292.8 300.0
Pension Obligation 219.3 219.3
Non-Pension Postretirement Benefits Obligation 436.1 421.1
Other 408.0 354.1
---------- ----------
3,712.0 3,756.7
---------- ----------
COMMITMENTS AND CONTINGENCIES (NOTE 8)
TOTAL $ 13,346.7 $ 12,004.4
=========== ==========
</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>
Six Months Ended June 30,
1999 1998
---------- --------
CASH FLOWS FROM OPERATING ACTIVITIES
<S> <C> <C>
NET INCOME $ 210.6 $ 265.1
EXTRAORDINARY ITEM, NET OF INCOME TAXES 26.7 --
---------- --------
INCOME BEFORE EXTRAORDINARY ITEM 237.3 265.1
Adjustments to Reconcile Net Income to Net Cash
Provided by Operating Activities:
Depreciation and Amortization 149.4 343.0
Deferred Income Taxes (38.2) (29.3)
Amortization of Investment Tax Credits (7.2) (9.0)
Deferred Energy Costs 56.1 27.1
Changes in Working Capital:
Accounts Receivable (278.5) (87.1)
Inventories 2.7 9.0
Accounts Payable 41.3 (11.3)
Other Current Assets and Liabilities 14.4 (68.8)
Other Items Affecting Operations 74.4 71.3
---------- --------
CASH FLOWS PROVIDED BY OPERATING ACTIVITIES 251.7 510.0
---------- --------
CASH FLOWS FROM INVESTING ACTIVITIES
Investment in Plant (244.4) (229.1)
Increase in Investments (35.0) (35.8)
---------- --------
NET CASH FLOWS USED IN INVESTING ACTIVITIES (279.4) (264.9)
---------- --------
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of Long-Term Debt 4,000.0 6.4
Common Stock Repurchase (1,507.3) --
Debt Repayments (1,202.5) (96.8)
Change in Short-Term Debt (299.0) (55.5)
Dividends on Preferred and Common Stock (109.9) (117.8)
Issuance of Company Obligated Mandatorily
Redeemable Preferred Securities of a Partnership -- 78.1
Issuance of Common Stock 14.0 9.3
Other Items Affecting Financing (16.1) 3.1
---------- --------
NET CASH FLOWS PROVIDED BY (USED IN) FINANCING ACTIVITIES 879.2 (173.2)
---------- --------
INCREASE IN CASH AND CASH EQUIVALENTS 851.5 71.9
---------- --------
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 48.1 33.4
---------- --------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 899.6 $ 105.3
========== ========
</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 June
30, 1999 and for the three and six months then ended are unaudited, but include
all adjustments that PECO Energy Company (Company) considers necessary for a
fair presentation of such financial statements. All adjustments are of a normal,
recurring nature. The year-end condensed consolidated balance sheet data were
derived from audited financial statements but do not include all disclosures
required by generally accepted accounting principles. Certain prior-year amounts
have been reclassified for comparative purposes. These notes should be read in
conjunction with the Notes to Consolidated Financial Statements in the Company's
1998 Annual Report to Shareholders, which are incorporated by reference in the
Company's Annual Report on Form 10-K for the year ended December 31, 1998.
2. TRANSITION BONDS
On March 25, 1999, PECO Energy Transition Trust (PETT), an independent
statutory business trust organized under the laws of Delaware and a wholly owned
subsidiary of the Company, issued $4 billion aggregate principal amount of
Transition Bonds (Transition Bonds) to securitize a portion of the Company's
authorized stranded cost recovery. The Transition Bonds are solely obligations
of PETT, secured by Intangible Transition Property sold by the Company to PETT
concurrently with the issuance of the Transition Bonds and certain other
collateral related thereto.
The terms of the Transition Bonds are as follows:
<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
</TABLE>
(a) The Class A-3 and A-5 Transition Bonds earn interest at a floating
rate. The rates provided for each such class above are as of June 30,
1999.
6
<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 are being amortized over the life of the Transition Bonds as a
reduction of interest expense, consistent with the Company's hedge accounting
policy.
The Company has entered into interest rate swaps to manage interest
rate exposure associated with the issuance of two floating rate series of
Transition Bonds. At June 30, 1999, the fair value of these instruments was $52
million based on the present value difference between the contracted rate (i.e.,
hedged rate) and the market rates at that date. A hypothetical 50 basis point
increase or decrease in the spot yield at June 30, 1999 would have resulted in
an aggregate fair value of these interest rate swaps of $91.2 million or $10.7
million, respectively. If the derivative instruments had been terminated at June
30, 1999, these estimated fair values represent the amount to be paid by the
counterparties to the Company.
The net proceeds to the Company from the securitization of a portion of
its allowed stranded cost recovery, after payment of fees and expenses and the
capitalization of PETT, were approximately $3.95 billion. In accordance with the
provisions of the Pennsylvania Electricity Generation Customer Choice and
Competition Act, the Company is utilizing these proceeds principally to reduce
its stranded costs and related capitalization. Through June 30, 1999, the
Company utilized the net proceeds to repurchase 38.7 million shares of Common
Stock for an aggregate purchase price of $1.507 billion; to retire: $811 million
of First Mortgage Bonds, a $400 million term loan, $208 million of commercial
paper, $150 million of accounts receivable financing and a $139 million capital
lease obligation; to repurchase $9 million of Company Obligated Mandatorily
Redeemable Preferred Securities of a Partnership (COMRPS); and to pay $25
million of debt issuance costs. The remaining proceeds of approximately $750
million are included in cash at June 30, 1999. In addition, on July 30, 1999,
the Company redeemed $212 million of COMRPS. On August 2, 1999, the Company
retired $37 million of Mandatorily Redeemable Preferred Stock pursuant to the
sinking fund requirements of those securities.
In the second quarter of 1999, the Company incurred an extraordinary
charge of $26.7 million, net of tax, consisting of prepayment premiums and the
write-off of unamortized deferred financing costs associated with the early
retirement of debt.
3. SEGMENT INFORMATION
The Company is primarily a vertically integrated public utility that
provides retail electric and natural gas service to the public in its
traditional service territory and retail electric generation service throughout
Pennsylvania pursuant to Pennsylvania's Customer Choice Program. The Company's
management has historically managed the Company as a vertically integrated
entity by analyzing its results of operations on a consolidated basis with an
emphasis on electric and gas operations.
During the first quarter of 1999, the Company completed the redesign
of its internal reporting structure to separate its distribution, generation,
7
<PAGE>
and ventures operations into business units and provide financial and
operational data on the same basis to senior management. The Company's
distribution business unit includes its electric transmission and distribution
services, regulated retail sales of generation services and retail gas
businesses. The Company's generation business unit includes the operation of its
generation assets and its power marketing group. The Company's ventures business
unit includes its unregulated retail energy supplier, infrastructure services
business and its telecommunications equity investments.
During the second quarter of 1999, the Company further revised the
internal reporting structure to include its unregulated retail energy supplier
with the generation business unit to more efficiently manage the Company's
overall energy supply requirements. Accordingly, the results of operations and
assets of the unregulated retail energy supplier are included in the generation
business unit for all periods presented.
The Company's segment information as of and for the three and six
months ended June 30, 1999 as compared to the same 1998 period is as follows (in
millions of dollars):
Quarter Ended June 30, 1999 as compared to the quarter ended June 30, 1998
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C> <C>
Intersegment
Distribution Generation Ventures Corporate Revenues Consolidated
------------ ---------- -------- --------- -------- ------------
Revenues:
1999 $734.0 $653.2 $ .6 $ - $(193.4) $1,194.4
1998 $905.5 $547.7 $ .7 $ - $(238.7) $1,215.2
EBIT (a):
1999 $298.2 $ 11.1 $( 15.1) $( 44.7) $ 249.5
1998 $356.0 $ 61.0 $( 35.8) $( 41.1) $ 340.1
Six Months Ended June 30, 1999 as compared to six months ended June 30, 1998
Revenues:
1999 $1,646.5 $1,197.9 $ 1.2 $ - $(394.8) $2,450.8
1998 $1,854.3 $1,029.6 $ 1.3 $ - $(479.8) $2,405.4
EBIT (a):
1999 $655.7 $ 41.0(b) $( 36.0) $( 81.8) $ 578.9
1998 $663.5 $ 99.0 $( 59.5) $( 87.9) $ 615.1
Total Assets:
1999 $10,810.8(c) $1,868.5 $240.2 $427.2 $13,346.7
1998 $ 9,723.6 $1,680.6 $216.1 $384.1 $12,004.4
<FN>
(a) EBIT - Earnings Before Interest and Income Taxes.
(b) Includes an $11.8 million reserve related to the Grays Ferry power purchase
agreement and $14.6 million related to the write-off of the investment in Grays
Ferry in connection with the settlement of litigation.
(c) Includes $750 million of proceeds from securitization of stranded costs.
</FN>
</TABLE>
8
<PAGE>
4. EARNINGS PER SHARE
Diluted earnings per average common share is calculated by dividing
earnings applicable to common stock by the average shares of common stock
outstanding after giving effect to stock options, issuable under the Company's
stock option plans, considered to be dilutive common stock equivalents. The
following table shows the effect of the stock options issuable under the
Company's stock option plans on the average number of shares used in calculating
diluted earnings per average common share (in millions of shares):
<TABLE>
<CAPTION>
Three Months Ended Six Months Ended
June 30, June 30,
1999 1998 1999 1998
----- ----- ----- -----
<S> <C> <C> <C> <C>
Average Common Shares Outstanding 192.0 222.7 207.6 222.6
Assumed Conversion of Stock Options 1.5 .7 1.5 .7
----- ----- ----- -----
Potential Average Dilutive
Common Shares Outstanding 193.5 223.4 209.1 223.3
===== ===== ===== =====
</TABLE>
5. SALES OF ACCOUNTS RECEIVABLE
The Company is party to an agreement with a financial institution,
under which it can sell or finance with limited recourse an undivided interest,
adjusted daily, in up to $275 million of designated accounts receivable until
November 2000. At June 30, 1999, the Company had sold a $275 million interest in
accounts receivable, consisting of a $232 million interest in accounts
receivable which the Company accounts for as a sale under Statement of Financial
Accounting Standards (SFAS) No. 125, "Accounting for Transfers and Servicing of
Financial Assets and Extinguishment of Liabilities," and a $43 million interest
in special agreement accounts receivable which are accounted for as a long-term
note payable. The Company retains the servicing responsibility for these
receivables. The agreement requires the Company to maintain the $275 million
interest, which, if not met, requires the Company to deposit cash in order to
satisfy such requirements. The Company, at June 30, 1999, met such requirements.
At June 30, 1999, the average annual service-charge rate, computed on a daily
basis on the portion of the accounts receivable sold but not yet collected, was
4.90%.
6. AMERGEN ENERGY COMPANY
On April 15, 1999, AmerGen Energy Company, LLC (AmerGen), the joint
venture between the Company and British Energy, plc (British Energy), announced
an interim agreement to purchase the Clinton Nuclear Power Station (Clinton)
from Illinois Power (IP), a subsidiary of Illinova Corporation. On June 30,
1999, AmerGen and British Energy signed a definitive agreement to purchase
Clinton from IP. AmerGen has entered into agreements to purchase Three Mile
Island Unit No.1 Nuclear Generating Facility, Nine Mile Point Unit 1 Nuclear
Generating Facility and 59% of Nine Mile Point Unit 2 Nuclear Generating
Facility. In addition, the Company and IP amended the January 15, 1998
Management Agreement, providing for the provision of certain management services
by the Company to IP in support of Clinton's outage recovery efforts and
operations.
9
<PAGE>
7. CLINTON NUCLEAR POWER STATION
Under the Amended Management Agreement, effective April 1, 1999, the
Company is responsible for the payment of all direct operating and maintenance
(O&M) costs and direct capital costs incurred by IP and allocable to the
operation of Clinton. IP will continue to pay indirect costs such as pension
benefits, payroll taxes and property taxes. Following the restart of Clinton,
which occurred on June 2, 1999, and through December 31, 1999, the Company is
selling 80% of the output of Clinton to IP. The remaining output is being sold
by the Company in the wholesale market. Under a separate agreement with the
Company, British Energy has agreed to share 50% of the costs and revenues
associated with the Amended Management Agreement. In the second quarter of 1999,
the Company recognized $14 million of revenue from sales to IP and $25 million
of O&M expenses related to Clinton.
8. COMMITMENTS AND CONTINGENCIES
For information regarding the Company's capital commitments, nuclear
insurance, nuclear decommissioning and spent fuel storage, energy commitments,
environmental issues and litigation, see note 5 of Notes to Consolidated
Financial Statements for the year ended December 31, 1998.
At June 30, 1999, the Company had entered into long-term agreements
with unaffiliated utilities to purchase transmission rights. These purchase
commitments result in obligations of approximately $50 million in 1999, $88
million in 2000, $51 million in 2001, and $41 million in 2002, $36 million in
2003 and $97 million thereafter.
The Company has identified 28 sites where former manufactured gas plant
(MGP) activities have or may have resulted in actual site contamination. As of
June 30, 1999, the Company had accrued $59 million for environmental
investigation and remediation costs, including $33 million for MGP investigation
and remediation that currently can be reasonably estimated. The Company cannot
predict whether it will incur other significant liabilities for additional
investigation and remediation costs at these or additional sites identified by
the Company, environmental agencies or others, or whether all such costs will be
recoverable from third parties.
On April 23, 1999, the Company and Grays Ferry Cogeneration Partnership
(Grays Ferry) entered into a final settlement of litigation. The settlement
resulted in a restructuring of the power purchase agreement between the Company
and Grays Ferry. The settlement also required the Company to contribute its
interest in the partnership to the remaining partners. Accordingly, the Company
recorded a charge to earnings of $14.6 million for the transfer of its
partnership interest and a reserve of $11.8 million related to the power
purchase agreement. The charge for the partnership interest transfer is recorded
in Other Income and Deductions and the reserve related to power purchase
agreement is recorded in Fuel and Energy Interchange Expense on the Company's
Statement of Income for the six months ended June 30, 1999. The settlement also
resolved the litigation with Westinghouse Power Generation and The Chase
Manhattan Bank.
10
<PAGE>
9. NEW ACCOUNTING PRONOUNCEMENTS
In June 1998, the Financial Accounting Standards Board (FASB) issued
SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities,"
(SFAS No. 133) to establish accounting and reporting standards for derivatives.
The new standard requires recognizing all derivatives as either assets or
liabilities on the balance sheet at their fair value and specifies the
accounting for changes in fair value depending upon the intended use of the
derivative. In June 1999, the FASB issued SFAS No. 137 "Accounting for
Derivative Instruments and Hedging Activities - Deferral of the Effective Date
of FASB Statement No. 133," (SFAS No. 137) which delayed the effective date for
SFAS No. 133 until fiscal years beginning after June 15, 2000. The Company
expects to adopt SFAS No. 133 in the first quarter of 2001. The Company is in
the process of evaluating the impact of SFAS No. 133 on its financial
statements.
In November 1998, the FASB's Emerging Issues Task Force (EITF) issued
EITF 98-10, "Accounting for Contracts Involved in Energy Trading and Risk
Management Activities." EITF 98-10 outlines attributes that may be indicative of
an energy trading operation and gives further guidance on the accounting for
contracts entered into by an energy trading operation. This accounting guidance
requires mark-to-market accounting for contracts considered to be a trading
activity. EITF 98-10 is applicable for fiscal years beginning after December 15,
1998 with any impact recorded as a cumulative effect adjustment through retained
earnings at the date of adoption.
The Company's wholesale marketing operations enter into long-term and
short-term commitments to purchase and sell energy and energy-related products
with the intent and ability to deliver or take delivery. The objective of the
long-term commitments is to establish a generation base that allows the Company
to meet the physical supply and demand requirements of a national wholesale
electric marketplace through scheduled, real-time delivery of electricity. The
Company utilizes short-term energy commitments and contracts, entered into in
the over-the-counter market, to economically hedge seasonal and operational
risks associated with peak demand periods and generation plant outages.
The Company reviewed the criteria indicative of an energy trading
operation as outlined in EITF 98-10 against the objectives and intent of the
Company's wholesale marketing operation's activities. The Company concluded that
none of the activities of its marketing operation are trading activities and
therefore these activities are not subject to EITF 98-10 or mark-to-market
accounting.
The Company records revenues and expenses associated with the energy
commitments at the time the underlying physical transaction closes.
Additionally, the Company evaluates its energy commitments for impairment based
on the lower of cost or market. At June 30, 1999, the Company concluded that no
energy commitments were impaired.
11
<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. As of January 2, 1999, two-thirds of each class
of the Company's retail electric customers in its traditional service territory
have a right to choose their generation suppliers. Effective January 2, 2000,
all of the Company's retail electric customers in its traditional service
territory will have the right to choose their generation suppliers. At June 30,
1999, approximately 239,000 customers representing 15% of the Company's
residential customers, 25% of its commercial customers and 58% of its industrial
customers had selected an alternate energy supplier. As of that date, Exelon
Energy, the Company's alternative energy supplier, was providing electric
generation service to approximately 141,000 business and residential customers
located throughout Pennsylvania.
Effective January 1, 1999, the Company reduced its retail electric
rates for all customers by 8%. On that date, the Company began recovering its
stranded costs through the collection of competitive transition charges from all
customers. On March 25, 1999, PECO Energy Transition Trust (PETT), a wholly
owned subsidiary of the Company, issued $4 billion of PECO Energy Transition
Trust Transition Bonds to securitize a portion of the Company's stranded cost
recovery. In accordance with the terms of the Competition Act, the Company is
utilizing the proceeds from the issuance of the Transition Bonds principally to
reduce stranded costs and capitalization.
The Company currently estimates that the impact of additional interest
expense associated with the Transition Bonds partially offset by interest
savings related to higher cost debt retired with Transition Bond proceeds,
combined with the anticipated reduction in common equity, will result in
earnings per share benefits of approximately $.15 and $.50 in 1999 and 2000,
respectively. These estimated earnings per share could change and are largely
dependent upon the timing and price of common stock repurchases and anticipated
net income available to common stock.
The Company expects that competition for both retail and wholesale
generation services will substantially affect its future results of operations.
See "Management's Discussion and Analysis of Financial Condition and Results of
Operations - Outlook," incorporated by reference in the Company's Annual Report
on Form 10-K for the year ended December 31, 1998.
The Company's internal reporting structure consists of its
distribution, generation, and ventures operations. The Company's distribution
business unit includes its electric transmission and distribution services,
regulated retail sales of generation services and retail gas businesses. The
Company's generation business unit includes the operation of its generation
assets, its power marketing group and its unregulated retail energy supplier.
The Company's ventures business unit includes its infrastructure services
business and its telecommunications equity investments.
12
<PAGE>
RESULTS OF OPERATIONS
The Company's Condensed Consolidated Statements of Income for the three
and six months ended June 30, 1998 reflect the reclassification of the results
of operations of Exelon Energy, from Other Income and Deductions.
Under its Amended Management Agreement with Illinois Power (IP),
effective April 1, 1999, the Company is responsible for the payment of all
direct operating and maintenance (O&M) costs and direct capital costs incurred
by IP and allocable to the operation of Clinton Nuclear Power Station (Clinton).
IP will continue to pay indirect costs such as pension benefits, payroll taxes
and property taxes. Following the restart of Clinton, which occurred on June
2,1999, and through December 31, 1999, the Company is selling 80% of the output
of Clinton to IP. The remaining output is being sold by the Company in the
wholesale market. Under a separate agreement with the Company, British Energy
has agreed to share 50% of the costs and revenues associated with the Amended
Management Agreement.
<TABLE>
<CAPTION>
Revenue and Expense Items as a
Percentage of Total Operating
Revenues Percentage Dollar Changes
1999 vs. 1998
Quarter Six Months Quarter Six Months
Ended Ended Ended Ended
June 30, June 30, June 30, June 30,
1999 1998 1999 1998
<S> <C> <C> <C> <C> <C> <C>
93% 93% 87% 89% Electric (2%) --%
7% 7% 13% 11% Gas 7% 13%
---- ---- ---- ----
100% 100% 100% 100% Total Operating Revenues (2%) 2%
---- ---- ---- ----
42% 30% 39% 31% Fuel and Energy Interchange 39% 30%
28% 21% 26% 22% Operating and Maintenance 32% 16%
5% 13% 5% 13% Depreciation and Amortization (64%) (64%)
4% 6% 5% 6% Taxes Other Than Income (37%) (22%)
---- ---- ---- ----
79% 70% 75% 72% Total Operating Expenses 11% 4%
---- ---- ---- ----
21% 30% 25% 28% Operating Income (31%) (5%)
---- ---- ---- ----
(10%) (8%) (8%) (8%) Interest Charges 28% 8%
( 1%) (2%) (2%) (2%) Other Income and Deductions (83%) 17%
---- ---- ---- ----
Income Before Income Taxes and
10% 20% 15% 18% Extraordinary Item (48%) (12%)
3% 8% 6% 7% Income Taxes (57%) (15%)
---- ---- ---- ----
7% 12% 9% 11% Income Before Extraordinary Item
(2%) -- (1%) -- Extraordinary Item 100% --%
---- ---- ---- ----
5% 12% 8% 11% Net Income (60%) (21%)
==== ==== ==== ====
</TABLE>
13
<PAGE>
Second Quarter 1999 Compared To Second Quarter 1998
Operating Revenues
Electric revenues decreased $26 million, or 2%, for the quarter ended
June 30, 1999 compared to the same 1998 period. The decrease was primarily
attributable to lower revenues from the distribution business unit of $176
million partially offset by higher revenues from the generation business unit of
$150 million. The decrease from the distribution business unit was attributable
to $136 million as a result of lower volume associated with the effects of
competition, $65 million related to the 8% across-the-board rate reduction
mandated by the Final Restructuring Order and $12 million related to decreased
sales volume from milder weather conditions as compared to the prior year
comparable period. These decreases were partially offset by $37 million of PJM
Interconnection, LLC (PJM) network transmission service revenue which commenced
April 1, 1998. PJM network transmission service revenues and charges were
recorded in the generation business unit in 1998 but are being recognized by the
distribution business unit in 1999 as a result of the Federal Energy Regulatory
Commission approval of the PJM Regional Transmission Owners' rate case
settlements. Stranded cost recovery is included in the Company's retail electric
rates beginning January 1, 1999. The increase from the generation business unit
was attributable to $117 million from increased volume in Pennsylvania resulting
from the sale of competitive electric generation services by Exelon Energy,
increased wholesale revenues of $58 million from the marketing of excess
generation capacity as a result of retail competition and $14 million from the
sale of generation from Clinton to IP, partially offset by $39 million of PJM
network transmission service revenue in the comparable period.
Gas revenues increased $6 million, or 7%, for the quarter ended June
30, 1999 compared to the same 1998 period. The increase was primarily
attributable to $4 million from increased volume as a result of cooler weather
conditions in the beginning of the quarter and $2 million from increased volume
from new and existing customers.
Fuel and Energy Interchange Expense
Fuel and energy interchange expense increased $140 million, or 39%, for
the quarter ended June 30, 1999 compared to the same 1998 period. As a
percentage of revenue, fuel and interchange expenses were 42% as compared to 30%
in the comparable prior year period. These increases were attributable to higher
fuel and energy interchange expenses associated with the generation business
unit of $83 million and the distribution business unit of $57 million. The
increase from the generation business unit was primarily attributable to $129
million related to increased volume from Exelon Energy sales, partially offset
by lower PJM network transmission service charges of $39 million and $3 million
of fuel savings associated with the full return to service of the Salem
Generating Station (Salem) in April 1998 which decreased the need to purchase
power to replace the output from these units. The increase from the distribution
business unit was attributable to $24 million of PJM network transmission
service charges, $46 million of purchases in the spot market and $10 million of
additional gas purchases as a result of higher volume associated with cooler
weather early in the quarter and additional volume to new and existing
customers. These increases were partially offset by $23 million of lower fuel
costs primarily as a result of lower volume associated with Customer Choice.
14
<PAGE>
Operating and Maintenance Expense
Operating and maintenance (O&M) expense increased $83 million, or 32%
for the quarter ended June 30, 1999 compared to the same 1998 period. As a
percentage of revenue, operating and maintenance expenses were 28% as compared
to 21% in the comparable prior year period. The generation business unit's O&M
expenses increased $58 million as a result of $25 million related to the revised
Clinton management agreement, $15 million associated with the Salem inventory
write-off and true-up of 1998 reimbursement of joint-owner expenses and $15
million related to the growth of unregulated retail sales of electricity. The
distribution unit's O&M expenses increased approximately $22 million as a result
of additional marketing expenses and expenses associated with Customer Choice.
In addition, the Company incurred additional costs of approximately $11 million
related to nuclear property insurance and $4 million associated with Year 2000
remediation expenditures, partially offset by $10 million of pension credits as
a result of the performance of the investments in the Company's pension plan.
Depreciation and Amortization Expense
Depreciation and amortization expense decreased $103 million, or 64%,
for the quarter ended June 30, 1999 compared to the same 1998 period. As a
percentage of revenue, depreciation and amortization expense was 5% as compared
to 13% in the comparable prior year period. The decrease was associated with the
December 1997 restructuring charge through which the Company wrote down a
significant portion of its generating plant and regulatory assets. In connection
with this restructuring charge, the Company reduced generation-related assets by
$8.4 billion, established a regulatory asset, Deferred Generation Costs
Recoverable in Current Rates of $424 million, which was fully amortized in 1998,
and established an additional regulatory asset, Competitive Transition Charge
(CTC) of $5.26 billion which will begin to be amortized in accordance with the
terms of the Final Restructuring Order in 2000. For additional information, see
"PART I, ITEM 1. - BUSINESS - Deregulation and Rate Matters," in the Company's
1998 Annual Report on Form 10-K.
Taxes Other Than Income
Taxes other than income decreased $27 million, or 37%, for the quarter
ended June 30, 1999 compared to the same 1998 period. As a percentage of
revenue, taxes other than income were 4%, as compared to 6%, in the comparable
prior year period. The decrease was primarily attributable to a $26 million
credit related to an adjustment to the Company's Pennsylvania capital stock tax
base as a result of the 1997 restructuring charge and lower gross receipts tax
of $3 million associated with lower retail electric and gas sales.
Interest Charges
Interest charges consist of interest expense, distributions on Company
Obligated Mandatorily Redeemable Preferred Securities of a Partnership (COMPRS)
and Allowance for Funds Used During Construction (AFUDC). Interest charges
increased $26 million, or 28%, for the quarter ended June 30, 1999 compared to
the same 1998 period. As a percentage of revenue, interest charges were 10% as
compared to 8% in the comparable prior year period. The increase was primarily
attributable to interest on the Transition Bonds of $60 million, partially
offset by the Company's ongoing program to reduce and/or refinance higher cost,
long-term debt, including the use of a portion of the proceeds from the issuance
of Transition Bonds, which reduced interest charges by $34 million.
15
<PAGE>
Other Income and Deductions
Other income and deductions excluding interest charges was a loss of $5
million for the quarter ended June 30, 1999 as compared to a loss of $27 million
in the same 1998 period. The decrease of $22 million was primarily attributable
to a $10 million write-off of a non-regulated business venture in the prior year
period and a $5 million improvement in the performance of the Company's equity
investments in telecommunications.
Income Taxes
The effective tax rate was 32% for the quarter ended June 30, 1999 as
compared to 38% in the same 1998 period. The decrease in the effective tax rate
was a result of tax benefits associated with the implementation of state tax
planning strategies, partially offset by the non-recognition for state income
tax purposes of certain operating losses. In addition, the disproportionate
relationship of regulated plant tax adjustments to income before income taxes
and extraordinary item contributed to the decrease in the effective tax rate.
Extraordinary Item
During the second quarter of 1999, the Company incurred an
extraordinary charge of $26.7 million, net of tax, consisting of prepayment
premiums and the write-off of unamortized deferred financing costs associated
with the early retirement of debt with a portion of the proceeds from the
issuance of Transition Bonds.
Preferred Stock Dividends
Preferred stock dividends for the quarter ended June 30, 1999 were
consistent with the same 1998 period.
Six Months Ended June 30, 1999 Compared to Six Months Ended June 30, 1998
Operating Revenues
Electric revenues increased $10 million for the six months ended June
30, 1999 compared to the same 1998 period. The increase was primarily
attributable to higher revenues from the generation business unit of $256
million partially offset by lower revenues from the distribution business unit
of $246 million. The increase from the generation business unit was attributable
to $204 million from increased volume in Pennsylvania resulting from the sale of
competitive electric generation services by Exelon Energy, increased wholesale
revenues of $77 million from the marketing of excess generation capacity as a
result of retail competition and $14 million from the sale of generation from
Clinton to IP, partially offset by $39 million of PJM network transmission
service revenue in the comparable 1998 period. The decrease from the
distribution business unit was attributable to $205 million as a result of lower
volume associated with the effects of retail competition and $120 million
related to the 8% across-the-board rate reduction mandated by the Final
Restructuring Order. These decreases were partially offset by $74 million of PJM
network transmission service revenue and $5 million related to increased sales
volume as a result of colder weather conditions in the first quarter of 1999
partially offset by milder weather conditions in the second quarter of 1999 as
compared to the prior year periods.
16
<PAGE>
Gas revenues increased $36 million, or 13%, for the six months ended
June 30, 1999 compared to the same 1998 period. The increase was primarily
attributable to $24 million from increased volume as a result of cooler weather
conditions in the beginning of the period as compared to the prior year period
and $12 million from increased volume from new and existing customers.
Fuel and Energy Interchange Expense
Fuel and energy interchange expense increased $222 million, or 30%, for
the six months ended June 30, 1999 compared to the same 1998 period. As a
percentage of revenue, fuel and interchange expenses were 39% as compared to 31%
in the comparable prior year period. These increases were attributable to higher
fuel and energy interchange expenses associated with the distribution business
unit of $119 million and the generation business unit of $103 million. The
increase from the distribution business unit was primarily attributable to $51
million of PJM network transmission service charges, $99 million of purchases in
the spot market and $21 million of additional gas purchases as a result of
higher volume associated with cooler weather early in the period and additional
volume to new and existing customers. These increase were partially offset by
$55 million of lower fuel costs as a result of lower volume associated with
Customer Choice. The increase from the generation business unit was primarily
attributable to $200 million related to increased volume from Exelon Energy
sales, partially offset by $45 million of lower fuel costs as a result of lower
volume, lower PJM network transmission service charges of $39 million, and $19
million of fuel savings associated with the full return to service of the Salem
Generating Station (Salem) in April 1998 which decreased the need to purchase
power to replace the output from these units.
Operating and Maintenance Expense
O&M expense increased $88 million, or 16% for the six months ended June
30, 1999 compared to the same 1998 period. As a percentage of revenue, operating
and maintenance expenses were 26% as compared to 22% in the comparable prior
year period. The generation business unit's O&M expenses increased $50 million
as a result of $25 million related to the revised Clinton management agreement,
$15 million associated with the Salem inventory write-off and true-up of 1998
reimbursement of joint-owner expenses and $10 million related to the growth of
unregulated retail sales of electricity, partially offset by $10 million of
lower O&M expenses as a result of the full return to service of Salem in April
1998. The distribution unit's O&M expenses increased approximately $22 million
as a result of additional marketing expenses and expenses associated with
Customer Choice. In addition, the Company incurred additional costs of
approximately $11 million related to nuclear property insurance and $16 million
associated with Year 2000 remediation expenditures, partially offset by $10
million of pension credits as a result of the performance of the investments in
the Company's pension plan.
Depreciation and Amortization Expense
Depreciation and amortization expense decreased $202 million, or 64%,
for the six months ended June 30, 1999 compared to the same 1998 period. As a
percentage of revenue, depreciation and amortization expense was 5% as compared
to 13% in the comparable prior year period. The decrease was associated with the
December 1997 restructuring charge through which the Company wrote down a
significant portion of its generating plant and regulatory assets.
17
<PAGE>
Taxes Other Than Income
Taxes other than income decreased $33 million, or 22%, for the six
months ended June 30, 1999 compared to the same 1998 period. As a percentage of
revenue, taxes other than income were 5%, as compared to 6%, in the comparable
prior year period. The decrease was primarily attributable to a $30 million
credit related to an adjustment to the Company's Pennsylvania capital stock tax
base as a result of the 1997 restructuring charge and lower gross receipts tax
of $6 million associated with lower retail electric and gas sales.
Interest Charges
Interest charges increased $15 million, or 8%, for the six months ended
June 30, 1999 compared to the same 1998 period. As a percentage of revenue,
interest charges were comparable to the prior year period at 8%. The increase
was primarily attributable to interest on the Transition Bonds of $60 million,
partially offset by the Company's ongoing program to reduce and/or refinance
higher cost, long-term debt, including the use of a portion of the proceeds from
the issuance of Transition Bonds, which reduced interest charges by $45 million.
Other Income and Deductions
Other income and deductions excluding interest charges was a loss of
$47 million for the six months ended June 30, 1999 as compared to a loss of $40
million in the same 1998 period. The increase of $7 million was primarily
attributable to a $15 million write-off of the investment in Grays Ferry in
connection with the settlement of litigation, and a charge related to the
abandonment of an information system of $7 million, partially offset by a $10
million write-off of a non-regulated business venture in the prior year period
and a $3 million improvement in the performance of the Company's equity
investments in telecommunications ventures.
Income Taxes
The effective tax rate was 37% for the six months ended June 30, 1999
as compared to 38% in the same 1998 period. The decrease in the effective tax
rate was a result of tax benefits associated with the implementation of state
tax planning strategies, partially offset by the non-recognition for state
income tax purposes of certain operating losses. In addition, the
disproportionate relationship of regulated plant tax adjustments to income
before income taxes and extraordinary item contributed to the decrease in the
effective tax rate.
Extraordinary Item
During the second quarter of 1999, the Company incurred an
extraordinary charge of $26.7 million, net of tax, consisting of prepayment
premiums and the write-off of unamortized deferred financing costs associated
with the early retirement of debt with a portion of the proceeds from the
issuance of Transition Bonds.
Preferred Stock Dividends
Preferred stock dividends for the six months ended June 30, 1999 were
consistent with the same 1998 period.
18
<PAGE>
DISCUSSION OF LIQUIDITY AND CAPITAL RESOURCES
Cash flows provided by operating activities decreased $258 million to
$252 million for the six months ended June 30, 1999 as compared to $510 million
in the same 1998 period. The decrease was primarily attributable to less cash
generated by operations of $192 million and changes in working capital of $62
million, principally related to accounts receivable from unregulated energy
sales.
Cash flows used by investing activities were $279 million for the six
months ended June 30, 1999 as compared to $265 million in the comparable 1998
period and consisted primarily of capital expenditures for plant.
Cash flows provided by financing activities were $879 million for the
six months ended June 30, 1999, as compared to cash used in financing activities
of $173 million in the comparable prior year period. The increase was
attributable to the issuance of $4 billion of Transition Bonds by PETT partially
offset by the repayment of short-term and long-term debt aggregating $1.5
billion and the application of $1.5 billion of Transition Bond proceeds to the
repurchase of common stock, including the settlement of the Company's common
stock forward purchase contract.
On March 25, 1999, PETT issued $4 billion of its Transition Bonds to
securitize a portion of the Company's authorized stranded cost recovery. The
Transition Bonds are solely obligations of PETT, secured by the Intangible
Transition Property (ITP) sold by the Company to PETT. Upon issuance of the
Transition Bonds, a portion of the competitive transition charges to be
collected by the Company to recover stranded costs was designated as Intangible
Transition Charges (ITC). The ITC is an irrevocable non-bypassable usage based
charge that is calculated to allow for the recovery of debt service and costs
related to the issuance of the Transition Bonds. The ITC will be allocated from
CTC and variable distribution charges (both of which are usage based charges).
PETT used the $3.95 billion of proceeds of the Transition Bonds to
purchase the ITP from the Company. Although the Transition Bonds are solely
obligations of PETT, they are included in the consolidated long-term debt of the
Company. In accordance with the terms of the Competition Act, the Company is
utilizing the proceeds principally to reduce stranded costs and capitalization.
The Company currently plans to reduce its capitalization in the following
proportions: fixed and floating-rate debt, 50%; preferred securities, 7%; common
equity, 43%. Through June 30, 1999, the Company utilized the net proceeds to
repurchase 38.7 million shares of Common Stock for an aggregate purchase price
of $1.507 billion; to retire: $811 million of First Mortgage Bonds, a $400
million term loan, $208 million of commercial paper, $150 million of accounts
receivable financing and a $139 million capital lease obligation; to repurchase
$9 million of Company Obligated Mandatorily Redeemable Preferred Securities of a
Partnership (COMRPS); and to pay $25 million of debt issuance costs. The
remaining proceeds of approximately $750 million are included in cash at June
30, 1999. In addition, on July 30, 1999, the Company redeemed $212 million of
COMRPS. On August 2, 1999, the Company retired $37 million of Mandatorily
Redeemable Preferred Stock pursuant to the sinking fund requirements of those
securities. The Company currently anticipates that it will complete the
repurchase of common equity through open market purchases from time to time in
compliance with Securities and Exchange Commission rules. The number of shares
purchased and the timing and manner or purchases are dependent upon market
conditions.
19
<PAGE>
Although the Company has sold the ITP to PETT, the ITC revenue, as well
as all interest expense and amortization expense associated with the Transition
Bonds, is reflected on the Company's Consolidated Statement of Income. The
combined schedule for amortization of the CTC and ITC assets is in accordance
with the amortization schedule set forth in the Final Restructuring Order. As a
result of the issuance of the Transition Bonds and the on-going capital
reduction by the Company, the Company expects its debt-to-total capital ratio to
be 60%, exclusive of the Transition Bonds, upon completion of the application of
the proceeds from securitization. The Company completed the majority of the
targeted debt and preferred security reductions by August 2, 1999, and expects
that the remaining reductions will be completed by December 31, 1999. The
weighted average cost of debt and preferred securities to be retired is
approximately 6.8%. The additional interest expense associated with the
Transition Bonds, which have an effective interest rate of approximately 5.8%,
will be partially offset by the anticipated interest savings associated with the
debt and preferred securities that will be retired. The Company currently
estimates that the impact of this additional expense, combined with the
anticipated reduction in common equity, will result in earnings per share
benefits of approximately $.15 and $.50 in 1999 and 2000, respectively. These
estimated earnings per share could change and are largely dependent upon the
timing and price of common stock repurchases and anticipated net income
available to common stock.
At June 30, 1999, the Company had outstanding $226 million of notes
payable, all of which were commercial paper. In addition, at June 30, 1999, the
Company had formal and informal lines of bank credit aggregating $100 million.
At June 30, 1999, the Company had no short-term investments.
On May 3, 1999, Standard & Poor's upgraded its ratings on the Company's
overall corporate credit to "A-" from "BBB+", first and refunding mortgage bonds
and collateralized medium-term notes to "A" from "BBB+", hybrid preferred
securities, capital trust securities and preferred stock to "BBB" from "BBB-".
YEAR 2000 READINESS DISCLOSURE
The Year 2000 Project (Y2K Project) is addressing the issue resulting
from computer programs using two digits rather than four to define the
applicable year and other programming techniques that constrain date
calculations or assign special meanings to certain dates. Any of the Company's
computer systems that have date-sensitive software or microprocessors may
recognize a date using "00" as the year 1900 rather than the year 2000. This
could result in a system failure or miscalculations causing disruptions of
operations, including, a temporary inability to process transactions, send
bills, operate generating stations, or engage in similar normal business
activities. Due to the severity of the potential impact of the Year 2000 Issue
(Y2K Issue) on the electric utility industry, the Company adopted a
comprehensive schedule to achieve Y2K readiness by the time specified by the
Nuclear Regulatory Commission (NRC). The Company has dedicated extensive
resources to the Project and believes it is progressing on schedule.
20
<PAGE>
The Company determined that it was required to modify, convert or
replace significant portions of its software and a subset of its system hardware
and embedded technology so that its computer systems will properly utilize dates
beyond December 31, 1999. The Company presently believes that with these
modifications, conversions and replacements the effect of the Y2K Issue on the
Company can be mitigated. If such modifications, conversions and replacements
are not made, or are not completed in a timely manner, the Y2K Issue could have
a material impact on the operations and financial condition of the Company. The
costs associated with this potential impact are not presently quantifiable. The
Company is utilizing both internal and external resources to reprogram, or
replace and test software and computer systems for the Project. The Project was
scheduled for completion by July 1, 1999, except for a small number of
modifications, conversions or replacements that are impacted by PUC changes,
vendor dates and/or are being incorporated into scheduled plant outages between
July and November 1999. The scheduled Project completion date was met, with the
limited anticipated exceptions noted above.
The Project is divided into four major sections - Information
Technology Systems (IT Systems), Embedded Technology (devices used to control,
monitor or assist the operation of equipment, machinery or plant), Supply Chain
(third-party suppliers and customers), and Contingency Planning. The general
phases common to the first two sections are: (1) inventorying Y2K items; (2)
assigning priorities to identified items; (3) assessing the Y2K readiness of
items determined to be material to the Company; (4) converting material items
that are determined not to be Y2K ready; (5) testing material items; and (6)
designing and implementing contingency plans for each critical Company process.
Material items are those believed by the Company to have a risk involving the
safety of individuals, may cause damage to property or the environment, or
affect revenues.
The IT Systems section includes both the conversion of applications
software that is not Y2K ready and the replacement of software when available
from the supplier. The Project has identified 363 critical systems of which 234
are IT Systems and 129 Embedded Systems. The current readiness status of IT
Systems is set forth below:
Number of Systems Progress Status
233 Systems Y2K Ready
1 System In Testing
Contingency planning for IT Systems has been completed.
The remaining 129 systems are the Embedded Systems consisting of
hardware and systems software other than IT Systems. The current readiness
status of those systems is set forth below:
Number of Systems Progress Status
120 Systems Y2K Ready
9 Systems In Progress
Contingency planning for Embedded Technology has been completed.
21
<PAGE>
The Supply Chain section includes the process of identifying and
prioritizing critical suppliers and communicating with them about their plans
and progress in addressing the Y2K Issue. The process of evaluating critical
suppliers was completed on March 31, 1999. The Company has completed contingency
plans for all critical suppliers.
In addition to addressing contingency plans with key suppliers, the
Company is currently developing contingency plans to address how to respond to
internal events which may disrupt normal operations. These plans address Y2K
risk scenarios that cross departments and business units. Emergency plans
already exist that cover various aspects of the Company's business. These plans
are being reviewed and updated to address the Y2K Issue. The Company is also
participating in industry contingency planning efforts.
The estimated total cost of the Project is $75 million, the majority of
which is attributable to testing. This estimate includes the Company's share of
Y2K costs for jointly owned facilities. The total amount expended on the Project
through June 30, 1999 was $44 million. The Company expects to fund the Project
from operating cash flows. The Company's failure to become Y2K ready could
result in an interruption in or a failure of certain normal business activities
or operations. In addition, there can be no assurance that the systems of other
companies on which the Company's systems rely or with which they communicate
will be converted in a timely manner, or that a failure to convert by another
company, or a conversion that is incompatible with the Company's systems, will
not have a material adverse effect on the Company. Such failures could
materially and adversely affect the Company's results of operations, liquidity
and financial condition. The Company is currently developing contingency plans
to address how to respond to events that may disrupt normal operations,
including activities with PJM. The costs of the Project and the date on which
the Company plans to complete the Y2K modifications are based on estimates, that
were derived utilizing numerous assumptions of future events, including the
continued availability of certain resources, third-party modification plans and
other factors, such as regulatory requirements that impact key systems. There
can be no assurance that these estimates will be achieved. Actual results could
differ materially from the projections. Specific factors that might cause a
material change include, but are not limited to, the availability and cost of
trained personnel, the ability to locate and correct all relevant computer
programs and microprocessors.
The Project is expected to significantly reduce the Company's level of
uncertainty about the Y2K Issue. The Company believes that the completion of the
Project, as scheduled, minimizes the possibility of significant interruptions of
normal operations.
On July 17, 1998, an order was entered by the PUC instituting a formal
investigation by the Office of Administrative Law on Year 2000 compliance by
jurisdictional fixed utilities and mission-critical service providers such as
the PJM (the Investigation). The order requires, (1) a written response to a
list of compliance program questions by August 6, 1998 and, (2) all
jurisdictional fixed utilities be Year 2000 compliant by March 31, 1999 or, if a
utility determines that mission-critical systems cannot be Year 2000 compliant
on or before March 31, 1999, the utility is required to file a detailed
contingency plan. The PUC adopted the federal government's definition for Year
2000 compliance and further defined Year 2000 compliance as a jurisdictional
22
<PAGE>
utility having all mission-critical Year 2000 hardware and software updates
and/or replacements installed and tested on or before March 31, 1999. On August
6, 1998, the Company filed its written response, in which the Company stated
that with a few carefully-assessed and closely-managed exceptions, the Company
will have all mission-critical systems Year 2000 ready by June 1999. Pursuant to
the formal investigation on Year 2000 compliance, the Company presented
testimony before the PUC on November 20, 1998.
On February 19, 1999, the PUC issued a Secretarial Letter notifying the
Company that it had hired a consultant to perform an assessment of the Company
and thirteen other utilities to evaluate the accuracy of their responses to the
compliance program questions and testimony provided before the PUC. The Company
complied with the PUC's directive in the Secretarial Letter to file updated
written responses to compliance questions by March 8, 1999, and to meet with the
consultant during a one-day on-site review session on March 8, 1999. On March
31, 1999, the Company filed contingency plans with the PUC for its
mission-critical systems scheduled to be ready after the March 31, 1999
deadline.
On April 8, 1999, the PUC issued an order requiring the Office of
Administrative Law Judge to identify (i) utilities which have complied with the
PUC's order of July 17, 1998 (the Order); (ii) utilities which have demonstrated
good cause for an extension of time within which they will fully comply with the
Order; and (iii) those utilities which have not complied with the Order and have
not shown good cause for an extension. The PUC required that this information be
posted to the PUC internet website and periodically updated. The PUC further
ordered that the Investigation with respect to utilities who have demonstrated
good cause for an extension of time remain open and under the jurisdiction of
the Office of Administrative Law Judge until compliance is achieved or
enforcement is warranted. PECO Energy has been identified by the PUC as a
utility which has demonstrated good cause for an extension of time within which
it will fully comply with the Order. Additional reporting dates to the
Administrative Law Judge include July 1, 1999 and October 1, 1999.
On May 11, 1998, the NRC issued a generic letter requiring all nuclear
plant operators to provide the NRC with the following information concerning the
operators' programs, planned or implemented, to address Year 2000 computer and
system issues at its facilities: (1) submission of a written response within 90
days, indicating whether the operator has pursued and continues to pursue
implementation of Year 2000 programs and addressing the program's scope,
assessment process, plans for corrective actions, quality assurance measures,
contingency plans and regulatory compliance, and (2) submission of a written
response, no later than July 1, 1999, confirming that such facilities are Year
2000 ready, or will be Year 2000 ready, by the year 2000 with regard to
compliance with the terms and conditions of the license(s) and NRC regulations.
On July 30, 1998, the Company filed its 90-day required written response
indicating that the Company has pursued and is continuing to pursue a Year 2000
program which is similar to that outlined in Nuclear Utility Year 2000
Readiness, NEI/NUSMG 97.07.
From November 3 to November 5, 1998, members of the NRC staff conducted
an audit of the Company's Year 2000 Program for the Limerick Generating Station,
Units No. 1 and No. 2. Some of the observations of the audit team included in
their written report issued on December 18, 1998, were that (1) the Company's
readiness program is comprehensive and based on the guidance contained in
23
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NEI/NUSMG 97.07, (2) the program is receiving proper management support and
oversight, and (3) project schedules are being aggressively pursued.
On April 28, 1999, the NRC issued Information Notice 99-12 advising
nuclear power plant licensees that NRC staff would be conducting additional Year
2000 readiness and contingency planning site-specific reviews at all commercial
nuclear power plants. The NRC performed its site-specific review of Peach Bottom
from May 24 to May 28, 1999, and its review of Limerick from June 7 to June 10,
1999.
On June 30, 1999, PECO Energy filed its completed response to Generic
Letter 98-01. In the response, PECO Energy confirmed that with the exception of
five non-safety plant systems, its Peach Bottom Atomic Power Station and
Limerick Generating Stations are Year 2000 ready. The Company advised the NRC
that remediation for three of the remaining systems is scheduled for completion
by September 30, 1999, and remediation for the other two systems is scheduled to
occur during planned plant outages in September 1999.
For additional information regarding the Year 2000 Readiness Disclosure
see "Management's Discussion and Analysis of Financial Condition and Results of
Operations" in the Company's Annual Report to Shareholders for the year 1998.
FORWARD-LOOKING STATEMENTS
Except for the historical information contained herein, certain of the
matters discussed in this Report are forward-looking statements, including the
estimated earnings per share benefits of the application of the Transition Bond
proceeds for 1999 and 2000, and accordingly, are subject to risks and
uncertainties. The factors that could cause actual results to differ materially
include those discussed herein as well as those listed in notes 2, 8 and 9 of
Notes to Condensed Consolidated Financial Statements and other factors discussed
in the Company's filings with the SEC. Readers are cautioned not to place undue
reliance on these forward-looking statements, which speak only as of the date of
this Report. The Company undertakes no obligation to publicly release any
revision to these forward-looking statements to reflect events or circumstances
after the date of this Report.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
The Company has entered into interest rate swaps to manage interest
rate exposure associated with the issuance of two floating rate series of
Transition Bonds. At June 30, 1999, the fair value of these instruments was $52
million based on the present value difference between the contracted rate (i.e.,
hedged rate) and the market rates at that date. A hypothetical 50 basis point
increase or decrease in the spot yield at June 30, 1999 would have resulted in
an aggregate fair value of these interest rate swaps of $91.2 million or $10.7
million, respectively. If the derivative instruments had been terminated at June
30, 1999, these estimated fair values represent the amount to be paid by the
counterparties to the Company.
24
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The Company's growing market share in the retail and wholesale electric
marketplace increases the Company's reliance on the efficient operation of its
generating units. The Company's ability to fully capitalize on volatile
wholesale market prices is also dependent on the performance of the Company's
generating units.
25
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PART II - OTHER INFORMATION
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Information regarding the submission of matters to a vote of security
holders is presented in the March 31, 1999 Form 10-Q.
ITEM 5. OTHER INFORMATION
As previously reported in the 1998 Form 10-K, the NRC issued a
confirmatory order modifying the license for Limerick Generating Station
(Limerick) Units No. 1 and No. 2 requiring that the Company complete final
implementation of corrective actions on the Thermo-Lag 330 issue by completion
of the April 1999 refueling outage of Limerick Unit No. 2. By letter dated May
3, 1999, the NRC approved the Company's request to extend the completion of
Thermo-lag corrective actions at Limerick until September 30, 1999.
As previously reported in the 1998 Form 10-K, in October 1990, General
Electric Company (GE) reported that crack indications were discovered near the
seam welds of the core shroud assembly in a GE Boiling Water Reactor (BWR)
located outside the United States. As a result, GE issued a letter requesting
that the owners of GE BWRs take interim corrective actions, including a review
of fabrication records and visual examinations of accessible areas of the core
shroud seam welds. Each of the reactors at Limerick and Peach Bottom is a GE
BWR. In accordance with industry experience and guidance, initial examination of
Limerick Unit No. 2 was completed during the April 1999 refueling outage.
Although crack indications were identified, the results of the inspections and
evaluations conclude that the condition of the Limerick Unit No. 2 core shroud,
projected through at least the next operating cycle, will support the required
safety margins, specified in the ASME code and reinforced by industry
recommendations.
As previously reported in the 1998 Form 10-K, as a result of several
BWRs experiencing clogging of some emergency core cooling system suction
strainers, which are part of the water supply system for emergency cooling of
the reactor core, the NRC issued a Bulletin in May 1996 to operators of BWRs
requesting that measures be taken to minimize the potential for clogging. The
NRC proposed three resolution options, including the installation of large
capacity passive strainers, with a request that actions be completed by the end
of the unit's first refueling outage after January 1997. Strainers were
installed at Peach Bottom Unit No. 3 during the October 1997 refueling outage.
Strainers were installed at Peach Bottom Unit No. 2 and Limerick Unit No. 1
during their refueling outages in October 1998 and April 1998, respectively.
Strainers were installed at Limerick Unit No. 2 during the April 1999 refueling
outage. The Company cannot predict what other actions, if any, the NRC may take
in this matter.
On June 22, 1999, Pennsylvania Governor Tom Ridge signed into law the
Natural Gas Choice and Competition Act ("Act") which expands choice of gas
suppliers to residential and small commercial customers and eliminates the five
percent gross receipts tax on gas distribution companies' sales of gas. Large
commercial and industrial customers have been able to choose their suppliers
since 1984. Currently, approximately one-third of the Company's total yearly
throughput is supplied by third parties.
26
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The Act permits gas distribution companies to continue to make
regulated sales of gas to their customers. The Act does not deregulate the
transportation service provided by gas distribution companies which remains
subject to rate regulation. Gas distribution companies will continue to provide
billing, metering, installation, maintenance and emergency response services.
In compliance with the schedule ordered by the Public Utility
Commission ("PUC"), the Company must file with the PUC by December 2, 1999 a
restructuring plan for the implementation of gas deregulation and customer
choice of gas service suppliers in its service territory (Restructuring Plan).
The Company expects gas to flow on its system pursuant to customer choice on
July 1, 2000. The Company is currently analyzing the impact of the Act on its
operations. The Company believes the impact on the Company would not be material
because of the PUC's existing requirement that gas distribution companies cannot
collect more than the actual cost of gas from customers, and the Act's
requirement that suppliers must accept assignment or release, at contract rates,
the portion of the gas distribution company's firm interstate pipeline contracts
required to serve the suppliers' customers.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits:
27 - Financial Data Schedule.
(b) Reports on Form 8-K filed during the reporting period:
Report, dated April 15, 1999 reporting information under "ITEM 5.
OTHER EVENTS" regarding AmerGen Energy Company, LLC, the joint
venture between the Company and British Energy, Inc., signing
an interim agreement to purchase the Clinton Nuclear Power
Station from Illinois Power (IP), a subsidiary of Illinova
Corporation.
Report, dated June 24, 1999 reporting information under "ITEM 5. OTHER
EVENTS" regarding AmerGen's signing a definitive agreement to
purchase the Nine Mile Point Unit 1 Nuclear Generating
Facility from Niagara Mohawk Power Corporation (NIMO), a
subsidiary of Niagara Mohawk Holdings, Inc. AmerGen has also
entered into an agreement to purchase NIMO's 41% ownership
interest in Nine Mile Point Unit 2 Nuclear Generating Facility
(NMP-2) and New York State Electric and Gas Corp.'s (NYSEG)
18% interest in NMP-2. NYSEG is a wholly owned subsidiary of
Energy East, Inc.
Reports on Form 8-K filed subsequent to the reporting period:
Report, dated July 1, 1999 reporting information under "ITEM 5. OTHER
EVENTS" regarding AmerGen's signing a definitive asset
purchase agreement to purchase Clinton.
27
<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: August 13, 1999
28
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