UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended...September 30, 1998..........
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from.........to...................
Commission file number..................1-1401...................
.......................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 224,045,506 shares of common stock outstanding on
September 30, 1998.
<PAGE>
<TABLE>
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
(Millions of Dollars)
<CAPTION>
3 Months Ended 9 Months Ended
September 30, September 30,
----------------------- ----------------------
1998 1997 1998 1997
--------- ---------- --------- ---------
OPERATING REVENUES
<S> <C> <C> <C> <C>
Electric $1,731.0 $1,232.2 $3,858.8 $3,146.1
Gas 42.9 46.0 295.7 327.8
--------- ---------- --------- ---------
TOTAL OPERATING REVENUES 1,773.9 1,278.2 4,154.5 3,473.9
--------- ---------- --------- ---------
OPERATING EXPENSES
Fuel and Energy Interchange 726.0 354.1 1,446.6 954.2
Operating and Maintenance 296.1 313.8 840.2 912.0
Depreciation and Amortization 153.2 143.5 468.8 433.6
Taxes Other Than Income Taxes 52.3 78.7 206.2 234.3
--------- ---------- --------- ---------
TOTAL OPERATING EXPENSES 1,227.6 890.1 2,961.8 2,534.1
--------- ---------- --------- ---------
OPERATING INCOME 546.3 388.1 1,192.7 939.8
--------- ---------- --------- ---------
OTHER INCOME AND DEDUCTIONS
Interest Expense (83.1) (93.2) (259.1) (279.3)
Company Obligated Mandatorily Redeemable
Preferred Securities of a Partnership (7.5) (7.7) (23.3) (21.3)
Allowance for Funds Used During Construction 2.1 4.0 8.4 18.4
Settlement of Salem Litigation - - - 69.8
Other, Net (9.5) (5.2) (42.2) (14.3)
--------- ---------- --------- ---------
TOTAL OTHER INCOME AND DEDUCTIONS (98.0) (102.1) (316.2) (226.7)
--------- ---------- --------- ---------
INCOME BEFORE INCOME TAXES 448.3 286.0 876.5 713.1
--------- ---------- --------- ---------
INCOME TAXES 174.6 128.0 337.7 319.3
--------- ---------- --------- ---------
NET INCOME 273.7 158.0 538.8 393.8
PREFERRED STOCK DIVIDENDS 3.2 4.5 9.8 13.5
--------- ---------- --------- ---------
EARNINGS APPLICABLE TO COMMON STOCK $ 270.5 $ 153.5 $ 529.0 $ 380.3
========= ========== ========= =========
AVERAGE SHARES OF COMMON STOCK
OUTSTANDING (Millions) 223.1 222.5 222.8 222.5
BASIC EARNINGS PER AVERAGE COMMON SHARE (Dollars) $ 1.21 $ 0.69 $ 2.37 $ 1.71
DILUTED EARNINGS PER AVERAGE COMMON SHARE (Dollars) $ 1.20 $ 0.69 $ 2.36 $ 1.71
DIVIDENDS PER AVERAGE COMMON SHARE (Dollars) $ 0.25 $ 0.45 $ 0.75 $ 1.35
<FN>
See Notes to Condensed Consolidated Financial Statements.
</FN>
</TABLE>
<PAGE>
<TABLE>
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Millions of Dollars)
<CAPTION>
September 30, December 31,
1998 1997
------------ ------------
(Unaudited)
ASSETS
UTILITY PLANT
<S> <C> <C>
Electric - Transmission & Distribution $ 3,682.5 $ 3,617.7
Electric - Generation 1,479.4 1,434.9
Gas 1,099.6 1,071.8
Common 322.1 302.7
---------- ----------
6,583.6 6,427.1
Less Accumulated Provision for Depreciation 2,833.6 2,690.8
---------- ----------
3,750.0 3,736.3
Nuclear Fuel, net 149.0 147.4
Construction Work in Progress 702.4 611.2
Leased Property, net 163.6 175.9
---------- ----------
4,765.0 4,670.8
---------- ----------
CURRENT ASSETS
Cash and Temporary Cash Investments 43.9 33.4
Accounts Receivable, net
Customer 233.1 173.3
Other 234.3 140.0
Inventories, at average cost
Fossil Fuel 87.5 84.9
Materials and Supplies 84.1 90.9
Deferred Generation Costs Recoverable in Current Rates 104.3 424.5
Deferred Energy Costs - Gas 18.0 35.7
Other 72.5 20.1
---------- ----------
877.7 1,002.8
---------- ----------
DEFERRED DEBITS AND OTHER ASSETS
Competitive Transition Charge 5,274.6 5,274.6
Recoverable Deferred Income Taxes 614.2 590.3
Deferred Non-Pension Postretirement Benefits Costs 92.5 97.4
Investments 512.0 515.8
Loss on Reacquired Debt 78.8 83.9
Other 133.2 121.0
---------- ----------
6,705.3 6,683.0
---------- ----------
TOTAL $ 12,348.0 $ 12,356.6
========== ==========
<FN>
See Notes to Condensed Consolidated Financial Statements.
</FN>
(continued on next page)
</TABLE>
<PAGE>
<TABLE>
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Millions of Dollars)
(continued)
<CAPTION>
September 30, December 31,
1998 1997
------------ ------------
(Unaudited)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION
Common Shareholders' Equity
<S> <C> <C>
Common Stock (No Par) $ 3,564.1 $ 3,517.7
Other Paid-In Capital 1.2 1.2
Retained Deficit (444.9) (792.2)
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 349.4 352.1
Long-Term Debt 3,589.9 3,853.1
---------- ----------
7,289.9 7,162.1
---------- ----------
CURRENT LIABILITIES
Notes Payable, Bank 116.0 401.5
Long-Term Debt Due Within One Year 256.4 247.1
Capital Lease Obligations Due Within One Year 70.9 55.8
Accounts Payable 288.1 306.9
Taxes Accrued 276.6 66.4
Interest Accrued 80.5 77.9
Dividends Payable 20.2 17.0
Deferred Income Taxes 42.9 185.7
Other 220.1 260.4
---------- ----------
1,371.7 1,618.7
---------- ----------
DEFERRED CREDITS AND OTHER LIABILITIES
Capital Lease Obligations 92.7 120.1
Deferred Income Taxes 2,393.9 2,297.1
Unamortized Investment Tax Credits 304.5 318.1
Pension Obligation 211.6 211.6
Non-Pension Postretirement Benefits Obligation 342.7 324.8
Other 341.0 304.1
---------- ----------
3,686.4 3,575.8
---------- ----------
COMMITMENTS AND CONTINGENCIES (NOTE 7)
TOTAL $ 12,348.0 $ 12,356.6
========== ==========
<FN>
See Notes to Condensed Consolidated Financial Statements.
</FN>
</TABLE>
<PAGE>
<TABLE>
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(Millions of Dollars)
<CAPTION>
9 Months Ended
September 30,
---------------------------------
1998 1997
---------- ----------
CASH FLOWS FROM OPERATING ACTIVITIES
<S> <C> <C>
NET INCOME $ 538.8 $ 393.8
Adjustments to Reconcile Net Income to Net Cash
Provided by Operating Activities:
Depreciation and Amortization 514.2 494.4
Deferred Income Taxes (69.4) (1.0)
Deferred Energy Costs 17.7 12.9
Salem Litigation Settlement - (69.8)
Changes in Working Capital:
Accounts Receivable (154.1) (30.3)
Inventories 4.2 11.7
Accounts Payable (18.8) 4.0
Other Current Assets and Liabilities 120.1 34.1
Other Items Affecting Operations 96.4 42.0
---------- ---------
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES 1,049.1 891.8
---------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES
Investment in Plant (316.9) (362.1)
Other Investments (40.0) (104.1)
---------- ----------
NET CASH FLOWS USED BY INVESTING ACTIVITIES (356.9) (466.2)
---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES
Change in Short-Term Debt (285.5) (130.0)
Issuance of Common Stock 46.4 -
Issuance of Long-Term Debt 9.8 17.2
Retirement of Long-Term Debt (265.8) (33.3)
Loss on Reacquired Debt 5.1 17.5
Issuance of Company Obligated Mandatorily
Redeemable Preferred Securities of a Partnership 78.1 50.0
Retirement of Company Obligated Mandatorily
Redeemable Preferred Securities of a Partnership (80.9) -
Dividends on Preferred and Common Stock (176.9) (314.0)
Change in Dividends Payable 3.2 5.3
Other Items Affecting Financing (15.2) 0.2
---------- ----------
NET CASH FLOWS USED BY FINANCING ACTIVITIES (681.7) (387.1)
---------- ----------
INCREASE IN CASH AND CASH EQUIVALENTS 10.5 38.5
---------- ----------
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 33.4 29.2
---------- ----------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 43.9 $ 67.7
========== ==========
<FN>
See Notes to Condensed Consolidated Financial Statements.
</FN>
</TABLE>
<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
September 30, 1998 and for the three and nine months then ended are unaudited,
but include all adjustments that PECO Energy Company (Company) considers
necessary for a fair presentation of such financial statements. All adjustments
are of a normal, recurring nature. The year-end condensed consolidated balance
sheet data were derived from audited financial statements but do not include all
disclosures required by generally accepted accounting principles. Certain
prior-year amounts have been reclassified for comparative purposes. These notes
should be read in conjunction with the Notes to Consolidated Financial
Statements in the Company's 1997 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, 1997 (1997 Form 10-K).
2. RATE MATTERS
On May 14, 1998, the Pennsylvania Public Utility Commission (PUC)
issued a final order (Final Restructuring Order) approving a Joint Petition for
Settlement (Global Settlement) filed by the Company and numerous parties to the
Company's restructuring proceeding. The Final Restructuring Order concludes the
Company's restructuring proceeding filed on April 1, 1997, pursuant to the
Electricity Generation Competition and Customer Choice Act (Competition Act).
The Final Restructuring Order provides for the recovery of $5.26 billion of
stranded costs over a 12-year period beginning in 1999 with a 10.75% return on
the stranded cost balance.
The Final Restructuring Order provides for the phase-in of customer
choice of electric generation suppliers (EGS) for all customers: one-third of
the peak load of each customer class on January 1, 1999; one-third on January 2,
1999 and the remainder on January 2, 2000. The order also establishes market
share thresholds to ensure that a minimum number of residential and commercial
customers choose an EGS. If less than 35% and 50% of residential and commercial
customers have chosen an EGS by January 1, 2001 and January 1, 2003,
respectively, then a number of customers sufficient to meet the necessary
threshold levels shall be randomly selected and assigned to an EGS through a
PUC-determined process.
Beginning January 1, 1999, electric rates will be unbundled into a
transmission and distribution component, a "transition charge" for recovery of
stranded costs and an energy and capacity charge. Eligible customers who choose
an EGS will not be charged the energy and capacity charge or the transmission
charge and instead will purchase their electric energy supply and transmission
at market-based rates from their EGS. Also, beginning January 1, 1999, the
Company will unbundle its retail electric rates for metering, meter reading and
billing and collection services to provide credits to those customers who elect
to have an alternative supplier perform these services.
In accordance with the Competition Act and the Final Restructuring
Order, all customers' kilowatthour (kWh) rates are capped at the year-end 1996
levels (system-wide average of 9.96 cents/kWh) through June 2005. The rate caps
are further adjusted by the following rate reductions. On January 1, 1999, the
Company will reduce its retail electric rates by 8% from the 1996 system-wide
average rate. The rate decrease will become 6% from January 1, 2000 until
January 1, 2001, when the system-wide average rate cap will revert to 9.96
cents/kWh. The transmission and distribution rate component will remain capped
at a system average rate of 2.98 cents/kWh through June 30, 2005. Additionally,
generation rate caps, defined as the sum of the applicable transition charge and
shopping credit, will remain in effect through 2010.
<PAGE>
The Final Restructuring Order requires that on January 1, 2001, 20% of
all of the Company's residential customers, determined by random selection and
without regard to whether such customers are obtaining generation service from
an EGS, shall be assigned to a provider of last resort default supplier other
than the Company through a PUC-approved bidding process.
The Final Restructuring Order authorizes the Company to securitize up
to $4 billion of its recoverable stranded costs through the issuance of
transition bonds. The proceeds of the transition bonds are required to be used
principally to reduce qualified stranded costs and related capitalization.
As previously reported in the 1997 Form 10-K, the Company filed
complaints in federal and state courts relating to the restructuring orders
issued by the PUC in December 1997, January 1998 and February 1998 (Original
Restructuring Orders). In addition, numerous other parties filed appeals and
cross appeals of the Original Restructuring Orders. In accordance with the terms
of the Final Restructuring Order, all appeals and cross-appeals filed by the
signatories to the Global Settlement have been placed in a pending but inactive
status. Such appeals and cross appeals will be permanently withdrawn at such
time that the Final Restructuring Order is no longer subject to administrative
or judicial challenge.
An intervenor brought an action asserting that the Competition Act
violated the Commerce Clause of the United States Constitution. On May 7, 1998,
the Commonwealth Court of Pennsylvania (Commonwealth Court) unanimously rejected
the claim. The intervenor petitioned the Supreme Court of Pennsylvania for
allowance of appeal. On September 29, 1998, the Pennsylvania Supreme Court
denied the petition. The intervenor has until December 28, 1998 to file a
petition for certiorari with the United States Supreme Court.
Two original jurisdiction actions were filed in the Commonwealth Court
claiming that the manner in which the Competition Act was passed by the
Pennsylvania legislature violated the Pennsylvania Constitution. On September
24, 1998, those claims were rejected by the Commonwealth Court. On October 26,
1998, the appeal period for those cases expired without any party filing an
appeal to the Pennsylvania Supreme Court.
3. RESTART OF SALEM GENERATING STATION (SALEM) Public Service Electric and
Gas Company (PSE&G), the operator of Salem Units No. 1 and No. 2, which are
42.59% owned by the Company, removed the units from service in the second
quarter of 1995. Unit No. 2 returned to commercial operation in the third
quarter of 1997 and Unit No. 1 returned to commercial operation on April 17,
1998. The following table summarizes replacement power costs recorded in the
accompanying Statements of Income as Fuel and Energy Interchange and Operating
and Maintenance costs relating to the shutdown of Salem:
Three Months Ended Nine Months Ended
September 30, September 30,
1998 1997 1998 1997
----- ----- ----- -----
Recorded on Accompanying
Statements of Income (millions)
Fuel and Energy Interchange $ - $ 27 $ 19 $ 84
Operating and Maintenance 2 12 13 38
----- ----- ----- -----
Total $ 2 $ 39 $ 32 $ 122
For the year ending December 31, 1998, the Company expects to incur and
expense approximately $35 million of costs related to the shutdown.
<PAGE>
4. 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 $425 million of designated accounts receivable until
November 2000. At September 30, 1998, the Company had sold a $425 million
interest in accounts receivable, consisting of a $311 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 $114
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 $425 million interest, which, if not met, requires the Company to
deposit cash in order to satisfy such requirements. The Company, at September
30, 1998, met such requirements. At September 30, 1998, the average annual
service-charge rate, computed on a daily basis on the portion of the accounts
receivable sold but not yet collected, was 5.6%.
5. STOCK REPURCHASE
During 1997, the Company's Board of Directors authorized the repurchase
of up to 25 million shares of its common stock from time to time through
open-market, privately negotiated and/or other types of transactions in
conformity with the rules of the SEC.
Pursuant to these authorizations, the Company has entered into forward
purchase agreements to be settled from time to time, at the Company's election,
on either a physical, net share or net cash basis. The amount at which these
agreements can be settled is dependent principally upon the market price of the
Company's common stock as compared to the forward purchase price per share and
the number of shares to be settled. If these agreements had been settled on a
net share basis at September 30, 1998, based on the closing price of the
Company's common stock on that date, the Company would have received
approximately 3,624,000 shares of Company common stock.
6. 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
Long-Term Incentive Plan (LTIP), considered to be dilutive common stock
equivalents. The following table shows the effect of the stock options issuable
under the Company's LTIP on the average number of shares used in calculating
diluted earnings per average common share:
Three Months Ended Nine Months Ended
September 30, September 30,
Description (Millions of shares) 1998 1997 1998 1997
- -------------------------------- ----- ----- ----- -----
Average Common Shares Outstanding 223.1 222.5 222.8 222.5
Assumed Conversion of Stock Options 1.9 0.1 1.7 0.1
----- ----- ----- -----
Potential Average Dilutive
Common Shares Outstanding 225.0 222.6 224.5 222.6
7. 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, 1997.
<PAGE>
The Company has identified 28 sites where former manufactured gas plant
(MGP) activities have or may have resulted in actual site contamination. As of
September 30, 1998, the Company had accrued $61 million for environmental
investigation and remediation costs, including $34 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 October 15, 1998, AmerGen Energy Company, LLC (AmerGen), the joint
venture between the Company and British Energy plc, signed a definitive asset
purchase agreement with GPU, Inc. to purchase Three Mile Island Nuclear
Generating Station Unit No. 1. In connection with the execution of the asset
purchase agreement, the Company and British Energy plc each agreed to make their
share of capital contributions to AmerGen in order to enable AmerGen to make the
payment required at closing and, if necessary, any additional payments required
under the asset purchase agreement.
The Company periodically reviews its investments to determine whether
they are properly valued in its financial statements.
8. ACCOUNTING MATTERS
In June 1998, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative
Instruments and Hedging Activities," 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 is 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.
<PAGE>
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
GENERAL
The Electricity Generation Customer Choice and Competition Act
(Competition Act) was enacted in December 1996 providing for the restructuring
of the electric utility industry in Pennsylvania, including the deregulation of
utility generation operations and the institution of retail competition for
generation supply beginning in 1999. Pursuant to the Competition Act, in April
1997, the Company filed with the Pennsylvania Public Utility Commission (PUC) a
restructuring plan in which it identified $7.5 billion of retail electric
generation-related stranded costs. In May 1998, the PUC entered an Opinion and
Order (Final Restructuring Order) which deregulates the Company's electric
generation operations and authorizes the Company to recover stranded costs of
$5.26 billion over 12 years beginning January 1, 1999. Additionally, the Final
Restructuring Order provides for the phase-in of customer choice between January
1, 1999 and January 2, 2000. Following completion of the phase-in, all of the
Company's customers will have the ability to choose their electric generation
supplier. For additional information concerning the Competition Act and Final
Restructuring Order, see "Management's Discussion and Analysis of Financial
Condition and Results of Operations" in the Company's Annual Report to
Shareholders for the year 1997; the Company's Annual Report on Form 10-K for the
year ended December 31, 1997 (1997 Form 10-K) under "PART I. ITEM 1.
BUSINESS-Deregulation and Rate Matters"; "PART II. ITEM 5. OTHER INFORMATION" of
the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 1998
(March 31, 1998 Form 10-Q); "PART II. ITEM 5. OTHER INFORMATION" of the
Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1998
(June 30, 1998 Form 10-Q); and under "PART II. ITEM 5. OTHER INFORMATION" in
this Quarterly Report on Form 10-Q (Report).
The rate reductions of the Final Restructuring Order (8% in 1999 and
reduced to 6% in 2000) are expected to reduce the Company's revenues from future
retail electric sales. The Company believes that its revenues from retail
electric sales will be further reduced by competition for electric generation
services, which will be available to two-thirds of its retail customers by
January 2, 1999 and all retail customers by January 2, 2000.
In light of the expected impact on future revenues of the Final
Restructuring Order and competition for electric generation services, the
Company is continuing its cost management efforts through a Competitive Cost
Review (CCR). Through CCR, the Company is continuing to conduct an in-depth
analysis and assessment of all Company expenses, capital expenditures, programs,
processes and staffing levels. The goal of CCR is to achieve significant cost
savings while maintaining high levels of service quality, reliability, safety
and overall performance.
In accordance with the cost-control targets of CCR, the Company is
committed to reducing annual operating and maintenance expense by at least $150
million by 2001. The expense reductions will be realized, in part, through the
elimination of approximately 1,200 positions in 1998 and 1999.
In April 1998, the Board of Directors authorized the implementation of
a retirement incentive program and an enhanced severance benefit program to
accompany targeted workforce reductions. The retirement incentive program allows
employees age 50 and older, who have been designated as excess or who are in job
classifications facing reduction, to retire from the Company. The enhanced
severance benefit program provides non-retiring excess employees with fewer than
ten years of service, benefits equal to two weeks pay per year of service.
Non-retiring excess employees with more than ten years of service receive
benefits equal to three weeks pay per year of service.
The Company anticipates that it will incur a one-time charge to
earnings in the fourth quarter of 1998 to recognize costs related to CCR;
however, the magnitude of such charge is not known at this time.
<PAGE>
The Company's future financial condition and results of operations are
also affected by other factors, such as the operation of nuclear generating
facilities, wholesale sales and purchases, weather conditions and the Company's
ability to develop its investments in new ventures into profitable enterprises.
In June 1998, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative
Instruments and Hedging Activities," 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 is 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.
RESULTS OF OPERATIONS
EARNINGS
Basic earnings per average common share for the three and nine months
ended September 30, 1998 were $1.21 and $2.37 per share, respectively, compared
to $0.69 and $1.71 per share in 1997. Diluted earnings per share for the three
and nine months ended September 30, 1998 were $1.20 and $2.36 per share,
respectively, compared to $0.69 and $1.71 per share in 1997.
The increase in third quarter earnings was due primarily to increased
operating revenues net of related fuel costs. Third quarter 1998 earnings also
benefited from the return to service of Salem Generating Station (Salem),
continued reduction of operating and maintenance costs, reduction of
uncollectible expenses and a one-time refund of gross receipts tax. These
factors were partially offset by higher losses from investments in subsidiaries.
Income tax expense increased due to higher earnings but was partially offset due
to full normalization of deferred taxes associated with deregulated generation
plant.
The increase in earnings for the nine months ended September 30, 1998
was primarily due to increased operating revenues net of related fuel costs, the
return to service of Salem, continued reduction of operating and maintenance
costs and a one-time refund of gross receipts tax. These factors were partially
offset by the benefit in 1997 of the recognition of the Salem litigation
settlement and, in 1998, by higher losses from investments in subsidiaries.
Income tax expense increased due to higher earnings but was partially offset due
to full normalization of deferred taxes associated with deregulated generation
plant.
OPERATING REVENUES
Electric revenues increased 40% and 23% for the three and nine months
ended September 30, 1998, respectively, compared to 1997. The increase for the
three months was primarily due to higher revenues from wholesale sales resulting
from an increase in energy prices in the spot market as well as an increase in
sales volume. Also contributing to the increase was higher revenues from retail
sales due to an increase in sales volume resulting from warmer weather
conditions. Partially offsetting these increases were lower average retail rates
as a result of the customer choice pilot program.
The increase in electric revenues for the nine months ended September
30, 1998 was primarily due to an increase from wholesale sales resulting from an
increase in energy prices in the spot market as well as an increase in sales
volume and an increase in retail sales resulting from warmer weather conditions.
Partially offsetting the increase were lower average retail rates as a result of
the customer choice pilot program.
<PAGE>
Gas revenues decreased 7% and 10% for the three and nine months ended
September 30, 1998 compared to 1997. The decrease for the three months was
primarily due to a decrease in gas transported for customers. The decrease for
the nine months was primarily due to milder weather conditions in the first
quarter as well a decrease in gas transported for customers.
FUEL AND ENERGY INTERCHANGE
Fuel and energy interchange expense increased 105% and 52% for the
three and nine months ended September 30, 1998 compared to 1997. The increase in
fuel and energy interchange was primarily due to an increase in the average
price paid by the Company for purchased power and additional power purchases
associated with increased wholesale electric sales. The increase was partially
offset by the return to service of Salem, which decreased the need to purchase
power to replace the output from these units.
OPERATING AND MAINTENANCE
Operating and maintenance expense decreased 6% and 8% for the three and
nine months ended September 30, 1998 compared to 1997. The decrease for the
three and nine months was primarily due to lower expenses at Salem due to the
conclusion of the outage, reduced uncollectible expenses and lower expenses at
nuclear- and fossil- fueled generating units and distribution system costs.
DEPRECIATION EXPENSE
Depreciation expense increased 7% and 8% for the three and nine months
ended September 30, 1998 compared to 1997, primarily due to the amortization of
Deferred Generation Costs Recoverable in Current Rates during 1998, preceding
the Company's transition to market-based pricing of electric generation in 1999.
Included in this amortization were charges that were included in Operating and
Maintenance expense and Interest Charges in 1997.
OTHER INCOME AND DEDUCTIONS
Other income and deductions excluding interest charges decreased
substantially for the three and nine months ended September 30, 1998 compared to
1997. The decrease for the three months was primarily due to increased losses
from investments in subsidiaries. The decrease for the nine months was primarily
due to the second quarter 1997 settlement reached with Public Service Electric
and Gas Company (PSE&G) related to the shutdown of Salem and, in 1998, increased
losses from investments in subsidiaries and the second quarter write-off of the
Company's investment in EnergyOne.
INTEREST CHARGES
Interest charges decreased 9% and 3% for the three and nine months
ended September 30, 1998 compared to 1997. Interest charges decreased for the
three months primarily due to the Company's ongoing program to reduce and/or
refinance higher cost, long-term debt and the write-off of electric generation
related debt discounts at December 31, 1997. These decreases were partially
offset by lower AFUDC caused by fewer projects in AFUDC base in 1998 and the
replacement of $62 million of preferred stock with Company Obligated Mandatorily
Redeemable Preferred Securities of a Partnership (COMRPS) in the third quarter
of 1997.
INCOME TAXES
Total income taxes increased 36% and 6% for the three and nine months
ended September 30, 1998 compared to 1997. The increase for the three and nine
months was primarily due to higher earnings but was partially offset due to full
normalization of deferred taxes associated with deregulated generation plant.
PREFERRED STOCK DIVIDENDS
Preferred stock dividends decreased 29% and 27% for the three and nine
months ended September 30, 1998 compared to 1997, primarily due to the
replacement of $62 million of preferred stock with COMRPS in the third quarter
of 1997.
<PAGE>
DISCUSSION OF LIQUIDITY AND CAPITAL RESOURCES
Total construction expenditures, primarily for utility plant, are
estimated to be $600 million for 1998. The estimated expenditures include
approximately $150 million for new ventures, principally through the
Telecommunications Group. Due to the expected impact of the Final Restructuring
Order and competition for electric generating services on its future capital
resources, the Company is currently evaluating its capital commitments for 1999
and beyond. Certain facilities under construction and to be constructed may
require permits and licenses which the Company has no assurance will be granted.
On October 16, 1998, Duff & Phelps Credit Rating Company upgraded its
ratings on the Company's 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-", and commercial paper
to "D-1" from "D-2".
At September 30, 1998, the Company had outstanding $116 million of
notes payable, all of which were commercial paper. At September 30, 1998, the
Company had formal and informal lines of bank credit aggregating $100 million.
At September 30, 1998, the Company had no short-term investments.
As a result of an extraordinary charge to earnings in December 1997,
the Company did not meet the earnings test under the Mortgage required for the
issuance of additional bonds against property additions for the twelve months
ended September 30, 1998. In addition, the Company does not expect to meet the
earnings test under the Mortgage for any twelve-month period ending prior to
December 31, 1998. At September 30, 1998, the Company was entitled to issue
approximately $3.9 billion of mortgage bonds against previously retired mortgage
bonds without regard to the earnings and property additions tests.
As a result of an extraordinary charge to earnings in December 1997,
the Company did not meet the earnings test of the Company's Amended and Restated
Articles of Incorporation (Articles), required for the issuance of additional
preferred stock without an affirmative vote of the holders of two-thirds of all
preferred shares outstanding, for the twelve months ended September 30, 1998. In
addition, the Company does not expect to meet the earnings test under the
Articles for any twelve-month period ending prior to December 31, 1998.
For the nine months ended September 30, 1998, the Company's Ratio of
Earnings to Fixed Charges (SEC Method) (Exhibit 12-1) and Ratio of Earnings to
Combined Fixed Charges and Preferred Stock Dividends (SEC Method) (Exhibit 12-2)
were 4.43 times and 4.17 times, respectively, compared to 3.58 times and 3.29
times, respectively, in 1997. See the 1997 Form 10-K under "PART I. ITEM 1.
BUSINESS-Capital Requirements and Financing Activities," for a discussion of the
ratio methods.
As previously disclosed, the Company's Board of Directors authorized
the repurchase of up to 25 million shares of its common stock from time to time
through open market, privately negotiated and/or other types of transactions in
conformity with the rules of the Securities and Exchange Commission (SEC).
The Company has entered into forward purchase agreements to be settled
from time to time, at the Company's election, on either a physical, net share or
net cash basis. The amount at which these agreements can be settled is dependent
principally upon the market price of the Company's common stock as compared to
the forward purchase price per share and the number of shares to be settled. If
these agreements had been settled on a net share basis at September 30, 1998,
based on the closing price of the Company's common stock on that date, the
Company would have received approximately 3,624,000 shares of Company common
stock.
<PAGE>
YEAR 2000 PROJECT
The Company's Year 2000 Project (Project) is proceeding 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 (Y2K Issue). 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, among other
things, a temporary inability to process transactions, send bills, operate
generation stations, or engage in similar normal business activities.
The Company has determined that it will be required to modify or
replace significant portions of its software and embedded technology so that its
computer systems will properly utilize dates beyond December 31, 1999. The
Company presently believes that with modifications to existing software,
conversions to new software, and replacement of embedded technology, the effect
of the Y2K Issue on the Company can be mitigated. If such modifications and
conversions 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 speculative and 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 June 1, 1999, except for
modifications, conversions or replacements that are being incorporated into
scheduled plant outages between June and December 1999.
The Project
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 Year 2000 items; (2)
assigning priorities to identified items; (3) assessing the Year 2000 readiness
of items determined to be material to the Company; (4) converting material items
that are determined not to be Year 2000 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 Year 2000 ready and the replacement of software when
available from the supplier. The Company estimates that the software conversion
phase was approximately 48% complete at September 30, 1998, and the remaining
conversions are on schedule to be tested and completed by June 1, 1999. The
Company estimates that replacements and upgrades will be completed on schedule
by June 1, 1999, although some vendor software replacements and upgrades are
behind schedule. Contingency planning for IT Systems is scheduled to be
completed by June 1, 1999. The Project has identified 343 critical IT Systems.
The current readiness status of those systems is set forth below:
Number of Systems Progress Status
- ----------------- -------------------------------------------------
26 Systems Year 2000 Ready
87 Systems In Testing
191 Systems In Active Code Modification, Or Package Upgrading
39 Systems Scheduled to Start after September 30, 1998
<PAGE>
The Embedded Technology section consists of hardware and systems
software other than IT Systems. The Company estimates that the Embedded
Technology section was approximately 61% complete at September 30, 1998, and the
remaining conversions are on schedule to be tested and completed by June 1,
1999. Contingency planning for Embedded Technology is scheduled to be completed
by June 1, 1999. The Project has identified 119 critical Embedded Technology
systems. The current readiness status of those systems is set forth below:
Number of Systems Progress Status
- ----------------- -------------------
25 Systems Year 2000 Ready
94 Systems In Active Upgrading
The Supply Chain section includes the process of identifying and
prioritizing critical suppliers and critical customers with common equipment at
the direct interface level, and communicating with them about their plans and
progress in addressing the Y2K Issue. The Company initiated formal
communications with all of its critical suppliers and critical customers to
determine the extent to which the Company may be vulnerable to their Year 2000
issues. The process of evaluating these critical suppliers and critical
customers has commenced and is scheduled to be completed by June 1, 1999.
Costs
The estimated total cost of the Project is $75.4 million, the majority
of which will be incurred during testing. This estimate includes the Company's
share of Year 2000 costs for jointly owned facilities. The total amount expended
on the Project through September 30, 1998 was $7.3 million. The Company expects
to fund the Project from operating cash flows. The Company's current cost
estimate for the Project is set forth below:
$ Millions
1998 1999 2000 Total
----- ----- ----- -----
O&M 22.3 37.5 9.3 69.1
Capital 1.4 4.9 - 6.3
----- ----- ----- -----
Total 23.7 42.4 9.3 75.4
Risks
The Company's failure to become Year 2000 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 timely converted, 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 Interconnection, L.L.C.
The costs of the Project and the date on which the Company plans to
complete the Year 2000 modifications are based on estimates, which were derived
utilizing numerous assumptions of future events including the continued
availability of certain resources, third-party modification plans and other
factors. However, 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 personnel trained in this area, the ability to locate
and correct all relevant computer programs and microprocessors, and similar
uncertainties.
<PAGE>
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 reduces the possibility of significant interruptions of
normal operations.
FORWARD-LOOKING STATEMENTS
Except for the historical information contained herein, certain of the
matters discussed in this Report are forward-looking statements which 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, 3 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.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
None.
<PAGE>
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
As previously reported in the March 31, 1998 Form 10-Q, the Grays Ferry
Cogeneration Partnership sued the Company in the Court of Common Pleas in
Philadelphia County (Common Pleas Court) to enjoin the Company's termination of
the power purchase agreements relating to the Grays Ferry Cogeneration Project
(Grays Ferry Project).
In a separate action, on March 18, 1998, Chase Manhattan Bank (Chase),
the lender for the Grays Ferry Project, filed an action in the United States
District Court for the Eastern District of Pennsylvania against the Company
alleging breach of the letter agreement relating to the Grays Ferry Project's
credit. On August 10, 1998, Chase voluntarily dismissed its suit against the
Company. On August 21, 1998, Chase intervened as a plaintiff in the Common Pleas
Court action.
ITEM 5. OTHER INFORMATION
As previously reported in the June 30, 1998 Form 10-Q, an intervenor
brought an action asserting that the Competition Act violated the Commerce
Clause of United States Constitution. On May 7, 1998, the Commonwealth Court of
Pennsylvania (Commonwealth Court) unanimously rejected the claim. The intervenor
petitioned the Supreme Court of Pennsylvania for allowance of an appeal, which
petition was denied on September 29, 1998. The intervenor has until December 28,
1998 to file a petition for certiorari with the United States Supreme Court.
As previously reported in the 1997 Form 10-K, two original jurisdiction
actions were filed in the Pennsylvania Commonwealth Court claiming that the
manner in which the Competition Act was passed by the Pennsylvania legislature
violated the Pennsylvania Constitution. On September 24, 1998, those claims were
rejected by the Commonwealth Court. On October 26, 1998, the appeal period for
those cases expired without any party filing an appeal to the Pennsylvania
Supreme Court.
On September 21, 1998, the PUC entered an Order directing holders of
installed capacity resources in PJM Interconnection L.L.C. (including the
Company) to immediately release/offer the capacity for sale at wholesale during
1999 at a presumptive price of $19.72 per kilowatt-year, a price below current
competitive wholesale market prices. On October 21, 1998, the Company filed a
Petition for Review of the PUC Order in Commonwealth Court seeking a declaration
that the PUC's Order is preempted because it attempts to regulate matters within
the exclusive federal jurisdiction of the Federal Energy Regulatory Commission.
On October 28, 1998, the Company entered into a settlement with the PUC under
which the Company agreed to make certain of its wholesale capacity available to
new market entrants serving retail load within the Company's service territory
at specified prices during 1999. On October 30, 1998, the PUC approved the
settlement.
On September 16, 1998, the NRC suspended its SALP program for an
interim period until the NRC staff completes a review of its nuclear power plant
performance assessment process. During the interim period while the SALP program
is suspended, the NRC will utilize the results of its plant performance reviews
to provide nuclear power plant performance information to licensees, state and
local officials and the public. These reviews are intended to identify
performance trends since the previous assessment and make any appropriate
changes to the NRC's inspection plans. At the end of the process, the NRC will
decide whether to resume the SALP program or substitute an alternative program.
As previously reported in the 1997 Form 10-K and the March 31, 1998
Form 10-Q, the NRC issued a Bulletin proposing the installation of large
capacity passive strainers to resolve the problem of clogging of emergency core
cooling system suction strainers experienced at some GE Boiling Water Reactors.
Strainers are scheduled to be installed at Unit No. 2 at Peach Bottom Atomic
Power Station (Peach Bottom) during its October-November 1998 refueling outage.
<PAGE>
As previously reported in the June 30, 1998 Form 10-Q, the NRC issued a
confirmatory order modifying the license for Peach Bottom Units No. 2 and No. 3
requiring that the Company complete final implementation of corrective actions
on the Thermo-Lag 330 issue by completion of the October 1999 refueling outage
of Peach Bottom Unit No. 3. In addition, 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.
The Company has been informed by PSE&G that, in connection with the
NRC's generic letter regarding Year 2000 issues, on July 23, 1998, PSE&G
provided its written response to the NRC outlining its Nuclear Business Unit
(NBU) Year 2000 program and indicating that planned implementation will allow
the NBU to be Year 2000 ready and in compliance with the terms and conditions of
its licenses and NRC regulation by January 1, 2000. As of September 30, 1998,
PSE&G's NBU Year 2000 effort is on schedule to meet the July 1999 NRC response
schedule.
The Company has been informed by PSE&G that, on September 15, 1998, the
NRC issued its latest Systematic Assessment of Licensee Performance (SALP) for
Salem for the period March 1, 1997 to August 1, 1998. In the areas of
Maintenance and Engineering, Salem was rated Category 2 or "good." In the areas
of Operations and Plant Support, Salem was rated Category 1 or "superior." The
NRC noted improved performance overall during the period, as demonstrated by the
nearly event-free return of both units to operation following the extended
outage. The NRC identified strong management oversight, safe and conservative
operations, good engineering support and effective programs for independent
oversight and self-assessment. The NRC also noted that although human
performance has improved significantly due to extensive training interventions,
continued close management attention is warranted in the Operations and
Maintenance areas.
The Company has been informed by PSE&G that, as part of an inspection
by the NRC in April 1997, the NRC noted certain weaknesses in PSE&G's fire
barrier systems. PSE&G sent a letter to the NRC in June 1997 addressing these
issues concerning the qualification of fire wrap barriers used to protect
electrical cabling at Salem. The letter outlined a resolution plan and schedule
to address the fire wrap issues. PSE&G had committed to alternative measures in
the form of fire watches until this plan is implemented. A review of the
installed fire barrier materials and safe shutdown analysis is currently in
progress. If certain modifications are mandated by the NRC, this could result in
a material adverse impact to the Company's financial condition, results of
operations and net cash flows. Additionally, failure to resolved these fire
barrier issues could result in potential NRC violations, fines and/or plant
shutdown.
As previously reported in the 1997 Form 10-K, the NRC had proposed to
issue a generic letter which would require all nuclear plant operators to
provide the NRC with information concerning the operators' programs, planned or
implemented, to address Year 2000 computer and system issues at its facilities.
On May 11, 1998, the NRC issued a Generic Letter requiring (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.
<PAGE>
An Order was entered on July 17, 1998, by the PUC, instituting a formal
investigation by the Office of Administrative Law Judge on Year 2000 compliance
by jurisdictional fixed utilities and mission-critical service providers such as
the PJM Interconnection. 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. The Company also stated
that it was in the process of developing Year 2000 contingency plans.
On September 24, 1998, the EPA announced the issuance of a final
regulation which will require 22 states and the District of Columbia to reduce
emissions of nitrogen oxides (NOx) by more than 1 million tons annually between
2003 and 2007. The main goal of the regulation is to limit the transport of
ozone pollution into the northeastern states, including Pennsylvania, by
reducing NOx emissions in southern and midwestern states. Pennsylvania
utilities, including the Company, are already subject to strict NOx emission
limits. A group of southern and midwestern utilities have announced their
intention of appealing the issuance of the EPA regulation to the Federal Court
of Appeals.
As previously reported in the 1997 Form 10-K, the Environmental
Protection Agency (EPA) sent letters to approximately 20 potentially responsible
parties (PRPs), including the Company, giving them 60 days to negotiate with the
EPA to perform the proposed remedy for the Metal Bank of America site outlined
in the EPA's December 1997 record of decision (ROD). The Company, along with the
nine other PRPs in the utility PRP group, responded to the EPA's letter by
offering to conduct the Remedial Design (RD) but not the Remedial Action (RA)
outlined in the ROD. The EPA rejected the PRP group's offer and, on June 26,
1998, issued an Order to the non-de minimis PRP Group members, and others,
including the owner, to implement the RD and RA. The PRP Group is proceeding as
required by the Order; it has selected a contractor which has been approved by
the EPA, and is preparing the RD Work Plan.
As previously reported in the 1997 Form 10-K, the Company was added as
a third-party defendant in an existing suit alleging that the Company is
responsible for sending waste to the Cinnaminson Ground Water Contamination
Site. On June 4, 1998, the Company entered into a settlement with the
defendants.
<PAGE>
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits:
12-1 - Statement regarding computation of ratio of
earnings to fixed charges.
12-2 - Statement regarding computation of ratio of
earnings to combined fixed charges and preferred
stock dividends.
27 - Financial Data Schedule.
(b) Reports on Form 8-K filed during the reporting period:
Report, dated July 17, 1998 reporting information under "ITEM 5. OTHER
EVENTS" regarding AmerGen Energy Company, LLC, the joint
venture between the Company and British Energy plc, entering
into a Letter of Intent to purchase Three Mile Island Unit No.
1 from GPU, Inc.
Reports on Form 8-K filed subsequent to the reporting period:
Report, dated October 15, 1998 reporting information under "ITEM 5.
OTHER EVENTS" regarding AmerGen Energy Company, LLC, the joint
venture between the Company and British Energy plc, signing a
definitive asset purchase agreement to purchase Three Mile
Island Unit No. 1 from GPU, Inc.
<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
Senior Vice President and
Chief Financial Officer
(Principal Financial and
Accounting Officer)
Date: October 30, 1998
EXHIBIT 12-1
<TABLE>
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
SEC METHOD
($000)
<CAPTION>
9 MONTHS
ENDED
09/30/98
--------
<S> <C>
NET INCOME $538,784
ADD BACK:
- - INCOME TAXES:
OPERATING INCOME 356,829
NON-OPERATING INCOME (19,115)
-------
NET TAXES 337,714
- - FIXED CHARGES:
INTEREST APPLICABLE TO DEBT 248,994
ANNUAL RENTALS 6,869
-------
TOTAL FIXED CHARGES 255,863
-------
ADJUSTED EARNINGS INCLUDING AFUDC $1,132,361
==========
RATIO OF EARNINGS TO FIXED CHARGES 4.43
====
</TABLE>
EXHIBIT 12-2
<TABLE>
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES
AND PREFERRED STOCK DIVIDEND REQUIREMENTS
SEC METHOD
($000)
<CAPTION>
9 MONTHS
ENDED
09/30/98
--------
<S> <C>
NET INCOME $538,784
ADD BACK:
- - INCOME TAXES:
OPERATING INCOME 356,829
NON-OPERATING INCOME (19,115)
-------
NET TAXES 337,714
- - FIXED CHARGES:
INTEREST APPLICABLE TO DEBT 248,994
ANNUAL RENTALS 6,869
-------
TOTAL FIXED CHARGES 255,863
EARNINGS REQUIRED FOR PREFERRED DIVIDENDS:
DIVIDENDS ON PREFERRED STOCK 9,832
ADJUSTMENT TO PREFERRED DIVIDENDS* 6,163
-------
15,995
-------
FIXED CHARGES AND PREFERRED DIVIDENDS $271,858
========
EARNINGS BEFORE INCOME TAXES AND
FIXED CHARGES $1,132,361
==========
RATIO OF EARNINGS TO COMBINED FIXED CHARGES
AND PREFERRED STOCK DIVIDEND REQUIREMENTS 4.17
====
<FN>
* ADDITIONAL CHARGE EQUIVALENT TO EARNINGS REQUIRED
TO ADJUST DIVIDENDS ON PREFERRED STOCK TO A PRE-TAX BASIS
</FN>
</TABLE>
<TABLE> <S> <C>
<ARTICLE> UT
<MULTIPLIER> 1,000,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-END> SEP-30-1998
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 4765
<OTHER-PROPERTY-AND-INVEST> 512
<TOTAL-CURRENT-ASSETS> 878
<TOTAL-DEFERRED-CHARGES> 5981
<OTHER-ASSETS> 212
<TOTAL-ASSETS> 12348
<COMMON> 3564
<CAPITAL-SURPLUS-PAID-IN> 1
<RETAINED-EARNINGS> (445)
<TOTAL-COMMON-STOCKHOLDERS-EQ> 3120
93
138
<LONG-TERM-DEBT-NET> 3590
<SHORT-TERM-NOTES> 116
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 116
<LONG-TERM-DEBT-CURRENT-PORT> 256
0
<CAPITAL-LEASE-OBLIGATIONS> 93
<LEASES-CURRENT> 71
<OTHER-ITEMS-CAPITAL-AND-LIAB> 4871
<TOT-CAPITALIZATION-AND-LIAB> 12348
<GROSS-OPERATING-REVENUE> 4155
<INCOME-TAX-EXPENSE> 338
<OTHER-OPERATING-EXPENSES> 2962
<TOTAL-OPERATING-EXPENSES> 3300
<OPERATING-INCOME-LOSS> 855
<OTHER-INCOME-NET> (34)
<INCOME-BEFORE-INTEREST-EXPEN> 821
<TOTAL-INTEREST-EXPENSE> 282
<NET-INCOME> 539
10
<EARNINGS-AVAILABLE-FOR-COMM> 529
<COMMON-STOCK-DIVIDENDS> 167
<TOTAL-INTEREST-ON-BONDS> 259
<CASH-FLOW-OPERATIONS> 1049
<EPS-PRIMARY> 2.37
<EPS-DILUTED> 2.36
</TABLE>
