UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
March 16, 2001
(Date of earliest
event reported)
EXELON CORPORATION
(Exact name of registrant as specified in its charter)
Pennsylvania 1-16169 23-2990190
(State or other (SEC (IRS Employer
jurisdiction of file number) Identification
incorporation) Number)
37th Floor, 10 South Dearborn Street
Post Office Box A-3005
Chicago, Illinois 60690-3005
(Address of principal executive offices)
Registrant's telephone number, including area code:
(312) 394-4321
Item 5. Other Events
The purpose of this Current Report is to file certain financial information
regarding Exelon Corporation and Subsidiary Companies. Such financial
information is set forth in the exhibits to this Current Report.
Item 7. Financial Statements and Exhibits
(c) Exhibits.
23 Consent of Independent Public Accountants
99-1 Selected Financial Data and Market for Registrant's Common Equity and
Related Stockholder Matters
99-2 Management's Discussion and Analysis of Financial Condition and
Results of Operations
99-3 Financial Statements and Supplementary Data
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned hereunto duly authorized.
EXELON CORPORATION
/S/ Ruth Ann M. Gillis
--------------------------------
Ruth Ann M. Gillis
Principal Financial Officer
March 16, 2001
Exhibit 23
Consent of Independent Public Accountants
Consent of Independent Public Accountants
We hereby consent to the incorporation by reference in the Post-Effective
Amendment No. 1 to Form S-4 Registration Statement on Form S-8 (File No.
333-37082) of Exelon Corporation and Subsidiary Companies of our report dated
January 30, 2001, except for Note 21 PETT Refinancing for which the date is
March 1, 2001, relating to the financial statements and financial statement
schedule, which report is included as an Exhibit to this Form 8-K Current
Report.
PricewaterhouseCoopers LLP
Chicago, Illinois
March 16, 2001
Exhibit 99-1
Exelon Corporation and Subsidiary Companies
Selected Financial Data and Market for Registrant's Common Equity
and Related Stockholder Matters
Selected Financial Data
For the Years Ended December 31,
--------------------------------
2000 1999 1998 1997 1996
-------- -------- -------- ------- -------
Statement of Income Data:
Operating Revenues $ 7,499 $ 5,478 $ 5,325 $ 4,601 $ 4,284
Operating Income 1,527 1,373 1,268 1,006 1,249
Income before Extraordinary Items
and Cumulative Effect of a Change in
Accounting Principle 566 607 520 320 499
Extraordinary Items (net of income taxes) (4) (37) (20) (1,834) --
Cumulative Effect of a Change in
Accounting Principle 24 -- -- -- --
Net Income (Loss) 586 570 500 (1,514) 499
Earnings per Share (Basic):
Income Before Extraordinary Items and
Cumulative Effect of a Change in
Accounting Principle $ 2.81 $ 3.10 $ 2.33 $ 1.44 $ 2.24
Extraordinary Items (0.02) (0.19) (0.09) (8.24) --
Cumulative Effect of a Change in
Accounting Principle 0.12 -- -- -- --
-------- -------- -------- ------- -------
Net Income (Loss) $ 2.91 $ 2.91 $ 2.24 $ (6.80) $ 2.24
======== ======== ======== ======== =======
Dividends per Share $ 0.91 $ 1.00 $ 1.00 $ 1.80 $1.755
======== ======== ======== ======== =======
Average Shares Outstanding 202 196 223 223 223
======== ======== ======== ======== =======
At December 31,
---------------
2000 1999 1998 1997 1996
-------- -------- -------- ------- -------
Balance Sheet Data:
Current Assets $ 4,184 $ 1,221 $ 582 $ 1,003 $ 420
Property, Plant and Equipment, net 12,936 5,004 4,804 4,671 10,942
Deferred Debits and Other Assets 17,477 6,862 6,662 6,683 3,899
-------- -------- -------- ------- -------
Total Assets $34,597 $13,087 $12,048 $12,357 $15,261
======== ======== ======== ======= =======
Current Liabilities $ 4,651 $ 1,286 $ 1,735 $ 1,619 $ 1,103
Long-Term Debt 12,958 5,969 2,920 3,853 3,936
Deferred Credits and Other Liabilities 9,143 3,738 3,756 3,576 4,982
Preferred Securities of Subsidiaries 630 321 579 582 594
Shareholders' Equity 7,215 1,773 3,058 2,727 4,646
-------- -------- -------- ------- -------
Total Liabilities and Shareholders' Equity $34,597 $13,087 $12,048 $12,357 $15,261
======== ======== ======== ======= =======
2
Market for Registrant's Common Equity and Related Stockholder Matters
Exelon Corporation's (Exelon) common stock is listed on the New York Stock
Exchange. The following table sets forth the high and low sales prices and
closing prices for Exelon's common stock for the past two years. The information
presented in the table below prior to October 20, 2000 represents PECO Energy
Company.
2000 1999
----------------------------------------- -----------------------------------------
Fourth Third Second First Fourth Third Second First
Quarter Quarter Quarter Quarter Quarter Quarter Quarter Quarter
High Price $71.00 $61.38 $46.81 $43.69 $38.81 $44.19 $50.50 $46.44
Low Price $53.88 $40.50 $36.56 $33.00 $31.50 $35.88 $41.88 $35.25
Close $70.21 $60.58 $40.31 $36.88 $34.75 $37.50 $41.88 $46.25
Dividends $ 0.16 $ 0.25 $ 0.25 $ 0.25 $ 0.25 $ 0.25 $ 0.25 $ 0.25
Exelon had 202,312 shareholders of record of common stock as of December 31,
2000.
3
Exhibit 99-2
Exelon Corporation and Subsidiary Companies
Management's Discussion And Analysis Of Financial Condition And
Results Of Operations
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
General
On October 20, 2000, Exelon Corporation (Exelon) became the parent corporation
for each of PECO Energy Company (PECO) and Commonwealth Edison Company (ComEd)
as a result of the completion of the transactions contemplated by an Agreement
and Plan of Exchange and Merger, as amended, among PECO, Unicom Corporation
(Unicom) and Exelon. Exelon issued 148 million shares of common stock and paid
$507 million in cash to Unicom shareholders in connection with the merger. The
merger was accounted for using the purchase method of accounting. Goodwill
recorded in connection with the acquisition was $4.9 billion, which is being
amortized over forty years. Exelon's results of operations consist of PECO's
results of operations for each of the three years ended December 31, 2000 and
Unicom's results of operations from October 20, 2000.
Exelon, through subsidiaries including PECO and ComEd, operates in three
business segments:
o Energy Delivery, consisting of the retail electricity distribution and
transmission businesses of ComEd in northern Illinois and PECO in
southeastern Pennsylvania and the natural gas distribution business of PECO
located in the Pennsylvania counties surrounding the City of Philadelphia.
o Generation, consisting of electric generating facilities, power marketing
operations and equity interests in Sithe Energies, Inc. (Sithe) and AmerGen
Energy Company, LLC (AmerGen).
o Enterprises, consisting of competitive retail energy sales, energy and
infrastructure services, communications and related investments. Effective
January 1, 2001, Enterprises will also include the operations of Exelon
Energy, which were previously included in Generation.
During January 2001, Exelon undertook a restructuring to separate Exelon's
generation and other competitive businesses from its regulated energy delivery
business. As part of the restructuring, the non-regulated operations and related
assets of ComEd and PECO were transferred to separate subsidiaries of Exelon.
Restructuring will streamline the process for managing, operating and tracking
financial performance of each business segment. Information is presented in this
section on the basis of these segments to the extent available.
1
Significant Operating Trends
Percentage of Total Operating
Revenues Percentage Dollar Changes
2000 vs.1999 1999 vs. 1998
------------ -------------
2000 1999 1998 Unicom
---- ---- ---- ------
Contribution(a) PECO
--------------- ----
100% 100% 100% Operating Revenue 28% 9% 3%
34% 39% 34% Fuel and Purchased Power 22% (1%) 19%
31% 27% 23% Operating and Maintenance 38% 23% 21%
4% -- -- Merger-Related Costs N.M. N.M. N.M.
-- -- 2% Early Retirement & Separation Program N.M. N.M. N.M.
6% 4% 12% Depreciation and Amortization 58% 36% (63)%
4% 5% 5% Taxes Other Than Income 32% (10%) (6)%
----- ----- -----
79% 75% 76% Total Operating Expenses 30% 16% 1%
---- ---- ----
21% 25% 24% Operating Income 22% (13%) 8%
==== ==== ====
(a) Percentage dollar changes attributable to the operations of Unicom since its
acquisition on October 20, 2000.
N.M. - not meaningful.
Results of Operations
Year Ended December 31, 2000 Compared To Year Ended December 31, 1999
Net Income and Earnings Per Share
Net income increased $141 million, or 23% in 2000, before giving effect to
extraordinary items, the cumulative effect of a change in accounting principle
and non-recurring items. Earnings per share, on the same basis, increased $0.57
per share, or 18%. Earnings per share increased less than net income because of
an increase in the weighted average shares of common stock outstanding as a
result of the issuance of common stock in connection with the merger, partially
offset by the repurchase of common stock with the proceeds from PECO's March
1999 and May 2000 stranded cost recovery securitizations. Net income, inclusive
of a $4 million extraordinary charge, a $24 million benefit for the cumulative
effect of a change in accounting principle and non-recurring items relating to
merger-related costs of $177 million and a writedown of a communications
investment of $21 million, increased $16 million, or 3% in 2000. Earnings per
share, on the same basis, were consistent with the prior year period.
2
Energy Delivery's results improved because of the acquisition of Unicom and
favorable rate adjustments. This improvement was partially offset by lower
margins due to the unplanned return of certain commercial and industrial
customers, milder weather, increased depreciation and amortization expense and
higher interest expense. Generation's results improved as a result of higher
margins on wholesale and unregulated retail energy sales. Enterprises' results
were adversely impacted by lower margins on its infrastructure services
businesses, increased amortization of goodwill and costs to integrate the
businesses acquired in 1999 and 2000.
Operating Revenue
2000 1999 $ Variance % Variance
---- ---- ---------- ----------
(in millions, except percentage data)
Energy Delivery $4,487 $3,265 $1,222 37.4%
Generation 2,089 2,097 (8) (0.4%)
Enterprises 923 116 807 695.7%
------- ------- -------
$7,499 $5,478 $2,021 36.9%
====== ====== ======
Energy Delivery
The increase in Energy Delivery's operating revenue was attributable to higher
electric revenue of $1,146 million and additional gas revenue of $76 million.
The increase in electric revenue reflected $1,113 million from the operations of
Unicom since the merger and $102 million from customers in Pennsylvania
selecting PECO as their electric generation supplier and rate adjustments in
Pennsylvania, partially offset by a decrease of $69 million as a result of lower
summer volume. Regulated gas revenue reflected increases of $44 million related
to higher prices, $29 million attributable to increased volume from new and
existing customers and $24 million from increased winter volume. These increases
were partially offset by $21 million of lower gross receipts tax collections as
a result of the repeal of the gross receipts tax on gas sales in connection with
gas restructuring in Pennsylvania.
Generation
The decrease in Generation's operating revenue resulted from lower electric
revenue of $22 million partially offset by higher gas revenue of $14 million.
The decrease in electric revenue was principally attributable to lower sales of
competitive retail electric generation services of $132 million, of which $196
million represented decreased volume that was partially offset by $64 million
from higher prices. In addition, the termination of the management agreement for
Clinton Nuclear Power Station (Clinton) resulted in lower revenues of $99
million. As a result of the acquisition by AmerGen of Clinton in December 1999,
the management agreement was terminated and, accordingly, the operations of
Clinton have been included in Equity in Earnings (Losses) of Unconsolidated
Affiliates on Exelon's Consolidated Statements of Income since that date. These
decreases were partially offset by an increase of $209 million from higher
wholesale revenue attributable to $159 million from the operations of Unicom
since the merger and $199 million associated with higher prices partially offset
by $149 million related to lower volume. Unregulated gas revenue increased
primarily as a result of $11 million from wholesale sales of excess natural gas.
Enterprises
The increase in Enterprises' operating revenue was attributable to $530 million
from the acquisition of thirteen infrastructure services companies during 2000
and 1999 and $277 million from the operations of Unicom since the merger.
3
Fuel and Purchased Power Expense
2000 1999 $ Variance % Variance
---- ---- ---------- ----------
(in millions, except percentage data)
Energy Delivery $ 462 $ 370 $ 92 24.9%
Generation 1,973 1,782 191 10.7%
Enterprises 171 -- 171 N.M.
------ ------ ------
$2,606 $2,152 $ 454 21.1%
====== ====== ======
Energy Delivery
Energy Delivery's increase in fuel and purchased power expense was primarily
attributable to $73 million from additional volume and increased prices related
to gas, $13 million as a result of favorable weather conditions and $4 million
in lower PJM Interconnection, LLC (PJM) ancillary charges.
Generation
Generation's increase in fuel and purchased power expense was primarily
attributable to $308 million from the operations of Unicom since the merger, an
increase of $120 million in the cost to supply Energy Delivery and an increase
of $5 million from wholesale operations principally related to $97 million as a
result of increased prices partially offset by $92 million as a result of
decreased volume. These increases were partially offset by lower fuel and
purchased power expenses of $262 million, principally related to reduced sales
of competitive retail electric generation services.
Enterprises
Enterprises' increase in fuel and purchased power expense was attributable to
$171 million from the operations of Unicom since the merger. Enterprises
includes the former Unicom's unregulated retail energy supplier.
Operating and Maintenance Expense
2000 1999 $ Variance % Variance
---- ---- ---------- ----------
(in millions, except percentage data)
Energy Delivery $ 644 $ 434 $ 210 48.4%
Generation 769 721 48 6.7%
Enterprises 736 136 600 441.2%
Corporate 161 163 (2) (1.2)%
------ ------ ------
$2,310 $1,454 $ 856 58.9%
====== ====== ======
Energy Delivery
Energy Delivery's increase in Operating and Maintenance (O&M) expense was
primarily attributable to $153 million from the operations of Unicom since the
merger and the direct charging to the business segments of O&M expenses that
were previously reported at Corporate.
Generation
Generation's increase in O&M expense was primarily attributable to $153 million
from the operations of Unicom since the merger partially offset by O&M expenses
related to the management agreement for Clinton of $70 million in 1999, $15
million related to the abandonment of two information systems implementations in
1999, $17 million related to lower administrative and general expenses
associated with the unregulated retail sales of electricity and $15 million
related to lower joint-owner expenses.
Enterprises
Enterprises' O&M expense increased $505 million from the infrastructure services
business as a result of acquisitions and $86 million from the operations of
Unicom since the merger.
4
Corporate
Corporate's O&M expense increased $155 million from the operations of Unicom
since the merger, partially offset by a decrease in expenses of $56 million
related to lower Year 2000 remediation expenditures, lower pension and
postretirement benefits expense of $31 million and the direct charging to
business segments of O&M expenses that were previously recorded at Corporate.
Merger-Related Costs
Merger-related costs charged to expense in 2000 were $276 million consisting of
$152 million of direct incremental costs and $124 million for employee costs.
Direct incremental costs represent expenses associated with completing the
merger, including professional fees, regulatory approval and settlement costs,
and settlement of compensation arrangements. Employee costs represent estimated
severance payments and pension and post-retirement benefits provided under
Exelon's Merger Separation Plan (MSP) for 642 eligible PECO employees who are
expected to be involuntarily terminated before October 2002 upon completion of
integration activities for the merged companies.
Depreciation and Amortization Expense
Depreciation and amortization expense increased $221 million, or 93%, to $458
million in 2000. The increase was primarily attributable to $134 million
associated with the merger, $57 million of amortization of PECO's Competitive
Transition Charges (CTC) which commenced in 2000 and $29 million related to
depreciation and amortization expense associated with the infrastructure
services business acquisitions.
Taxes Other Than Income
Taxes other than income increased $60 million, or 23%, to $322 million in 2000.
The increase was primarily attributable to $84 million from the operations of
Unicom since the merger and a non-recurring $22 million capital stock tax credit
related to a 1999 adjustment associated with the impact of the PECO's 1997
restructuring charge. These increases were partially offset by lower real estate
taxes of $18 million relating to a change in tax laws for utility property in
Pennsylvania and $11 million as a result of the elimination of the gross
receipts tax on natural gas sales net of an increase in gross receipts tax on
electric sales.
Interest Charges
Interest charges consist of interest expense and distributions on preferred
securities of subsidiaries. Interest charges increased $203 million, or 47%, to
$632 million in 2000. The increase was primarily attributable to $156 million
from the operations of Unicom since the merger and interest of $104 million on
the transition bonds issued to securitize PECO's stranded cost recovery,
partially offset by $77 million of lower interest charges as a result of the
reduction of PECO's long-term debt with the proceeds from the securitization.
Equity in Earnings (Losses) of Unconsolidated Affiliates
Equity in earnings (losses) of unconsolidated affiliates decreased $3 million,
or 8%, to losses of $41 million in 2000 as compared to losses of $38 million in
1999. The decrease was primarily attributable to $8 million of additional losses
from communications investments, partially offset by $4 million of earnings from
AmerGen as a result of the acquisitions of Clinton and Three Mile Island Unit
No. 1 Nuclear Generating Facility in December 1999 and Oyster Creek Nuclear
Generating Facility in September 2000.
Other Income and Deductions
Other income and deductions excluding interest charges and equity in earnings
(losses) of unconsolidated affiliates decreased $6 million, or 10%, to $53
million in 2000 as compared to $59 million in 1999. The decrease in other income
and deductions was primarily attributable to the writedown of a communications
investment of $33 million, and a decrease in interest income of $10 million.
These decreases were partially offset by a $15 million write-off in 1999 of the
investment in a cogeneration facility in connection with the settlement of
litigation, gains on sales of investments of $13 million and $9 million from the
operations of Unicom since the merger.
5
Income Taxes
The effective tax rate was 37.6% in 2000 as compared to 37.1% in 1999.
Extraordinary Items
In 2000, Exelon incurred extraordinary charges aggregating $6 million ($4
million, net of tax) related to 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 securitization of PECO's stranded
cost recovery in May 2000.
In 1999, Exelon incurred extraordinary charges aggregating $62 million ($37
million, net of tax) related to prepayment premiums and the write-off of
unamortized debt costs associated with the repayment and refinancing of debt.
Cumulative Effect of a Change in Accounting Principle
In 2000, Exelon recorded a benefit of $40 million ($24 million, net of tax)
representing the cumulative effect of a change in accounting method for nuclear
outage costs by PECO in conjunction with the synchronization of accounting
policies in connection with the merger.
Year Ended December 31, 1999 Compared To Year Ended December 31, 1998
Net Income and Earnings Per Share
Net income increased $70 million, or 14%, to $570 million in 1999. Earnings per
share increased $0.67 per share or 30%, to $2.91 per share in 1999. Earnings per
share increased more than net income because of a decrease in the weighted
average shares of common stock outstanding as a result of the repurchase of
approximately 44.1 million shares with a portion of the proceeds of PECO's March
1999 stranded cost recovery securitization.
Operating Revenues
1999 1998 $ Variance % Variance
---- ---- ---------- ----------
(in millions, except percentage data)
Energy Delivery $3,265 $3,799 $ (534) (14.1%)
Generation 2,097 1,513 584 38.6%
Enterprises 116 13 103 792.3%
----- ------- ------
$5,478 $5,325 $ 153 2.9%
====== ====== =======
Energy Delivery
The decrease in Energy Delivery's operating revenues was primarily attributable
to lower volume associated with the effects of retail competition of $508
million and $278 million related to the 8% across-the-board rate reduction
mandated by Pennsylvania deregulation. These decreases were partially offset by
$149 million of PJM network transmission service revenue and $59 million related
to higher volume as a result of favorable weather conditions as compared to
1998. PJM network transmission service revenues and charges, which commenced
April 1, 1998, were recorded in Generation in 1998 but were recognized by Energy
Delivery in 1999 as a result of the Federal Energy Regulatory Commission (FERC)
approval of the PJM Regional Transmission Owners' rate case settlements.
Stranded cost recovery was included in PECO's retail electric rates beginning
January 1, 1999. In addition, gas revenues increased $50 million primarily
attributable to increased volume as a result of favorable weather conditions of
$27 million and increased volume from new and existing customers of $20 million
as compared to 1998.
Generation
The increase in Generation's operating revenues was primarily attributable to
$473 million from increased volume in Pennsylvania as a result of the sale of
competitive retail electric generation services, increased wholesale revenues of
$133 million from the marketing of excess generation capacity as a result of
retail competition and revenues of $99 million from the sale of generation from
Clinton to Illinois Power (IP), partially offset by the inclusion of $116
million of PJM network transmission service revenue in 1998.
6
Under the management agreement with IP, PECO was responsible for the payment of
all direct O&M costs and direct capital costs incurred by IP and allocable to
the operation of Clinton. These costs were reflected in O&M expenses. IP was
responsible for fuel and indirect costs such as pension benefits, payroll taxes
and property taxes. Following the restart of Clinton on June 2, 1999, and
through December 15, 1999, PECO sold 80% of the output of Clinton to IP. The
remaining output was sold by PECO in the wholesale market. Under a separate
agreement with PECO, British Energy Inc., a wholly owned subsidiary of British
Energy plc (British Energy) agreed to share 50% of the costs and revenues
associated with the management agreement with IP. Effective December 15, 1999,
AmerGen acquired Clinton. Accordingly, the results of operations of Clinton have
been accounted for under the equity method of accounting in Exelon's
Consolidated Statements of Income since the acquisition date.
Enterprises
The increase in Enterprises' operating revenue was attributable to the effects
of the infrastructure services company acquisitions made in 1999.
Fuel and Purchased Power Expense
1999 1998 $ Variance % Variance
---- ---- ---------- ----------
(in millions, except percentage data)
Energy Delivery $ 370 $ 191 $ 179 93.7%
Generation 1,782 1,620 162 10.0%
------ ------ -------
$2,152 $1,811 $ 341 18.8%
====== ====== =======
Energy Delivery
Energy Delivery's increase in fuel and purchased power expense was attributable
to $98 million of PJM network transmission service charges, $51 million of
purchases in the spot market and $30 million of additional volume as a result of
weather conditions.
Generation
Generation's increase in fuel and purchased power expense was primarily
attributable to $565 million related to increased volume from the sale of
competitive electric generation services and a $36 million reserve related to a
power supply contract in Massachusetts as a result of higher than anticipated
cost of supply in the New England power pool. These increases were partially
offset by $277 million of fuel savings from wholesale operations as a result of
lower volume and efficient operation of generating assets, the inclusion of PJM
network transmission service charges of $116 million in 1998, and the reversal
of $27 million in reserves associated with a cogeneration facility in connection
with the final settlement of litigation and expected prices of electricity over
the remaining life of the power purchase agreements for the facility. In
addition, the full return to service of Salem Generating Station (Salem) in
April 1998 resulted in $19 million of fuel savings associated with a reduction
in purchased power costs.
Operating and Maintenance Expense
1999 1998 $ Variance % Variance
---- ---- ---------- ----------
(in millions, except percentage data)
Energy Delivery $ 434 $ 431 $ 3 0.7%
Generation 721 543 178 32.8%
Enterprises 136 38 98 257.9%
Corporate 163 186 (23) (12.4)%
------ ------ ------
$1,454 $1,198 $ 256 21.4%
====== ====== ======
Energy Delivery
Energy Delivery's O&M expenses included $11 million of additional expenses
related to restoration activities as a result of Hurricane Floyd which were
partially offset by lower electric transmission and distribution expenses.
7
Generation
Generation's increase in O&M expense was primarily a result of $70 million
related to Clinton operations in connection with the management agreement, $24
million related to the growth of Exelon Energy, $15 million of charges related
to the abandonment of two information systems implementations, $10 million
associated with the Salem inventory write-off for excess and obsolete inventory
and $7 million related to the true-up of 1998 reimbursement of joint-owner
expenses. These decreases were partially offset by $10 million of lower O&M
expenses as a result of the full return to service of Salem in April 1998.
Enterprises
Enterprises' increase in O&M expense was related to the infrastructure services
company acquisitions made in 1999.
Corporate
Corporate's decrease in O&M expense was primarily as a result of $17 million of
lower pension and postretirement benefits expense attributable to the
performance of the investments in PECO's pension plan.
Depreciation and Amortization Expense
Depreciation and amortization expense decreased $406 million, or 63%, to $237
million in 1999. The decrease in depreciation and amortization expense was
associated with the December 1997 restructuring charge through which PECO wrote
down a significant portion of its generating plant and regulatory assets. In
connection with this restructuring charge, PECO 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, CTC, of $5.3 billion. CTC
is being amortized over an eleven year period ending December 31, 2010.
Taxes Other Than Income
Taxes other than income decreased $18 million, or 6%, to $262 million in 1999.
The decrease in taxes other than income was primarily attributable to a $34
million credit related to an adjustment of PECO's Pennsylvania capital stock tax
base as a result of the 1997 restructuring charge, partially offset by an
increase of $17 million in real estate taxes as a result of changes in tax laws
for utility property in Pennsylvania.
Interest Charges
Interest charges increased $54 million, or 14%, to $429 million in 1999. The
increase in interest charges was primarily attributable to interest on the
transition bonds issued to securitize PECO's stranded cost recovery of $179
million, partially offset by a $99 million reduction in interest charges
resulting from the use of securitization proceeds to repay long-term debt and
preferred securities of subsidiaries. In addition, Exelon's ongoing program to
reduce or refinance higher cost, long-term debt reduced interest charges by $26
million.
Equity in Earnings (Losses) of Unconsolidated Affiliates
Equity in earnings (losses) of unconsolidated affiliates increased $16 million
or 30%, to losses of $38 million in 1999. The lower losses are primarily
attributable to customer base growth for communications joint ventures.
Other Income and Deductions
Other income and deductions, excluding interest charges and equity in earnings
(losses) of unconsolidated affiliates, increased $58 million, to income of $59
million in 1999 as compared to income of $1 million in 1998. The increase in
other income and deductions was primarily attributable to $28 million of
interest income earned on the unused portion of the proceeds from securitization
of stranded cost recovery prior to application, $14 million of gain on the sale
of assets, a $10 million donation to a City of Philadelphia street lighting
project in 1998 and a $7 million write-off of a non-regulated business venture
in 1998. These increases were partially offset by a $15 million write-off of an
investment in connection with the settlement of litigation.
8
Income Taxes
The effective tax rate was 37.1% in 1999 as compared to 38.1% in 1998. The
decrease in the effective tax rate was primarily attributable to an income tax
benefit of approximately $11 million related to the favorable resolution of
certain outstanding issues in connection with the settlement of an Internal
Revenue Service audit and tax benefits associated with the implementation of
state tax planning strategies, partially offset by the non-recognition for state
income tax purposes of certain operating losses.
Extraordinary Items
In 1999, Exelon incurred extraordinary charges aggregating $62 million ($37
million, net of tax) related to prepayment premiums and the write-off of
unamortized debt costs associated with the repayment and refinancing of debt.
In 1998, Exelon incurred extraordinary charges aggregating $34 million ($20
million, net of tax) related to prepayment premiums and the write-off of
unamortized debt costs associated with the repayment of debt.
Liquidity and Capital Resources
Cash flows from operations were $1,096 million in 2000 as compared to $883
million in 1999 and $1,486 million in 1998.
Cash flows used in investing activities were $1,203 million in 2000 as compared
to $886 million in 1999 and $521 million in 1998. The increase in 2000 was
primarily attributable to the acquisition of a 49.9% interest in Sithe for $704
million and cash consideration for the merger of $507 million. Capital
expenditures increased by $261 million to $752 million in 2000. These increases
were partially offset by prepayments of scheduled lease payments received in
connection with Unicom's like-kind exchange transaction entered into in June
2000 of $1.2 billion and $118 million of investments in and advances to joint
ventures that occurred in 1999.
Cash flows used in financing activities were $255 million in 2000 as compared to
cash flows provided by financing activities of $183 million in 1999 and cash
flows used in financing activities of $950 million in 1998. Cash flows from
financing activities in 2000 primarily reflect PECO's additional securitization
of stranded cost recovery and the use of related proceeds.
Exelon's capital resources are primarily provided by internally generated cash
flows from operations and, to the extent necessary, external financing. Capital
resources are used primarily to fund Exelon's capital requirements, including
construction, investments in new and existing ventures, repayments of maturing
debt and preferred securities of subsidiaries and payment of common stock
dividends. Any potential future acquisitions could require external financing,
including the issuance by Exelon of common stock.
Exelon's estimated capital expenditures and other investments in 2001 are
approximately $2.7 billion. Exelon's proposed capital expenditures and other
investments are subject to periodic review and revision to reflect changes in
economic conditions and other factors.
For the year ended December 31, 2000, capital expenditures for PECO and ComEd
were $219 million and $1.2 billion, respectively. Energy Delivery's estimated
capital expenditures for 2001 are approximately $1.2 billion, principally for
intensive efforts to continue to improve the reliability of its distribution
system in the Chicago region. Exelon anticipates that PECO and ComEd will obtain
external financing, when necessary, through borrowings or issuance of preferred
securities by PECO or ComEd, or capital contributions from Exelon.
Generation's capital expenditures were $288 million in 2000. Generation's
estimated capital expenditures for 2001 are approximately $950 million,
principally for maintenance, nuclear fuel and increases in capacity at existing
plants. In addition, Generation holds an option to purchase the remaining 50.1%
interest in Sithe, exercisable between December 2002 and December 2005, at a
price to be determined based on
9
prevailing market conditions. Generation and British Energy, Generation's joint
venture partner in AmerGen, have each agreed to provide up to $100 million to
AmerGen at any time for operating expenses. Exelon anticipates that Generation's
capital expenditures will be funded by internally generated funds, Generation
borrowings or capital contributions from Exelon. Any borrowings by Generation
may be initially guaranteed by Exelon as a result of Generation's lack of
separate operational history.
Enterprises' capital expenditures, including acquisitions, were $394 million in
2000. Enterprises' estimated capital expenditures for 2001 are approximately
$456 million, primarily for strategic acquisitions and investments. All of
Enterprises' investments are expected to be funded by capital contributions or
borrowings from Exelon.
Exelon has obtained an order from the Securities and Exchange Commission (SEC)
under the Public Utility Holding Company Act of 1935 (PUHCA) authorizing
financing transactions, including the issuance of common stock, preferred
securities, long-term debt and short-term debt in an aggregate amount not to
exceed $4 billion. Exelon requested, and the SEC reserved jurisdiction over, an
additional $4 billion in financing authorization. Exelon agreed to limit its
short-term debt outstanding to $3 billion of the $4 billion total financing
authority. The SEC order also authorized Exelon guarantees of up to $4.5 billion
outstanding at any one time. The SEC order requires Exelon to maintain a ratio
of common equity to total capitalization (including securitization debt) on and
after June 30, 2002 of not less than 30%. At December 31, 2000, Exelon's common
equity to total capitalization was 31%. Under PUHCA and the Federal Power Act,
Exelon, PECO, ComEd and Generation can only pay dividends from retained or
current earnings. However, the SEC order granted permission to Exelon and ComEd
to pay up to $500 million in dividends out of additional paid-in capital,
provided that Exelon agreed not to pay dividends out of paid-in capital after
December 31, 2002 if its common equity is less than 30% of its total
capitalization. At December 31, 2000, Exelon had retained earnings of $332
million, PECO had retained earnings of $197 million, ComEd had retained earnings
of $133 million and Generation had no retained earnings. Exelon is also limited
by order of the SEC under PUHCA to an aggregate investment of $4 billion in
exempt wholesale generators and foreign utility companies.
The Board of Directors of Exelon has announced its intention, subject to
approval and declaration by the Board of Directors each quarter, to declare
annual dividends on its common stock of $1.69 per share.
At December 31, 2000, Exelon's capital structure consisted of 60% of long-term
debt of Exelon and subsidiaries, 31% common stock, 6% notes payable and 3%
preferred securities of subsidiaries. Long-term debt includes $7.6 billion of
securitization debt constituting obligations of certain consolidated special
purpose entities representing 33% of capitalization.
Exelon meets its short-term liquidity requirements primarily through the
issuance of commercial paper and borrowings under bank credit facilities by
Exelon, PECO and ComEd. Exelon, along with PECO and ComEd, entered into a $2
billion unsecured revolving credit facility with a group of banks. This credit
facility is used principally to support the commercial paper program of Exelon,
PECO and ComEd.
At December 31, 2000, Exelon had outstanding $1.4 billion of notes payable
including $161 million of commercial paper. For the year ended December 31,
2000, average interest rates on notes payable were 7.18%. Certain of the credit
agreements to which Exelon, PECO and ComEd are a party require each of them to
maintain a debt to total capitalization ratio of 65% (excluding securitization
debt). At December 31, 2000, the debt to total capitalization ratios on the same
basis for Exelon, PECO and ComEd were 51%, 48%, and 43%, respectively.
In October 2000, Exelon obtained a $1.25 billion term loan due June 30, 2001 to
finance the cash consideration paid to former holders of Unicom common stock in
connection with the merger and to finance the purchase of its 49.9% interest in
Sithe in December 2000. Interest rates on the advances from the credit facility
are based on the London Interbank Offering Rate (LIBOR) as of the date of the
advance. The average interest rate on this term loan for the period it was
outstanding in 2000 was 7.62%. Exelon expects to refinance this term loan on or
before its due date.
10
Quantitative and Qualitative Disclosures About Market Risk
Exelon is exposed to market risks associated with commodity price, credit,
interest rates and equity prices.
Commodity Price Risk
Exelon utilizes contracts for the forward sale and purchase of energy to manage
its available generation capacity and its physical delivery obligations to
wholesale and retail customers. Energy option contracts and energy swap
arrangements are used to limit the market price risk associated with forward
contracts. Market price risk exposure is the difference between the fixed price
commitments in the contracts and the market price of the commodity. The
estimated market price exposure associated with a 10% decrease in the average
around the clock market price of electricity is a $60 million decrease in net
income. Although Exelon expects to begin to use financial and commodity
contracts for trading purposes in the second quarter of 2001, such contracts
were not utilized for trading or speculative purposes in 2000. Exelon has
established risk policies, procedures and limits to manage its exposure to
market risk.
Credit Risk
ComEd and PECO are each obligated to provide service to all customers within
their respective franchised territories. As a result, ComEd and PECO each have a
broad customer base. For the year ended December 31, 2000, ComEd's ten largest
customers represented approximately 3% of its retail electric revenues and
PECO's ten largest customers represented approximately 10% of its retail
electric revenues. Credit risk for Energy Delivery is managed by each company's
credit and collection policies which are regulated by their respective state
authorities.
Generation manages credit risk through established policies, including deposits
and letters of credit for counterparties to bilateral contractual arrangements.
For sales into the spot markets, the administrators (generally independent
system operators (ISOs)) of those markets maintain financial assurance policies
that are established and enforced by those administrators. Such policies may not
protect Generation from credit risk of load-serving entities purchasing services
in the spot markets, particularly load-serving entities that have a statutory
obligation to serve customers.
In the energy services and infrastructure businesses, credit risks are managed
through established credit and collection policies.
Interest Rate Risk
Exelon uses a combination of fixed rate and variable rate debt to reduce
interest rate exposure. Interest rate swaps may be used to adjust exposure when
deemed appropriate, based upon market conditions. These strategies are employed
to maintain the lowest cost of capital. As of December 31, 2000, a hypothetical
10% increase in the interest rates associated with variable rate debt would
result in an $11 million decrease in pre-tax earnings for 2001.
Exelon has entered into interest rate swaps to manage interest rate exposure
associated with the floating rate series of transition bonds issued to
securitize PECO's stranded cost recovery (Transition Bonds). At December 31,
2000, these interest rate swaps had a fair market value of $21 million based on
the present value difference between the contract and market rates at December
31, 2000.
The aggregate fair value of the Transition Bond derivative instruments that
would have resulted from a hypothetical 50 basis point decrease in the spot
yield at December 31, 2000 is estimated to be $17 million. If the derivative
instruments had been terminated at December 31, 2000, this estimated fair value
represents the amount to be paid by Exelon to the counterparties.
11
The aggregate fair value of the Transition Bond derivative instruments that
would have resulted from a hypothetical 50 basis point increase in the spot
yield at December 31, 2000 is estimated to be $59 million. If the derivative
instruments had been terminated at December 31, 2000, this estimated fair value
represents the amount to be paid by the counterparties to Exelon.
In February 2000, PECO entered into forward starting interest rate swaps for a
notional amount of $1 billion in anticipation of the issuance of $1 billion of
Series 2000-A Transition Bonds in the second quarter of 2000. In May 2000, PECO
settled these forward starting interest rate swaps and paid the counterparties
$13 million which was deferred and is being amortized over the life of the
Series 2000-A Transition Bonds as an increase in interest expense.
Equity Price Risk
Exelon maintains trust funds, as required by the Nuclear Regulatory Commission
(NRC), to fund certain costs of decommissioning its nuclear plants. As of
December 31, 2000, these funds were invested primarily in domestic equity
securities and fixed rate, fixed income securities and are reflected at fair
value on the Consolidated Balance Sheets. The mix of securities is designed to
provide returns to be used to fund decommissioning and to compensate for
inflationary increases in decommissioning costs. However, the equity securities
in the trusts are exposed to price fluctuations in equity markets, and the value
of fixed rate, fixed income securities are exposed to changes in interest rates.
Exelon actively monitors the investment performance and periodically reviews
asset allocation in accordance with Exelon's nuclear decommissioning trust
investment policy. A hypothetical 10% increase in interest rates and decrease in
equity prices would result in a $224 million reduction in the fair value of the
trust assets. PECO's restructuring settlement agreement provides for the
collection of authorized nuclear decommissioning costs through the CTC.
Additionally, PECO is permitted to seek recovery from customers of any increases
in these costs. To fund nuclear decommissioning costs, ComEd is permitted to
recover $73 million annually through 2006, subject to adjustment in 2005 and
2006 based upon nuclear plant usage to serve ComEd customers.
Outlook
Changes in the Utility Industry
The electric utility industry historically has consisted of vertically
integrated companies which combine generation, transmission and distribution
assets, serve customers within relatively defined service territories, and
operate under extensive Federal and state regulation of rates, operations and
other matters. Rate regulation of the utility industry is based on recovery of
prudently incurred investments and operating costs plus a return on invested
capital. The ability of utilities to recover their investment and other costs
through rates provided a relatively stable financial environment for electric
utilities.
The Federal Energy Policy Act of 1992, among other things, empowered FERC to
introduce a greater level of competition into the wholesale marketplace for
electric energy. Under FERC Order No. 888, utilities are required to file
open-access tariffs for their transmission systems. In addition to Federal rules
introducing a greater level of wholesale competition, a number of states,
including Pennsylvania and Illinois, have adopted legislation to introduce
retail competition into the electric industry. The focus of both the Federal and
state initiatives to replace rate regulation with competition has been to
disaggregate regulated, unified electric service into distribution, transmission
and generation services, and to allow competition for generation services.
Distribution and transmission services remain regulated by state and Federal
regulatory authorities.
While significant steps have been taken to increase competition for generation
of electricity, the level of competition varies greatly from state to state.
Some states, such as Illinois and Pennsylvania, have adopted extensive
restructuring initiatives, while other states have done little or nothing to
introduce competition. Additionally, the transition to competition has been
difficult in some states, such as California, where the regulatory structures
adopted are perceived to be flawed.
12
Exelon's ability to develop a competitive energy business depends, in large
part, on new and continuing regulatory restructuring initiatives. Exelon's
ability to grow may be hindered if some states refrain from introducing
competition as a response to difficulties encountered in California and
elsewhere. In addition, the patchwork of inconsistent state regulations
restructuring the electric industry may limit Exelon's ability to compete as a
generator of electricity and as a seller of unregulated energy services.
National legislation that seeks to address concerns arising out of perceived
shortcomings of restructuring initiatives in some states could either restrict
or enhance Exelon's ability to compete.
Exelon believes that competition for electric generation services has created
new uncertainties. These uncertainties include future prices of generation
services in both the wholesale and retail markets, supply and demand volatility,
and changes in customer profiles that may impact the margins on various varying
electric service offerings. As a result, Exelon may be able to achieve greater
rates of return, but it will also face an increased risk of being unable to
cover its costs, as the generation markets become more competitive.
Merger and Restructuring
Deregulation in the electric industry, as in most other industries that have
deregulated, has resulted in substantial consolidation of entities within the
industry in order for those entities to pursue new strategies presented by
competition and to achieve economies of scale. Exelon believes that the
consolidation and transformation of the electric and natural gas segments of the
energy industry will result in the emergence of a limited number of substantial
competitors. These large entities will have assets and skills necessary to
create value in one or more of the traditional segments of the utility industry.
Exelon believes that companies that have the financial strength, strategic
foresight and operational skills to establish scale and early leadership
positions in key segments of the energy industry will be in the best position to
compete in the new marketplace.
As a result of the merger of Unicom and PECO, Exelon is one of the largest
utilities in the United States, with annualized sales of over 120,000
gigawatthours. Management of Exelon believes that the merger will provide
substantial strategic and financial benefits to shareholders, employees and
customers. The benefits include expanded generation capacity, an enhanced power
marketing business, a broadened distribution platform, strategic fit and
compatibility, a foundation for growth of unregulated businesses and cost
savings. Exelon's future financial condition and results of operations are, in
large part, dependent upon its ability to realize the anticipated benefits of
the merger.
In connection with the regulatory approvals of the merger, Exelon received
authorization to restructure its operations. During January 2001, Exelon
undertook a restructuring to separate Exelon's generation and other competitive
businesses from its regulated energy delivery business. In addition, Exelon
formed Exelon Business Services Company, which provides a full range of support
services to Exelon's business units, such as legal, human resources and
financial services. Exelon anticipates that additional steps will be taken to
restructure the operations of its energy delivery business. Exelon's future
results of operations are dependent on its ability to combine the parallel
business units that previously were part of Unicom or PECO into integrated
business units with a larger scale and geographical scope, while maintaining the
benefits previously realized through the combination of energy delivery,
generation and enterprises businesses within a single corporation. Consolidating
functions and integrating organizations, procedures and operations in a timely
and efficient manner will be a challenge for Exelon, particularly in light of
the continuing changes in the energy industry.
Energy Delivery
Exelon believes that its energy delivery business will provide a significant and
steady source of earnings for reinvestment in growth opportunities. Exelon's
primary goals for its energy delivery companies, ComEd and PECO, are to deliver
reliable service, to improve customer service and to sustain productive
regulatory relationships. Achieving these goals is expected to maximize the
value of Exelon's energy delivery assets.
13
Electric Distribution
ComEd's and PECO's distribution rates are assessed on a per kilowatthour basis.
Consequently, revenues from distribution service are dependent on usage levels
of customers, which are in turn affected by weather and economic activity in the
franchised service territories. Electric utility restructuring legislation was
adopted in Pennsylvania in December 1996 and in Illinois in December 1997. Both
states, through their regulatory agencies, established a phased approach to
competition, allowing customers to choose an alternative electric supplier;
required rate reductions and imposed caps on rates during a transition period;
and allowed the collection of CTCs from customers to recover stranded costs.
Under the restructuring regulations adopted at the Federal and state levels, the
role of electric utilities in the supply and delivery of energy is changing.
ComEd and PECO continue to be obligated to provide a reliable delivery system
under cost-based rates. They are also obligated to supply generation service
during the transition period to a competitive supply marketplace to customers
who do not or cannot choose an alternate supplier. Retail competition for
generation services has resulted in reduced revenues from regulated rates and
the sale of increasing amounts of energy at market-based rates.
The rates for the generation service provided by ComEd and PECO are subject to
rate caps during the transition periods. PECO has entered into a long-term power
purchase agreement with Generation to obtain sufficient power at the rates it is
allowed to charge to serve customers who do not choose alternate generation
suppliers. ComEd has entered into a long-term power purchase agreement with
Generation to obtain sufficient power at fixed rates.
ComEd. Under the Illinois legislation, as of December 31, 2000, all
non-residential customers were eligible to choose a new electric supplier or
elect the purchase power option. The purchase power option allows the purchase
of electric energy from ComEd at market-based prices. ComEd's residential
customers become eligible to choose a new electric supplier or elect the
purchase power option in May 2002. As of December 31, 2000, over 9,500
non-residential customers, representing approximately 27% of ComEd's retail
kilowatthour sales for the twelve months prior to the introduction of
open-access, elected to receive their electric energy from an alternative
electric supplier or chose the purchase power option.
In addition to retail competition for generation services, the Illinois
legislation will affect ComEd's future operations through a 5% residential base
rate reduction that will become effective in October 2001, a base rate freeze
generally effective until at least January 1, 2005 and the collection of a CTC
from customers who choose to purchase electric energy from an alternative
supplier or elect the purchase power option during a transition period that
extends through 2006.
Effective October 1, 1999, the CTC was established in accordance with a formula
defined in the Illinois legislation. The CTC, which is applied on a cents per
kilowatthour basis, considers the revenue which would have been collected from a
customer under tariffed rates, reduced by the revenue the utility will receive
for providing delivery services to the customer, the market price for
electricity and a defined mitigation factor, which represents the utility's
opportunity to develop new revenue sources and achieve cost savings. The CTC
allows ComEd to recover some of its costs which might otherwise be unrecoverable
under market-based rates. If the earned return on common equity of ComEd during
the period ending December 31, 2004 exceeds an established threshold, one-half
of the excess earnings must be refunded to customers. The threshold rate of
return on common equity is based on the 30-Year Treasury Bond rate, plus 8.5% in
the years 2000 through 2004. Earnings for purposes of ComEd's rate cap include
ComEd's net income calculated in accordance with generally accepted accounting
principles and may include accelerated amortization of regulatory assets and the
amortization of goodwill. As a result of the Illinois restructuring legislation,
ComEd has recorded a $385 million regulatory asset that it expects to fully
recover and amortize by the end of 2003. ComEd does not currently expect to
trigger the earnings sharing provisions in the years 2001 through 2004.
As part of a settlement agreement between ComEd and the City of Chicago (City)
relating to the franchise agreement, ComEd and the City agreed to a revised
combination of ongoing work under the franchise
14
agreement and new initiatives that will result in defined transmission and
distribution expenditures by ComEd to improve electric service in the City. The
utility restructuring legislation in Illinois also committed ComEd to spend at
least $2 billion during the period 1999 through 2004 on transmission and
distribution facilities outside of the City. In addition, ComEd conducted an
extensive evaluation of the reliability of its transmission and distribution
systems in response to several outages in the summer of 1999. As a result of the
evaluation, ComEd has increased its construction and O&M expenditures on its
transmission and distribution facilities in order to improve their reliability.
As a result of ComEd's commitments to improve the reliability of its
transmission and distribution system, ComEd expects that its capital
expenditures will exceed depreciation on its rate base assets through at least
2002. The base rate freeze will generally preclude rate recovery on and of such
investments through 2006. Unless ComEd can offset the additional carrying costs
against cost savings, its return on investment will be reduced during the period
of the rate freeze and until rate increases are approved authorizing a return of
and on this new investment.
PECO. Retail competition for electric generation services began in Pennsylvania
on January 1, 1999, and by January 1, 2000 all of PECO's retail electric
customers had the right to choose their generation suppliers. In addition to
retail competition for generation services, PECO's settlement of its
restructuring case provided for the obligation of PECO to provide generation
services to customers who do not or cannot choose an alternate supplier through
December 31, 2010 and established caps on generation rates (consisting of the
charge for stranded cost recovery and the shopping credit) and transmission and
distribution rates until December 1, 2010, and June 30, 2005, respectively.
PECO's settlement of its restructuring case included a number of provisions
designed to encourage competition for generation services. The provisions
include above-market shopping credits for generation service which provide an
economic incentive for customers to choose an alternative supplier, periodic
assignments of a portion of PECO's non-shopping customers to alternative
suppliers and the selection of an alternative supplier as the provider of last
resort (PLR) for a portion of PECO's customers. At December 31, 2000,
approximately 18% of PECO's residential load, 46% of its commercial load and 42%
of its industrial load were purchasing generation service from an alternative
generation supplier.
PECO has been authorized to recover stranded costs of $5.3 billion over a
twelve-year period ending December 31, 2010 with a return on the unamortized
balance of 10.75%. PECO's recovery of stranded costs is based on the level of
transition charges established in the settlement of PECO's restructuring case
and the projected annual retail sales in PECO's service territory. Recovery of
transition charges for stranded costs and PECO's allowed return on its recovery
of stranded costs are included in operating revenue. In 2000, CTC revenue was
$628 million and is scheduled to increase to $932 million by 2010, the final
year of stranded cost recovery. Amortization of PECO's stranded cost recovery,
which is a regulatory asset, began in 2000 and is included in depreciation and
amortization. The amortization expense for 2000 was $57 million and will
increase to $879 million by 2010.
In connection with its request to securitize an additional $1 billion of its
stranded cost recovery, PECO agreed to provide its customers with additional
rate reductions of $60 million in 2001. Under the settlement agreement entered
into by PECO relating to the Pennsylvania Public Utility Commission's (PUC)
approval of the merger, PECO agreed to $200 million in aggregate rate reductions
for all customers over the period January 1, 2002 through 2005 and extended the
cap on PECO's transmission and distribution rates through December 31, 2006.
The cap on PECO's transmission and distribution rates through December 31, 2006
is subject to certain limited exceptions, including significant increases in
Federal or state taxes or other significant changes in law or regulations that
would not allow PECO to earn a fair rate of return. The cap on transmission and
distribution rates limits PECO's ability to recover increased costs and its
investments in new transmission and distribution facilities through rates.
Additionally, the rate reductions agreed to in connection with the merger with
Unicom will reduce PECO's earnings in future years unless those rate reductions
can be offset by cost savings resulting from the merger.
15
Under the Pennsylvania legislation, licensed entities, including alternative
generation suppliers, may act as agents to provide a single bill and provide
associated billing and collection services to retail customers located in PECO's
retail electric service territory. In that event, the alternative supplier or
other third party replaces the customer as the obligor with respect to the
customer's bill and PECO generally has no right to collect such receivable from
the customer. Third party billing would change PECO's customer profile (and risk
of non-payment by customers) by replacing multiple customers with the alternate
generation supplier providing third-party billing to those customers. To date,
no third parties are providing billing of PECO's charges to customers.
Natural Gas. On July 1, 2000, PECO implemented the Pennsylvania Natural Gas
Choice and Competition Act (Act) that was passed in 1999. The Act expands choice
of gas suppliers to residential and small commercial customers and eliminates
the 5% 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 PECO's total yearly throughput
is supplied by third parties.
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.
Exelon believes there will be no material impact on its financial condition or
operations 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.
Transmission. Energy Delivery also provides wholesale transmission service under
rates established by FERC. FERC has used its regulation of transmission to
encourage competition for wholesale generation services and the development of
regional structures to facilitate regional wholesale markets. In December 1999,
FERC issued Order No. 2000 (Order 2000) requiring jurisdictional utilities to
file a proposal to form a regional transmission organization (RTO) meeting
certain governance, operational, and scope and scale requirements articulated in
the order or, alternatively, to describe efforts to participate in or work
toward participating in an RTO or explain why they were not participating in an
RTO. Order 2000 is generally designed to separate the governance and operation
of the transmission system from generation companies and other market
participants. RTOs may be organized and may independently manage regional
transmission systems in a variety of ways, including through independent
for-profit or not-for-profit transmission companies, independent not-for-profit
system operators or ISOs (such as the Midwest Independent Transmission System
Operator (MISO)), as well as other structures. FERC has set December 15, 2001 as
the deadline for transferring control over transmission facilities to approved
RTOs.
ComEd has been a transmission-owning member of the MISO, a prospective RTO. On
October 31, 2000, ComEd announced its intention to join the Alliance Regional
Transmission Organization (Alliance), an RTO being established by utilities
generally located to the east of ComEd. Participation options in the Alliance
are being evaluated, including a transfer of the transmission assets for a
passive equity interest, leasing or a management-type arrangement. ComEd has
provided notice of its intention to withdraw from its membership in the MISO,
which withdrawal is needed in order to participate in the Alliance. As a result
of the merger, ComEd believes that its transmission facilities may be withdrawn
from participation in the MISO as of a date no later than October 31, 2001,
subject to FERC approval. In late February 2001, ComEd, the MISO and other
market participants reached a proposed settlement regarding ComEd's withdrawal
from the MISO. The proposed settlement is subject to FERC approval, which has
the power to accept, reject or make changes as a condition to its approval. If
the settlement is approved, ComEd will be permitted to withdraw from the MISO
and to join the Alliance. At present, ComEd believes it has established adequate
reserves for its portion of costs related to its withdrawal from the MISO.
16
PECO provides regional transmission service pursuant to a regional open-access
transmission tariff filed by it and the other transmission owners who are
members of PJM. PJM is a power pool that integrates, through central dispatch,
the generation and transmission operations of its member companies across a
50,000 square mile territory. Under the PJM tariff, transmission service is
provided on a region-wide, open-access basis using the transmission facilities
of the PJM members at rates based on the costs of transmission service. PJM's
Office of Interconnection is the ISO for PJM and is responsible for operation of
the PJM control area and administration of the PJM open-access transmission
tariff. PECO and the other transmission owners in PJM have turned over control
of their transmission facilities to the ISO. The PJM ISO and the transmission
owners who are members of PJM, including PECO, have filed with FERC for approval
of PJM as an RTO.
Generation
Exelon believes that its generation and power marketing business will be the
primary growth vehicle in the near term. Exelon's generation strategy is to
develop a national generation portfolio with fuel and dispatch diversity, to
recognize the cost savings and operational benefits of owning and operating
substantial generating capacity and to optimize the value of Exelon's low-cost
generating capacity through power marketing expertise.
Generation competes nationally in the wholesale electric generation markets on
the basis of price and service offerings, utilizing its generation portfolio to
assure customers of energy deliverability. Generation's generating capacity is
primarily located in the Midwest, Mid-Atlantic and Northeast regions. Generation
owns a 50% interest in AmerGen and a 49.9% interest in Sithe. Generation has
agreed to supply ComEd and PECO with their respective load requirements for
customers through 2006 and 2010, respectively. Generation has also contracted
with Exelon Energy to meet its load requirements pursuant to its competitive
retail generation sales agreements. In addition, Generation has contracts to
sell energy and capacity to third parties. To the extent that Generation's
resources exceed its contractual commitments, it markets these resources on a
short-term basis or sells them in the spot market. Generation's future results
of operations are dependent upon its ability to operate its generating
facilities efficiently to meet its contractual commitments and to sell energy
services in the wholesale markets. A substantial portion of Generation's
capacity, including all of the nuclear capacity, is base load generation
designed to operate for extended periods of time at low marginal costs. Nuclear
generation is currently the most effective way for Generation to meets its
commitments for sales to Energy Delivery and other utilities. During 2000, the
nuclear generating facilities now owned by Generation operated at a 94% weighted
average capacity factor. To meet its long-term commitments to provide energy,
including its commitment to meet the PLR load obligations of PECO and ComEd,
Generation must operate its nuclear generating facilities at planned capacity
levels which are at or above 90% for each of the years 2001 through 2003.
Failure to achieve these capacity levels would require Generation to contract or
purchase in the spot market more expensive energy to meet these commitments.
Because of Generation's reliance on nuclear facilities, any changes in
regulations by the NRC requiring additional investments or resulting in
increased operating or decommissioning costs of nuclear generating units could
adversely affect Generation.
The future growth of Generation is dependent upon its ability to acquire
additional generating capacity and to successfully develop additional capacity.
Growth is also dependent upon the power marketing activity of Generation.
Through its Power Team, Generation enters into short-term and long-term
contracts to purchase and sell energy and energy-related services. Power Team
relies on its unique market knowledge. Generation's power marketing operations
are dependent upon continued development of the wholesale energy market and
Power Team's ability to manage trading and credit risks in those markets.
Generation's power marketing activities include short-term and long-term
commitments to purchase and sell energy and related energy products and to
purchase transmission service to deliver power. See Note 18 of the Notes to
Consolidated Financial Statements.
Because of its substantial ownership interest in generation and investments in
AmerGen and Sithe, Generation utilizes contracts for the forward sale and
purchase of energy to manage its available generation capacity and its physical
delivery obligations to wholesale and retail customers. As a result, increased
costs
17
of operating its generating facilities or depressed prices in the wholesale
market will adversely affect its results of operations. While Generation
attempts to enter into bilateral contracts for the majority of its generation,
it also participates in the spot markets in the Northeast. These markets are
newly created, are continuing to develop and are subject to significant price
volatility. The spot markets also involve the credit risks of market
participants purchasing energy which Generation may not be able to manage or
hedge. Likewise, investments in new generation, whether purchased or developed,
are dependent upon the future success of both the bilateral and spot energy
wholesale markets.
During 2001, Generation intends to pursue financial trading, primarily to
complement the marketing of its generation portfolio. Generation intends to
manage the risk of these activities through a mix of long-term and short-term
supply obligations and through the use of established policies, procedures and
trading limits. Financial trading, together with the effects of the adoption of
Statement of Financial Accounting Standards (SFAS) No. 133, may cause volatility
in Exelon's future results of operations.
Enterprises
Enterprises consists primarily of Exelon Infrastructure Services, Inc. (EIS),
the infrastructure services business, Exelon Services, the energy services
business, Exelon Energy, the competitive retail energy sales business and Exelon
Thermal, a district cooling company. Enterprises also invests in new
entrepreneurial companies seeking opportunities arising from deregulation.
The results of EIS and Exelon Services are dependent on continued restructuring
of the electric utility industry and growth of the communications, cable and
internet industries which have resulted in demand for outsourced construction
and maintenance services. Exelon anticipates that EIS and Exelon Services will
each continue to acquire other similar service companies. Accordingly, their
results of operations will be dependent upon their ability to consolidate
acquired companies into a single company with larger scale and geographic scope.
Exelon Energy's business is dependent upon continued deregulation of retail
electric and gas markets and its ability to obtain supplies of electricity and
gas at competitive prices in the wholesale market.
Enterprises investments are weighted toward the communications industry, but
also include companies in energy services and retail services, including
e-commerce. Investments in the communications industries have included joint
ventures with established companies. Investments in other areas have generally
been in new ventures. Enterprises continually monitors the performance and
potential of its investments and evaluates opportunities to sell existing
investments and to make new investments. In the past, Exelon has been required
to write off or write down certain investments. The sale, write down, or write
off of investments may increase the volatility of earnings.
Other Factors
Annual operating results can be significantly affected by weather. Since
Exelon's peak retail demand is in the summer months, temperature variations in
summer months generally have a more significant impact on results of operations
than variations during winter months.
Inflation affects Exelon through increased operating costs and increased capital
costs for utility plant. As a result of the rate caps imposed under the
legislation in Illinois and Pennsylvania and price pressures due to competition,
Exelon may not be able to pass the costs of inflation through to customers.
Exelon's operations have in the past and may in the future require substantial
capital expenditures in order to comply with environmental laws. Additionally,
under Federal and state environmental laws, Exelon is generally liable for the
costs of remediating environmental contamination of property now or formerly
owned by Exelon and of property contaminated by hazardous substances generated
by Exelon. Exelon owns or leases a number of real estate parcels, including
parcels on which its operations or the operations of others may have resulted in
contamination by substances that are considered hazardous under environmental
18
laws. Exelon has identified 72 sites where former manufactured gas plant (MGP)
activities have or may have resulted in actual site contamination. Exelon is
currently involved in a number of proceedings relating to sites where hazardous
substances have been deposited and may be subject to additional proceedings in
the future.
As of December 31, 2000 and 1999, Exelon had accrued $172 million and $57
million, respectively, for environmental investigation and remediation costs,
including $140 million and $32 million, respectively, for MGP investigation and
remediation that currently can be reasonably estimated. The increases were
primarily attributable to the acquisition of Unicom. Exelon expects to expend
$27 million for environmental remediation activities in 2001. Exelon cannot
predict whether it will incur other significant liabilities for any additional
investigation and remediation costs at these or additional sites identified by
Exelon, environmental agencies or others, or whether such costs will be
recoverable from third parties.
For a discussion of other contingencies, see Note 18 of Notes to Consolidated
Financial Statements.
New Accounting Pronouncements
In June 1998, the Financial Accounting Standards Board (FASB) issued 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. 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," which
delayed the effective date for SFAS No. 133 until fiscal years beginning after
June 15, 2000. The effect of adopting SFAS No. 133 in the first quarter of 2001
will result in a cumulative after-tax increase in net income of approximately
$17 million and other comprehensive income of approximately $21 million. The
adoption will also impact the assets and liabilities recorded on the
Consolidated Balance Sheets of Exelon and may result in future earnings
volatility. The determination of the impact of SFAS No. 133 is based on current
interpretations of SFAS No. 133, including interpretations of the Derivatives
Implementation Group of the FASB, related to the treatment of electricity
capacity contracts. If final guidance, when issued, changes the treatment of
electricity capacity contracts, the effects of the implementation of SFAS No.
133 may differ from the amounts disclosed above.
In September 2000, the FASB issued SFAS No. 140, "Accounting for Transfers and
Servicing of Financial Assets and Extinguishments of Liabilities, a Replacement
of FASB Statement No, 125." This new standard revises the standards for
accounting for securitizations and other transfers of financial assets and
collateral and requires certain disclosures, but it carries over most of the
provisions of SFAS No. 125 without reconsideration. SFAS No. 140 provides
accounting and reporting standards for transfers and servicing of financial
assets and extinguishments of liabilities. SFAS No. 140 is effective for
transfers and servicing of financial assets and extinguishments of liabilities
occurring after March 31, 2001 and should be applied prospectively. At December
31, 2000, Exelon did not anticipate entering into any transactions that would be
subject to the provisions of SFAS No. 140 when it becomes effective.
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 Note 18 of
Notes to Consolidated Financial Statements and other factors discussed in
Exelon'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. Exelon undertakes no obligation to publicly release any revision to
these forward-looking statements to reflect events or circumstances after the
date of this Report.
Exhibit 99-3
Exelon Corporation and Subsidiary Companies
Financial Statements and Supplementary Data
Report of Independent Accountants
To the Shareholders and
Board of Directors of
Exelon Corporation:
In our opinion, the accompanying consolidated balance sheets and related
consolidated statements of income, cash flows and changes in shareholders'
equity and comprehensive income present fairly, in all material respects, the
financial position of Exelon Corporation and Subsidiary Companies (Exelon) at
December 31, 2000 and December 31, 1999, and the results of their operations and
their cash flows for each of the three years in the period ended December 31,
2000 in conformity with accounting principles generally accepted in the United
States of America. These financial statements are the responsibility of Exelon's
management; our responsibility is to express an opinion on these financial
statements based on our audits. We conducted our audits of these statements in
accordance with auditing standards generally accepted in the United States of
America, which require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
As discussed in Note 1 to the consolidated financial statements, Exelon acquired
Unicom Corporation on October 20, 2000 in a business combination accounted for
under the purchase method of accounting. The results of Unicom Corporation are
included in the consolidated financial statements since the acquisition date.
As discussed in Note 4 to the consolidated financial statements, Exelon changed
its method of accounting for nuclear outage costs in 2000.
PricewaterhouseCoopers LLP
Chicago, Illinois
January 30, 2001, except for
Note 21 PETT Refinancing for
which the date is March 1, 2001
Page 2
Exelon Corporation and Subsidiary Companies
Consolidated Statements of Income
For the Years Ended December 31,
--------------------------------
2000 1999 1998
------- ------- -------
In Millions, except per share data
----------------------------------
Operating Revenues $ 7,499 $ 5,478 $ 5,325
Operating Expenses
Fuel and Purchased Power 2,606 2,152 1,811
Operating and Maintenance 2,310 1,454 1,198
Merger-Related Costs 276 -- --
Early Retirement and Separation Program -- -- 125
Depreciation and Amortization 458 237 643
Taxes Other Than Income 322 262 280
------- ------- -------
Total Operating Expenses 5,972 4,105 4,057
------- ------- -------
Operating Income 1,527 1,373 1,268
------- ------- -------
Other Income and Deductions
Interest Expense (608) (396) (331)
Distributions on Preferred Securities of Subsidiaries (24) (33) (44)
Equity in Earnings (Losses) of Unconsolidated Affiliates (41) (38) (54)
Other, Net 53 59 1
------- ------- -------
Total Other Income and Deductions (620) (408) (428)
------- ------- -------
Income Before Income Taxes, Extraordinary Items and
Cumulative Effect of a Change in Accounting Principle 907 965 840
Income Taxes 341 358 320
------- ------- -------
Income Before Extraordinary Items and Cumulative Effect
Of a Change in Accounting Principle 566 607 520
Extraordinary Items (net of income taxes of $2, $25, and
$14 for 2000, 1999, and 1998, respectively) (4) (37) (20)
Cumulative Effect of a Change in Accounting Principle
(net of income taxes of $16) 24 -- --
------- ------- -------
Net Income $ 586 $ 570 $ 500
======= ======= =======
Average Shares of Common Stock Outstanding 202 196 223
======= ======= =======
Earnings Per Share:
Basic:
Income Before Extraordinary Items and Cumulative
Effect of a Change in Accounting Principle $ 2.81 $ 3.10 $ 2.33
Extraordinary Items (0.02) (0.19) (0.09)
Cumulative Effect of a Change in Accounting Principle 0.12 -- --
------- ------- -------
Net Income $ 2.91 $ 2.91 $ 2.24
======= ======= =======
Diluted:
Income Before Extraordinary Items and Cumulative
Effect of a Change in Accounting Principle $ 2.77 $ 3.08 $ 2.32
Extraordinary Items (0.02) (0.19) (0.09)
Cumulative Effect of a Change in Accounting Principle 0.12 -- --
------- ------- -------
Net Income $ 2.87 $ 2.89 $ 2.23
======= ======= =======
Dividends Per Common Share $ 0.91 $ 1.00 $ 1.00
======= ======= =======
See Notes to Consolidated Financial Statements
Page 3
Exelon Corporation and Subsidiary Companies
Consolidated Statements of Cash Flows
For the Years Ended December 31,
--------------------------------
2000 1999 1998
---- ---- ----
(In Millions)
-----------
Cash Flows from Operating Activities
Net Income $ 586 $ 570 $ 500
Adjustments to reconcile Net Income to Net
Cash Flows provided by Operating Activities:
Depreciation and Amortization 607 358 765
Extraordinary Items (net of income taxes) 4 37 20
Cumulative Effect of a Change in Accounting
Principle (net of income taxes) (24) -- --
Provision for Uncollectible Accounts 89 59 72
Deferred Income Taxes 193 7 (115)
Merger-Related Costs 276 -- --
Early Retirement and Separation Program -- -- 125
Deferred Energy Costs (79) 23 6
Equity in (Earnings) Losses of Unconsolidated Affiliates 41 38 54
Other Operating Activities (87) 6 (22)
Changes in Working Capital:
Accounts Receivable (445) (159) 3
Repurchase of Accounts Receivable (50) (150) --
Inventories 49 (43) 14
Accounts Payable, Accrued Expenses, & Other Current Liabilities (35) 149 63
Other Current Assets (29) (12) 1
------- ------- -------
Net Cash Flows provided by Operating Activities 1,096 883 1,486
Cash Flows from Investing Activities
Investment in Plant (752) (491) (415)
Unicom Merger Consideration (507) -- --
Proceeds from Direct Financing Leases 1,228 -- --
Investment in Sithe Energies, Inc. (704) -- --
Exelon Infrastructure Services Acquisitions (245) (222) --
Investments in and Advances to Joint Ventures -- (118) (59)
Contributions to Nuclear Decommissioning Trust Funds (115) (26) (21)
Other Investing Activities (108) (29) (26)
------- ------- -------
Net Cash Flows used in Investing Activities (1,203) (886) (521)
Cash Flows from Financing Activities
Issuance of Long-Term Debt, net of issuance costs 1,021 4,170 13
Common Stock Repurchases (496) (1,705) --
Retirement of Long-Term Debt (665) (1,343) (842)
Change in Short-Term Debt 10 (388) 124
Redemption of Preferred Securities of Subsidiaries (19) (258) (81)
Issuance of Preferred Securities of Subsidiaries -- -- 78
Dividends on Common Stock (157) (196) (223)
Capital Lease Payments -- (139) (60)
Other Financing Activities 51 42 41
------- ------- -------
Net Cash Flows provided by (used in) Financing Activities (255) 183 (950)
------- ------- -------
Increase (Decrease) in Cash and Cash Equivalents (362) 180 15
Cash and Cash Equivalents at beginning of period 228 48 33
Cash Acquired in Unicom Merger 974 -- --
------- ------- -------
Cash and Cash Equivalents at end of period $ 840 $ 228 $ 48
======= ======= =======
See Notes to Consolidated Financial Statements
Page 4
Exelon Corporation and Subsidiary Companies
Consolidated Balance Sheets
At December 31,
2000 1999
-------- --------
Assets (In Millions)
-----------
Current Assets
Cash and Cash Equivalents $ 840 $ 228
Accounts Receivable, net
Customer 2,137 344
Other 415 360
Inventories, at average cost
Fossil Fuel 157 113
Materials and Supplies 297 93
Deferred Income Taxes 62 --
Other 276 83
-------- --------
Total Current Assets 4,184 1,221
-------- --------
Property, Plant and Equipment, net 12,936 5,004
Deferred Debits and Other Assets
Regulatory Assets 7,135 6,072
Nuclear Decommissioning Trust Funds 3,109 408
Investments 1,583 130
Goodwill, net 5,186 121
Other 464 131
-------- --------
Total Deferred Debits and Other Assets 17,477 6,862
-------- --------
Total Assets $ 34,597 $ 13,087
======== ========
Liabilities and Shareholders' Equity
Current Liabilities
Notes Payable, Bank $ 1,373 $ 163
Long-Term Debt Due Within One Year 908 128
Accounts Payable 1,193 270
Accrued Expenses 720 616
Deferred Income Taxes -- 14
Other 457 95
-------- --------
Total Current Liabilities 4,651 1,286
-------- --------
Long-Term Debt 12,958 5,969
Deferred Credits and Other Liabilities
Deferred Income Taxes 4,409 2,411
Unamortized Investment Tax Credits 330 286
Nuclear Decommissioning Liability for Retired Plants 1,301 --
Pension Obligations 567 213
Non-Pension Postretirement Benefits Obligation 819 443
Spent Nuclear Fuel Obligation 810 --
Other 907 385
-------- --------
Total Deferred Credits and Other Liabilities 9,143 3,738
-------- --------
Preferred Securities of Subsidiaries 630 321
Commitments and Contingencies
Shareholders' Equity
Common Stock 6,883 3,577
Deferred Compensation -- (3)
Retained Earnings(Accumulated Deficit) 332 (100)
Treasury Stock, at cost -- (1,705)
Accumulated Other Comprehensive Income -- 4
-------- --------
Total Shareholders' Equity 7,215 1,773
-------- --------
Total Liabilities and Shareholders' Equity $ 34,597 $ 13,087
======== ========
See Notes to Consolidated Financial Statements
Page 5
Exelon Corporation and Subsidiary Companies
Consolidated Statements of Changes in Shareholders' Equity and Comprehensive Income
Year Ended December 31, 2000 1999 1998
- ----------------------- ---- ---- ----
Shares Amount Shares Amount Shares Amount
------ ------ ------ ------ ------ ------
(dollars in millions and shares in thousands)
Common Stock
- ------------
Balance at Beginning of Year 225,354 $3,577 224,684 $3,558 222,547 $3,507
Capital Stock Activity:
Cancellation of Treasury Shares (54,875) (2,175) -- --
Long Term Incentive Plan Issuances 563 67 670 19 2,137 51
Reorganization Pursuant to Share Exchange (7) -- --
Shares Issued to Acquire Unicom 147,963 5,310 -- --
Merger Consideration - Stock Options 111 -- --
---------------------------------------------------------------
Balance at End of Year 319,005 $6,883 225,354 $3,577 224,684 $3,558
Deferred Compensation
- ---------------------
Balance at Beginning of Year $(3) $-- $--
Amortization 5 2 --
Long Term Incentive Plan Issuances (9) (5) --
Reorganization Pursuant to Share Exchange 7 -- --
------------------------------------------------------
Balance at End of Year $-- $(3) $--
Retained Earnings(Accumulated Deficit)
- --------------------------------------
Balance at Beginning of Year $(100) $(501) $(781)
Net Income 586 570 500
Dividends:
Common Stock (157) (196) (223)
Capital Stock Activity:
Expenses of Capital Stock Activity -- -- 3
Stock Forward Repurchase Contract (5) 12 (8)
Long Term Incentive Plan Issuances 8 15 8
------------------------------------------------------
Balance at End of Year $332 $(100) $(501)
Treasury Shares
- ---------------
Balance at Beginning of Year 44,082 $(1,705) $-- $--
Capital Stock Activity:
Repurchase of Common Stock 11,950 (496) 22,610 (1,009) --
Stock Forward Repurchase Contract -- 21,489 (696) --
Long Term Incentive Plan Issuances (195) 7 -- --
Stock Option Exercises (962) 19 (17) -- --
Cancellation of Treasury Shares (54,875) 2,175 -- --
-------------------------------------------------------------
Balance at End of Year -- $-- 44,082 $(1,705) $--
Accumulated Other Comprehensive Income
- --------------------------------------
Balance at Beginning of Year $4 $-- $--
Unrealized Gain(Loss) on Marketable Securities,
net of income taxes of $(3), $3,
and $0, respectively (4) 4 --
------------------------------------------------------
Balance at End of Year $-- $4 $--
Total Shareholders' Equity $7,215 $1,773 $3,057
====== ====== ======
Comprehensive Income
- --------------------
Net Income $586 $570 $500
Other Comprehensive Income, net of income taxes (4) 4 --
---------- ---------- ----------
Total Comprehensive Income $582 $574 $500
========== ========== ==========
See Notes to Consolidated Financial Statements
Page 6
Exelon Corporation and Subsidiary Companies
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data unless otherwise noted)
1. Significant Accounting Policies
Description of Business
On October 20, 2000, Exelon Corporation (Exelon) became the parent
corporation for each of PECO Energy Company (PECO) and Commonwealth Edison
Company (ComEd). See Note 2 - Merger. Exelon is a utility services holding
company engaged, through its subsidiaries, in the production, purchase,
transmission, distribution and sale of electricity to 5 million retail
customers, and the distribution and sale of natural gas to 425,000 retail
customers. Exelon's retail electric service territories are located principally
in southeastern Pennsylvania, including the City of Philadelphia, and northern
Illinois, including metropolitan Chicago. Exelon also engages in the wholesale
marketing of electricity, the provision of utility infrastructure,
communications and other utility related services in various regions of the
United States.
Basis of Presentation
The consolidated financial statements of Exelon include the accounts of
its majority-owned subsidiaries after the elimination of intercompany
transactions. Exelon accounts for its 20% to 50% owned investments and joint
ventures, in which it exerts significant influence, under the equity method of
accounting. Exelon consolidates its proportionate interest in its jointly owned
electric utility plants. Exelon accounts for its less than 20% owned investments
under the cost method of accounting. Accounting policies for regulated
operations are in accordance with those prescribed by the regulatory authorities
having jurisdiction, principally the Pennsylvania Public Utility Commission
(PUC), the Illinois Commerce Commission (ICC), the Federal Energy Regulatory
Commission (FERC) and the Securities and Exchange Commission (SEC) under the
Public Utility Holding Company Act of 1935 (PUHCA).
Exelon, formed as a wholly owned subsidiary of PECO in 1999, became the
parent company of PECO when each share of outstanding common stock of PECO was
exchanged for one share of Exelon common stock in connection with the merger.
See Note 2 - Merger. In addition, for accounting purposes, PECO was deemed the
acquiror in the merger. Accordingly, the financial statements for the periods
presented represent the historical financial statements of PECO pursuant to the
reorganization and the historical information of the former Unicom entity from
October 20, 2000 reflecting the acquisition.
Accounting for the Effects of Regulation
Exelon accounts for all of its regulated electric and gas operations in
accordance with Statement of Financial Accounting Standards (SFAS) No. 71,
"Accounting for the Effects of Certain Types of Regulation," requiring Exelon to
record the financial statement effects of the rate regulation to which such
operations are currently subject. Use of SFAS No. 71 is applicable to the
utility operations of Exelon that meet the following criteria: (1) third-party
regulation of rates; (2) cost-based rates; and (3) a reasonable assumption that
all costs will be recoverable from customers through rates. Exelon believes that
it is probable that regulatory assets associated with these operations will be
recovered. If a separable portion of Exelon's business no longer meets the
provisions of SFAS No. 71, Exelon is required to eliminate the financial
statement effects of regulation for that portion.
Use of Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
Page 7
Revenues
Operating revenues are generally recorded as service is rendered or
energy is delivered to customers. At the end of each month, Exelon accrues an
estimate for the unbilled amount of energy delivered or services provided to its
electric and gas customers. Exelon recognizes contract revenue and profits on
long-term fixed-price contracts from its services businesses by the
percentage-of-completion method of accounting based on costs incurred as a
percentage of estimated total costs of individual contracts.
Purchased Gas Adjustment Clause
PECO's natural gas rates are subject to a fuel adjustment clause
designed to recover or refund the difference between the actual cost of
purchased gas and the amount included in base rates. Differences between the
amounts billed to customers and the actual costs recoverable are deferred and
recovered or refunded in future periods by means of prospective quarterly
adjustments to rates.
Nuclear Fuel
The cost of nuclear fuel is capitalized and charged to fuel expense
using the unit of production method. Estimated costs of nuclear fuel disposal
are charged to fuel expense as the related fuel is consumed.
Depreciation, Amortization and Decommissioning
Depreciation is provided over the estimated service lives of property,
plant and equipment on a straight line basis. Annual depreciation provisions for
financial reporting purposes, expressed as a percentage of average service life
for each asset category are presented below:
Asset Category 2000 1999 1998
-------------- ---- ---- ----
Electric -- Transmission and Distribution 4.16% 1.83% 1.96%
Electric -- Generation 5.02% 5.12% 5.26%
Gas 2.39% 2.36% 2.40%
Common 2.10% 2.13% 4.54%
Other Property and Equipment 8.11% 8.61% 2.80%
Amortization of regulatory assets is provided over the recovery period
as specified in the related regulatory agreement. Goodwill associated with the
merger is being amortized on a straight line basis over 40 years. See Note 2 -
Merger. Goodwill associated with other acquisitions is being amortized over
periods from 10 to 20 years. Accumulated amortization of goodwill was $35
million and $1 million at December 31, 2000 and 1999, respectively.
Exelon's estimate of the costs for decommissioning its nuclear
generating stations is currently included in regulated rates. The amounts
recovered from customers are deposited in trust accounts and invested for
funding of future costs for current and retired plants. Exelon accounts for the
current period's cost of decommissioning by recording a charge to depreciation
expense and a corresponding liability in accumulated depreciation for its
operating nuclear units and a reduction to regulatory assets for its retired
units. Exelon believes that the amounts being recovered from customers through
electric rates along with the earnings on the trust funds will be sufficient to
fully fund its decommissioning obligations.
Capitalized Interest
Exelon uses SFAS No. 34, "Capitalizing Interest Costs," to calculate
the costs during construction of debt funds used to finance its non-regulated
construction projects. Exelon recorded capitalized interest of $2 million, $6
million and $7 million in 2000, 1999 and 1998, respectively.
Allowance for Funds Used During Construction (AFUDC) is the cost,
during the period of construction, of debt and equity funds used to finance
construction projects for regulated operations. AFUDC is recorded as a charge to
Construction Work in Progress and as a non-cash credit to AFUDC which is
included in Other Income and Deductions. The rates used for capitalizing AFUDC
are computed under a method prescribed by regulatory authorities.
Page 8
Income Taxes
Deferred Federal and state income taxes are provided on all significant
temporary differences between book bases and tax bases of assets and
liabilities, transactions that reflect taxable income in a year different from
book income and tax carryforwards. Investment tax credits previously utilized
for income tax purposes have been deferred on the Consolidated Balance Sheets
and are recognized in book income over the life of the related property. Exelon
and its subsidiaries file a consolidated Federal income tax return. Income taxes
are allocated to each of Exelon's subsidiaries within the consolidated group
based on the separate return method.
Gains and Losses on Reacquired Debt
Gains and losses on reacquired debt are recognized in Exelon's
Consolidated Statements of Income as incurred. Gains and losses on reacquired
debt related to regulated operations incurred prior to January 1, 1998, have
been deferred and are being amortized to interest expense over the period
approved for ratemaking purposes.
Comprehensive Income
Comprehensive income includes all changes in equity during a period
except those resulting from investments by and distributions to shareholders.
Comprehensive income is reflected in the Consolidated Statements of Changes in
Shareholders' Equity and Comprehensive Income.
Cash and Cash Equivalents
Exelon considers all temporary cash investments purchased with an
original maturity of three months or less to be cash equivalents.
Marketable Securities
Marketable securities are classified as available-for-sale securities
and are reported at fair value, with the unrealized gains and losses, net of
tax, reported in other comprehensive income. Unrealized gains and losses on
marketable securities held in the nuclear decommissioning trust funds are
reported in accumulated depreciation for operating units and as a reduction of
regulatory assets for retired units. At December 31, 2000 and 1999, Exelon had
no held-to-maturity or trading securities.
Property, Plant and Equipment
Property, plant and equipment is recorded at cost. Exelon evaluates the
carrying value of property, plant and equipment and other long-term assets based
upon current and anticipated undiscounted cash flows, and recognizes an
impairment when it is probable that such estimated cash flows will be less than
the carrying value of the asset. Measurement of the amount of impairment, if
any, is based upon the difference between carrying value and fair value. The
cost of maintenance, repairs and minor replacements of property are charged to
maintenance expense as incurred.
Upon retirement, the cost of regulated property plus removal costs less
salvage value, are charged to accumulated depreciation by the regulated
subsidiaries in accordance with the provisions of SFAS No. 71. For unregulated
property, the cost and accumulated depreciation of property, plant and equipment
retired or otherwise disposed of are removed from the related accounts and
included in the determination of the gain or loss on disposition.
Capitalized Software Costs
Costs incurred during the application development stage of software
projects for software which is developed or obtained for internal use are
capitalized. At December 31, 2000 and 1999, capitalized software costs totaled
$285 million and $105 million, respectively, net of $53 million and $32 million
accumulated amortization, respectively. Such capitalized amounts are amortized
ratably over the expected lives of the projects when they become operational,
not to exceed ten years. Certain capitalized software is being amortized over
fifteen years pursuant to regulatory approval.
Retail and Wholesale Energy Commitments
In the normal course of business, Exelon utilizes contracts for the
forward sale and purchase of energy to manage the utilization of its available
generating capability and provision of wholesale energy to
Page 9
its retail affiliates. Exelon also utilizes energy option contracts and energy
financial swap arrangements to limit the market price risk associated with the
forward energy commodity contracts. Through December 31, 2000, Exelon recognized
any gains or losses on forward commodity contracts when the underlying
transactions affect earnings. Revenues and expenses associated with market price
risk management contracts are amortized over the terms of such contracts.
At December 31, 2000, Exelon's retail and wholesale activities included
short-term and long-term commitments, which are carried at the lower of cost or
market, to purchase and sell energy and energy-related products in the retail
and wholesale markets with the intent and ability to deliver or take delivery.
Revenue and expense associated with energy commitments is reported at the time
the underlying physical transaction affects earnings.
Hedge Accounting
Hedge accounting is applied only if the derivative reduces the risk of
the underlying hedged item and is designated at inception as a hedge, with
respect to the hedged item. If a derivative instrument ceased to meet the
criteria for deferral, any gains or losses are recognized in income.
New Accounting Pronouncements
In June 1998, the Financial Accounting Standards Board (FASB) issued
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. 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," which
delayed the effective date for SFAS No. 133 until fiscal years beginning after
June 15, 2000. The effect of adopting SFAS No. 133 in the first quarter of 2001
will result in a cumulative after-tax increase in net income of approximately
$17 million and other comprehensive income of approximately $21 million. The
adoption will also impact the assets and liabilities recorded on the
Consolidated Balance Sheets of Exelon and may result in future earnings
volatility. The determination of the impact of SFAS No. 133 is based on current
interpretations of SFAS No. 133, including interpretations of the Derivatives
Implementation Group of the FASB, related to the treatment of electricity
capacity contracts. If final guidance, when issued, changes the treatment of
electricity capacity contracts, the effects of the implementation of SFAS No.
133 may differ from the amounts disclosed above.
In September 2000, the FASB issued SFAS No. 140, "Accounting for
Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,
a Replacement of FASB Statement No, 125." This new standard revises the
standards for accounting for securitizations and other transfers of financial
assets and collateral and requires certain disclosures, but it carries over most
of the provisions of SFAS No. 125without reconsideration. SFAS No. 140 provides
accounting and reporting standards for transfers and servicing of financial
assets and extinguishments of liabilities. SFAS No. 140 is effective for
transfers and servicing of financial assets and extinguishments of liabilities
occurring after March 31, 2001 and should be applied prospectively. At December
31, 2000, Exelon did not anticipate entering into any transactions that would be
subject to the provisions of SFAS No. 140 when it becomes effective.
Reclassifications
Dividends on preferred stock of PECO for 1999 and 1998 have been
reclassified to Distributions on Preferred Securities of Subsidiaries, resulting
in a deduction before, rather than after, net income. This reclassification
reflects the current organizational structure in which PECO is a subsidiary of
Exelon. Certain other prior year amounts have been reclassified for comparative
purposes.
Page 10
2. Merger
On October 20, 2000, Exelon became the parent corporation for each of
PECO and ComEd as a result of the completion of the transactions contemplated by
an Agreement and Plan of Exchange and Merger, as amended (Merger Agreement),
among PECO, Unicom Corporation (Unicom) and Exelon. Pursuant to the Merger
Agreement, (a) each share of outstanding common stock of PECO was exchanged for
one share of common stock of Exelon (Share Exchange) and (b) Unicom merged with
and into Exelon (Merger and together with the Share Exchange, Merger
Transaction). In the Merger Transaction, each share of the outstanding common
stock of Unicom was converted into 0.875 shares of common stock of Exelon plus
$3.00 in cash. Also pursuant to the Merger Agreement, PECO and Unicom
repurchased approximately $1.5 billion of common stock prior to the closing of
the Merger Transaction, with Unicom repurchasing approximately $1.0 billion of
its common stock, and PECO repurchasing approximately $500 million of its common
stock. As a result of the Share Exchange, Exelon became the owner of all of the
common stock of PECO. As a result of the Merger, Unicom ceased to exist and its
subsidiaries, including ComEd, became subsidiaries of Exelon.
The Merger was accounted for using the purchase method of accounting.
The total purchase price was $5,973 million. In connection with the Merger,
Exelon issued 148 million shares of common stock in the amount of $5,310 million
and paid $507 million in cash to Unicom shareholders pursuant to the terms of
the Merger Agreement. The source of the cash consideration was borrowings under
an Exelon term loan. In addition, the merger consideration included $111 million
of fair value of stock options and awards for certain Unicom employees and $45
million of direct acquisition costs. The cost in excess of net assets acquired
was $4,874 million, which will be amortized over forty years. Exelon's results
of operations include Unicom's results of operations since October 20, 2000. The
purchase price allocation is preliminary and further refinement may occur based
upon the final resolution of employee severance obligations. The fair value of
the assets acquired, including the cost in excess of net assets acquired, and
liabilities assumed in the Merger are as follows:
Current Assets (including cash of $974) $2,751
Property, Plant and Equipment 7,658
Deferred Debits and Other Assets 5,773
Cost in excess of net assets acquired 4,874
Current Liabilities (2,406)
Long-Term Debt (7,419)
Deferred Credits and Other Liabilities (4,930)
Preferred Securities of Subsidiaries (328)
------
Total purchase price $5,973
======
Selected unaudited pro forma combined results of operations for the
years ended December 31, 2000 and 1999, assuming the Merger Transaction occurred
on January 1, 2000 and 1999, respectively, are presented as follows:
2000 1999
---- ----
(unaudited)
Total revenues $13,508 $12,225
Net income $1,216 $1,156
Net income per common share (basic) $3.81 $3.62
Net income per common share (diluted) $3.77 $3.58
Merger related costs of $367 million ($220 million, net of income
taxes) or $0.69 per common share (basic) and $0.68 per common share (diluted)
have been excluded from the pro forma information above. Pro forma information
assumes the effects of Unicom's 1999 fossil plant sale and the issuance of
transition bonds and notes occurred at the beginning of 1999. The pro forma
financial information is not necessarily indicative of the operating results
that would have occurred had the Merger Transaction been consummated as of the
dates indicated, nor are they necessarily indicative of future operating
results.
Page 11
Merger-Related Costs
In association with the Merger Transaction, Exelon recorded certain
reserves for restructuring costs. The reserves associated with PECO were charged
to expense, while the reserves associated with Unicom were recorded as part of
the application of purchase accounting and did not affect results of operations.
Merger-related costs charged to expense in 2000 were $276 million
consisting of $152 million of direct incremental costs and $124 million for
employee costs. Direct incremental costs represent expenses directly associated
with completing the Merger Transaction, including professional fees, regulatory
approval and settlement costs, and settlement of compensation arrangements.
Employee costs represent estimated severance payments and pension and
postretirement benefits provided under Exelon's Merger Separation Plan (MSP) for
eligible employees who are expected to be involuntarily terminated before
October 2002 due to integration activities of the merged companies.
Included in the purchase price allocation is a liability for exit costs
of $307 million for additional employee costs and additional liabilities of
approximately $39 million for estimated costs of exiting various business
activities of former Unicom activities that were not compatible with the
strategic business direction of Exelon. The employee costs include employee
severance, actuarially determined pension and post-retirement costs, and
relocation and other benefits of $128 million, $158 million and $21 million,
respectively. The involuntary terminations are a result of merger integration
and reengineering of processes, primarily in the areas of corporate support,
generation, and energy delivery. The $307 million estimated liability is subject
to a final determination of the level of benefits to be provided to a portion of
the employees whose positions are expected to be eliminated as a result of the
merger but are not eligible for the MSP. Adjustments to the liability to reflect
final determination of benefit levels will be recorded as an adjustment to
goodwill.
Approximately 2,900 positions have been identified to be eliminated as
a result of the Merger Transaction. Exelon anticipates that $282 million of
employee costs will be funded from its pension and postretirement benefit plans
and $149 million will be funded from general corporate funds. At December 31,
2000, the reserve balance for employee severance, relocation and other benefits
was $144 million and is expected to be expended by October 2002.
3. Acquisitions
Sithe Energies, Inc. Acquisition
On December 18, 2000, Exelon acquired 49.9% of the outstanding common
stock of Sithe Energies, Inc. (Sithe) for $704 million, with an option to
purchase the remaining common stock outstanding exercisable between December
2002 and December 2005, at a price to be determined based on prevailing market
conditions.
Sithe is an independent power generator in North America utilizing
primarily fossil and hydro generation. The purchase involves approximately
10,000 megawatts (MW) of generation consisting of 3,800 MW of existing merchant
generation, 2,500 MW under construction, and another 3,700 MW of generation in
various stages of development, as well as Sithe's domestic marketing and
development businesses. The generation assets are located primarily in
Massachusetts and New York, but also include plants in Pennsylvania, California,
Colorado and Idaho, as well as Canada and Mexico.
Exelon Infrastructure Services, Inc. Acquisitions
In 2000, Exelon Infrastructure Services, Inc. (EIS), an unregulated
majority owned subsidiary of Exelon, acquired the stock or assets of seven
utility service contracting companies for an aggregate purchase price of
approximately $245 million, net of cash acquired of $9 million, including EIS
common stock valued at $14 million. The acquisitions were accounted for using
the purchase method of accounting. The initial estimate of the excess of
purchase price over the fair value of net assets acquired was approximately $216
million.
Page 12
The allocation of purchase price to the fair value of assets acquired
and liabilities assumed in these acquisitions is as follows:
Current Assets (net of cash acquired) $ 63
Property, Plant and Equipment 17
Cost in excess of net assets acquired 216
Current Liabilities (51)
------
Total $ 245
=====
Cost in excess of net assets acquired associated with EIS acquisitions
is being amortized over 20 years.
At December 31, 2000 and 1999, Current Assets includes $70 million and
$48 million, respectively, of Costs and Earnings in Excess of Billings on
uncompleted contracts and Current Liabilities includes $23 million and $9
million, respectively, of Billings and Earnings in Excess of Costs on
uncompleted contracts.
AmerGen Energy Company, LLC
In August 2000, AmerGen Energy Company LLC (AmerGen), a joint venture
with British Energy, Inc., a wholly owned subsidiary of British Energy plc,
(British Energy), completed the purchase of Oyster Creek Nuclear Generating
Facility (Oyster Creek) from GPU, Inc. (GPU) for $10 million. Under the terms of
the purchase agreement, GPU agreed to fund outage costs not to exceed $89
million, including the cost of fuel, for a refueling outage that occurred in
2000. AmerGen will repay these costs to GPU in nine equal annual installments
beginning in August 2001. In addition, AmerGen assumed full responsibility for
the ultimate decommissioning of Oyster Creek. At the closing of the sale, GPU
provided funding for the decommissioning trust of $440 million. In conjunction
with this acquisition, AmerGen has received a fully funded decommissioning trust
fund which has been computed assuming the anticipated costs to appropriately
decommission Oyster Creek discounted to net present value using the NRC's
mandated rate of 2%. AmerGen believes that the amount of the trust fund and
investment earnings thereon will be sufficient to meet its decommissioning
obligation. GPU is purchasing the electricity generated by Oyster Creek pursuant
to a three-year power purchase agreement.
4. Accounting Change
During the fourth quarter of 2000, as a result of the synchronization
of accounting policies with Unicom in connection with the Merger Transaction,
PECO changed its method of accounting for nuclear outage costs to record such
costs as incurred. Previously, PECO accrued these costs over the operating unit
cycle. As a result of the change in accounting method for nuclear outage costs,
PECO recorded income of $24 million, net of income taxes of $16 million. The
change is reported as a cumulative effect of a change in accounting principle on
the Consolidated Statements of Income as of December 31, 2000, representing the
balance of the nuclear outage cost reserve at January 1, 2000. On a pro forma
basis, Exelon reported net income for 1999 and 1998 would have been decreased by
$6 million, or $0.03 per diluted share and increased by $11 million, or $0.05
per diluted share, respectively.
Page 13
5. Regulatory Issues
ComEd
In 2000, the phased process to implement competition in the electric
industry continued as mandated by the requirements of the Illinois restructuring
legislation.
Customer Choice
As of December 31, 2000, all non-residential customers were eligible to
choose a new electric supplier or elect the purchase power option which allows
the purchase of electric energy from ComEd at market-based prices. ComEd's
residential customers become eligible to choose a new electric supplier or elect
the purchase power option in May 2002. As of December 31, 2000, over 9,500
non-residential customers, representing approximately 27% of ComEd's retail
kilowatthour sales for the twelve months prior to the introduction of
open-access, had elected to receive their electric energy from a residential
electric supplier or had chosen the purchase power option. ComEd is unable to
predict the long term impact of customer choice on results of operations.
Rate Reductions and Caps
The Illinois restructuring legislation also provided a 15% residential
base rate reduction effective August 1, 1998 with an additional 5% residential
base rate reduction to be implemented in October 2001. Notwithstanding the rate
reduction and subject to certain earnings tests, a rate freeze will generally be
in effect until at least January 1, 2005. A utility may request a rate increase
during the rate freeze period only when necessary to ensure the utility's
financial viability. Under the Illinois restructuring legislation, if the earned
return on common equity of a utility during this period exceeds an established
threshold, one-half of the excess earnings must be refunded to customers. The
threshold rate of return on common equity is based on the 30-Year Treasury Bond
rate plus 8.5% in the years 2000 through 2004. Earnings for purposes of ComEd's
rate cap include ComEd's net income calculated in accordance with generally
accepted accounting principles and may include accelerated amortization of
regulatory assets and the amortization of goodwill. As a result of the Illinois
restructuring legislation, ComEd has recorded a $385 million regulatory asset
that it expects to fully recover and amortize by the end of 2003. The utility's
earned return on common equity and the threshold return on common equity for
ComEd are each calculated on a two-year average basis. The earnings sharing
provision is applicable only to ComEd's earnings. ComEd did not trigger in 2000
and does not currently expect to trigger the earnings sharing provisions of the
Illinois restructuring legislation in the years 2001 through 2004.
PECO
In 2000, the phased process to implement competition in the electric
industry continued as mandated by the requirements of the PUC's Final
Restructuring Order.
Customer Choice
The PUC's Final Restructuring Order provided for the phase-in of
customer choice of electric generation supplier (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 remaining one-third on January 1, 2000. The Final
Restructuring Order also established market share thresholds to ensure that a
minimum number of residential and commercial customers choose an EGS or a PECO
affiliate. If less than 35% and 50% of residential and commercial customers have
chosen an EGS, including residential customers assigned to an EGS as a provider
of last resort default supplier, by January 1, 2001 and January 1, 2003,
respectively, the number of customers sufficient to meet the necessary threshold
levels shall be randomly selected and assigned to an EGS through a
PUC-determined process. On January 1, 2001, the 35% threshold was met for all
three customer classes as a result of agreements assigning customers to New
Power Company and Green Mountain as providers of last resort default service. At
December 31, 2000, approximately 18% of PECO's residential load, 46% of its
commercial load and 42% of its industrial load were purchasing generation from
an alternative generation supplier.
Page 14
Rate Reductions and Caps
Under the Final Restructuring Order, retail electric rates were capped
at year-end 1996 levels (system-wide average of 9.96 cents/kilowatt hour (kWh))
through June 2005. The Final Restructuring Order required PECO to reduce its
retail electric rates by 8% from the 1996 system-wide average rate on January 1,
1999. This rate reduction decreased to 6% on January 1, 2000 until January 1,
2001. The transmission and distribution rate component were capped at a
system-wide 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
energy and capacity charge, will remain in effect through 2010.
On March 16, 2000, the PUC issued an order authorizing PECO to
securitize up to an additional $1 billion of its authorized stranded costs
recovery. In accordance with the terms of that order, PECO will provide its
retail customers with rate reductions in the total amount of $60 million
beginning on January 1, 2001. This rate reduction will be effective for calendar
year 2001 only.
Under a comprehensive settlement agreement in connection with achieving
regulatory approval of the Merger Transaction, PECO agreed to $200 million in
rate reductions for all customers in Pennsylvania over the period January 1,
2002 through 2005 and extended the rate caps on PECO's retail electric
distribution charges through December 31, 2006.
6. Supplemental Financial Information
Supplemental Income Statement Information
Taxes Other Than Income
For the Year Ended December 31,
-------------------------------
2000 1999 1998
---- ---- ----
Gross receipts $159 $155 $156
Real estate 68 72 51
Payroll 41 28 30
Other 54 7 43
-------- ------- -------
Total $ 322 $ 262 $ 280
===== ===== =====
Other, Net
For the Year Ended December 31,
-------------------------------
2000 1999 1998
---- ---- ----
Interest income $ 62 $ 52 $ 26
Gain (loss) on disposition of assets, net (19) (1) (5)
Settlement of power purchase agreement 6 -- 14
AFUDC 3 4 4
Other 1 4 (38)
------- ------- -----
Total $ 53 $ 59 $ 1
===== ===== ======
Page 15
Supplemental Cash Flow Information
For the Year Ended December 31,
-------------------------------
2000 1999 1998
---- ---- ----
Cash paid during the year:
Interest (net of amount capitalized) $519 $350 $385
Income taxes (net of refunds) $272 $304 $347
Noncash investing and financing:
Issuance of Exelon shares for Unicom $5,310 -- --
Capital lease obligations incurred -- -- $38
Issuance of EIS stock $14 $11 --
Depreciation and amortization:
Property, plant and equipment $325 $207 $190
Nuclear fuel 149 104 62
Regulatory assets 53 -- 424
Decommissioning 46 29 29
Goodwill 34 1 --
Leased property -- 17 60
---- ---- ----
$607 $358 $765
==== ==== ====
Supplemental Balance Sheet Information
Investments
December 31,
2000 1999
---- ----
Investment in Sithe $ 704 $ --
Direct financing leases 409 --
Energy services and other ventures 185 57
Affordable housing projects 88 --
Emission allowances 82 --
Investment in AmerGen 44 40
Investments in subsidiaries and joint ventures 36 --
Communications ventures 35 24
Marketable securities -- 9
------ -----
Total $1,583 $ 130
====== =====
Prior to the merger, Unicom entered into a like-kind exchange transaction. Under
the transaction, Unicom invested approximately $1.6 billion in passive
generating station leases with two separate entities. The generating stations
were leased back to such entities as part of the transaction. For financial
accounting purposes, the investments are accounted for as direct financing lease
investments. Under the terms of the lease agreements, Exelon received a
prepayment of $1.2 billion in the fourth quarter, which reduced the investment
in the lease. There are no minimum scheduled lease payments to be received over
the next five years. The components of the net investment in the direct
financing leases as of December 31, 2000 are as follows:
Total minimum lease payments $1,492
Less: Unearned income 1,083
------
$ 409
======
Page 16
Regulatory Assets
December 31,
2000 1999
---- ----
Competitive transition charge $ 5,218 $ 5,275
Recoverable deferred income taxes (see Note 13) 632 638
Nuclear decommissioning costs 719 --
Recoverable transition costs 385 --
Loss on reacquired debt 99 71
Compensated absences 4 4
Non-pension postretirement benefits 78 84
------- ------
Long-Term Regulatory Assets 7,135 6,072
Deferred energy costs (current asset) 86 7
------- ------
Total $ 7,221 $6,079
======= ======
At December 31, 2000 and 1999, the Competitive Transition Charge (CTC)
includes the unamortized balance of $4.8 billion and $3.9 billion, respectively,
of Intangible Transition Property (ITP) sold to PECO Energy Transition Trust
(PETT) in connection with the securitization of PECO's stranded cost recovery.
ITP represents the irrevocable right of PECO or its assignee to collect
non-bypassable charges from customers to recover stranded costs.
7. Earnings Per Share
Diluted earnings per share are calculated by dividing net income by the
weighted average shares of common stock outstanding including shares issuable
upon exercise of stock options outstanding under Exelon's stock option plans
considered to be common stock equivalents. The following table shows the effect
of these stock options on the weighted average number of shares outstanding used
in calculating diluted earnings per share (in millions):
2000 1999 1998
---- ---- ----
Average Common Shares Outstanding 202 196 223
Assumed Exercise of Stock Options 2 1 1
----- ----- -----
Average Dilutive Common Shares Outstanding 204 197 224
===== ===== =====
8. Accounts Receivable
Accounts receivable -- Customer at December 31, 2000 and 1999 included
unbilled operating revenues of $498 million and $153 million, respectively. The
allowance for uncollectible accounts at December 31, 2000 and 1999 was $200
million and $112 million, respectively.
Accounts receivable -- Other at December 31, 2000 and 1999 included
demand notes receivable from a communications investment in the amount of $153
million. The average interest rate on the notes receivable was 6.22% and 5.66%
at December 31, 2000 and 1999, respectively. Interest income related to the
notes receivable was $10 million and $6 million in 2000 and 1999, respectively.
PECO 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 $225 million of designated accounts receivable until November
2005. At December 31, 2000, PECO had sold a $225 million interest in accounts
receivable, consisting of a $185 million interest in accounts receivable which
PECO accounted for as a sale under SFAS No. 125, "Accounting for Transfers and
Servicing of Financial Assets and Extinguishment of Liabilities," and a $40
million interest in special-agreement accounts receivable which was accounted
for as a long-term note payable. See Note 12 - Long-Term Debt. PECO retains the
servicing responsibility for these receivables. The agreement requires PECO to
maintain the $225 million
Page 17
interest, which, if not met, requires PECO to deposit cash in order to satisfy
such requirements. At December 31, 2000 and 1999, PECO met this requirement and
was not required to make any cash deposits.
9. Property, Plant, and Equipment
A summary of property, plant and equipment by classification as of
December 31, 2000 and 1999 is as follows:
2000 1999
---- ----
Electric -- Transmission & Distribution $9,447 $3,953
Electric -- Generation 4,044 1,942
Gas 1,181 1,176
Common 408 408
Nuclear Fuel 2,341 1,551
Construction Work in Progress 1,189 232
Leased Property 2 2
Other Property, Plant and Equipment 1,274 152
------- -------
Total Property, Plant and Equipment 19,886 9,416
Less Accumulated Depreciation (including accumulated
amortization of nuclear fuel of $1,445 and $1,281 in
2000 and 1999, respectively) 6,950 4,412
-------- -------
Property, Plant and Equipment, net $12,936 $5,004
======= ======
10. Jointly Owned Electric Utility Plant
Exelon's undivided ownership interests in jointly owned electric
utility plant at December 31, 2000, were as follows:
Production Plant
----------------------------------------------------------
Transmission
Peach Quad and Other
Bottom Salem Keystone Conemaugh Cities Plant
------ ----- -------- --------- ------ ----------------
Operator PECO PSE&G Sithe Sithe ComEd Various Co.
---- ----- ----- ----- ----- -----------
Participating Interest 46.25% 42.59% 20.99% 20.72% 75% 21% to 43%
Exelon's Share:
Utility Plant $378 $3 $120 $190 $84 $80
Accumulated
Depreciation $214 $3 $94 $118 $ 2 $31
Construction
Work in Progress $41 $41 $4 $10 $38 $--
Exelon's undivided ownership interests are financed with Exelon funds
and, when placed in service, all operations are accounted for as if such
participating interests were wholly owned facilities.
On September 30, 1999, Exelon reached an agreement to purchase an
additional 7.51% ownership interest in Peach Bottom Atomic Power Station (Peach
Bottom) from Atlantic City Electric Company and Delmarva Power & Light Company
for $18 million. On December 24, 2000, Exelon completed the purchase of Delmarva
Power & Light Company's 3.755% interest in Peach Bottom for $9 million. The
purchase of Atlantic City Electric Company's ownership interest is still pending
regulatory approval which is expected in 2001.
Page 18
11. Notes Payable, Banks
2000 1999 1998
---- ---- ----
Average borrowings $186 $242 $209
Average interest rates, computed on daily basis 6.62% 5.62% 5.83%
Maximum borrowings outstanding $500 $728 $525
Average interest rates, at December 31 7.18% 6.80% 6.17%
Exelon, PECO and ComEd entered into a $2 billion unsecured revolving
credit facility on December 20, 2000 with a group of banks. This credit facility
is used principally to support the commercial paper programs of Exelon, PECO and
ComEd. At December 31, 2000 and 1999, the amount of commercial paper outstanding
was $161 million and $142 million, respectively. At December 31, 1999, Exelon
had $21 million of borrowings on lines of credit.
In October 2000, Exelon obtained a $1.25 billion term loan due June 30,
2001 to finance the cash consideration paid to former holders of Unicom common
stock in connection with the Merger Transaction and to finance the purchase of
its 49.9% interest in Sithe in December 2000. Interest rates on the advances
from the credit facility are based on the London Interbank Offering Rate (LIBOR)
as of the date of the advance. On December 31, 2000, Exelon had $1,210 million
outstanding on this term loan which is also reflected in Notes Payable, Bank on
the Consolidated Balance Sheet. The average interest rate on this term loan for
the period it was outstanding in 2000 was 7.6%. Exelon expects to refinance this
term loan on or before its due date.
Page 19
12. Long Term Debt
Maturity At December 31,
---------------
Rates Date 2000 1999
----- ---- ---- ----
ComEd Transitional Trust
Notes Series 1998-A: 5.29%-5.74% 2001-2008 $2,720 $ --
PETT
Bonds Series 1999-A:
Fixed rates 5.48%-6.13% 2001-2008(a) 2,706 2,826
Floating rates 6.955%-7.03% 2004-2007(a) 1,132 1,132
PETT
Bonds Series 2000-A: 7.18%-7.65% 2001-2009(a) 1,000 --
First and Refunding Mortgage Bonds (b) (c):
Fixed rates 4.40%-10.25% 2001-2024 4,260 1,538
Floating rates 4.28% 2011-2015 154 154
Notes payable 6.40%-9.20% 2002-2023 1,459 38
Pollution control notes:
Fixed rates 5.875% 2007 46 --
Floating rates 4.73% 2009-2034 461 369
Notes payable - accounts
receivable agreement 6.66% 2005 40 49
Sinking fund debentures 2.875%-4.75% 2001-2011 27 --
-------- ---------
Total Long-Term debt (d) 14,005 6,106
Unamortized debt discount and premium, net (139) (9)
Due within one year (908) (128)
--------- --------
Long-Term debt $12,958 $5,969
========= ========
(a) The maturity date represents the expected final payment date which is the
date when all principal and interest of the related class of transition bonds is
expected to be paid in full in accordance with the expected amortization
schedule for the applicable class. The date when all principal and interest must
be paid in full for the PETT Bonds Series 1999-A and 2000-A are 2003 through
2009 and 2003 through 2010, respectively. The current portion of transition
bonds is based upon the expected maturity date.
(b) Utility plant of PECO and ComEd is subject to the liens of their respective
mortgage indentures.
(c) Includes first mortgage bonds issued under the PECO and ComEd mortgage
indentures securing pollution control notes.
(d) Long-term debt maturities in the period 2001 through 2005 and thereafter are
as follows:
2001 $ 908
2002 1,491
2003 1,622
2004 1,101
2005 1,426
Thereafter 7,457
--------
Total $14,005
=======
Page 20
In 1999, PECO entered into treasury forwards associated with the
anticipated issuance of the Series 2000-A Transition Bonds. On May 2, 2000,
these instruments were settled with net proceeds to the counterparties of $13
million which has been deferred and is being amortized over the life of the
Series 2000-A Transition Bonds as an increase to interest expense consistent
with Exelon's hedge accounting policy.
In 1998, PECO entered into treasury forwards and forward starting
interest rate swaps to manage interest rate exposure associated with the
anticipated issuance of the Series 1999-A Transition Bonds. On March 18, 1999,
these instruments were settled with net proceeds of $80 million to PECO which
were deferred and are being amortized over the life of the Series 1999-A
Transition Bonds as a reduction of interest expense consistent with Exelon's
hedge accounting policy. At December 31, 2000 and 1999, the unamortized net gain
was $51 million and $71 million, respectively.
In 2000, 1999 and 1998, Exelon incurred extraordinary charges
aggregating $6 million ($4 million, net of tax), $62 million ($37 million, net
of tax) and $34 million ($20 million, net of tax), respectively, consisting of
prepayment premiums and the write-offs of unamortized deferred financing costs
associated with the early retirement of debt.
13. Income Taxes
Income tax expense (benefit) is comprised of the following components:
For the Year Ended December 31,
-------------------------------
2000 1999 1998
---- ---- ----
Included in operations:
Federal
Current $ 163 $ 293 $ 358
Deferred 163 6 (109)
Investment tax credit, net (15) (14) (18)
State
Current -- 72 95
Deferred 30 1 (6)
------- -------- --------
$ 341 $ 358 $ 320
===== ====== ======
Included in extraordinary item:
Federal
Current (2) (19) (11)
State
Current -- (6) (3)
------- --------- ---------
$ (2) $ (25) $ (14)
======== ======== =========
Included in cumulative effect of a change in accounting principle:
Federal
Deferred 13 -- --
State
Deferred 3 -- --
-------- --------- --------
$ 16 $ -- $ --
======= ========= ========
Page 21
The total income tax provisions, excluding the extraordinary item and cumulative
effect of a change in accounting principle, differed from amounts computed by
applying the federal statutory tax rate to pre-tax income as follows:
For the Year Ended December 31,
-------------------------------
2000 1999 1998
---- ---- ----
Income Before Extraordinary Items and
Cumulative Effect of a Change in
Accounting Principle $ 566 $ 607 $ 520
Income Taxes 341 358 320
----- ----- -----
Income Before Income Taxes
Extraordinary Items and Cumulative
Effect of a Change in Accounting
Principle $ 907 $ 965 $ 840
Income taxes on above at federal
statutory rate of 35% $ 317 $ 338 $ 294
Increase (decrease) due to:
Property basis differences 1 (8) (10)
State income taxes, net of federal income
tax benefit 19 46 58
Amortization of investment tax credit (15) (14) (18)
Amortization of goodwill 8 -- --
Prior period income taxes 4 (7) (13)
Dividends on PECO Preferred Stock 4 4 4
Other, net 3 (1) 5
----- ----- -----
Income Taxes $ 341 $ 358 $ 320
===== ===== =====
Effective income tax rate 37.6% 37.1% 38.1%
===== ===== =====
Provisions for deferred income taxes consist of the tax effects of the following
temporary differences:
For the Year Ended December 31,
-------------------------------
2000 1999 1998
---- ---- ----
Depreciation and amortization $ 200 $ 23 $ 140
Deferred generation charges recoverable (23) -- (175)
Transition bond hedge 29 (29) --
Deferred energy costs 10 (9) (2)
Retirement and separation programs (31) 7 (51)
Merger cost (25) -- --
Alternative minimum tax credits (4) -- (42)
Other 37 15 15
---- ------ ------
Subtotal 193 7 (115)
Cumulative effect of a change in
accounting principle 16 -- --
---- ------ ------
Total $209 $ 7 $(115)
==== ====== ======
Page 22
The tax effect of temporary differences giving rise to Exelon's net deferred tax
liability as of December 31, 2000 and 1999 is as follows:
2000 1999
---- ----
Nature of temporary difference:
Plant basis difference $4,535 $2,703
Deferred investment tax credit 330 286
Deferred debt refinancing costs 48 37
Deferred gain on like kind exchange 466 --
Deferred pension and postretirement obligations (437) (148)
Other, net (265) (167)
------ ------
Deferred income taxes (net) on the balance sheet $4,677 $2,711
====== ======
In accordance with SFAS No. 71, Exelon has recorded a recoverable
deferred income tax asset of $632 million and $638 million at December 31, 2000
and 1999, respectively. These balances are applicable only to regulated assets,
as a result of the discontinuance of SFAS No. 71 for Exelon's electric
generation operations. These recoverable deferred income taxes include the
deferred tax effects associated principally with liberalized depreciation
accounted for in accordance with the ratemaking policies of the PUC and ICC, as
well as the revenue impacts thereon, and assume continued recovery of these
costs in future rates.
The Internal Revenue Service is currently auditing certain Exelon's
subsidiaries federal tax returns for 1996 through 1999. The current audits are
not expected to have an adverse impact on financial condition or results of
operations of Exelon.
14. Retirement Benefits
Exelon and its subsidiaries have defined benefit pension plans and
postretirement benefit plans applicable to essentially all PECO and ComEd
employees and certain employees of other subsidiaries. Benefits under these
plans reflect each employee's compensation, years of service and age at
retirement. Funding is based upon actuarially determined contributions that take
into account the amount deductible for income tax purposes and the minimum
contribution required under the Employee Retirement Income Security Act of 1974,
as amended. The following tables provide a reconciliation of benefit
obligations, plan assets and funded status of the plans.
Pension Benefits Other Postretirement Benefits
---------------- -----------------------------
2000 1999 2000 1999
------- ------- ------- -------
Change in Benefit Obligation:
Net benefit obligation at beginning of year $ 2,054 $ 2,310 $ 798 $ 848
Service cost 39 29 24 19
Interest cost 219 154 83 57
Plan participants' contributions -- -- 1 --
Plan amendments -- 25 -- --
Actuarial (gain)loss 228 (300) 144 (77)
Acquisitions 4,231 -- 1,228 --
Curtailments/Settlements (74) -- 4 --
Special termination benefits 217 -- 48 --
Gross benefits paid (219) (164) (55) (49)
------- ------- ------- -------
Net benefit obligation at end of year $ 6,695 $ 2,054 $ 2,275 $ 798
======= ======= ======= =======
Change in Plan Assets:
Fair value of plan assets at beginning of year $ 2,982 $ 2,745 $ 244 $ 223
Actual return on plan assets 173 400 (7) 20
Employer contributions 2 1 84 50
Plan participants' contributions -- -- 1 --
Acquisitions 4,062 -- 921 --
Gross benefits paid (219) (164) (55) (49)
------- ------- ------- -------
Fair value of plan assets at end of year $ 7,000 $ 2,982 $ 1,188 $ 244
======= ======= ======= =======
Page 23
Funded status at end of year $ 305 $ 928 $(1,087) $ (554)
Miscellaneous adjustment -- -- 5 --
Unrecognized net actuarial (gain)loss (777) (1,129) 143 (43)
Unrecognized prior service cost 77 85 -- --
Unrecognized net transition obligation (asset) (21) (26) 122 154
------- ------- ------- -------
Net amount recognized at end of year $ (416) $ (142) $ (817) $ (443)
======= ======= ======= =======
Amounts recognized in the consolidated
balance sheets consist of:
Prepaid benefit cost $ 151 $ 71 2 N/A
Accrued benefit cost (567) (213) (819) (443)
------- ------- ------- -------
Net amount recognized at end of year $ (416) $ (142) $ (817) $ (443)
======= ======= ======= =======
Pension Benefits Other Postretirement Benefits
------------------------- -----------------------------
2000 1999 1998 2000 1999 1998
----- ----- ----- ----- ----- -----
Weighted-average assumptions
as of December 31,
Discount rate 7.60% 8.00% 7.00% 7.60% 8.00% 7.00%
Expected return on plan assets 9.50% 9.50% 9.50% 8.00% 8.00% 8.00%
Rate of compensation increase 4.30% 5.00% 5.00% 4.30% 5.00% 5.00%
Health care cost trend on covered charges N/A N/A N/A 7.00% 8.00% 6.50%
decreasing decreasing decreasing
to ultimate to ultimate to ultimate
trend of 5.0% trend of 5.0% trend of 5.0%
in 2005 in 2006 in 2002
Pension Benefits Other Postretirement Benefits
------------------------- -----------------------------
2000 1999 1998 2000 1999 1998
----- ----- ----- ----- ----- -----
Components of net periodic benefit cost (benefit):
Service cost $ 39 $ 29 $ 30 $ 24 $ 19 $ 18
Interest cost 219 154 154 83 57 54
Expected return on assets (316) (222) (210) (34) (16) (13)
Amortization of:
Transition obligation (asset) (4) (4) (5) 12 12 15
Prior service cost 7 5 6 -- -- --
Actuarial (gain)loss (26) (8) (7) -- -- --
Curtailment charge (credit) (12) -- (62) 24 -- 53
Settlement charge (credit) (16) -- (13) -- -- --
----- ----- ----- ----- ----- -----
Net periodic benefit cost (benefit) $(109) $ (46) $(107) $ 109 $ 72 $ 127
===== ===== ===== ===== ===== =====
Special termination benefit charge $ 217 $ -- $ 114 $ 48 $ -- $ 30
===== ===== ===== ===== ===== =====
Sensitivity of retiree welfare results
Effect of a one percentage point increase in assumed health care cost trend
on total service and interest cost components $ 34
on postretirement benefit obligation $ 325
Effect of a one percentage point decrease in assumed health care cost trend
on total service and interest cost components $ (27)
on postretirement benefit obligation $ (263)
Prior service cost is amortized on a straight line basis over the
average remaining service period of employees expected to receive benefits under
the plans.
During 2000, costs were recognized for special termination benefits in
connection with the enhanced retirement and severance benefits provided under to
employees expected to be terminated as a result of the Merger Transaction.
Special termination benefits of $217 million represented PECO's accelerated
separation and enhancement benefits of $96 million and ComEd's accelerated
liability increase of $121 million inclusive of $96 million for separation
benefits and $25 million for plan enhancements under Exelon's MSP. In addition,
Exelon recognized settlement and curtailment credits of $28 million in
connection with Exelon's MSP. During 1999, all retirees and beneficiaries who
began receiving benefit payments prior to January 1, 1994 were granted a
cost-of-living adjustment resulting in a $25 million increase in the projected
benefit obligation. During 1998, costs were recognized for special termination
benefits in connection with the retirement incentives and enhanced severance
benefits provided under the Early Retirement and Separation Program.
Page 24
Exelon provides certain health care and life insurance benefits for
retired employees. Exelon employees become eligible for these benefits if they
retire from Exelon with ten years of service. Certain benefits for active
employees are provided by several insurance companies whose premiums are based
upon the benefits paid during the year.
Additionally, Exelon maintains a nonqualified supplemental retirement
plan which covers any excess pension benefits that would be payable to
management employees under the qualified plan but which are limited by the
Internal Revenue Code. The fair value of plan assets excludes $24 million held
in a grantor trust as of December 31, 2000 for the payment of benefits under the
supplemental plan and $9 million held in a grantor trust as of December 31, 2000
for the payment of postretirement medical benefits.
Exelon sponsors savings plans for the majority of its employees. The
plans allow employees to contribute a portion of their pretax income in
accordance with specified guidelines. Exelon matches a percentage of the
employee contribution up to certain limits. The cost of Exelon's matching
contribution to the savings plans totaled $17 million, $7 million, and $7
million in 2000, 1999, and 1998, respectively.
15. Preferred Securities of Subsidiaries
Preferred and Preference Stock
At December 31, 2000 and 1999, Series Preference Stock of PECO, no par
value, consisted of 100,000,000 shares authorized, of which no shares were
outstanding. At December 31, 2000 and 1999, cumulative Preferred Stock of PECO,
no par value, consisted of 15,000,000 shares authorized and the amounts set
forth below:
Shares Outstanding Amount
------------------ ------
Current At December 31,
Redemption ---------------------------------------------
Price (a) 2000 1999 2000 1999
--------- ---- ---- ---- ----
Series (without mandatory redemption)
$4.68 $104.00 150,000 150,000 $ 15 $ 15
$4.40 112.50 274,720 274,720 27 27
$4.30 102.00 150,000 150,000 15 15
$3.80 106.00 300,000 300,000 30 30
$7.48 (b) 500,000 500,000 50 50
------- ------- ---- ----
1,374,720 1,374,720 137 137
Series (with mandatory redemption)
$6.12 (c) 370,800 556,200 37 56
------- ------- ----- -----
Total preferred stock 1,745,520 1,930,920 $174 $193
========= ========= ==== ====
(a) Redeemable, at the option of PECO, at the indicated dollar amounts per
share, plus accrued dividends.
(b) None of the shares of this series is subject to redemption prior to April 1,
2003.
(c) PECO exercised its right to double (to 370,800 shares, from the original
185,400 share requirement) the first annual sinking fund requirement for the
$6.12 Series on August 2, 1999. PECO made the annual sinking fund payment of
$18.5 million on August 2, 2000. Future annual sinking fund requirements in 2001
and 2002 are $18.5 million.
At December 31, 2000, ComEd Series $1.425 Convertible Preferred Stock, ComEd
Prior Preferred Stock and ComEd Preference Stock consisted of 51,773, 850,000
and 6,810,451 shares authorized, respectively, none of which were outstanding.
Page 25
Company Obligated Mandatorily Redeemable Preferred Securities
At December 31, 2000 and 1999, subsidiary trusts of PECO and ComEd had
outstanding the following preferred securities:
Trust Securities Outstanding Amount
---------------------------- ------
Mandatory Distri- Liqui- At December 31,
Redemption bution dation ---------------
Date Rate Value 2000 1999 2000 1999
---- ---- ----- ----------------------- ------- -----
PECO Energy
Capital Trust II 2037 8.00% $ 25 2,000,000 2,000,000 $ 50 $ 50
PECO Energy
Capital Trust III 2028 7.38% 1,000 78,105 78,105 78 78
--------- --------- ----- -----
Total 2,078,105 2,078,105 $ 128 $ 128
========= ========= ===== =====
ComEd Financing I 2035 8.48% $ 25 8,000,000 -- $ 200 --
ComEd Financing II 2027 8.50% 1,000 150,000 -- 150 --
Unamortized Discount (22) --
--------- --------- ----- -----
Total 8,150,000 -- $ 328 --
========= ========= ===== =====
The securities issued by the PECO trusts represent Company Obligated
Mandatorily Redeemable Preferred Securities of a Partnership (COMRPS) having a
distribution rate and liquidation value equivalent to the trust securities. The
COMRPS are the sole assets of these trusts and represent limited partnership
interests of PECO Energy Capital, L.P. (Partnership), a Delaware limited
partnership. Each holder of a trust's securities is entitled to withdraw the
corresponding number of COMRPS from the trust in exchange for the trust
securities so held. Each series of COMRPS is supported by PECO's deferrable
interest subordinated debentures, held by the Partnership, which bear interest
at rates equal to the distribution rates on the related series of COMRPS.
ComEd Financing I and ComEd Financing II are wholly owned subsidiary
trusts of ComEd. Each ComEd trust's sole assets are subordinated deferrable
interest securities issued by ComEd bearing interest rates equivalent to the
distribution rate of the related trust security.
The interest expense on the debentures and deferrable interest
securities is included in Distributions on Preferred Securities of Subsidiaries
in the Consolidated Statements of Income and is deductible for tax purposes.
16. Common Stock
At December 31, 2000 and 1999, common stock without par value consisted
of 600,000,000 and 500,000,000 shares authorized and 319,005,112 and 181,271,692
shares outstanding, respectively.
Stock Repurchase
In January 2000, in connection with the Merger Agreement, PECO entered
into a forward purchase agreement to purchase $500 million of its common stock
from time to time. Settlement of this forward purchase agreement was, at PECO's
election, on a physical, net share or net cash basis. In May 2000, PECO utilized
a portion of the proceeds from the securitization of its stranded cost recovery
to physically settle this agreement, resulting in the repurchase of 12 million
shares of common stock for $496 million. In connection with the settlement of
this agreement, PECO received $1 million in accumulated dividends on the
repurchased shares and paid $6 million of interest.
During 1997, PECO'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, PECO entered into forward
purchase agreements to be settled from time to time, at PECO's election, on a
physical, net share or
Page 26
net cash basis. PECO utilized the proceeds from the securitization of a portion
of its stranded cost recovery in the first quarter of 1999, to physically settle
these agreements, resulting in the purchase of 21 million shares of common stock
for $696 million. In connection with the settlement of these agreements, PECO
received $18 million in accumulated dividends on the repurchased shares and paid
$6 million of interest.
Stock-Based Compensation Plans
Exelon maintains a Long-Term Incentive Plan (LTIP) for certain
full-time salaried employees and previously maintained a broad-based incentive
program for certain other employees. The types of long-term incentive awards
that have been granted under the LTIP are non-qualified options to purchase
shares of Exelon's common stock and common stock awards. The types of long-term
incentive awards that have been granted under the broad-based incentive program
are non-qualified options to purchase shares of Exelon's common stock. At
December 31, 2000, there were 9,000,000 options authorized for issuance under
the LTIP and 2,000,000 options authorized under the broad-based incentive
program. Exelon uses the disclosure-only provisions of SFAS No. 123, "Accounting
for Stock-Based Compensation." If Exelon elected to account for its stock-based
compensation plans based on SFAS No. 123, it would have recognized compensation
expense of $60 million, $10 million and $6 million, for 2000, 1999 and 1998,
respectively. In addition, net income would have been $526 million, $560 million
and $494 million for 2000, 1999 and 1998, respectively, and earnings per share
would have been $2.58, $2.84 and $2.20 for 2000, 1999 and 1998, respectively.
Page 27
The exercise price of the stock options is equal to the fair market
value of the underlying stock on the date of option grant. Options granted under
the LTIP and the broad-based incentive program become exercisable upon
attainment of a target share value and/or time. All options expire 10 years from
the date of grant. Information with respect to the LTIP and the broad-based
incentive program at December 31, 2000 and changes for the three years then
ended, is as follows:
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Exercise
Price Price Price
Shares (per share) Shares (per share) Shares (per share)
2000 2000 1999 1999 1998 1998
- ----------------------------------------------------------------------------------------------------------
Balance at January 1 6,065,897 $ 31.91 4,663,008 $ 27.71 3,816,794 $ 26.14
Options granted/assumed 11,089,051(a) 46.09 2,049,789 39.32 3,087,558 28.37
Options exercised (1,725,058) 31.79 (568,000) 25.17 (2,130,744) 23.86
Options canceled (142,031) 39.95 (78,900) 38.14 (110,600) 26.40
--------- ---------- ---------
Balance at December 31 15,287,859 42.13 6,065,897 31.91 4,663,008 27.71
========== ========= =========
Exercisable at
December 31 4,953,942 30.04 3,331,903 25.60 3,462,550 23.91
========= ========= =========
Weighted average fair value
of options granted during
year $ 16.62 $ 8.24 $ 3.43
======= ======= =======
(a) Includes 5.3 million options converted in the Merger.
The fair value of each option is estimated on the date of grant using
the Black-Scholes option-pricing model with the following weighted average
assumptions used for grants in 2000, 1999, and 1998, respectively:
2000 1999 1998
---- ---- ----
Dividend yield 3.6% 5.7% 6.8%
Expected volatility 36.8% 30.5% 21.4%
Risk-free interest rate 5.9% 5.9% 5.5%
Expected life (years) 5.0 9.5 9.5
Page 28
At December 31, 2000, the options outstanding, based on ranges of exercise
prices, were as follows:
Options Outstanding Options Exercisable
---------------------------------------- -------------------------
Weighted
Average
Remaining Weighted Weighted
Contractual Average Average
Range of Number Life Exercise Number Exercise
Exercise Prices Outstanding (years) Price Exercisable Price
- ----------------- ---------------------------------------------- ---------------------------
$15.01-$20.00 680,700 6.81 $19.67 680,700 $19.67
$20.01-$25.00 1,055,009 6.71 22.60 1,055,009 22.60
$25.01-$30.00 1,021,016 4.27 27.22 1,021,016 27.22
$30.01-$35.00 159,044 8.70 33.52 72,469 33.40
$35.01-$40.00 6,240,998 8.51 37.96 1,615,955 37.42
$40.01-$45.00 1,460,992 8.38 41.18 490,908 40.86
$45.01-$60.00 4,670,100 9.79 59.24 17,885 47.34
--------- ----------
Total 15,287,859 4,953,942
========== =========
Exelon issued 195,725 shares, 120,300 shares and 7,000 shares of common
stock awards during 2000, 1999 and 1998, respectively. Vesting for the common
stock awards is over a period not to exceed 10 years from the grant date.
Compensation cost of $9 million, $5 million and $0.2 million, respectively,
associated with these awards is amortized to expense over the vesting period.
The related accumulated amortization was approximately $7 million and $2 million
at December 31, 2000 and 1999, respectively.
17. Financial Instruments
Fair values of financial instruments, including liabilities, are
estimated based on quoted market prices for the same or similar issues. The
carrying amounts and fair values of Exelon's financial instruments as of
December 31, 2000 and 1999 were as follows:
2000 1999
----------------------- ------------------------
Carrying Carrying
Amount Fair Value Amount Fair Value
-------- ---------- -------- ----------
Non-derivatives:
Assets
Cash and cash equivalents $ 840 $ 840 $ 228 $ 228
Trust accounts for decommissioning
nuclear plants 3,109 3,109 408 408
Marketable securities -- -- 9 9
Liabilities
Long-term debt (including amounts
due within one year) 13,866 14,336 6,097 5,822
Preferred Securities of Subsidiaries 630 601 321 254
Derivatives:
Interest rate swaps -- (19) -- 36
Forward interest rate swaps -- 40 -- 66
Energy swap contract 34 34 -- --
Financial instruments which potentially subject Exelon to
concentrations of credit risk consist principally of cash equivalents and
customer accounts receivable. Exelon places its cash equivalents with
high-credit quality financial institutions. Generally, such investments are in
excess of the Federal Deposit
Page 29
Insurance Corporation limit. Concentrations of credit risk with respect to
customer accounts receivable are limited due to Exelon's large number of
customers and their dispersion across many industries.
The fair value of derivatives generally reflects the estimated amounts
that Exelon would receive or pay to terminate the contracts at the reporting
date, thereby taking into account the current unrealized gains or losses of open
contracts. Dealer quotes are available for all of Exelon's derivatives.
Exelon entered into interest rate swaps relating to two variable rate
series of transition bonds in the aggregate notional amount of $1.1 billion with
an average interest rate of 6.65%. Exelon has also entered into forward starting
interest rate swaps relating to two variable rate series of transition bonds in
the aggregate notional amount of $1.1 billion with an average interest rate of
6.01%. In anticipation of the refinancing of a portion of the two variable rate
series of transition bonds in the first quarter of 2001, Exelon settled $318
million of the forward starting interest rate swaps in December 2000. The
notional amount of derivatives do not represent amounts that are exchanged by
the parties and, thus, are not a measure of Exelon's exposure. The amounts
exchanged are calculated on the basis of the notional or contract amounts, as
well as on the other terms of the derivatives, which relate to interest rates
and the volatility of these rates.
Exelon would be exposed to credit-related losses in the event of
non-performance by the counterparties that issued the derivative instruments.
Exelon does not expect that counterparties to the interest rate swaps will fail
to meet these obligations, given their high credit ratings. The credit exposure
of derivatives contracts is represented by the fair value of contracts at the
reporting date. Exelon's interest rate swaps are documented under master
agreements. Among other things, these agreements provide for a maximum credit
exposure for both parties. Payments are required by the appropriate party when
the maximum limit is reached.
18. Commitments and Contingencies
Capital Commitments
Exelon estimates that it will spend approximately $2.7 billion for
capital expenditures and other investments in 2001. Exelon has commitments to
provide AmerGen with capital contributions equivalent to 50% of the purchase
price of any acquisitions AmerGen makes in 2001. In addition, Exelon and British
Energy have each agreed to provide up to $100 million to AmerGen at any time for
operating expenses. See Note 3 - Acquisitions: AmerGen Energy Company, LLC.
Nuclear Insurance
The Price-Anderson Act limits the liability of nuclear reactor owners
for claims that could arise from a single incident. The current limit is $9.5
billion and is subject to change to account for the effects of inflation and
changes in the number of licensed reactors. Through its subsidiaries, Exelon
carries the maximum available commercial insurance of $200 million and the
remaining $9.3 billion is provided through mandatory participation in a
financial protection pool. Under the Price-Anderson Act, all nuclear reactor
licensees can be assessed up to $89 million per reactor per incident, payable at
no more than $10 million per reactor per incident per year. This assessment is
subject to inflation and state premium taxes. In addition, the U.S. Congress
could impose revenue-raising measures on the nuclear industry to pay claims.
Exelon carries property damage, decontamination and premature
decommissioning insurance for each station loss resulting from damage to its
nuclear plants. In the event of an accident, insurance proceeds must first be
used for reactor stabilization and site decontamination. If the decision is made
to decommission the facility, a portion of the insurance proceeds will be
allocated to a fund, which Exelon is required by the Nuclear Regulatory
Commission (NRC) to maintain, to provide for decommissioning the facility.
Exelon is unable to predict the timing of the availability of insurance proceeds
to Exelon and the amount of such proceeds which would be available. Under the
terms of the various insurance agreements, Exelon could be assessed up to $69
million for losses incurred at any plant insured by the insurance
Page 30
companies. Exelon is self-insured to the extent that any losses may exceed the
amount of insurance maintained. Such losses could have a material adverse effect
on Exelon's financial condition and results of operations.
Additionally, through its subsidiaries, Exelon is a member of an
industry mutual insurance company that provides replacement power cost insurance
in the event of a major accidental outage at a nuclear station. The premium for
this coverage is subject to assessment for adverse loss experience. Exelon's
maximum share of any assessment is $18 million per year.
In addition, Exelon participates in the American Nuclear Insurers
Master Worker Program, which provides coverage for worker tort claims filed for
bodily injury caused by a nuclear energy accident. This program was modified,
effective January 1, 1998, to provide coverage to all workers whose
"nuclear-related employment" began on or after the commencement date of reactor
operations. Exelon will not be liable for a retrospective assessment under this
new policy. However, in the event losses incurred under the small number of
policies in the old program exceed accumulated reserves, a maximum retroactive
assessment of up to $50 million could apply.
Nuclear Decommissioning and Spent Fuel Storage
Exelon's current estimate of its nuclear facilities' decommissioning
cost is $6.9 billion. Decommissioning costs are recoverable through regulated
rates. Under rates in effect through December 31, 2000, Exelon collected and
expensed approximately $46 million in 2000 from customers which was accounted
for as a component of depreciation expense and accumulated depreciation for
operating units and regulatory assets for retired units. At December 31, 2000
and 1999, $2.6 billion and $383 million, respectively, was included in
accumulated depreciation. In order to fund future decommissioning costs, at
December 31, 2000 and 1999, Exelon held $3.1 billion and $408 million,
respectively, in trust accounts which are included as Investments in Exelon's
Consolidated Balance Sheets and include both net unrealized and realized gains.
Net unrealized gains of $539 million and $45 million, respectively, were
recognized in accumulated depreciation in Exelon's Consolidated Balance Sheets
at December 31, 2000 and 1999, respectively. Net realized gains of $11 million
and $14 million were also recognized in accumulated depreciation in Exelon's
Consolidated Balance Sheets at December 31, 2000 and 1999, respectively. Exelon
believes that the amounts being recovered from customers through regulated rates
and earnings on nuclear decommissioning trust funds will be sufficient to fully
fund the unrecorded portion of its decommissioning obligation.
In connection with the transfer of ComEd's nuclear generating stations
to Generation, ComEd asked the ICC to approve the continued recovery of
decommissioning costs after the transfer. On December 20, 2000, the ICC issued
an order finding that the ICC has the legal authority to permit ComEd to
continue to recover decommissioning costs from customers for the six-year term
of the power purchase agreements between ComEd and Generation. Under the ICC
order, ComEd is permitted to recover $73 million per year from customers for
decommissioning for the years 2001 through 2004. In 2005 and 2006, ComEd can
recover up to $73 million annually, depending upon the portion of the output of
the former ComEd nuclear stations that ComEd purchases from Generation.
Subsequent to 2006, there will be no further recoveries of decommissioning costs
from customers. The ICC order also provides that any surplus funds after the
nuclear stations are decommissioned must be refunded to customers. The amount of
recovery in the ICC order is less than the $84 million annual amount ComEd
recovered in 2000. The ICC order is currently pending appeal in the Illinois
Appellate Court.
Under the Nuclear Waste Policy Act of 1982 (NWPA), the U.S. Department
of Energy (DOE) is responsible for the selection and development of repositories
for, and the disposal of, spent nuclear fuel and high-level radioactive waste
(SNF). ComEd and PECO, as required by the NWPA, each signed a contract with the
DOE (Standard Contract) to provide for disposal of SNF from their respective
nuclear generating stations. In accordance with the NWPA and the Standard
Contract, ComEd and PECO pay the DOE one mill ($.001) per kilowatthour of net
nuclear generation for the cost of nuclear fuel long-term storage and disposal.
This fee may be adjusted prospectively in order to ensure full cost recovery.
The NWPA and the Standard Contract required the DOE to begin taking possession
of SNF generated by nuclear generating units by no later than January 1998. The
DOE, however, failed to meet that deadline and its performance is
Page 31
expected to be delayed significantly. The DOE's current estimate for opening an
SNF facility is 2010. This extended delay in SNF acceptance by the DOE has led
to Exelon's consideration of additional dry storage alternatives.
In July 1998, ComEd filed a complaint against the United States
Government (Government) in the United States Court of Federal Claims (Court)
seeking to recover damages caused by the DOE's failure to honor its contractual
obligation to begin disposing of SNF in January 1998. ComEd subsequently moved
for partial summary judgment on liability of its breach of contract claim. In
August 2000, the United States Court of Appeals for the Federal Circuit decided
two other similar cases against the Government, rejecting the Government's
jurisdictional defense and granting partial summary judgment on liability for
the plaintiff utilities in one of those cases. The Court later denied the
Government's request for rehearing. Following that ruling, ComEd and seven other
utility plaintiffs filed motions in their respective cases in the Court to set a
coordinated discovery schedule on damages. On January 8, 2001, the Government
filed a motion to reassign all of the SNF cases to one Court judge for purposes
of consolidating the cases to address certain damage issues. Those motions are
pending before the Court. ComEd has also requested that the Court grant its
pending summary judgment motion on liability, particularly in light of the
Federal Circuit's decision in August 2000.
In July 2000, PECO entered into an agreement with the DOE relating to
PECO's Peach Bottom nuclear generating unit to address the DOE's failure to
begin removal of SNF in January 1998 as required by the Standard Contract. Under
that agreement, the DOE agrees to provide PECO with credits against PECO's
future contributions to the Nuclear Waste Fund over the next ten years to
compensate PECO for SNF storage costs incurred as a result of the DOE's breach
of the contract. The agreement also provides that, upon PECO's request, the DOE
will take title to the SNF and the interim storage facility at Peach Bottom
provided certain conditions are met. In November 2000, eight utilities with
nuclear power plants filed a Joint Petition for Review against the DOE with the
United States Court of Appeals for the Eleventh Circuit seeking to invalidate
that portion of the agreement providing for credits to PECO against nuclear
waste fund payments on the ground that such provision is a violation of the
NWPA. PECO has intervened as a defendant in that case, which is ongoing.
The Standard Contract with the DOE also requires that PECO and ComEd
pay the DOE a one-time fee applicable to nuclear generation through April 6,
1983. PECO's fee has been paid. Pursuant to the Contract, ComEd has elected to
pay the one-time fee of $277 million, with interest to the date of payment, just
prior to the first delivery of SNF to the DOE. As of December 31, 2000, the
liability for the one-time fee with interest was $810 million.
Energy Commitments
Exelon's wholesale operations include the physical delivery and
marketing of power obtained through its generation capacity, and long,
intermediate and short-term contracts. Exelon maintains a net positive supply of
energy and capacity, through ownership of generation assets and power purchase
and lease agreements, to protect it from the potential operational failure of
one of its owned or contracted power generating units. Exelon has also
contracted for access to additional generation through bilateral long-term power
purchase agreements. These agreements are firm commitments related to power
generation of specific generation plants and/or are dispatchable in nature -
similar to asset ownership. Exelon enters into power purchase agreements with
the objective of obtaining low-cost energy supply sources to meet its physical
delivery obligations to its customers. Exelon has also purchased firm
transmission rights to ensure that it has reliable transmission capacity to
physically move its power supplies to meet customer delivery needs. The intent
and business objective for the use of its capital assets and contracts is to
provide Exelon with physical power supply to enable it to deliver energy to meet
customer needs. Except for hedging purposes, Exelon does not use financial
contracts in its wholesale marketing activities. In 2001, Exelon anticipates the
use of financial contracts to manage the risk surrounding trading for profit
activities.
Exelon has entered into bilateral long-term contractual obligations for
sales of energy to load-serving entities, including electric utilities,
municipalities, electric cooperatives, and retail load aggregators. Exelon also
enters into contractual obligations to deliver energy to wholesale market
participants who
Pgae 32
primarily focus on the resale of energy products for delivery. Exelon provides
delivery of its energy to these customers through access to its transmission
assets or rights for firm transmission.
In addition, Exelon has entered into long-term power purchase
agreements with Independent Power Producers (IPP) under which Exelon makes fixed
capacity payments to the IPP in return for exclusive rights to the energy and
capacity of the generating units for a fixed period. The terms of the long-term
power purchase agreements enable Exelon to supply the fuel and dispatch energy
from the plants.
At December 31, 2000, Exelon had long-term commitments, in millions of
megawatt-hours (MWh) and dollars, relating to the purchase and sale of energy,
capacity and transmission rights from unaffiliated utilities and others as
expressed in the following tables:
Power Only
-----------------------------------------
Purchases Sales
-------------- ----------------
MWh Dollars MWh Dollars
--- ------- --- --------
2001 17 $362 36 $ 840
2002 11 167 18 371
2003 9 135 15 327
2004 5 71 8 190
2005 4 61 6 148
Thereafter 5 81 4 87
------ --------
Total $877 $1,963
====== ========
Capacity Capacity Transmission
Purchases Sales Rights Purchases
in Dollars in Dollars in Dollars
---------- ---------- ----------
2001 $ 856 $ 32 $ 119
2002 881 21 35
2003 786 16 32
2004 778 3 25
2005 414 3 25
Thereafter 5,200 8 80
------- ------ --------
Total $8,915 $ 83 $316
======= ====== ========
In 1997, PECO entered into a power supply contract in Massachusetts. In
1999, PECO determined that, based upon anticipated prices of energy in
Massachusetts through the remaining life of the power supply contract, it had
incurred a loss of approximately $36 million.
PECO entered into a final settlement of litigation in 1999 that
resulted in a restructuring of power purchase agreements between PECO and a
cogeneration facility. The settlement also required PECO to contribute its
partnership interest in the cogeneration facility to the remaining partners.
Accordingly, PECO recorded a charge to earnings of $15 million for the transfer
of its partnership interest which is recorded in Other Income and Deductions on
Exelon's Consolidated Statements of Income. The settlement also resolved related
litigation with Westinghouse Power Generation and the Chase Manhattan Bank.
Subsequently, in 1999, PECO revised its estimate for losses associated with the
cogeneration facility power purchase agreements and reversed approximately $26
million of reserves, which consisted principally of the remaining balance of a
reserve previously recognized in 1997.
Environmental Issues
Exelon's operations have in the past and may in the future require
substantial capital expenditures in order to comply with environmental laws.
Additionally, under Federal and state environmental laws, Exelon, through its
subsidiaries, is generally liable for the costs of remediating environmental
contamination of property now or formerly owned by Exelon and of property
contaminated by hazardous substances generated by Exelon. Exelon owns or leases
a number of real estate parcels, including parcels on which its operations or
the operations of others may have resulted in contamination by substances which
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are considered hazardous under environmental laws. Exelon has identified 72
sites where former manufactured gas plant (MGP) activities have or may have
resulted in actual site contamination. Exelon is currently involved in a number
of proceedings relating to sites where hazardous substances have been deposited
and may be subject to additional proceedings in the future.
As of December 31, 2000 and 1999, Exelon had accrued $172 million and
$57 million, respectively, for environmental investigation and remediation
costs, including $140 million and $32 million, respectively, for MGP
investigation and remediation, that currently can be reasonably estimated. The
increases were primarily attributable to the acquisition of Unicom. Exelon
cannot reasonably estimate whether it will incur other significant liabilities
for additional investigation and remediation costs at these or additional sites
identified by Exelon, environmental agencies or others, or whether such costs
will be recoverable from third parties.
Leases
Minimum future operating lease payments as of December 31, 2000 were:
2001 $ 82
2002 81
2003 78
2004 63
2005 61
Remaining years 633
---
Total minimum future lease payments $998
====
Rental expense under operating leases totaled $41 million, $54 million,
and $69 million in 2000, 1999 and 1998, respectively.
Early Retirement and Separation Program
At December 31, 1998, PECO incurred a charge of $125 million ($74
million, net of income taxes) for its Early Retirement and Separation Program
relating to 1,157 employees. The estimated cost of separation benefits was
approximately $47 million. Retirement benefits of approximately $78 million are
being paid to the retirees over their lives. All cash payments related to the
Early Retirement and Separation Program were funded through the assets of PECO's
Service Annuity Plan. The Early Retirement and Separation Program terminated on
June 30, 2000.
Litigation
Cajun Electric Power Cooperative, Inc. On May 27, 1998, the United
States Department of Justice, on behalf of the Rural Utilities Service and the
Chapter 11 Trustee for the Cajun Electric Power Cooperative, Inc. (Cajun), filed
an action claiming breach of contract against PECO in the United States District
Court for the Middle District of Louisiana arising out of PECO's termination of
the contract to purchase Cajun's interest in the River Bend nuclear power plant.
This action seeks the full purchase price of the 30% interest in the River Bend
nuclear plant, $50 million, plus interest and consequential damages. While PECO
cannot predict the outcome of this matter, PECO believes that it validly
exercised its right of termination and did not breach the agreement.
FERC Municipal Request for Refund. Three of ComEd's wholesale municipal
customers filed a complaint and request for refund with the FERC alleging that
ComEd failed to properly adjust their rates, as provided for under the terms of
their electric service contracts, to track certain refunds made to ComEd's
retail customers in the years 1992 through 1994. In the third quarter of 1998,
the FERC granted the complaint and directed that refunds be made, with interest.
ComEd filed a request for rehearing. On January 11, 2001, the FERC issued its
Order on Rehearing Requesting Submission of Additional Information. Responsive
pleadings have been filed by all parties and final FERC action is still pending.
ComEd's management believes an adequate reserve has been established in
connection with the case.
Service Interruptions. In August 1999, three class action lawsuits were
filed, and subsequently consolidated, in the Circuit Court of Cook County,
Illinois seeking damages for personal injuries, property
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damage and economic losses from ComEd related to a series of service
interruptions that occurred in the summer 1999. The combined effect of these
interruptions resulted in over 168,000 customers losing service for more than 4
hours. Conditional class certification has been approved by the Court for the
sole purpose of exploring settlement talks. A hearing on a motion filed by ComEd
to dismiss the complaints is expected in March 2001. A portion of any settlement
or verdict may be covered by insurance and discussions with the carrier are
ongoing. Exelon's management believes adequate reserves have been established in
connection with these cases.
Reliability Investigation. In 1999, the ICC opened an investigation
regarding the design and reliability of ComEd's transmission and distribution
system, which was expanded during 2000 to include a circuit breaker fire that
occurred in October 2000 at a ComEd substation. The ICC has issued several
reports in that investigation covering the summer 1999 outages as well as the
transmission and distribution system. These reports include recommendations and
an implementation timetable. The recommendations are not legally binding on
ComEd, however, the ICC may enforce them through litigation. Two more reports
are anticipated in early 2001, and the investigation is expected to conclude by
mid-2001. Since summer 1999, ComEd has devoted significant resources to
improving the reliability of its transmission and distribution system. Exelon's
management believes that the likelihood of a successful material claim resulting
from the investigation is remote.
Retail Rate Law. In 1996, several developers of non-utility generating
facilities filed litigation against various Illinois officials claiming that the
enforcement against those facilities of an amendment to Illinois law removing
the entitlement of those facilities to state-subsidized payments for electricity
sold to ComEd after March 15, 1996 violated their rights under the federal and
state constitutions, and against ComEd for a declaratory order that their rights
under their contracts with ComEd were not affected by the amendment. On August
4, 1999, the Illinois Appellate Court held that the developers' claims against
the state were premature, and the Illinois Supreme Court denied leave to appeal
that ruling. Developers of both facilities have since filed amended complaints
repeating their allegations that ComEd breached the contracts in question, and
requesting damages for such breach, in the amount of the difference between the
state-subsidized rate and the amount ComEd was willing to pay for the
electricity. ComEd intends to vigorously contest this matter.
Pennsylvania Real Estate Tax Appeals
Exelon is involved in tax appeals regarding two of its nuclear
facilities, Limerick (Montgomery County) and Peach Bottom (York County). Exelon
is also involved in the tax appeal for Three Mile Island Unit No. 1 Nuclear
Generating Facility (Dauphin County) through AmerGen. Exelon does not believe
the outcome of these matters will have a material adverse effect on Exelon's
results of operations or financial condition.
Other Tax Issues
The Illinois Department of Revenue has issued a notice of tax liability
to ComEd alleging deficiencies in Illinois invested capital tax payments for the
years 1998-1997. The alleged deficiencies, including interest and penalties,
totaled approximately $54 million as of December 31, 2000. ComEd has protested
the notices, and the matter is currently pending. Interest will continue to
accumulate on the alleged tax deficiencies.
General
Exelon is involved in various other litigation matters. The ultimate
outcome of such matters, while uncertain, is not expected to have a material
adverse effect on Exelon's financial condition or results of operations.
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19. Segment Information
Exelon evaluates the performance of its business segments based on
Earnings Before Interest Expense and Income Taxes (EBIT). Exelon's general
corporate expenses and certain non-recurring expenses are excluded from the
internal evaluation of reportable segment performance. General corporate
expenses include the cost of executive management, corporate accounting and
finance, information technology, risk management, human resources and legal
functions and employee benefits.
Energy Delivery consists of the retail electricity distribution and
transmission businesses of ComEd in northern Illinois and PECO in southeastern
Pennsylvania and the natural gas distribution business of PECO. Generation
consists of electric generating facilities, power marketing operations and
Exelon's interests in Sithe and AmerGen. Enterprises consists of competitive
retail energy sales, energy and infrastructure services, communications and
related investments. Effective January 1, 2001, Enterprises will also include
the operations of Exelon Energy, which were previously included in Generation.
An analysis and reconciliation of Exelon's business segment information to the
respective information in the consolidated financial statements are as follows:
Energy Intersegment
Delivery Generation Enterprises Corporate Revenues Consolidated
-------- ---------- ----------- --------- -------- ------------
Revenues:
2000 $ 4,511 $ 3,393 $ 974 $ -- $ (1,379) $ 7,499
1999 $ 3,265 $ 2,896 $ 116 $ -- $ (799) $ 5,478
1998 $ 3,799 $ 2,523 $ 12 $ -- $ (1,009) $ 5,325
EBIT:
2000 $ 1,602 $ 474 $ (71) $ (466)(a) $ -- $ 1,539
1999 $ 1,386 $ 239 $ (41) $ (190) $ -- $ 1,394
1998 $ 1,378 $ 233 $ (139) $ (257)(a) $ -- $ 1,215
Depreciation and Amortization:
2000 $ 223 $ 201 $ 34 $ -- $ -- $ 458
1999 $ 108 $ 125 $ 4 $ -- $ -- $ 237
1998 $ 533 $ 110 $ -- $ -- $ -- $ 643
Capital Expenditures:
2000 $ 367 $ 288 $ 70 $ 27 $ -- $ 752
1999 $ 205 $ 245 $ 1 $ 40 $ -- $ 491
1998 $ 175 $ 205 $ 6 $ 29 $ -- $ 415
Total Assets:
2000 $27,424 $ 5,734 $ 2,277 $ (838) $ -- $ 34,597
1999 $10,306 $ 1,734 $ 640 $ 407 $ -- $ 13,087
1998 $ 9,759 $ 1,687 $ 217 $ 385 $ -- $ 12,048
(a) Includes non-recurring items of $276 million for merger-related expenses in
2000 and $125 million in 1998 for the Early Retirement and Separation
Program.
Equity in losses of communications investments of $45 million, $38 million and
$54 million for 2000, 1999, and 1998, respectively, are included in the
Enterprises business unit's EBIT. Equity in earnings(losses) of AmerGen of $4
million and ($0.5) million for 2000 and 1999, respectively, are included in the
Generation business unit's EBIT.
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20. Quarterly Data (Unaudited)
The data shown below include all adjustments which Exelon considers
necessary for a fair presentation of such amounts:
Income Before
Extraordinary Items and
Operating Operating Cumulative Effect of a Net
Revenues Income Change in Accounting Principle Income
----------------- ------------------ ------------------------------ ----------------
2000 1999 2000 1999 2000 1999 2000 1999
---- ---- ---- ---- ---- ---- ---- ----
Quarter ended:
March 31 $1,352 $1,267 $343(b) $365 $ 163 $154 $192(c) $154
June 30 1,385 1,213 313(b) 245 122 93 116(c) 66
September 30 1,629 1,729 449(b) 471 235 228 232(c) 228
December 31 (a) 3,133 1,269 422(b) 292 46 132 46 122
Earnings Per Share Before
Extraordinary Items and Earnings
Average Shares Cumulative Effect of a Per Share
Outstanding Change in Accounting Principle Net Income
------------- ------------------------------ ---------------
2000 1999 2000 1999 2000 1999
---- ---- ---- ---- ---- ----
(in millions)
Quarter ended:
March 31 184 223 $0.89 $0.69 $1.04 $0.69
June 30 174 192 0.70 0.48 0.68 0.34
September 30 170 187 1.38 1.22 1.37 1.22
December 31 (a) 283 184 0.16 0.71 0.16 0.66
(a) Reflects the effects of the acquisition of Unicom as of October 20, 2000.
(b) Reflects a $276 million charge ($177 million, net of income taxes) for
merger-related costs consisting of $152 million of direct incremental costs and
$124 million for employee costs. Incremental merger expenses of $11 million, $9
million, $13 million and $13 million for each of the four quarters in 2000,
respectively, were reflected in Operating and Maintenance Expense.
(c) Reflects a Cumulative Effect of a Change in Accounting Principle of $24
million as a result of PECO's change in accounting method for nuclear outages to
recognize such expense as incurred rather than accrued over the operating cycle.
See Note 4 - Accounting Change. The effects of the Change in Accounting
Principle were $29 million, or $0.16 per share, $(3) million, or $(0.02) per
share, and $(2) million, or $(0.01) per share in each of the first three
quarters in 2000, respectively.
21. Subsequent Events
Restructuring
During January 2001, Exelon undertook a corporate restructuring to
separate Exelon's generation and other competitive businesses from its regulated
energy delivery business. As part of the restructuring, the non-regulated
operations and related assets of ComEd and PECO were transferred to separate
subsidiaries of Exelon. Restructuring will streamline the process for managing,
operating and tracking financial performance of each business segment.
PETT Refinancing
On March 1, 2001, Exelon refinanced $806 million of floating rate
Series 1999-A Transition Bonds through the issuance by PETT of fixed-rate
transition bonds.
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