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%
==== ==== ====
<FN>
(a) Percentage dollar changes attributable to the operations of Unicom since its
acquisition on October 20, 2000.
</FN>
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.
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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.
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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
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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.