UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended September 30, 2003
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Commission Name of Registrant; State of Incorporation; IRS Employer
File Number Address of Principal Executive Offices; and Identification
Telephone Number Number
- --------------------- --------------------------------------------------------- ------------------------
1-16169 EXELON CORPORATION 23-2990190
(a Pennsylvania corporation)
10 South Dearborn Street - 37th Floor
P.O. Box 805379
Chicago, Illinois 60680-5379
(312) 394-7398
1-1839 COMMONWEALTH EDISON COMPANY 36-0938600
(an Illinois corporation)
10 South Dearborn Street - 37th Floor
P.O. Box 805379
Chicago, Illinois 60680-5379
(312) 394-4321
1-1401 PECO ENERGY COMPANY 23-0970240
(a Pennsylvania corporation)
P.O. Box 8699 2301 Market Street
Philadelphia, Pennsylvania 19101-8699
(215) 841-4000
333-85496 EXELON GENERATION COMPANY, LLC 23-3064219
(a Pennsylvania limited liability company)
300 Exelon Way
Kennett Square, Pennsylvania 19348
(610) 765-6900
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [_].
The number of shares outstanding of each registrant's common stock as of
September 30, 2003 was:
Exelon Corporation Common Stock, without par value 327,021,190
Commonwealth Edison Company Common Stock, $12.50 par value 127,016,483
PECO Energy Company Common Stock, without par value 170,478,507
Exelon Generation Company, LLC not applicable
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act). Exelon Corporation Yes [X] No [ ]
Commonwealth Edison Company, PECO Energy Company and Exelon Generation Company,
LLC Yes [ ] No [X].
TABLE OF CONTENTS
Page No.
--------
FILING FORMAT 3
FORWARD-LOOKING STATEMENTS 3
WHERE TO FIND MORE INFORMATION 3
PART I. FINANCIAL INFORMATION 4
ITEM 1. FINANCIAL STATEMENTS 4
Exelon Corporation
Consolidated Statements of Income and Comprehensive Income 5
Consolidated Statements of Cash Flows 6
Consolidated Balance Sheets 7
Commonwealth Edison Company
Consolidated Statements of Income and Comprehensive Income 9
Consolidated Statements of Cash Flows 10
Consolidated Balance Sheets 11
PECO Energy Company
Consolidated Statements of Income and Comprehensive Income 13
Consolidated Statements of Cash Flows 14
Consolidated Balance Sheets 15
Exelon Generation Company, LLC
Consolidated Statements of Income and Comprehensive Income 17
Consolidated Statements of Cash Flows 18
Consolidated Balance Sheets 19
Condensed Combined Notes to Consolidated Financial Statements 21
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS 71
Exelon Corporation 76
Commonwealth Edison Company 109
PECO Energy Company 124
Exelon Generation Company, LLC 140
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK 157
ITEM 4. CONTROLS AND PROCEDURES 169
PART II. OTHER INFORMATION 172
ITEM 1. LEGAL PROCEEDINGS 172
ITEM 3. DEFAULTS UPON SENIOR SECURITIES 172
ITEM 5. OTHER INFORMATION 173
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K 174
SIGNATURES 176
2
FILING FORMAT
This combined Form 10-Q is being filed separately by Exelon
Corporation (Exelon), Commonwealth Edison Company (ComEd), PECO Energy
Company (PECO) and Exelon Generation Company, LLC (Generation)
(Registrants). Information contained herein relating to any individual
registrant has been filed by such registrant on its own behalf. No
registrant makes any representation as to information relating to any other
registrant.
FORWARD-LOOKING STATEMENTS
Except for the historical information contained herein, certain of
the matters discussed in this Report are forward-looking statements, within
the meaning of the Private Securities Litigation Reform Act of 1995, that
are subject to risks and uncertainties. The factors that could cause actual
results to differ materially from the forward-looking statements made by a
registrant include those factors discussed herein, as well as the items
discussed in (a) the Registrants' 2002 Annual Report on Form 10-K - ITEM 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations--Business Outlook and the Challenges in Managing Our Business
for each of Exelon, ComEd, PECO and Generation, (b) the Registrants' 2002
Annual Report on Form 10-K - ITEM 8. Financial Statements and Supplementary
Data: Exelon - Note 19, ComEd - Note 16, PECO - Note 18 and Generation -
Note 13 and (c) other factors discussed in filings with the United States
Securities and Exchange Commission (SEC) by the Registrants. Readers are
cautioned not to place undue reliance on these forward-looking statements,
which apply only as of the date of this Report. None of the Registrants
undertakes any obligation to publicly release any revision to its
forward-looking statements to reflect events or circumstances after the
date of this Report.
WHERE TO FIND MORE INFORMATION
The public may read and copy any reports or other information that
the Registrants file with the SEC at the SEC's public reference room at 450
Fifth Street, N.W., Washington, D.C. 20549. The public may obtain
information on the operation of the Public Reference Room by calling the
SEC at 1-800-SEC-0330. These documents are also available to the public
from commercial document retrieval services, the web site maintained by the
SEC at www.sec.gov and Exelon's website at www.exeloncorp.com.
3
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
4
EXELON CORPORATION
------------------
EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended Nine Months Ended
------------------ -----------------
September 30, September 30,
------------ -------------
(in millions, except per share data) 2003 2002 2003 2002
- ----------------------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES $ 4,441 $ 4,370 $ 12,236 $ 11,245
OPERATING EXPENSES
Purchased power 1,179 1,233 2,765 2,543
Purchased power from unconsolidated affiliate 133 104 310 220
Fuel 551 373 1,908 1,233
Impairment of Exelon Boston Generating, LLC long-lived assets 945 -- 945 --
Operating and maintenance 1,226 1,114 3,438 3,252
Depreciation and amortization 293 345 842 1,012
Taxes other than income 131 201 489 568
- ---------------------------------------------------------------------------------------------------------------------------------
Total operating expenses 4,458 3,370 10,697 8,828
- ---------------------------------------------------------------------------------------------------------------------------------
OPERATING INCOME (LOSS) (17) 1,000 1,539 2,417
- ---------------------------------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest expense (213) (249) (652) (739)
Interest expense to affiliates (4) -- (9) --
Distributions on preferred securities of subsidiaries (8) (11) (30) (34)
Equity in earnings of unconsolidated affiliates 49 92 82 114
Other, net (21) 16 (153) 239
- ---------------------------------------------------------------------------------------------------------------------------------
Total other income and deductions (197) (152) (762) (420)
- ---------------------------------------------------------------------------------------------------------------------------------
INCOME (LOSS) BEFORE INCOME TAXES AND CUMULATIVE
EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES (214) 848 777 1,997
INCOME TAXES (112) 297 258 724
- ---------------------------------------------------------------------------------------------------------------------------------
INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF CHANGES IN
ACCOUNTING PRINCIPLES (102) 551 519 1,273
CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING
PRINCIPLES (net of income taxes of $69 and $(90) for the nine
months ended September 30, 2003 and 2002, respectively) -- -- 112 (230)
- ---------------------------------------------------------------------------------------------------------------------------------
NET INCOME (LOSS) (102) 551 631 1,043
- ---------------------------------------------------------------------------------------------------------------------------------
OTHER COMPREHENSIVE INCOME (LOSS) (net of income taxes)
Minimum pension liability 9 -- 9 --
Cash flow hedge adjustment 142 (32) 58 (103)
Foreign currency translation adjustment -- -- 2 --
Unrealized gain (loss) on marketable securities 5 (73) 3 (158)
SFAS No. 143 transition adjustment -- -- 168 --
Interest in other comprehensive income (loss)
of unconsolidated affiliates 1 (20) 9 (21)
- ---------------------------------------------------------------------------------------------------------------------------------
Total other comprehensive income (loss) 157 (125) 249 (282)
- ---------------------------------------------------------------------------------------------------------------------------------
TOTAL COMPREHENSIVE INCOME $ 55 $ 426 $ 880 $ 761
==================================================================================================================================
AVERAGE SHARES OF COMMON STOCK OUTSTANDING - Basic 326 323 325 322
==================================================================================================================================
AVERAGE SHARES OF COMMON STOCK OUTSTANDING - Diluted 326 324 328 324
==================================================================================================================================
EARNINGS (LOSS) PER AVERAGE COMMON SHARE:
BASIC:
Income (loss) before cumulative effect of changes in
accounting principles $ (0.31) $ 1.71 $ 1.60 $ 3.95
Cumulative effect of changes in accounting principles -- -- 0.34 (0.71)
- ---------------------------------------------------------------------------------------------------------------------------------
Net income (loss) $ (0.31) $ 1.71 $ 1.94 $ 3.24
==================================================================================================================================
DILUTED:
Income (loss) before cumulative effect of changes in
accounting principles $ (0.31) $ 1.70 $ 1.59 $ 3.93
Cumulative effect of changes in accounting principles -- -- 0.34 (0.71)
- ---------------------------------------------------------------------------------------------------------------------------------
Net income (loss) $ (0.31) $ 1.70 $ 1.93 $ 3.22
==================================================================================================================================
DIVIDENDS PER COMMON SHARE $ 0.50 $ 0.44 $ 1.42 $ 1.32
==================================================================================================================================
See Condensed Combined Notes to Consolidated Financial Statements
5
EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended September 30,
-------------------------------
(in millions) 2003 2002
- -----------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 631 $ 1,043
Adjustments to reconcile net income to net cash flows provided by
operating activities:
Depreciation, amortization and accretion, including nuclear fuel 1,290 1,284
Cumulative effect of changes in accounting principles (net of income taxes) (112) 230
Gain on sale of investment -- (199)
Provision for uncollectible accounts 72 107
Deferred income taxes (363) 293
Equity in earnings of unconsolidated affiliates (82) (114)
Impairment of investments 295 46
Impairment of long-lived assets 950 --
Employee severance-related costs 152 --
Pension and non-pension postretirement curtailment costs 26 --
Net realized (gains) losses on nuclear decommissioning trust funds (9) 32
Other operating activities 91 56
Changes in assets and liabilities:
Accounts receivable (19) (358)
Inventories (55) (25)
Accounts payable, accrued expenses and other current liabilities 50 1
Changes in payables and receivables from unconsolidated affiliates 18 46
Other current assets (100) 68
Pension and non-pension postretirement benefits obligations (241) 22
Other noncurrent assets and liabilities (41) 131
- -----------------------------------------------------------------------------------------------------------------------
Net cash flows provided by operating activities 2,553 2,663
- -----------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (1,501) (1,534)
Proceeds from liquidated damages 92 --
Proceeds from nuclear decommissioning trust funds 1,880 1,184
Investment in nuclear decommissioning trust funds (2,043) (1,330)
Note receivable from unconsolidated affiliate 35 (42)
Proceeds from sale of investments 186 287
Acquisition of generating plants -- (443)
Other investing activities 50 19
- -----------------------------------------------------------------------------------------------------------------------
Net cash flows used in investing activities (1,301) (1,859)
- -----------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt 2,105 956
Retirement of long-term debt (2,075) (1,946)
Change in short-term debt (599) 428
Issuance of long-term debt to affiliate 103 --
Issuance of mandatorily redeemable preferred securities of subsidiaries 200 --
Retirement of mandatorily redeemable preferred securities of subsidiaries (250) (18)
Retirement of preferred stock of subsidiaries (50) --
Dividends paid on common stock (461) (420)
Payment on acquisition note payable to Sithe Energies, Inc. (210) --
Proceeds from employee stock plans 139 64
Contribution from minority interest of consolidated subsidiary -- 43
Change in restricted cash 78 81
Other financing activities (85) (16)
- -----------------------------------------------------------------------------------------------------------------------
Net cash flows used in financing activities (1,105) (828)
- -----------------------------------------------------------------------------------------------------------------------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 147 (24)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 469 485
- -----------------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS INCLUDING CASH CLASSIFIED AS HELD FOR SALE $ 616 $ 461
CASH CLASSIFIED AS HELD FOR SALE ON THE CONSOLIDATED BALANCE SHEET (12) --
- -----------------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 604 $ 461
=======================================================================================================================
See Condensed Combined Notes to Consolidated Financial Statements
6
EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,
(in millions) 2003 2002
- -----------------------------------------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 604 $ 469
Restricted cash 318 396
Accounts receivable, net
Customer 1,952 2,076
Other 270 284
Receivable from unconsolidated affiliate --- 39
Inventories, at average cost
Fossil fuel 198 175
Materials and supplies 289 306
Other 429 380
Assets held for sale 109 --
- -----------------------------------------------------------------------------------------------------------------------
Total current assets 4,169 4,125
- -----------------------------------------------------------------------------------------------------------------------
PROPERTY, PLANT AND EQUIPMENT, NET 19,476 17,126
DEFERRED DEBITS AND OTHER ASSETS
Regulatory assets 5,304 5,993
Nuclear decommissioning trust funds 3,404 3,053
Investments 1,198 1,403
Goodwill 4,734 4,992
Other 859 793
- -----------------------------------------------------------------------------------------------------------------------
Total deferred debits and other assets 15,499 16,234
- -----------------------------------------------------------------------------------------------------------------------
TOTAL ASSETS $ 39,144 $ 37,485
=======================================================================================================================
See Condensed Combined Notes to Consolidated Financial Statements
7
EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,
(in millions) 2003 2002
- -----------------------------------------------------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Notes payable $ 82 $ 681
Note payable to unconsolidated affiliate 326 534
Long-term debt due within one year 2,067 1,402
Accounts payable 1,692 1,607
Accrued expenses 1,242 1,354
Other 287 296
Liabilities held for sale 57 --
- -----------------------------------------------------------------------------------------------------------------------
Total current liabilities 5,753 5,874
- -----------------------------------------------------------------------------------------------------------------------
LONG-TERM DEBT 12,468 13,127
LONG-TERM DEBT TO AFFILIATE 103 --
MANDATORILY REDEEMABLE PREFERRED SECURITIES 422 --
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred income taxes 3,798 3,702
Unamortized investment tax credits 291 301
Nuclear decommissioning liability for retired plants -- 1,395
Asset retirement obligation 2,481 --
Pension obligation 1,609 1,959
Non-pension postretirement benefits obligation 1,033 877
Spent nuclear fuel obligation 865 858
Regulatory liabilities 880 --
Other 1,026 978
- -----------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 11,983 10,070
- -----------------------------------------------------------------------------------------------------------------------
Total liabilities 30,729 29,071
- -----------------------------------------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES
MINORITY INTEREST OF CONSOLIDATED SUBSIDIARIES 1 77
PREFERRED SECURITIES OF SUBSIDIARIES 87 595
SHAREHOLDERS' EQUITY
Common stock 7,226 7,059
Deferred compensation -- (1)
Retained earnings 2,210 2,042
Accumulated other comprehensive income (loss) (1,109) (1,358)
- -----------------------------------------------------------------------------------------------------------------------
Total shareholders' equity 8,327 7,742
- -----------------------------------------------------------------------------------------------------------------------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 39,144 $ 37,485
=======================================================================================================================
See Condensed Combined Notes to Consolidated Financial Statements
8
COMMONWEALTH EDISON COMPANY
---------------------------
COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended Nine Months Ended
------------------ -----------------
September 30, September 30,
------------- -------------
(in millions) 2003 2002 2003 2002
- -----------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES
Operating revenues $ 1,717 $ 1,912 $ 4,473 $ 4,685
Operating revenues from affiliates 20 26 49 49
- -----------------------------------------------------------------------------------------------------------------------
Total operating revenues 1,737 1,938 4,522 4,734
- -----------------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES
Purchased power 6 8 17 20
Purchased power from affiliate 885 967 1,984 2,046
Operating and maintenance 259 234 683 620
Operating and maintenance from affiliates 40 33 98 104
Depreciation and amortization 97 129 287 397
Taxes other than income 87 77 235 223
- -----------------------------------------------------------------------------------------------------------------------
Total operating expenses 1,374 1,448 3,304 3,410
- -----------------------------------------------------------------------------------------------------------------------
OPERATING INCOME 363 490 1,218 1,324
- -----------------------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest expense (107) (122) (322) (374)
Distributions on mandatorily redeemable preferred securities (6) (7) (20) (22)
Interest income from affiliates 6 8 20 23
Other, net 9 (8) 28 6
- -----------------------------------------------------------------------------------------------------------------------
Total other income and deductions (98) (129) (294) (367)
- -----------------------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT
OF A CHANGE IN ACCOUNTING PRINCIPLE 265 361 924 957
INCOME TAXES 102 146 365 381
- -----------------------------------------------------------------------------------------------------------------------
INCOME BEFORE CUMULATIVE EFFECT OF A CHANGE IN
ACCOUNTING PRINCIPLE 163 215 559 576
CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING
PRINCIPLE (net of income taxes of $0) -- -- 5 --
- -----------------------------------------------------------------------------------------------------------------------
NET INCOME 163 215 564 576
- -----------------------------------------------------------------------------------------------------------------------
OTHER COMPREHENSIVE INCOME (LOSS) (net of income taxes)
Cash flow hedge adjustment 3 (19) 31 (25)
Unrealized gain (loss) on marketable securities 2 (1) 3 (3)
Foreign currency translation adjustment -- -- 2 --
- -----------------------------------------------------------------------------------------------------------------------
Total other comprehensive income (loss) 5 (20) 36 (28)
- -----------------------------------------------------------------------------------------------------------------------
TOTAL COMPREHENSIVE INCOME $ 168 $ 195 $ 600 $ 548
=======================================================================================================================
See Condensed Combined Notes to Consolidated Financial Statements
9
COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended September 30,
-------------------------------
(in millions) 2003 2002
- -----------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 564 $ 576
Adjustments to reconcile net income to net cash flows provided by
operating activities:
Depreciation and amortization 287 397
Cumulative effect of a change in accounting principle (net of income taxes) (5) --
Gain on sale of investments (3) --
Provision for uncollectible accounts 31 29
Deferred income taxes 92 92
Employee severance-related costs 58 --
Pension and non-pension postretirement curtailment costs 2 --
Other operating activities 49 76
Changes in assets and liabilities:
Accounts receivable (55) (198)
Inventories 7 (4)
Accounts payable, accrued expenses and other current liabilities (102) 52
Changes in receivables and payables to affiliates (45) 449
Other current assets (12) (2)
Pension and non-pension postretirement benefits obligations (112) 15
Other noncurrent assets and liabilities (14) 9
- -----------------------------------------------------------------------------------------------------------------------
Net cash flows provided by operating activities 742 1,491
- -----------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (537) (549)
Investment in affiliate money pool (147) --
Notes receivable from affiliates 213 14
Proceeds from sale of investments 5 --
Other investing activities 16 7
- -----------------------------------------------------------------------------------------------------------------------
Net cash flows used in investing activities (450) (528)
- -----------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt 1,427 701
Retirement of long-term debt (1,139) (1,365)
Issuance of mandatorily redeemable preferred securities 200 --
Retirement of mandatorily redeemable preferred securities (200) --
Change in short-term debt (71) 94
Dividends paid on common stock (305) (353)
Change in restricted cash (17) (37)
Settlement of cash flow hedges (45) (10)
Other financing activities (36) --
- -----------------------------------------------------------------------------------------------------------------------
Net cash flows used in financing activities (186) (970)
- -----------------------------------------------------------------------------------------------------------------------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 106 (7)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 16 23
- -----------------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 122 $ 16
=======================================================================================================================
SUPPLEMENTAL CASH FLOW INFORMATION
Noncash investing and financing activities:
Retirement of treasury shares $ -- $ 1,344
Adoption of SFAS No. 143 - adjustment to other paid in capital and goodwill 210 --
See Condensed Combined Notes to Consolidated Financial Statements
10
COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,
(in millions) 2003 2002
- -----------------------------------------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 122 $ 16
Restricted cash 82 65
Accounts receivable, net
Customer 818 782
Other 60 72
Inventories, at average cost 50 65
Deferred income taxes 19 20
Receivables from affiliates 151 15
Other 26 14
- -----------------------------------------------------------------------------------------------------------------------
Total current assets 1,328 1,049
- -----------------------------------------------------------------------------------------------------------------------
PROPERTY, PLANT AND EQUIPMENT, NET 8,039 7,756
DEFERRED DEBITS AND OTHER ASSETS
Regulatory assets -- 447
Investments 36 42
Goodwill 4,711 4,916
Receivables from affiliates 2,228 1,300
Prepaid pension asset 48 --
Other 389 320
- -----------------------------------------------------------------------------------------------------------------------
Total deferred debits and other assets 7,412 7,025
- -----------------------------------------------------------------------------------------------------------------------
TOTAL ASSETS $ 16,779 $ 15,830
=======================================================================================================================
See Condensed Combined Notes to Consolidated Financial Statements
11
COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,
(in millions) 2003 2002
- -----------------------------------------------------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Notes payable $ -- $ 71
Long-term debt due within one year 519 698
Accounts payable 207 201
Accrued expenses 465 538
Payables to affiliates 186 416
Customer deposits 78 81
Other 13 18
- -----------------------------------------------------------------------------------------------------------------------
Total current liabilities 1,468 2,023
- -----------------------------------------------------------------------------------------------------------------------
LONG-TERM DEBT 5,755 5,268
MANDATORILY REDEEMABLE PREFERRED SECURITIES 344 --
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred income taxes 1,776 1,650
Unamortized investment tax credits 49 51
Pension obligation -- 91
Non-pension postretirement benefits obligation 187 138
Payables to affiliates 39 224
Regulatory liabilities 880 --
Other 332 297
- -----------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 3,263 2,451
- -----------------------------------------------------------------------------------------------------------------------
Total liabilities 10,830 9,742
- -----------------------------------------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES
MANDATORILY REDEEMABLE PREFERRED SECURITIES -- 330
SHAREHOLDERS' EQUITY
Common stock 1,588 1,588
Preference stock 7 7
Other paid in capital 4,029 4,239
Receivable from parent (509) (615)
Retained earnings 836 577
Accumulated other comprehensive income (loss) (2) (38)
- -----------------------------------------------------------------------------------------------------------------------
Total shareholders' equity 5,949 5,758
- -----------------------------------------------------------------------------------------------------------------------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 16,779 $ 15,830
=======================================================================================================================
See Condensed Combined Notes to Consolidated Financial Statements
12
PECO ENERGY COMPANY
-------------------
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended Nine Months Ended
------------------ -----------------
September 30, September 30,
------------- -------------
(in millions) 2003 2002 2003 2002
- -----------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES
Operating revenues $ 1,146 $ 1,221 $ 3,319 $ 3,230
Operating revenues from affiliates 3 3 9 9
- -----------------------------------------------------------------------------------------------------------------------
Total operating revenues 1,149 1,224 3,328 3,239
- -----------------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES
Purchased power 61 68 189 175
Purchased power from affiliate 421 441 1,101 1,090
Fuel 28 40 285 228
Operating and maintenance 178 125 414 350
Operating and maintenance from affiliates 14 15 39 57
Depreciation and amortization 134 127 370 348
Taxes other than income 12 85 123 207
- -----------------------------------------------------------------------------------------------------------------------
Total operating expenses 848 901 2,521 2,455
- -----------------------------------------------------------------------------------------------------------------------
OPERATING INCOME 301 323 807 784
- -----------------------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest expense (73) (93) (241) (280)
Interest expense to affiliate (2) -- (2) --
Distributions on mandatorily redeemable preferred securities (1) (2) (6) (7)
Other, net (10) 5 -- 7
- -----------------------------------------------------------------------------------------------------------------------
Total other income and deductions (86) (90) (249) (280)
- -----------------------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 215 233 558 504
INCOME TAXES 74 76 193 166
- -----------------------------------------------------------------------------------------------------------------------
NET INCOME 141 157 365 338
Preferred stock dividends (1) (2) (4) (6)
- -----------------------------------------------------------------------------------------------------------------------
NET INCOME ON COMMON STOCK $ 140 $ 155 $ 361 $ 332
=======================================================================================================================
OTHER COMPREHENSIVE INCOME (LOSS) (net of income taxes)
Net income $ 141 $ 157 $ 365 $ 338
Other comprehensive income (loss) (net of income taxes):
Cash flow hedge adjustment 2 (5) 2 (10)
Unrealized gain (loss) on marketable securities 1 (1) 1 --
- -----------------------------------------------------------------------------------------------------------------------
Total other comprehensive income (loss) 3 (6) 3 (10)
- -----------------------------------------------------------------------------------------------------------------------
TOTAL COMPREHENSIVE INCOME $ 144 $ 151 $ 368 $ 328
=======================================================================================================================
See Condensed Combined Notes to Consolidated Financial Statements
13
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended September 30,
--------------------------------
(in millions) 2003 2002
- -----------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 365 $ 338
Adjustments to reconcile net income to net cash flows provided by
operating activities:
Depreciation and amortization 370 348
Provision for uncollectible accounts 38 48
Deferred income taxes (76) (64)
Employee severance-related costs 25 --
Pension and non-pension postretirement curtailment costs 16 --
Other operating activities (2) (2)
Changes in assets and liabilities:
Accounts receivable 25 (69)
Changes in receivables and payables to affiliates 68 (27)
Inventories (44) (8)
Accounts payable, accrued expenses and other current liabilities 39 (107)
Prepaid taxes (46) (49)
Deferred energy costs (33) 50
Other current assets (4) (2)
Pension and non-pension postretirement benefits obligations 17 8
Other noncurrent assets and liabilities (1) 9
- -----------------------------------------------------------------------------------------------------------------------
Net cash flows provided by operating activities 757 473
- -----------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (191) (180)
Other investing activities (2) 3
- -----------------------------------------------------------------------------------------------------------------------
Net cash flows used in investing activities (193) (177)
- -----------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt 450 225
Retirement of long-term debt (709) (571)
Issuance of long-term debt to affiliate 103 --
Retirement of mandatorily redeemable preferred securities (50) (19)
Retirement of preferred stock (50) --
Change in short-term debt (188) 274
Dividends paid on preferred and common stock (248) (261)
Contribution from parent 17 30
Change in restricted cash 132 113
Other financing activities (2) (5)
- -----------------------------------------------------------------------------------------------------------------------
Net cash flows used in financing activities (545) (214)
- -----------------------------------------------------------------------------------------------------------------------
INCREASE IN CASH AND CASH EQUIVALENTS 19 82
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 63 32
- -----------------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 82 $ 114
=======================================================================================================================
See Condensed Combined Notes to Consolidated Financial Statements
14
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,
(in millions) 2003 2002
- -----------------------------------------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 82 $ 63
Restricted cash 199 331
Accounts receivable, net
Customer 326 379
Other 32 39
Inventories, at average cost
Fossil fuel 111 67
Materials and supplies 8 8
Deferred energy costs 64 31
Prepaid taxes 47 1
Other 11 8
- -----------------------------------------------------------------------------------------------------------------------
Total current assets 880 927
- -----------------------------------------------------------------------------------------------------------------------
PROPERTY, PLANT AND EQUIPMENT, NET 4,239 4,159
DEFERRED DEBITS AND OTHER ASSETS
Regulatory assets 5,304 5,546
Investments 23 19
Prepaid pension asset 62 41
Other 22 28
- -----------------------------------------------------------------------------------------------------------------------
Total deferred debits and other assets 5,411 5,634
- -----------------------------------------------------------------------------------------------------------------------
TOTAL ASSETS $ 10,530 $ 10,720
=======================================================================================================================
See Condensed Combined Notes to Consolidated Financial Statements
15
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,
(in millions) 2003 2002
- -----------------------------------------------------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Notes payable $ 12 $ 200
Payables to affiliates 142 170
Long-term debt due within one year 292 689
Accounts payable 66 87
Accrued expenses 402 332
Deferred income taxes 27 27
Other 36 33
- -----------------------------------------------------------------------------------------------------------------------
Total current liabilities 977 1,538
- -----------------------------------------------------------------------------------------------------------------------
LONG-TERM DEBT 5,087 4,951
LONG-TERM DEBT TO AFFILIATE 103 --
MANDATORILY REDEEMABLE PREFERRED SECURITIES 78 --
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred income taxes 2,855 2,903
Unamortized investment tax credits 22 24
Non-pension postretirement benefits obligation 317 251
Payable to affiliate 7 --
Other 140 164
- -----------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 3,341 3,342
- -----------------------------------------------------------------------------------------------------------------------
Total liabilities 9,586 9,831
- -----------------------------------------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES
MANDATORILY REDEEMABLE PREFERRED SECURITIES -- 128
SHAREHOLDERS' EQUITY
Common stock 1,993 1,976
Receivable from parent (1,661) (1,758)
Preferred stock 87 137
Retained earnings 517 401
Accumulated other comprehensive income 8 5
- -----------------------------------------------------------------------------------------------------------------------
Total shareholders' equity 944 761
- -----------------------------------------------------------------------------------------------------------------------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 10,530 $ 10,720
=======================================================================================================================
See Condensed Combined Notes to Consolidated Financial Statements
16
EXELON GENERATION COMPANY, LLC
------------------------------
EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended, Nine Months Ended,
------------------ -----------------
September 30, September 30,
------------------ -----------------
(in millions) 2003 2002 2003 2002
- -----------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES
Operating revenues $ 1,180 $ 750 $ 3,055 $ 1,924
Operating revenues from affiliates 1,357 1,463 3,246 3,309
- -----------------------------------------------------------------------------------------------------------------------
Total operating revenues 2,537 2,213 6,301 5,233
- -----------------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES
Purchased power 1,096 1,147 2,531 2,334
Purchased power from affiliates 144 110 350 247
Fuel 449 273 1,156 706
Impairment of Exelon Boston Generating, LLC long-lived assets 945 -- 945 --
Operating and maintenance 476 351 1,337 1,098
Operating and maintenance from affiliates 54 40 136 136
Depreciation and amortization 51 68 142 197
Taxes other than income 28 37 115 126
- -----------------------------------------------------------------------------------------------------------------------
Total operating expenses 3,243 2,026 6,712 4,844
- -----------------------------------------------------------------------------------------------------------------------
OPERATING INCOME (LOSS) (706) 187 (411) 389
- -----------------------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest expense (22) (22) (52) (48)
Interest expense - affiliates (3) (1) (11) (3)
Equity in earnings of unconsolidated affiliates 53 87 90 119
Other, net (30) 14 (164) 54
- -----------------------------------------------------------------------------------------------------------------------
Total other income and deductions (2) 78 (137) 122
- -----------------------------------------------------------------------------------------------------------------------
INCOME (LOSS) BEFORE INCOME TAXES AND CUMULATIVE
EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES (708) 265 (548) 511
INCOME TAXES (280) 102 (209) 198
- -----------------------------------------------------------------------------------------------------------------------
INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF CHANGES IN
ACCOUNTING PRINCIPLES (428) 163 (339) 313
CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING
PRINCIPLES (net of income taxes of $70 and $9 for the nine
months ended September 30, 2003 and 2002, respectively) -- -- 108 13
- -----------------------------------------------------------------------------------------------------------------------
NET INCOME (LOSS) (428) 163 (231) 326
- -----------------------------------------------------------------------------------------------------------------------
OTHER COMPREHENSIVE INCOME (LOSS) (net of income taxes)
Cash flow hedge adjustment 147 (11) 30 (79)
Unrealized gain (loss) on marketable securities 1 (69) (1) (151)
SFAS No. 143 transition adjustment -- -- 168 --
Interest in other comprehensive income (loss)
of unconsolidated affiliates 1 (20) 9 (21)
- -----------------------------------------------------------------------------------------------------------------------
Total other comprehensive income (loss) 149 (100) 206 (251)
- -----------------------------------------------------------------------------------------------------------------------
TOTAL COMPREHENSIVE INCOME (LOSS) $ (279) $ 63 $ (25) $ 75
=======================================================================================================================
See Condensed Combined Notes to Consolidated Financial Statements
17
EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended September 30,
-------------------------------
(in millions) 2003 2002
- -----------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss) $ (231) $ 326
Adjustments to reconcile net income (loss) to net cash flows provided
by operating activities:
Depreciation, amortization and accretion, including nuclear fuel 594 475
Cumulative effect of changes in accounting principles (net of income taxes) (108) (13)
Provision for uncollectible accounts 1 20
Deferred income taxes (393) 246
Equity in earnings of unconsolidated affiliates (90) (119)
Impairment of investment 255 --
Impairment of long-lived assets 950 --
Employee severance-related costs 45 --
Pension and non-pension postretirement curtailment costs 6 --
Net realized (gains) losses on nuclear decommissioning trust funds (9) 32
Other operating activities 6 33
Changes in assets and liabilities:
Accounts receivable (124) (90)
Changes in receivables and payables to affiliates, net 254 (278)
Inventories (10) (16)
Accounts payable, accrued expenses and other current liabilities 100 153
Other current assets (16) (95)
Pension and non-pension postretirement benefits obligations (91) (3)
Other noncurrent assets and liabilities 2 100
- -----------------------------------------------------------------------------------------------------------------------
Net cash flows provided by operating activities 1,141 771
- -----------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (733) (715)
Proceeds from liquidated damages 92 --
Proceeds from nuclear decommissioning trust funds 1,880 1,184
Investment in nuclear decommissioning trust funds (2,043) (1,330)
Notes receivable from affiliates 20 (42)
Acquisition of generating plants -- (443)
Other investing activities 12 3
- -----------------------------------------------------------------------------------------------------------------------
Net cash flows used in investing activities (772) (1,343)
- -----------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt 211 30
Retirement of long-term debt (4) (4)
Payment on acquisition note payable to Sithe Energies, Inc. (210) --
Proceeds (repayment) of affiliate money pool funds (178) 348
Distribution to member (116) (30)
Contribution from minority interest of consolidated subsidiary -- 43
Change in restricted cash (25) --
Other financing activities (2) --
- -----------------------------------------------------------------------------------------------------------------------
Net cash flows (used in) provided by financing activities (324) 387
- -----------------------------------------------------------------------------------------------------------------------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 45 (185)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 58 224
- -----------------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 103 $ 39
=======================================================================================================================
SUPPLEMENTAL CASH FLOW INFORMATION
Noncash financing activities:
Distribution to member $ 17 $ --
See Condensed Combined Notes to Consolidated Financial Statements
18
EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,
(in millions) 2003 2002
- -----------------------------------------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 103 $ 58
Restricted cash 37 --
Accounts receivable, net
Customer 644 587
Other 92 57
Receivables from affiliates 313 594
Inventories, at average cost
Fossil fuel 72 97
Materials and supplies 229 217
Deferred income taxes 2 7
Other 192 188
- -----------------------------------------------------------------------------------------------------------------------
Total current assets 1,684 1,805
- -----------------------------------------------------------------------------------------------------------------------
PROPERTY, PLANT AND EQUIPMENT, NET 7,010 4,800
DEFERRED DEBITS AND OTHER ASSETS
Nuclear decommissioning trust funds 3,404 3,053
Investments 487 657
Receivable from affiliate 41 220
Deferred income taxes 292 271
Prepaid pension asset 98 --
Other 224 201
- -----------------------------------------------------------------------------------------------------------------------
Total deferred debits and other assets 4,546 4,402
- -----------------------------------------------------------------------------------------------------------------------
TOTAL ASSETS $ 13,240 $ 11,007
=======================================================================================================================
See Condensed Combined Notes to Consolidated Financial Statements
19
EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,
(in millions) 2003 2002
- -----------------------------------------------------------------------------------------------------------------------
LIABILITIES AND MEMBER'S EQUITY
CURRENT LIABILITIES
Long-term debt due within one year $ 1,251 $ 5
Accounts payable 1,287 1,126
Payables to affiliates 67 10
Notes payable to affiliates 477 863
Accrued expenses 397 482
Other 90 108
- -----------------------------------------------------------------------------------------------------------------------
Total current liabilities 3,569 2,594
- -----------------------------------------------------------------------------------------------------------------------
LONG-TERM DEBT 1,110 2,132
DEFERRED CREDITS AND OTHER LIABILITIES
Unamortized investment tax credits 220 226
Nuclear decommissioning liability for retired plants -- 1,395
Asset retirement obligation 2,479 --
Pension obligation -- 37
Non-pension postretirement benefits obligation 480 410
Spent nuclear fuel obligation 865 858
Payable to affiliate 1,144 --
Other 421 402
- -----------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 5,609 3,328
- -----------------------------------------------------------------------------------------------------------------------
Total liabilities 10,288 8,054
- -----------------------------------------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES
MINORITY INTEREST OF CONSOLIDATED SUBSIDIARY -- 54
MEMBER'S EQUITY
Membership interest 2,490 2,296
Undistributed earnings 577 924
Accumulated other comprehensive income (loss) (115) (321)
- -----------------------------------------------------------------------------------------------------------------------
Total member's equity 2,952 2,899
- -----------------------------------------------------------------------------------------------------------------------
TOTAL LIABILITIES AND MEMBER'S EQUITY $13,240 $ 11,007
=======================================================================================================================
See Condensed Combined Notes to Consolidated Financial Statements
20
EXELON CORPORATION AND SUBSIDIARY COMPANIES
COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONDENSED COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)
1. BASIS OF PRESENTATION (Exelon, ComEd, PECO and Generation)
The consolidated financial statements of Exelon Corporation
(Exelon), Commonwealth Edison Company (ComEd), PECO Energy Company (PECO)
and Exelon Generation Company, LLC (Generation) include the accounts of
their majority-owned subsidiaries after the elimination of intercompany
transactions. Investments and joint ventures in which a 20% to 50% interest
is owned and a significant influence is exerted are accounted for under the
equity method of accounting. PECO Energy Capital Trust IV (PECO Trust IV),
which was created in May 2003, is a wholly owned financing subsidiary of
PECO. As of July 1, 2003, PECO Trust IV is no longer consolidated within
the financial statements of Exelon or PECO. See Note 2 - New Accounting
Principles and Accounting Changes for further discussion of the
deconsolidation of this entity.
The accompanying consolidated financial statements as of September
30, 2003 and for the three and nine months then ended are unaudited, but,
in the opinions of the managements of Exelon, ComEd, PECO and Generation,
include all adjustments that are considered necessary for a fair
presentation of their respective financial statements. All adjustments are
of a normal, recurring nature, except as otherwise disclosed. The December
31, 2002 Consolidated Balance Sheets were derived from audited financial
statements but do not include all disclosures required by accounting
principles generally accepted in the United States of America (GAAP).
Certain prior-year amounts have been reclassified for comparative purposes.
These reclassifications had no effect on net income or shareholders' or
member's equity. These notes should be read in conjunction with the Notes
to Consolidated Financial Statements of Exelon, ComEd, PECO and Generation
included in or incorporated by reference in ITEM 8 of their Annual Reports
on Form 10-K for the year ended December 31, 2002.
2. NEW ACCOUNTING PRINCIPLES AND ACCOUNTING CHANGES (Exelon, ComEd, PECO
and Generation)
Accounting Principles with a Cumulative Effect upon Adoption
SFAS No. 143
Financial Accounting Standards Board (FASB) Statement of Financial
Accounting Standards (SFAS) No. 143, "Accounting for Asset Retirement
Obligations" (SFAS No. 143) provides accounting requirements for retirement
obligations (whether statutory, contractual or as a result of principles of
promissory estoppel) associated with tangible long-lived assets. Exelon,
ComEd, PECO and Generation were required to adopt SFAS No. 143 as of
January 1, 2003. A significant retirement obligation is Generation's
obligation to decommission its nuclear plants at the end of their license
21
lives projected to be from 2029 through 2056. These nuclear plants, the
decommissioning obligation and the related nuclear decommissioning trust
fund investments were transferred to Generation by ComEd and PECO in
connection with the Exelon corporate restructuring on January 1, 2001.
Generation had decommissioning assets in trust accounts of $3,404
million and $3,053 million as of September 30, 2003 and December 31, 2002,
respectively. Generation anticipates that all trust fund assets will
ultimately be used to decommission Generation's nuclear plants.
After considering interpretations of the transitional guidance
included in SFAS No. 143, Exelon recorded income of $112 million (net of
income taxes) as a cumulative effect of a change in accounting principle in
connection with its adoption of this standard in the first quarter of 2003.
The components of the cumulative effect of a change in accounting
principle, net of income taxes, were as follows:
---------------------------------------------------------------------------
Generation (net of income taxes of $52) $ 80
Generation's investments in AmerGen Energy Company, LLC and
Sithe Energies, Inc. (net of income taxes of $18) 28
ComEd (net of income taxes of $0) 5
Exelon Enterprises Company, LLC (net of income taxes of $(1)) (1)
---------------------------------------------------------------------------
Total $ 112
===========================================================================
The cumulative effect of the change in accounting principle in
adopting SFAS No. 143 had no impact on PECO's income statement.
The asset retirement obligation (ARO) as of January 1, 2003 was
determined under SFAS No. 143 to be $2,366 million and $2,363 million for
Exelon and Generation, respectively. As further explained below, the
adoption also resulted in recording regulatory assets and liabilities.
Exelon's accretion expense of the ARO for the three and nine months ended
September 30, 2003 was $39 million and $117 million, respectively.
Generation's accretion expense for the three and nine months ended
September 30, 2003 was $39 million and $116 million, respectively. The
following table provides a reconciliation of the AROs reflected on the
balance sheet at December 31, 2002 and September 30, 2003:
Generation Exelon
----------------------------------------------------------------------------------------------------
Accumulated depreciation $ 2,845 $ 2,845
Nuclear decommissioning liability for retired units 1,395 1,395
----------------------------------------------------------------------------------------------------
Decommissioning obligation at December 31, 2002 4,240 4,240
Net reduction due to adoption of SFAS No. 143 1,877 1,874
----------------------------------------------------------------------------------------------------
Asset retirement obligation at January 1, 2003 2,363 2,366
Reclassification of Enterprises ARO to liabilities held for sale
during the third quarter of 2003 -- (2)
Accretion expense for nine months ended September 30, 2003 116 117
----------------------------------------------------------------------------------------------------
Asset retirement obligation at September 30, 2003 $ 2,479 $ 2,481
====================================================================================================
22
Determination of Asset Retirement Obligation
In accordance with SFAS No. 143, a probability-weighted,
discounted cash flow model with multiple scenarios was used to determine
the "fair value" of the decommissioning obligation. SFAS No. 143 also
stipulates that fair value represents the amount a third party would
receive for assuming an entity's entire obligation.
The present value of future estimated cash flows was calculated
using credit-adjusted, risk-free rates applicable to the various businesses
in order to determine the fair value of the decommissioning obligation at
the time of adoption of SFAS No. 143.
Significant changes in the assumptions underlying the items
discussed above could materially affect the balance sheet amounts and
future costs related to decommissioning recorded in the consolidated
financial statements.
The following tables set forth Exelon's net income and earnings
per common share for the three and nine months ended September 30, 2002
adjusted as if SFAS No. 143 had been applied effective January 1, 2002.
Three Months Ended Nine Months Ended
September 30, 2002 September 30, 2002
-----------------------------------------------------------------------------------------------------------------------
Reported income before cumulative effect
of changes in accounting principles $ 551 $ 1,273
Adjustment as if SFAS No. 143 had been applied
effective January 1, 2002 8 28
-----------------------------------------------------------------------------------------------------------------------
Adjusted income before cumulative effect
of changes in accounting principles $ 559 $ 1,301
=======================================================================================================================
Three Months Ended Nine Months Ended
September 30, 2002 September 30, 2002
-----------------------------------------------------------------------------------------------------------------------
Reported net income $ 551 $ 1,043
Adjustment as if SFAS No. 143 had been applied
effective January 1, 2002:
Adjustment to income before cumulative effect
of changes in accounting principles 8 28
Cumulative effect of changes in accounting principles -- 132
-----------------------------------------------------------------------------------------------------------------------
Adjusted net income $ 559 $ 1,203
=======================================================================================================================
23
Three Months Ended September 30, 2002
-------------------------------------
Basic earnings per common share: Reported Adjustment (1) Adjusted
------------------------------------------------------------------------------------------------------------------
Income before cumulative effect
of changes in accounting principles $ 1.71 $ 0.02 $ 1.73
Net income $ 1.71 $ 0.02 $ 1.73
------------------------------------------------------------------------------------------------------------------
Three Months Ended September 30, 2002
-------------------------------------
Diluted earnings per common share: Reported Adjustment (1) Adjusted
------------------------------------------------------------------------------------------------------------------
Income before cumulative effect
of changes in accounting principles $ 1.70 $ 0.02 $ 1.72
Net income $ 1.70 $ 0.02 $ 1.72
------------------------------------------------------------------------------------------------------------------
(1) The adjustment represents the earnings impact as if SFAS No. 143 had been applied effective January 1, 2002.
Nine Months Ended September 30, 2002
-------------------------------------
Basic earnings per common share: Reported Adjustment (1) Adjusted
------------------------------------------------------------------------------------------------------------------
Income before cumulative effect
of changes in accounting principles $ 3.95 $ 0.09 $ 4.04
Net income $ 3.24 $ 0.50 $ 3.74
------------------------------------------------------------------------------------------------------------------
Nine Months Ended September 30, 2002
-------------------------------------
Diluted earnings per common share: Reported Adjustment (1) Adjusted
------------------------------------------------------------------------------------------------------------------
Income before cumulative effect
of changes in accounting principles $ 3.93 $ 0.09 $ 4.02
Net income $ 3.22 $ 0.49 $ 3.71
------------------------------------------------------------------------------------------------------------------
(1) The adjustment represents the earnings impact as if SFAS No. 143 had been applied effective January 1, 2002.
Effect of adopting SFAS No. 143
Exelon was required to re-measure the decommissioning liabilities
at fair value using the methodology prescribed by SFAS No. 143. The
transition provisions of SFAS No. 143 required Exelon to apply this
re-measurement back to the historical periods in which asset retirement
obligations were incurred, resulting in a re-measurement of these
obligations at the date the related assets were acquired. Since the nuclear
plants previously owned by ComEd were acquired by Exelon on October 20,
2000 (Merger Date) as a result of the merger of Exelon, Unicom Corporation
and PECO (Merger), Exelon's historical accounting for its ARO has been
revised as if SFAS No. 143 had been in effect at the Merger Date.
In the case of the former ComEd plants, the calculation of the
SFAS No. 143 ARO yielded decommissioning obligations lower than the value
of the corresponding trust assets. ComEd has previously collected amounts
from customers (which were subsequently transferred to Generation) in
advance of Generation's recognition of decommissioning expense under SFAS
No. 143. While it is expected that the trust assets will ultimately be used
entirely for the decommissioning of the plants, the current measurement
required by SFAS No. 143 shows an excess of assets over related ARO
liabilities. As such, in accordance with regulatory accounting practices
and a December 2000 Illinois Commerce Commission (ICC) Order, a regulatory
liability of $948 million and a corresponding receivable from Generation
were recorded at ComEd upon the adoption of SFAS No. 143. At September 30,
2003, the regulatory liability and corresponding receivable from Generation
24
totaled $1,144 million. Exelon believes that all of the decommissioning
assets, including up to $73 million of annual collections from ComEd
ratepayers through 2006, will be used to decommission the former ComEd
plants. Accordingly, Exelon expects the regulatory liability and
corresponding receivable from Generation will be reduced to zero at or
before the conclusion of the decommissioning of the former ComEd plants.
In the case of the former PECO plants, the SFAS No. 143 ARO
calculation yielded decommissioning obligations greater than the
corresponding trust assets. As such, a regulatory asset of $20 million and
a corresponding payable to Generation were recorded upon adoption at PECO.
At September 30, 2003, the regulatory asset and corresponding payable to
Generation totaled $7 million. Exelon believes that all of the
decommissioning assets, including $29 million of annual collections from
PECO ratepayers which will increase to approximately $33 million beginning
in 2004, will be used to decommission the former PECO plants. Exelon also
expects the regulatory asset and corresponding payable to Generation will
be reduced to zero at the conclusion of the decommissioning of the former
PECO plants. See Note 5 - Regulatory Issues for more information regarding
the annual collections from PECO.
Prior to the adoption of SFAS No. 143, Generation's accumulated
depreciation included $2,845 million for decommissioning liabilities
related to active nuclear plants. This amount was reclassified to an ARO
upon the adoption of SFAS No. 143. Additionally, Generation adjusted the
total decommissioning liability for the ComEd plants to $1,575 million and
for the PECO plants to $787 million. As described above, Generation
recorded a payable to ComEd of $948 million and a receivable from PECO of
$20 million. Generation also recorded an asset retirement cost asset (ARC)
of $172 million related to the establishment of the ARO related to former
PECO plants in accordance with SFAS No. 143. The ARC is being amortized
over the remaining lives of the plants.
As discussed above, Exelon re-measured its 2001
decommissioning-related balances associated with the Merger purchase price
allocation at ComEd and the January 2001 corporate restructuring as if SFAS
No. 143 had been in effect at the Merger Date. Exelon concluded that had
SFAS No. 143 been in effect, ComEd would not have recorded an impairment of
its regulatory asset for decommissioning of its retired nuclear plants as a
purchase price allocation adjustment in 2001 as a result of the December
2000 ICC order. Increased net assets would have been transferred to
Generation by ComEd in the corporate restructuring. Accordingly, Exelon
recorded a reduction of goodwill of approximately $210 million, with a
corresponding reduction in its overall decommissioning obligation in
connection with the implementation of SFAS No. 143 on January 1, 2003.
Similarly, ComEd recorded a reduction of $210 million of goodwill and of
shareholders' equity, and Generation recorded a $210 million increase in
member's equity and a corresponding reduction of its decommissioning
obligation. In addition, ComEd recorded a cumulative effect of a change in
accounting principle of $5 million to reverse goodwill amortization that
had been recorded in 2001. Exelon and ComEd also reclassified a regulatory
asset related to nuclear decommissioning costs for retired units of $248
million to regulatory liabilities.
In accordance with the provisions of SFAS No. 143 and regulatory
accounting guidance, Exelon recorded a SFAS No. 143 transition adjustment
to accumulated other comprehensive income to reclassify $168 million of
25
accumulated net unrealized losses on the nuclear decommissioning trust
funds to regulatory assets and liabilities.
The following tables set forth ComEd and Generation's net income
and Generation's income before cumulative effect of changes in accounting
principles for the three and nine months ended September 30, 2002 adjusted
as if SFAS No. 143 had been applied effective January 1, 2002. ComEd's
income before cumulative effect of a change in accounting principle was not
affected by the adoption of SFAS No. 143.
Three Months Ended Nine Months Ended
ComEd September 30, 2002 September 30, 2002
------------------------------------------------------------------------------------------------------------------
Reported net income $ 215 $ 576
Adjustment as if SFAS No. 143 had been applied
effective January 1, 2002:
Cumulative effect of changes in accounting principles -- 5
------------------------------------------------------------------------------------------------------------------
Adjusted net income $ 215 $ 581
==================================================================================================================
Three Months Ended Nine Months Ended
Generation September 30, 2002 September 30, 2002
------------------------------------------------------------------------------------------------------------------
Reported income before cumulative effect
of changes in accounting principles $ 163 $ 313
Adjustment as if SFAS No. 143 had been applied
effective January 1, 2002 8 28
------------------------------------------------------------------------------------------------------------------
Adjusted income before cumulative effect
of changes in accounting principles $ 171 $ 341
==================================================================================================================
Three Months Ended Nine Months Ended
Generation September 30, 2002 September 30, 2002
------------------------------------------------------------------------------------------------------------------
Reported net income $ 163 $ 326
Adjustment as if SFAS No. 143 had been applied
effective January 1, 2002:
Adjustment to income before cumulative effect
of changes in accounting principles 8 28
Cumulative effect of changes in accounting principles -- 128
------------------------------------------------------------------------------------------------------------------
Adjusted net income $ 171 $ 482
==================================================================================================================
Accounting methodology under SFAS No. 143
For the former ComEd plants, realized gains and losses on
decommissioning trust funds are reflected in other income and deductions in
Generation's Consolidated Statements of Income and Comprehensive Income,
while the unrealized gains and losses on marketable securities held in the
trust funds adjust the payable Generation currently has to ComEd. The
increases in the ARO are recorded in operating and maintenance expense as
accretion expense, while the funds received from ComEd for decommissioning
are recorded in revenue. Generation's payable to ComEd is adjusted each
reporting period to reflect the difference between the decommissioning
assets and the ARO levels. As such, if the ARO increases at a rate faster
than the increase in the trust fund assets, ComEd's regulatory liability
and receivable from Generation will decrease. If and when the trust assets
are exceeded by the decommissioning liability, Generation is responsible
for any shortfall in funding. The result of the above accounting will have
26
no earnings impact to Generation for as long as the trust assets exceed the
decommissioning liabilities for the former ComEd plants.
The above accounting practices are also applicable for the former
PECO plants owned by Generation. Additionally, depreciation expense will be
recognized on the ARC established upon adoption of SFAS No. 143. However,
as PECO has the expectation of full recovery from ratepayers of
decommissioning costs of its former plants, the result of the above
accounting will ultimately reflect no earnings impact to Generation.
Therefore, to the extent that the net of decommissioning revenues collected
and realized investment income differ from the accretion expense to the
decommissioning liability and the related depreciation of the ARC, an
adjustment to net the amounts to zero would be recorded by Generation for
that period with the offset to PECO's regulatory asset balance.
The ongoing effects to Generation for the accounting for the
decommissioning of the AmerGen Energy Company, LLC (AmerGen) plants are
recorded within Generation's equity in earnings of AmerGen. AmerGen is a
50% owned subsidiary of Generation.
SFAS No. 141 and SFAS No. 142
In 2001, the FASB issued SFAS No. 141, "Business Combinations"
(SFAS No. 141), which requires that all business combinations be accounted
for under the purchase method of accounting and establishes criteria for
the separate recognition of intangible assets acquired in business
combinations. In addition, SFAS No. 141 required that unamortized negative
goodwill related to pre-July 1, 2001 purchases be recognized as a change in
accounting principle concurrent with the adoption of SFAS No. 142,
"Goodwill and Other Intangible Assets" (SFAS No. 142). Upon AmerGen's
adoption of SFAS No. 141 in January 2002, Generation recognized its
proportionate share of income of $22 million ($13 million, net of income
taxes) as a cumulative effect of a change in accounting principle.
Exelon, ComEd, PECO and Generation adopted SFAS No. 142 as of
January 1, 2002. SFAS No. 142 established new accounting and reporting
standards for goodwill and intangible assets. Exelon recorded a charge of
$357 million ($243 million, net of income taxes and minority interest) upon
the adoption of SFAS No. 142 with respect to goodwill recorded in certain
Reporting Units of Exelon Enterprises Company, LLC (Enterprises). This
charge was recorded as a cumulative effect of a change in accounting
principle in the first quarter of 2002.
The components of the net transitional impairment loss recognized
in the first quarter of 2002 as a cumulative effect of a change in
accounting principle were as follows:
---------------------------------------------------------------------------
Enterprises goodwill impairment (net of income taxes of $(103)) $(254)
Minority interest (net of income taxes of $4) 11
Elimination of AmerGen negative goodwill (net of income taxes of $9) 13
---------------------------------------------------------------------------
Total cumulative effect of a change in accounting principle $(230)
===========================================================================
At September 30, 2003, Exelon had goodwill of $4,734 million of
which $4,711 million relates to ComEd and the remaining goodwill relates to
Enterprises' Reporting Units. Consistent with SFAS No. 142, the remaining
27
goodwill is reviewed for impairment on an annual basis, or more frequently
if significant events occur that could indicate an impairment exists. ComEd
and Enterprises perform their annual reviews in the fourth quarter of their
fiscal years. See Note 3 - Acquisitions, Dispositions and Retirements for a
discussion of an impairment of Enterprises' goodwill related to the
InfraSource Reporting Unit recorded in the second quarter of 2003.
Other Accounting Principles and Accounting Changes
SFAS No. 146
In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities" (SFAS No. 146). SFAS No. 146
requires that the liability for costs associated with exit or disposal
activities be recognized when incurred, rather than at the date of a
commitment to an exit or disposal plan. SFAS No. 146 is to be applied
prospectively to exit or disposal activities initiated after December 31,
2002. Exelon, ComEd, PECO and Generation's results of operations were not
affected by the adoption SFAS No. 146.
FIN No. 45
In November 2002, the FASB released FASB Interpretation (FIN) No.
45, "Guarantor's Accounting and Disclosure Requirements for Guarantees,
Including Indirect Guarantees of Indebtedness of Others" (FIN No. 45),
providing for expanded disclosures and recognition of a liability for the
fair value of the obligation undertaken by the guarantor. Under FIN No. 45,
guarantors are required to disclose the nature of the guarantee, the
maximum amount of potential future payments, the carrying amount of the
liability and the nature and amount of recourse provisions or available
collateral that would be recoverable by the guarantor. Exelon, ComEd, PECO
and Generation adopted the disclosure requirements under FIN No. 45, which
were effective for financial statements for periods ended after December
15, 2002. The recognition and measurement provisions of FIN No. 45 were
effective for guarantees issued or modified after December 31, 2002. The
adoption of FIN No. 45 had no material effect on Exelon, ComEd, PECO or
Generation's results of operations. Liabilities associated with guarantees
entered into during the nine months ended September 30, 2003 are reflected
in Note 9 - Commitments and Contingencies.
28
SFAS No. 148
In December 2002, the FASB issued SFAS No. 148, "Accounting for
Stock-Based Compensation - Transition and Disclosure - an amendment of FASB
Statement No. 123" (SFAS No. 148). SFAS No. 148 provides alternative
methods of transition for a voluntary change to the fair value based method
of accounting for stock-based employee compensation and requires
disclosures in both annual and interim financial statements regarding the
method of accounting for stock-based compensation and the effect of the
method on financial results. SFAS No. 148 was effective for financial
statements for fiscal years ended after December 15, 2002. Exelon adopted
the additional disclosure requirements of SFAS No. 148 and continues to
account for its stock-compensation plans under the disclosure only
provision of SFAS No. 123, "Accounting for Stock-Based Compensation" (SFAS
No. 123). The tables below show the effect on net income and earnings per
share for Exelon and the effect on net income for ComEd, PECO and
Generation had Exelon elected to account for stock-based compensation plans
using the fair value method under SFAS No. 123 for the three and nine
months ended September 30, 2003 and 2002:
Exelon
Three Months Ended September 30,
--------------------------------
2003 2002
------------------------------------------------------------------------------------------------------------------
Net income (loss) - as reported $ (102) $ 551
Deduct: Total stock-based compensation expense
determined under fair value based method for all
awards, net of income taxes (5) (8)
------------------------------------------------------------------------------------------------------------------
Pro forma net income (loss) $ (107) $ 543
==================================================================================================================
Earnings (loss) per share:
Basic - as reported $ (0.31) $ 1.71
Basic - pro forma $ (0.33) $ 1.68
Diluted - as reported $ (0.31) $ 1.70
Diluted - pro forma $ (0.33) $ 1.67
------------------------------------------------------------------------------------------------------------------
Nine Months Ended September 30,
-------------------------------
2003 2002
------------------------------------------------------------------------------------------------------------------
Net income - as reported $ 631 $ 1,043
Deduct: Total stock-based compensation expense
determined under fair value based method for all
awards, net of income taxes (16) (25)
------------------------------------------------------------------------------------------------------------------
Pro forma net income $ 615 $ 1,018
==================================================================================================================
Earnings per share:
Basic - as reported $ 1.94 $ 3.24
Basic - pro forma $ 1.89 $ 3.16
Diluted - as reported $ 1.93 $ 3.22
Diluted - pro forma $ 1.88 $ 3.14
------------------------------------------------------------------------------------------------------------------
29
ComEd
Three Months Ended September 30,
--------------------------------
2003 2002
-------------------------------------------------------------------------------------------------------------------
Net income - as reported $ 163 $ 215
Deduct: Total stock-based compensation expense
determined under fair value based method for all
awards, net of income taxes (1) (3)
-------------------------------------------------------------------------------------------------------------------
Pro forma net income $ 162 $ 212
===================================================================================================================
Nine Months Ended September 30,
-------------------------------
2003 2002
-------------------------------------------------------------------------------------------------------------------
Net income - as reported $ 564 $ 576
Deduct: Total stock-based compensation expense
determined under fair value based method for all
awards, net of income taxes (4) (10)
-------------------------------------------------------------------------------------------------------------------
Pro forma net income $ 560 $ 566
===================================================================================================================
PECO
Three Months Ended September 30,
--------------------------------
2003 2002
-------------------------------------------------------------------------------------------------------------------
Net income on common stock- as reported $ 140 $ 155
Deduct: Total stock-based compensation expense
determined under fair value based method for all
awards, net of income taxes (1) (3)
-------------------------------------------------------------------------------------------------------------------
Pro forma net income on common stock $ 139 $ 152
===================================================================================================================
Nine Months Ended September 30,
-------------------------------
2003 2002
-------------------------------------------------------------------------------------------------------------------
Net income on common stock- as reported $ 361 $ 332
Deduct: Total stock-based compensation expense
determined under fair value based method for all
awards, net of income taxes (2) (10)
-------------------------------------------------------------------------------------------------------------------
Pro forma net income on common stock $ 359 $ 322
===================================================================================================================
Generation
Three Months Ended September 30,
--------------------------------
2003 2002
-------------------------------------------------------------------------------------------------------------------
Net income (loss) - as reported $ (428) $ 163
Deduct: Total stock-based compensation expense
determined under fair value based method for all
awards, net of income taxes (3) (4)
-------------------------------------------------------------------------------------------------------------------
Pro forma net income (loss) $ (431) $ 159
===================================================================================================================
Nine Months Ended September 30,
-------------------------------
2003 2002
-------------------------------------------------------------------------------------------------------------------
Net income (loss) - as reported $ (231) $ 326
Deduct: Total stock-based compensation expense
determined under fair value based method for all
awards, net of income taxes (8) (11)
-------------------------------------------------------------------------------------------------------------------
Pro forma net income (loss) $ (239) $ 315
===================================================================================================================
30
FIN No. 46
In January 2003, the FASB issued FIN No. 46, "Consolidation of
Variable Interest Entities" (FIN No. 46), which addresses the requirements
for consolidating certain variable interest entities and applies
immediately to variable interest entities created after January 31, 2003.
FIN No. 46, as amended by FASB Staff Position (FSP) No. FIN 46-6,
"Effective Date of FASB Interpretation No. 46, Consolidation of Variable
Interest Entities," requires Exelon to consolidate variable interest
entities, created prior to February 1, 2003, as of December 31, 2003.
As of July 1, 2003, PECO Trust IV, a wholly owned financing
subsidiary of PECO created in May 2003, was no longer consolidated within
the financial statements of Exelon or PECO pursuant to the provisions of
FIN No. 46. PECO recognized equity in earnings of less than $1 million for
the three and nine months ended September 30, 2003 related to this
unconsolidated subsidiary. Amounts of $103 million owed to PECO Trust IV by
PECO are recorded as long-term debt to affiliate within the Consolidated
Balance Sheets, and interest owed to this entity is recorded as interest
expense to affiliate within the Consolidated Statements of Income and
Comprehensive Income. This change in presentation had no significant impact
on net income or the balance sheet of Exelon or PECO. Prior periods have
not been restated.
Based on management's interpretation of the current provisions of
FIN No. 46, it is reasonably possible that the remaining wholly owned
financing trusts and limited partnerships of ComEd and PECO will be
required to be deconsolidated as of December 31, 2003. This change in
presentation is anticipated to have no significant impact on net income or
the balance sheet of Exelon, ComEd or PECO.
Based on management's interpretation of the current provisions of
FIN No. 46, it is reasonably possible that Generation will consolidate
Sithe Energies, Inc. (Sithe) and AmerGen as of December 31, 2003.
Generation is a 49.9% owner of Sithe and has accounted for this entity as
an unconsolidated equity investment. Sithe owns and operates power
generating facilities. AmerGen is a joint venture between Generation and
British Energy, Inc. (British Energy) and owns and operates three nuclear
units, the Clinton Power Station (Clinton), Three Mile Island Unit 1 (TMI)
and Oyster Creek Generating Station (Oyster Creek). Refer to Note 17 -
Unconsolidated Equity Investments in Generation's Form 10-K for the year
ended December 31, 2002 and Note 4 - Unconsolidated Investments and Note 15
- Subsequent Events in this Form 10-Q for further information related to
Generation's investments in Sithe and AmerGen and Exelon's agreement to
purchase British Energy's interest in AmerGen. Also, see Note 13 - Related
Party Transactions for a description of the activity between Exelon and
Sithe and Exelon and AmerGen.
SFAS No. 149
In April 2003, the FASB issued SFAS No. 149, "Amendment of
Statement 133 on Derivative Instruments and Hedging Activities" (SFAS No.
149). SFAS No. 149 amends and clarifies financial accounting and reporting
for derivative instruments, including certain derivative instruments
embedded in other contacts, and for hedging activities under SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities" (SFAS No.
133). SFAS No. 149 also amends SFAS No. 133 for decisions made (1) as part
31
of the Derivatives Implementation Group process that effectively required
amendments to SFAS No. 133, (2) in connection with other FASB projects
dealing with financial instruments, and (3) in connection with
implementation issues raised in relation to the application of the
definition of a derivative.
SFAS No. 149 was effective for contracts entered into or modified
after June 30, 2003, except as stated below, and for hedging relationships
designated after June 30, 2003. In addition, except as stated below, all
provisions of SFAS No. 149 were to be applied prospectively. The provisions
of SFAS No. 149 that relate to SFAS No. 133 implementation issues that have
been effective for fiscal quarters that began prior to June 15, 2003 should
continue to be applied in accordance with their respective effective dates.
In addition, certain provisions relating to forward purchases or sales of
when-issued securities or other securities that do not yet exist should be
applied to both existing contracts and new contracts entered into after
June 30, 2003.
The adoption of SFAS No. 149 had no impact on the Consolidated
Balance Sheets or Statements of Income and Comprehensive Income of Exelon,
ComEd, PECO and Generation.
SFAS No. 150
In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain
Financial Instruments with Characteristics of both Liabilities and Equity"
(SFAS No. 150). SFAS No. 150 requires that certain instruments that have
characteristics of both liabilities and equity be classified as liabilities
in the statement of financial position. SFAS No. 150 affects the accounting
for three types of freestanding financial instruments: mandatorily
redeemable shares, instruments that do or may require the issuer to buy
back some of its shares in exchange for cash or other assets, and
obligations that can be settled with shares, the monetary value of which is
fixed, tied solely or predominantly to a variable such as a market index,
or varies inversely with the value of the issuer's shares.
Substantially all the guidance in SFAS No. 150 was effective for
financial instruments entered into or modified after May 31, 2003, and
otherwise was effective for Exelon as of July 1, 2003.
As of July 1, 2003, ComEd and PECO reclassified mandatorily
redeemable preferred securities of subsidiaries from equity to liabilities
of $344 million and $78 million, respectively. There was no impact from the
adoption of this standard on the Consolidated Statements of Income and
Comprehensive Income of ComEd and PECO.
During June 2003, PECO issued $103 million of subordinated
debentures to PECO Trust IV in connection with the issuance by PECO Trust
IV of $100 million of preferred securities (see Note 12 - Long-Term Debt
and Preferred Securities). These preferred securities were recorded as
liabilities of PECO as of June 30, 2003 in accordance with SFAS No. 150.
Effective July 1, 2003, PECO Trust IV was deconsolidated from the financial
statements of PECO in conjunction with the adoption of FIN No. 46. The $103
million of subordinated debentures issued by PECO to PECO Trust IV was
recorded as long-term debt to affiliate within the Consolidated Balance
Sheets.
As previously reported in Generation's Capital Commitments
footnotes to the financial statements in the 2002 Form 10-K, Generation has
a 73% interest in the Southeast Chicago Project, LLC (Southeast Chicago),
which owns a peaking facility in Chicago. Southeast Chicago is obligated to
redeem approximately $52 million over the next 19 years to a party, not
affiliated with Generation, that owns the remaining 27% interest. Under SFAS
No. 150, this mandatory redemption requires Generation to classify its
minority interest in Southeast Chicago as a liability at fair value. As
such, at July 1, 2003, Generation reclassified $52 million of minority
interest to other noncurrent liabilities on the Consolidated Balance Sheet.
32
Change in Depreciation Estimate
ComEd
Effective July 1, 2002, ComEd lowered its depreciation rates based
on a depreciation study reflecting its significant construction program in
recent years, changes in and development of new technologies, and changes
in estimated plant service lives since the last depreciation study. The
annualized reduction in depreciation expense, based on December 31, 2001
plant balances, was estimated to be approximately $100 million ($60
million, net of income taxes). As a result of the change, operating income
for the nine months ended September 30, 2003 increased approximately $48
million ($29 million after income taxes) compared to the same period in
2002.
3. ACQUISITIONS, DISPOSITIONS AND RETIREMENTS (Exelon and Generation)
InfraSource Sale
On September 24, 2003, Enterprises sold the electric
construction and services, underground and telecom businesses of
InfraSource, Inc. (InfraSource). Cash proceeds to Enterprises from the sale
were approximately $175 million, net of transaction costs and cash
transferred to the buyer upon sale, plus a $30 million subordinated note
receivable maturing in 2011. At September 30, 2003, the present value of
the note receivable was approximately $12 million. In connection with this
transaction, Enterprises entered into an agreement that may result in
certain payments to InfraSource if the amount of services Exelon purchases
from InfraSource during the period from closing through 2006 is below
specified thresholds. Pursuant to the sales agreement, certain working
capital adjustments to the purchase price may be made in 2004.
In connection with the agreement to sell certain businesses of
InfraSource, Enterprises recorded an impairment charge during the second
quarter of 2003 of approximately $48 million (before income taxes and
minority interest) pursuant to SFAS No. 142 related to the goodwill
recorded within the InfraSource Reporting Unit. Management of Enterprises
primarily considered the negotiated sales price and the estimated book
value of InfraSource at the time of the closing of the sale in determining
the amount of the goodwill impairment charge. In connection with the
closing of the sale in the third quarter of 2003, Enterprises recorded a
gain of $44 million (before income taxes), primarily due to the book value
of InfraSource at the date of closing being lower than estimated in the
second quarter of 2003. The net impact of the goodwill impairment in the
second quarter and the gain recorded in the third quarter was a loss before
income taxes and minority interest of $4 million for the nine months ended
September 30, 2003. The net impact was recorded as an operating and
maintenance expense within the Consolidated Statements of Income and
Comprehensive Income for the nine months ended September 30, 2003.
33
Exelon Thermal Holdings, Inc.
Enterprises classified the assets and liabilities of certain
entities of Exelon Thermal Holdings, Inc. as held for sale within the
Consolidated Balance Sheet pursuant to SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets" (SFAS No. 144) as of September
30, 2003. These businesses are reported under the Enterprises segment
pursuant to SFAS No. 131, "Disclosures about Segments of an Enterprise and
Related Information." The major classes of assets and liabilities
classified as held for sale as of September 30, 2003 consist of the
following (in millions):
-------------------------------------------------------------------------
Cash $ 12
Property, plant and equipment, net 86
Other long-term assets 2
Long-term notes receivable 9
-------------------------------------------------------------------------
Total assets classified as held for sale $ 109
=========================================================================
-------------------------------------------------------------------------
Accounts payable, accrued expenses and other current liabilities $ 11
Debt 39
Asset retirement obligation 2
Other long-term liabilities 5
-------------------------------------------------------------------------
Total liabilities classified as held for sale $ 57
=========================================================================
Sale of Investment in AT&T Wireless
On April 1, 2002, Enterprises sold its 49% interest in AT&T
Wireless PCS of Philadelphia, LLC to a subsidiary of AT&T Wireless Services
for $285 million in cash. Enterprises recorded a gain of $116 million (net
of income taxes) on the $84 million investment as an other income and
deduction in Exelon's Consolidated Statements of Income and Comprehensive
Income.
Generation
Sithe New England Holdings Acquisition
On November 1, 2002, Generation purchased the assets of Sithe New
England Holdings, LLC (now known as Exelon New England), a subsidiary of
Sithe, and related power marketing operations. The purchase price for the
Exelon New England assets consisted of a $536 million note to Sithe, $14
million of direct acquisition costs and a $208 million adjustment to
Generation's previously existing investment in Sithe related to Exelon New
England.
34
The allocation of the purchase price to the fair value of assets
acquired and liabilities assumed in the acquisition was as follows:
-------------------------------------------------------------------------
Current assets (including $12 million of cash acquired) $ 85
Property, plant and equipment 1,949
Deferred debits and other assets 63
Current liabilities (154)
Deferred credits and other liabilities (149)
Long-term debt (1,036)
-------------------------------------------------------------------------
Total purchase price $ 758
=========================================================================
In connection with the acquisition, Generation assumed certain
Sithe guarantees, including a guarantee of an equity contribution to be
made to Sithe Boston Generating, LLC (currently known as Exelon Boston
Generating, LLC (EBG)), a project subsidiary of Exelon New England.
Pursuant to Generation's assumed equity guarantee, upon the occurrence of
certain events, Generation would be obligated to (1) contribute up to $38
million of equity for the purpose of completing the construction of two
generating facilities and/or to fund certain reserve funds and (2) pay
certain taxes.
EBG has a $1.25 billion credit facility (EBG Facility), which was
entered into primarily to finance the construction of Mystic 8 and 9 and
Fore River. The approximately $1.1 billion of debt outstanding under the
credit facility at September 30, 2003 is reflected in Generation's
Consolidated Balance Sheets as a current liability due to certain events of
default described below. The EBG Facility is non-recourse to Generation and
an event of default under the EBG Facility does not constitute an event of
default under any other debt instruments of Exelon or its subsidiaries.
The EBG Facility required that all of the projects achieve
"Project Completion," as defined in the EBG Facility (Project Completion),
by June 12, 2003. On June 11, 2003, EBG negotiated an extension of the
Project Completion date to July 11, 2003. Project Completion was not
achieved by July 12, 2003, resulting in an event of default under the EBG
Facility. On July 3, 2003, the lenders under the EBG Facility and EBG
executed a letter agreement as a result of which the lenders were precluded
during the period July 11, 2003 through August 29, 2003 from exercising any
remedies resulting from the failure of all of the projects to achieve
Project Completion. At that time, EBG stated that it would continue to
monitor the projects, assess all of its options relating to the projects,
and continue discussions with the lenders. Mystic 8 and 9 and Fore River
have all begun commercial operation, although they have not yet achieved
Project Completion.
As a result of Generation's continuing evaluation of the projects
and discussions with the lenders, Generation has commenced the process of
an orderly transition out of the ownership of EBG and the projects. The
transition will take place in a manner that complies with applicable
regulatory requirements. For a period of time, Generation expects to
continue to provide administrative and operational services to EBG in its
operation of the projects. Generation informed the lenders of its decision
to exit and that it will not provide additional funding to the projects
35
beyond its existing contractual obligations. Generation cannot predict the
timing of the transition.
In connection with the decision in late July 2003 to transition
out of the ownership of EBG and the projects, Generation recorded an
impairment charge of its long-lived assets pursuant to SFAS No. 144 of $945
million ($573 million net of income taxes) in operating expenses within the
Consolidated Statements of Income and Comprehensive Income during the third
quarter of 2003. In determining the amount of the impairment charge,
management compared the carrying value of EBG's long-lived assets to the
fair value of those assets. The fair value of EBG's long-lived assets was
determined using the estimated future discounted cash flows from those
assets. Generation used a probability-weighted approach for developing
estimates of future cash flows with the most likely scenarios weighted
higher. Forecasted cash flows incorporated assumptions relative to the
period of time that Generation will continue to own and operate EBG. The
time required to fully transition out of ownership of EBG is uncertain and
subject to change. Through the extinguishment of the outstanding debt and
upon the finalization of Generation's transition out of ownership of EBG
and the projects, Generation's net charge (including the $573 million
charge discussed above) is estimated to be $550 million after income taxes.
4. UNCONSOLIDATED INVESTMENTS (Exelon, PECO and Generation)
Sithe
Generation is a 49.9% owner of Sithe and has accounted for the
investment as an unconsolidated equity investment through September 30,
2003. In the first quarter of 2003, Generation recorded an impairment
charge of $200 million (before income taxes) in other income and deductions
within the Consolidated Statements of Income and Comprehensive Income
associated with a decline in the fair value of the Sithe investment, which
was considered to be other-than-temporary. Generation's management
considered various factors in the decision to impair this investment,
including management's negotiations to sell its interest in Sithe. The
discussions surrounding the sale indicated that the fair value of the Sithe
investment was below its book value, and as such, an impairment was
required. In the third quarter of 2003, Generation recorded an additional
impairment charge of $55 million (before income taxes) in other income and
deductions within the Consolidated Statements of Income and Comprehensive
Income to reflect an additional decline in the fair value of its investment
in Sithe. This additional decline in fair value was primarily attributable
to the changes in terms with a new acquirer, which occurred in the third
quarter of 2003, as described below.
At December 31, 2002, Sithe had total assets of $2.6 billion
(including the $534 million note from Generation which has subsequently
been reduced to $326 million) and total liabilities of $1.8 billion. Of the
total liabilities, Sithe had $1.3 billion of debt which included $624
million of subsidiary debt incurred primarily to finance the construction
of six new generating facilities, $461 million of subordinated debt, $103
million of line of credit borrowings, $43 million of current portion of
long-term debt and capital leases, $30 million of capital leases, and
excludes $453 million of non-recourse debt associated with Sithe's equity
investments. For the year ended December 31, 2002, Sithe had revenues of
$1.0 billion and incurred a net loss of approximately $348 million. Exelon
36
contractually does not own any interest in Sithe International, a
subsidiary of Sithe. As such, a portion of Sithe's net assets and results
of operations would be eliminated from Generation's balance sheet and
results of operations through a minority interest.
The book value of Generation's investment in Sithe was $163
million at September 30, 2003. For the nine months ended September 30,
2003, Sithe had revenues of $562 million. Generation recorded $6 million of
equity method income for Sithe for the nine months ended September 30,
2003. See Note 2 - New Accounting Principles and Accounting Changes for a
discussion of Sithe in relation to FIN No. 46.
On May 29, 2003, Exelon Fossil Holdings, Inc., a wholly owned
subsidiary of Generation, issued an irrevocable call notice for the
purchase of the 35.2% interest in Sithe owned by Apollo Energy, LLC and the
14.9% interest owned by subsidiaries of Marubeni Corporation. The total
purchase price under the call is based on the terms of the existing Put and
Call Agreement (PCA) among the parties and is $621 million. The transfer of
ownership requires various regulatory approvals, including the Federal
Energy Regulatory Commission (FERC), the state environmental agency in New
Jersey, and expiration of the Hart Scott Rodino waiting period. Early
termination of the Hart Scott Rodino waiting period was granted effective
August 22, 2003.
Under the terms of the PCA, the purchase price must be funded
within six months of the call notice being issued. Additionally, because
the Federal Power Act restricts Generation's ownership of more than 50% of
a qualifying facility, the qualifying facilities owned by Sithe must be
sold or restructured before closing to preserve their status as qualifying
facilities. See below for information regarding a separate agreement
reached by Sithe to sell six U.S. generating facilities, each a qualifying
facility, and an entity holding Sithe's Canadian assets. At the closing,
Sithe is expected to distribute in excess of $600 million of available cash
to Generation.
On August 13, 2003, Generation announced an agreement with
entities controlled by Reservoir Capital Group (Reservoir), a private
investment firm, to sell a 50% interest in Sithe in exchange for $75.8
million in cash. The sale will occur after Generation's purchase of the
remaining 50.1% interest in Sithe. The sale requires approval by the FERC,
a Hart Scott Rodino filing and a filing with the state regulatory
commission in New York. Both of these filings have been made. Early
termination of the Hart Scott Rodino waiting period was granted September
30, 2003. The sale is expected to close in the fourth quarter of 2003.
Both Generation and Reservoir's 50% interests in Sithe will be
subject to put and call options that could result in either party owning
100% of Sithe. While Generation's intent is to fully divest Sithe by the
end of 2004, the timing of the put and call options vary by acquirer and
can extend through March 2006. The pricing of the put and call options is
dependent on numerous factors such as the acquirer, date of acquisition and
assets owned by Sithe at the time of exercise.
37
In a separate transaction, Sithe has entered into an agreement
with Reservoir to sell entities holding six U.S. generating facilities,
each a qualifying facility under the Public Utility Regulatory Policies
Act, and an entity holding Sithe's Canadian assets in exchange for $46.2
million ($26.2 million in cash and a $20 million two-year note). The sale
requires approvals from Sithe's board of directors and shareholders and
regulatory filings in New Jersey and Canada. Both of these filings have
been made. The sale is also expected to close in the fourth quarter of
2003. This sale is not contingent on the sale of Generation's 50% interest
in Sithe to Reservoir.
AmerGen
Generation is a 50% owner of AmerGen and has accounted for the
investment as an unconsolidated equity investment through September 30,
2003. In addition to Generation's 50% ownership of AmerGen, Generation also
has significant purchased power agreements (PPAs) with AmerGen. See Note 9
- Commitments and Contingencies for further discussion of Generation's PPAs
with AmerGen. The book value of Generation's investment in AmerGen was $306
million at September 30, 2003. For the nine months ended September 30,
2003, AmerGen had revenues of $529 million. Generation recorded $84 million
of equity method earnings for AmerGen for the nine months ended September
30, 2003. See Note 15 - Subsequent Events for information regarding
Generation's agreement to purchase British Energy's 50% interest in
AmerGen. See Note 2 - New Accounting Principles and Accounting Changes for
discussion of AmerGen concerning FIN No. 46.
At December 31, 2002, AmerGen had total assets of $1.6 billion and
total liabilities of $1.3 billion. Of the total liabilities, AmerGen had
$60 million of long-term debt, $35 million of notes payable to Generation,
which were subsequently repaid in 2003, and $26 million of current portion
of long-term debt. For the year ended December 31, 2002, AmerGen had
revenues and net income of $644 million and $161 million, respectively.
Other
Pursuant to FIN No. 46, PECO deconsolidated PECO Trust IV during
the third quarter of 2003. See Note 2 - New Accounting Principles and
Accounting Changes.
5. REGULATORY ISSUES (Exelon, ComEd and PECO)
ComEd
On March 3, 2003, ComEd entered into an agreement with various
Illinois electric retail market suppliers, key customer groups and
governmental parties regarding several matters affecting ComEd's rates for
electric service (Agreement). The Agreement addressed, among other things,
issues related to ComEd's delivery services rate proceeding, market value
index proceeding, the process for competitive service declarations for
large-load customers and an amendment and extension of the PPA with
Generation. During the second quarter of 2003, the ICC issued orders
consistent with the Agreement which is now effective.
During the first quarter of 2003, ComEd recorded a charge to
earnings, associated with the funding of specified programs and initiatives
associated with the Agreement, of $51 million (before income taxes) on a
38
present value basis. This amount was partially offset by the reversal of a
$12 million (before income taxes) reserve established in the third quarter
of 2002 for a potential capital disallowance in ComEd's delivery services
rate proceeding and a credit of $10 million (before income taxes) related
to the capitalization of employee incentive payments provided for in the
delivery services order. The charge of $51 million and the credit of $10
million were recorded in operating and maintenance expense and the reversal
of the $12 million reserve was recorded in other, net within ComEd's
Consolidated Statements of Income and Comprehensive Income. The net
one-time charge for these items was $29 million (before income taxes). In
accordance with the Agreement, ComEd made payments of $17 million during
the nine months ended September 30, 2003.
ComEd filed a request on September 12, 2003 with the FERC seeking
an adjustment in transmission rates to reflect nearly $500 million of
infrastructure investments made during the last five years to accommodate
sizeable regional growth in electricity demand.
ComEd's proposed increase would adjust rates from 95 cents per
kilowatt-month to $1.18 per kilowatt-month, effective November 1, 2003.
Transmission rates were last set in 1999, based on 1998 costs. Because of
the rate freeze and the method for calculating competitive transition
charges (CTCs) in Illinois, ComEd expects that the requested rate
adjustment will not significantly increase overall revenue. Several parties
have intervened in this rate proceeding. The ultimate outcome of the
proceeding is unknown.
PECO
As previously reported in the 2002 Form 10-K, the Pennsylvania
Utility Commission's (PUC) Final Electric Restructuring Order established
market share thresholds (MST) to promote competition. On May 1, 2003, the
PUC approved the residential customer plan filed by PECO in February 2003.
Under the plan and subsequent auction in September 2003, an aggregate of
267,000 residential customers will be transferred to alternative electric
generation suppliers during December 2003. Customers transferred have the
right to return to PECO at any time. PECO does not expect the transfer of
customers pursuant to the MST plan to have a material impact on its results
of operations, financial position or cash flows.
On July 25, 2003, the PUC approved an adjustment to the Nuclear
Decommissioning Cost Adjustment clause. Effective January 1, 2004, PECO
will be permitted to recover an additional $3.6 million annually, or $33
million compared to $29 million previously.
39
6. EARNINGS PER SHARE (Exelon)
Diluted earnings per share are calculated by dividing net income
by the weighted average number of 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):
Three Months Ended September 30, Nine Months Ended September 30,
-------------------------------- -------------------------------
2003 2002 2003 2002
-------------------------------------------------------------------------------------------------------------------
Average Common Shares Outstanding 326 323 325 322
Assumed Exercise of Stock Options -- 1 3 2
-------------------------------------------------------------------------------------------------------------------
Average Dilutive Common Shares Outstanding 326 324 328 324
===================================================================================================================
The number of stock options not included in the calculation of
diluted common shares outstanding due to their antidilutive effect was 15
million and 5 million for the three and nine months ended September 30,
2003, respectively, and 5 million for the three and nine months ended
September 30, 2002.
40
7. SEGMENT INFORMATION (Exelon, ComEd, PECO and Generation)
Exelon operates in three business segments: Energy Delivery (ComEd
and PECO), Generation and Enterprises. Exelon evaluates the performance of
its business segments on the basis of net income.
ComEd, PECO and Generation each operate in a single business
segment; as such, no separate segment information is provided for these
registrants.
Exelon's segment information for the three and nine months ended
September 30, 2003 and 2002 and at September 30, 2003 and December 31, 2002
is as follows:
Three Months Ended September 30, 2003 and 2002
Corporate and
Energy Intersegment
Delivery Generation Enterprises Eliminations Consolidated
-------------------------------------------------------------------------------------------------------------------
Total Revenues (1):
2003 $ 2,886 $ 2,537 $ 437 $ (1,419) $ 4,441
2002 3,162 2,213 509 (1,514) 4,370
Intersegment Revenues:
2003 $ 23 $ 1,357 $ 38 $ (1,418) $ --
2002 29 1,463 22 (1,514) --
Income (Loss) Before Income Taxes:
2003 $ 479 $ (708) $ 26 $ (11) $ (214)
2002 591 265 20 (28) 848
Income Taxes:
2003 $ 176 $ (280) $ 10 $ (18) $ (112)
2002 221 102 5 (31) 297
Net Income (Loss):
2003 $ 303 $ (428) $ 16 $ 7 $ (102)
2002 370 163 15 3 551
-------------------------------------------------------------------------------------------------------------------
(1) $65 million and $67 million in utility taxes are included in the
revenues and expenses for the three months ended September 30, 2003
and 2002, respectively, for ComEd. $61 million and $64 million in
utility taxes are included in the revenues and expenses for the three
months ended September 30, 2003 and 2002, respectively, for PECO.
41
Nine Months Ended September 30, 2003 and 2002, September 30, 2003, and
December 31, 2002
Corporate and
Energy Intersegment
Delivery Generation Enterprises Eliminations Consolidated
-------------------------------------------------------------------------------------------------------------------
Total Revenues (1):
2003 $ 7,850 $ 6,301 $ 1,459 $ (3,374) $ 12,236
2002 7,973 5,233 1,475 (3,436) 11,245
Intersegment Revenues:
2003 $ 58 $ 3,246 $ 74 $ (3,378) $ --
2002 59 3,309 72 (3,440) --
Income (Loss) Before Income Taxes and the Cumulative Effect of Changes in Accounting
Principles:
2003 $ 1,478 $ (548) $ (99) $ (54) $ 777
2002 1,455 511 115 (84) 1,997
Income Taxes:
2003 $ 558 $ (209) $ (37) $ (54) $ 258
2002 547 198 46 (67) 724
Cumulative Effect of Changes in Accounting Principles:
2003 $ 5 $ 108 $ (1) $ -- $ 112
2002 -- 13 (243) -- (230)
Net Income (Loss):
2003 $ 925 $ (231) $ (63) $ -- $ 631
2002 908 326 (174) (17) 1,043
Total Assets:
September 30, 2003 $ 27,309 $ 13,240 $ 877 $ (2,282) $ 39,144
December 31, 2002 26,550 11,007 1,297 (1,369) 37,485
-------------------------------------------------------------------------------------------------------------------
(1) $178 million and $181 million in utility taxes are included in the
revenues and expenses for the nine months ended September 30, 2003 and
2002, respectively, for ComEd. $159 million and $157 million in
utility taxes are included in the revenues and expenses for the nine
months ended September 30, 2003 and 2002, respectively, for PECO.
8. FAIR VALUE OF FINANCIAL ASSETS AND LIABILITIES (Exelon, ComEd, PECO and
Generation)
During the three and nine months ended September 30, 2003 and
2002, Exelon recorded pre-tax gains (losses) in other comprehensive income
relating to mark-to-market (MTM) adjustments of contracts designated as
cash flow hedges as follows:
ComEd PECO Generation Enterprises Exelon
-------------------------------------------------------------------------------------------------------------------
Three months ended September 30, 2003 $ 12 $ 6 $ 241 $ (12) $ 247
Three months ended September 30, 2002 (36) -- (24) 4 (56)
Nine months ended September 30, 2003 7 11 50 (10) 58
Nine months ended September 30, 2002 (52) (1) (130) 19 (164)
-------------------------------------------------------------------------------------------------------------------
42
During the three and nine months ended September 30, 2003 and
2002, Generation recognized net MTM gains (losses) in purchased power on
outstanding non-trading energy derivative contracts not designated as cash
flow hedges included in the Consolidated Balance Sheets at September 30,
2003 and 2002 as follows:
2003 2002
-------------------------------------------------------------------------------------------------------------------
Three months ended September 30, $ (18) $ 1
Nine months ended September 30, (17) 11
-------------------------------------------------------------------------------------------------------------------
During the three and nine months ended September 30, 2003 and
2002, Generation recognized net MTM losses in operating revenues on
outstanding proprietary trading contracts included in the consolidated
balance sheets at September 30, 2003 and 2002 as follows:
2003 2002
-------------------------------------------------------------------------------------------------------------------
Three months ended September 30, $ -- $ --
Nine months ended September 30, (4) (13)
-------------------------------------------------------------------------------------------------------------------
Amounts in accumulated other comprehensive income related to
interest rate cash flow hedges are reclassified into earnings when the
forecasted interest payment occurs. Amounts in accumulated other
comprehensive income related to energy commodity cash flows are
reclassified into earnings when the forecasted purchase or sale of the
energy commodity occurs. As of September 30, 2003, deferred net gains
(losses) on derivative instruments accumulated in other comprehensive
income that are expected to be reclassified to earnings during the next
twelve months are as follows:
ComEd PECO Generation Enterprises Exelon
-------------------------------------------------------------------------------------------------------------------
Net gains (losses) expected to be reclassified $ -- $ 11 $ (103) $ 12 $ (80)
-------------------------------------------------------------------------------------------------------------------
As of September 30, 2003, ComEd expects to amortize during the
next twelve months $6 million of regulatory assets for settled cash flow
swaps. During the three and nine months ended September 30, 2003 and 2002,
ComEd reclassified amounts between other comprehensive income and
regulatory assets for cash flow swaps settled as follows:
2003 2002
-------------------------------------------------------------------------------------------------------------------
Three months ended September 30, (net of tax of $2 and $0, respectively) $ (4) $ --
Nine months ended September 30, (net of tax of ($19) and ($4), respectively) 26 6
-------------------------------------------------------------------------------------------------------------------
In 2003, ComEd entered into forward-starting interest rate swaps
with an aggregate notional amount of $440 million to manage interest rate
exposure associated with an anticipated debt issuance. In connection with
the 2003 issuances of First Mortgage Bonds, forward-starting interest rate
swaps with an aggregate notional amount of $1,070 million were settled with
net proceeds to counterparties of $45 million ($19 million, net of income
taxes) that has been deferred in regulatory assets and is being amortized
over the life of the First Mortgage Bonds as a net increase to interest
expense. See Note 12 - Long-Term Debt and Preferred Securities for
additional information regarding the issuance of the First Mortgage Bonds.
At September 30, 2003, ComEd had settled all of its forward-starting swaps.
43
ComEd has entered into interest rate swaps to effectively convert
$485 million in fixed-rate debt to floating rate debt. These swaps have
been designated as fair-value hedges as defined in SFAS No. 133, and as
such, changes in the fair value of the swaps are recorded in earnings.
However, as long as the hedge remains effective, changes in the fair value
of the swaps are offset by changes in the fair value of the hedged
liabilities. Any change in the fair value of the hedge as a result of
ineffectiveness would be recorded immediately in earnings. As of September
30, 2003, these swaps had an aggregate fair market value of $39 million,
which was classified as other deferred debits and other assets within the
Consolidated Balance Sheets.
PECO 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. These interest rate
swaps were designated as cash flow hedges as defined by SFAS No. 133, and
as such, changes in fair value of the swaps will be recorded in other
comprehensive income. At September 30, 2003, these interest rate swaps had
an aggregate fair market value exposure of $11 million based on the present
value difference between the contract and market rates at September 30,
2003.
In 2003, PECO entered into forward-starting interest rate swaps
with an aggregate notional amount of $360 million to manage interest rate
exposure associated with an anticipated debt issuance. In connection with
the April 28, 2003 issuance of $450 million of First and Refunding Mortgage
Bonds, PECO settled the swaps for net proceeds of $1 million (before income
taxes), which was recorded in other comprehensive income and is being
amortized over the life of the debt issuance. See Note 12 - Long-Term Debt
and Preferred Securities for additional information regarding the issuance
of the First and Refunding Mortgage Bonds.
Under the terms of the EBG Facility, EBG is required to
effectively fix the interest rate on 50% of borrowings under the facility
through its maturity in 2007. As of September 30, 2003, EBG has entered
into interest rate swap agreements, which have effectively fixed the
interest rate on $861 million of notional principal, or approximately 80%
of borrowings outstanding under the EBG Facility. The fair market value
exposure of these swaps, designated as cash flow hedges, is $91 million.
Generation has entered into interest rate swaps with an aggregate
notional amount of $400 million to manage interest rate exposures
associated with an anticipated debt issuance. As of September 30, 2003,
these swaps had an aggregate fair market value exposure of less than $1
million based on the present value difference between the contract and
market rates at September 30, 2003.
44
Generation classifies investments in the trust accounts for
decommissioning nuclear plants as available-for-sale. The following tables
show the fair values, gross unrealized gains and losses and amortized cost
for the securities held in these trust accounts.
September 30, 2003
---------------------------------------------------------------
Gross Gross
Amortized Unrealized Unrealized Estimated
Cost Gains Losses Fair Value
-------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents $ 85 $ -- $ -- $ 85
Equity securities 1,918 161 (369) 1,710
Debt securities
Government obligations 1,018 51 (4) 1,065
Other debt securities 538 30 (24) 544
-------------------------------------------------------------------------------------------------------------------
Total debt securities 1,556 81 (28) 1,609
-------------------------------------------------------------------------------------------------------------------
Total available-for-sale securities $ 3,559 $ 242 $ (397) $ 3,404
===================================================================================================================
Net unrealized losses of $155 million were recognized in
regulatory assets, regulatory liabilities or accumulated other
comprehensive income in Exelon's Consolidated Balance Sheet at September
30, 2003. Net unrealized losses of $155 million were recognized in
noncurrent affiliate payables, noncurrent affiliate receivables or
accumulated other comprehensive income in Generation's Consolidated Balance
Sheet as of September 30, 2003. Net unrealized losses of $346 million were
recognized in accumulated depreciation and accumulated other comprehensive
income in the Consolidated Balance Sheets of Generation at December 31,
2002.
During the three and nine months ended September 30, 2003 and
2002, proceeds from the sale of decommissioning trust investments and gross
realized gains and losses on those sales were as follows:
Three Months Ended September 30, Nine Months Ended September 30,
-------------------------------- -------------------------------
2003 2002 2003 2002
- ---------------------------------------------------------------------------------------------------------
Proceeds from sales $ 618 $ 295 $ 1,880 $ 1,184
Gross realized gains 138 12 203 43
Gross realized losses (141) (21) (194) (77)
- ---------------------------------------------------------------------------------------------------------
Net realized losses of $3 million and $11 million for the three
months ended September 30, 2003 and 2002, respectively, were recorded in
other income and deductions. Net realized gains of $9 million and net
realized losses of $32 million for the nine months ended September 30, 2003
and 2002, respectively, were recorded in other income and deductions. Net
realized losses of $2 million were recognized in accumulated depreciation
at September 30, 2002. The available-for-sale securities held at September
30, 2003 have an average maturity of six to ten years. The cost of these
securities was determined on the basis of specific identification.
45
9. COMMITMENTS AND CONTINGENCIES (Exelon, ComEd, PECO and Generation)
For information regarding capital commitments, nuclear
decommissioning and spent fuel storage, see the Commitments and
Contingencies and Nuclear Decommissioning and Spent Fuel Storage Notes in
the Notes to Consolidated Financial Statements of Exelon, ComEd, PECO and
Generation in the 2002 Form 10-K. See Note 2 - New Accounting Principles
and Accounting Changes of this Form 10-Q for further discussion of nuclear
decommissioning commitments and contingencies.
Environmental Liabilities
As of September 30, 2003, Exelon had accrued $117 million for
environmental investigation and remediation costs that currently can be
reasonably estimated, including $93 million for manufactured gas plant
(MGP) investigation and remediation. Exelon has identified 70 sites where
former MGP activities have or may have resulted in actual site
contamination.
As of September 30, 2003, ComEd had accrued $74 million for
environmental investigation and remediation costs that currently can be
reasonably estimated. This reserve included $69 million (discounted) for
MGP investigation and remediation.
As of September 30, 2003, PECO had accrued $33 million
(undiscounted) for environmental investigation and remediation costs that
currently can be reasonably estimated, including $24 million for MGP
investigation and remediation. Pursuant to a PUC order, PECO is currently
recovering a provision for environmental costs annually for the remediation
of sites of former MGP facilities, for which PECO has recorded a regulatory
asset (see Note 14 - Supplemental Financial Information).
As of September 30, 2003, Generation had accrued $10 million
(undiscounted) for environmental investigation and remediation cost, none
of which relates to MGP investigation and remediation.
Exelon, ComEd, PECO and Generation cannot predict the extent to
which they will incur other significant liabilities for additional
investigation and remediation costs at these or additional sites identified
by environmental agencies or others, or whether such costs may be
recoverable from third parties.
46
Energy Commitments
Generation had long-term commitments as of September 30, 2003
relating to the net purchase and sale of energy, capacity and transmission
rights from unaffiliated utilities, including Midwest Generation, LLC
(Midwest Generation), AmerGen and others, as expressed in the following
table:
Power Only Purchases from
Net Capacity Power Only --------------------------- Transmission Rights
Purchases(1) Non-Affiliate Sales AmerGen(2) Non-Affiliates Purchases(3)
------------------------------------------------------------------------------------------------------------------------
2003 $ 129 $ 939 $ 98 $ 537 $ 19
2004 753 2,064 515 1,324 110
2005 415 867 410 378 86
2006 405 236 423 251 3
2007 488 81 431 237 --
Thereafter 4,113 1 1,863 878 --
------------------------------------------------------------------------------------------------------------------------
Total $ 6,303 $ 4,188 $ 3,740 $ 3,605 $ 218
========================================================================================================================
(1) Net Capacity Purchases includes Midwest Generation commitments as of
September 30, 2003. In 2003, Generation will take 1,778 MWs of option
capacity under the Collins and Peaking Unit Agreements as well as
1,265 MWs of optional capacity under the Coal Generation PPA. On June
25, 2003, Generation notified Midwest Generation of its exercise of
its call option under the Coal Generation PPA for 2004. Generation
exercised its call option on 687 MWs of capacity for 2004 generated by
Waukegan Unit 8 and Fisk Unit 19 and did not exercise its option on
578 MWs of capacity at Waukegan Unit 6, Crawford Unit 7, and Will
County Unit 3. See Note 15 - Subsequent Events for additional
information regarding the PPAs with Midwest Generation, including the
MWs contracted for in 2004. Net Capacity Purchases also include
capacity sales to TXU Corp. (TXU) under the PPA entered into in
connection with the purchase of two generating plants in April 2002,
which states that TXU will purchase the plant output from May through
September from 2002 through 2006. The combined capacity of the two
plants is 2,334 MWs.
(2) Generation has entered into PPAs dated June 26, 2003, December 18,
2001, and November 22, 1999 with AmerGen. Generation has agreed to
purchase 100% of the energy generated by Oyster Creek through April 9,
2009. Generation has agreed to purchase all the energy from TMI from
January 1, 2002 through December 31, 2014. Generation has agreed to
purchase all of the residual energy from Clinton not sold to Illinois
Power through December 31, 2004. Currently, the residual output is
approximately 31% of the total output of Clinton, but will increase to
100% and the obligation will continue until Clinton's license issued
by the U.S. Nuclear Regulatory Commission (NRC) expires in 2026. See
Note 15 - Subsequent Events regarding Generation's agreement to
purchase British Energy's interest in AmerGen.
(3) Transmission Rights Purchases include estimated commitments in 2004
and 2005 for additional transmission rights that will be required to
fulfill firm sales contracts.
Additionally, Generation has the following energy commitments:
In connection with the 2001 corporate restructuring, Generation
entered into a PPA with ComEd under which Generation has agreed to supply
all of ComEd's load requirements through 2004. Under the ComEd PPA, prices
for energy vary depending upon the time of day and month of delivery.
During 2005 and 2006, ComEd's PPA is a partial requirements agreement under
which ComEd will purchase all of its required energy and capacity from
Generation, up to the available capacity of the nuclear generating plants
formerly owned by ComEd and transferred to Generation. Under the terms of
the PPA, Generation is responsible for obtaining any required transmission
service, subject to ComEd's obligation to obtain network service over the
ComEd system. The PPA also specifies that prior to 2005, ComEd and
Generation will jointly determine and agree on a market-based price for
energy delivered under the PPA for 2005 and 2006, which is expected to
exceed current pricing. In the event that the parties cannot agree to
market-based prices for 2005 and 2006 prior to July 1, 2004, ComEd has the
option of terminating the PPA effective December 31, 2004. ComEd will
obtain any additional supply required from market sources in 2005 and 2006,
and subsequent to 2006, will obtain all of its supply from market sources,
47
which could include Generation. The ComEd PPA for 2005 and 2006 may be
extended to a full requirements contract as a result of the Agreement (see
Note 5 - Regulatory Issues). Under the Agreement, various interested
parties have agreed to not oppose such an extension.
In connection with the 2001 corporate restructuring, Generation
entered into a PPA with PECO under which Generation has agreed to supply
PECO with substantially all of PECO's electric supply needs through 2010.
Also, under the restructuring, PECO assigned its rights and obligations
under various PPAs and fuel supply agreements to Generation. Generation
supplies power to PECO from the transferred generation assets, assigned
PPAs and other market sources.
Under terms of the 2001 corporate restructuring, ComEd remits to
Generation any amounts collected from customers for nuclear
decommissioning, currently totaling $73 million per year. Under an
agreement effective September 2001, PECO remits to Generation any amounts
collected from customers for nuclear decommissioning, currently totaling
$29 million per year. This amount will increase to $33 million effective
January 1, 2004 as a result of a July 2003 PUC order. See Note 5 -
Regulatory Issues. See Note 2 - New Accounting Principles and Accounting
Changes for further discussion of the impact of the adoption of SFAS No.
143 on these collections.
Litigation
Exelon
Securities Litigation. Between May 8 and June 14, 2002, several
class action lawsuits were filed in the Federal District Court in Chicago
asserting nearly identical securities law claims on behalf of purchasers of
Exelon securities between April 24, 2001 and September 27, 2001. See Note
19 - Commitments and Contingencies in Exelon's 2002 Form 10-K for
additional information regarding this litigation. On June 13, 2003, the
court dismissed the amended complaint with prejudice. The plaintiffs have
not appealed the court's order of dismissal, thereby terminating the case.
ComEd
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 its rates, as provided for
under the terms of the electric service contracts with the municipal
customers and to track certain refunds made to ComEd's retail customers in
the years 1992 through 1994. In July 2003, ComEd and the municipal
customers executed a settlement agreement ending the litigation. Under the
settlement, ComEd paid a total of approximately $3 million to the three
municipalities during the third quarter of 2003.
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. The
developers also filed suit against ComEd for a declaratory judgment that
their rights under their contracts with ComEd were not affected by the
amendment and for breach of contract. On November 25, 2002, the court
48
granted the developers' motions for summary judgment. The judge also
entered a permanent injunction enjoining ComEd from refusing to pay the
retail rate on the grounds of the amendment, and Illinois from denying
ComEd a tax credit on account of such purchases. ComEd and Illinois have
each appealed the ruling. ComEd believes that it did not breach the
contracts in question and that the damages claimed far exceed any loss that
any project incurred by reason of its ineligibility for the subsidized
rate. ComEd intends to prosecute its appeal and defend each case
vigorously. While ComEd cannot currently predict the outcome of this
action, ComEd does not believe that it will have a material adverse impact
on ComEd's results of operations.
Service Interruptions. In August 1999, three class action lawsuits
were filed against ComEd, and subsequently consolidated, in the Circuit
Court of Cook County, Illinois seeking damages for personal injuries,
property damage and economic losses related to a series of service
interruptions that occurred in the summer of 1999. The combined effect of
these interruptions resulted in over 168,000 customers losing service for
more than four hours. The court approved conditional class certification
for the sole purpose of exploring settlement. ComEd filed a motion to
dismiss the complaints. On April 24, 2001, the court dismissed four of the
five counts of the consolidated complaint without prejudice and the sole
remaining count was dismissed in part. On June 1, 2001, the plaintiffs
filed a second amended consolidated complaint and ComEd has filed an
answer. On December 5, 2002, a settlement was reached, whereby ComEd will
pay up to $8 million, which includes $4 million paid to date. In an order
dated October 3, 2003, the court approved the settlement. A portion of the
settlement may be covered by insurance. ComEd has remaining reserves of
approximately $3 million related to unpaid claims and costs.
PECO and Generation
Real Estate Tax Appeals. PECO and Generation are each challenging
real estate taxes assessed on nuclear plants since 1997. PECO is involved
in litigation in which it is contesting Pennsylvania Public Utility Realty
Tax Act of March 4, 1971, as amended (PURTA) taxes assessed in 1997 and has
appealed local real estate assessments for 1998 and 1999 on its formerly
owned Limerick Generating Station (Montgomery County, PA) (Limerick) and
Peach Bottom Atomic Power Station (York County, PA) (Peach Bottom) plants.
Generation is involved in real estate tax appeals for 2000 through 2003,
also regarding the valuation of its Limerick and Peach Bottom plants, its
Quad Cities Station (Rock Island County, IL) and, through its ownership
interest in AmerGen, TMI (Dauphin County, PA).
During the third quarter of 2003, upon completion of updated
nuclear plant appraisal studies, PECO and Generation recorded reductions of
$58 million and $15 million, respectively, to reserves recorded for
exposures associated with the real estate taxes. While PECO and Generation
believe the resulting reserve balances as of September 30, 2003 reflect the
most likely probable expected outcome of the litigation and appeals
proceedings in accordance with SFAS No. 5, "Accounting for Contingencies,"
the ultimate outcome of such matters could result in additional unfavorable
or favorable adjustments to the consolidated financial statements of PECO
or Generation, and such adjustments could be material.
49
Generation
Cotter Corporation Litigation. During 1989 and 1991, actions were
brought in Federal and state courts in Colorado against ComEd and its
subsidiary, Cotter Corporation (Cotter), seeking unspecified damages and
injunctive relief based on allegations that Cotter permitted radioactive
and other hazardous material to be released from its mill into areas owned
or occupied by the plaintiffs, resulting in property damage and potential
adverse health effects. In 1994, a Federal jury returned nominal dollar
verdicts against Cotter on eight plaintiffs' claims in the 1989 cases,
which verdicts were upheld on appeal. The remaining claims in the 1989
actions were settled or dismissed. In 1998, a jury verdict was rendered
against Cotter in favor of 14 of the plaintiffs in the 1991 cases, totaling
approximately $6 million in compensatory and punitive damages, interest and
medical monitoring. On appeal, the Tenth Circuit Court of Appeals reversed
the jury verdict and remanded the case for new trial. These plaintiffs'
cases were consolidated with the remaining 26 plaintiffs' cases, which had
not been tried. The consolidated trial was completed on June 28, 2001. The
jury returned a verdict against Cotter and awarded $16 million in various
damages. On November 20, 2001, the District Court entered an amended final
judgment that included an award of both pre-judgment and post-judgment
interests, costs, and medical monitoring expenses that totaled $43 million.
In November 2000, another trial involving a separate sub-group of 13
plaintiffs seeking $19 million in damages plus interest was completed in
Federal District Court in Denver. The jury awarded nominal damages of
$42,500 to 11 of 13 plaintiffs but awarded no damages for any personal
injury or health claims, other than requiring Cotter to perform periodic
medical monitoring at minimal cost. Cotter appealed these judgments to the
Tenth Circuit Court of Appeals. On April 22, 2003, the Tenth Circuit Court
of Appeals reversed both judgments and remanded the cases for retrial. On
September 5, 2003, plaintiffs appealed the Tenth Circuit's decision to the
United States Supreme Court. Cotter has filed its response to the
plaintiff's petition.
On February 18, 2000, ComEd sold Cotter to an unaffiliated third
party. As part of the sale, ComEd agreed to indemnify Cotter for any
liability incurred by Cotter as a result of these actions, as well as any
liability arising in connection with the West Lake Landfill discussed in
the next paragraph. In connection with Exelon's 2001 corporate
restructuring, the responsibility to indemnify Cotter for any liability
related to these matters was transferred by ComEd to Generation. Generation
cannot predict the ultimate outcome of the cases.
The U.S. Environmental Protection Agency (EPA) has advised Cotter
that it is potentially liable in connection with radiological contamination
at a site known as the West Lake Landfill in Missouri. Cotter is alleged to
have disposed of approximately 39,000 tons of soils mixed with 8,700 tons
of leached barium sulfate at the site. Cotter, along with three other
companies identified by the EPA as potentially responsible parties (PRPs),
has submitted a draft feasibility study addressing options for remediation
of the site. The PRPs are also engaged in discussions with the State of
Missouri and the EPA. The estimated costs of remediation for the site range
from $0 to $87 million. Once a remedy is selected, it is expected that the
PRPs will agree on an allocation of responsibility for the costs. Until an
agreement is reached, Generation cannot predict its share of the costs,
and, as such, no amounts have been accrued as of September 30, 2003.
50
Raytheon Litigation. In March 2001, two subsidiaries of Sithe New
England acquired in November 2002 brought an action in the New York Supreme
Court against Raytheon Corporation (Raytheon) relating to its failure to
honor its guaranty with respect to the performance of the Mystic and Fore
River projects, as a result of the abandonment of the projects by the
turnkey contractor. In a related proceeding, in May 2002, Raytheon
submitted claims to the International Chamber of Commerce Court of
Arbitration (Arbitration Court) seeking equitable relief and damages for
alleged owner-caused performance delays in connection with the Fore River
Power Plant Engineering, Procurement & Construction Agreement (EPC
Agreement). The EPC Agreement, executed by a Raytheon subsidiary and
guaranteed by Raytheon, governs the design, engineering, construction,
start-up, testing and delivery of an 800-MW combined-cycle power plant in
Weymouth, Massachusetts. Hearings by the Arbitration Court with respect to
liability were held in January and February 2003. On May 12, 2003, the
Arbitration Court issued an interim order finding in favor of Raytheon on
liability but limited the grounds upon which Raytheon could claim schedule
and cost relief. After the interim order, Raytheon amended its claim to
seek 110 days of schedule relief (which would reduce Raytheon's liquidated
damage payment for late delivery by approximately $20 million) and
additional damages of $12 million. Raytheon also has asserted a claim in
the amount of approximately $13 million for loss of efficiency and
productivity as a result of an alleged constructive acceleration. The
aggregate amount of Raytheon's asserted claims is approximately $45
million, not including general and administrative costs, profit and
interest that Raytheon asserts are due under the EPC Agreement. Hearings by
the Arbitration Court with respect to damages were conducted and a final
decision is expected in the fourth quarter of 2003. Generation believes
that Sithe New England properly rejected Raytheon's request for a change
order and that Raytheon's damage claims are inflated. In addition to its
asserted claims, Raytheon has indicated that it will bring additional
claims for damages. Generation will continue to vigorously defend its
position in the litigation and contest any additional claims that may be
asserted.
On August 29, 2003, Raytheon filed an action against two
subsidiaries of EBG (Project Companies) and BNP Paribas in the Superior
Court of the Commonwealth of Massachusetts. Raytheon alleged that the
Project Companies and BNP Paribas failed to provide adequate assurance that
Raytheon would be paid the remaining amounts due under the Fore River and
Mystic construction contracts. Raytheon sought: (1) an injunction
preventing the Project Companies and BNP Paribas from drawing upon certain
letters of credit guaranteeing Raytheon's performance; (2) the right to
terminate the construction contracts; and (3) an order allowing Raytheon to
seize project funds totaling approximately $40 million. Raytheon
subsequently dismissed BNP Paribas from the litigation. On October 9, 2003,
the court issued a preliminary injunction preserving the status quo and
preventing the Project Companies from drawing upon the letters of credit
until such time as the court decides Raytheon's pending motion for partial
summary judgment. The court has heard argument on Raytheon's motion for
partial summary judgment but has not announced any decision. Generation is
unable to predict the ultimate outcome of these legal proceedings.
Clean Air Act. On June 1, 2001, the EPA issued to EBG a Notice of
51
Violation (NOV) and Reporting Requirement pursuant to Sections 113 and 114
of the Clean Air Act, alleging numerous exceedances of opacity limits and
violations of opacity-related monitoring, recording and reporting
requirements at certain generating units in Everett, Massachusetts (Mystic
Station). On January 8, 2002, the EPA indicated that it had decided to
resolve the NOV through an administrative compliance order and a judicial
civil penalty action. In March 2002, the EPA issued and Exelon Mystic LLC,
a wholly owned subsidiary of EBG, voluntarily entered a Compliance Order
and Reporting Requirement (Compliance Order) regarding Mystic Station,
under which Mystic Station installed new ignition equipment on three of the
four operating units at the plant. Mystic Station also undertook an
extensive opacity monitoring and testing program for all four operating
units at the plant to help determine if additional compliance measures were
needed. Pursuant to the requirements of the Compliance Order, EBG switched
three of the four operating units to a lower sulfur fuel oil by September
1, 2002. The Compliance Order did not address civil penalties. By a letter
dated April 21, 2003, the United States Department of Justice notified EBG
that, at the request of the EPA, it intended to bring a civil penalty
action but also offered the opportunity to resolve the matter through
settlement discussions. EBG is pursuing settlement discussions with the EPA
and the Department of Justice. Generation cannot reasonably predict the
ultimate outcome of the settlement discussions.
Exelon, ComEd, PECO and Generation
Exelon, ComEd, PECO and Generation are involved in various other
litigation matters that are being defended and handled in the ordinary
course of business, and Exelon, ComEd, PECO and Generation maintain
accruals for such costs that are probable of being incurred and subject to
reasonable estimation. The ultimate outcome of such matters, as well as the
matters discussed above, while uncertain, are not expected to have a
material adverse effect on their respective financial condition or results
of operations.
52
Commercial Commitments
Exelon, ComEd, PECO and Generation's commercial commitments as of
September 30, 2003, representing commitments not recorded on the balance
sheet but potentially triggered by future events, including obligations to
make payment on behalf of other parties and financing arrangements to
secure their obligations, were as follows:
Expiration within
-----------------------------------------------------------------------
2008
Exelon Total 2003 2004-2005 2006-2007 and beyond
------------------------------------------------------------------------------------------------------------------
Related to Obligations Recorded on the Balance Sheet
----------------------------------------------------
Letters of credit (non-debt) (a) $ 121 $ 29 $ 92 $ -- $ --
Letters of credit (long-term debt) (b) 413 50 363 -- --
Preferred securities guarantees (c) 528 -- -- -- 528
Guarantees of long-term debt (d) 41 -- 2 -- 39
Midwest Generation Capacity
Reservation Agreement guarantee (e) 33 1 7 7 18
Other
-----
Guarantees of letters of credit (f) 28 4 24 -- --
Performance guarantees (g) 112 -- -- -- 112
Surety bonds (h) 622 197 256 12 157
Energy marketing contract
guarantees (i) 208 91 113 4 --
Nuclear insurance guarantees (j) 1,559 -- -- -- 1,559
Lease guarantees (k) 10 -- -- 1 9
EBG equity guarantee (l) 38 38 -- -- --
Fuel purchase agreements (m) 2,130 139 791 586 614
------------------------------------------------------------------------------------------------------------------
Total $ 5,843 $ 549 $ 1,648 $ 610 $ 3,036
==================================================================================================================
Expiration within
-----------------------------------------------------------------------
2008
ComEd Total 2003 2004-2005 2006-2007 and beyond
------------------------------------------------------------------------------------------------------------------
Related to Obligations Recorded on the Balance Sheet
----------------------------------------------------
Letters of credit (non-debt) (a) $ 26 $ 1 $ 25 $ -- $ --
Letters of credit (long-term debt) (b) 50 50 -- -- --
Preferred securities guarantees (c) 350 -- -- -- 350
Midwest Generation Capacity
Reservation Agreement guarantee (e) 33 1 7 7 18
Other
-----
Surety bonds (h) 21 -- 3 -- 18
------------------------------------------------------------------------------------------------------------------
Total $ 480 $ 52 $ 35 $ 7 $ 386
==================================================================================================================
53
Expiration within
-----------------------------------------------------------------------
2008
PECO Total 2003 2004-2005 2006-2007 and beyond
------------------------------------------------------------------------------------------------------------------
Related to Obligations Recorded on the Balance Sheet
----------------------------------------------------
Letters of credit (non-debt) (a) $ 29 $ -- $ 29 $ -- $ --
Preferred securities guarantees (c) 178 -- -- -- 178
Other
-----
Surety bonds (h) 46 -- 46 -- --
------------------------------------------------------------------------------------------------------------------
Total $ 253 $ -- $ 75 $ -- $ 178
==================================================================================================================
Expiration within
-----------------------------------------------------------------------
2008
Generation Total 2003 2004-2005 2006-2007 and beyond
------------------------------------------------------------------------------------------------------------------
Related to Obligations Recorded on the Balance Sheet
----------------------------------------------------
Letters of credit (non-debt) (a) $ 16 $ 9 $ 7 $ -- $ --
Letters of credit (long-term debt) (b) 363 -- 363 -- --
Other
-----
Performance guarantees (g) 101 -- -- -- 101
Energy marketing contract
guarantees (i) 36 36 -- -- --
EBG equity guarantee (l) 38 38 -- -- --
Fuel purchase agreements (m) 2,130 139 791 586 614
Nuclear insurance guarantee (n) 151 -- -- -- 151
------------------------------------------------------------------------------------------------------------------
Total $ 2,835 $ 222 $ 1,161 $ 586 $ 866
==================================================================================================================
(a) Letters of credit (non-debt) - Exelon and certain of its subsidiaries
maintain non-debt letters of credit to provide credit support for
certain transactions as requested by third parties.
(b) Letters of credit (long-term debt) - Direct-pay letters of credit
issued in connection with variable-rate debt in order to provide
liquidity in the event that it is not possible to remarket all of the
debt as required following specific events, including changes in the
basis of determining the interest rate on the debt.
(c) Preferred securities guarantees - Guarantees issued to guarantee the
preferred securities of the unconsolidated and consolidated subsidiary
trusts of ComEd and PECO.
(d) Guarantees of long-term debt - Issued to guarantee payment of
Enterprises' debt.
(e) Midwest Generation Capacity Reservation Agreement guarantee - In
connection with ComEd's agreement with the City of Chicago (Chicago)
entered into on February 20, 2003, Midwest Generation assumed from
Chicago a Capacity Reservation Agreement that Chicago had entered into
with Calumet Energy Team, LLC. ComEd will reimburse Chicago for any
nonperformance by Midwest Generation under the Capacity Reservation
Agreement. The estimated fair value of this guarantee under FIN 45 of
$4 million is included as a liability on ComEd's Consolidated Balance
Sheets. Additional information regarding this liability is included
within this section under the heading "General" below.
(f) Guarantees of letters of credit - Guarantees issued to provide support
for letters of credit as required by third parties. These guarantees
could be called upon only in the event of non-payment by a subsidiary.
(g) Performance guarantees - Guarantees issued to ensure performance under
specific contracts.
(h) Surety bonds - Guarantees issued related to contract and commercial
surety bonds, excluding bid bonds.
(i) Energy marketing contract guarantees - Guarantees issued to ensure
performance under energy commodity contracts.
(j) Nuclear insurance guarantees - Guarantees of nuclear insurance
required under the Price-Anderson Act. $1.0 billion of this total
exposure is exempt from the $4.5 billion PUHCA guarantee limit by SEC
rule.
(k) Lease guarantees - Guarantees issued to ensure payments on building
leases.
(l) EBG equity guarantee- See Note 3 - Acquisitions, Dispositions and
Retirements for further information on the $38 million guarantee.
Pursuant to existing guarantees, after construction of the EBG
facilities is complete, Exelon could be required to pay up to an
additional $42 million relating to various construction and tax
obligations.
(m) Fuel purchase agreements - Commitments to purchase fuel supplies for
nuclear and fossil generation.
(n) Nuclear insurance guarantee - Guarantees of nuclear insurance required
under the Price-Anderson Act. This amount relates to Generation's
guarantee of AmerGen's plants. Exelon has a $1.4 billion guarantee
relating to Generation's directly owned plants that is not included in
this amount.
54
Credit Contingencies
Generation is a counterparty to Dynegy in various energy
transactions. The credit ratings of Dynegy are considered below investment
grade by two credit rating agencies. Generation has credit risk associated
with Dynegy through Generation's equity investment in Sithe. Sithe is a 60%
owner of the Independence generating station (Independence), a 1,040-MW
gas-fired qualified facility that has an energy-only long-term tolling
agreement with Dynegy with a related financial swap arrangement. As of
September 30, 2003, Sithe had recognized an asset on its balance sheet
related to the fair market value of the financial swap agreement with Dynegy
that is marked to market under the provisions of SFAS No. 133. If Dynegy is
unable to fulfill the terms of this agreement, Sithe would be required to
impair this financial swap asset. Generation estimates, as a 49.9% owner of
Sithe, that the impairment would result in an after-tax reduction of its
earnings of approximately $16 million.
In addition to the impairment of the financial swap asset, if
Dynegy were unable to fulfill its obligations under the financial swap
agreement and the tolling agreement, Generation may incur a further
impairment associated with Independence.
Additionally, the future economic value of AmerGen's PPA with
Illinois Power Company, a subsidiary of Dynegy, could be impacted by events
related to Dynegy's financial condition.
ComEd and Generation are parties to various transactions with
Midwest Generation. Midwest Generation's credit ratings have been downgraded
by certain credit rating agencies. Furthermore, the June 30, 2003 Form 10-Q
filed by Edison Mission Energy (EME), an intermediate parent company of
Edison Mission Midwest Holdings (EMMH) and Midwest Generation, indicates
that EMMH is not expected to have sufficient cash to repay $911 million of
debt when it matures on December 11, 2003; a failure to repay, extend, or
refinance the EMMH obligation would likely result in a default under the
senior secured notes and term loan of Mission Energy Holding Company, EME's
parent company; and these events could make it necessary for EME to file a
petition for reorganization under Chapter 11 of the United States Bankruptcy
Code. Reorganization under Chapter 11 of the United States Bankruptcy Code
does not assure non-performance under all contracts; however, the
reorganization would increase the possibility of the obligations described
in the following two paragraphs reverting to ComEd or Generation.
In connection with ComEd's sale in December 1999 of fossil
generating assets to Midwest Generation, ComEd entered into an agency
agreement with EMMH and EME whereby EMMH assumed the benefits and
liabilities of a long-term coal purchase contract and a railcar lease. EME
guaranteed EMMH's performance. EMMH did not become a direct party to the
obligations, and ComEd remained obligated and was not released. In
connection with the Merger and subsequent restructuring, Generation assumed
any contingent obligation on these contracts from ComEd. In the event of
EMMH and EME's non-performance under the coal purchase contract, Generation
would be required to fulfill the purchase commitments that extend through
2012. The contract requires the purchase of two million tons of coal
annually or specifies a minimum payout. Based upon current market prices,
Generation's contingent obligations for the minimum purchase obligation for
the contract years 2003 to 2012 are estimated to be approximately $81
million (the net present value of the obligation approximates $51 million)
related to this agreement. The railcar lease covers approximately 1,400 coal
transport railcars through 2014. In the event of EMMH and EME's
non-performance under the railcar lease, Generation would be required to
fulfill the lease payments that extend through 2014. The remaining lease
payments for the railcars approximate $65 million (the net present value of
the obligation approximates $38 million). However, based on current prices
for railcars in these particular markets, Generation believes it would be
able to effectively sublease the railcars without incurring any exposure
related to this obligation.
55
Generation and ComEd have entered into other agreements with
Midwest Generation and have other related exposures. In connection with
ComEd's fossil generating asset sale to Midwest Generation, Midwest
Generation and EME agreed to indemnify ComEd for various environmental
exposures or penalties. Generation assumed any contingent obligations
relating to generation-related environmental issues of ComEd in connection
with the Merger and subsequent restructuring. Exelon cannot reasonably
estimate the possible environmental exposures or penalties that could arise
if Midwest Generation or EME do not honor their indemnity to ComEd or if the
indemnity is discharged in bankruptcy. Midwest Generation also indemnified
Generation and ComEd for approximately 50% of any post-acquisition asbestos
claims relating to the plants sold to Midwest Generation. Generation assumed
any contingent obligations of ComEd relating to these asbestos claims in
connection with the Merger and subsequent restructuring. The bankruptcy of
or non-performance of Midwest Generation of its obligations to Generation
and ComEd for asbestos claims could result in contingent obligations to
Generation and ComEd of up to an estimated $5 million. In addition, ComEd is
exposed to risks associated with accounts receivable from transmission and
station power services provided by ComEd to Midwest Generation. The
bankruptcy of or non-performance of Midwest Generation of its obligations to
ComEd for transmission and station power services provided by ComEd could
result in ComEd recording a write-off of up to an estimated $3 million.
Generation accounts for certain derivative financial instruments
under the normal purchases and normal sales exemption of SFAS No. 133. As of
September 30, 2003, Generation is a party to forward energy purchase and
sale contracts with Midwest Generation, which are accounted for in that
manner and, as such, are not marked-to-market. If Generation determines that
the possibility of non-performance by Midwest Generation on these contracts
becomes more than remote, these contracts will be required to be
marked-to-market through earnings, which would be expected to result in a
charge to Exelon and Generation's results of operations and such charge
could be material.
Spent Fuel Storage
In July 2000, PECO and the U. S. Department of Energy (DOE)
entered into a settlement agreement whereby, in return for foregoing a
breach of contract lawsuit against the DOE, PECO agreed to receive credits
against its contributions to the Nuclear Waste Fund to cover its costs of
having to construct and maintain an independent spent fuel storage facility
at Peach Bottom, a facility co-owned by PECO (now Generation). In September
2002, the U.S. Courts of Appeals for the 11th Circuit ruled that the
settlement agreement's credit-based funding mechanism violated provisions
of the Nuclear Waste Policy Act. Generation, as successor to PECO,
currently is in good faith discussions with the DOE regarding a new
settlement agreement with a different funding mechanism. On August 14,
2003, Generation received a letter from the DOE demanding repayment of $40
million of previously received credits from the Nuclear Waste Fund. The
letter also demanded $1.5 million of accrued interest expense. Although a
new settlement would offset Generation's payments, Generation nonetheless
has reserved its 50% ownership share of these amounts. Because Generation
56
expenses the casks and capitalizes the permanent components of its spent
fuel storage facilities, these reserves increased Generation's operating
and maintenance expense approximately $11 million and its capital base
approximately $9 million during the third quarter of 2003. The remainder of
the recorded obligation to the DOE will be recovered from the co-owner of
the facility. See Note 9 - Nuclear Decommissioning and Spent Nuclear Fuel
Storage in Generation's 2002 Form 10-K for additional information regarding
this matter.
General
On February 20, 2003, ComEd entered into separate agreements with
Chicago and with Midwest Generation (Midwest Agreement). Under the terms of
the agreement with Chicago, ComEd will pay Chicago $60 million over ten
years ($6 million was paid during the first quarter of 2003) and be
relieved of a requirement, originally transferred to Midwest Generation
upon the sale of ComEd's fossil stations in 1999, to build a 500-MW
generation facility. Under the Midwest Agreement, ComEd received $22
million from Midwest Generation during the first quarter 2003 and $10
million during April 2003, to relieve Midwest Generation's obligation under
the fossil sale agreement. Midwest Generation also assumed from Chicago a
Capacity Reservation Agreement that Chicago had entered into with Calumet
Energy Team, LLC (CET), which is effective through June 2012. ComEd is
obligated to reimburse Chicago for any nonperformance by Midwest Generation
under the Capacity Reservation Agreement and paid approximately $2 million
for amounts owed to CET by Chicago at the time the agreement was executed.
In the first quarter of 2003, ComEd recorded a guarantee liability of $4
million under the provisions of FIN No. 45 related to its obligation to
reimburse Chicago for any nonperformance by Midwest Generation. The net
effect of the settlement to ComEd will be amortized over the remaining life
of the franchise agreement with Chicago.
ComEd and PECO have entered into several agreements with a tax
consultant related to the filing of refund claims with the Internal Revenue
Service (IRS) and have made refundable prepayments of $11 million and $1
million, respectively, during the nine months ended September 30, 2003 for
potential fees associated with these agreements. The fees for these
agreements are contingent upon a successful outcome and are based upon a
percentage of the refunds recovered from the IRS, if any. As such, ultimate
net cash outflows to ComEd and PECO related to these agreements will either
be positive or neutral depending upon the outcome of the refund claim with
the IRS. These potential tax benefits and associated fees could be material
to the financial position, results of operations and cash flows of ComEd
and PECO. ComEd's tax benefits for periods prior to the Merger would be
recorded as a reduction of goodwill pursuant to a reallocation of the
Merger purchase price. ComEd and PECO cannot predict the timing of the
final resolution of these refund claims.
10. SEVERANCE BENEFITS (Exelon, ComEd, PECO and Generation)
Exelon, ComEd, PECO and Generation provide severance and health
and welfare benefits to terminated employees pursuant to pre-existing
severance plans primarily based upon each individual employee's years of
service with Exelon and compensation level. The registrants account for
57
their ongoing severance plans in accordance with SFAS No. 112, "Employer's
Accounting for Postemployment Benefits, an amendment of FASB Statements No.
5 and 43" (SFAS No. 112) and accrue amounts associated with severance
benefits that are considered probable and that can be reasonably estimated.
As part of the implementation of Exelon's new business model
referred to as The Exelon Way during the third quarter of 2003, Exelon
identified 1,042 positions for elimination by the end of 2004. The majority
of the headcount reductions are professional and managerial employees.
Exelon recorded a charge for cash severance of $87 million during the third
quarter of 2003, which represented cash severance costs that were probable
and could be reasonably estimated as of September 30, 2003. In addition to
cash severance, Exelon incurred pension and postretirement benefit costs
associated with The Exelon Way during the third quarter of 2003 of $80
million. In total, Exelon recorded a charge of $167 million in the third
quarter for severance and related postretirement health and welfare benefits
and pension and postretirement curtailment costs associated with The Exelon
Way. See Note 11 - Retirement Benefits for a description of the charges for
the pension and postretirement benefit plans. Exelon based its estimate of
the number of positions to be eliminated on management's current plans and
its ability to determine the appropriate staffing levels to effectively
operate the businesses. Exelon anticipates incurring further costs
associated with The Exelon Way upon identifying additional positions to be
eliminated. These costs will be recorded in the period in which the costs
can be reasonably estimated.
The following table details, by segment, Exelon's total cash
severance expense recorded as an operating and maintenance expense within
the Consolidated Statements of Income and Comprehensive Income for the
three and nine months ended September 30, 2003.
Corporate and
Energy Intersegment
Cash severance charges Delivery Generation Enterprises Eliminations Consolidated
------------------------------------------------------------------------------------------------------------------
Expense Recorded in Three Months Ended
September 30, 2003 $ 50 $ 20 $ 7 $ 10 $ 87
Expense Recorded in Nine Months Ended
September 30, 2003 53 24 7 11 95
------------------------------------------------------------------------------------------------------------------
The following table provides information on total cash severance
expense recorded as an operating and maintenance expense within the
Consolidated Statements of Income and Comprehensive Income of ComEd, PECO
and Generation:
Cash severance charges ComEd PECO Generation
------------------------------------------------------------------------------------------------------------------
Expense Recorded in Three Months Ended
September 30, 2003 $ 37 $ 13 $ 20
Expense Recorded in Nine Months Ended
September 30, 2003 37 16 24
------------------------------------------------------------------------------------------------------------------
58
The following tables provide a reconciliation of the liability
recorded by Exelon, ComEd, PECO and Generation for severance benefits:
Balance at Other Balance at
Cash severance obligations January 1, 2003 Additions Payments Adjustments September 30, 2003
------------------------------------------------------------------------------------------------------------------
Exelon $ 45 $ 95 $ (25) $ 3 $ 118
ComEd 15 37 (10) -- 42
PECO -- 16 -- -- 16
Generation 14 24 (4) 3 37
------------------------------------------------------------------------------------------------------------------
11. RETIREMENT BENEFITS (Exelon, ComEd, PECO and Generation)
During the third quarter of 2003, Exelon announced an amendment
related to the benefit provisions of its postretirement welfare benefit
plans. The amendment was effective August 1, 2003 and reduced the benefits
attributable to prior service through increased retiree cost-sharing for
medical coverage. The changes in the postretirement welfare plan design due
to the amendment were incorporated into the August 1, 2003 remeasurement of
the plan obligation discussed below. The amendment resulted in a reduction
of the accumulated projected benefit obligation related to the
postretirement welfare benefit plans of approximately $337 million and a
reduction of cost of $36 million. Exelon recognized approximately $14
million of this cost reduction in the third quarter of 2003 with the
remainder to be recognized in the fourth quarter of 2003.
Due to The Exelon Way and the overall reduction in active
employees during the third quarter of 2003, certain defined benefit pension
plans and postretirement welfare benefit plans were subject to
remeasurement as of August 1, 2003. The threshold basis for curtailment
remeasurement was a reduction in future service greater than 5%. The
curtailment of certain of the pension plans resulted in a reduction of the
additional minimum liability and a decrease in the intangible pension asset
of $10 million. Overall, the projected benefit obligation of the pension
plan increased by $1 million due to the curtailment. The projected benefit
obligation associated with the postretirement benefit plans increased by
$17 million due to the curtailment.
The remeasurements of the plan obligations resulted in accelerated
recognition of a portion of the prior service cost generated by the pension
and postretirement benefit plans, resulting in the recognition of
curtailment charges during the third quarter of 2003. The magnitude of the
curtailment charge differed by registrant based on the number of
participants identified for termination and the amount of the unrecognized
prior service costs at the date of remeasurement. The following table
provides information regarding the curtailment charges recorded in
operating and maintenance expense within the Consolidated Statements of
Income and Comprehensive Income during the three months ended September 30,
2003 due to the accelerated recognition of a portion of the prior service
cost:
59
Curtailment charges Pension plans Other postretirement plans
------------------------------------------------------------------------------------------------------------------
Exelon $ 11 $ 15
ComEd 1 1
PECO 6 10
Generation 3 4
------------------------------------------------------------------------------------------------------------------
During the third quarter of 2003, Exelon recognized an additional
charge associated with special health and welfare benefits offered through
The Exelon Way. The following table provides information regarding the
charges recorded as an operating and maintenance expense within the
Consolidated Statements of Income and Comprehensive Income during the three
months ended September 30, 2003:
Special health and welfare charges Other postretirement plans
------------------------------------------------------------------------------------------------------------------
Exelon $ 54
ComEd 20
PECO 12
Generation 20
------------------------------------------------------------------------------------------------------------------
12. LONG-TERM DEBT AND PREFERRED SECURITIES (Exelon, ComEd, PECO and
Generation)
Effective July 1, 2003, ComEd and PECO reclassified the carrying
values of their preferred securities issued prior to June 1, 2003 from
equity to liabilities in conjunction with the adoption of SFAS No. 150. The
total amounts reclassified from equity to liabilities were $422 million,
$344 million and $78 million for Exelon, ComEd and PECO, respectively. See
Note 2 - New Accounting Principles and Accounting Changes for additional
information regarding the adoption of FIN No. 46 and SFAS No. 150.
On September 30, 2003, ComEd retired $250 million of variable
interest medium term notes due September 30, 2003.
On September 30, 2003, ComEd redeemed $42 million of variable rate
Pollution Control Revenue Bonds, 1994 B Series, due October 15, 2014
originally issued through the Illinois Development Finance Authority.
On September 24, 2003, ComEd issued $42 million of variable
interest Pollution Control Revenue Refunding Bonds due November 1, 2019
through the Illinois Development Finance Authority.
On August 25, 2003, ComEd issued $250 million of 4.74% First
Mortgage Bonds, due in 2010. These bond issuances were used to finance the
repayment and early retirement of long-term debt.
60
On July 15, 2003, ComEd retired $100 million of its First Mortgage
Bonds due July 15, 2003. The 6.625% bonds were refinanced with long-term
debt issued on August 25, 2003.
On May 15, 2003, ComEd redeemed $42 million of 5.875% Pollution
Control Revenue Bonds 1977 Series A, due May 15, 2007 originally issued
through the Illinois Industrial Pollution Control Financing Authority.
On May 8, 2003, ComEd issued $40 million of variable interest
Pollution Control Revenue Refunding Bonds due May 15, 2017 through the
Illinois Development Finance Authority.
On April 15, 2003, ComEd redeemed $160 million of its First
Mortgage Bonds, at a redemption price of 103.664% of the principal amount,
plus accrued interest. The bonds, which carried an interest rate of 8%,
were refinanced with long-term debt issued on April 7, 2003.
On April 7, 2003, ComEd issued $395 million of 4.70% First
Mortgage Bonds, due on April 15, 2015. The proceeds of these bonds were
used to refund other First Mortgage Bonds.
On March 20, 2003, ComEd Financing I, a wholly owned financing
subsidiary of ComEd, redeemed $200 million of trust preferred securities at
a redemption price of 100% of the principal amount, plus accrued
distributions. ComEd redeemed $206 million of subordinated debentures
issued to ComEd Financing I. The preferred securities, which carried an
interest rate of 8.48%, were refinanced with the proceeds from a March 17,
2003 issue of $200 million of trust preferred securities by ComEd Financing
III, a wholly owned financing subsidiary of ComEd, which have an annual
distribution rate of 6.35% and are mandatorily redeemable in 2033. The
subordinated debentures, which carried an interest rate of 8.48%, were
refinanced with the proceeds from a March 17, 2003 issue of $206 million of
subordinated debentures from ComEd to ComEd Financing III, which have an
annual distribution rate of 6.35% and are mandatorily redeemable in 2033.
On March 18, 2003, ComEd redeemed $236 million of its First
Mortgage Bonds, at a redemption price of 103.863% of the principal amount,
plus accrued interest. The bonds, which carried an interest rate of 8.375%,
were refinanced with long-term debt issued on April 7, 2003.
On January 22, 2003, ComEd issued $350 million of 3.70% First
Mortgage Bonds, due in 2008 and $350 million of 5.875% First Mortgage
Bonds, due in 2033. These bond issuances were used to refinance long-term
debt that had been previously retired during the third and fourth quarters
of 2002.
During the nine months ended September 30, 2003, Exelon and ComEd
retired $267 million and $52 million of commercial paper classified as
long-term debt, respectively.
During the nine months ended September 30, 2003, Exelon retired
$493 million of transitional funding trust notes, comprised of $254 million
for ComEd and $239 million for PECO.
61
During the nine months ended September 30, 2003, ComEd recorded
prepayment premiums of $15 million and net unamortized premiums, discounts
and debt issuance expenses of $57 million associated with the early
retirement of debt in 2003 that have been deferred by ComEd in regulatory
assets and will be amortized to interest expense over the life of the
related new debt issuance consistent with regulatory recovery.
During June 2003, PECO issued $103 million of subordinated
debentures to PECO Trust IV in connection with the issuance by PECO Trust
IV of $100 million of preferred securities with an annual distribution rate
of 5.75% that are mandatorily redeemable in 2033. The trust preferred
securities were recorded as liabilities of PECO as of June 30, 2003 in
accordance with SFAS No. 150. Effective July 1, 2003, PECO Trust IV was
deconsolidated from the financial statements of PECO in conjunction with
the adoption of FIN No. 46. See Note 2 - New Accounting Principles and
Accounting Changes for further information. The $103 million of
subordinated debentures issued by PECO to PECO Trust IV was recorded as
long-term debt to affiliate within the Consolidated Balance Sheets. The
proceeds of the issue were used to redeem the trust preferred securities
and preferred stock discussed below.
Also on June 24, 2003, PECO Energy Capital Trust II, a wholly
owned financing subsidiary of PECO, redeemed $50 million of its 8.00% trust
preferred securities at a redemption price of $25 per trust receipt, plus
accrued and unpaid distributions. PECO redeemed $52 million of subordinated
debentures to PECO Energy Capital Trust II.
On June 11, 2003, PECO redeemed $50 million of its $7.48 preferred
stock at a redemption price of $103.74 per share, plus accrued and unpaid
dividends.
On April 28, 2003, PECO issued $450 million of 3.50% First and
Refunding Mortgage Bonds due on May 1, 2008. The proceeds from the sale of
the bonds were used to repay aggregate principal of maturing debt and to
repay commercial paper that was used to refinance long-term debt.
On June 3, 2003, Generation issued $17 million of variable rate
Pollution Control Revenue Refunding Bonds, Series A, due June 1, 2027
through the Indiana County Industrial Development Authority (Pennsylvania).
The proceeds of these bonds were used to refund $17 million of Pollution
Control Revenue Refunding Bonds, due June 1, 2027, issued on behalf of
PECO.
During the third quarter of 2003, an event of default occurred
related to the EBG Facility. See Note 3 - Acquisitions, Dispositions and
Retirements for further information.
On September 29, 2003, Generation closed on an $850 million
revolving credit facility that replaced a $550 million revolving credit
facility that had originally closed on June 13, 2003. Generation used the
facility to make the first payment to Sithe relating to the $536 million
note that was used to purchase Exelon New England. This note was
restructured in June 2003 to provide for a payment of $210 million of the
principal on June 16, 2003, payment of $236 million of the principal on the
earlier of December 1, 2003 or change of control of Generation, and payment
62
of the remaining principal on the earlier of December 1, 2004 or change of
control of Generation. At September 30, 2003, Generation had $640 million
available under this credit facility.
Exelon, ComEd, PECO and Generation maintain a $1.5 billion 364-day
credit facility to support commercial paper issuances. At September 30,
2003, sublimits under the credit facility were $1.0 billion, $100 million
and $400 million for Exelon Corporate, ComEd and PECO, respectively.
Generation did not have a sublimit under the facility at September 30,
2003. Exelon Corporate, ComEd and PECO had approximately $720 million, $360
million and $75 million available under the credit facility, respectively,
reflecting commercial paper, letters of credit and loans outstanding at
September 30, 2003. At September 30, 2003, commercial paper outstanding was
$70 million and $12 million at Exelon Corporate and PECO, respectively.
ComEd and Generation did not have any commercial paper outstanding at
September 30, 2003.
See Note 8 - Fair Value of Financial Assets and Liabilities for
additional information regarding interest rate swaps of ComEd, PECO and
Generation.
63
13. RELATED-PARTY TRANSACTIONS (Exelon, ComEd, PECO and Generation)
ComEd
ComEd's financial statements reflect related-party transactions as
reflected in the tables below.
Three Months Nine Months
------------------- -------------------
Ended September 30, Ended September 30,
------------------- -------------------
2003 2002 2003 2002
-----------------------------------------------------------------------------------------------------------------------
Operating revenues from affiliates
Generation (1) $ 16 $ 22 $ 42 $ 41
Enterprises (1) 4 4 7 8
Purchased power from affiliate
Generation (2) 885 967 1,984 2,046
Operating & maintenance from affiliates
BSC (3) 32 29 84 94
Enterprises (4, 5) 8 4 14 10
Interest income from affiliates
UII (6) 5 8 17 23
Exelon intercompany money pool (10) 1 -- 2 --
Other -- -- 1 --
Capitalized costs
BSC (3) 1 3 3 6
Enterprises (5) 10 3 21 16
Cash dividends paid to parent 94 118 305 353
-----------------------------------------------------------------------------------------------------------------------
September 30, 2003 December 31, 2002
-----------------------------------------------------------------------------------------------------------------------
Receivables from affiliates (current)
UII (6) $ -- $ 15
Exelon intercompany money pool (10) 147 --
Other 4 --
Receivables from affiliates (noncurrent)
UII (6) 1,071 1,284
Generation (8) 1,144 --
Other 13 16
Payables to affiliates (current)
Generation decommissioning (7) 11 59
Generation (1, 2) 162 339
BSC (3) 13 18
Payables to affiliates (noncurrent)
Generation decommissioning obligation (7) 33 218
Other 6 6
Shareholders' equity - receivable from parent (9) 509 615
-----------------------------------------------------------------------------------------------------------------------
(1) ComEd provides electric, transmission, and other ancillary services to
Generation and Enterprises.
(2) Effective January 1, 2001, ComEd entered into a PPA with Generation.
See Note 9 - Commitments and Contingencies for further information
regarding the PPA. The Generation payable primarily consists of
services related to the PPA.
(3) ComEd receives a variety of corporate support services from Exelon
Business Services Company (BSC), including legal, human resource,
financial, information technology, supply management and corporate
governance services. A portion of such services, provided at cost
including applicable overhead, is capitalized.
(4) ComEd has contracted with Exelon Services (an Enterprises company) to
provide energy conservation services to ComEd customers.
(5) ComEd receives substation and transmission engineering and
construction services under contracts with InfraSource. A portion of
such services is capitalized.
64
(6) ComEd has a note and interest receivable with a variable interest rate
of the one month forward LIBOR rate plus 50 basis points from Unicom
Investments Inc. (UII) relating to the December 1999 fossil plant
sale. This note matures in December 2011.
(7) ComEd has a short-term and long-term payable to Generation, primarily
representing ComEd's legal requirements to remit collections of
nuclear decommissioning costs from customers to Generation.
(8) ComEd has a receivable from Generation related to a regulatory
liability as a result of the adoption of SFAS No. 143. For further
information see Note 2 - New Accounting Principles and Accounting
Changes.
(9) ComEd has a non-interest bearing receivable from Exelon related to
Exelon's agreement to fund future income tax payments resulting from
the collection by ComEd of instrument funding changes. The receivable
is expected to be settled over the years 2003 through 2008.
(10) ComEd participates in Exelon's intercompany money pool. ComEd earns
interest on its investments in the money pool at a market rate of
interest.
Exelon and PECO
Exelon and PECO's financial statements reflect related-party transactions
with its unconsolidated financing subsidiary, PECO Trust IV, as reflected
in the tables below.
Three Months Nine Months
------------ -----------
Ended September 30, Ended September 30,
------------------- -------------------
2003 2002 2003 2002
------------------------------------------------------------------------------------------------------------------
Interest expense to PECO Trust IV (1) $ 2 $ -- $ 2 $ --
------------------------------------------------------------------------------------------------------------------
September 30, 2003 December 31, 2002
------------------------------------------------------------------------------------------------------------------
Note receivable from PECO Trust IV (long-term) (1) $ 1 $ --
Debt to PECO Trust IV (1) 103 --
------------------------------------------------------------------------------------------------------------------
(1) As of July 1, 2003, PECO Trust IV, a wholly owned financing subsidiary
of PECO created in May 2003, is no longer consolidated within the
financial statements of Exelon or PECO pursuant to the provisions of
FIN No. 46. Amounts owed to PECO Trust IV are recorded as long-term
debt to affiliate within the Consolidated Balance Sheets, and interest
owed to PECO Trust IV is recorded as interest expense within the
Consolidated Statements of Income and Comprehensive Income. A note
receivable was recorded as of July 1, 2003 representing amounts owed
to PECO from PECO Trust IV related to debt issuance costs paid by
PECO. PECO holds $3 million of the common securities issued by PECO
Trust IV.
65
PECO
In addition to the transactions described above, PECO's financial
statements reflect a number of related-party transactions as reflected in
the table below.
Three Months Nine Months
------------ -----------
Ended September 30, Ended September 30,
------------------- -------------------
2003 2002 2003 2002
------------------------------------------------------------------------------------------------------------------
Operating revenues from affiliate
Generation (1) $ 3 $ 3 $ 8 $ 9
Other -- -- 1 --
Purchased power from affiliate
Generation (2) 421 441 1,101 1,090
Operating & maintenance from affiliates
BSC (3) 14 10 36 36
Enterprises (4) -- 5 3 21
Capitalized costs
BSC (3) 1 2 6 8
Enterprises (4) 10 6 23 16
Cash dividends paid to parent 79 85 244 255
------------------------------------------------------------------------------------------------------------------
September 30, 2003 December 31, 2002
------------------------------------------------------------------------------------------------------------------
Payables to affiliates (current)
Generation (2) $ 123 $ 124
BSC (3) 18 26
Enterprises (4) -- 19
Other 1 1
Payable to affiliate (noncurrent)
Generation (5) 7 --
Shareholders' equity - receivable from parent (6) 1,661 1,758
------------------------------------------------------------------------------------------------------------------
(1) PECO provides energy to Generation for Generation's own use.
(2) Effective January 1, 2001, PECO entered into a PPA with Generation.
See Note 9 - Commitments and Contingencies for further information
regarding the PPA.
(3) PECO receives a variety of corporate support services from BSC,
including legal, human resource, financial, information technology,
supply management and corporate governance services. Such services are
provided at cost, including applicable overhead. Some of these costs
are capitalized.
(4) PECO receives services from Enterprises for construction, which are
capitalized, and the implementation of automated meter reading
technology, which are expensed.
(5) PECO has a payable to Generation related to a regulatory asset as a
result of the adoption of SFAS No. 143. See Note 2 - New Accounting
Principles and Accounting Changes for further discussion of the
adoption of SFAS No. 143.
(6) PECO has a non-interest bearing receivable from Exelon related to
Exelon's agreement to fund future income tax payments resulting from
the collection of PECO's stranded costs recovery. The receivable is
expected to be settled over the years 2003 through 2010.
66
Exelon and Generation
Exelon and Generation's financial statements reflect related-party
transactions with unconsolidated affiliates as reflected in the tables
below.
Three Months Nine Months
------------ -----------
Ended September 30, Ended September 30,
------------------- -------------------
2003 2002 2003 2002
------------------------------------------------------------------------------------------------------------------
Purchased power from AmerGen (1) $ 133 $ 104 $ 310 $ 220
Interest income from AmerGen (2) -- 1 1 2
Interest expense to Sithe (3) 2 -- 7 --
Services provided to AmerGen (4) 50 16 85 46
Services provided to Sithe (5) -- -- 1 1
Services provided by Sithe (6,7) -- 3 5 5
------------------------------------------------------------------------------------------------------------------
September 30, 2003 December 31, 2002
------------------------------------------------------------------------------------------------------------------
Net receivable from AmerGen (1,2,4) $ -- $ 39
Net payable to AmerGen (1,2,4) 22 --
Net receivable from Sithe (3,5,6,7) 1 --
Net payable to Sithe (3,5,6,7) -- 7
Note payable to Sithe (3) 326 534
------------------------------------------------------------------------------------------------------------------
(1) Generation has entered into PPAs dated June 26, 2003, December 18,
2001, and November 22, 1999 with AmerGen. Generation has agreed to
purchase 100% of the energy generated by Oyster Creek through April 9,
2009. Generation has agreed to purchase all the energy from Unit No. 1
at Three Mile Island Nuclear Station from January 1, 2002 through
December 31, 2014. Generation agreed to purchase all of the residual
energy from Clinton not sold to Illinois Power through December 31,
2004. Currently, the residual output is approximately 31% of the total
output of Clinton, but will increase to 100% and the obligation will
continue until the Clinton NRC license expires in 2026. See Note 15 -
Subsequent Events regarding Generation's agreement to purchase British
Energy's interest in AmerGen.
(2) In February 2002, Generation entered into an agreement to loan AmerGen
up to $75 million at an interest rate equal to the one-month London
Interbank Offering Rate plus 2.25%. In July 2002, the limit of the
loan agreement was increased to $100 million and the maturity date was
extended to July 1, 2003. The principal balance of the loan was paid
in full during the second quarter of 2003.
(3) Under the terms of the agreement to acquire Exelon New England dated
November 1, 2002, Generation issued a $534 million note due on June
18, 2003 to Sithe. In June 2003, the principal of the note was
increased $2 million, and the payment terms of the note were changed.
Generation paid $210 million of principal in June 2003, $236 million
of the principal is to be paid by December 1, 2003 or upon change of
control of Generation, and the balance of the note is to be paid by
December 1, 2004 or upon change of control of Generation. The note
bears interest at the rate equal to LIBOR plus 0.875%. Interest
accrued on the note as of September 30, 2003 was less than $1 million.
(4) Under a service agreement dated March 1, 1999, Generation provides
certain operation and support services to the nuclear facilities owned
by AmerGen. This service agreement has an indefinite term and may be
terminated by Generation or AmerGen with 90 days notice. Generation is
compensated for these services at cost.
(5) Under a service agreement dated December 18, 2000, Generation provides
engineering and environmental services for fossil facilities owned by
Sithe and for certain developmental projects. Generation is
compensated for these services at cost.
(6) Under a service agreement dated December 18, 2000, Sithe provides
Generation fuel and project development services. Sithe is compensated
for these services at cost.
(7) Under a service agreement dated November 1, 2002, Sithe provides
Generation certain transition services related to the transition of
the Exelon New England asset acquisition, which occurred November
2002.
67
Generation
In addition to the transactions described above, Generation's
financial statements reflect a number of related-party transactions as
reflected in the tables below.
Three Months Ended September 30, Nine Months Ended September 30,
-------------------------------- -------------------------------
2003 2002 2003 2002
------------------------------------------------------------------------------------------------------------------
Operating revenues from affiliates
ComEd (1) $ 885 $ 949 $ 1,984 $ 2,029
PECO (1) 421 441 1,101 1,090
Exelon Energy Company (2) 51 73 161 190
Purchased power from affiliates
ComEd (4) 11 -- 31 13
PECO (4) -- -- -- 1
Exelon Energy Company (4) -- 6 9 13
Operating & maintenance from affiliates
ComEd (4) 5 4 11 11
PECO (4) 3 3 8 8
BSC (6) 46 33 117 117
Interest expense - affiliate
Exelon intercompany money pool (8) 1 -- 2 --
Exelon (3) -- 1 2 3
Cash distribution paid to member 71 30 116 30
------------------------------------------------------------------------------------------------------------------
September 30, 2003 December 31, 2002
------------------------------------------------------------------------------------------------------------------
Receivables from affiliates (current)
ComEd (1) $ 162 $ 339
ComEd decommissioning receivable (7) 11 59
PECO (1) 123 124
BSC (6) -- 14
Exelon Energy Company (2) 16 19
Other 1 --
Receivables from affiliates (noncurrent)
ComEd decommissioning receivable (7) 33 218
PECO decommissioning receivable (5) 7 --
Other -- 2
Payables to affiliates (current)
Exelon (3) 2 3
BSC (6) 43 --
Payable to affiliate (noncurrent)
ComEd decommissioning (5) 1,144 --
Notes payable to affiliate - Exelon (3) 4 329
Notes payable to affiliates - Exelon intercompany money pool (8) 147 --
------------------------------------------------------------------------------------------------------------------
(1) Effective January 1, 2001, Generation entered into PPAs with ComEd and
PECO. See Note 9 - Commitments and Contingencies for further
information on the PPAs. In 2002, Generation recorded transmission
expense to ComEd of $18 million and $17 million in the three and nine
months, respectively, as a reduction of revenue.
(2) Generation sells power to Exelon Energy Company (an Enterprises
company).
(3) Generation has a payable to Exelon related to certain compensation
plans.
68
(4) Generation purchases power from PECO for Generation's own use, buys
back excess power from Exelon Energy Company and purchases
transmission and ancillary services from ComEd and PECO. In 2002,
Generation recorded transmission expense to ComEd of $18 million and
$17 million in the three and nine months, respectively, as a reduction
of revenue.
(5) Generation has a long-term payable to ComEd and a long-term receivable
from PECO as a result of the adoption of SFAS No. 143. See Note 2 -
New Accounting Principles and Accounting Changes for further
discussion of the adoption of SFAS No. 143.
(6) Generation receives a variety of corporate support services from BSC,
including legal, human resource, financial, information technology,
supply management and corporate governance services. Such services are
provided at cost, including applicable overhead. Some third-party
reimbursements due Generation are recovered through BSC.
(7) Generation has a short-term and had a long-term receivable from ComEd,
primarily representing ComEd's legal requirements to remit collections
of nuclear decommissioning costs from customers to Generation
resulting from the 2001 corporate restructuring.
(8) Generation participates in Exelon's intercompany money pool.
Generation pays interest on its borrowings from the money pool at a
market rate of interest.
14. SUPPLEMENTAL FINANCIAL INFORMATION (Exelon, ComEd and PECO)
September 30, December 31,
ComEd 2003 2002
------------------------------------------------------------------------------------------------------------------
Regulatory Assets (Liabilities)
Nuclear decommissioning
(see Note 2 - New Accounting Principles and Accounting Changes) $ (1,144) $ --
Nuclear decommissioning costs for retired plants -- 248
Recoverable transition costs 141 175
Reacquired debt costs and interest rate swap settlements 163 84
Recoverable deferred income taxes (64) (68)
Other 24 8
------------------------------------------------------------------------------------------------------------------
Total $ (880) $ 447
==================================================================================================================
September 30, December 31,
PECO 2003 2002
------------------------------------------------------------------------------------------------------------------
Regulatory Assets
Competitive transition charge $ 4,381 $ 4,639
Recoverable deferred income taxes 752 729
Non-pension postretirement benefits 60 64
Reacquired debt costs 49 53
Nuclear decommissioning and decontamination funds 27 32
Nuclear decommissioning
(see Note 2 - New Accounting Principles and Accounting Changes) 7 --
MGP regulatory asset (see Note 9 - Commitments and Contingencies) 16 20
Compensated absences 9 6
Postemployment benefits 3 3
------------------------------------------------------------------------------------------------------------------
Long-term regulatory assets 5,304 5,546
Deferred energy costs (current asset) 64 31
------------------------------------------------------------------------------------------------------------------
Total $ 5,368 $ 5,577
==================================================================================================================
69
Exelon's long-term regulatory assets and liabilities as of
September 30, 2003 were $5,304 million and $880 million, respectively.
Exelon's long-term regulatory assets as of December 31, 2002 were $5,993
million.
ComEd's depreciation, which is included in cost of service for
rate purposes, includes an estimated cost of dismantling and removing plant
from service upon retirement. ComEd has estimated future removal costs
embedded in accumulated depreciation related to rate-regulated plant assets
were approximately $1.2 billion at September 30, 2003 in accordance with
regulatory accounting practice.
PECO has historically incurred removal costs in excess of amounts
recovered in rates. As such, PECO does not have any amounts embedded in
accumulated depreciation as of September 30, 2003.
15. SUBSEQUENT EVENTS (Exelon, ComEd and Generation)
ComEd
On October 7, 2003, ComEd redeemed $150 million of First Mortgage
Bonds, at a redemption price of 103.765% of the principal amount, plus
accrued interest. The bonds, which carried an interest rate of 7.750%, were
refinanced with long-term debt issued on August 25, 2003.
Generation
On October 1, 2003, Generation notified Midwest Generation of its
exercise of certain termination options under the existing Collins
Generation Station and Peaking Unit Purchase Power Agreements, releasing
303 MWs for 2004, the fifth and final year of the contract. With the
exercise of the termination options on the peaking plants in addition to
the exercise of the options on the coal plants in June 2003 (see Note 9 -
Commitments and Contingencies for further information regarding the Coal
Generation PPA), the contract with Midwest Generation is finalized for
2004. Generation will take 1,696 MWs of non-option coal capacity, 687 MWs
of option coal capacity, 1,084 MWs of Collins Station capacity and 392 MWs
of peaking capacity from Midwest Generation in 2004. In total, Generation
has retained 3,859 MWs of capacity under the terms of the three existing
PPAs with Midwest Generation.
On October 2, 2003, Mitsubishi Heavy Industries, LTD (MHI) and
Mitsubishi Heavy Industries of America (MHIA) filed a New York state court
action against Exelon Mystic Development, LLC (Mystic) and Exelon Fore
River Development, LLC (Fore River) seeking to enjoin these indirect
subsidiaries of Generation from drawing upon letters of credit posted to
guarantee MHI's performance under certain gas turbine contracts. MHI and
MHIA also seek $34 million from these entities in connection with work
performed on these contracts. Generation believes that Mystic and Fore
River's contracts with MHI and MHIA have been assigned to Raytheon and that
the claims against the Generation entities are without merit.
On October 10, 2003, Exelon executed an agreement to purchase
British Energy's 50% interest in AmerGen for $276.5 million. The
transaction is expected to close in the first half of 2004. The purchase
70
price matched the offer by FPL Energy, which announced on September 11,
2003 that it intended to buy British Energy's share of AmerGen. Under the
AmerGen limited liability company operating agreement between Exelon and
British Energy, either party can exercise a right of first refusal by
matching any bona fide third-party offer agreed to by the other member. See
Note 4 - Unconsolidated Investments for additional information regarding
AmerGen.
71
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
(Dollars in millions, unless otherwise noted)
GENERAL
Exelon Corporation (Exelon), a registered public utility holding
company, through its subsidiaries, operates in three business segments:
o Energy Delivery, whose businesses include the regulated sale of
electricity and distribution and transmission services by
Commonwealth Edison Company (ComEd) in northern Illinois and PECO
Energy Company (PECO) in southeastern Pennsylvania and the sale of
natural gas and distribution services by PECO in the Pennsylvania
counties surrounding the City of Philadelphia.
o Generation, consisting of Exelon Generation Company, LLC's
(Generation) owned and contracted for electric generating
facilities, energy marketing operations, and equity interests in
Sithe Energies, Inc. (Sithe) and AmerGen Energy Company, LLC
(AmerGen).
o Enterprises, consisting of Exelon Enterprises Company, LLC's
(Enterprises) competitive retail energy sales, energy and
infrastructure services, communications and other investments
(primarily weighted towards the energy services and retail
services industries).
See Note 7 of the Condensed Combined Notes to Consolidated
Financial Statements for further segment information.
CRITICAL ACCOUNTING ESTIMATES
Management of each of the registrants makes a number of
significant estimates, assumptions and judgments in the preparation of
their financial statements. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations - Critical Accounting
Estimates" in the 2002 Form 10-K for a discussion of the estimates and
judgments necessary in the registrants' accounting for derivative
instruments, regulatory assets and liabilities, nuclear decommissioning,
asset impairments, defined benefit pension and other postretirement welfare
benefits, stock-based compensation plans, business combinations, unbilled
energy revenues, long-term contract accounting and environmental costs. Set
forth below is an update to the 2002 Form 10-K.
Asset Impairments (Exelon, ComEd, PECO and Generation)
Exelon evaluates the carrying value of long-lived assets,
excluding goodwill, when circumstances indicate the carrying value of those
assets may not be recoverable. The review of assets for impairment requires
significant assumptions about operating strategies and estimates of future
cash flows. A variation in an assumption could result in a different
conclusion regarding the realizability of the asset. The potential impact
of recognizing an impairment on the
72
assets reported within the Consolidated Balance Sheets, as well as on net
income, could be and has been material to the consolidated financial
statements.
During the second quarter of 2003, Exelon recorded an impairment
charge related to investments held by Enterprises of approximately $35
million (before income taxes). Management determined that an
other-than-temporary decline in the fair value of these investments had
occurred and considered various factors in the decision to record an
impairment of the investments, including recent third-party valuations of
the investments. The other-than-temporary determination was significant
because any increase in fair value of these investments will not be
recoverable until they are sold. Had management determined otherwise, no
impairment charge would have been recorded. The valuations of these
investments, which form the basis for the impairment charge, required
assumptions regarding the future earnings potential of these investments.
Actual results from these investments have fluctuated in the past and are
expected to continue.
During the first and third quarters of 2003, Generation recorded
impairment charges totaling $255 million (before income taxes) associated
with a decline in the fair value of its investment in Sithe. In reaching
that decision, management considered various factors, including
negotiations to sell its investment in Sithe, which indicated an
other-than-temporary decline in fair value. The charges included estimates
of potential guarantees under FASB Interpretation (FIN) No. 45,
"Guarantor's Accounting and Disclosure Requirements for Guarantees,
Including Indirect Guarantees of Indebtedness to Others" (FIN No. 45)
associated with the sale of the investment, which are subject to change.
During the third quarter of 2003, Generation recorded an
impairment charge related to the long-lived assets of Exelon Boston
Generating, LLC (EBG), an indirect subsidiary of Generation, of $945
million (before income taxes) due to its decision to transition out of the
ownership of EBG. See Note 3 of the Condensed Combined Notes to
Consolidated Financial Statements for further information. In determining
the amount of the impairment charge, management compared the carrying value
of EBG's long-lived assets to their estimated fair value. The fair value
was determined using the estimated future discounted cash flows from those
assets. Forecasted cash flows incorporated assumptions relative to the
period of time that Generation will continue to own and operate EBG. The
time required to fully transition out of ownership of EBG is uncertain and
subject to change. Exelon used a probability-weighted approach for
developing estimates of future cash flows with the most likely scenarios
weighted higher. A change in Exelon's probability assessment for each
scenario could have a significant impact on the estimated future cash
flows. Exelon utilized a discount rate based upon valuations of the
business developed at the purchase date.
Goodwill (Exelon, ComEd)
ComEd had approximately $4.7 billion of goodwill recorded at
September 30, 2003. The goodwill will remain at its recorded amount unless
it is determined to be impaired, which is based upon an analysis of
expected future cash flows. Exelon and ComEd perform an assessment for
impairment of their goodwill at least annually, or more frequently, if
events or circumstances indicate that goodwill might be impaired. The
annual goodwill impairment assessment will be performed in the fourth
quarter of 2003. Discounted cash flow models will
73
be used to determine the fair value of the Reporting Units in the annual
assessment. The discounted cash flow models include significant assumptions
regarding revenue growth rates, general expense escalation rates, impacts
of The Exelon Way, allowed return on equity and a risk-adjusted discount
rate. These assumptions are subject to change from period to period.
If an impairment is determined at ComEd, the amount of the
impaired goodwill will be written-off and expensed at ComEd. Under current
regulations, a significant goodwill impairment may restrict ComEd's ability
to pay dividends. ComEd is pursuing various solutions to address ComEd's
ability to pay dividends if a significant goodwill impairment exists. Based
upon Illinois legislation, goodwill impairments are excluded from
determining whether or not the earnings cap amount has been met or exceeded.
A goodwill impairment charge at ComEd may not affect Exelon's results of
operations. Exelon's goodwill impairment test would include assessing the
cash flows of the entire Energy Delivery business segment (a single
Reporting Unit, which includes PECO, as defined under current accounting
guidance), not just ComEd's cash flows.
In connection with an agreement to sell certain businesses of
InfraSource, Inc. (InfraSource), Exelon recorded an impairment charge
during the second quarter of 2003 of approximately $48 million (before
minority interest and income taxes) related to the goodwill recorded within
the InfraSource Reporting Unit. Management of Enterprises primarily
considered the negotiated sales price of InfraSource in determining the
amount of the goodwill impairment charge. This charge was partially offset
by a gain recorded during the third quarter of 2003 upon the closing of the
sale.
Severance Accounting (Exelon, ComEd, PECO and Generation)
As part of the implementation of The Exelon Way, Exelon has
identified 1,042 positions for elimination by the end of 2004 and
anticipates identifying additional positions for elimination in 2005 and
2006. Exelon will provide severance benefits to terminated employees
pursuant to pre-existing severance plans primarily based upon each
individual employee's years of service with Exelon and compensation level.
The registrants have recorded charges in the third quarter of 2003 related
to severance benefits that are considered probable and can be reasonably
estimated in accordance with Financial Accounting Standards Board (FASB)
Statement of Financial Accounting Standards (SFAS) No. 112, "Employer's
Accounting for Postemployment Benefits, an amendment of FASB Statements No.
5 and 43" (SFAS No. 112). A significant assumption in calculating the
severance charge was the determination of the number of positions to be
eliminated. The registrants based their estimates on management's current
plans and its ability to determine the appropriate staffing levels to
effectively operate the businesses. Exelon anticipates incurring further
costs associated with The Exelon Way upon identifying additional positions
to be eliminated. These costs will be recorded in the period in which the
costs can be reasonably estimated.
Defined Benefit Pension and Other Postretirement Welfare Benefits (Exelon,
ComEd, PECO and Generation)
During the third quarter of 2003, Exelon announced a benefit plan
amendment that reduced the benefits attributable to prior service through
increased retiree cost-sharing for medical coverage. Furthermore, in
connection with the implementation of The Exelon Way
74
during the third quarter of 2003, the overall reduction in active employees
triggered a curtailment charge related to certain defined benefit pension
and postretirement welfare benefit plans. Curtailment accounting applies
when an event occurs that significantly reduces the expected years of
future service of active plan participants. The expected reduction in plan
participants ranged between five and ten percent of the total eligible
participants of each plan that qualified for curtailment accounting. The
plan amendment and curtailments resulted in remeasurements of the plan
obligations as of August 1, 2003. The total increase in net periodic
benefit costs due to the curtailments recorded during the third quarter of
2003 was $26 million. Pension and postretirement costs are anticipated to
total $234 million in 2003, including the effects of the amendment and
curtailments, compared to $111 million in 2002.
The selection of key actuarial assumptions utilized in the
measurement of the plan obligations drives the results of the analysis and
the resulting charges. The long-term expected rate of return on plan assets
(EROA) assumption used in calculating pension cost was 9.00% at August 1,
2003 compared to 9.50% at December 31, 2002. The EROA assumption used in
calculating the other postretirement benefit obligation ranged from 7.52%
to 8.68% at August 1, 2003 compared to 8.80% at December 31, 2002. A lower
EROA is used in the calculation of other postretirement benefit costs as
the other postretirement benefit trust activity is partially taxable while
the pension trust activity is non-taxable. The Moody's Aa Corporate Bond
Index was used as a basis in selecting the discount rate, using 6.60% at
August 1, 2003 compared to 6.75% at December 31, 2002 in the estimate of
pension expense and other postretirement benefit costs. The reduction in
discount rate is due to the decline in Moody's Aa Corporate Bond Index
during 2003.
Real Estate Tax Assessments (Exelon, PECO and Generation)
PECO and Generation are challenging real estate taxes assessed on
nuclear plants since 1997. PECO is involved in litigation in which it is
contesting Pennsylvania Public Utility Realty Tax Act of March 4, 1971, as
amended (PURTA) taxes assessed in 1997 and has appealed local real estate
assessments for 1998 and 1999 on its formerly owned Limerick Generating
Station (Montgomery County, PA) (Limerick) and Peach Bottom Atomic Power
Station (York County, PA) (Peach Bottom) plants. Generation is involved in
real estate tax appeals for 2000 through 2003, also regarding the valuation
of its Limerick and Peach Bottom plants, its Quad Cities Station (Rock
Island County, IL) and, through its ownership interest in AmerGen, Three
Mile Island (Dauphin County, PA).
During the third quarter of 2003, upon completion of updated
nuclear plant appraisal studies, PECO and Generation recorded reductions of
$58 million and $15 million, respectively, to reserves recorded for
exposures associated with the real estate taxes. While PECO and Generation
believe the resulting reserve balances as of September 30, 2003 reflect the
most likely probable expected outcome of the litigation and appeals
proceedings in accordance with SFAS No. 5, "Accounting for Contingencies,"
the ultimate outcome of such matters could result in additional unfavorable
or favorable adjustments to the consolidated financial statements of PECO
or Generation, and such adjustments could be material.
75
Nuclear Decommissioning (Exelon and Generation)
Generation adopted SFAS No. 143, "Asset Retirement Obligations"
(SFAS No. 143) on January 1, 2003. SFAS No. 143 primarily affected the
accounting for the decommissioning of Generation's nuclear generating
plants and changed the method used to report the decommissioning
obligation. Exelon and Generation recorded income of $112 million and $108
million (net of income taxes), respectively, as a cumulative effect of a
change in accounting principle in connection with their adoptions of this
standard in the first quarter of 2003.
To estimate the fair value of the decommissioning obligation,
management used a probability-weighted, discounted cash flow model with
multiple scenarios. Key assumptions used in the determination of fair value
included decommissioning cost studies prepared by a third party, annual
cost escalation studies to determine escalation factors based on inflation
indices, and the assignment of probabilities to various cost levels and
various timing scenarios. These timing scenarios incorporated current
license lives and life extensions and the timing of Department of Energy
(DOE) acceptance for disposal of spent nuclear fuel. The estimated
probability-weighted cash flows using these various scenarios were
discounted using credit-adjusted, risk-free rates applicable to the various
businesses. Significant changes in the assumptions underlying the items
discussed above could materially affect the balance sheet amounts and
future costs related to decommissioning recorded in the consolidated
financial statements. Under SFAS No. 143, the fair value of the nuclear
decommissioning obligation will continue to be adjusted on an ongoing basis
as the model input factors change.
NEW ACCOUNTING PRONOUNCEMENTS
See Note 2 of the Condensed Combined Notes to Consolidated
Financial Statements for discussion of new accounting pronouncements.
EXELON CORPORATION
------------------
RESULTS OF OPERATIONS
Three Months Ended September 30, 2003 Compared To Three Months Ended
September 30, 2002
Net Income and Earnings Per Share
Exelon's net loss for the three months ended September 30, 2003
was $102 million compared to net income of $551 million in 2002. Loss per
diluted common share for the three months ended September 30, 2003 was
$0.31 compared to income per diluted share of $1.70 in 2002. The overall
decrease in income of $653 million resulted from charges recorded in 2003
associated with the impairment of the long-lived assets of EBG, severance
and related postretirement health and welfare benefits accruals and pension
and postretirement curtailment costs associated with The Exelon Way, and a
decline in the fair value of Generation's investment in Sithe. These
charges were partially offset by the reduction of property tax reserves at
PECO and Generation and a gain recognized at Enterprises due to the sale of
InfraSource during 2003.
76
Results of Operations by Business Segment
Exelon evaluates its performance on a business segment basis. The
comparisons presented under this heading are comparisons of operating
results and other statistical information for the three months ended
September 30, 2003 to operating results and other statistical information
for the same period in 2002. These results reflect intercompany
transactions, which are eliminated in Exelon's consolidated financial
statements.
Exelon corporate operations provide the business segments a
variety of support services including legal, human resources, financial,
information technology, supply management and corporate governance
services. These costs are allocated to the business segments. Additionally,
the results of Exelon's corporate operations include costs for strategic
long-term planning, certain governmental affairs, and interest costs and
income from various investment and financing activities.
Net Income (Loss) by Business Segment
Three Months Ended September 30,
--------------------------------
2003 2002 Variance % Change
-------------------------------------------------------------------------------------------------------------------
Energy Delivery $ 303 $ 370 $ (67) (18.1%)
Generation (428) 163 (591) n.m.
Enterprises 16 15 1 6.7%
Corporate 7 3 4 133.3%
-------------------------------------------------------------------------------------------------
Total $ (102) $ 551 $ (653) (118.5%)
=================================================================================================
n.m. - not meaningful
Results of Operations - Energy Delivery
Three Months Ended September 30,
--------------------------------
Energy Delivery 2003 2002 Variance % Change
-------------------------------------------------------------------------------------------------------------------
Operating revenues $ 2,886 $ 3,162 $ (276) (8.7%)
Revenue, net of purchased power & fuel expense 1,485 1,637 (152) (9.3%)
Operating income 664 812 (148) (18.2%)
Income before income taxes 479 591 (112) (19.0%)
Net income 303 370 (67) (18.1%)
-------------------------------------------------------------------------------------------------------------------
The changes in Energy Delivery's revenue, net of purchased power
and fuel expense, for the three months ended September 30, 2003 compared to
the same period in 2002, included the following:
o unfavorable weather impacts of $75 million, primarily the result
of cooler summer weather,
o unfavorable variance of $52 million due to changes in customer
rates due to lower competitive transition charge (CTC)
collections at ComEd,
o unfavorable rate mix of $21 million at PECO as a result of
changes in monthly usage patterns by all customer classes,
o unfavorable pricing changes of $20 million related to ComEd's
purchased power agreement (PPA) with Generation,
77
o unfavorable variance of $16 million under the ComEd PPA with
Generation related to decommissioning collections associated with
the adoption of SFAS No. 143 in 2003, which had no impact on net
income as these amounts were recorded in depreciation and
amortization expense in 2002 (see Note 2 of the Condensed
Combined Notes to Consolidated Financial Statements),
o net favorable change of $8 million at ComEd as a result of 2002
third-party energy reconciliations,
o lower PJM ancillary charges at PECO resulting in a favorable
variance of $4 million, and
o net favorable changes due to customer choice of $3 million.
The changes in operating income, other than changes in revenue,
net of purchased power and fuel expense, for the three months ended
September 30, 2003 compared to the same period in 2002, included the
following:
o decreased costs of $67 million associated with PECO's real estate
taxes, including a reduction of reserves for real estate taxes of
$58 million in 2003,
o decreased payroll expense of $22 million due to fewer employees,
o lower amortization of ComEd's recoverable transition costs of $21
million in 2003,
o a 2002 increase in the reserve for manufactured gas plant (MGP)
investigation and remediation of $17 million, net of 2003
increases,
o reduction of amortization expense of $16 million at ComEd for
nuclear decommissioning of retired plants due to the adoption of
SFAS No. 143 (see Note 2 of the Condensed Combined Notes to
Consolidated Financial Statements), which had no impact on net
income as these amounts were recorded as purchased power in 2003,
o decreased costs of $10 million associated with the initial
implementation of automated meter reading services at PECO in
2002,
o unfavorable variance of $101 million due to severance and related
postretirement health and welfare benefits accruals and pension
and postretirement curtailment costs associated with The Exelon
Way,
o unfavorable variance of $30 million due to higher storm-related
costs,
o unfavorable variance of $9 million due to employee fringe
benefits, and
o $8 million in 2003 at ComEd for use tax payments for periods
prior to the merger of Exelon, Unicom Corporation and PECO on
October 20, 2000 (Merger).
The changes in other income and deductions for the three months
ended September 30, 2003 compared to the same period in 2002 included a
reduction in interest expense primarily related to a decrease of $21
million attributable to less outstanding debt and refinancing of existing
debt at lower interest rates and a reduction of $12 million as a result of
a 2002 reserve accrual for a potential plant disallowance from an audit
performed in conjunction with ComEd's delivery services rate case. This $12
million was reversed in March 2003 as a result of the March 3, 2003
agreement. See the Contractual Obligations, Commercial Commitments and
Off-Balance Sheet Obligations section below for further information
regarding the agreement.
Energy Delivery's effective income tax rate was 36.7% for the
three months ended September 30, 2003, compared to 37.4% for the same
period in 2002.
78
Energy Delivery Operating Statistics and Revenue Detail
Energy Delivery's electric sales statistics and revenue detail
were as follows:
Three Months Ended September 30,
--------------------------------
Retail Deliveries - (in gigawatthours (GWhs))(1) 2003 2002 Variance % Change
-------------------------------------------------------------------------------------------------------------------
Bundled Deliveries (2)
Residential 11,530 12,543 (1,013) (8.1%)
Small Commercial & Industrial 7,502 8,095 (593) (7.3%)
Large Commercial & Industrial 5,552 6,079 (527) (8.7%)
Public Authorities & Electric Railroads 1,486 1,836 (350) (19.1%)
-----------------------------------------------------------------------------------------------------
Total Bundled Deliveries 26,070 28,553 (2,483) (8.7%)
-----------------------------------------------------------------------------------------------------
Unbundled Deliveries (3)
Alternative Energy Suppliers
----------------------------
Residential 258 371 (113) (30.5%)
Small Commercial & Industrial 2,241 1,794 447 24.9%
Large Commercial & Industrial 3,142 2,428 714 29.4%
Public Authorities & Electric Railroads 426 299 127 42.5%
-----------------------------------------------------------------------------------------------------
6,067 4,892 1,175 24.0%
-----------------------------------------------------------------------------------------------------
PPO (ComEd Only)
----------------
Small Commercial & Industrial 884 782 102 13.0%
Large Commercial & Industrial 896 1,249 (353) (28.3%)
Public Authorities & Electric Railroads 428 345 83 24.1%
-----------------------------------------------------------------------------------------------------
2,208 2,376 (168) (7.1%)
-----------------------------------------------------------------------------------------------------
Total Unbundled Deliveries 8,275 7,268 1,007 13.9%
-----------------------------------------------------------------------------------------------------
Total Retail Deliveries 34,345 35,821 (1,476) (4.1%)
=====================================================================================================
(1) One GWh is the equivalent of one million kilowatthours (kWh).
(2) Bundled service reflects deliveries to customers taking electric
generation service under tariffed rates.
(3) Unbundled service reflects customers electing to receive electric
generation service from an alternative energy supplier or ComEd's Power
Purchase Option (PPO).
79
Three Months Ended September 30,
--------------------------------
Electric Revenue 2003 2002 Variance % Change
-------------------------------------------------------------------------------------------------------------------
Bundled Revenues (1)
Residential $ 1,226 $ 1,318 $ (92) (7.0%)
Small Commercial & Industrial 698 757 (59) (7.8%)
Large Commercial & Industrial 373 402 (29) (7.2%)
Public Authorities & Electric Railroads 102 125 (23) (18.4%)
-----------------------------------------------------------------------------------------------------
Total Bundled Revenues 2,399 2,602 (203) (7.8%)
-----------------------------------------------------------------------------------------------------
Unbundled Revenues (2)
Alternative Energy Suppliers
----------------------------
Residential 20 32 (12) (37.5%)
Small Commercial & Industrial 62 60 2 3.3%
Large Commercial & Industrial 46 67 (21) (31.3%)
Public Authorities & Electric Railroads 8 10 (2) (20.0%)
-----------------------------------------------------------------------------------------------------
136 169 (33) (19.5%)
-----------------------------------------------------------------------------------------------------
PPO (ComEd Only)
----------------
Small Commercial & Industrial 65 57 8 14.0%
Large Commercial & Industrial 56 74 (18) (24.3%)
Public Authorities & Electric Railroads 26 19 7 36.8%
-----------------------------------------------------------------------------------------------------
147 150 (3) (2.0%)
-----------------------------------------------------------------------------------------------------
Total Unbundled Revenues 283 319 (36) (11.3%)
-----------------------------------------------------------------------------------------------------
Total Electric Retail Revenues 2,682 2,921 (239) (8.2%)
-----------------------------------------------------------------------------------------------------
Wholesale and Miscellaneous Revenue (3) 151 174 (23) (13.2%)
-----------------------------------------------------------------------------------------------------
Total Electric Revenue $ 2,833 $ 3,095 $ (262) (8.5%)
=====================================================================================================
(1) Bundled revenue reflects deliveries to customers taking electric
service under tariffed rates, which include the cost of energy and the
delivery cost of the transmission and the distribution of the energy.
PECO's tariffed rates also include a competitive transition charge.
(2) Unbundled revenue reflects revenue from customers electing to receive
electric generation service from an alternative energy supplier or
ComEd's PPO. Revenue from customers choosing an alternative energy
supplier includes a distribution charge and a CTC. Revenue from
customers choosing ComEd's PPO includes an energy charge at market
rates, transmission and distribution charges and a CTC. Transmission
charges received from alternative energy suppliers are included in
wholesale and miscellaneous revenue.
(3) Wholesale and miscellaneous revenues include transmission revenue,
sales to municipalities and other wholesale energy sales.
The differences in electric retail revenues for the three months
ended September 30, 2003 as compared to the same period in 2002 were
attributable to the following:
Variance
--------------------------------------------------------------------------
Weather $ (161)
Rate changes (52)
Customer choice (50)
Rate mix (21)
Volume 41
Other effects 4
--------------------------------------------------------------------------
Electric retail revenue $ (239)
==========================================================================
o Weather. The demand for electricity is impacted by weather conditions.
Very warm weather in summer months and very cold weather in other
months are referred to as "favorable weather conditions" because these
weather conditions result in increased sales of electricity.
Conversely, mild weather reduces demand. The weather impact for the
three months ended September 30, 2003 was unfavorable compared to the
same period in 2002 as a result of
80
cooler summer weather in 2003. Cooling degree-days in the ComEd and
PECO service territories were 25% lower and 11% lower, respectively,
in 2003 as compared to 2002.
o Rate Changes. The decrease in revenues attributable to rate changes
reflects decreased collections of $81 million in CTCs in 2003 by ComEd
due to a decrease in CTC rates effective June 1, 2003, partially
offset by higher wholesale market prices which increased energy
revenue received under ComEd's PPO by $29 million.
o Customer Choice. All ComEd and PECO customers have the choice to
purchase energy from alternative suppliers. This affects revenues from
the sale of energy but not revenue from the delivery of electricity
since ComEd and PECO continue to deliver electricity that is purchased
from alternative suppliers. For the three months ended September 30,
2003 and 2002, 18% and 14%, respectively, of energy delivered to
Energy Delivery's customers was provided by alternative electric
suppliers. The decrease in electric retail revenues includes a
decrease in revenues of $36 million from customers in Illinois
electing to purchase energy from an alternative retail electric
supplier (ARES) or ComEd's PPO, and a decrease in revenues of $14
million from customers in Pennsylvania selecting an alternative
electric generation supplier.
The Pennsylvania Utility Commission's (PUC) Final Electric
Restructuring Order established market share thresholds (MST) to
promote competition. The MST requirements provide that if, as of
January 1, 2003, less than 50% of residential and commercial customers
have chosen an alternative electric generation supplier, the number of
customers sufficient to meet the MST shall be randomly selected and
assigned to an alternative electric generation supplier through a PUC
determined process. On January 1, 2003, the number of customers
choosing an alternative electric generation supplier did not meet the
MST. In January 2003, PECO submitted to the PUC an MST plan to meet
the 50% threshold requirement for its commercial customers, which was
approved by the PUC in February 2003. As of March 31, 2003, an auction
had been completed for the commercial customers. In May 2003, the
customer enrollment phase was completed, and customers that did not
choose to opt out of the program were transferred to the alternative
electric generation suppliers. In February 2003, PECO filed a
residential customer MST plan, and on May 1, 2003, the PUC approved
the plan. The approved plan provides for a two-step process with a
total of up to 400,000 residential customers being assigned to winning
alternative electric generation supplier bidders: up to 100,000 in
July 2003 and another 300,000 in December 2003. The auction for the
first phase of the residential program received no supplier bids.
Therefore, according to the MST plan requirements, 75% of those
customers are required to be added to the auction for the second phase
of the residential program for a total of 375,000 customers. In
September 2003, the auction for the second phase of the residential
customer MST plan resulted in two winning bidders who were awarded an
aggregate of 267,000 customers. The selected customers will be
transferred during December 2003. No renewable bids were received for
any customers. Any customer transferred has the right to return to
PECO at any time. PECO does not expect the transfer of customers
pursuant to the MST plan to have a material impact on its results of
operations, financial position or cash flows.
o Rate Mix. Revenues related to changes in rate mix at PECO decreased
$21 million due to changes in monthly usage patterns in all customer
classes for the three months ended September 30, 2003 as compared to
the same period in 2002.
81
o Volume. Revenues from higher delivery sales, exclusive of the effect
of weather, increased $40 million at ComEd due to an increased number
of customers and increased usage per customer, primarily residential
and small commercial and industrial. Revenues from delivery sales,
exclusive of the effect of weather, increased $1 million at PECO.
Energy Delivery's gas sales statistics and revenue detail were as
follows:
Three Months Ended September 30,
--------------------------------
Deliveries to customers in million cubic feet (mmcf) 2003 2002 Variance % Change
-------------------------------------------------------------------------------------------------------------------
Retail sales 3,498 3,805 (307) (8.1%)
Transportation 6,012 7,542 (1,530) (20.3%)
-----------------------------------------------------------------------------------------------------
Total 9,510 11,347 (1,837) (16.2%)
=====================================================================================================
Three Months Ended September 30,
--------------------------------
Revenue 2003 2002 Variance % Change
-------------------------------------------------------------------------------------------------------------------
Retail sales $ 47 $ 43 $ 4 9.3%
Transportation 4 5 (1) (20.0%)
Resales and other 2 19 (17) (89.5%)
-----------------------------------------------------------------------------------------------------
Total $ 53 $ 67 $ (14) (20.9%)
=====================================================================================================
The changes in gas retail revenue for the three months ended
September 30, 2003 as compared to the same period in 2002, were as follows:
Variance
-------------------------------------------------------------------------------------------------------------------
Rate changes $ 6
Volume (2)
-------------------------------------------------------------------------------------------------------------------
Total gas retail revenues $ 4
===================================================================================================================
o Rate Changes. The favorable variance in rate changes is attributable
to increases of 15% and 7% in the purchased gas adjustment by the PUC
effective March 1, 2003 and June 1, 2003, respectively. The average
rate per million cubic feet for the three months ended September 30,
2003 was 18% higher than the same period in 2002. PECO's gas rates are
subject to periodic adjustments by the PUC and are designed to recover
from or refund to customers the difference between the actual cost of
purchased gas and the amount included in base rates and to recover or
refund increases or decreases in certain state taxes not recovered in
base rates.
o Volume. Delivery volume was lower in the three months ended September
30, 2003 compared to the same period in 2002 due to decreased retail
sales in all customer classes.
The reduction in transportation volumes and revenues was primarily
the result of lower intercompany deliveries to Generation during the three
months ended September 30, 2003 compared to the same period in 2002.
82
Lower resale revenues are attributable to a decrease in off-system
sales, exchanges and capacity releases during the three months ended
September 30, 2003 compared to the same period in 2002.
Results of Operations - Generation
Three Months Ended September 30,
--------------------------------
2003 2002 Variance % Change
-------------------------------------------------------------------------------------------------------------------
Operating revenues $ 2,537 $ 2,213 $ 324 14.6%
Revenue, net of purchased power & fuel expense 848 683 165 24.2%
Operating income (loss) (706) 187 (893) n.m.
Income (loss) before income taxes (708) 265 (973) n.m.
Net income (loss) (428) 163 (591) n.m.
-------------------------------------------------------------------------------------------------------------------
n.m. - not meaningful
The changes in Generation's revenue, net of purchased power and
fuel expense, for the three months ended September 30, 2003 compared to the
same period in 2002, included the following:
o increased market sales of electricity of $167 million primarily
attributable to regional demand and higher prices, and reduced
capacity payments as a result of releasing Midwest Generation options,
o unfavorable weather conditions in the ComEd and PECO service
territories in 2003 resulted in a net volume decrease, partially
offset by price increases, resulting in a $121 million unfavorable
variance on revenues from Energy Delivery,
o increased decommissioning revenue from ComEd of $16 million associated
with the adoption of SFAS No. 143, which was effective January 1,
2003,
o mark-to-market losses on hedging activities of $18 million in 2003
compared to no gains or losses in 2002, and
o increases of $13 million as a result of reduced proprietary trading
activity and overall trade portfolio performance.
Other significant factors affecting the changes in revenue, net of
purchased power and fuel, include the impacts of the plants acquired during
2002 resulting in a net favorable variance of $60 million. In addition, the
impacts of lower volumes of purchased power, which were partially offset by
higher fuel costs, resulted in a net favorable impact of $49 million.
The changes in operating income (loss), other than changes in
revenue, net of purchased power and fuel expense, for the three months
ended September 30, 2003 compared to the same period in 2002, included the
following:
o impairment charge of $945 million related to the long-lived assets of
EBG,
o $46 million in severance and related postretirement health and welfare
benefits accruals and pension and postretirement curtailment costs
associated with The Exelon Way,
o higher costs of $15 million for employee medical, pension and other
employee payroll and benefit costs in 2003,
o increased operating and maintenance (O&M) costs of $30 million due to
the acquisition of Exelon New England in the fourth quarter of 2002,
83
o reduced refueling outage costs of $9 million, resulting from fewer
total refueling outage days in 2003,
o additional depreciation of $17 million due to capital additions placed
in service and plant acquisitions made after the third quarter of
2002,
o accretion expense of $60 million recognized in 2003 to increase the
asset retirement obligation established at the adoption of SFAS No.
143, and to adjust the earnings impact of certain of the nuclear
decommissioning revenues earned from ComEd and PECO, nuclear
decommissioning trust fund investment income, income taxes incurred on
nuclear decommissioning trust fund activities, partially offset by the
elimination of decommissioning expense of $29 million, also as a
result of the adoption of SFAS No. 143 (see Note 2 of the Condensed
Combined Notes to Consolidated Financial Statements for further
discussion of SFAS No. 143), and
o decreased property taxes of $15 million as a result of reductions in
reserves in the third quarter of 2003 recorded for exposures
associated with real estate taxes.
The changes in other income and deductions for the three months
ended September 30, 2003 compared to the same period in 2002, included the
following:
o impairment charge of $55 million related to Generation's investment in
Sithe,
o increased decommissioning trust investment income of $9 million, which
is almost entirely offset by accretion expense, net of depreciation,
recorded in O&M, and
o decreased equity in earnings of unconsolidated affiliates of $34
million due to the purchase of Exelon New England in November 2002,
the negative impacts of power trading activity at Sithe and reduced
earnings from AmerGen.
Generation's effective income tax rate was 39.5% for the three
months ended September 30, 2003 compared to 38.5% for the same period in
2002. This increase was primarily attributable to the impact of changes in
income before income taxes as a result of the impairment charges recorded
in the third quarter of 2003 related to Generation's investment in Sithe
and the long-lived assets of EBG.
84
Generation Operating Statistics
Generation's sales and the supply of these sales, excluding the
trading portfolio, were as follows:
Three Months Ended September 30,
--------------------------------
Sales (in GWhs) 2003 2002 Variance % Change
-------------------------------------------------------------------------------------------------------------------
Energy Delivery and Exelon Energy Company 32,237 35,996 (3,759) (10.4%)
Market Sales 29,613 21,177 8,436 39.8%
-----------------------------------------------------------------------------------------------------
Total Sales 61,850 57,173 4,677 8.2%
=====================================================================================================
Three Months Ended September 30,
--------------------------------
Supply of Sales (in GWhs) 2003 2002 Variance % Change
-------------------------------------------------------------------------------------------------------------------
Nuclear Generation (1) 30,152 29,817 335 1.1%
Purchases - non-trading portfolio (2) 24,062 23,425 637 2.7%
Fossil and Hydro Generation 7,636 3,931 3,705 94.3%
-----------------------------------------------------------------------------------------------------
Total Supply 61,850 57,173 4,677 8.2%
=====================================================================================================
(1) Excluding AmerGen.
(2) Including PPAs with AmerGen.
Trading volumes of 11,086 GWhs and 28,455 GWhs for the three
months ended September 30, 2003 and 2002, respectively, are not included in
the table above. The decrease in trading volume is a result of reduced
volumetric and Value-at-Risk (VaR) trading limits in 2003, which are set by
Exelon's Risk Management Committee and approved by the Board of Directors.
Generation's average margin and other operating data for the three
months ended September 30, 2003 and 2002 were as follows:
Three Months Ended September 30,
--------------------------------
($/MWh) 2003 2002 % Change
-------------------------------------------------------------------------------------------------------------------
Average Revenue
Energy Delivery and Exelon Energy Company $ 41.51 $ 40.56 2.3%
Market Sales 38.43 35.50 8.3%
Total - excluding the trading portfolio 40.03 38.69 3.5%
Average Supply Cost (1) - excluding the trading portfolio $ 27.31 $ 26.66 2.4%
Average Margin - excluding the trading portfolio $ 12.72 $ 12.04 5.6%
-----------------------------------------------------------------------------------------------------------------
(1) Average supply cost includes purchased power and fuel costs.
(2) Including PPAs with AmerGen.
Three Months Ended September 30,
--------------------------------
2003 2002
-------------------------------------------------------------------------------------------------------------------
Nuclear fleet capacity factor (1) 95.3% 93.9%
Nuclear fleet production cost per MWh (1) $ 11.69 $ 12.40
Average purchased power cost for wholesale operations per MWh (2) $ 51.53 $ 53.75
-------------------------------------------------------------------------------------------------------------------
(1) Including AmerGen and excluding Salem, which is operated by Public
Service Enterprise Group Incorporated (PSE&G).
(2) Including PPAs with AmerGen.
The factors below contributed to the overall increase in
Generation's average margin for the three months ended September 30, 2003
as compared to the same period in 2002.
85
Generation's average revenue per MWh was affected by:
o higher market prices as a result of increased fuel prices, and
o increased weighted average on and off-peak prices per MWh for supply
agreements with ComEd and PECO.
Generation's supply mix changed as a result of:
o increased nuclear generation due to a lower number of refueling and
unplanned outages during 2003 compared to 2002,
o increased fossil generation due to the effect of the Exelon New
England plants acquired in November 2002, which in total account for
an increase of 3,570 GWhs, and
o a new PPA with AmerGen entered into during the second quarter of 2003,
resulting in 1,228 GWhs purchased from Oyster Creek Nuclear Generating
Station (Oyster Creek) in the third quarter of 2003.
Higher nuclear capacity factors and decreased nuclear production
costs are primarily due to 16 fewer planned refueling outage days,
resulting in a $9 million decrease in outage costs, in the three months
ended September 30, 2003 as compared to the same period in 2002. The three
months ended September 30, 2003 included nine unplanned outages compared to
seven unplanned outages during the three months ended September 30, 2002.
Results of Operations - Enterprises
Three Months Ended September 30,
--------------------------------
2003 2002 Variance % Change
-------------------------------------------------------------------------------------------------------------------
Operating revenues $ 437 $ 509 $ (72) (14.1%)
Operating income 24 15 9 60.0%
Income before income taxes 26 20 6 30.0%
Net income 16 15 1 6.7%
-------------------------------------------------------------------------------------------------------------------
The changes in Enterprises' operating income for the three months
ended September 30, 2003 compared to the same period in 2002, included the
following:
o a gain on sale of $44 million, net of transaction costs and before
income taxes, related to the sale of the electric construction and
services, underground and telecom businesses of InfraSource,
o lower operating income at InfraSource of $21 million primarily
resulting from a decrease in the electric business of $26 million and
a decrease in the underground business of $2 million, partially offset
by lower depreciation of $8 million as a result of the classification
of InfraSource's property, plant and equipment as held for sale in the
second quarter of 2003,
o lower operating income at Exelon Services of $2 million, primarily
resulting from reduced construction projects,
o lower operating income at Exelon Energy Company of $4 million
primarily resulting from the reversal of mark-to-market adjustments of
$1 million and additional gas supply costs and business wind-down
costs of $4 million for Northeast operations, partially
86
offset by higher gross margins of $2 million in the Midwest
attributable to increased unit margins and higher volumes, and
o higher allocated O&M costs of $6 million.
The change in other income and deductions for the three months ended
September 30, 2003 compared to the same period in 2002 was primarily due to
lower equity in earnings of unconsolidated affiliates of $9 million
primarily resulting from the recovery of trade receivables in 2002 that
were previously considered uncollectible at a communications joint venture.
The effective income tax rate was 38.5% for the three months ended
September 30, 2003, compared to 25.0% for the same period in 2002. The
increase in the effective tax rate was primarily attributable to a
reduction in estimated state income tax recorded during the three months
ended September 30, 2002.
Nine Months Ended September 30, 2003 and Nine Months Ended September 30,
2002
Net Income and Earnings Per Share
Exelon's net income for the nine months ended September 30, 2003
decreased $412 million or 40%, compared to the same period in 2002. Diluted
earnings per common share on the same basis decreased $1.29 per share. Net
income for the nine months ended September 30, 2003 reflects $112 million
of income for the cumulative effect of a change in accounting principle as
a result of the adoption of SFAS No. 143 while net income for the nine
months ended September 30, 2002 reflects a $230 million charge for the
cumulative effect of a change in accounting principle, reflecting goodwill
impairment upon the adoption of SFAS No. 142, "Goodwill and Other
Intangible Assets" (SFAS No. 142). See Note 2 of the Condensed Combined
Notes to Consolidated Financial Statements for further information
regarding the adoptions of SFAS No. 143 and SFAS No. 142.
Income before cumulative effect of changes in accounting
principles for the nine months ended September 30, 2003 decreased $754
million, or 59%, compared to the same period in 2002. Diluted earnings per
common share on the same basis decreased $2.34 per share. The decrease in
income before cumulative effect of changes in accounting principles reflects
an impairment of the long-lived assets of EBG recorded during the third
quarter of 2003, impairment charges related to Generation's investment in
Sithe recorded in the first and third quarters of 2003 and severance and
related postretirement health and welfare benefits accruals and pension and
post-employment curtailment costs associated with The Exelon Way. These
reductions in income were partially offset by reductions in property tax
reserves at PECO and Generation during the third quarter of 2003, increased
energy margins at Generation due to the acquisition of Exelon New England in
November 2002 and decreased interest expense at Energy Delivery due to
refinancing of outstanding debt at lower interest rates. Additionally, a
gain was recorded in the second quarter of 2002 due to the sale of an
investment in AT&T Wireless held by Enterprises.
87
Results of Operations by Business Segment
The comparisons presented under this heading are comparisons of
operating results and other statistical information for the nine months
ended September 30, 2003 to operating results and other statistical
information for the same period in 2002. These results reflect intercompany
transactions, which are eliminated in Exelon's consolidated financial
statements.
Net Income (Loss) Before Cumulative Effect of Changes in Accounting
Principles by Business Segment
Nine Months Ended September 30,
-------------------------------
2003 2002 Variance % Change
-------------------------------------------------------------------------------------------------------------------
Energy Delivery $ 920 $ 908 $ 12 1.3%
Generation (339) 313 (652) n.m.
Enterprises (62) 69 (131) (189.9%)
Corporate -- (17) 17 (100.0%)
-------------------------------------------------------------------------------------------------
Total $ 519 $ 1,273 $ (754) (59.2%)
=================================================================================================
n.m. - not meaningful
Net Income (Loss) by Business Segment
Nine Months Ended September 30,
-------------------------------
2003 2002 Variance % Change
-------------------------------------------------------------------------------------------------------------------
Energy Delivery $ 925 $ 908 $ 17 1.9%
Generation (231) 326 (557) (170.9%)
Enterprises (63) (174) 111 (63.8%)
Corporate -- (17) 17 (100.0%)
-------------------------------------------------------------------------------------------------
Total $ 631 $ 1,043 $ (412) (39.5%)
=================================================================================================
Results of Operations - Energy Delivery
Nine Months Ended September 30,
-------------------------------
Energy Delivery 2003 2002 Variance % Change
-------------------------------------------------------------------------------------------------------------------
Operating revenues $ 7,850 $ 7,973 $ (123) (1.5%)
Revenue, net of purchased power & fuel expense 4,274 4,414 (140) (3.2%)
Operating income 2,025 2,108 (83) (3.9%)
Income before income taxes and cumulative effect of a
change in accounting principle 1,478 1,455 23 1.6%
Income before cumulative effect of a change in
accounting principle 920 908 12 1.3%
Net income 925 908 17 1.9%
-------------------------------------------------------------------------------------------------------------------
The changes in Energy Delivery's revenue, net of purchased power
and fuel expense, for the nine months ended September 30, 2003 compared to
the same period in 2002, included the following:
o net unfavorable weather impacts of $63 million, primarily the result
of cooler summer weather partially offset by colder winter weather,
o unfavorable pricing changes of $60 million related to ComEd's PPA with
Generation,
o unfavorable variance of $47 million under the ComEd PPA with
Generation related to decommissioning collections associated with the
adoption of SFAS No. 143 in 2003,
88
which had no impact on net income as these amounts were recorded in
depreciation and amortization expense in 2002 (see Note 2 of the
Condensed Combined Notes to Consolidated Financial Statements),
o unfavorable rate mix variance of $28 million at PECO as a result of
changes in monthly usage patterns by all customer classes,
o net unfavorable changes due to customer choice of $25 million,
including ComEd's customers electing to purchase energy from
alternative energy suppliers or electing ComEd's PPO, under which
non-residential customers can purchase power from ComEd at a
market-based rate,
o increases in weather normalized volumes of $32 million as a result of
increases in the number of customers and additional average usage per
customer, primarily residential and small commercial and industrial
customers at ComEd, and small and large commercial and industrial
customers at PECO,
o favorable variance of $23 million due to changes in customer rates due
to additional CTC collections at ComEd, and
o net favorable change of $8 million at ComEd as a result of 2002
third-party energy reconciliations.
The changes in operating income, other than changes in revenue,
net of purchased power and fuel expense, for the nine months ended
September 30, 2003 compared to the same period in 2002, included the
following:
o a decrease in real estate taxes at PECO of $70 million, including a
reduction of $58 million of reserves for real estate taxes in 2003,
o decreased payroll expense of $64 million due to fewer employees,
o reduction in depreciation expense of $48 million due to the impact of
lower depreciation rates at ComEd effective July 1, 2002, partially
offset by increased depreciation expense in 2003 of $24 million due to
higher plant in service balances,
o reduction of amortization expense of $47 million for nuclear
decommissioning of retired plants at ComEd due to the adoption of SFAS
No. 143, which had no impact on net income as these amounts were
recorded as purchased power in 2003 (see Note 2 of the Condensed
Combined Notes to Consolidated Financial Statements),
o lower amortization of ComEd's recoverable transition costs of $41
million in 2003,
o decreased costs of $23 million associated with the initial
implementation of automated meter reading services at PECO in 2002,
o decreased costs of $12 million in the reserve for MGP investigation
and remediation in 2002 net of 2003 increases,
o a reversal of $12 million of accrued use tax at PECO as a result of an
audit settlement,
o unfavorable variance of $101 million due to severance and related
postretirement health and welfare benefits accruals and pension and
postretirement curtailment costs associated with The Exelon Way,
o unfavorable variance of $35 million due to higher storm-related costs,
o a net one-time charge of $41 million in 2003 at ComEd as the result of
an agreement described in Note 5 of Condensed Combined Notes to
Consolidated Financial Statements,
o unfavorable variance of $28 million due to employee fringe benefits,
and
o additional amortization in 2003 of $20 million at PECO related to
PECO's CTC in accordance with the Pennsylvania Competitive Act.
89
The changes in other income and deductions for the nine months
ended September 30, 2003 compared to the same period in 2002, included the
following:
o a reduction in interest expense primarily related to a decrease of $66
million attributable to less outstanding debt and refinancing of
existing debt at lower interest rates, and
o a reduction of $12 million as a result of a 2002 reserve accrual for a
potential plant disallowance from an audit performed in conjunction
with ComEd's delivery services rate case, and the reversal in 2003 of
this reserve as the result of an agreement described in Note 5 of the
Condensed Combined Notes to Consolidated Financial Statements.
Energy Delivery's effective income tax rate was 37.8% for the nine
months ended September 30, 2003, compared to 37.6% for the same period in
2002.
ComEd recorded a gain due to the adoption of SFAS No. 143 as a
cumulative effect of a change in accounting principle of $5 million, net of
income taxes, in the first quarter of 2003. See Note 2 of the Condensed
Combined Notes to Consolidated Financial Statements for further discussion
of these effects.
Energy Delivery Operating Statistics and Revenue Detail
Energy Delivery's electric sales statistics and revenue detail
were as follows:
Nine Months Ended September 30,
-------------------------------
Retail Deliveries - (GWhs) 2003 2002 Variance % Change
-------------------------------------------------------------------------------------------------------------------
Bundled Deliveries (1)
Residential 28,969 28,984 (15) (0.1%)
Small Commercial & Industrial 21,555 22,782 (1,227) (5.4%)
Large Commercial & Industrial 15,896 17,436 (1,540) (8.8%)
Public Authorities & Electric Railroads 4,710 5,715 (1,005) (17.6%)
-----------------------------------------------------------------------------------------------------
Total Bundled Deliveries 71,130 74,917 (3,787) (5.1%)
-----------------------------------------------------------------------------------------------------
Unbundled Deliveries (2)
Alternative Energy Suppliers
----------------------------
Residential 708 1,720 (1,012) (58.8%)
Small Commercial & Industrial 5,371 4,075 1,296 31.8%
Large Commercial & Industrial 7,504 5,551 1,953 35.2%
Public Authorities & Electric Railroads 954 618 336 54.4%
-----------------------------------------------------------------------------------------------------
14,537 11,964 2,573 21.5%
-----------------------------------------------------------------------------------------------------
PPO (ComEd Only)
----------------
Small Commercial & Industrial 2,546 2,384 162 6.8%
Large Commercial & Industrial 3,646 3,952 (306) (7.7%)
Public Authorities & Electric Railroads 1,497 861 636 73.9%
-----------------------------------------------------------------------------------------------------
7,689 7,197 492 6.8%
-----------------------------------------------------------------------------------------------------
Total Unbundled Deliveries 22,226 19,161 3,065 16.0%
-----------------------------------------------------------------------------------------------------
Total Retail Deliveries 93,356 94,078 (722) (0.8%)
=====================================================================================================
(1) Bundled service reflects deliveries to customers taking electric
generation service under tariffed rates.
(2) Unbundled service reflects customers electing to receive electric
generation service from an alternative energy supplier or ComEd's PPO.
90
Nine Months Ended September 30,
-------------------------------
Electric Revenue 2003 2002 Variance % Change
-------------------------------------------------------------------------------------------------------------------
Bundled Revenues (1)
Residential $ 2,899 $ 2,880 $ 19 0.7%
Small Commercial & Industrial 1,874 2,007 (133) (6.6%)
Large Commercial & Industrial 1,065 1,152 (87) (7.6%)
Public Authorities & Electric Railroads 309 356 (47) (13.2%)
-----------------------------------------------------------------------------------------------------
Total Bundled Revenues 6,147 6,395 (248) (3.9%)
-----------------------------------------------------------------------------------------------------
Unbundled Revenues (2)
Alternative Energy Suppliers
----------------------------
Residential 52 129 (77) (59.7%)
Small Commercial & Industrial 161 107 54 50.5%
Large Commercial & Industrial 149 111 38 34.2%
Public Authorities & Electric Railroads 25 18 7 38.9%
-----------------------------------------------------------------------------------------------------
387 365 22 6.0%
-----------------------------------------------------------------------------------------------------
PPO (ComEd Only)
----------------
Small Commercial & Industrial 174 155 19 12.3%
Large Commercial & Industrial 199 214 (15) (7.0%)
Public Authorities & Electric Railroads 81 48 33 68.8%
-----------------------------------------------------------------------------------------------------
454 417 37 8.9%
-----------------------------------------------------------------------------------------------------
Total Unbundled Revenues 841 782 59 7.5%
-----------------------------------------------------------------------------------------------------
Total Electric Retail Revenues 6,988 7,177 (189) (2.6%)
-----------------------------------------------------------------------------------------------------
Wholesale and Miscellaneous Revenue (3) 414 438 (24) (5.5%)
-----------------------------------------------------------------------------------------------------
Total Electric Revenue $ 7,402 $ 7,615 $ (213) (2.8%)
=====================================================================================================
(1) Bundled revenue reflects deliveries to customers taking electric
service under tariffed rates, which include the cost of energy and the
delivery cost of the transmission and the distribution of the energy.
PECO's tariffed rates also include a CTC charge.
(2) Unbundled revenue reflects revenue from customers electing to receive
electric generation service from an alternative energy supplier or
ComEd's PPO. Revenue from customers choosing an alternative energy
supplier includes a distribution charge and a CTC. Revenues from
customers choosing ComEd's PPO includes an energy charge at market
rates, transmission and distribution charges and a CTC. Transmission
charges received from alternative energy suppliers are included in
wholesale and miscellaneous revenue.
(3) Wholesale and miscellaneous revenues include transmission revenue,
sales to municipalities and other wholesale energy sales.
The differences in electric retail revenues for the nine months
ended September 30, 2003 as compared to the same period in 2002 were
attributable to the following:
Variance
-------------------------------------------------------------------------------------------------------------------
Weather $ (189)
Customer choice (116)
Rate mix (28)
Volume 109
Rate changes 23
Other effects 12
-------------------------------------------------------------------------------------------------------------------
Electric retail revenue $ (189)
===================================================================================================================
o Weather. The weather impact for the nine months ended September 30,
2003 was unfavorable compared to the same period in 2002 as a result
of cooler summer weather in 2003, partially offset by colder winter
weather. Cooling degree-days in the ComEd and
91
PECO service territories were 36% lower and 19% lower, respectively,
in 2003 as compared to 2002. Heating degree-days in the ComEd and PECO
service territories were 15% higher and 35% higher, respectively, in
2003 as compared to 2002.
o Customer Choice. For the nine months ended September 30, 2003 and
September 30, 2002, 16% and 13%, respectively, of energy delivered to
Energy Delivery's customers was provided by alternative electric
suppliers. The decrease in electric retail revenues includes a
decrease in revenues of $113 million from customers in Illinois
electing to purchase energy from an ARES or ComEd's PPO, and a
decrease in revenues of $3 million from customers in Pennsylvania
selecting and alternative electric generation supplier.
o Rate Mix. Revenues related to changes in rate mix at PECO decreased
$28 million due to changes in monthly usage patterns in all customer
classes for the nine months ended September 30, 2003 as compared to
the same period in 2002.
o Volume. Revenues from higher delivery volume, exclusive of the effect
of weather, increased due to an increased number of customers and
increased usage per customer, primarily in the residential and small
commercial and industrial customer classes for ComEd and in the small
and large commercial and industrial customer classes for PECO.
o Rate Changes. The increase in revenues attributable to rate changes
reflects the collection of additional CTCs in 2003 by ComEd through
June 1, 2003, offset by lower collections since then. The net increase
for the nine months ended September 30, 2003 was $65 million. Starting
in the June 2003 billing cycle, the increased wholesale market price
of electricity, net of increased mitigation factors, as a result of
an agreement described in Note 5 of the Condensed Combined Notes to
Consolidated Financial Statements, decreased the collections of CTCs
as compared to the respective period in 2002 by $81 million. Changes
in wholesale market prices decreased energy revenue received under
ComEd's PPO by $42 million.
Energy Delivery's gas sales statistics and revenue detail were as
follows:
Nine Months Ended September 30,
-------------------------------
Deliveries to customers in mmcf 2003 2002 Variance % Change
-------------------------------------------------------------------------------------------------------------------
Retail sales 44,183 34,128 10,055 29.5%
Transportation 19,954 22,862 (2,908) (12.7%)
-----------------------------------------------------------------------------------------------------
Total 64,137 56,990 7,147 12.5%
=====================================================================================================
n.m. - not meaningful
Nine Months Ended September 30,
-------------------------------
Revenue 2003 2002 Variance % Change
-------------------------------------------------------------------------------------------------------------------
Retail sales $ 418 $ 309 $ 109 35.3%
Transportation 14 15 (1) (6.7%)
Resales and other 16 34 (18) (52.9%)
-----------------------------------------------------------------------------------------------------
Total $ 448 $ 358 $ 90 25.1%
=====================================================================================================
92
The changes in gas retail revenue for the nine months ended
September 30, 2003 as compared to the same period in 2002, were as follows:
Variance
-------------------------------------------------------------------------------------------------------------------
Weather $ 73
Volume 21
Rate changes 15
-------------------------------------------------------------------------------------------------------------------
Total gas retail revenue $ 109
===================================================================================================================
o Weather. The weather impact was favorable compared to the prior year
as a result of colder winter weather. Heating degree-days increased
35% in the nine months ended September 30, 2003 compared to the same
period in 2002. Retail sales deliveries increased approximately 8,600
mmcf due to the colder weather.
o Volume. Exclusive of weather impacts, higher delivery volume increased
revenue in the nine months ended September 30, 2003 compared to the
same period in 2002 resulting from increased retail sales in all
classes. Deliveries to retail customers increased approximately 1,500
mmcf, or 4% in the nine months ended September 30, 2003 compared to
the same period in 2002.
o Rate Changes. The favorable variance in rates is attributable to
increases of 15% and 7% in the purchased gas adjustment by the PUC
effective March 1, 2003 and June 1, 2003, respectively. The average
rate per mmcf for the nine months ended September 30, 2003 was 5%
higher than the rate in the same 2002 period. PECO's gas rates are
subject to periodic adjustments by the PUC and are designed to recover
from or refund to customers the difference between actual cost of
purchased gas and the amount included in base rates and to recover or
refund increases or decreases in certain state taxes not recovered in
base rates.
The reduction in transportation volumes and revenues was primarily
the result of lower intercompany deliveries to Generation during the nine
months ended September 30, 2003 compared to the same period in 2002.
Lower resale revenues are attributable to a decrease in off-system
sales, exchanges and capacity releases during the nine months ended
September 30, 2003 compared to the same period in 2002.
93
Results of Operations - Generation
Nine Months Ended September 30,
-------------------------------
2003 2002 Variance % Change
-------------------------------------------------------------------------------------------------------------------
Operating revenues $ 6,301 $ 5,233 $ 1,068 20.4%
Revenue, net of purchased power & fuel expense 2,264 1,946 318 16.3%
Operating income (loss) (411) 389 (800) n.m.
Income (loss) before income taxes and cumulative effect
of changes in accounting principles (548) 511 (1,059) n.m.
Income (loss) before cumulative effect of changes in
accounting principles (339) 313 (652) n.m.
Net income (loss) (231) 326 (557) (170.9%)
-------------------------------------------------------------------------------------------------------------------
n.m. - not meaningful
The changes in Generation's revenue, net of purchased power and
fuel expense, for the nine months ended September 30, 2003 compared to the
same period in 2002, included the following:
o increased market sales of $593 million primarily attributable to
higher regional demand and higher prices, and reduced capacity
payments as a result of releasing Midwest Generation options,
o unfavorable weather conditions in the ComEd and PECO service
territories in 2003 resulted in a net volume decrease, partially
offset by price increases, resulting in a $112 million unfavorable
variance on revenue from Energy Delivery,
o increased decommissioning revenue from ComEd of $47 million associated
with the adoption of SFAS No. 143, which was not included in revenue
in 2002,
o mark-to-market losses on hedging activities of $17 million in 2003
compared to a gain of $11 million in 2002,
o favorable changes in trade book activity of $26 million were a result
of lower losses from decreased trading volumes in 2003 compared to
2002, and
o additional nuclear fuel amortization of $16 million in 2003 resulting
from under performing fuel at the Quad Cities Unit 1.
Other significant factors affecting the changes in revenue, net of
purchased power and fuel, include the impacts of the plants acquired during
2002 resulting in a net favorable variance of $111 million. In addition,
the impacts of higher prices of purchased power and fuel costs, partially
offset by lower volumes of purchased power, resulted in a net unfavorable
impact of $301 million.
The changes in operating income (loss), other than changes in
revenue, net of purchased power and fuel expense, for the nine months ended
September 30, 2003 compared to the same period in 2002, included the
following:
o impairment charge of $945 million related to the long-lived assets of
EBG,
o increased accretion expense of $162 million due to the adoption of
SFAS No. 143, partially offset by reduced decommissioning expense of
$93 million,
o higher costs of $51 million for employee medical, pension and other
employee payroll and benefit costs in 2003, partially offset by a
one-time executive severance charge of $19 million in 2002,
94
o increased O&M costs of $68 million due to asset acquisitions made
during 2002 and a $5 million asset impairment charge recorded in 2003
related to Mystic Station Units 4, 5, and 6,
o $46 million in severance and related postretirement health and welfare
benefits accruals and pension and postretirement curtailment costs
associated with The Exelon Way,
o reduced refueling outage costs of $61 million, including $17 million
at one of Generation's co-owned facilities, resulting from fewer
refueling outage days in 2003,
o additional depreciation of $39 million due to capital additions placed
in service and plant acquisitions made during 2002 and $13 million due
to plant acquisitions made after the third quarter of 2002, partially
offset by a $12 million reduction to depreciation expense due to life
extensions made in 2002, and
o reduction in worker's compensation expense of $8 million compared to
2002.
The changes in other income and deductions for the nine months
ended September 30, 2003 compared to the same period in 2002, included the
following:
o impairment charges of $255 million related to Generation's equity
investment in Sithe,
o increased decommissioning trust investment income of $41 million,
which is almost entirely offset with accretion expense, net of
depreciation, recorded in O&M,
o decreased equity in earnings of unconsolidated affiliates of $29
million and
o increased interest expense of $12 million primarily due to $8 million
of interest expense on the long-term debt assumed as a part of the
Exelon New England asset acquisition, reduced capitalized interest in
2003, and $7 million of interest incurred on the note payable to
Sithe.
Generation's effective income tax rate was 38.1% for the nine
months ended September 30, 2003 compared to 38.7% for the same period in
2002. This decrease was primarily attributable to the impact of changes in
income before taxes as a result of the impairments of Generation's
investment in Sithe and the long-lived assets of EBG.
Cumulative effect of changes in accounting principles recorded in
the nine months ended September 30, 2003 and 2002 included income of $108
million, net of income taxes, recorded in the first quarter of 2003 related
to the adoption of SFAS No. 143 and income of $13 million, net of income
taxes, recorded in 2002 related to the adoption of SFAS No. 141, "Business
Combinations" (SFAS No. 141) and SFAS No. 142. See Note 2 of the Condensed
Combined Notes to Consolidated Financial Statements for further discussion
of these effects.
95
Generation Operating Statistics
Generation's sales and the supply of these sales, excluding the
trading portfolio, were as follows:
Nine Months Ended September 30,
-------------------------------
Sales (in GWhs) 2003 2002 Variance % Change
-------------------------------------------------------------------------------------------------------------------
Energy Delivery and Exelon Energy Company 89,700 94,646 (4,946) (5.2%)
Market Sales 80,877 61,089 19,788 32.4%
-----------------------------------------------------------------------------------------------------
Total Sales 170,577 155,735 14,842 9.5%
=====================================================================================================
Nine Months Ended September 30,
-------------------------------
Supply of Sales (in GWhs) 2003 2002 Variance % Change
-------------------------------------------------------------------------------------------------------------------
Nuclear Generation (1) 89,101 86,127 2,974 3.5%
Purchases - non-trading portfolio (2) 63,435 59,496 3,939 6.6%
Fossil and Hydro Generation 18,041 10,112 7,929 78.4%
-----------------------------------------------------------------------------------------------------
Total Supply 170,577 155,735 14,842 9.5%
=====================================================================================================
(1) Excluding AmerGen.
(2) Including PPAs with AmerGen.
Trading volumes of 28,532 GWhs and 51,260 GWhs for the nine months
ended September 30, 2003 and 2002, respectively, are not included in the
table above. The decrease in trading volume is a result of reduced
volumetric and VaR trading limits in 2003, which are set by the Risk
Management Committee and approved by the Board of Directors.
Generation's average margin and other operating data for the nine
months ended September 30, 2003 and 2002 were as follows:
Nine Months Ended September 30,
-------------------------------
($/MWh) 2003 2002 % Change
-------------------------------------------------------------------------------------------------------------------
Average Revenue
Energy Delivery and Exelon Energy Company $ 35.45 $ 34.86 1.7%
Market Sales 37.11 31.55 17.6%
Total - excluding the trading portfolio 36.24 33.56 8.0%
Average Supply Cost (1) - excluding the trading portfolio $ 23.67 $ 21.04 12.5%
Average Margin - excluding the trading portfolio $ 12.57 $ 12.52 0.4%
-----------------------------------------------------------------------------------------------------------------
(1) Average supply cost includes purchased power and fuel costs.
Nine Months Ended September 30,
-------------------------------
2003 2002
-------------------------------------------------------------------------------------------------------------------
Nuclear fleet capacity factor (1) 94.5% 92.1%
Nuclear fleet production cost per MWh (1) $ 12.16 $ 13.05
Average purchased power cost for wholesale operations per MWh (2) $ 45.42 $ 43.60
-------------------------------------------------------------------------------------------------------------------
(1) Including AmerGen and excluding Salem, which is operated by PSE&G.
(2) Including PPAs with AmerGen.
The factors below contributed to the overall increase in
Generation's average margin for the nine months ended September 30, 2003 as
compared to the same period in 2002.
96
Generation's average revenue per MWh was affected by:
o higher market prices as a result of increased fuel prices and
o increased weighted average on and off-peak prices per MWh for supply
agreements with ComEd and PECO.
Generation's supply mix changed as a result of:
o increased nuclear generation due to a lower number of refueling and
unplanned outages during 2003 compared to 2002,
o increased fossil generation due to the effect of the acquisition of
two generating plants in Texas in April 2002, and the Exelon New
England plants acquired in November 2002, which in total account for
an increase of 6,565 GWhs,
o increased quantity of purchased power at higher prices, and
o a new PPA with AmerGen entered into during the second quarter of 2003,
resulting in 2,481 GWhs purchased from Oyster Creek in 2003.
Higher nuclear capacity factors and decreased nuclear production
costs are primarily due to 66 fewer planned refueling outage days,
resulting in a $44 million decrease in outage costs, in the nine months
ended September 30, 2003 as compared to the same period in 2002. The nine
months ended September 30, 2003 and 2002 included 20 unplanned outages in
each year.
Generation's financial results are greatly dependent on the
performance of its nuclear units, including Generation's ability to
maintain stable cost levels and high nuclear capacity factors. Problems
that may occur at nuclear facilities that result in increased costs include
accelerated replacement of suspect fuel assemblies and reduced generation
due to maintenance and mid-cycle outages. For example, in the second
quarter of 2003, the Quad Cities Unit 1 required a significant repair and
did not operate above 85% capacity factor until a root cause analysis was
completed. Although this individual matter did not result in a significant
decrease in operating income, this type of reduction in operational
capacity can adversely affect Generation's financial results. Generation
completed the analysis and returned the unit to its normal operating
capacity in August 2003.
Results of Operations - Enterprises
Nine Months Ended September 30,
-------------------------------
2003 2002 Variance % Change
-------------------------------------------------------------------------------------------------------------------
Operating revenues $ 1,459 $ 1,475 $ (16) (1.1%)
Operating loss (60) (35) (25) 71.4%
Income (loss) before income taxes and cumulative effect
of changes in accounting principles (99) 115 (214) (186.1%)
Income (loss) before cumulative effect of changes in
accounting principles (62) 69 (131) (189.9%)
Net loss (63) (174) 111 (63.8%)
-------------------------------------------------------------------------------------------------------------------
97
The changes in Enterprises' operating loss for the nine months
ended September 30, 2003 compared to the same period in 2002, included the
following:
o an impairment charge of $48 million, before income taxes and minority
interest, related to the goodwill of InfraSource recorded during the
second quarter of 2003, partially offset by a gain of $44 million,
before income taxes, related to the sale of the electric construction
and services, underground and telecom business of InfraSource recorded
during the third quarter of 2003,
o lower operating income at InfraSource of $25 million primarily
resulting from a decrease in the electric business of $37 million,
partially offset by lower depreciation of $10 million as a result of
the classification of InfraSource's property, plant and equipment as
held for sale during the second quarter of 2003,
o lower operating income at Exelon Services of $3 million as a result of
reduced construction projects,
o higher operating income at Exelon Energy Company of $3 million
resulting from lower operating expense from the discontinuance of
retail sales in the PJM region including 2002 costs for accelerated
depreciation of $14 million and general and administrative costs of $2
million. These costs were partially offset by lower gross margins of
$13 million in 2003. The lower gross margins resulted from the
reversal of mark-to-market adjustments of $13 million and additional
gas supply costs and business wind-down costs of $12 million for
Northeast operations, partially offset by higher gross margins of $10
million in the Midwest attributable to increased unit margins, higher
volumes, and higher natural gas prices, and a $2 million favorable
variance related to the wind-down of a contract, and
o higher operating income at Exelon Thermal of $4 million resulting from
lower production costs.
The changes in other income and deductions for the nine months
ended September 30, 2003 compared to the same period in 2002, include the
following additional impacts:
o a gain of $198 million, before income taxes, in the second quarter of
2002 due to the sale of the investment in AT&T Wireless, and
o an impairment charge in 2003 of energy-related investments of $22
million, communications investments of $13 million, and $5 million of
software-related investments due to an other-than-temporary decline in
value, partially offset by an impairment charge in 2002 of
communications investments of $29 million, energy-related investments
of $11 million and a net impairment of other assets of $4 million.
The effective income tax rate was 37.4% for the nine months ended
September 30, 2003, compared to 40.0% for the same period in 2002. This
decrease in the effective tax rate was attributable to lower effective
income tax rates on the impairment charges and sale of the InfraSource
businesses.
The cumulative effect of a change in accounting principle recorded
in the first quarter of 2003 due to the adoption of SFAS No. 143 reduced
net income by $1 million, net of income taxes. The cumulative effect of a
change in accounting principle recorded in the first quarter of 2002 for
the adoption of SFAS No. 142 reduced net income by $243 million, net of
income
98
taxes. See Note 2 of the Condensed Combined Notes to Consolidated Financial
Statements for further discussion of these effects.
Enterprises continues to pursue the divestiture of other
businesses; however, it may be unable to successfully implement its
divestiture strategy of certain businesses for a number of reasons,
including an inability to locate appropriate buyers or to negotiate
acceptable terms for the transactions. In addition, the amount that
Enterprises may realize from a divestiture is subject to fluctuating market
conditions that may contribute to pricing and other terms that are
materially different than expected and could result in a loss on the sale.
Timing of any divestitures may positively or negatively affect the results
of operations as Exelon expects certain businesses to be profitable going
forward.
General
Due to revenue needs in the states in which Exelon operates,
various state income tax and fee increases have been proposed or are being
contemplated. If these changes are enacted, they could increase Exelon's
state income tax expense. At this time, however, Exelon cannot predict
whether legislation or regulation will be introduced, the form of any
legislation or regulation, whether any such legislation or regulation will
be passed by the state legislatures or regulatory bodies, and, if enacted,
whether any such legislation or regulation would be effective retroactively
or prospectively. As a result, Exelon cannot currently estimate the effect
of these potential changes in tax laws or regulation.
LIQUIDITY AND CAPITAL RESOURCES
Exelon's businesses are capital intensive and require considerable
capital resources. These capital resources are primarily provided by
internally generated cash flows from Energy Delivery and Generation's
operations. When necessary, Exelon obtains funds from external sources in
the capital markets and through bank borrowings. Exelon's access to
external financing at reasonable terms depends on Exelon's and its
subsidiaries' credit ratings and general business conditions, as well as
that of the utility industry in general. If these conditions deteriorate to
where Exelon no longer has access to external financing sources at
reasonable terms, Exelon has access to a $1.5 billion revolving credit
facility that Exelon currently utilizes to support its commercial paper
program. See the Credit Issues section of Liquidity and Capital Resources
for further discussion. Exelon primarily uses its capital resources to fund
capital requirements, including construction, to invest in new and existing
ventures, to repay maturing debt and to pay common stock dividends. Future
acquisitions that Exelon may undertake may require external financing,
which might include Exelon issuing common stock.
Exelon is in the process of implementing its new business model
referred to as The Exelon Way. This business model is focused on improving
operating cash flows while meeting service and financial commitments
through integration of operations and consolidation of support functions.
Exelon has targeted approximately $300 million of annual cash savings
beginning in 2004 and increasing the annual cash savings to $600 million in
2006.
As part of the implementation of The Exelon Way, Exelon has
identified 1,042 positions
99
for elimination by the end of 2004 and anticipates identifying additional
positions for elimination in 2005 and 2006. Exelon recorded a charge for
cash severance of $87 million during the third quarter 2003, which Exelon
anticipates will be paid by December 31, 2004. Exelon anticipates incurring
further costs associated with The Exelon Way upon identifying additional
positions to be eliminated. These costs will be recorded in the period in
which the costs can be reasonably estimated.
On September 26, 2003 Exelon announced that it was exploring the
possibility of acquiring Illinois Power Company from Dynegy Corporation.
Cash Flows from Operating Activities
Cash flows provided by operations for the nine months ended
September 30, 2003 were $2.6 billion compared to $2.7 billion in the nine
months ended September 30, 2002. The decrease in cash flows was primarily
attributable to the $360 million funding of pension benefit obligations
partially offset by a $162 million increase in cash flows generated from
working capital. Energy Delivery's cash flow from operating activities
primarily results from sales of electricity and gas to a stable and diverse
base of retail customers at fixed prices. Energy Delivery's future cash
flows will depend upon the ability to achieve cost savings in operations
and the impact of the economy, weather, customer choice and future
regulatory proceedings on its revenues. Generation's cash flows from
operating activities primarily result from the sale of electric energy to
wholesale customers, including Energy Delivery and Enterprises.
Generation's future cash flow from operating activities will depend upon
future demand and market prices for energy and the ability to continue to
produce and supply power at competitive costs. Although the amounts may
vary from period to period as a result of the uncertainties inherent in
business, Exelon expects that Energy Delivery and Generation will continue
to provide a reliable and steady source of internal cash flow from
operations for the foreseeable future.
Cash Flows used in Investing Activities
Cash flows used in investing activities for the nine months ended
September 30, 2003 were $1.3 billion, compared to $1.9 billion for the nine
months ended September 30, 2002. The decrease in cash used for investing
activities during the current year is primarily attributable to the plant
acquisition costs of $443 million during the nine months ended September
30, 2002, the reduction of capital expenditures of $33 million, the receipt
of liquated damages from Raytheon of $92 million during the nine months
ended September 30, 2003 and an increase in cash proceeds from related
parties of $77 million, partially offset by increased investments in
nuclear decommissioning trust fund assets of $17 million. Additionally,
cash flows from investing activities in 2002 include the cash proceeds from
the sale of AT&T of $285 million, while cash proceeds from the sale of
InfraSource during the current year were $175 million.
100
Capital expenditures by business segment for the nine months
ended September 30, 2003 and 2002 were as follows:
Nine Months Ended September 30,
--------------------------------
2003 2002
-------------------------------------------------------------------------------------------------------------------
Energy Delivery $ 728 $ 729
Generation 641 715
Enterprises 19 34
Corporate and other 21 56
-------------------------------------------------------------------------------------------------------------------
Total capital expenditures (net of liquidated damages received) $ 1,409 $ 1,534
===================================================================================================================
Energy Delivery's capital expenditures for 2003 reflect continuing
efforts to further improve the reliability of its transmission and
distribution systems and capital additions to support new business and
customer growth. Exelon anticipates that Energy Delivery's capital
expenditures will be funded by internally generated funds, borrowings, the
issuance of preferred securities, or capital contributions from Exelon.
Generation's capital expenditures for 2003 reflect the
construction of three EBG generating facilities with capacity of 2,421 MWs
of energy, additions to and upgrades of existing facilities (including
nuclear refueling outages), and nuclear fuel. During the nine months ended
September 30, 2003, EBG received $92 million of liquidated damages from
Raytheon as a result of Raytheon not meeting the expected completion date
and certain contractual performance criteria in connection with Raytheon's
construction of Exelon New England's Mystic 8 and 9 and Fore River. Exelon
anticipates that Generation's capital expenditures will be funded by
internally generated funds, borrowings or capital contributions from
Exelon.
Enterprises' capital expenditures for 2003 are primarily for
additions of equipment. All of Enterprises' capital expenditures are
expected to be funded by internally generated funds, capital contributions
or borrowings from Exelon.
Cash Flows used in Financing Activities
Cash flows used in financing activities were $1.1 billion for the
nine months ended September 30, 2003 compared to $828 million for the same
period in 2002. The increased use of cash over the prior year is primarily
attributable to the $210 million payment of the acquisition note payable to
Sithe in June 2003 and increased interest rate swap settlement payments of
$35 million over the same period in 2002, partially offset by an increase
in cash proceeds from the exercise of stock options of $75 million and a
net increase in cash proceeds from the issuance of debt and preferred
securities of $14 million over the same period in 2002. See Note 12 of the
Condensed Combined Notes to Consolidated Financial Statements for further
discussion of Exelon's debt and preferred securities financing activities
in 2003.
Dividends paid on common stock increased from $420 million for the
nine months ended September 30, 2002 to $461 million for the nine months
ended September 30, 2003. On July 29, 2003, the Exelon Board of Directors
declared a dividend of $0.50 per share on Exelon's common stock,
representing an increase of $0.16 per share annually or approximately 8.7%.
Payment of future dividends is subject to approval and declaration by the
Board.
101
Credit Issues
Exelon meets its short-term liquidity requirements primarily
through the issuance of commercial paper by the Exelon corporate holding
company (Exelon Corporate) and by ComEd and PECO. Exelon Corporate
participates, along with ComEd, PECO and Generation, in a $1.5 billion
unsecured 364-day revolving credit facility with a group of banks. The
credit facility became effective on November 22, 2002 and includes a
term-out option that allows any outstanding borrowings at the end of the
revolving credit period to be repaid on November 21, 2004. Exelon Corporate
may increase or decrease the sublimits of each of the participants upon
written notification to the banks. At September 30, 2003, sublimits under
the credit facility were $1.0 billion, $100 million and $400 million for
Exelon Corporate, ComEd and PECO, respectively. Generation did not have a
sublimit under the facility at September 30, 2003. The credit facility is
used principally to support the commercial paper programs of Exelon
Corporate, ComEd and PECO. At September 30, 2003, Exelon's Consolidated
Balance Sheet reflected $82 million of commercial paper outstanding. For
the nine months ended September 30, 2003, the average interest rate on
notes payable was approximately 1.28%.
The credit facility requires Exelon Corporate, ComEd, PECO and
Generation to maintain a minimum cash from operations to interest expense
ratio for the twelve-month period ended on the last day of any quarter. The
ratios exclude revenues and interest expenses attributable to
securitization debt, certain changes in working capital, distributions on
preferred securities of subsidiaries and, in the case of Exelon Corporate
and Generation, revenues from Exelon New England and interest on the debt
of Exelon New England's project subsidiaries. Exelon Corporate is measured
at the Exelon consolidated level. At September 30, 2003, Exelon Corporate,
ComEd, PECO and Generation were in compliance with the credit agreement
thresholds. The following table summarizes the threshold reflected in the
credit agreement that the ratio cannot be less than for the twelve-month
period ended September 30, 2003:
Exelon Corporate ComEd PECO Generation
-------------------------------------------------------------------------------------------------------------------
Credit agreement threshold 2.65 to 1 2.25 to 1 2.25 to 1 3.25 to 1
-------------------------------------------------------------------------------------------------------------------
To provide an additional short-term borrowing option that will
generally be more favorable to the borrowing participants than the cost of
external financing, Exelon operates an intercompany money pool.
Participation in the money pool is subject to authorization by Exelon's
corporate treasurer. ComEd, PECO, Generation and Exelon Business Services
Company (BSC) may participate in the money pool as lenders and borrowers,
and Exelon Corporate may participate as a lender. Funding of, and
borrowings from, the money pool are predicated on whether the contributions
and borrowings result in economic benefits to all the participants.
Interest on borrowings is based on short-term market rates of interest, or,
if from an external source, specific borrowing rates. During the nine
months ended September 30, 2003, ComEd had various investments in the money
pool, and Generation had various loans from the money pool. The maximum
amount of ComEd's investments and Generation's loans outstanding at any
time during 2003 was $344 million. As of September 30, 2003, the
outstanding ComEd investment and Generation loan balance was $147 million.
During the nine months ended September 30, 2003, PECO had various
investments in the money pool, and BSC had various loans from the money
pool. The maximum amount of PECO's investments and
102
BSC's loans outstanding at any time during 2003 was $59 million. As of
September 30, 2003, there were no outstanding PECO investments or BSC loan
balances.
EBG has approximately $1.1 billion of debt outstanding under a
$1.25 billion credit facility (EBG Facility) at September 30, 2003. The EBG
Facility was entered into primarily to finance the construction of Mystic 8
and 9 and Fore River. The EBG Facility required that all of the projects
achieve "Project Completion," as defined in the EBG Facility (Project
Completion), by June 12, 2003. On June 11, 2003, EBG negotiated an extension
of the Project Completion date to July 11, 2003. On July 3, 2003, the
lenders under the EBG Facility and EBG executed a letter agreement as a
result of which the lenders were precluded during the period July 11, 2003
through August 29, 2003 from exercising any remedies resulting from the
failure of all of the projects to achieve Project Completion. At that time,
EBG stated that it would continue to monitor the projects, assess all of its
options relating to the projects, and continue discussions with the lenders.
Project Completion was not achieved by July 12, 2003, resulting in an event
of default under the EBG Facility. The EBG Facility is non-recourse to
Generation and an event of default under the EBG Facility does not
constitute an event of default under any other debt instruments of Exelon or
its subsidiaries. Mystic 8 and 9 and Fore River are in commercial operation,
although they have not yet achieved Project Completion.
As a result of Exelon's continuing evaluation of the projects and
discussions with the lenders, Exelon has commenced the process of an
orderly transition out of the ownership of EBG and the projects. The
transition will take place in a manner that complies with applicable
regulatory requirements. For a period of time, Exelon expects to continue
to provide administrative and operational services to EBG in its operation
of the projects. Exelon informed the lenders of its decision to exit and
that it will not provide additional funding to the projects beyond its
existing contractual obligations. Exelon cannot predict the timing of the
transition.
The debt outstanding under the EBG Facility of approximately $1.1
billion at September 30, 2003 is reflected in Exelon's Consolidated Balance
Sheet as a current liability.
On June 13, 2003, Generation closed on a $550 million revolving
credit facility. Generation used the facility to make the first payment to
Sithe of $210 million relating to the $536 million note, which was
established in connection with the acquisition of Exelon New England.
On September 29, 2003, Generation replaced the $550 million
facility with a new $850 million revolving credit facility. The existing
$210 million of borrowings under the original facility remain outstanding
under the new credit facility. The note with Sithe was restructured in the
third quarter to provide for the remaining balance of $326 million to be
paid in two installments. Generation will be required to repay $236 million
of the principal on the earlier of December 1, 2003 or change of control,
and the remaining principal balance on the earlier of December 1, 2004 or
change of control.
Generation's $850 million facility is also expected to provide the
initial funding of the acquisition of British Energy's 50% interest in
AmerGen.
103
Exelon's access to the capital markets, including the commercial
paper market, and its financing costs in those markets depend on the
securities ratings of the entity that is accessing the capital markets.
None of Exelon's borrowings is subject to default or prepayment as a result
of a downgrading of securities ratings although such a downgrading could
increase fees and interest charges under Exelon's $1.5 billion credit
facility and certain other credit facilities. From time to time, Exelon
enters into energy commodity and other contracts that require the
maintenance of investment grade ratings. Failure to maintain investment
grade ratings would allow counterparties to certain energy commodity
contracts to terminate the contracts and settle the transactions on a net
present value basis.
As part of the normal course of business, Exelon and Generation
routinely enter into physical or financially settled contracts for the
purchase and sale of capacity, energy, fuels and emissions allowances.
These contracts either contain express provisions or otherwise permit
Exelon, Generation and its counterparties to demand adequate assurance of
future performance when there are reasonable grounds for doing so. In
accordance with the contracts and applicable contracts law, if Exelon or
Generation is downgraded by a credit rating agency, especially if such
downgrade is to a level below investment grade, it is possible that a
counterparty could attempt to rely on such a downgrade as a basis for
making a demand for adequate assurance of future performance. Depending on
Exelon or Generation's net position with a counterparty, the demand could
be for the posting of collateral. In the absence of expressly agreed to
provisions that specify the collateral that must be provided, the
obligation to supply the collateral requested will be a function of the
facts and circumstances of Exelon or Generation's situation at the time of
the demand. If Exelon or Generation can reasonably claim that it is willing
and financially able to perform its obligations, it may be possible to
successfully argue that no collateral should be posted or that only an
amount equal to two or three months of future payments should be
sufficient.
Exelon obtained an order from the United States Securities and
Exchange Commission (SEC) under PUHCA authorizing through March 31, 2004
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. As of September 30, 2003, there was $2.7 billion of
financing authority remaining under the SEC order. Exelon's request for an
additional $4 billion in financing authorization is pending with the SEC.
The current order limits Exelon's short-term debt outstanding to $3 billion
of the $4 billion total financing authority. Exelon's request that the
short-term debt sub-limit restriction be eliminated is pending with the
SEC. The SEC order also authorized Exelon to issue guarantees of up to $4.5
billion outstanding at any one time. At September 30, 2003, Exelon had
provided $1.85 billion of guarantees under the SEC order. See Contractual
Obligations, Commercial Commitments and Off-Balance Sheet Obligations in
this section for further discussion of guarantees. The SEC order requires
Exelon and ComEd to maintain a ratio of common equity to total
capitalization (including securitization debt) on and after September 30,
2002 of not less than 30%. At September 30, 2003, Exelon and ComEd's common
equity ratios were 35% and 47%, respectively. Exelon and ComEd expect that
they will maintain a common equity ratio of at least 30%.
Under PUHCA, Exelon, ComEd, PECO and Generation can pay dividends
only from retained, undistributed or current earnings. Furthermore, a
significant loss recorded at ComEd
104
may limit the dividends that ComEd can distribute to Exelon. However, the
SEC order granted permission to ComEd, and to Exelon, to the extent Exelon
receives dividends from ComEd paid from ComEd additional paid-in-capital,
to pay up to $500 million in dividends out of additional paid-in capital,
although Exelon may not pay dividends out of paid-in capital after December
31, 2002 if its common equity is less than 30% of its total capitalization.
At September 30, 2003, Exelon had retained earnings of $2.2 billion,
including ComEd's retained earnings of $836 million, PECO's retained
earnings of $517 million and Generation's undistributed earnings of $577
million. Exelon is also limited by order of the SEC under PUHCA to an
aggregate investment of $4 billion in exempt wholesale generators (EWGs)
and foreign utility companies (FUCOs). At September 30, 2003, Exelon had
invested $2.8 billion in EWGs, leaving $1.2 billion of investment authority
under the order. Exelon's request for an additional $1.5 billion in EWG
investment authorization is pending with the SEC.
Contractual Obligations, Commercial Commitments and Off-Balance Sheet
Obligations
Contractual obligations represent cash obligations that are
considered to be firm commitments and commercial commitments represent
commitments triggered by future events. Exelon's contractual obligations
and commercial commitments as of September 30, 2003 were materially
unchanged, other than the normal course of business, from the amounts set
forth in the 2002 Form 10-K except for the following:
o On March 3, 2003, ComEd entered into an agreement with various
Illinois electric retail market suppliers, key customer groups and
governmental parties regarding several matters affecting ComEd's rates
for electric service (Agreement). The Agreement addressed, among other
things, issues related to ComEd's delivery services rate proceeding,
market value index proceeding, the process for competitive service
declarations for large-load customers and an extension of the PPA with
Generation. During the second quarter of 2003, the ICC issued orders
consistent with the Agreement, which is now effective.
The Agreement provides for a modification of the methodology used
to determine ComEd's market value energy credit. That credit is used
to determine the price for specified market-based rate offerings and
the amount of the CTC that ComEd is allowed to collect from customers
who select an ARES or the PPO. The credit was adjusted upwards through
agreed upon "adders" which took effect in June 2003 and will have the
effect of reducing ComEd's CTC charges to customers. Prior to the
Agreement, all CTC charges were subject to annual mid-year adjustments
based on the forward market prices for on-peak energy and historical
market prices for off-peak energy. The Agreement provides that the
annual market price adjustment will reflect forward market prices for
energy, rather than historical, and allows customers an option to lock
in current levels of CTC charges for multi-year periods during the
regulatory transition period ending in 2006. These changes provide
customers and suppliers greater price certainty and are expected to
result in an increase in the number of customers electing to purchase
energy from alternate suppliers.
The annual market price adjustments to the CTC effective in June
2002 and June 2003 had the effect of significantly increasing the CTC
charge in June 2002, and subsequently significantly reducing the CTC
charge in June 2003. In 2002, ComEd collected $306 million in CTC
revenue. Based on the changes in the CTC as part of the Agreement and
105
on current assumptions about the competitive price of delivered energy
and customers' choice of electric supplier, ComEd estimates that CTC
revenue will be approximately $300 million in 2003 and approximately
$140 million for each of the years 2004 through 2006.
During the first quarter of 2003, ComEd recorded a charge to
earnings associated with the funding of specified programs and
initiatives associated with the Agreement of $51 million on a present
value basis before income taxes. This amount was partially offset by
the reversal of a $12 million (before income taxes) reserve
established in the third quarter of 2002 for a potential capital
disallowance in ComEd's delivery services rate proceeding and a credit
of $10 million (before income taxes) related to the capitalization of
employee incentive payments provided for in the delivery services
order. The net one-time charge for these items was $29 million (before
income taxes).
o ComEd and PECO have entered into several agreements with a tax
consultant related to the filing of refund claims with the Internal
Revenue Service (IRS) and have made refundable prepayments of $11
million and $1 million, respectively, for potential fees associated
with these agreements. The fees for these agreements are contingent
upon a successful outcome and are based upon a percentage of the
refunds recovered from the IRS, if any. As such, ultimate net cash
flows to ComEd and PECO related to these agreements will either be
positive or neutral depending upon the outcome of the refund claim
with the IRS. These potential tax benefits and associated fees could
be material to the financial position, results of operations and cash
flows of Energy Delivery. ComEd's tax benefits for periods prior to
the Merger would be recorded as a reduction of goodwill pursuant to a
reallocation of the Merger purchase price. Energy Delivery cannot
predict the timing of the final resolution of these refund claims.
o See Note 12 to the Condensed Combined Notes to Consolidated Financial
Statements for discussion of material changes in Exelon's debt and
preferred securities obligations from those set forth in the 2002 Form
10-K.
o Generation entered into a PPA dated June 26, 2003 with AmerGen. Under
the PPA, Generation has agreed to purchase 100% of energy generated by
Oyster Creek through April 9, 2009. See Note 9 of the Condensed
Combined Notes to Consolidated Financial Statements for the commercial
commitments table representing Exelon's commitments not recorded on
the balance sheet but potentially triggered by future events,
including obligations to make payment on behalf of other parties and
financing arrangements to secure their obligations.
o On May 29, 2003, Exelon Fossil Holdings, Inc., a wholly owned
subsidiary of Generation, issued an irrevocable call notice for the
purchase of the 35.2% interest in Sithe owned by Apollo Energy, LLC
and the 14.9% interest owned by subsidiaries of Marubeni Corporation.
The total purchase price under the call was based on the terms of the
existing Put and Call Agreement (PCA) among the parties and is $621
million. The transfer of ownership requires various regulatory
approvals, including the Federal Energy Regulatory Commission (FERC),
the state environmental agency in New Jersey, and expiration of the
Hart Scott Rodino
106
waiting period. Early termination of the Hart Scott Rodino waiting
period was granted effective August 22, 2003.
Under the terms of the PCA, the purchase price must be funded
within six months of the call notice being issued. Additionally,
because the Federal Power Act restricts Generation's ownership of more
than 50% of qualifying facilities, the qualifying facilities owned by
Sithe must be sold or restructured before closing to preserve their
status as qualifying facilities. See below for information regarding a
separate agreement reached by Sithe to sell six U.S. generating
facilities, each a qualifying facility, and an entity holding Sithe's
Canadian assets. At the closing, Sithe is expected to distribute in
excess of $600 million of available cash to Generation.
On August 13, 2003, Generation announced an agreement with
entities controlled by Reservoir Capital Group (Reservoir), a private
investment firm, to sell 50% of Sithe in exchange for $75.8 million in
cash. The sale will occur after Generation's purchase of the remaining
50.1% interest in Sithe. The sale requires FERC approval, a Hart Scott
Rodino filing and a filing with the state regulatory commission in New
York. Both of these filings have been made. Early termination of the
Hart Scott Rodino waiting period was granted September 30, 2003. The
sale is expected to close in the fourth quarter of 2003.
Both Generation and Reservoir's 50% interests in Sithe will be
subject to put and call options that could result in either party
owning 100% of Sithe. While Generation's intent is to fully divest
Sithe by the end of 2004, the timing of the put and call options vary
by acquirer and can extend through March 2006. The pricing of the put
and call options is dependent on numerous factors such as the
acquirer, date of acquisition and assets owned by Sithe at the time of
exercise.
In a separate transaction, Sithe has entered into an agreement
with Reservoir to sell entities holding six U.S. generating
facilities, each a qualifying facility under the Public Utility
Regulatory Policies Act, and an entity holding Sithe's Canadian assets
in exchange for $46.2 million ($26.2 million in cash and a $20 million
two-year note). The sale requires approvals from Sithe's board of
directors and shareholders and regulatory filings in New Jersey and
Canada. Both of these filings have been made. The sale is also
expected to close in the fourth quarter of 2003. This sale is not
contingent on the sale of Exelon's 50% interest in Sithe to Reservoir.
o In June 2003, Generation entered an agreement with USEC Inc. to
purchase approximately $700 million of nuclear fuel from 2005 through
2010.
o On August 14, 2003, Generation received a letter from the DOE
demanding repayment of $40 million of previously received credits from
the Nuclear Waste Fund. The letter also demanded $1.5 million of
accrued interest expense. Although a new settlement would offset
Generation's payments, Generation nonetheless has reserved its 50%
ownership share of these amounts. Because Generation expenses the
casks and capitalizes the permanent components of its spent fuel
storage facilities, these reserves increased Generation's operating
and maintenance expense approximately $11 million and its capital base
107
approximately $9 million during the third quarter of 2003. The
remainder of the recorded obligation to the DOE will be recovered from
the co-owner of the facility. See Note 9 - Nuclear Decommissioning and
Spent Nuclear Fuel Storage in Generation's 2002 Form 10-K for
additional information regarding this matter.
o Under the Price-Anderson Act, all nuclear reactor licensees can be
assessed a maximum charge per reactor per incident. Effective August
20, 2003, the maximum assessment for all nuclear operators per reactor
per incident (including a 5% surcharge) increased from $89 million to
$101 million. The maximum payable per reactor per incident per year of
$10 million is unchanged. The change in the maximum assessment is the
result of an inflation adjustment, required by the Price-Anderson Act.
Based on the increase of the maximum assessment, Exelon's nuclear
insurance guarantees increased from $1,380 million to $1,559 million.
o On October 10, 2003, Exelon executed an agreement to purchase British
Energy's 50% interest in AmerGen for $276.5 million. The transaction
is expected to close in the first half of 2004. The purchase price
matched the offer by FPL Energy, which announced on September 11, 2003
that it intended to buy British Energy's share of AmerGen. Under the
AmerGen limited liability company operating agreement between Exelon
and British Energy, either can exercise a right of first refusal by
matching any bona fide third-party offer agreed to by the other
member. See Note 4 of the Condensed Combined Notes to Consolidated
Financial Statements for additional information regarding AmerGen.
108
COMMONWEALTH EDISON COMPANY
---------------------------
GENERAL
ComEd operates in a single business segment and its operations
consist of the regulated sale of electricity and distribution and
transmission services in northern Illinois.
RESULTS OF OPERATIONS
Three Months Ended September 30, 2003 Compared to Three Months Ended
September 30, 2002
Significant Operating Trends - ComEd
Three Months Ended September 30,
--------------------------------
2003 2002 Variance % Change
-------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES $ 1,737 $ 1,938 $ (201) (10.4%)
OPERATING EXPENSES
Purchased power 891 975 (84) (8.6%)
Operating and maintenance 299 267 32 12.0%
Depreciation and amortization 97 129 (32) (24.8%)
Taxes other than income 87 77 10 13.0%
-----------------------------------------------------------------------------------------------------
Total operating expenses 1,374 1,448 (74) (5.1%)
-----------------------------------------------------------------------------------------------------
OPERATING INCOME 363 490 (127) (25.9%)
-----------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest expense (107) (122) 15 (12.3%)
Distributions on mandatorily redeemable preferred securities (6) (7) 1 (14.3%)
Other, net 15 -- 15 n.m.
-----------------------------------------------------------------------------------------------------
Total other income and deductions (98) (129) 31 (24.0%)
-----------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 265 361 (96) (26.6%)
INCOME TAXES 102 146 (44) (30.1%)
-----------------------------------------------------------------------------------------------------
NET INCOME $ 163 $ 215 $ (52) (24.2%)
=====================================================================================================
n.m. - not meaningful
Net Income
Net income decreased $52 million, or 24%, for the three months
ended September 30, 2003 as compared to the same period in 2002. Net income
was negatively impacted by lower operating revenues net of purchased power
expense primarily due to unfavorable weather, and charges associated with
The Exelon Way severance partially offset by lower amortization expense and
lower interest expense.
109
Operating Revenues
ComEd's electric sales statistics were as follows:
Three Months Ended September 30,
--------------------------------
Retail Deliveries - (in GWhs) 2003 2002 Variance % Change
-------------------------------------------------------------------------------------------------------------------
Bundled Deliveries (1)
Residential 8,197 9,121 (924) (10.1%)
Small Commercial & Industrial 5,749 6,029 (280) (4.6%)
Large Commercial & Industrial 1,539 2,073 (534) (25.8%)
Public Authorities & Electric Railroads 1,269 1,612 (343) (21.3%)
-------------------------------------------------------------------------------------------------
16,754 18,835 (2,081) (11.0%)
-------------------------------------------------------------------------------------------------
Unbundled Deliveries (2)
ARES
----
Small Commercial & Industrial 1,721 1,640 81 4.9%
Large Commercial & Industrial 2,934 2,192 742 33.9%
Public Authorities & Electric Railroads 426 299 127 42.5%
-------------------------------------------------------------------------------------------------
5,081 4,131 950 23.0%
-------------------------------------------------------------------------------------------------
PPO
---
Small Commercial & Industrial 884 782 102 13.0%
Large Commercial & Industrial 896 1,249 (353) (28.3%)
Public Authorities & Electric Railroads 428 345 83 24.1%
-------------------------------------------------------------------------------------------------
2,208 2,376 (168) (7.1%)
-------------------------------------------------------------------------------------------------
Total Unbundled Deliveries 7,289 6,507 782 12.0%
-------------------------------------------------------------------------------------------------
Total Retail Deliveries 24,043 25,342 (1,299) (5.1%)
=================================================================================================
(1) Bundled service reflects deliveries to customers taking electric
service under tariffed rates.
(2) Unbundled service reflects customers electing to receive electric
generation service from an ARES or the PPO.
110
Three Months Ended September 30,
--------------------------------
Electric Revenue 2003 2002 Variance % Change
-------------------------------------------------------------------------------------------------------------------
Bundled Revenues (1)
Residential $ 760 $ 840 $ (80) (9.5%)
Small Commercial & Industrial 487 506 (19) (3.8%)
Large Commercial & Industrial 82 106 (24) (22.6%)
Public Authorities & Electric Railroads 82 104 (22) (21.2%)
-------------------------------------------------------------------------------------------------
1,411 1,556 (145) (9.3%)
-------------------------------------------------------------------------------------------------
Unbundled Revenues (2)
ARES
----
Small Commercial & Industrial 34 51 (17) (33.3%)
Large Commercial & Industrial 41 60 (19) (31.7%)
Public Authorities & Electric Railroads 8 10 (2) (20.0%)
-------------------------------------------------------------------------------------------------
83 121 (38) (31.4%)
-------------------------------------------------------------------------------------------------
PPO
---
Small Commercial & Industrial 65 57 8 14.0%
Large Commercial & Industrial 56 74 (18) (24.3%)
Public Authorities & Electric Railroads 26 19 7 36.8%
-------------------------------------------------------------------------------------------------
147 150 (3) (2.0%)
-------------------------------------------------------------------------------------------------
Total Unbundled Revenues 230 271 (41) (15.1%)
-------------------------------------------------------------------------------------------------
Total Electric Retail Revenues 1,641 1,827 (186) (10.2%)
Wholesale and Miscellaneous Revenue (3) 96 111 (15) (13.5%)
-------------------------------------------------------------------------------------------------
Total Electric Revenue $ 1,737 $ 1,938 $ (201) (10.4%)
=================================================================================================
(1) Bundled revenue reflects deliveries to customers taking electric
service under tariffed rates, which include the cost of energy and the
delivery cost of the transmission and the distribution of the energy.
(2) Revenue from customers choosing an ARES includes a distribution charge
and a CTC charge. Transmission charges received from ARES are included
in wholesale and miscellaneous revenue. Revenue from customers choosing
the PPO includes an energy charge at market rates, transmission and
distribution charges, and a CTC charge.
(3) Wholesale and miscellaneous revenues include transmission revenue,
sales to municipalities and other wholesale energy sales.
The changes in electric retail revenues for the three months ended
September 30, 2003, as compared to the same period in 2002, are
attributable to the following:
Variance
-------------------------------------------------------------------------------------------------------------------
Weather $ (143)
Rate changes (52)
Customer choice (36)
Volume 40
Other effects 5
-------------------------------------------------------------------------------------------------------------------
Electric retail revenue $ (186)
===================================================================================================================
o Weather. The demand for electricity is impacted by weather conditions.
Very warm weather in summer months and very cold weather in other
months are referred to as "favorable weather conditions" because these
weather conditions result in increased sales of electricity.
Conversely, mild weather reduces demand. The weather impact for the
three months ended September 30, 2003 was unfavorable compared to the
same period in 2002 as a result of cooler summer weather in 2003.
Cooling degree-days decreased 25% in the three months
111
ended September 30, 2003 compared to the same period in 2002, and were
3% lower than normal.
o Rate Changes. The decrease in collection of CTCs in 2003 by ComEd of
$81 million due to a decrease in the CTC rates due to higher wholesale
market prices of electricity, net of increased mitigation factors.
This was partially offset by increased wholesale market prices which
increased energy revenue received under ComEd's PPO by $29 million.
Starting in the June 2003 billing cycle the increased wholesale market
price of electricity, net of increased mitigation factors, as a result
of the Agreement described in Note 5 of the Condensed Combined Notes
to Consolidated Financial Statements, decreases the collection of CTCs
as compared to the respective period in 2002.
o Customer Choice. All ComEd customers have the choice to purchase
energy from other suppliers. This choice generally does not impact the
volume of deliveries, but affects revenue collected from customers
related to energy supplied by ComEd. However, as of September 30,
2003, no ARES has sought approval from the ICC, and no electric
utilities have chosen to enter the ComEd residential market for the
supply of electricity.
For the three months ended September 30, 2003, the energy
provided by alternative suppliers was 5,081 GWhs, or 21.1%, as
compared to 4,131 GWhs, or 16.3%, for the three months ended September
30, 2002.
The decrease in revenues reflects customers in Illinois electing
to purchase energy from an ARES or the PPO. As of September 30, 2003,
the number of retail customers that had elected to purchase energy
from an ARES or the ComEd PPO was approximately 20,000, or 0.6%, as
compared to 22,700, or 0.6%, as of September 30, 2002. MWhs delivered
to such customers increased from approximately 6.5 million for the
three months ended September 30, 2002 to 7.3 million for the three
months ended September 30, 2003, or from 26% to 30% of total quarterly
retail deliveries.
o Volume. Revenues from higher delivery volume, exclusive of weather,
increased due to an increased usage per customer, primarily
residential and small commercial and industrial.
Wholesale and miscellaneous revenue for the three months ended
September 30, 2003 compared to the three months ended September 30, 2002
decreased $15 million primarily due to a 2002 reimbursement from Generation
of $12 million for third-party energy reconciliations.
Purchased Power
Purchased power expense decreased $84 million, or 9%, for the
three months ended September 30, 2003. The decrease in purchased power
expense was primarily attributable to a $75 million decrease due to
unfavorable weather conditions, a $42 million decrease as a result of
customers choosing to purchase energy from an ARES, a $20 million decrease
due to additional energy billed in 2002 under the PPA with Generation as a
result of third-party energy reconciliations discussed in the operating
revenue section above, partially offset by an increase of $22 million due
to higher volume, $21 million increase due to pricing changes related to
ComEd's PPA with Generation and an increase of $16 million under the PPA
related to decommissioning collections associated with the adoption of SFAS
No. 143. The $16 million increase in purchased power expense related to
SFAS No. 143 had no impact on net income as it was offset by lower
regulatory asset amortization in depreciation and amortization expense.
112
Operating and Maintenance
O&M expense increased $32 million, or 12%, for the three months
ended September 30, 2003. The increase in O&M expense was primarily
attributable to $60 million of The Exelon Way severance and related
postretirement health and welfare benefits accruals and pension and
postretirement curtailment costs and $12 million of additional
storm-related costs, partially offset by a 2002 $17 million increase in
manufactured gas plant (MGP) investigation and remediation reserve charges
net of 2003 increases, a decrease in payroll expenses of $15 million due to
fewer employees, and a decrease of $6 million in bad debt expense.
Depreciation and Amortization
Depreciation and amortization expense decreased $32 million, or
25%, for the three months ended September 30, 2003 as follows:
Three Months Ended September 30,
--------------------------------
2003 2002 Variance % Change
-------------------------------------------------------------------------------------------------------------------
Depreciation expense $ 77 $ 75 $ 2 2.7%
Recoverable transition costs amortization 12 33 (21) (63.6%)
Other amortization expense 8 21 (13) (61.9%)
-------------------------------------------------------------------------------------------------
Total depreciation and amortization $ 97 $ 129 $ (32) (24.8%)
=================================================================================================
The increase in depreciation expense is primarily due to higher
property, plant and equipment balances.
Recoverable transition costs amortization decreased in the three
months ended September 30, 2003 compared to the same period in 2002. The
decrease is a result of additional amortization in 2002. ComEd expects to
fully recover its recoverable transition costs regulatory asset balance of
$141 million by 2006. Consistent with the provision of the Illinois
legislation, regulatory assets may be recovered at amounts that provide
ComEd an earned return on common equity within the Illinois legislation
earnings threshold.
The decrease in other amortization primarily relates to the
reclassification of a regulatory asset for nuclear decommissioning as a
result of the adoption of SFAS No. 143 in 2003 (see Note 2 of the Condensed
Combined Notes to Consolidated Financial Statements). This decrease had no
impact on net income as it was offset by increased purchased power from
Generation.
Taxes Other Than Income
Taxes other than income increased by $10 million, or 13%, as a
result of a $5 million real estate tax refund in 2002 and $8 million in
2003 for use tax payments for periods prior to the Merger.
Interest Charges
Interest charges consist of interest expense and distributions on
mandatorily redeemable preferred securities. Interest charges decreased $16
million, or 12%, for the three months ended September 30, 2003 as a result
of scheduled principal payments and refinancing existing debt at lower
interest rates.
113
Other, Net
Other, net increased by $15 million for the three months ended
September 30, 2003 as compared to the same period in 2002. In 2002, ComEd
recorded a $12 million reserve accrual for a potential plant disallowance
from an audit performed in conjunction with ComEd's delivery services rate
case. This $12 million was reversed in March 2003 as a result of the March
3, 2003 agreement - as more fully described in Note 5 to the Condensed
Combined Notes to Consolidated Financial Statements.
Income Taxes
The effective income tax rate was 38.5% for the three months ended
September 30, 2003, compared to 40.4% for the three months ended September
30, 2002.
Nine Months Ended September 30, 2003 Compared to Nine Months Ended
September 30, 2002
Significant Operating Trends - ComEd
Nine Months Ended September 30,
-------------------------------
2003 2002 Variance % Change
-------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES $ 4,522 $ 4,734 $ (212) (4.5%)
OPERATING EXPENSES
Purchased power 2,001 2,066 (65) (3.1%)
Operating and maintenance 781 724 57 7.9%
Depreciation and amortization 287 397 (110) (27.7%)
Taxes other than income 235 223 12 5.4%
-----------------------------------------------------------------------------------------------------
Total operating expenses 3,304 3,410 (106) (3.1%)
-----------------------------------------------------------------------------------------------------
OPERATING INCOME 1,218 1,324 (106) (8.0%)
-----------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest expense (322) (374) 52 (13.9%)
Distributions on mandatorily redeemable preferred securities (20) (22) 2 (9.1%)
Other, net 48 29 19 65.5%
-----------------------------------------------------------------------------------------------------
Total other income and deductions (294) (367) 73 (19.9%)
-----------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES AND CUMULATIVE
EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE 924 957 (33) (3.4%)
INCOME TAXES 365 381 (16) (4.2%)
-----------------------------------------------------------------------------------------------------
NET INCOME BEFORE CUMULATIVE EFFECT OF
A CHANGE IN ACCOUNTING PRINCIPLE 559 576 (17) (3.0%)
CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING
PRINCIPLE 5 -- 5 n.m.
-----------------------------------------------------------------------------------------------------
NET INCOME $ 564 $ 576 $ (12) (2.1%)
=====================================================================================================
n.m. - not meaningful
Net Income
Net income decreased $12 million, or 2%, for the nine months ended
September 30, 2003 as compared to the same period in 2002. Net income was
negatively impacted by lower operating revenues net of purchased power
expense primarily due to unfavorable weather, and
114
charges associated with The Exelon Way severance partially offset by lower
depreciation and amortization expense and lower interest expense.
Operating Revenues
ComEd's electric sales statistics were as follows:
Nine Months Ended September 30,
-------------------------------
Retail Deliveries - (in GWhs) 2003 2002 Variance % Change
-------------------------------------------------------------------------------------------------------------------
Bundled Deliveries (1)
Residential 20,246 21,392 (1,146) (5.4%)
Small Commercial & Industrial 16,490 17,078 (588) (3.4%)
Large Commercial & Industrial 4,706 6,151 (1,445) (23.5%)
Public Authorities & Electric Railroads 4,018 5,097 (1,079) (21.2%)
-------------------------------------------------------------------------------------------------
45,460 49,718 (4,258) (8.6%)
-------------------------------------------------------------------------------------------------
Unbundled Deliveries (2)
ARES
----
Small Commercial & Industrial 4,327 3,822 505 13.2%
Large Commercial & Industrial 6,894 5,200 1,694 32.6%
Public Authorities & Electric Railroads 954 618 336 54.4%
-------------------------------------------------------------------------------------------------
12,175 9,640 2,535 26.3%
-------------------------------------------------------------------------------------------------
PPO
---
Small Commercial & Industrial 2,546 2,384 162 6.8%
Large Commercial & Industrial 3,646 3,952 (306) (7.7%)
Public Authorities & Electric Railroads 1,497 861 636 73.9%
-------------------------------------------------------------------------------------------------
7,689 7,197 492 6.8%
-------------------------------------------------------------------------------------------------
Total Unbundled Deliveries 19,864 16,837 3,027 18.0%
-------------------------------------------------------------------------------------------------
Total Retail Deliveries 65,324 66,555 (1,231) (1.8%)
=================================================================================================
(1) Bundled service reflects deliveries to customers taking electric
service under tariffed rates.
(2) Unbundled service reflects customers electing to receive electric
generation service from an ARES or the PPO.
115
Nine Months Ended September 30,
-------------------------------
Electric Revenue 2003 2002 Variance % Change
-------------------------------------------------------------------------------------------------------------------
Bundled Revenues (1)
Residential $ 1,778 $ 1,881 $ (103) (5.5%)
Small Commercial & Industrial 1,289 1,343 (54) (4.0%)
Large Commercial & Industrial 240 324 (84) (25.9%)
Public Authorities & Electric Railroads 247 297 (50) (16.8%)
-------------------------------------------------------------------------------------------------
3,554 3,845 (291) (7.6%)
-------------------------------------------------------------------------------------------------
Unbundled Revenues (2)
ARES
----
Small Commercial & Industrial 106 94 12 12.8%
Large Commercial & Industrial 133 101 32 31.7%
Public Authorities & Electric Railroads 25 18 7 38.9%
-------------------------------------------------------------------------------------------------
264 213 51 23.9%
-------------------------------------------------------------------------------------------------
PPO
---
Small Commercial & Industrial 174 155 19 12.3%
Large Commercial & Industrial 199 214 (15) (7.0%)
Public Authorities & Electric Railroads 81 48 33 68.8%
-------------------------------------------------------------------------------------------------
454 417 37 8.9%
-------------------------------------------------------------------------------------------------
Total Unbundled Revenues 718 630 88 14.0%
-------------------------------------------------------------------------------------------------
Total Electric Retail Revenues 4,272 4,475 (203) (4.5%)
Wholesale and Miscellaneous Revenue (3) 250 259 (9) (3.5%)
-------------------------------------------------------------------------------------------------
Total Electric Revenue $ 4,522 $ 4,734 $ (212) (4.5%)
=================================================================================================
(1) Bundled revenue reflects deliveries to customers taking electric
service under tariffed rates, which include the cost of energy and the
delivery cost of the transmission and the distribution of the energy.
(2) Revenue from customers choosing an ARES includes a distribution charge
and a CTC charge. Transmission charges received from ARES are included
in wholesale and miscellaneous revenue. Revenue from customers choosing
the PPO includes an energy charge at market rates, transmission and
distribution charges, and a CTC charge.
(3) Wholesale and miscellaneous revenues include transmission revenue,
sales to municipalities and other wholesale energy sales.
The changes in electric retail revenues for the nine months ended
September 30, 2003, as compared to the same period in 2002, are
attributable to the following:
Variance
-------------------------------------------------------------------------------------------------------------------
Weather $ (197)
Customer choice (113)
Volume 72
Rate changes 23
Other effects 12
-------------------------------------------------------------------------------------------------------------------
Electric retail revenue $ (203)
===================================================================================================================
o Weather. The weather impact for the nine months ended September 30,
2003 was unfavorable compared to the same period in 2002 as a result
of cooler summer weather in 2003. Cooling degree-days decreased 36% in
the nine months ended September 30, 2003 compared to the same period
in 2002 and were partially offset by a 15% increase in heating degree
days in the nine months ended September 30, 2003 compared to the same
period in 2002.
116
o Customer Choice. The decrease in revenues reflects customers in
Illinois electing to purchase energy from an ARES or the PPO.
For the nine months ended September 30, 2003, the energy provided
by alternative suppliers was 12,175 GWhs, or 18.6%, as compared to
9,640 GWhs, or 14.5%, for the nine months ended September 30, 2002.
As of September 30, 2003, the number of retail customers that had
elected to purchase energy from an ARES or the ComEd PPO was
approximately 20,000, or 0.6%, as compared to 22,700, or 0.6%, as of
September 30, 2002. MWhs delivered to such customers increased from
approximately 16.8 million for the nine months ended September 30,
2002 to 19.9 million for the nine months ended September 30, 2003, or
from 25% to 30% of total year-to-date retail deliveries.
o Volume. Revenues from higher delivery volume, exclusive of weather,
increased due to an increased number of customers and increased usage
per customer, primarily residential and small commercial and
industrial.
o Rate Changes. The increase in revenues attributable to rate changes
reflects the collection of additional CTCs in 2003 by ComEd of $65
million due to an increase in sales to customers choosing an ARES or
the ComEd PPO and an increase in CTC rates due to the lower wholesale
market price of electricity, net of increased mitigation factors.
Lower wholesale market prices decreased revenue received under ComEd's
PPO by $42 million. Starting in the June 2003 billing cycle, the
increased wholesale market price of electricity, net of increased
mitigation factors, as a result of the Agreement described in Note 5
of the Condensed Combined Notes to Consolidated Financial Statements,
decreases the collection of CTCs as compared to the respective period
in 2002.
Wholesale and miscellaneous revenue for the nine months ended
September 30, 2003 compared to the nine months ended September 30, 2002
decreased $9 million primarily due to a 2002 reimbursement from Generation
of $12 million for third-party energy reconciliations.
Purchased Power
Purchased power expense decreased $65 million, or 3%, for the nine
months ended September 30, 2003. The decrease in purchased power expense
was primarily attributable to a $102 million decrease due to unfavorable
weather and a $91 million decrease as a result of customers choosing to
purchase energy from an ARES, a $20 million decrease due to additional
energy billed in 2002 under the PPA with Generation as a result of
third-party energy reconciliations discussed in the operating revenue
section above, partially offset by an increase of $44 million due to higher
volume, an increase of $60 million due to pricing changes related to
ComEd's PPA with Generation and an increase of $47 million under the PPA
related to decommissioning collections associated with the adoption of SFAS
No. 143 that were not included in purchased power in 2002. The $47 million
increase in purchased power expense related to SFAS No. 143 had no impact
on net income as it was offset by lower regulatory asset amortization in
depreciation and amortization expense.
Operating and Maintenance
O&M expense increased $57 million, or 8%, for the nine months
ended September 30, 2003. The increase in O&M expense was primarily
attributable to a net one-time charge of $41 million in 2003 as the result
of the Agreement as more fully described in Note 5 of the
117
Condensed Combined Notes to Consolidated Financial Statements, $60 million
due to The Exelon Way severance and related postretirement health and
welfare benefits accruals and pension and postretirement curtailment costs,
$13 million of additional storm-related costs and $16 million increase in
employee fringe benefits partially offset by $5 million of higher corporate
allocations in 2002 due to executive severance, $12 million lower MGP
investigation and remediation reserve charges, net of 2003 increases, and
$53 million decrease in payroll expenses due to fewer employees.
Depreciation and Amortization
Depreciation and amortization expense decreased $110 million, or
28%, for the nine months ended September 30, 2003 as follows:
Nine Months Ended September 30,
-------------------------------
2003 2002 Variance % Change
-------------------------------------------------------------------------------------------------------------------
Depreciation expense $ 229 $ 258 $ (29) (11.2%)
Recoverable transition costs amortization 34 75 (41) (54.7%)
Other amortization expense 24 64 (40) (62.5%)
-------------------------------------------------------------------------------------------------
Total depreciation and amortization $ 287 $ 397 $ (110) (27.7%)
=================================================================================================
The decrease in depreciation expense is primarily due to lower
depreciation rates effective July 1, 2002, partially offset by higher
property, plant and equipment balances. ComEd completed a depreciation
study and implemented lower depreciation rates effective July 1, 2002. The
new depreciation rates reflect ComEd's significant construction program in
recent years, changes in and development of new technologies, and changes
in estimated plant service lives since the last depreciation study. The
annual reduction in depreciation expense is estimated to be approximately
$100 million ($60 million, net of income taxes) based on December 31, 2001
plant balances. As a result of the change, depreciation expense decreased
$48 million ($29 million, net of income taxes) for the nine months ended
September 30, 2003. The decrease in depreciation expense is partially
offset by increased depreciation due to capital additions.
Recoverable transition costs amortization decreased in the nine
months ended September 30, 2003 compared to the same period in 2002. The
decrease is a result of additional amortization in 2002. ComEd expects to
fully recover its recoverable transition costs regulatory asset balance of
$141 million by 2006. Consistent with the provision of the Illinois
legislation, regulatory assets may be recovered at amounts that provide
ComEd an earned return on common equity within the Illinois legislation
earnings threshold.
The decrease in other amortization primarily relates to the
reclassification of a regulatory asset for nuclear decommissioning as a
result of the adoption of SFAS No. 143 in 2003 (see Note 2 of the Condensed
Combined Notes to Consolidated Financial Statements). This decrease had no
impact on net income as it was offset by increased purchased power from
Generation.
Taxes Other Than Income
Taxes other than income increased $12 million or 5%, for the nine
months ended September 30, 2003 primarily as a result of $5 million in
Illinois Public Utility Fund taxes that were not charged in 2002, a $5
million real estate tax refund in 2002 and $8 million in 2003 for
118
use tax payments for periods prior to the Merger, partially offset by a $5
million refund in 2003 of Illinois Electricity Distribution taxes.
Interest Charges
Interest charges consist of interest expense and distributions on
mandatorily redeemable preferred securities. Interest charges decreased $54
million, or 14%, for the nine months ended September 30, 2003. The decrease
in interest expense was primarily attributable to the impact of lower
interest rates as a result of refinancing existing debt at lower interest
rates for the nine months ended September 30, 2003 as compared to the nine
months ended September 30, 2002 and the annual retirement of $340 million
in Transitional Trust Notes.
Other, Net
Other, net increased $19 million or 66%, for the nine months ended
September 30, 2003 as compared to the same period in 2002. In 2002, ComEd
recorded a $12 million reserve accrual for a potential plant disallowance
from an audit performed in conjunction with ComEd's delivery services rate
case. This $12 million was reversed in March 2003 as a result of the March
3, 2003 agreement - as more fully described in Note 5 to the Condensed
Combined Notes to Consolidated Financial Statements.
Income Taxes
The effective income tax rate was 39.5% for the nine months ended
September 30, 2003, compared to 39.8% for the nine months ended September
30, 2002.
Due to revenue needs in the states in which ComEd operates,
various state income tax and fee increases have been proposed or are being
contemplated. If these changes are enacted, they could increase ComEd's
state income tax expense. At this time, however, ComEd cannot predict
whether legislation or regulation will be introduced, the form of any
legislation or regulation, whether any such legislation or regulation will
be passed by the state legislatures or regulatory bodies, and, if enacted,
whether any such legislation or regulation would be effective retroactively
or prospectively. As a result, ComEd cannot currently estimate the effect
of these potential changes in tax laws or regulation.
Cumulative Effect of a Change in Accounting Principle
On January 1, 2003, ComEd adopted SFAS No. 143, resulting in
income of $5 million, net of tax. See Note 2 of the Condensed Combined
Notes to Consolidated Financial Statements for further discussion of the
adoption of SFAS No. 143.
LIQUIDITY AND CAPITAL RESOURCES
ComEd's business is capital intensive and requires considerable
capital resources. ComEd's capital resources are primarily provided by
internally generated cash flows from operations and, to the extent
necessary, external financing including the issuance of commercial paper,
participation in the intercompany money pool or capital contributions from
Exelon. ComEd's access to external financing at reasonable terms is
dependent on its credit ratings and general business conditions, as well as
that of the utility industry in general. If these conditions deteriorate to
where ComEd no longer has access to external financing sources at
reasonable
119
terms, ComEd has access to a revolving credit facility that ComEd currently
utilizes to support its commercial paper program. See the Credit Issues
section of Liquidity and Capital Resources for further discussion. Capital
resources are used primarily to fund ComEd's capital requirements,
including construction, repayments of maturing debt and the payment of
dividends.
As part of the implementation of The Exelon Way, ComEd has
identified 451 positions for elimination by the end of 2004 and anticipates
identifying additional positions for elimination in 2005 and 2006. ComEd
recorded a charge for cash severance of $37 million during the third quarter
2003, which ComEd anticipates will be paid by December 31, 2004. ComEd
anticipates incurring further costs associated with The Exelon Way upon
identifying additional positions to be eliminated. These costs will be
recorded in the period in which the costs can be reasonably estimated.
Cash Flows from Operating Activities
Cash flows provided by operations were $742 million for the nine
months ended September 30, 2003 compared to $1.5 billion for the nine
months ended September 30, 2002. The decrease in cash flows in 2003 was
primarily attributable to a $504 million decrease in working capital as a
result of the paydown of payables to affiliates and other outstanding
liabilities, a decrease of $127 million for pension and non-pension
postretirement benefits obligation, a decrease in depreciation and
amortization of $110 million. ComEd's future cash flows will depend upon
the ability to achieve cost savings in operations and the impact of the
economy, weather, customer choice and future regulatory proceedings on its
revenues. Although the amounts may vary from period to period as a result
of uncertainties inherent in the business, ComEd expects to continue to
provide a reliable and steady source of internal cash flow from operations
for the foreseeable future.
Cash Flows from Investing Activities
Cash flows used in investing activities were $450 million for the
nine months ended September 30, 2003 compared to $528 million for the nine
months ended September 30, 2002. The decrease in cash flows used in
investing activities in 2003 was primarily attributable to the receipt of
$213 million from Unicom Investments Inc. related to an intercompany note
payable partially offset by $147 million invested in the Exelon
intercompany money pool.
ComEd estimates that it will spend approximately $720 million in
total capital expenditures for 2003. Approximately two-thirds of the
budgeted 2003 expenditures are for continuing efforts to further improve
the reliability of its transmission and distribution systems. The remaining
one third is for capital additions to support new business and customer
growth. ComEd anticipates that its capital expenditures will be funded by
internally generated funds, borrowings, the issuance of preferred
securities, or capital contributions from Exelon. ComEd's proposed capital
expenditures and other investments are subject to periodic review and
revision to reflect changes in economic conditions and other factors.
120
Cash Flows from Financing Activities
Cash flows used in financing activities were $186 million for the
nine months ended September 30, 2003 as compared to cash flows used in
financing of $970 million for the nine months ended September 30, 2002.
Cash flows used in financing activities were primarily attributable to debt
issuances and payments of dividends to Exelon, partially offset by
retirements and redemptions. The decrease in cash flows used in financing
activities is primarily attributable to increased debt and preferred
securities issuances of $926 million, partially offset by increased debt
and preferred securities redemptions of $139 million and increased interest
rate swap settlement payments of $35 million. See Note 12 of the Condensed
Combined Notes to Consolidated Financial Statements for further discussion
of ComEd's debt and preferred securities financing activities. ComEd paid a
$305 million dividend to Exelon during the nine months ended September 30,
2003 compared to a $353 million dividend for the nine months ended
September 30, 2002.
Credit Issues
ComEd meets its short-term liquidity requirements primarily
through the issuance of commercial paper. ComEd, along with Exelon, PECO
and Generation, participates in a $1.5 billion unsecured 364-day revolving
credit facility with a group of banks. The credit facility that became
effective on November 22, 2002 includes a term-out option that allows any
outstanding borrowings at the end of the revolving credit period to be
repaid on November 21, 2004. Exelon may increase or decrease the sublimits
of each of the participants upon written notification to the banks. As of
September 30, 2003, ComEd's sublimit was $100 million. The credit facility
is used principally to support ComEd's commercial paper program. At
September 30, 2003, ComEd had no commercial paper outstanding. For the nine
months ended September 30, 2003, the average interest rate on notes payable
was approximately 1.47%.
The credit facility requires ComEd to maintain a cash from
operations to interest expense ratio for the twelve-month period ended on
the last day of any quarter. The ratio excludes revenues and interest
expenses attributable to securitization of debt, certain changes in working
capital, and distributions on preferred securities of subsidiaries. ComEd's
threshold for the ratio reflected in the credit agreement cannot be less
than 2.25 to 1 for the twelve-month period ended September 30, 2003. At
September 30, 2003, ComEd was in compliance with the credit agreement
thresholds.
To provide an additional short-term borrowing option that will
generally be more favorable to the borrowing participants than the cost of
external financing, Exelon operates an intercompany money pool.
Participation in the money pool is subject to authorization by the Exelon
corporate treasurer. ComEd, PECO, Generation and BSC may participate in the
money pool as lenders and borrowers, and Exelon Corporate may participate
as a lender. Funding of, and borrowings from, the money pool are predicated
on whether such funding results in mutual economic benefits to each of the
participants. Interest on borrowings is based on short-term market rates of
interest, or, if from an external source, specific borrowing rates. There
were no material money pool transactions in 2002. During the nine months
ended September 30, 2003, ComEd had various investments in the money pool.
The maximum amount of outstanding
121
investments at any time during 2003 was $344 million. As of September 30,
2003, ComEd's investment in the money pool was $147 million. For the nine
months ended September 30, 2003, ComEd earned $2 million in interest.
ComEd's access to the capital markets, including the commercial
paper market, and its financing costs in those markets are dependent on its
securities ratings. None of ComEd's borrowings is subject to default or
prepayment as a result of a downgrading of securities ratings although such
a downgrading could increase interest charges under certain bank credit
facilities.
Under PUHCA, ComEd is precluded from lending or extending credit
or indemnity to Exelon and can only pay dividends from retained or current
earnings. Furthermore, a significant loss recorded at ComEd may limit the
dividends that ComEd can distribute to Exelon. However, the SEC has
authorized ComEd to pay up to $500 million in dividends out of additional
paid-in capital, provided ComEd may not pay dividends out of paid-in
capital after December 31, 2002 if its common equity is less than 30% of
its total capitalization (including transitional trust notes). At September
30, 2003, ComEd had retained earnings of $836 million and its common equity
ratio was 47%. Long-term debt included $1.7 billion of transitional trust
notes.
Contractual Obligations, Commercial Commitments and Off-Balance Sheet
Obligations
Contractual obligations represent cash obligations that are
considered to be firm commitments and commercial commitments represent
commitments triggered by future events. ComEd's contractual obligations and
commercial commitments as of September 30, 2003 were materially unchanged,
other than in the normal course of business, from the amounts set forth in
the 2002 Form 10-K except for the following:
o On March 3, 2003, ComEd entered into the Agreement with various
Illinois electric retail market suppliers, key customer groups and
governmental parties regarding several matters affecting ComEd's rates
for electric service. The Agreement addressed, among other things,
issues related to ComEd's delivery services rate proceeding, market
value index proceeding, the process for competitive service
declarations for large-load customers and an extension of the PPA with
Generation. During the second quarter of 2003, the ICC issued orders
consistent with the Agreement, which is now effective.
The Agreement provides for a modification of the methodology used
to determine ComEd's market value energy credit. That credit is used
to determine the price for specified market-based rate offerings and
the amount of the CTC that ComEd is allowed to collect from customers
who select an ARES or the PPO. The credit was adjusted upwards through
agreed upon "adders" which took effect in June 2003 and will have the
effect of reducing ComEd's CTC charges to customers. Prior to the
Agreement, all CTC charges were subject to annual mid-year adjustments
based on the forward market prices for on-peak energy and historical
market prices for off-peak energy. The Agreement provides that the
annual market price adjustment will reflect forward market prices for
energy, rather than historical, and allows customers an option to lock
in current levels of CTC charges for multi-year periods during the
regulatory transition period ending in 2006. These changes provide
customers and
122
suppliers greater price certainty and are expected to result in an
increase in the number of customers electing to purchase energy from
alternate suppliers.
The annual market price adjustments to the CTC effective in June
2002 and June 2003 had the effect of significantly increasing the CTC
charge in June 2002, and subsequently significantly reducing the CTC
charge in June 2003. In 2002, ComEd collected $306 million in CTC
revenue. Based on the changes in the CTC as part of the Agreement and
on current assumptions about the competitive price of delivered energy
and customers' choice of electric supplier, ComEd estimates that CTC
revenue will be approximately $300 million in 2003 and approximately
$140 million for each of the years 2004 through 2006.
In the first quarter of 2003, ComEd recorded a charge to earnings
associated with the funding of specified programs and initiatives
associated with the Agreement of $51 million on a present value basis
before income taxes. This amount is partially offset by the reversal
of a $12 million (before income taxes) reserve established in the
third quarter of 2002 for a potential capital disallowance in ComEd's
delivery services rate proceeding and a credit of $10 million (before
income taxes) related to the capitalization of employee incentive
payments provided for in the delivery services order. The net one-time
charge for these items is $29 million (before income taxes).
o ComEd has entered into several agreements with a tax consultant
related to the filing of refund claims with the IRS and has made
refundable prepayments of $11 million for potential fess associated
with these agreements. The fees for these agreements are contingent
upon a successful outcome and are based upon a percentage of the
refunds recovered from the IRS, if any. As such, ultimate net cash
flows to ComEd related to these agreements will either be positive or
neutral depending upon the outcome of the refund claim with the IRS.
These potential tax benefits and associated fees could be material to
the financial position, results of operations and cash flows of ComEd.
ComEd's tax benefits for periods prior to the Merger would be recorded
as a reduction of goodwill pursuant to a reallocation of the Merger
purchase price. ComEd cannot predict the timing of the final
resolution of these refund claims.
o See Note 12 to the Condensed Combined Notes to Consolidated Financial
Statements for discussion of material changes in ComEd's debt and
preferred securities obligations from those set forth in the 2002 Form
10-K.
o See Note 9 of the Condensed Combined Notes to Consolidated Financial
Statements for the commercial commitments table representing ComEd's
commitments not recorded on the balance sheet but potentially
triggered by future events, including obligations to make payment on
behalf of other parties and financing arrangements to secure their
obligations.
123
PECO ENERGY COMPANY
-------------------
GENERAL
PECO operates in a single business segment, and its operations
consist of the regulated sale of electricity and distribution and
transmission in southeastern Pennsylvania and the sale of natural gas and
distribution services in the Pennsylvania counties surrounding the City of
Philadelphia.
RESULTS OF OPERATIONS
Three Months Ended September 30, 2003 Compared to Three Months Ended
September 30, 2002
Significant Operating Trends - PECO
Three Months Ended September 30,
--------------------------------
2003 2002 Variance % Change
-------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES $ 1,149 $ 1,224 $ (75) (6.1%)
OPERATING EXPENSES
Purchased power 482 509 (27) (5.3%)
Fuel 28 40 (12) (30.0%)
Operating and maintenance 192 140 52 37.1%
Depreciation and amortization 134 127 7 5.5%
Taxes other than income 12 85 (73) (85.9%)
-----------------------------------------------------------------------------------------------------
Total operating expenses 848 901 (53) (5.9%)
-----------------------------------------------------------------------------------------------------
OPERATING INCOME 301 323 (22) (6.8%)
-----------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest expense (73) (93) 20 (21.5%)
Interest expense to affiliate (2) -- (2) n.m.
Distributions on mandatorily redeemable preferred securities (1) (2) 1 (50.0%)
Other, net (10) 5 (15) n.m.
-----------------------------------------------------------------------------------------------------
Total other income and deductions (86) (90) 4 (4.4%)
-----------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 215 233 (18) (7.7%)
INCOME TAXES 74 76 (2) (2.6%)
-----------------------------------------------------------------------------------------------------
NET INCOME 141 157 (16) (10.2%)
Preferred stock dividends (1) (2) 1 (50.0%)
-----------------------------------------------------------------------------------------------------
NET INCOME ON COMMON STOCK $ 140 $ 155 $ (15) (9.7%)
=====================================================================================================
n.m. - not meaningful
124
Net Income
Net income on common stock decreased $15 million, or 10%, for the
three months ended September 30, 2003 as compared to the same period in
2002. The decrease was a result of lower sales volume, unfavorable weather
conditions, increased O&M related to storm-related damage, and The Exelon
Way severance costs, partially offset by lower other operating and
maintenance expenses, taxes other than income and interest expense on debt.
Operating Revenue
PECO's electric sales statistics were as follows:
Three Months Ended September 30,
--------------------------------
Retail Deliveries - (in GWhs) 2003 2002 Variance % Change
-------------------------------------------------------------------------------------------------------------------
Bundled Deliveries (1)
Residential 3,333 3,422 (89) (2.6%)
Small Commercial & Industrial 1,753 2,066 (313) (15.2%)
Large Commercial & Industrial 4,013 4,006 7 0.2%
Public Authorities & Electric Railroads 217 224 (7) (3.1%)
-------------------------------------------------------------------------------------------------
9,316 9,718 (402) (4.1%)
-------------------------------------------------------------------------------------------------
Unbundled Deliveries (2)
Residential 258 371 (113) (30.5%)
Small Commercial & Industrial 520 154 366 n.m.
Large Commercial & Industrial 208 236 (28) (11.9%)
Public Authorities & Electric Railroads (3) -- -- -- --
-------------------------------------------------------------------------------------------------
986 761 225 29.6%
-------------------------------------------------------------------------------------------------
Total Retail Deliveries 10,302 10,479 (177) (1.7%)
=================================================================================================
(1) Bundled service reflects deliveries to customers taking electric
service under tariffed rates.
(2) Unbundled service reflects customers electing to receive electric
generation service from an alternative energy supplier.
(3) PECO's unbundled sales to Public Authorities and Electric Railroads
were less than one GWh per quarter.
125
Three Months Ended September 30,
--------------------------------
Electric Revenue 2003 2002 Variance % Change
-------------------------------------------------------------------------------------------------------------------
Bundled Revenue (1)
Residential $ 466 $ 478 $ (12) (2.5%)
Small Commercial & Industrial 211 251 (40) (15.9%)
Large Commercial & Industrial 292 296 (4) (1.4%)
Public Authorities & Electric Railroads 19 21 (2) (9.5%)
-------------------------------------------------------------------------------------------------
988 1,046 (58) (5.5%)
-------------------------------------------------------------------------------------------------
Unbundled Revenue (2)
Residential 20 32 (12) (37.5%)
Small Commercial & Industrial 28 9 19 n.m.
Large Commercial & Industrial 5 7 (2) (28.6%)
Public Authorities & Electric Railroads (3) -- -- -- --
-------------------------------------------------------------------------------------------------
53 48 5 10.4%
-------------------------------------------------------------------------------------------------
Total Electric Retail Revenues 1,041 1,094 (53) (4.8%)
Wholesale and Miscellaneous Revenue (4) 55 63 (8) (12.7%)
-------------------------------------------------------------------------------------------------
Total Electric Revenue $ 1,096 $ 1,157 $ (61) (5.3%)
=================================================================================================
(1) Bundled revenue reflects revenue from customers taking electric service
under tariffed rates, which includes the cost of energy, the delivery
cost of the transmission and the distribution of the energy and a CTC
charge.
(2) Unbundled revenue reflects revenue from customers electing to receive
generation from an alternative supplier, which includes a distribution
charge and a CTC charge.
(3) PECO's unbundled sales to Public Authorities and Electric Railroads
were less than $1 million per quarter.
(4) Wholesale and miscellaneous revenues include transmission revenue and
other wholesale energy sales.
The changes in electric retail revenues for the three months ended
September 30, 2003, as compared to the same period in 2002, were as
follows:
Variance
-------------------------------------------------------------------------------------------------------------------
Rate mix $ (21)
Weather (18)
Customer choice (14)
Volume 1
Other effects (1)
-------------------------------------------------------------------------------------------------------------------
Retail revenue $ (53)
===================================================================================================================
o Rate Mix. The decrease in revenues from rate mix is due to changes in
monthly usage patterns in all customer classes during the three months
ended September 30, 2003 as compared to the same period in 2002.
o Weather. The demand for electricity is impacted by weather conditions.
Very warm weather in summer months and very cold weather in other
months are referred to as "favorable weather conditions" because these
weather conditions result in increased sales of electricity.
Conversely, mild weather reduces demand. The weather impact was
unfavorable compared to the prior year as a result of cooler summer
weather during the quarter. Cooling degree-days decreased 11%.
o Customer Choice. All PECO customers may choose to purchase energy from
other suppliers. This choice generally does not impact kWh deliveries,
but reduces revenue collected from customers because they are not
obtaining generation supply from PECO.
126
For the three months ended September 30, 2003, the energy
provided by alternative suppliers was 986 GWhs, or 9.6%, as compared
to 761 GWhs, or 7.3%, for the three months ended September 30, 2002.
As of September 30, 2003, the number of customers served by
alternative suppliers was 297,821, or 19.6%, as compared to 285,549,
or 18.7%, as of September 30, 2002.
The PUC's Final Electric Restructuring Order established MST to
promote competition. The MST requirements provide that if, as of
January 1, 2003, less than 50% of residential and commercial customers
have chosen an alternative electric generation supplier, the number of
customers sufficient to meet the MST shall be randomly selected and
assigned to an alternative electric generation supplier through a PUC
determined process. On January 1, 2003, the number of customers
choosing an alternative electric generation supplier did not meet the
MST. In January 2003, PECO submitted to the PUC an MST plan to meet
the 50% threshold requirement for its commercial customers, which was
approved by the PUC in February 2003. As of March 31, 2003, an auction
had been completed for the commercial customers. In May 2003, the
customer enrollment phase was completed and customers that did not
choose to opt out of the program were transferred to the alternative
electric generation suppliers. In February 2003, PECO filed a
residential customer MST plan, and on May 1, 2003, the PUC approved
the plan. The approved plan provides for a two-step process with a
total of up to 400,000 residential customers being assigned to winning
alternative electric generation supplier bidders: up to 100,000 in
July 2003, and another 300,000 in December 2003. The auction for the
first phase of the residential program received no supplier bids.
Therefore, according to the MST plan requirements, 75% of those
customers are required to be added to the auction for the second phase
of the residential program for a total of 375,000 customers. In
September 2003, the auction for the second phase of the residential
customer MST plan resulted in two winning bidders who were awarded an
aggregate of 267,000 residential customers. The selected customers
will be transferred during December 2003. No renewable bids were
received for any customers. Any customer transferred has the right to
return to PECO at any time. PECO does not expect the transfer of
customers pursuant to the MST plan to have a material impact on its
results of operations, financial position or cash flows.
o Volume. Exclusive of weather impacts, higher delivery volume affected
PECO's revenue by $1 million compared to the same period in 2002
primarily related to decreases in usage by the residential class
offset by an increase in usage by the small commercial and industrial
class.
127
PECO's gas sales statistics for the three months ended September
30, 2003 as compared to the same period in 2002 were as follows:
Three Months Ended September 30,
--------------------------------
Deliveries to customers in mmcf 2003 2002 Variance % Change
-------------------------------------------------------------------------------------------------------------------
Retail sales 3,498 3,805 (307) (8.1%)
Transportation 6,012 7,542 (1,530) (20.3%)
-----------------------------------------------------------------------------------------------------
Total 9,510 11,347 (1,837) (16.2%)
=====================================================================================================
Three Months Ended September 30,
--------------------------------
Revenue 2003 2002 Variance % Change
-------------------------------------------------------------------------------------------------------------------
Retail sales $ 47 $ 43 $ 4 9.3%
Transportation 4 5 (1) (20.0%)
Resales and other 2 19 (17) (89.5%)
-----------------------------------------------------------------------------------------------------
Total $ 53 $ 67 $ (14) (20.9%)
=====================================================================================================
The changes in gas retail revenue for the three months ended
September 30, 2003 as compared to the same period in 2002, were as follows:
Variance
-------------------------------------------------------------------------------------------------------------------
Rate changes $ 6
Volume (2)
-------------------------------------------------------------------------------------------------------------------
Total gas retail revenues $ 4
===================================================================================================================
o Rate Changes. The favorable variance in rate changes is attributable
to increases of 15% and 7% in the purchased gas adjustment by the PUC
effective March 1, 2003 and June 1, 2003, respectively. The average
rate per million cubic feet for the three months ended September 30,
2003 was 18% higher than the same period in 2002. PECO's gas rates are
subject to periodic adjustments by the PUC and are designed to recover
from or refund to customers the difference between the actual cost of
purchased gas and the amount included in base rates and to recover or
refund increases or decreases in certain state taxes not recovered in
base rates.
o Volume. Delivery volume was lower in the three months ended September
30, 2003 compared to the same period in 2002 due to decreased retail
sales in all customer classes.
The reduction in transportation volumes and revenues are primarily
the result of lower intercompany deliveries to Generation during the three
months ended September 30, 2003 compared to the same period in 2002.
Lower resale revenues are attributable to a decrease in off-system
sales, exchanges and capacity releases during the three months ended
September 30, 2003 compared to the same period in 2002.
128
Purchased Power
Purchased power expense for the three months ended September 30,
2003 decreased $27 million, or 5%, as compared to the same period in 2002.
The decrease in purchased power expense was primarily attributable to $11
million of unfavorable weather conditions, $11 million from customers in
Pennsylvania selecting an alternative electric generation supplier and $9
million related to lower PJM ancillary charges, partially offset by higher
delivery volumes of $3 million.
Fuel
Fuel expense for the three months ended September 30, 2003
decreased $12 million, or 30%, as compared to the same period in 2002. This
decrease was primarily attributable to lower wholesale sales of gas of $17
million, partially offset by higher gas prices and volumes of $4 million.
Operating and Maintenance
O&M expense for the three months ended September 30, 2003
increased $52 million, or 37%, as compared to the same period in 2002. The
increase in O&M expense was primarily attributable to $41 million of
severance and related postretirement health and welfare benefits accruals
and pension and postretirement curtailment costs associated with The Exelon
Way, $18 million of higher storm-related costs, $4 million of higher
corporate allocations, and $2 million of higher expense related to the
allowance for the uncollectible accounts, partially offset by $10 million
of lower costs associated with the initial implementation of automated
meter reading services in 2002 and a $7 million decrease in payroll
expense.
Depreciation and Amortization
Depreciation and amortization expense for the three months ended
September 30, 2003 increased $7 million, or 6%, as compared to the same
period in 2002 was as follows:
Three Months Ended September 30,
--------------------------------
2003 2002 Variance % Change
-------------------------------------------------------------------------------------------------------------------
Competitive transition charge amortization $ 96 $ 90 $ 6 6.7%
Depreciation expense 33 31 2 6.5%
Other amortization expense 5 6 (1) (16.7%)
-------------------------------------------------------------------------------------------------
Total depreciation and amortization $ 134 $ 127 $ 7 5.5%
=================================================================================================
The additional amortization of the CTC is in accordance with
PECO's original settlement under the Pennsylvania Competition Act.
Taxes Other Than Income
Taxes other than income for the three months ended September 30,
2003 decreased $73 million, or 86%, as compared to the same period in 2002.
The decrease was primarily attributable to $58 million related to the
reversal of real estate tax accruals during the third quarter of 2003, $9
million related to 2002 real estate tax expense, $3 million related to 2002
capital stock tax and $3 million of lower gross receipts tax related to
lower revenues.
129
Interest Charges
Interest charges consist of interest expense, interest expense to
affiliate and distributions on mandatorily redeemable preferred securities.
Interest charges decreased $19 million, or 20%, in the three months ended
September 30, 2003 as compared to the same period in 2002. The decrease was
primarily attributable to lower interest expense on long-term debt of $10
million as a result of less outstanding debt and refinancing of existing
debt at lower rates, and a reversal of accrued interest expense on federal
income taxes of $8 million.
Other, Net
Other, net decreased income by $15 million in the three months
ended September 30, 2003 as compared to the same period in 2002. The
decrease was attributable to reversal of interest income on federal income
taxes.
Income Taxes
The effective tax rate was 34.4% for the three months ended
September 30, 2003 as compared to 32.6% for the same period in 2002. The
increase in the effective tax rate primarily reflects the impact of changes
in income before income taxes.
Preferred Stock Dividends
Preferred stock dividends for the three months ended September 30,
2003 were consistent as compared to the same period in 2002.
130
Nine Months Ended September 30, 2003 Compared to Nine Months Ended
September 30, 2002
Significant Operating Trends - PECO
Nine Months Ended September 30,
-------------------------------
2003 2002 Variance % Change
-------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES $ 3,328 $ 3,239 $ 89 2.7%
OPERATING EXPENSES
Purchased power 1,290 1,265 25 2.0%
Fuel 285 228 57 25.0%
Operating and maintenance 453 407 46 11.3%
Depreciation and amortization 370 348 22 6.3%
Taxes other than income 123 207 (84) (40.6%)
-----------------------------------------------------------------------------------------------------
Total operating expenses 2,521 2,455 66 2.7%
-----------------------------------------------------------------------------------------------------
OPERATING INCOME 807 784 23 2.9%
-----------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest expense (241) (280) 39 (13.9%)
Interest expense to affiliate (2) -- (2) n.m.
Distributions on mandatorily redeemable preferred securities (6) (7) 1 (14.3%)
Other, net -- 7 (7) n.m.
-----------------------------------------------------------------------------------------------------
Total other income and deductions (249) (280) 31 (11.1%)
-----------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 558 504 54 10.7%
INCOME TAXES 193 166 27 16.3%
-----------------------------------------------------------------------------------------------------
NET INCOME 365 338 27 8.0%
Preferred stock dividends (4) (6) 2 (33.3%)
-----------------------------------------------------------------------------------------------------
NET INCOME ON COMMON STOCK $ 361 $ 332 $ 29 8.7%
=====================================================================================================
n.m. - not meaningful
Net Income
Net income on common stock increased $29 million, or 9%, for the
nine months ended September 30, 2003 as compared to the same period in
2002. The increase was a result of higher sales volume, favorable weather
conditions, lower interest expense and taxes other than income, partially
offset by increased O&M resulting from storm-related damage, and The Exelon
Way severance costs, increased income taxes and depreciation and
amortization expense.
131
Operating Revenue
PECO's electric sales statistics were as follows:
Nine Months Ended September 30,
-------------------------------
Retail Deliveries (in GWhs) 2003 2002 Variance % Change
-------------------------------------------------------------------------------------------------------------------
Bundled Deliveries (1)
Residential 8,723 7,592 1,131 14.9%
Small Commercial & Industrial 5,065 5,704 (639) (11.2%)
Large Commercial & Industrial 11,190 11,285 (95) (0.8%)
Public Authorities & Electric Railroads 692 617 75 12.2%
-------------------------------------------------------------------------------------------------
25,670 25,198 472 1.9%
-------------------------------------------------------------------------------------------------
Unbundled Deliveries (2)
Residential 708 1,720 (1,012) (58.8%)
Small Commercial & Industrial 1,044 253 791 n.m.
Large Commercial & Industrial 610 351 259 73.8%
Public Authorities & Electric Railroads (3) -- -- -- --
-------------------------------------------------------------------------------------------------
2,362 2,324 38 1.6%
-------------------------------------------------------------------------------------------------
Total Retail Deliveries 28,032 27,522 510 1.9%
=================================================================================================
(1) Bundled service reflects deliveries to customers taking electric
service under tariffed rates.
(2) Unbundled service reflects customers electing to receive electric
generation service from an alternative energy supplier.
(3) PECO's unbundled sales to Public Authorities and Electric Railroads
were less than one GWh per quarter.
Nine Months Ended September 30,
-------------------------------
Electric Revenue 2003 2002 Variance % Change
-------------------------------------------------------------------------------------------------------------------
Bundled Revenue (1)
Residential $ 1,122 $ 999 $ 123 12.3%
Small Commercial & Industrial 585 664 (79) (11.9%)
Large Commercial & Industrial 825 829 (4) (0.5%)
Public Authorities & Electric Railroads 62 58 4 6.9%
-------------------------------------------------------------------------------------------------
2,594 2,550 44 1.7%
-------------------------------------------------------------------------------------------------
Unbundled Revenue (2)
Residential 52 129 (77) (59.7%)
Small Commercial & Industrial 54 13 41 n.m.
Large Commercial & Industrial 16 10 6 60.0%
Public Authorities & Electric Railroads (3) -- -- -- --
-------------------------------------------------------------------------------------------------
122 152 (30) (19.7%)
-------------------------------------------------------------------------------------------------
Total Electric Retail Revenues 2,716 2,702 14 0.5%
Wholesale and Miscellaneous Revenue (4) 164 179 (15) (8.4%)
-------------------------------------------------------------------------------------------------
Total Electric Revenue $ 2,880 $ 2,881 $ (1) --
=================================================================================================
(1) Bundled revenue reflects revenue from customers taking electric service
under tariffed rates, which includes the cost of energy, the delivery
cost of the transmission and the distribution of the energy and a CTC
charge.
(2) Unbundled revenue reflects revenue from customers electing to receive
generation from an alternative supplier, which includes a distribution
charge and a CTC charge.
(3) PECO's unbundled sales to Public Authorities and Electric Railroads
were less than $1 million per quarter.
(4) Wholesale and miscellaneous revenues include transmission revenue and
other wholesale energy sales.
132
The changes in electric retail revenues for the nine months ended
September 30, 2003, as compared to the same period in 2002, were as
follows:
Variance
-------------------------------------------------------------------------------------------------------------------
Volume $ 37
Weather 8
Rate Mix (28)
Customer choice (3)
-------------------------------------------------------------------------------------------------------------------
Retail revenue $ 14
===================================================================================================================
o Volume. Exclusive of weather impacts, higher delivery volume affected
PECO's revenue by $37 million compared to the same period in 2002
primarily related to increases in the small and large commercial and
industrial customer classes.
o Weather. The weather impact was favorable compared to the prior year
as a result of colder winter weather partially offset by cooler summer
weather. Heating degree-days increased 35% and cooling degree-days
decreased 19% for the nine months ended September 30, 2003 compared to
the same period in 2002.
o Rate Mix. The decrease in revenues from rate mix is due to changes in
monthly usage patterns in all customer classes during the nine months
ended September 30, 2003 as compared to the same period in 2002.
o Customer Choice. All PECO customers may choose to purchase energy from
other suppliers. This choice generally does not impact kWh deliveries,
but reduces revenue collected from customers because they are not
obtaining generation supply from PECO.
For the nine months ended September 30, 2003, the energy provided
by alternative suppliers was 2,362 GWhs, or 8.4%, as compared to 2,324
GWhs, or 8.4%, for the nine months ended September 30, 2002. As of
September 30, 2003, the number of customers served by alternative
suppliers was 297,821, or 19.6%, as compared to 285,549, or 18.7%, as
of September 30, 2002.
PECO's gas sales statistics and revenue detail were as follows:
Nine Months Ended September 30,
-------------------------------
Deliveries to customers in mmcf 2003 2002 Variance % Change
-------------------------------------------------------------------------------------------------------------------
Retail sales 44,183 34,128 10,055 29.5%
Transportation 19,954 22,862 (2,908) (12.7%)
-----------------------------------------------------------------------------------------------------
Total 64,137 56,990 7,147 12.5%
=====================================================================================================
Nine Months Ended September 30,
-------------------------------
Revenue 2003 2002 Variance % Change
-------------------------------------------------------------------------------------------------------------------
Retail sales $ 418 $ 309 $ 109 35.3%
Transportation 14 15 (1) (6.7%)
Resales and other 16 34 (18) (52.9%)
-----------------------------------------------------------------------------------------------------
Total $ 448 $ 358 $ 90 25.1%
=====================================================================================================
133
The changes in gas retail revenue for the nine months ended
September 30, 2003 as compared to the same period in 2002, were as follows:
Variance
-------------------------------------------------------------------------------------------------------------------
Weather $ 73
Volume 21
Rate changes 15
-------------------------------------------------------------------------------------------------------------------
Total gas retail revenue $ 109
===================================================================================================================
o Weather. The weather impact was favorable compared to the prior year
as a result of colder winter weather. Heating degree-days increased
35% in the nine months ended September 30, 2003 compared to the same
period in 2002. Retail sales deliveries increased approximately 8,600
mmcf due to the colder weather.
o Volume. Exclusive of weather impacts, higher delivery volume increased
revenue in the nine months ended September 30, 2003 compared to the
same period in 2002 resulting from increased retail sales in all
classes. Deliveries to retail customers increased approximately 1,500
mmcf, or 4% in the nine months ended September 30, 2003 compared to
the same period in 2002.
o Rate Changes. The favorable variance in rates is attributable to
increases of 15% and 7% in the purchased gas adjustment by the PUC
effective March 1, 2003 and June 1, 2003, respectively. The average
rate per mmcf for the nine months ended September 30, 2003 was 5%
higher than the rate in the same 2002 period. PECO's gas rates are
subject to periodic adjustments by the PUC and are designed to recover
from or refund to customers the difference between actual cost of
purchased gas and the amount included in base rates and to recover or
refund increases or decreases in certain state taxes not recovered in
base rates.
The reduction in transportation volumes and revenues are primarily
the result of lower intercompany deliveries to Generation during the nine
months ended September 30, 2003 compared to the same period in 2002.
Lower resale revenues are attributable to a decrease in off-system
sales, exchanges and capacity releases during the nine months ended
September 30, 2003 compared to the same period in 2002.
Purchased Power
Purchased power expense for the nine months ended September 30,
2003 increased $25 million, or 2%, as compared to the same period in 2002.
The increase in purchased power expense was primarily attributable to $24
million of higher electric delivery volume and $2 million related to higher
PJM ancillary charges.
Fuel
Fuel expense for the nine months ended September 30, 2003
increased $57 million, or 25%, as compared to the same period in 2002. This
increase was primarily attributable to $50 million of favorable weather
conditions, $15 million from higher gas prices and $11 million of higher
delivery volumes, partially offset by $24 million in reductions from resale
transactions.
134
Operating and Maintenance
O&M expense for the nine months ended September 30, 2003 increased
$46 million, or 11% as compared to the same period in 2002. The increase in
O&M expense was primarily attributable to $41 million of severance and
related postretirement health and welfare benefits accruals and pension and
postretirement curtailment costs associated with The Exelon Way, $22
million of higher storm-related costs, $12 million of increased employee
fringe benefits, partially offset by $23 million of lower costs associated
with the initial implementation of automated meter reading services in
2002, $7 million of lower expense related to the allowance for
uncollectible accounts and $6 million of additional miscellaneous other net
positive impacts.
Depreciation and Amortization
Depreciation and amortization expense for the nine months ended
September 30, 2003 increased $22 million, or 6%, as compared to the same
period in 2002 as follows:
Nine Months Ended September 30,
-------------------------------
2003 2002 Variance % Change
-------------------------------------------------------------------------------------------------------------------
Competitive transition charge amortization $ 256 $ 236 $ 20 8.5%
Depreciation expense 99 94 5 5.3%
Other amortization expense 15 18 (3) (16.7%)
-------------------------------------------------------------------------------------------------
Total depreciation and amortization $ 370 $ 348 $ 22 6.3%
=================================================================================================
The additional amortization of the CTC is in accordance with
PECO's original settlement under the Pennsylvania Competition Act and the
increase in depreciation expense resulted from additional plant in service.
Taxes Other Than Income
Taxes other than income for the nine months ended September 30,
2003 decreased $84 million, or 41%, as compared to the same period in 2002.
The decrease was primarily attributable to a $58 million reversal of real
estate tax accruals during the third quarter of 2003, a $12 million
reversal of the use tax accrual due to an audit settlement and a $12
million decrease in 2003 real estate tax expense.
Interest Charges
Interest charges consist of interest expense, interest expense to
affiliates and distributions on mandatorily redeemable preferred
securities. Interest charges decreased $38 million, or 13%, in the nine
months ended September 30, 2003 as compared to the same period in 2002. The
decrease was primarily attributable to lower interest expense on long-term
debt of $28 million as a result of scheduled principal payments and
refinancing of existing debt at lower interest rates and an $8 million
reversal of accrued interest expense on federal income taxes.
Other, Net
Other, net decreased $7 million in the nine months ended September
30, 2003 as compared to the same period in 2002. The decrease was primarily
attributable to reversal of interest income on federal income taxes of $14
million, partially offset by $4 million related to higher interest income
and the favorable settlement of a customer contract of $3 million.
135
Income Taxes
The effective tax rate was 34.6% for the nine months ended
September 30, 2003 as compared to 32.9% for the same period in 2002. The
increase in the effective tax rate primarily reflects the impact of changes
in income before income taxes.
Due to revenue needs in the states in which PECO operates, various
state income tax and fee increases have been proposed or are being
contemplated. If these changes are enacted, they could increase PECO's
state income tax expense. At this time, however, PECO cannot predict
whether legislation or regulation will be introduced, the form of any
legislation or regulation, whether any such legislation or regulation will
be passed by the state legislatures or regulatory bodies, and, if enacted,
whether any such legislation or regulation would be effective retroactively
or prospectively. As a result, PECO cannot currently estimate the effect of
these potential changes in tax laws or regulation.
Preferred Stock Dividends
Preferred stock dividends for the nine months ended September 30,
2003 were consistent as compared to the same period in 2002.
LIQUIDITY AND CAPITAL RESOURCES
PECO's business is capital intensive and requires considerable
capital resources. PECO's capital resources are primarily provided by
internally generated cash flows from operations and, to the extent
necessary, external financing including the issuance of commercial paper,
participation in the intercompany money pool or capital contributions from
Exelon. PECO's access to external financing at reasonable terms is
dependent on its credit ratings and general business conditions, as well as
that of the utility industry in general. If these conditions deteriorate to
where PECO no longer has access to external financing sources at reasonable
terms, PECO has access to a revolving credit facility that PECO currently
utilizes to support its commercial paper program. See the Credit Issues
section of Liquidity and Capital Resources for further discussion. Capital
resources are used primarily to fund PECO's capital requirements, including
construction, repayments of maturing debt and payment of dividends.
As part of the implementation of The Exelon Way, PECO has
identified 140 positions for elimination by the end of 2004 and anticipates
identifying additional positions for elimination in 2005 and 2006. PECO
recorded a charge for cash severance of $13 million during the third quarter
2003, which PECO anticipates will be paid by December 31, 2004. PECO
anticipates incurring further costs associated with The Exelon Way upon
identifying additional positions to be eliminated. These costs will be
recorded in the period in which the costs can be reasonably estimated.
136
Cash Flows from Operating Activities
Cash flows provided by operations for the nine months ended
September 30, 2003 and 2002 were $757 million and $473 million,
respectively. The increase in cash flows was primarily attributable to a
$300 million increase in working capital and by a $27 million increase in
net income, partially offset by an $83 million change in deferred energy
costs. PECO's cash flow from operating activities primarily results from
sales of electricity and gas to a stable and diverse base of retail
customers at fixed prices. PECO's future cash flows will depend upon the
ability to achieve operating cost reductions and the impact of the economy,
weather, customer choice and future regulatory proceedings on its revenues.
Although the amounts may vary from period to period as a result of the
uncertainties inherent in its business, PECO expects that it will continue
to provide a reliable and steady source of internal cash flow from
operations for the foreseeable future.
Cash Flows from Investing Activities
Cash flows used in investing activities for the nine months ended
September 30, 2003 and 2002 were $193 million and $177 million,
respectively. The increase in cash flows used in investing activities was
primarily attributable to an increase in capital expenditures.
PECO's projected capital expenditures for 2003 are $272 million.
Approximately 60% of the budgeted 2003 expenditures are for continuing
efforts to further improve the reliability of its transmission and
distribution systems. The remainder is for capital additions to support new
business and customer growth. PECO anticipates that its capital
expenditures will be funded by internally generated funds, borrowings, the
issuance of preferred securities, or capital contributions from Exelon.
PECO's proposed capital expenditures and other investments are subject to
periodic review and revision to reflect changes in economic conditions and
other factors.
137
Cash Flows from Financing Activities
Cash flows used in financing activities for the nine months ended
September 30, 2003 and 2002 were $545 million and $214 million,
respectively. Cash flows used in financing activities are primarily
attributable to debt service and payment of dividends to Exelon. The
increase in cash flows used in financing activities is primarily
attributable to increased debt and preferred securities redemptions of $681
million, partially offset by additional issuances of long-term debt of
$328. See Note 12 of the Condensed Combined Notes to Consolidated Financial
Statements for further discussion of PECO's debt financing activities. For
the nine months ended September 30, 2003, PECO paid Exelon $244 million in
common stock dividends compared to $255 million for the same period in
2002.
Credit Issues
PECO meets its short-term liquidity requirements primarily through
the issuance of commercial paper and borrowings from Exelon's intercompany
money pool. PECO, along with Exelon, ComEd and Generation, participates in
a $1.5 billion unsecured 364-day revolving credit facility with a group of
banks. The credit facility became effective November 22, 2002 and includes
a term-out option that allows any outstanding borrowings at the end of the
revolving credit period to be repaid on November 21, 2004. Exelon may
increase or decrease the sublimits of each of the participants upon written
notification to the banks. As of September 30, 2003, PECO's sublimit was
$400 million. The credit facility is used by PECO principally to support
its commercial paper program. At September 30, 2003, PECO's Consolidated
Balance Sheet reflected $12 million in commercial paper outstanding. For
the nine months ended September 30, 2003, the average interest rate on
notes payable was approximately 1.25%.
The credit facility requires PECO to maintain a cash from
operations to interest expense ratio for the twelve-month period ended on
the last day of any quarter. The ratio excludes revenues and interest
expenses attributable to securitization debt, certain changes in working
capital and distributions on preferred securities of subsidiaries. PECO's
threshold for the ratio reflected in the credit agreement cannot be less
than 2.25 to 1 for the twelve-month period ended September 30, 2003. At
September 30, 2003, PECO was in compliance with the credit agreement
thresholds.
To provide an additional short-term borrowing option that will
generally be more favorable to the borrowing participants than the cost of
external financing, Exelon operates an intercompany money pool.
Participation in the money pool is subject to authorization by Exelon's
corporate treasurer. ComEd, PECO, Generation and BSC may participate in the
money pool as lenders and borrowers, and Exelon Corporate may participate
as a lender. Funding of, and borrowings from, the money pool are predicated
on whether such funding results in mutual economic benefits to each of the
participants. Interest on borrowings is based on short-term market rates of
interest, or, if from an external source, specific borrowing rates. During
the nine months ended September 30, 2003, PECO had various investments in
the money pool. The maximum amount of outstanding investments at any time
during 2003 was $59 million. As of September 30, 2003, there was no
outstanding investment balance. For the nine months ended September 30,
2003, PECO earned less than $1 million in interest.
138
PECO's access to the capital markets, including the commercial
paper market, and its financing costs in those markets are dependent on its
securities ratings. None of PECO's borrowings is subject to default or
prepayment as a result of a downgrading of securities ratings although such
a downgrading could increase interest charges under certain bank credit
facilities.
Under PUHCA, PECO is precluded from lending or extending credit or
indemnity to Exelon and can pay dividends only from retained or current
earnings. At September 30, 2003, PECO had retained earnings of $517
million.
Long-term debt included $4 billion of transition bonds.
Contractual Obligations, Commercial Commitments and Off-Balance Sheet
Obligations
Contractual obligations represent cash obligations that are
considered to be firm commitments and commercial commitments represent
commitments triggered by future events. PECO's contractual obligations and
commercial commitments as of September 30, 2003 were materially unchanged,
other than in the normal course of business, from the amounts set forth in
the 2002 Form 10-K except for the following:
o PECO has entered into several agreements with a tax consultant related
to the filing of refund claims with the IRS and has made refundable
prepayments of $1 million for potential fees associated with these
agreements. The fees for these agreements are contingent upon a
successful outcome and are based upon a percentage of the refunds
recovered from the IRS, if any. As such, ultimate net cash flows to
PECO related to these agreements will either be positive or neutral
depending upon the outcome of the refund claim with the IRS. These
potential tax benefits and associated fees could be material to the
financial position, results of operations and cash flows of PECO. PECO
cannot predict the timing of the final resolution of these refund
claims.
o See Note 12 of the Condensed Combined Notes to Consolidated Financial
Statements for further discussion of material changes in PECO's debt
and preferred securities obligations from those set forth in the 2002
Form 10-K.
o See Note 9 of the Condensed Combined Notes to Consolidated Financial
Statements for the commercial commitments table representing PECO's
commitments not recorded on the balance sheet but potentially
triggered by future events, including obligations to make payment on
behalf of other parties and financing arrangements to secure their
obligations.
139
EXELON GENERATION COMPANY, LLC
------------------------------
GENERAL
Generation operates as a single segment and its operations consist
of electric generating facilities, energy marketing operations and equity
interests in Sithe and AmerGen.
RESULTS OF OPERATIONS
Three Months Ended September 30, 2003 Compared to Three Months Ended
September 30, 2002
Significant Operating Trends - Generation
Three Months Ended September 30,
--------------------------------
2003 2002 Variance % Change
-------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES $ 2,537 $ 2,213 $ 324 14.6%
OPERATING EXPENSES
Purchased power 1,240 1,257 (17) (1.4%)
Fuel 449 273 176 64.5%
Impairment of Exelon Boston Generating, LLC 945 -- 945 n.m.
Operating and maintenance 530 391 139 35.5%
Depreciation and amortization 51 68 (17) (25.0%)
Taxes other than income 28 37 (9) (24.3%)
-----------------------------------------------------------------------------------------------------
Total operating expenses 3,243 2,026 1,217 60.1%
-----------------------------------------------------------------------------------------------------
OPERATING INCOME (LOSS) (706) 187 (893) n.m.
-----------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest expense (25) (23) (2) 8.7%
Equity in earnings of unconsolidated affiliates 53 87 (34) (39.1%)
Other, net (30) 14 (44) n.m.
-----------------------------------------------------------------------------------------------------
Total other income and deductions (2) 78 (80) (102.6%)
-----------------------------------------------------------------------------------------------------
INCOME (LOSS) BEFORE INCOME TAXES (708) 265 (973) n.m.
INCOME TAXES (280) 102 (382) n.m.
-----------------------------------------------------------------------------------------------------
NET INCOME (LOSS) $ (428) $ 163 $ (591) n.m.
=====================================================================================================
n.m. - not meaningful
Net Income (Loss)
Generation's net income decreased by $591 million for the three
months ended September 30, 2003 compared to the same period in 2002
primarily due to a $945 million ($573 million, net of income taxes)
impairment charge related to Generation's long-lived assets in EBG, an
additional $55 million ($36 million, net of income taxes) impairment charge
related to Generation's investment in Sithe, and $46 million ($30 million,
net of income taxes) due to severance and related postretirement health and
welfare benefits accruals and pension and postretirement curtailment costs
associated with The Exelon Way. The decrease was partially offset by a $165
million increase in revenue, net of purchased power and fuel. Net income
(loss) was additionally affected by a net decrease in the equity in
earnings of unconsolidated affiliates.
140
Operating Revenues
Revenues increased by $324 million, or 15% for the three months
ended September 30, 2003 compared to the same period in 2002. For the three
months ended September 30, 2003 and 2002, Generation's sales were as
follows:
Three Months Ended September 30,
--------------------------------
Revenue (in millions) 2003 2002 Variance % Change
-------------------------------------------------------------------------------------------------------------------
Energy Delivery and Exelon Energy Company $ 1,338 $ 1,461 $ (123) (8.4%)
Market Sales 1,138 752 386 51.3%
-----------------------------------------------------------------------------------------------------
Total Energy Sales Revenue 2,476 2,213 263 11.9%
Trading Portfolio 1 (12) 13 (108.3%)
Other Revenue 60 12 48 n.m.
-----------------------------------------------------------------------------------------------------
Total Revenue $ 2,537 $ 2,213 $ 324 14.6%
=====================================================================================================
Three Months Ended September 30,
--------------------------------
Sales (in GWhs) 2003 2002 Variance % Change
-------------------------------------------------------------------------------------------------------------------
Energy Delivery and Exelon Energy Company 32,237 35,996 (3,759) (10.4%)
Market Sales 29,613 21,177 8,436 39.8%
-----------------------------------------------------------------------------------------------------
Total Sales 61,850 57,173 4,677 8.2%
=====================================================================================================
Trading volumes of 11,086 GWhs and 28,455 GWhs for the three
months ended September 30, 2003 and 2002, respectively, are not included in
the table above. The decrease in trading volume is a result of reduced
volumetric and VaR trading limits in 2003, which are set by the Risk
Management Committee and approved by the Board of Directors.
Generation's average revenue (per MWh) on energy sales for the
three months ended September 30, 2003 and 2002 is as follows:
Three Months Ended September 30,
--------------------------------
($/MWh) 2003 2002 % Change
-------------------------------------------------------------------------------------------------------------------
Average Revenue
Energy Delivery and Exelon Energy Company $ 41.51 $ 40.56 2.3%
Market Sales 38.43 35.50 8.3%
Total - excluding the trading portfolio 40.03 38.69 3.5%
-------------------------------------------------------------------------------------------------------------------
Energy Delivery and Exelon Energy Company. Sales to Energy
Delivery decreased by $102 million primarily due to unfavorable weather in
ComEd and PECO's service territories during the three months ended
September 30, 2003 compared to the same period in 2002. Generation's
average revenue per MWh was affected by increased weighted average on and
off-peak prices per MWh for supply agreements with ComEd and PECO. Sales to
Exelon Energy Company decreased $21 million for the three months ended
September 30, 2003 compared to the same period in 2002 primarily due to the
discontinuance of Exelon Energy Company operations in the PJM region.
141
Market Sales. The increase in market sales was primarily
attributable to a $227 million increase resulting from increased production
from generating assets acquired during 2002. In addition, market sales
increased $149 million as a result of favorable market prices, primarily
driven by increased fossil fuel prices, and a $19 million increase due to
lower load requirements to affiliates.
Trading Revenues. Trading activity increased revenue by $1 million
during the three months ended September 30, 2003 compared to a $12 million
decrease for the same period in 2002 due to reduced trading volume and
overall portfolio performance improvement in 2003.
Other Revenues. Other revenues increased primarily due to
increases in natural gas market sales. As a result of natural gas supply
contracts assigned to Generation with the 2002 asset acquisitions,
Generation had an excess supply of natural gas. Other revenues also include
nuclear decommissioning cost recoveries from ComEd and PECO.
Purchased Power and Fuel
Generation's supply source of its sales and average supply costs
are summarized below:
Three Months Ended September 30,
--------------------------------
Supply of Sales (in GWhs) 2003 2002 Variance % Change
-------------------------------------------------------------------------------------------------------------------
Nuclear Generation (1) 30,152 29,817 335 1.1%
Purchases - non-trading portfolio (2) 24,062 23,425 637 2.7%
Fossil and Hydro Generation 7,636 3,931 3,705 94.3%
-----------------------------------------------------------------------------------------------------
Total Supply 61,850 57,173 4,677 8.2%
=====================================================================================================
(1) Excluding AmerGen.
(2) Including PPAs with AmerGen.
Three Months Ended September 30,
--------------------------------
($/MWh) 2003 2002 % Change
-----------------------------------------------------------------------------------------------------------------
Average Supply Cost (1) - excluding trading portfolio $ 27.31 $ 26.66 2.4%
-----------------------------------------------------------------------------------------------------------------
(1) Average supply cost includes purchased power and fuel costs.
Generation's supply mix changed as a result of:
o increased nuclear generation due to a lower number of refueling and
unplanned outages during 2003 compared to 2002,
o increased fossil generation due to the Exelon New England plants
acquired in November 2002, which in total account for an increase of
3,570 GWhs, and
o Generation entered into a new PPA with AmerGen in the second quarter
of 2003. As a result, 1,228 GWhs were purchased from Oyster Creek in
the third quarter of 2003.
Purchased power decreased $17 million, or 1%, for the three months
ended September 30, 2003 compared to the same period in 2002, primarily due
to the positive impact of the Exelon New England plants becoming
operational during the three months ended September 30, 2003 and reduced
capacity payments as a result of releasing Midwest Generation options.
Generation's demand for counterparty purchased power was decreased due to a
$29 million increase in purchased power from AmerGen as a result of the
June 2003 PPA to purchase 100% of the output of Oyster Creek. The decrease
in purchased power was partially offset by a $18 million loss on
mark-to-market hedging activity for the three months ended September 30,
2003 compared to no gain or loss in the same period in 2002.
142
Fuel expense increased $176 million, or 65%, for the three months
ended September 30, 2003 compared to the same period in 2002, as summarized
below:
Three Months Ended September 30,
--------------------------------
(in millions) 2003 2002 Variance % Change
-------------------------------------------------------------------------------------------------------------------
Nuclear Generation (1) $ 125 $ 124 $ 1 0.8%
Fossil and Hydro Generation 324 149 175 117.4%
-----------------------------------------------------------------------------------------------------
Total $ 449 $ 273 $ 176 64.5%
=====================================================================================================
(1) Excluding AmerGen
This increase was primarily due to a $154 million increase in
fossil fuel costs for generation plant assets acquired in 2002. In
addition, fuel expense increased $10 million due to the write down of coal
inventory as a result of a fuel burn analysis and $8 million increase due
to increased emission allowance trade activity.
Impairment of Exelon Boston Generating, LLC
In connection with the decision to transition out of the ownership
of EBG and the projects, Generation recorded a long-lived asset impairment
charge of $945 million ($573 million net of income taxes).
Operating and Maintenance
O&M expense increased $139 million, or 36%, for the three months
ended September 30, 2003 compared to the same period in 2002. The increase
in O&M expense was primarily attributable to a $46 million increase in
severance and related postretirement health and welfare benefits accruals
and pension and postretirement curtailment costs associated with The Exelon
Way and $60 million of accretion expense related to SFAS No. 143. Accretion
expense includes $39 million of accretion of the asset retirement
obligation and $21 million to adjust the earnings impact of certain of the
nuclear decommissioning revenues earned from ComEd and PECO, nuclear
decommissioning trust fund investment income, income taxes incurred on
nuclear decommissioning trust fund activities, accretion of the asset
retirement obligation and depreciation of the asset retirement cost asset
to zero. For a further discussion of SFAS No. 143, see Note 2 of the
Condensed Combined Notes to Consolidated Financial Statements. Operating
and maintenance expense also included $30 million of additional expenses
due to asset acquisitions made after the third quarter of 2002, and $15
million of additional employee payroll and benefits costs. These increases
were partially offset by $9 million of lower nuclear refueling outage costs
and $4 million reduction in other O&M costs.
Three Months Ended September 30,
--------------------------------
2003 2002
-------------------------------------------------------------------------------------------------------------------
Nuclear fleet capacity factor (1) 95.3% 93.9%
Nuclear fleet production cost per MWh (1) $ 11.69 $ 12.40
Average purchased power cost for wholesale operations per MWh (2) $ 51.53 $ 53.75
-------------------------------------------------------------------------------------------------------------------
(1) Including AmerGen and excluding Salem, which is operated by PSE&G.
(2) Including PPAs with AmerGen.
The higher nuclear capacity factor and decreased nuclear
production costs were primarily due to 16 fewer planned refueling outage
days, resulting in a $9 million decrease in outage costs, in the three
months ended September 30, 2003 as compared to the same period in 2002.
143
Additionally, the three months ended September 30, 2003 and 2002 included 9
and 7 unplanned outages, respectively.
Depreciation and Amortization
Depreciation and amortization expense decreased $17 million, or
25%, for the three months ended September 30, 2003 as compared to the same
period in 2002. The decrease was primarily attributable to a $29 million
net reduction in decommissioning expense, net of ARC depreciation, as these
costs are included in operating and maintenance expense after the adoption
of SFAS No. 143, and a $3 million decrease due to life extensions of asset
additions in 2002. These decreases were partially offset by $10 million of
additional depreciation expense on capital additions placed in service
after the third quarter of 2002, and $7 million related to plant
acquisitions made after the third quarter of 2002. For a further discussion
of SFAS No. 143, see Note 2 of the Condensed Combined Notes to Consolidated
Financial Statements.
Taxes Other Than Income
Taxes other than income decreased $9 million, or 24%, for the
three months ended September 30, 2003 compared to the same period in 2002
primarily resulting from a $15 million reduction to reserves recorded for
exposures associated with real estate taxes. This decrease was partially
offset by a $7 million increase in property taxes related to asset
acquisitions made after the third quarter of 2002.
Interest Expense
Interest expense increased $2 million, or 9%, for the three months
ended September 30, 2003 compared to the same period in 2002. The increase
was primarily due to $6 million of interest expense on the long-term debt
obtained as a part of the Exelon New England asset acquisition and $2
million of interest expense on the $536 million note payable issued to
Sithe in November 2002. This increase is partially offset by a $2 million
decrease in interest on Generation's spent fuel obligation to the
Department of Energy due to lower interest rates, and a $2 million increase
in capitalized interest due to a change in capitalized interest rates.
Equity in Earnings of Unconsolidated Affiliates
Equity in earnings of unconsolidated affiliates decreased $34
million, or 39%, for the three months ended September 30, 2003 compared to
the same period in 2002. The decrease was partly due to a $17 million
decrease in Generation's equity earnings of AmerGen. AmerGen's earnings
were primarily affected by decreased power sales due to changes in PPAs
that resulted in lower prices in the summer months and higher expenses at
AmerGen related to severance costs associated with The Exelon Way.
Conversely, the change in PPAs resulted in higher prices in all non-summer
months during 2003 as compared to 2002. The decrease was also due to a $17
million decrease in Generation's equity in earnings of Sithe. Sithe's
earnings were primarily affected by Generation's purchase of Sithe New
England's assets in November 2002 and unfavorable mark-to-market losses at
Sithe.
Other, Net
Other, net decreased $44 million for the three months ended
September 30, 2003 compared to the same period in 2002. The decrease was
due to a $55 million impairment charge as a result of a change in fair
144
value of Generation's investment in Sithe. This decrease was offset by $9
million of higher net realized gains and investment income related to the
nuclear decommissioning trust funds. These net realized gains and
investment income are almost entirely offset with accretion expense in
2003, which is included in O&M expense.
Income Taxes
The effective income tax rate was 39.5% for the three months ended
September 30, 2003 compared to 38.5% for the same period in 2002. This
increase was primarily attributable to the impact of changes in income
before taxes as a result of the impairments recorded in the third quarter
related to Generation's investment in Sithe and long-lived assets of EBG.
Nine Months Ended September 30, 2003 Compared to Nine Months Ended
September 30, 2002
Significant Operating Trends - Generation
Nine Months Ended September 30,
-------------------------------
2003 2002 Variance % Change
-------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES $ 6,301 $ 5,233 $ 1,068 20.4%
OPERATING EXPENSES
Purchased power 2,881 2,581 300 11.6%
Fuel 1,156 706 450 63.7%
Impairment of Exelon Boston Generating, LLC 945 -- 945 n.m.
Operating and maintenance 1,473 1,234 239 19.4%
Depreciation and amortization 142 197 (55) (27.9%)
Taxes other than income 115 126 (11) (8.7%)
-----------------------------------------------------------------------------------------------------
Total operating expenses 6,712 4,844 1,868 38.6%
-----------------------------------------------------------------------------------------------------
OPERATING INCOME (LOSS) (411) 389 (800) n.m.
-----------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest expense (63) (51) (12) 23.5%
Equity in earnings of unconsolidated affiliates 90 119 (29) (24.4%)
Other, net (164) 54 (218) n.m.
-----------------------------------------------------------------------------------------------------
Total other income and deductions (137) 122 (259) n.m.
-----------------------------------------------------------------------------------------------------
INCOME (LOSS) BEFORE INCOME TAXES AND CUMULATIVE
EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES (548) 511 (1,059) n.m.
INCOME TAXES (209) 198 (407) n.m
-----------------------------------------------------------------------------------------------------
INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF CHANGES IN
ACCOUNTING PRINCIPLES (339) 313 (652) n.m.
CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING
PRINCIPLES, NET OF INCOME TAXES 108 13 95 n.m.
-----------------------------------------------------------------------------------------------------
NET INCOME (LOSS) $ (231) $ 326 $ (557) (170.9%)
=====================================================================================================
n.m. - not meaningful
Net Income (Loss)
Generation's net income decreased by $557 million, or 171%, for
the nine months ended September 30, 2003 compared to the same period in
2002. Income before cumulative effect of changes in accounting principles
decreased by $652 million for the nine months ended September 30, 2003
145
compared to the same period in 2002 primarily due to the third quarter
impairment charge for the long-lived assets of EBG of $945 million ($573
million, net of income taxes), first and third quarter impairment charges
for Generation's equity investment in Sithe totaling $255 million ($166
million, net of income taxes), and a $46 million charge ($30 million, net
of income taxes) due to severance and related postretirement health and
welfare benefit accruals and pension and postretirement curtailment costs
associated with The Exelon Way. These decreases were partially offset by
higher revenue resulting from increased market electric sales. Net income
(loss) was additionally affected by a net decrease in equity in earnings of
unconsolidated affiliates.
Operating Revenues
Revenues increased by $1,068 million, or 20%, for the nine months
ended September 30, 2003 compared to the same period in 2002. For the nine
months ended September 30, 2003 and 2002, Generation's sales were as
follows:
Nine Months Ended September 30,
-------------------------------
Revenue (in millions) 2003 2002 Variance % Change
-------------------------------------------------------------------------------------------------------------------
Energy Delivery and Exelon Energy Company $ 3,180 $ 3,299 $ (119) (3.6%)
Market Sales 3,001 1,927 1,074 55.7%
-----------------------------------------------------------------------------------------------------
Total Energy Sales Revenue 6,181 5,226 955 18.3%
-----------------------------------------------------------------------------------------------------
Trading Portfolio (1) (27) 26 (96.3%)
Other Revenue 121 34 87 n.m.
-----------------------------------------------------------------------------------------------------
Total Revenue $ 6,301 $ 5,233 $ 1,068 20.4%
=====================================================================================================
Nine Months Ended September 30,
-------------------------------
Sales (in GWhs) 2003 2002 Variance % Change
-------------------------------------------------------------------------------------------------------------------
Energy Delivery and Exelon Energy Company 89,700 94,646 (4,946) (5.2%)
Market Sales 80,877 61,089 19,788 32.4%
-----------------------------------------------------------------------------------------------------
Total Sales 170,577 155,735 14,842 9.5%
=====================================================================================================
Trading volumes of 28,532 GWhs and 51,260 GWhs for the nine months
ended September 30, 2003 and 2002, respectively, are not included in the
table above. The decrease in trading volume is a result of reduced
volumetric and VaR trading limits in 2003, which are set by the Risk
Management Committee and approved by the Board of Directors.
Generation's average revenues (per MWh) on energy sales for the
nine months ended September 30, 2003 and 2002 were as follows:
Nine Months Ended September 30,
-------------------------------
($/MWh) 2003 2002 % Change
-------------------------------------------------------------------------------------------------------------------
Average Revenue
Energy Delivery and Exelon Energy Company $ 35.45 $ 34.86 1.7%
Market Sales 37.11 31.55 17.6%
Total - excluding the trading portfolio 36.24 33.56 8.0%
-------------------------------------------------------------------------------------------------------------------
Energy Delivery and Exelon Energy Company. Sales to Energy
Delivery decreased by $85 million as a result of a net overall reduction in
volume demand that resulted from unfavorable weather and customers choosing
alternative suppliers under the customer choice program. The decrease was
146
partially offset by increased prices per MWh for supply agreements with
ComEd and PECO. Sales to Exelon Energy Company decreased by $34 million for
the nine months ended September 30, 2003 compared to the same period in
2002 primarily due to the discontinuance of Exelon Energy Company
operations in the PJM region.
Market Sales. The increase of $1,074 million resulted primarily
from increased production from generating assets acquired during 2002, and
from lower load requirements of affiliates and higher wholesale market
prices, primarily attributable to higher fossil fuel prices.
Trading Revenues. Trading activity reduced revenue by $1 million
during the nine months ended September 30, 2003 compared to a reduction of
$27 million during the same period in 2002 due to lower trading activity in
2003.
Other Revenues. Other revenues increased primarily due to
increases in natural gas market sales. As a result of natural gas supply
contracts assigned to Generation with the 2002 asset acquisitions,
Generation had an excess supply of natural gas. Other revenues also include
nuclear decommissioning cost recoveries from ComEd and PECO.
Purchased Power and Fuel
Generation's supply source of its sales and average supply costs
are summarized below:
Nine Months Ended September 30,
-------------------------------
Supply of Sales (in GWhs) 2003 2002 Variance % Change
-------------------------------------------------------------------------------------------------------------------
Nuclear Generation (1) 89,101 86,127 2,974 3.5%
Purchases - non-trading portfolio (2) 63,435 59,496 3,939 6.6%
Fossil and Hydro Generation 18,041 10,112 7,929 78.4%
-----------------------------------------------------------------------------------------------------
Total Supply 170,577 155,735 14,842 9.5%
=====================================================================================================
(1) Excluding AmerGen.
(2) Including PPAs with AmerGen.
Nine Months Ended September 30,
-------------------------------
($/MWh) 2003 2002 % Change
------------------------------------------------------------------------------------------------------------------
Average Supply Cost (1) - excluding trading portfolio $ 23.67 $ 21.04 12.5%
------------------------------------------------------------------------------------------------------------------
(1) Average supply cost includes purchased power and fuel costs.
Generation's supply mix changed as a result of:
o increased nuclear generation due to a lower number of refueling and
unplanned outages during 2003 compared to 2002,
o increased fossil generation due to the effect of the acquisition of
two generating plants in Texas in April 2002 and the Exelon New
England plants acquired in November 2002, which in total account for
an increase of 6,565 GWhs, and
o increased quantity of purchased power at higher prices. In addition,
Generation entered into a new PPA with AmerGen in the second quarter
of 2003. As a result, 2,481 GWhs were purchased from Oyster Creek in
the second and third quarters of 2003.
Purchased power increased $300 million, or 12%, for the nine
months ended September 30, 2003 compared to the same period in 2002 due to a
$339 million increase related to higher market prices and the commencement
of Exelon New England commercial operations resulting in an additional $35
million increase. The increase in purchased power also reflects
mark-to-market hedging losses of $17 million for the nine months ended
September 30, 2003 compared to gains of $11 million in the same period in
2002. The increase was partially offset by $114 million related to decreased
volume and reduced capacity
147
payments as a result of releasing Midwest Generation options. Generation's
demand for counterparty purchased power decreased $91 million because of an
increase in purchased power from AmerGen due to a June 2003 PPA to purchase
100% of the output of Oyster Creek.
Fuel expense increased $450 million, or 64%, for the nine months
ended September 30, 2003 compared to the same period in 2002, as summarized
below:
Nine Months Ended September 30,
-------------------------------
(in millions) 2003 2002 Variance % Change
-------------------------------------------------------------------------------------------------------------------
Nuclear Generation (1) $ 385 $ 360 $ 25 6.9%
Fossil and Hydro Generation 771 346 425 122.8%
-----------------------------------------------------------------------------------------------------
Total $ 1,156 $ 706 $ 450 63.7%
=====================================================================================================
(1) Excluding AmerGen
This increase is primarily the result of increases in fossil fuel
generation required to meet increased market demand for energy, operation
of new base load plants in New England and increased demand in all regions
during the first quarter of 2003. Fossil and other fuel expense increased
$415 million as a result of acquisitions of generating plants in 2002. In
addition, fuel expense increased $10 million due to the writedown of coal
inventory as a result of a fuel burn analysis Nuclear fuel expense
increased $25 million, including $9 million due to higher nuclear
generation and $16 million due to additional fuel amortization resulting
from under-performing fuel at the Quad Cities Unit 1, which was completely
replaced in May 2003.
Impairment of Exelon Boston Generating, LLC
In connection with the decision to transition out of the ownership
of EBG and the projects, Generation recorded a long-lived asset impairment
charge of $945 million ($573 million net of income taxes).
Operating and Maintenance
O&M expense increased $239 million, or 19%, for the nine months
ended September 30, 2003 compared to the same period in 2002. The increase
in O&M expense was primarily attributable to $46 million of severance and
related postretirement health and welfare benefits accruals and pension and
postretirement curtailment costs associated with The Exelon Way and $162
million of accretion expense related to SFAS No. 143. Accretion expense
includes $116 million of accretion of the asset retirement obligation and
$46 million to adjust the earnings impact of certain of the nuclear
decommissioning revenues earned from ComEd and PECO, nuclear
decommissioning trust fund investment income, income taxes incurred on
nuclear decommissioning trust fund activities, accretion of the asset
retirement obligation and depreciation of the asset retirement cost asset
to zero. For a further discussion of SFAS No. 143, see Note 2 of the
Condensed Combined Notes to Consolidated Financial Statements. The increase
in O&M was also due to $51 million of additional employee payroll and
benefits costs and $68 million of additional expenses due to asset
acquisitions made after the third quarter of 2002. Also, Generation
recorded an impairment charge of $5 million in 2003 related to the pending
retirement of Mystic Station Units 4, 5 and 6. These increases were
partially offset by $61 million of lower nuclear refueling outage costs,
including $17 million for Generation's ownership interest in Salem, which
is operated by the co-owner, PSE&G, a one-time executive severance expense
148
recorded in 2002 of $19 million, and an $8 million reduction in worker's
compensation expense.
Nine Months Ended September 30,
-------------------------------
2003 2002
-------------------------------------------------------------------------------------------------------------------
Nuclear fleet capacity factor (1) 94.5% 92.1%
Nuclear fleet production cost per MWh (1) $ 12.16 $ 13.05
Average purchased power cost for wholesale operations per MWh (2) $ 45.42 $ 43.60
-------------------------------------------------------------------------------------------------------------------
(1) Including AmerGen and excluding Salem, which is operated by PSE&G.
(2) Including PPAs with AmerGen.
The higher nuclear capacity factor and decreased nuclear
production costs are primarily due to 66 fewer planned refueling outage
days, resulting in a $44 million decrease in outage costs, in the nine
months ended September 30, 2003 as compared to the same period in 2002. The
nine months ended September 30, 2003 and 2002 included 20 unplanned
outages.
Generation's financial results are greatly dependent on the
performance of its nuclear units, including Generation's ability to
maintain stable cost levels and high nuclear capacity factors. Problems
that may occur at nuclear facilities that result in increased costs include
accelerated replacement of suspect fuel assemblies, reduced generation due
to maintenance and mid-cycle outages. For example, in the second quarter of
2003, the Quad Cities Unit 1 required a significant repair and did not
operate above an 85% capacity factor until a root cause analysis was
completed. Although this individual matter did not result in a significant
decrease in operating income, this type of reduction in operational
capacity can adversely affect Generation's financial results. Generation
completed the analysis and returned the unit to its normal operating
capacity in August 2003.
Depreciation and Amortization
Depreciation and amortization expense decreased $55 million, or
28%, for the nine months ended September 30, 2003 compared to the same
period in 2002. The decrease was primarily attributable to a $93 million
reduction in decommissioning expense net of ARC depreciation, as these
costs are included in operating and maintenance expense after the adoption
of SFAS No. 143, and a $12 million decrease due to life extensions of asset
additions in 2002. The decrease was partially offset by $39 million of
additional depreciation expense on capital additions placed in service
after the second quarter of 2002, and $13 million of expense related to
plant acquisitions made after the third quarter of 2002. For a further
discussion of SFAS No. 143 see Note 2 of the Condensed Combined Notes to
Consolidated Financial Statements.
Taxes Other Than Income
Taxes other than income decreased $11 million, or 9%, for the nine
months ended September 30, 2003 compared to the same period in 2002
primarily due to a $20 million decrease in property taxes, including a $15
million reduction to reserves recorded for exposures associated with real
estate taxes. This decrease was partially offset by a $17 million increase
in property taxes related to asset acquisitions made after the third quarter
of 2002.
149
Interest Expense
Interest expense increased $12 million, or 24%, for the nine
months ended September 30, 2003 compared to the same period in 2002. The
increase was primarily due to $8 million of interest expense on the
long-term debt assumed as a part of the Exelon New England asset
acquisition, $7 million of additional interest expense on the $536 million
note payable issued to Sithe in November 2002, and a $4 million decrease in
capitalized interest. This increase is partially offset by a $3 million
decrease in interest on Generation's obligation to the Department of Energy
due to lower interest rates.
Equity in Earnings of Unconsolidated Affiliates
Equity in earnings of unconsolidated affiliates decreased $29
million, or 24%, for the nine months ended September 30, 2003 compared to
the same period in 2002. This decrease resulted from a $31 million decrease
in Generation's equity in earnings of Sithe. Sithe's earnings were
primarily affected by Generation's purchase of Exelon New England's assets
from Sithe in November 2002 and unfavorable mark-to-market losses at Sithe.
This decrease was partially offset by a $3 million increase in Generation's
equity in earnings of AmerGen. AmerGen's earnings were favorably affected
in the nine months ended September 30, 2003 by increased power sales,
reduced outage costs, and lower accretion expense resulting from the
adoption of SFAS No. 143. This favorable impact was offset by decreased
power sales due to changes in PPAs that resulted in lower prices in the
summer months. Conversely, the change in PPAs resulted in higher prices in
the non-summer months during 2003 as compared to 2002.
Other, Net
Other, net decreased $218 million for the nine months ended
September 30, 2003 compared to the same period in 2002. This decrease is
primarily a result of $255 million of impairment charges related to
Generation's equity investment in Sithe due to an other-than-temporary
decline in value. This charge was partially offset by $41 million of higher
net realized gains and investment income related to the decommissioning
trust funds. These net realized gains and investment income were almost
entirely offset with accretion expense in 2003, which is included in
operating and maintenance expense.
Income Taxes
The effective income tax rate was 38.1% for the nine months ended
September 30, 2003 compared to 38.7% for the same period in 2002. The
decrease was primarily attributed to the impact of changes in income before
income taxes as a result of the impairments of Generation's investment in
Sithe and the long-lived assets of EBG.
Due to revenue needs in the states in which Generation operates,
various state income tax and fee increases have been proposed or are being
contemplated. If these changes are enacted, they could increase
Generation's state income tax expense. At this time, however, Generation
cannot predict whether legislation or regulation will be introduced, the
form of any legislation or regulation, whether any such legislation or
regulation will be passed by the state legislatures or regulatory bodies,
and, if enacted, whether any such legislation or regulation would be
effective retroactively or prospectively. As a result, Generation cannot
currently estimate the effect of potential changes in tax law or
regulation.
150
Cumulative Effect of Changes in Accounting Principles
On January 1, 2003, Generation adopted SFAS No. 143 resulting in a
benefit of $108 million, net of income taxes of $70 million.
On January 1, 2002, Generation adopted SFAS No. 141 resulting in a
benefit of $13 million, net of income taxes of $9 million.
See Note 2 of the Condensed Combined Notes to Consolidated
Financial Statements for further discussion of the adoption of SFAS No. 143
and SFAS No. 141.
LIQUIDITY AND CAPITAL RESOURCES
Generation's business is capital intensive and requires
considerable capital resources. Generation's capital resources are
primarily provided by internally generated cash flows from operations and,
to the extent necessary, external financings including participation in the
intercompany money pool and/or capital contributions from Exelon.
Generation's access to external financing at reasonable terms is dependent
on its credit ratings and general business conditions, as well as that of
the utility industry in general. If these conditions deteriorate to where
Generation no longer has access to external financing sources at reasonable
terms, Generation has access to a revolving credit facility. See the Credit
Issues section of Liquidity and Capital Resources for further discussion.
Capital resources are used primarily to fund Generation's capital
requirements, including construction, investments in new and existing
ventures, repayments of maturing debt and the payment of distributions to
Exelon. Any future acquisitions could require external financing or
borrowings or capital contributions from Exelon.
As part of the implementation of The Exelon Way, Generation has
identified 317 positions for elimination by the end of 2004 and anticipates
identifying additional positions for elimination in 2005 and 2006.
Generation recorded a charge for cash severance of $20 million during the
third quarter 2003, which Generation anticipates will be paid by December
31, 2004. Generation anticipates incurring further costs associated with The
Exelon Way upon identifying additional positions to be eliminated. These
costs will be recorded in the period in which the costs can be reasonably
estimated.
Cash Flows from Operating Activities
Cash flows provided by operations were $1,141 million for the nine
months ended September 30, 2003, compared to $771 million for the same
period in 2002. The increase in cash flows from operating activities was
primarily attributable to a $530 million increase in cash flows derived
from working capital. Cash flows used in operating activities for
collateral were $1 million as of September 30, 2003, compared to $48
million for the same period in 2002. The use of cash for collateral will
depend upon future market prices for energy and to the extent forward
energy deals are entered into under agreements with negotiated collateral
provisions. When power prices return to previous levels or when Generation
delivers the power under its forward contracts, the collateral would be
returned to Generation with no impact on its results of operations.
Generation's cash flows from operating activities primarily result from the
sale of electric energy to wholesale customers, including Generation's
affiliated companies, as well as settlements arising from Generation's
151
trading activities. Generation's future cash flow from operating activities
will depend upon future demand and market prices for energy and the ability
to continue to produce and supply power at competitive costs.
Cash Flows from Investing Activities
Cash flows used in investing activities were $772 million for the
nine months ended September 30, 2003, compared to $1,343 million for the
same period in 2002. The decrease in cash flows used in investing
activities during the current year was primarily attributable to plant
acquisition costs of $443 million during the nine months ended September
30, 2002, and $92 million for liquidated damages received from Raytheon in
2003 (see Note 9 of the Condensed Combined Notes to Consolidated Financial
Statements).
Generation's capital expenditures for 2003 reflect the
construction of three EBG generating facilities with projected capacity of
2,421 MWs of energy and additions to and upgrades of existing facilities
(including nuclear refueling outages) and nuclear fuel. During the nine
months ended September 30, 2003, EBG received $92 million of liquidated
damages from Raytheon as a result of Raytheon not meeting the expected
completion date and certain contractual performance criteria in connection
with Raytheon's construction of Mystic 8 and 9 and Fore River. Exelon
anticipates that Generation's capital expenditures will be funded by
internally generated funds, borrowings or capital contributions from Exelon.
Cash Flows from Financing Activities
Cash flows used in financing activities were $324 million for the
nine months ended September 30, 2003, compared to cash flows provided by
financing activities of $387 million for the same period in 2002. The
decrease in cash flows from financing activities was primarily due to a
$526 million decrease in cash receipts from affiliates, $86 million
increase in distributions paid to Exelon, the $210 million partial payment
of the acquisition note payable to Sithe, a reduction in contributions from
minority interest holders of $43 million and a $25 million reduction in
restricted cash during the nine months ended September 30, 2003 compared to
the same period in 2002. The decrease in cash provided by financing
activities was partially offset by an increase in borrowings under the
revolving credit facility of $181 million during the current year over the
same period in 2002. See Note 12 of the Condensed Combined Notes to
Consolidated Financial Statements for further discussion of Generation's
debt financing activities.
Credit Issues
Generation meets its short-term liquidity requirements primarily
through intercompany borrowings from Exelon and participation in the
intercompany money pool. Generation, along with Exelon, ComEd and PECO,
participates in a $1.5 billion unsecured 364-day revolving credit facility
with a group of banks. The credit facility became effective on November 22,
2002 and includes a term-out option that allows any outstanding borrowings
at the end of the revolving credit period to be repaid on November 21,
2004. Exelon may increase or decrease the sublimits of each of the
participants upon written notification to the banks. As of September 30,
2003, the sublimit for Generation was zero.
152
The credit facility requires Generation to maintain a cash from
operations to interest expense ratio for the twelve-month period ended on
the last day of any quarter. The ratio excludes certain changes in working
capital, revenues from Exelon New England and interest on the debt of
Exelon New England's project subsidiaries. Generation's threshold for the
ratio reflected in the credit agreement cannot be less than 3.25 to 1 for
the twelve-month period ended September 30, 2003. At September 30, 2003,
Generation was in compliance with the credit agreement thresholds.
To provide an additional short-term borrowing option that will
generally be more favorable to the borrowing participants than the cost of
external financing, Exelon operates an intercompany money pool.
Participation in the money pool is subject to authorization by the Exelon
corporate treasurer. ComEd, PECO, Generation and BSC may participate in the
money pool as lenders and borrowers, and Exelon Corporate may participate
as a lender. Funding of, and borrowings from, the money pool are predicated
on whether such funding results in mutual economic benefits to each of the
participants. Interest on borrowings is based on short-term market rates of
interest, or, if from an external source, specific borrowing rates. During
the nine months ended September 30, 2003, Generation had various borrowings
under the money pool. The maximum amount of loans outstanding at any time
during the quarter was $344 million. As of September 30, 2003, Generation
owed the money pool $147 million on these loans. For the nine months ended
September 30, 2003, Generation paid $2 million in interest to the money
pool.
EBG has approximately $1.1 billion of debt outstanding under the
EBG Facility at September 30, 2003. The EBG Facility was entered into
primarily to finance the construction of Mystic 8 and 9 and Fore River. The
EBG Facility required that all of the projects achieve Project Completion,
by June 12, 2003. On June 11, 2003, EBG negotiated an extension of the
Project Completion date to July 11, 2003. On July 3, 2003, the lenders under
the EBG Facility and EBG executed a letter agreement as a result of which
the lenders were precluded during the period July 11, 2003 through August
29, 2003 from exercising any remedies resulting from the failure of all of
the projects to achieve Project Completion. At that time, EBG stated that it
would continue to monitor the projects, assess all of its options relating
to the projects, and continue discussions with the lenders. Project
Completion was not achieved by July 12, 2003, resulting in an event of
default under the EBG Facility. The EBG Facility is non-recourse to
Generation and an event of default under the EBG Facility does not
constitute an event of default under any other debt instruments of Exelon or
its subsidiaries. Mystic 8 and 9 and Fore River are in commercial operation,
although they have not yet achieved Project Completion.
As a result of Generation's continuing evaluation of the projects
and discussions with the lenders, Generation has commenced the process of
an orderly transition out of the ownership of EBG and the projects. The
transition will take place in a manner that complies with applicable
regulatory requirements. For a period of time, Generation expects to
continue to provide administrative and operational services to EBG in its
operation of the projects. Generation informed the lenders of its decision
to exit and that it will not provide additional funding to the projects
beyond its existing contractual obligations. Generation cannot predict the
timing of the transition.
153
The debt outstanding under the EBG Facility of approximately $1.1
billion at September 30, 2003 is reflected in Generation's Consolidated
Balance Sheet as a current liability.
On June 13, 2003, Generation closed on a $550 million revolving
credit facility. Generation used the facility to make the first payment to
Sithe of $210 million relating to the $536 million note, which was
established in connection with the acquisition of Exelon New England.
On September 29, 2003, Generation replaced the $550 million
facility with a new $850 million revolving credit facility. The existing
$210 million of borrowings under the original facility remain outstanding
under the new credit facility. The note with Sithe has been restructured in
the third quarter to provide for the remaining balance of $326 million to
be paid in two installments. Generation will be required to repay $236
million of the principal on the earlier of December 1, 2003 or change of
control, and the remaining principal balance on the earlier of December 1,
2004 or change of control.
Generation's $850 million facility is also expected to provide the
initial funding of the acquisition of British Energy's 50% interest in
AmerGen.
Generation's access to the capital markets and its financing costs
in those markets are dependent on its securities ratings. None of
Generation's borrowings is subject to default or prepayment as a result of
a downgrading of securities ratings although such a downgrading could
increase interest charges under certain bank credit facilities. From time
to time Generation enters into energy commodity and other derivative
transactions that require the maintenance of investment grade ratings.
Failure to maintain investment grade ratings would allow the counterparty
to terminate the derivative and settle the transaction on a net present
value basis.
As part of the normal course of business, Exelon and Generation
routinely enter into physical or financially settled contracts for the
purchase and sale of capacity, energy, fuels and emissions allowances.
These contracts either contain express provisions or otherwise permit
Exelon, Generation and its counterparties to demand adequate assurance of
future performance when there are reasonable grounds for doing so. In
accordance with the contracts and applicable contracts law, if Exelon or
Generation is downgraded by a credit rating agency, especially if such
downgrade is to a level below investment grade, it is possible that a
counterparty could attempt to rely on such a downgrade as a basis for
making a demand for adequate assurance of future performance. Depending on
Exelon or Generation's net position with a counterparty, the demand could
be for the posting of collateral. In the absence of expressly agreed to
provisions that specify the collateral that must be provided, the
obligation to supply the collateral requested will be a function of the
facts and circumstances of Exelon or Generation's situation at the time of
the demand. If Exelon or Generation can reasonably claim that it is willing
and financially able to perform its obligations, it may be possible to
successfully argue that no collateral should be posted or that only an
amount equal to two or three months of future payments should be
sufficient.
154
Under PUHCA, Generation is precluded from lending or extending
credit or indemnity to Exelon and can only pay dividends from undistributed
or current earnings. At September 30, 2003, Generation had undistributed
earnings of $577 million.
Contractual Obligations, Commercial Commitments and Off-Balance Sheet
Obligations
Contractual obligations represent cash obligations that are
considered to be firm commitments and commercial commitments represent
commitments triggered by future events. Generation's contractual
obligations and commercial commitments as of September 30, 2003 were
materially unchanged from the amounts set forth in the 2002 Form 10-K
except for the following:
o Generation entered into a PPA dated June 26, 2003 with AmerGen. Under
the PPA, Generation has agreed to purchase 100% of energy generated by
Oyster Creek through April 9, 2009. See Note 9 of the Condensed
Combined Notes to Consolidated Financial Statements for the commercial
commitments table representing Generation's commitments not recorded
on the balance sheet but potentially triggered by future events,
including obligations to make payment on behalf of other parties and
financing arrangements to secure their obligations.
o On May 29, 2003, Exelon Fossil Holdings, Inc., a wholly owned
subsidiary of Generation, issued an irrevocable call notice to
purchase the 35.2% interest in Sithe owned by Apollo Energy, LLC and
the 14.9% interest owned by subsidiaries of Marubeni Corporation. The
total purchase price under the call is based on the terms of the
existing PCA among the parties and is $621 million. The transfer of
ownership requires various regulatory approvals, including the FERC,
the state environmental agency in New Jersey, and expiration of the
Hart Scott Rodino waiting period. Early termination of the Hart Scott
Rodino waiting period was granted effective August 22, 2003.
Under the terms of the PCA, the purchase price must be funded
within six months of the call notice being issued. Additionally,
because the Federal Power Act restricts Generation's ownership of more
than 50% of a qualifying facility, the qualifying facilities owned by
Sithe must be sold or restructured before closing to preserve their
status as qualifying facilities. See below for information regarding a
separate agreement reached by Sithe to sell six U.S. generating
facilities, each a qualifying facility, and an entity holding Sithe's
Canadian assets. At the closing, Sithe is expected to distribute in
excess of $600 million of available cash to Generation.
On August 13, 2003, Generation announced an agreement with
entities controlled by Reservoir, a private investment firm, to sell
50% of Sithe in exchange for $75.8 million in cash. The sale will occur
after Generation's purchase of the remaining 50.1% interest in Sithe.
The sale requires FERC approval, a Hart Scott Rodino filing and a
filing with the state regulatory commission in New York. Both of these
filings have been made. Early termination of the Hart Scott Rodino
waiting period was granted September 30, 2003. The sale is expected to
close in the fourth quarter of 2003.
155
Both Exelon and Reservoir's 50% interests in Sithe will be
subject to put and call options that could result in either party
owning 100% of Sithe. While Exelon's intent is to fully divest Sithe by
the end of 2004, the timing of the put and call options vary by
acquirer and can extend through March 2006. The pricing of the put and
call options is dependent on numerous factors such as the acquirer,
date of acquisition and assets owned by Sithe at the time of exercise.
In a separate transaction, Sithe has entered into an agreement
with Reservoir to sell entities holding six U.S. generating facilities,
each a qualifying facility under the Public Utility Regulatory Policies
Act, and an entity holding Sithe's Canadian assets in exchange for
$46.2 million ($26.2 million in cash and a $20 million two-year note).
The sale requires approvals from Sithe's board of directors and
shareholders and regulatory filings in New Jersey and Canada. Both
these filing have been made. The sale is also expected to close in the
fourth quarter of 2003. This sale is not contingent on the sale of
Generation's 50% interest in Sithe to Reservoir.
o In June 2003, Generation entered an agreement with USEC Inc. to
purchase approximately $700 million of nuclear fuel from 2005 through
2010.
o On August 14, 2003, Generation received a letter from the Department
of Energy (DOE) demanding repayment of $40 million of previously
received credits from the Nuclear Waste Fund. The letter also demanded
$1.5 million of accrued interest expense. Although a new settlement
would offset Generation's payments, Generation nonetheless has
reserved its 50% ownership share of these amounts. Because Generation
expenses the casks and capitalizes the permanent components of its
spent fuel storage facilities, these reserves increased Generation's
operating and maintenance expense approximately $11 million and its
capital base approximately $9 million during the third quarter of
2003. The remainder of the recorded obligation to the DOE will be
recovered from the co-owner of the facility. See Note 9 - Nuclear
Decommissioning and Spent Nuclear Fuel Storage in Generation's 2002
Form 10-K for additional information regarding this matter.
o Under the Price-Anderson Act, all nuclear reactor licensees can be
assessed a maximum charge per reactor per incident. Effective August
20, 2003, the maximum assessment for all nuclear operators per reactor
per incident (including a 5% surcharge) increased from $89 million to
$101 million. The maximum payable per reactor per incident per year of
$10 million is unchanged. The change in the maximum assessment is the
result of an inflation adjustment, required by the Price-Anderson Act.
Based on the increase of the maximum assessment, Generation's nuclear
insurance guarantee of AmerGen's plants increased from $134 million to
$151 million.
156
o On October 10, 2003, Exelon executed an agreement to purchase British
Energy's 50% interest in AmerGen for $276.5 million. The transaction
is expected to close in the first half of 2004. The purchase price
matched the offer by FPL Energy, which announced on September 11, 2003
that it intended to buy British Energy's share of AmerGen. Under the
AmerGen limited liability company operating agreement between Exelon
and British Energy, either can exercise a right of first refusal by
matching any bona fide third-party offer agreed to by the other
member. See Note 4 of the Condensed Combined Notes to Financial
Statements for additional information regarding AmerGen.
As discussed in Note 2 of the Condensed Combined Notes to
Consolidated Financial Statements, it is reasonably possible that
Generation will consolidate Sithe and AmerGen as of December 31, 2003
pursuant to FIN No. 46, "Consolidation of Variable Interest Entities." See
Note 4 of the Condensed Combined Notes to Consolidated Financial Statements
for further discussion of Generation's investments in Sithe and AmerGen.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
Commodity Price Risk
Generation
Commodity price risk is associated with market price movements
resulting from excess or insufficient generation, changes in fuel costs,
market liquidity and other factors. Trading activities and non-trading
marketing activities include the purchase and sale of electric capacity and
energy and fossil fuels, including oil, gas, coal and emission allowances.
The availability and prices of energy and energy-related commodities are
subject to fluctuations due to factors such as weather, governmental
environmental policies, changes in supply and demand, state and Federal
regulatory policies and other events.
Normal Operations and Hedging Activities
Electricity available from Generation's owned or contracted
generation supply in excess of its obligations to customers, including
Energy Delivery's retail load, is sold into the wholesale markets. To
reduce price risk caused by market fluctuations, Generation enters into
physical contracts as well as derivative contracts, including forwards,
futures, swaps, and options, with approved counterparties to hedge its
anticipated exposures. The maximum length of time over which cash flows
related to energy commodities are currently being hedged is four years.
Generation has an estimated 94% hedge ratio in 2003 for its energy
marketing portfolio. This hedge ratio represents the percentage of
Generation's forecasted aggregate annual economic generation supply that is
committed to firm sales, including sales to ComEd and PECO's retail load.
ComEd and PECO's retail load assumptions are based on forecasted average
demand. The hedge ratio is not fixed and will vary from time to time
depending upon market conditions, demand, and energy market option
volatility and actual loads. During peak periods, the amount hedged
declines to meet the commitment to ComEd and PECO.
157
Market price risk exposure is the risk of a change in the value of
unhedged positions. Absent any opportunistic efforts to mitigate market
price exposure, the estimated market price exposure for Generation's
non-trading portfolio associated with a ten percent reduction in the annual
average around-the-clock market price of electricity is an approximately $6
million decrease in net income, or approximately $0.02 per share. This
sensitivity assumes a consistent hedge ratio and that price changes occur
evenly throughout the year and across all markets. The sensitivity also
assumes a static portfolio. Generation expects to actively manage its
portfolio to mitigate market price exposure. Actual results could differ
depending on the specific timing of, and markets affected by, price
changes, as well as future changes in Generation's portfolio.
Proprietary Trading Activities
Generation uses financial contracts for proprietary trading
purposes. Proprietary trading includes all contracts entered into purely to
profit from market price changes as opposed to hedging an exposure. These
activities are accounted for on a mark-to-market basis. The proprietary
trading activities are a complement to Generation's energy marketing
portfolio and represent a very small portion of its overall energy
marketing activities. For example, the limit on open positions in
electricity for any forward month represents less than 1% of Generation's
owned and contracted supply of electricity. The trading portfolio is
subject to stringent risk management limits and policies, including volume,
stop-loss and value-at-risk limits.
Generation's energy contracts are accounted for under SFAS No.
133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS
No. 133). Most non-trading contracts qualify for the normal purchases and
normal sales exemption to SFAS No. 133 discussed in the Critical Accounting
Estimates section of Management's Discussion and Analysis of Financial
Condition and Result of Operations of the 2002 Form 10-K. Those that do not
are recorded as assets or liabilities on the balance sheet at fair value.
Changes in the fair value of qualifying hedge contracts are recorded in
Other Comprehensive Income (OCI), and gains and losses are recognized in
earnings when the underlying transaction occurs. Changes in the fair value
of derivative contracts that do not meet hedge criteria under SFAS No. 133
and the ineffective portion of hedge contracts are recognized in earnings
on a current basis.
The following detailed presentation of the trading and non-trading
marketing activities at Generation is included to address the recommended
disclosures by the energy industry's Committee of Chief Risk Officers.
Generation does not consider its proprietary trading to be a significant
activity in its business; however, Generation believes it is important to
include these risk management disclosures.
158
The following tables describe the drivers of Generation's energy
trading and marketing business and gross margin included in the income
statement for the three and nine months ended September 30, 2003. Normal
operations and hedging activities represent the marketing of electricity
available from Generation's owned or contracted generation sold into the
wholesale market, including to ComEd and PECO to serve their retail loads.
As the information in these tables highlights, mark-to-market activities
represent a small portion of the overall gross margin for Generation.
Accrual activities, including normal purchases and sales, account for the
majority of the gross margin. The mark-to-market activities reported here
are those relating to changes in fair value due to external movement in
prices. Further delineation of gross margin by the type of accounting
treatment typically afforded each type of activity is also presented (i.e.,
mark-to-market vs. accrual accounting treatment).
Three Months Ended September 30, 2003
-----------------------------------------------------
Normal Operations and Proprietary
Hedging Activities (a) Trading Total
------------------------------------------------------------------------------------------------------------------
Mark-to-market activities:
--------------------------
Unrealized mark-to-market gain/(loss)
Origination unrealized gain/(loss) at inception $ -- $ -- $ --
Changes in fair value prior to settlements 47 1 48
Changes in valuation techniques and assumptions -- -- --
Reclassification to realized at settlement of contracts (65) (1) (66)
------------------------------------------------------------------------------------------------------------------
Total change in unrealized fair value (18) -- (18)
Realized net settlement of transactions subject to mark-to-market 65 1 66
------------------------------------------------------------------------------------------------------------------
Total mark-to-market activities gross margin $ 47 $ 1 $ 48
------------------------------------------------------------------------------------------------------------------
Accrual activities:
-------------------
Accrual activities revenue $ 1,642 $ -- $ 1,642
Hedge gains/(losses) reclassified from OCI 710 -- 710
------------------------------------------------------------------------------------------------------------------
Total revenue - accrual activities 2,352 -- 2,352
------------------------------------------------------------------------------------------------------------------
Purchased power and fuel 765 -- 765
Hedges of purchased power and fuel reclassified from OCI 787 -- 787
------------------------------------------------------------------------------------------------------------------
Total purchased power and fuel 1,552 -- 1,552
------------------------------------------------------------------------------------------------------------------
Total accrual activities gross margin 800 -- 800
------------------------------------------------------------------------------------------------------------------
Total gross margin $ 847 $ 1 $ 848 (b)
==================================================================================================================
(a) Normal Operations and Hedging Activities only include derivative
contracts Generation enters into to hedge anticipated exposures
related to its owned and contracted generation supply, but excludes
its owned and contracted generating assets.
(b) Total Gross Margin represents revenue, net of purchased power and fuel
expense for Generation.
159
Nine Months Ended September 30, 2003
----------------------------------------------------------
Normal Operations and Proprietary
Hedging Activities (a) Trading Total
------------------------------------------------------------------------------------------------------------------
Mark-to-market activities:
--------------------------
Unrealized mark-to-market gain/(loss)
Origination unrealized gain/(loss) at inception $ -- $ -- $ --
Changes in fair value prior to settlements 182 (1) 181
Changes in valuation techniques and assumptions -- -- --
Reclassification to realized at settlement of contracts (199) (3) (202)
------------------------------------------------------------------------------------------------------------------
Total change in unrealized fair value (17) (4) (21)
Realized net settlement of transactions subject to mark-to-market 199 3 202
------------------------------------------------------------------------------------------------------------------
Total mark-to-market activities gross margin $ 182 $ (1) $ 181
------------------------------------------------------------------------------------------------------------------
Accrual activities:
-------------------
Accrual activities revenue $ 4,099 $ -- $ 4,099
Hedge gains/(losses) reclassified from OCI 1,724 -- 1,724
------------------------------------------------------------------------------------------------------------------
Total revenue - accrual activities 5,823 -- 5,823
------------------------------------------------------------------------------------------------------------------
Purchased power and fuel 1,745 -- 1,745
Hedges of purchased power and fuel reclassified from OCI 1,995 -- 1,995
------------------------------------------------------------------------------------------------------------------
Total purchased power and fuel 3,740 -- 3,740
------------------------------------------------------------------------------------------------------------------
Total accrual activities gross margin 2,083 -- 2,083
------------------------------------------------------------------------------------------------------------------
Total gross margin $ 2,265 $ (1) $ 2,264 (b)
==================================================================================================================
(a) Normal Operations and Hedging Activities only include derivative
contracts Generation enters into to hedge anticipated exposures
related to its owned and contracted generation supply, but excludes
its owned and contracted generating assets.
(b) Total Gross Margin represents revenue, net of purchased power and fuel
expense for Generation.
The following table provides detail on changes in Generation's
mark-to-market net asset or liability balance sheet position from January
1, 2003 to September 30, 2003. It indicates the drivers behind changes in
the balance sheet amounts. This table incorporates the mark-to-market
activities that are recorded in earnings, as shown in the previous table,
as well as the settlements from OCI to earnings and changes in fair value
for the hedging activities that are recorded in Accumulated Other
Comprehensive Income on the September 30, 2003 Consolidated Balance Sheet.
Normal Operations and Proprietary
Hedging Activities Trading Total
------------------------------------------------------------------------------------------------------------------
Total mark-to-market energy contract net assets
(liabilities) at January 1, 2003 $ (168) $ 5 $ (163)
Total change in fair value for the nine months ended September 30, 2003
of contracts recorded in earnings 182 (1) 181
Reclassification to realized at settlement of contracts recorded in earnings (199) (3) (202)
Reclassification to realized at settlement from OCI 271 -- 271
Effective portion of changes in fair value - recorded in OCI (205) -- (205)
Purchase/sale of existing contracts or portfolios subject to mark-to-market -- -- --
------------------------------------------------------------------------------------------------------------------
Total mark-to-market energy contract net assets (liabilities)
at September 30, 2003 $ (119) $ 1 $ (118)
==================================================================================================================
160
The following table details the balance sheet classification of
the mark-to-market energy contract net assets recorded as of September 30,
2003:
Normal Operations and Proprietary
Hedging Activities Trading Total
-------------------------------------------------------------------------------------------------------------------
Current assets $ 204 $ 1 $ 205
Noncurrent assets 79 -- 79
------------------------------------------------------------------------------------------------------------------
Total mark-to-market energy contract assets 283 1 284
------------------------------------------------------------------------------------------------------------------
Current liabilities (301) -- (301)
Noncurrent liabilities (101) -- (101)
------------------------------------------------------------------------------------------------------------------
Total mark-to-market energy contract liabilities (402) -- (402)
------------------------------------------------------------------------------------------------------------------
Total mark-to-market energy contract net assets (liabilities) $ (119) $ 1 $ (118)
==================================================================================================================
The majority of Generation's contracts are non-exchange traded
contracts valued using prices provided by external sources, primarily price
quotations available through brokers or over-the-counter, on-line
exchanges. Prices reflect the average of the bid-ask midpoint prices
obtained from all sources that Generation believes provide the most liquid
market for the commodity. The terms for which such price information is
available varies by commodity, by region and by product. The remainder of
the assets represents contracts for which external valuations are not
available, primarily option contracts. These contracts are valued using the
Black model, an industry standard option valuation model. The fair values
in each category reflect the level of forward prices and volatility factors
as of September 30, 2003 and may change as a result of changes in these
factors. Management uses its best estimates to determine the fair value of
commodity and derivative contracts it holds and sells. These estimates
consider various factors including closing exchange and over-the-counter
price quotations, time value, volatility factors and credit exposure. It is
possible, however, that future market prices could vary from those used in
recording assets and liabilities from energy marketing and trading
activities and such variations could be material.
161
The following table, which presents maturity and source of fair
value of mark-to-market energy contract net assets, provides two
fundamental pieces of information. First, the table provides the source of
fair value used in determining the carrying amount of Generation's total
mark-to-market asset or liability. Second, this table provides the
maturity, by year, of Generation's net assets/liabilities, giving an
indication of when these mark-to-market amounts will settle and generate or
require cash.
Maturities within
-----------------------------------------------------------
2008 and Total Fair
2003 2004 2005 2006 2007 Beyond Value
------------------------------------------------------------------------------------------------------------------------
Normal Operations, qualifying cash flow hedge contracts (1):
Prices provided by other external sources $(6) $ (98) $ (10) $ (6) $ -- $ -- $ (120)
------------------------------------------------------------------------------------------------------------------------
Total $(6) $ (98) $ (10) $ (6) $ -- $ -- $ (120)
------------------------------------------------------------------------------------------------------------------------
Normal Operations, other derivative contracts (2):
Actively quoted prices $ -- $ 2 $ -- $ -- $ -- $ -- $ 2
Prices provided by other external sources 4 14 5 4 -- -- 27
Prices based on model or other valuation methods 4 (17) (3) (9) (3) -- (28)
------------------------------------------------------------------------------------------------------------------------
Total $ 8 $ (1) $ 2 $ (5) $ (3) $ -- $ 1
------------------------------------------------------------------------------------------------------------------------
Proprietary Trading, other derivative contracts (3):
Actively quoted prices $(2) $ 3 $ -- $ -- $ -- $ -- $ 1
Prices provided by other external sources 1 (4) 1 -- -- -- (2)
Prices based on model or other valuation methods 1 1 -- -- -- -- 2
------------------------------------------------------------------------------------------------------------------------
Total $-- $ -- $ 1 $ -- $ -- $ -- $ 1
========================================================================================================================
Average tenor of proprietary trading portfolio (4) 1.75 years
========================================================================================================================
(1) Mark-to-market gains and losses on contracts that qualify as cash flow
hedges are recorded in other comprehensive income.
(2) Mark-to-market gains and losses on other non-trading derivative
contracts that do not qualify as cash flow hedges are recorded in
earnings.
(3) Mark-to-market gains and losses on trading contracts are recorded in
earnings.
(4) Following the recommendations of the Committee of Chief Risk Officers,
the average tenor of the proprietary trading portfolio measures the
average time to collect value for that portfolio. Generation measures
the tenor by separating positive and negative mark-to-market values in
its proprietary trading portfolio, estimating the mid-point in years
for each and then reporting the highest of the two mid-points
calculated. In the event that this methodology resulted in
significantly different absolute values of the positive and negative
cash flow streams, Generation would use the mid-point of the portfolio
with the largest cash flow stream as the tenor.
162
The table below provides details of effective cash flow hedges
under SFAS No. 133 included in the balance sheet as of September 30, 2003.
The data in the table gives an indication of the magnitude of SFAS No. 133
hedges Generation has in place, however, given that under SFAS No. 133 not
all hedges are recorded in OCI, the table does not provide an
all-encompassing picture of Generation's hedges. The table also includes a
roll-forward of Accumulated Other Comprehensive Income on the Consolidated
Balance Sheets related to cash flow hedges for the nine months ended
September 30, 2003, providing insight into the drivers of the changes (new
hedges entered into during the period and changes in the value of existing
hedges). Information related to energy merchant activities is presented
separately from interest rate hedging activities.
Total Cash Flow Hedge Other Comprehensive Income Activity,
Net of Income Tax
-------------------------------------------------------------------------------------------------------------------
Normal Operations and Interest Rate and Total Cash
Hedging Activities Other Hedges (1) Flow Hedges
-------------------------------------------------------------------------------------------------------------------
Accumulated OCI derivative loss at January 1, 2003 $ (114) $ (5) $ (119)
Changes in fair value (124) (11) (135)
Reclassifications from OCI to net income 165 -- 165
-------------------------------------------------------------------------------------------------------------------
Accumulated OCI derivative loss
at September 30, 2003 $ (73) $ (16) $ (89)
===================================================================================================================
(1) Includes interest rate hedges at Generation.
Generation uses a VaR model to assess the market risk associated
with financial derivative instruments entered into for proprietary trading
purposes. The measured VaR represents an estimate of the potential change
in value of Generation's proprietary trading portfolio.
The VaR estimate includes a number of assumptions about current
market prices, estimates of volatility and correlations between market
factors. These estimates, however, are not necessarily indicative of actual
results, which may differ because actual market rate fluctuations may
differ from forecasted fluctuations and because the portfolio may change
over the holding period.
Generation estimates VaR using a model based on the Monte Carlo
simulation of commodity prices that captures the change in value of forward
purchases and sales as well as option values. Parameters and values are
back tested daily against daily changes in mark-to-market value for
proprietary trading activity. VaR assumes that normal market conditions
prevail and that there are no changes in positions. Generation uses a 95%
confidence interval, one-day holding period, one-tailed statistical measure
in calculating its VaR. This means that Generation may state that there is
a one in 20 chance that if prices move against its portfolio positions, its
pre-tax loss in liquidating its portfolio in a one-day holding period would
exceed the calculated VaR. To account for unusual events and loss of
liquidity, Generation uses stress tests and scenario analysis.
For financial reporting purposes only, Generation calculates
several other VaR estimates. The higher the confidence interval, the less
likely the chance that the VaR estimate would be exceeded. A longer holding
period considers the effect of liquidity in being able to actually
liquidate the portfolio. A two-tailed test considers potential upside in
the portfolio in addition to the potential downside in the portfolio
163
considered in the one-tailed test. The following table provides the VaR for
all proprietary trading positions of Generation as of September 30, 2003.
Proprietary
Trading VaR
-------------------------------------------------------------------------------------------------------------------
95% Confidence Level, One-Day Holding Period, One-Tailed
Period end $ 0.1
Average for the period 0.1
High 0.2
Low 0.0
95% Confidence Level, Ten-Day Holding Period, Two-Tailed
Period end $ 0.2
Average for the period 0.3
High 0.6
Low 0.1
99% Confidence Level, One-Day Holding Period, Two-Tailed
Period end $ 0.1
Average for the period 0.1
High 0.2
Low 0.0
-------------------------------------------------------------------------------------------------------------------
Credit Risk
Generation
Generation has credit risk associated with counterparty
performance on energy contracts which includes, but is not limited to, the
risk of financial default or slow payment. Generation manages counterparty
credit risk through established policies, including counterparty credit
limits, and in some cases, requiring deposits and letters of credit to be
posted by certain counterparties. Generation's counterparty credit limits
are based on a scoring model that considers a variety of factors, including
leverage, liquidity, profitability, credit ratings and risk management
capabilities. Generation has entered into payment netting agreements or
enabling agreements that allow for payment netting with the majority of its
large counterparties, which reduce Generation's exposure to counterparty
risk by providing for the offset of amounts payable to the counterparty
against amounts receivable from the counterparty. The credit department
monitors current and forward credit exposure to counterparties and their
affiliates, both on an individual and an aggregate basis.
164
The following tables provide information on Generation's credit
exposure, net of collateral, as of September 30, 2003. They further
delineate that exposure by the credit rating of the counterparties and
provide guidance on the concentration of credit risk to individual
counterparties and an indication of the maturity of a company's credit risk
by credit rating of the counterparties. The tables below do not include
sales to Generation's affiliates or exposure through Independent System
Operators.
Total Number Of Net Exposure Of
Exposure Counterparties Counterparties
Before Credit Credit Net Greater than 10% Greater than 10%
Rating Collateral Collateral Exposure of Net Exposure of Net Exposure
--------------------------------------------------------------------------------------------------------------------------
Investment grade $ 208 $ -- $ 208 2 $ 81
Split rating -- -- -- -- --
Non-investment grade 14 6 8 -- --
No external ratings
Internally rated - investment grade 26 4 22 3 10
Internally rated - non-investment grade 11 5 6 1 11
--------------------------------------------------------------------------------------------------------------------------
Total $ 259 $ 15 $ 244 6 $ 102
==========================================================================================================================
Maturity of Credit Risk Exposure
---------------------------------------------------------------
Exposure Total Exposure
Less than Greater than Before Credit
Rating 2 Years 2-5 Years 5 Years Collateral
-------------------------------------------------------------------------------------------------------------------
Investment grade $ 194 $ 14 $ -- $ 208
Split rating -- -- -- --
Non-investment grade 14 -- -- 14
No external ratings
Internally rated - investment grade 25 1 -- 26
Internally rated - non-investment grade 11 -- -- 11
-------------------------------------------------------------------------------------------------------------------
Total $ 244 $ 15 $ -- $ 259
===================================================================================================================
Generation is a counterparty to Dynegy in various energy
transactions. The credit ratings of Dynegy are considered below investment
grade by two credit rating agencies. Generation has credit risk associated
with Dynegy through Generation's equity investment in Sithe. Sithe is a 60%
owner of the Independence generating station, a 1,040-MW gas-fired
qualified facility that has an energy-only long-term tolling agreement with
Dynegy with a related financial swap arrangement. As of September 30, 2003,
Sithe had recognized an asset on its balance sheet related to the fair
market value of the financial swap agreement with Dynegy that is
marked-to-market under the provisions of SFAS No. 133. If Dynegy is unable
to fulfill the terms of this agreement, Sithe would be required to impair
this financial swap asset. Generation estimates, as a 49.9% owner of Sithe,
that the impairment would result in an after-tax reduction of Generation's
equity earnings of approximately $16 million.
In addition to the impairment of the financial swap asset, if
Dynegy were unable to fulfill its obligations under the financial swap
agreement and the tolling agreement, Generation may incur a further
impairment associated with Sithe's Independence station.
165
Additionally, the future economic value of AmerGen's purchased
power arrangement with Illinois Power Company, a subsidiary of Dynegy,
could be impacted by events related to Dynegy's financial condition.
ComEd and Generation are parties to various transactions with
Midwest Generation. Midwest Generation's credit ratings have been
downgraded by certain credit rating agencies. Furthermore, the June 30,
2003 Form 10-Q filed by Edison Mission Energy (EME), an intermediate parent
company of Edison Mission Midwest Holdings (EMMH) and Midwest Generation,
indicates that EMMH is not expected to have sufficient cash to repay $911
million of debt when it matures on December 11, 2003; a failure to repay,
extend, or refinance the EMMH obligation would likely result in a default
under the senior secured notes and term loan of Mission Energy Holding
Company, EME's parent company; and these events could make it necessary for
EME to file a petition for reorganization under Chapter 11 of the United
States Bankruptcy Code. Reorganization under Chapter 11 of the United
States Bankruptcy Code does not assure non-performance under all contracts;
however, the reorganization would increase the possibility of the
obligations described in the following two paragraphs reverting to ComEd or
Generation.
In connection with ComEd's sale in December 1999 of fossil
generating assets to Midwest Generation, ComEd entered into an agency
agreement with EMMH and EME whereby EMMH assumed the benefits and
liabilities of a long-term coal purchase contract and a railcar lease. EME
guaranteed EMMH's performance. EMMH did not become a direct party to the
obligations, and ComEd remained obligated and was not released. In
connection with the Merger and subsequent restructuring, Generation assumed
any contingent obligation on these contracts from ComEd. In the event of
EMMH and EME's non-performance under the coal purchase contract, Generation
would be required to fulfill the purchase commitments that extend through
2012. The contract requires the purchase of two million tons of coal
annually or specifies a minimum payout. Based upon current market prices,
Generation's contingent obligations for the minimum purchase obligation for
the contract years 2003 to 2012 are estimated to be approximately $81
million (the net present value of the obligation approximates $51 million)
related to this agreement. The railcar lease covers approximately 1,400
coal transport railcars through 2014. In the event of EMMH and EME's
non-performance under the railcar lease, Generation would be required to
fulfill the lease payments that extend through 2014. The remaining lease
payments for the railcars approximate $65 million (the net present value of
the obligation approximates $38 million). However, based on current prices
for railcars in these particular markets, Generation believes it would be
able to effectively sublease the railcars without incurring any exposure
related to this obligation.
Generation and ComEd have entered into other agreements with
Midwest Generation and have other related exposures. In connection with
ComEd's fossil generating asset sale to Midwest Generation, Midwest
Generation and EME agreed to indemnify ComEd for various environmental
exposures or penalties. Generation assumed any contingent obligations
relating to generation-related environmental issues of ComEd in connection
with the Merger and subsequent restructuring. Exelon cannot reasonably
estimate the possible environmental exposures or penalties that could arise
if Midwest Generation or EME do not honor their indemnity to ComEd or if
the indemnity is discharged in bankruptcy. Midwest Generation also
indemnified Generation and ComEd for approximately 50% of any
post-acquisition asbestos claims relating to the plants sold to Midwest
Generation. Generation assumed any contingent obligations of ComEd relating
to these asbestos claims in connection with the Merger and subsequent
restructuring. The bankruptcy of or non-performance of Midwest Generation
of its obligations to Generation and ComEd for asbestos claims could result
in contingent obligations to Generation and ComEd of up to an estimated $5
million. In addition, ComEd is exposed to risks associated with accounts
receivable from transmission and station power services provided by ComEd
to Midwest Generation. The bankruptcy of or non-performance of Midwest
Generation of its obligations to ComEd for transmission and station power
services provided by ComEd could result in ComEd recording a write-off of
up to an estimated $3 million.
Generation accounts for certain derivative financial instruments
under the normal purchases and normal sales exemption of SFAS No. 133. As
of September 30, 2003, Generation is a party to forward energy purchase and
sale contracts with Midwest Generation, which are accounted for in that
manner and, as such, are not marked-to-market. If Generation determines
that the possibility of non-performance by Midwest Generation on these
contracts becomes more than remote, these contracts will be required to be
marked-to-market through earnings, which would be expected to result in a
charge to Exelon and Generation's results of operations and such charge
could be material.
As part of the normal course of business, Exelon and Generation
routinely enter into physical or financially settled contracts for the
purchase and sale of capacity, energy, fuels and emissions allowances.
These contracts either contain express provisions or otherwise permit
Exelon, Generation and its counterparties to demand adequate assurance of
future performance when there are reasonable grounds for doing so. In
accordance with the contracts and applicable contracts law, if Exelon or
Generation is downgraded by a credit rating agency, especially if such
downgrade is to a level below investment grade, it is possible that a
counterparty could attempt to rely on such a downgrade as a basis for
making a demand for adequate assurance of future performance. Depending on
Exelon or Generation's net position with a counterparty, the demand could
be for the posting of collateral. In the absence of expressly agreed to
provisions that specify the collateral that must be provided, the
obligation to supply the collateral requested will be a function of the
facts and circumstances of Exelon or Generation's situation at the time of
the demand. If Exelon or Generation can reasonably claim that it is willing
and financially able to perform its obligations, it may be possible to
successfully argue that no collateral should be posted or that only an
amount equal to two or three months of future payments should be
sufficient.
Interest Rate Risk
ComEd
ComEd 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. ComEd also
166
utilizes forward-starting interest rate swaps and treasury rate locks to
lock in interest rate levels in anticipation of future financing. These
strategies are employed to maintain the lowest cost of capital. At
September 30, 2003, ComEd has settled all of its interest rate swaps
designated as cash flow hedges.
ComEd has entered into fixed-to-floating interest rate swaps in
order to maintain its targeted percentage of variable rate debt associated
with fixed-rate debt issuances in the aggregate amount of $485 million. At
September 30, 2003, these interest rate swaps, designated as fair value
hedges, had an aggregate fair market value of $39 million based on the
present value difference between the contract and market rates at September
30, 2003. If these derivative instruments had been terminated at September
30, 2003, this estimated fair value represents the amount that would be
paid by the counterparties to ComEd.
The aggregate fair value of the interest rate swaps, designated as
fair value hedges, that would have resulted from a hypothetical 50 basis
point decrease in the spot yield at September 30, 2003 is estimated to be
$45 million in ComEd's favor.
The aggregate fair value of the interest rate swaps, designated as
fair value hedges, that would have resulted from a hypothetical 50 basis
point increase in the spot yield at September 30, 2003 is estimated to be
$33 million in ComEd's favor.
PECO
In February 2003, PECO entered into forward-starting interest rate
swaps in the aggregate amount of $360 million to lock in interest rate
levels in anticipation of future financings. The debt issuances that these
swaps were hedging were considered probable in February 2003 and closed in
April 2003; therefore, PECO accounted for these interest rate swap
transactions as hedges. In connection with PECO's April 28, 2003 issuance
of $450 million in First and Refunding Mortgage Bonds, PECO settled the
swaps for net proceeds of $1 million, which was recorded in other
comprehensive income and is being amortized over the life of the debt
issuance.
PECO 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. At September 30, 2003,
these interest rate swaps had an aggregate fair market value exposure of
$11 million based on the present value difference between the contract and
market rates at September 30, 2003. If these derivative instruments had
been terminated at September 30, 2003, this estimated fair value represents
the amount to be paid by PECO to the counterparties.
The aggregate fair value exposure of the interest rate swaps that
would have resulted from a hypothetical 50 basis point decrease in the spot
yield at September 30, 2003 is estimated to be $12 million in the
counterparties favor.
The aggregate fair value exposure of the interest rate swaps that
would have resulted from a hypothetical 50 basis point increase in the spot
yield at September 30, 2003 is estimated to be $10 million in the
counterparties favor.
167
PECO also has interest rate swaps in place to satisfy counterparty
credit requirements in regards to the floating rate series of transition
bonds which are mirror swaps of each other. These swaps are not designated
as cash flow hedges; therefore, they are required to be marked-to-market if
there is a difference in their values. Since these swaps offset each other,
a mark-to-market adjustment is not expected to occur.
Generation
Generation uses a combination of fixed rate and variable rate debt
to reduce interest rate exposure. Generation also uses interest rate swaps
when deemed appropriate to adjust exposure based upon market conditions.
These strategies are employed to achieve a lower cost of capital. As of
September 30, 2003, a hypothetical 10% increase in the interest rates
associated with variable rate debt would not have a material impact on
pre-tax earnings for the three and nine months ended September 30, 2003.
Under the terms of the EBG Facility, EBG is required to
effectively fix the interest rate on 50% of borrowings under the facility
through its maturity in 2007. As of September 30, 2003, EBG had entered
into interest rate swap agreements that have effectively fixed the interest
rate on $861 million of notional principal, or approximately 80% of
borrowings outstanding under the EBG Facility at September 30, 2003. The
fair market value exposure of these swaps, designated as cash flow hedges,
is $91 million. If these derivative instruments had been terminated at
September 30, 2003, this estimated fair value represents the amount to be
paid by EBG to the counterparties.
The aggregate fair value exposure of the interest rate swaps
designated as cash flow hedges that would have resulted from a hypothetical
50 basis point decrease in the spot yield at September 30, 2003 is
estimated to be $104 million in the counterparties favor.
The aggregate fair value exposure of the interest rate swaps
designated as cash flow hedges that would have resulted from a hypothetical
50 basis point increase in the spot yield at September 30, 2003 is
estimated to be $78 million in the counterparties favor.
In 2003, Generation entered into forward-starting interest rate
swaps in the aggregate amount of $400 million to lock in interest rate
levels in anticipation of future financings. The debt issuances that these
swaps are hedging are considered probable; therefore, Generation has
accounted for these interest rate swap transactions as hedges. At September
30, 2003, these interest rate swaps, designated as cash flow hedges, had an
aggregate fair market value exposure of less than $1 million based on the
present value of the difference between the contract and market rates at
September 30, 2003. If these derivative instruments had been terminated at
September 30, 2003, this estimated fair value represents the amount to be
paid by Generation to the counterparties.
The aggregate fair value exposure of the interest rate swaps
designated as cash flow hedges that would have resulted from a hypothetical
50 basis point decrease in the spot yield at September 30, 2003 is
estimated to be $17 million in the counterparties favor.
168
The aggregate fair value of the interest rate swaps designated as
cash flow hedges that would have resulted from a hypothetical 50 basis
point increase in the spot yield at September 30, 2003 is estimated to be
$16 million in Generation's favor.
Equity Price Risk
Generation
Generation maintains trust funds, as required by the NRC, to fund
certain costs of decommissioning its nuclear plants. As of September 30,
2003, decommissioning trust funds are reflected at fair value on
Generation's Consolidated Balance Sheets. The mix of securities in the
trust funds 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 trust funds
are exposed to price fluctuations in equity markets, and the value of fixed
rate, fixed income securities are exposed to changes in interest rates.
Generation actively monitors the investment performance of the trust funds
and periodically reviews asset allocation in accordance with Generation's
nuclear decommissioning trust fund investment policy. A hypothetical 10%
increase in interest rates and decrease in equity prices would result in a
$212 million reduction in the fair value of the trust assets.
ITEM 4. CONTROLS AND PROCEDURES
Exelon
During the third quarter of 2003, Exelon's management, including
the principal executive officer and principal financial officer, evaluated
Exelon's disclosure controls and procedures related to the recording,
processing, summarization and reporting of information in Exelon's periodic
reports that it files with the SEC. These disclosure controls and
procedures have been designed to ensure that (a) material information
relating to Exelon, including its consolidated subsidiaries, is made known
to Exelon's management, including these officers, by other employees of
Exelon and its subsidiaries, and (b) this information is recorded,
processed, summarized, evaluated and reported, as applicable, within the
time periods specified in the SEC's rules and forms. Due to the inherent
limitations of control systems, not all misstatements may be detected.
These inherent limitations include the realities that judgments in
decision-making can be faulty and that breakdowns can occur because of
simple error or mistake. Additionally, controls could be circumvented by
the individual acts of some persons or by collusion of two or more people.
Exelon's controls and procedures can only provide reasonable, not absolute,
assurance that the above objectives have been met. Also, Exelon does not
control or manage certain of its unconsolidated entities and as such, the
disclosure controls and procedures with respect to such entities are more
limited than those it maintains with respect to its consolidated
subsidiaries.
Accordingly, as of September 30, 2003, these officers (principal
executive officer and principal financial officer) concluded that Exelon's
disclosure controls and procedures were effective to accomplish their
objectives. Exelon continually strives to improve its disclosure controls
and procedures to enhance the quality of its financial reporting and to
maintain dynamic systems that change as conditions warrant.
169
ComEd
During the third quarter of 2003, ComEd's management, including
the principal executive officer and principal financial officer, evaluated
ComEd's disclosure controls and procedures related to the recording,
processing, summarization and reporting of information in ComEd's periodic
reports that it files with the SEC. These disclosure controls and
procedures have been designed to ensure that (a) material information
relating to ComEd, including its consolidated subsidiaries, is made known
to ComEd's management, including these officers, by other employees of
ComEd and its subsidiaries, and (b) this information is recorded,
processed, summarized, evaluated and reported, as applicable, within the
time periods specified in the SEC's rules and forms. Due to the inherent
limitations of control systems, not all misstatements may be detected.
These inherent limitations include the realities that judgments in
decision-making can be faulty and that breakdowns can occur because of
simple error or mistake. Additionally, controls could be circumvented by
the individual acts of some persons or by collusion of two or more people.
ComEd's controls and procedures can only provide reasonable, not absolute,
assurance that the above objectives have been met. Also, ComEd does not
control or manage certain of its unconsolidated entities and as such, the
disclosure controls and procedures with respect to such entities are more
limited than those it maintains with respect to its consolidated
subsidiaries.
Accordingly, as of September 30, 2003, these officers (principal
executive officer and principal financial officer) concluded that ComEd's
disclosure controls and procedures were effective to accomplish their
objectives. ComEd continually strives to improve its disclosure controls
and procedures to enhance the quality of its financial reporting and to
maintain dynamic systems that change as conditions warrant.
PECO
During the third quarter of 2003, PECO's management, including the
principal executive officer and principal financial officer, evaluated
PECO's disclosure controls and procedures related to the recording,
processing, summarization and reporting of information in PECO's periodic
reports that it files with the SEC. These disclosure controls and
procedures have been designed to ensure that (a) material information
relating to PECO, including its consolidated subsidiaries, is made known to
PECO's management, including these officers, by other employees of PECO and
its subsidiaries, and (b) this information is recorded, processed,
summarized, evaluated and reported, as applicable, within the time periods
specified in the SEC's rules and forms. Due to the inherent limitations of
control systems, not all misstatements may be detected. These inherent
limitations include the realities that judgments in decision-making can be
faulty and that breakdowns can occur because of simple error or mistake.
Additionally, controls could be circumvented by the individual acts of some
persons or by collusion of two or more people. PECO's controls and
procedures can only provide reasonable, not absolute, assurance that the
above objectives have been met. Also, PECO does not control or manage
certain of its unconsolidated entities and as such, the disclosure controls
and procedures with respect to such entities are more limited than those it
maintains with respect to its consolidated subsidiaries.
Accordingly, as of September 30, 2003, these officers (principal
executive officer and principal financial officer) concluded that PECO's
disclosure controls and procedures were effective to accomplish their
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objectives. PECO continually strives to improve its disclosure controls and
procedures to enhance the quality of its financial reporting and to
maintain dynamic systems that change as conditions warrant.
Generation
During the third quarter of 2003, Generation's management,
including the principal executive officer and principal financial officer,
evaluated Generation's disclosure controls and procedures related to the
recording, processing, summarization and reporting of information in
Generation's periodic reports that it files with the SEC. These disclosure
controls and procedures have been designed to ensure that (a) material
information relating to Generation, including its consolidated
subsidiaries, is made known to Generation's management, including these
officers, by other employees of Generation and its subsidiaries, and (b)
this information is recorded, processed, summarized, evaluated and
reported, as applicable, within the time periods specified in the SEC's
rules and forms. Due to the inherent limitations of control systems, not
all misstatements may be detected. These inherent limitations include the
realities that judgments in decision-making can be faulty and that
breakdowns can occur because of simple error or mistake. Additionally,
controls could be circumvented by the individual acts of some persons or by
collusion of two or more people. Generation's controls and procedures can
only provide reasonable, not absolute, assurance that the above objectives
have been met. Also, Generation does not control or manage certain of its
unconsolidated entities and as such, the disclosure controls and procedures
with respect to such entities are more limited than those it maintains with
respect to its consolidated subsidiaries.
Accordingly, as of September 30, 2003, these officers (principal
executive officer and principal financial officer) concluded that
Generation's disclosure controls and procedures were effective to
accomplish their objectives. Generation continually strives to improve its
disclosure controls and procedures to enhance the quality of its financial
reporting and to maintain dynamic systems that change as conditions
warrant.
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PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
ComEd
As previously reported in the 2002 Form 10-K and the June 2003
Form 10-Q, three of ComEd's wholesale municipal customers had filed a
complaint and request for refund with the FERC alleging that ComEd failed
to properly adjust its rates pursuant to the terms of the respective
electric service contracts. In July 2003 ComEd and the municipal customers
executed a settlement agreement ending the litigation. Pursuant to the
settlement, ComEd paid approximately $3 million, in total, to the three
municipalities.
Generation
As previously reported in the 2002 Form 10-K and the June 2003
Form 10-Q, Generation and Raytheon are involved in various litigation
matters in connection with EBG. On August 29, 2003, Raytheon filed a new
action against two subsidiaries of EBG (Project Companies) and BNP Paribas
in the Superior Court of the Commonwealth of Massachusetts. Raytheon
alleged that the Project Companies and BNP Paribas failed to provide
adequate assurance that Raytheon would be paid the remaining amounts due
under the Fore River and Mystic construction contracts. Raytheon sought:
(1) an injunction preventing the Project Companies and BNP Paribas from
drawing upon certain letters of credit guaranteeing Raytheon's performance;
(2) the right to terminate the construction contracts; and (3) an order
allowing Raytheon to seize project funds totaling approximately $40
million. Raytheon subsequently dismissed BNP Paribas from the litigation.
On October 9, 2003, the court issued a preliminary injunction preserving
the status quo and preventing the Project Companies from drawing upon the
letters of credit until such time as the court decides Raytheon's pending
motion for partial summary judgment. The court has heard argument on
Raytheon's motion for partial summary judgment but has not announced any
decision.
On October 2, 2003, Mitsubishi Heavy Industries, LTD (MHI) and
Mitsubishi Heavy Industries of America (MHIA) filed a New York state court
action against Exelon Mystic Development, LLC and Exelon Fore River
Development, LLC seeking to enjoin these indirect subsidiaries of
Generation from drawing upon letters of credit posted to guarantee MHI's
performance under certain gas turbine contracts. MHI and MHIA also seek $34
million from these entities in connection with work performed on these
contracts. Generation believes that Exelon Mystic's and Exelon Fore River's
contracts with MHI and MHIA have been assigned to Raytheon Corporation and
that the claims against the Exelon entities are without merit.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
Generation
EBG has approximately $1.1 billion of debt outstanding under the
EBG Facility. The EBG Facility, which is non-recourse to Generation, was
entered into primarily to finance the construction of Mystic 8 and 9 and
Fore River and required that all of the projects achieve Project Completion
by June 12, 2003. EBG negotiated an extension of the required
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completion date to July 11, 2003. Project Completion was not achieved by
July 12, 2003, resulting in an event of default under the EBG Facility.
Although the generating units are in commercial operation, Project
Completion has not been achieved to date. The event of default under the
EBG Facility does not constitute an event of default under any other debt
instruments of Exelon or its subsidiaries. EBG does not know which, if any,
remedies the lenders will exercise.
ITEM 5. OTHER INFORMATION
ComEd
As previously reported in the 2002 Form 10-K, in July 2002, the
FERC conditionally approved ComEd's decision to join PJM. On April 1, 2003,
ComEd received approval from the FERC to transfer control of ComEd's
transmission assets to PJM. The FERC also accepted for filing the PJM
tariff as amended to reflect the inclusion of ComEd and other new members,
subject to a compliance filing, which was made on May 1, 2003, and to
hearing on certain issues. On June 2, 2003, ComEd began receiving electric
transmission reservation services from PJM and transferred control of its
Open Access Same Time Information System to PJM. On September 11, 2003, the
August 14, 2003 blackout caused PJM to delay ComEd's integration until
spring of 2004. PJM wants to integrate any lessons learned from the
blackout probes into ComEd's transition plan.
On August 21, 2003, ComEd set a new record for highest daily peak
load experienced to date of 22,054 MWs.
PECO
As previously reported in the 2002 Form 10-K, the PUC's Final
Electric Restructuring Order established MSTs to promote competition. On
May 1, 2003, the PUC approved the residential customer plan filed by PECO
in February 2003. Under the plan and subsequent auction in September 2003,
an aggregate of 267,000 residential customers will be transferred to
alternative electric generation suppliers during December 2003. Any
customer transferred has the right to return to PECO at any time.
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ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits:
10.1 - Retirement and Separation between Exelon Corporation, PECO
Energy Company and Kenneth G. Lawrence, dated as of May 11,
2003. Filed on behalf of PECO.
10.2 - Purchase and Sale Agreement dated as of October 10, 2003
between British Energy Investment Ltd. and Exelon Generation
Company, LLC relating to the sale and purchase of 100% of the
shares of British Energy US Holdings Inc. Filed on behalf of
Exelon and Generation.
Certifications Pursuant to Rule 13a-14(a) and 15d-14(a) of the
Securities and Exchange Act of 1934 as to the Quarterly Report on
Form 10-Q for the quarterly period ended September 30, 2003 filed by
the following officers for the following companies:
- --------------------------------------------------------------------------------
31-1 - Filed by John W. Rowe for Exelon Corporation
31-2 - Filed by Robert S. Shapard for Exelon Corporation
31-3 - Filed by Michael B. Bemis for Commonwealth Edison Company
31-4 - Filed by Robert S. Shapard for Commonwealth Edison Company
31-5 - Filed by Michael B. Bemis for PECO Energy Company
31-6 - Filed by Robert S. Shapard for PECO Energy Company
31-7 - Filed by Oliver D. Kingsley Jr. for Exelon Generation Company, LLC
31-8 - Filed by Robert S. Shapard for Exelon Generation Company, LLC
- --------------------------------------------------------------------------------
Certifications Pursuant to Section 1350 of Chapter 63 of Title 18
United States Code (Sarbanes - Oxley Act of 2002) as to the Quarterly
Report on Form 10-Q for the quarterly period ended September 30, 2003
filed by the following officers for the following companies:
- --------------------------------------------------------------------------------
32-1 - Filed by John W. Rowe for Exelon Corporation
32-2 - Filed by Robert S. Shapard for Exelon Corporation
32-3 - Filed by Michael B. Bemis for Commonwealth Edison Company
32-4 - Filed by Robert S. Shapard for Commonwealth Edison Company
32-5 - Filed by Michael B. Bemis for PECO Energy Company
32-6 - Filed by Robert S. Shapard for PECO Energy Company
32-7 - Filed by Oliver D. Kingsley Jr. for Exelon Generation Company, LLC
32-8 - Filed by Robert S. Shapard for Exelon Generation Company, LLC
- --------------------------------------------------------------------------------
(b) Reports on Form 8-K:
Exelon, ComEd, PECO and/or Generation filed Current Reports on Form 8-K
during the three months ended September 30, 2003 regarding the following
items:
Date of Earliest
Event Reported Description of Item Reported
- --------------------------------------------------------------------------------
July 3, 2003 "ITEM 5. OTHER EVENTS" filed for Exelon and Generation
regarding the fact that EBG did not anticipate that
the construction of the Mystic 8 and 9 and Fore River
generating stations would achieve Project Completion
as defined in EBG's credit facility by July 11, 2003.
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July 29, 2003 "ITEM 5. OTHER EVENTS" filed for Exelon and Generation
announcing that Exelon commenced the process of an
orderly transition out of the ownership of EBG and the
projects.
August 6, 2003 "ITEM 5. OTHER EVENTS" filed for Exelon, ComEd, PECO
and Generation reaffirming Exelon's 2003 earnings
guidance and announcing workforce reductions related
to The Exelon Way.
August 13, 2003 "ITEM 5. OTHER EVENTS" filed for Exelon and Generation
regarding a note to Exelon's financial community
announcing an agreement with entities controlled by
Reservoir to sell 50% of Sithe, after closing on a
call transaction announced in May 2003. In a separate
transaction, Sithe has entered into an agreement with
Resevoir to sell entities holding six U.S. generating
facilities and an entity holding Sithe's Canadian
assets.
August 25, 2003 "ITEM 5. OTHER EVENTS" filed for ComEd regarding
ComEd's sale of $250 million of First Mortgage Bonds.
"ITEM 7. FINANCIAL STATEMENTS AND EXHIBITS" including
exhibits to ComEd's Form S-3, Registration No.
333-99363.
August 29, 2003 "ITEM 5. OTHER EVENTS" filed for Exelon and Generation
regarding the fact that the period during which the
lenders were precluded from exercising any remedies
resulting from the failure of the EBG projects to
achieve Project Completion had expired. Exelon was
continuing discussions with the lenders regarding the
orderly transition of the projects. Exelon has
informed the lenders that Generation will not provide
additional funding to the projects beyond its existing
contractual obligations.
September 12, 2003 "ITEM 5. OTHER EVENTS" filed for Exelon and ComEd
regarding a filing with the Federal Energy Regulatory
Commission to seek an adjustment in transmission
rates. The exhibit includes the press release
announcing the filing.
September 24, 2003 "ITEM 5. OTHER EVENTS" filed for Exelon announcing
that it had finalized the sale of InfraSource, Inc.
September 26, 2003 "ITEM 5. OTHER EVENTS" filed for Exelon and ComEd
announcing that Exelon is exploring the possibility of
acquiring Illinois Power Company from Dynegy Inc.
- --------------------------------------------------------------------------------
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SIGNATURES
- --------------------------------------------------------------------------------
Pursuant to requirements of the Securities Exchange Act of 1934,
the registrant has duly caused this report to be signed on its behalf by
the undersigned thereunto duly authorized.
EXELON CORPORATION
/s/ John W. Rowe /s/ Robert S. Shapard
----------------- ----------------------
JOHN W. ROWE ROBERT S. SHAPARD
Chairman and Executive Vice President and Chief
Chief Executive Officer Financial Officer
(Principal Executive Officer) (Principal Financial Officer)
/s/ Matthew F. Hilzinger
------------------------
MATTHEW F. HILZINGER
Vice President and Corporate Controller
(Principal Accounting Officer)
October 29, 2003
Pursuant to requirements of the Securities Exchange Act of 1934,
the registrant has duly caused this report to be signed on its behalf by
the undersigned thereunto duly authorized.
COMMONWEALTH EDISON COMPANY
/s/ Michael B. Bemis /s/ Robert S. Shapard
-------------------- ----------------------
MICHAEL B. BEMIS ROBERT S. SHAPARD
President, Exelon Energy Delivery Executive Vice President and Chief
(Principal Executive Officer) Financial Officer, Exelon
(Principal Financial Officer)
/s/ Duane M. DesParte /s/ Frank M. Clark
--------------------- ------------------
DUANE M. DESPARTE FRANK M. CLARK
Vice President and Controller, President, ComEd
Exelon Energy Delivery
(Principal Accounting Officer)
October 29, 2003
176
- --------------------------------------------------------------------------------
Pursuant to requirements of the Securities Exchange Act of 1934,
the registrant has duly caused this report to be signed on its behalf by
the undersigned thereunto duly authorized.
PECO ENERGY COMPANY
/s/ Michael B. Bemis /s/ Robert S. Shapard
-------------------- ----------------------
MICHAEL B. BEMIS ROBERT S. SHAPARD
President, Exelon Energy Delivery Executive Vice President and Chief
(Principal Executive Officer) Financial Officer, Exelon
(Principal Financial Officer)
/s/ Duane M. DesParte /s/ Denis P. O'Brien
--------------------- --------------------
DUANE M. DESPARTE DENIS P. O'BRIEN
Vice President and Controller, President, PECO
Exelon Energy Delivery
(Principal Accounting Officer)
October 29, 2003
- --------------------------------------------------------------------------------
Pursuant to requirements of the Securities Exchange Act of 1934,
the registrant has duly caused this report to be signed on its behalf by
the undersigned thereunto duly authorized.
EXELON GENERATION COMPANY, LLC
/s/ Oliver D. Kingsley Jr. /s/ Robert S. Shapard
-------------------------- ---------------------
OLIVER D. KINGSLEY JR. ROBERT S. SHAPARD
Chief Executive Officer and Executive Vice President and Chief
President Financial Officer, Exelon
(Principal Executive Officer) (Principal Financial Officer)
/s/ Thomas Weir III
------------------------------
THOMAS WEIR III
Vice President and Controller
(Principal Accounting Officer)
October 29, 2003
177