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 June 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
June 30, 2003 was:
Exelon Corporation Common Stock, without par value 325,848,491
Commonwealth Edison Company Common Stock, $12.50 par value 127,016,429
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 61
Exelon Corporation 61
Commonwealth Edison Company 90
PECO Energy Company 105
Exelon Generation Company, LLC 120
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK 135
ITEM 4. CONTROLS AND PROCEDURES 147
PART II. OTHER INFORMATION 150
ITEM 1. LEGAL PROCEEDINGS 150
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 150
ITEM 5. OTHER INFORMATION 152
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K 153
SIGNATURES 156
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 Corporation'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 June 30, Six Months Ended June 30,
--------------------------- -------------------------
(in millions, except per share data) 2003 2002 2003 2002
- -------------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES $ 3,721 $ 3,519 $ 7,795 $ 6,876
OPERATING EXPENSES
Purchased power 746 699 1,586 1,311
Purchased power from unconsolidated affiliate 110 60 177 116
Fuel 531 364 1,356 860
Operating and maintenance 1,100 1,070 2,212 2,137
Depreciation and amortization 275 332 549 667
Taxes other than income 159 181 358 367
- -------------------------------------------------------------------------------------------------------------------------
Total operating expenses 2,921 2,706 6,238 5,458
- -------------------------------------------------------------------------------------------------------------------------
OPERATING INCOME 800 813 1,557 1,418
- -------------------------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest expense (220) (241) (443) (490)
Distributions on preferred securities of subsidiaries (10) (11) (22) (23)
Equity in earnings of unconsolidated affiliates 15 9 33 22
Other, net 9 194 (134) 222
- -------------------------------------------------------------------------------------------------------------------------
Total other income and deductions (206) (49) (566) (269)
- -------------------------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT
OF CHANGES IN ACCOUNTING PRINCIPLES 594 764 991 1,149
INCOME TAXES 222 279 370 427
- -------------------------------------------------------------------------------------------------------------------------
INCOME BEFORE CUMULATIVE EFFECT OF CHANGES IN
ACCOUNTING PRINCIPLES 372 485 621 722
CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING
PRINCIPLES (net of income taxes of $69 and $(90) for the six
months ended June 30, 2003 and 2002, respectively) -- -- 112 (230)
- -------------------------------------------------------------------------------------------------------------------------
NET INCOME 372 485 733 492
- -------------------------------------------------------------------------------------------------------------------------
OTHER COMPREHENSIVE INCOME (LOSS) (net of income taxes)
Cash flow hedge adjustment 62 (16) (84) (68)
Foreign currency translation adjustment 1 -- 2 --
Unrealized gain (loss) on marketable securities 3 (72) (2) (87)
SFAS No. 143 transition adjustment -- -- 168 --
Interest in other comprehensive income (loss) of unconsolidated
affiliates 17 (7) 8 (1)
- -------------------------------------------------------------------------------------------------------------------------
Total other comprehensive income (loss) 83 (95) 92 (156)
- -------------------------------------------------------------------------------------------------------------------------
TOTAL COMPREHENSIVE INCOME $ 455 $ 390 $ 825 $ 336
=========================================================================================================================
AVERAGE SHARES OF COMMON STOCK OUTSTANDING - Basic 325 322 324 322
=========================================================================================================================
AVERAGE SHARES OF COMMON STOCK OUTSTANDING - Diluted 327 324 327 324
=========================================================================================================================
EARNINGS PER AVERAGE COMMON SHARE:
BASIC:
Income before cumulative effect of changes in accounting
principles $ 1.14 $ 1.50 $ 1.92 $ 2.24
Cumulative effect of changes in accounting principles -- -- 0.34 (0.71)
- -------------------------------------------------------------------------------------------------------------------------
Net income $ 1.14 $ 1.50 $ 2.26 $ 1.53
- -------------------------------------------------------------------------------------------------------------------------
DILUTED:
Income before cumulative effect of changes in accounting
principles $ 1.14 $ 1.50 $ 1.90 $ 2.23
Cumulative effect of changes in accounting principles -- -- 0.34 (0.71)
- -------------------------------------------------------------------------------------------------------------------------
Net income $ 1.14 $ 1.50 $ 2.24 $ 1.52
=========================================================================================================================
DIVIDENDS PER COMMON SHARE $ 0.46 $ 0.44 $ 0.92 $ 0.88
=========================================================================================================================
See Condensed Combined Notes to Consolidated Financial Statements
5
EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended June 30,
-------------------------
(in millions) 2003 2002
- -----------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 733 $ 492
Adjustments to reconcile net income to net cash flows provided by
operating activities:
Depreciation, amortization and accretion, including nuclear fuel 846 848
Cumulative effect of changes in accounting principles (net of income taxes) (112) 230
Gain on sale of investments -- (199)
Provision for uncollectible accounts 43 67
Deferred income taxes (100) (10)
Equity in earnings of unconsolidated affiliates (33) (22)
Impairment of investments 238 38
Impairment of goodwill and long-lived assets 53 --
Net realized (gains) losses on nuclear decommissioning trust funds (12) 21
Other operating activities 12 40
Changes in assets and liabilities:
Accounts receivable 66 (281)
Inventories (16) (3)
Accounts payable, accrued expenses and other current liabilities (62) 364
Changes in payables and receivables from unconsolidated affiliates 19 12
Other current assets (214) (143)
Deferred energy costs (24) 49
Pension and non-pension postretirement benefits obligations (146) 10
Other noncurrent assets and liabilities 1 125
- -----------------------------------------------------------------------------------------------------------------------
Net cash flows provided by operating activities 1,292 1,638
- -----------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (1,019) (1,028)
Proceeds from liquidated damages 86 --
Proceeds from nuclear decommissioning trust funds 1,262 889
Investment in nuclear decommissioning trust funds (1,368) (943)
Note receivable from unconsolidated affiliate 35 (75)
Proceeds from sale of investment 6 285
Acquisition of generating plants -- (443)
Other investing activities 11 47
- -----------------------------------------------------------------------------------------------------------------------
Net cash flows used in investing activities (987) (1,268)
- -----------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt 1,813 701
Retirement of long-term debt (1,479) (697)
Change in short-term debt (100) 110
Issuance of preferred securities of subsidiaries 300 --
Retirement of preferred securities of subsidiaries (300) --
Dividends paid on common stock (285) (280)
Payment on acquisition note payable to Sithe Energies, Inc. (210) --
Proceeds from employee stock plans 91 60
Change in restricted cash (29) (26)
Other financing activities (85) (10)
- -----------------------------------------------------------------------------------------------------------------------
Net cash flows used in financing activities (284) (142)
- -----------------------------------------------------------------------------------------------------------------------
INCREASE IN CASH AND CASH EQUIVALENTS 21 228
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 469 485
- -----------------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS INCLUDING CASH CLASSIFIED AS HELD FOR SALE 490 713
CASH CLASSIFIED AS HELD FOR SALE ON THE CONSOLIDATED BALANCE SHEET (26) --
- -----------------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 464 $ 713
- -----------------------------------------------------------------------------------------------------------------------
See Condensed Combined Notes to Consolidated Financial Statements
6
EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
June 30, December 31,
(in millions) 2003 2002
- -----------------------------------------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 464 $ 469
Restricted cash 425 396
Accounts receivable, net
Customer 1,903 2,076
Other 246 284
Receivable from unconsolidated affiliate -- 39
Inventories, at average cost
Fossil fuel 172 175
Materials and supplies 309 306
Other 579 380
Assets held for sale 352 --
- -----------------------------------------------------------------------------------------------------------------------
Total current assets 4,450 4,125
- -----------------------------------------------------------------------------------------------------------------------
PROPERTY, PLANT AND EQUIPMENT, NET 20,323 17,126
DEFERRED DEBITS AND OTHER ASSETS
Regulatory assets 5,414 5,993
Nuclear decommissioning trust funds 3,316 3,053
Investments 1,189 1,403
Goodwill 4,735 4,992
Other 861 793
- -----------------------------------------------------------------------------------------------------------------------
Total deferred debits and other assets 15,515 16,234
- -----------------------------------------------------------------------------------------------------------------------
TOTAL ASSETS $ 40,288 $ 37,485
=======================================================================================================================
See Condensed Combined Notes to Consolidated Financial Statements
7
EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
June 30, December 31,
(in millions) 2003 2002
- -----------------------------------------------------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Notes payable $ 581 $ 681
Note payable to unconsolidated affiliate 326 534
Long-term debt due within one year 2,391 1,402
Accounts payable 1,762 1,607
Accrued expenses 1,205 1,354
Other 283 296
Liabilities held for sale 81 --
- -----------------------------------------------------------------------------------------------------------------------
Total current liabilities 6,629 5,874
- -----------------------------------------------------------------------------------------------------------------------
LONG-TERM DEBT 12,480 13,127
MANDATORILY REDEEMABLE PREFERRED SECURITIES 100 --
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred income taxes 3,973 3,702
Unamortized investment tax credits 295 301
Nuclear decommissioning liability for retired plants -- 1,395
Asset retirement obligation 2,444 --
Pension obligation 1,747 1,959
Non-pension postretirement benefits obligation 943 877
Spent nuclear fuel obligation 863 858
Regulatory liabilities 810 --
Other 1,037 978
- -----------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 12,112 10,070
- -----------------------------------------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES
MINORITY INTEREST OF CONSOLIDATED SUBSIDIARIES 79 77
PREFERRED SECURITIES OF SUBSIDIARIES 510 595
SHAREHOLDERS' EQUITY
Common stock 7,169 7,059
Deferred compensation -- (1)
Retained earnings 2,475 2,042
Accumulated other comprehensive income (loss) (1,266) (1,358)
- -----------------------------------------------------------------------------------------------------------------------
Total shareholders' equity 8,378 7,742
- -----------------------------------------------------------------------------------------------------------------------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 40,288 $ 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 June 30, Six Months Ended June 30,
-------------------------- -------------------------
(in millions) 2003 2002 2003 2002
- ---------------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES
Operating revenues $ 1,345 $ 1,469 $ 2,756 $ 2,773
Operating revenues from affiliates 16 12 29 23
- ---------------------------------------------------------------------------------------------------------------------------
Total operating revenues 1,361 1,481 2,785 2,796
- ---------------------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES
Purchased power 5 6 11 12
Purchased power from affiliate 528 547 1,099 1,079
Operating and maintenance 193 191 425 386
Operating and maintenance from affiliates 28 29 58 71
Depreciation and amortization 96 133 190 268
Taxes other than income 68 73 148 146
- ---------------------------------------------------------------------------------------------------------------------------
Total operating expenses 918 979 1,931 1,962
- ---------------------------------------------------------------------------------------------------------------------------
OPERATING INCOME 443 502 854 834
- ---------------------------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest expense (106) (127) (215) (252)
Distributions on mandatorily redeemable preferred securities (6) (7) (14) (15)
Interest income from affiliates 7 8 13 16
Other, net 5 6 21 13
- ---------------------------------------------------------------------------------------------------------------------------
Total other income and deductions (100) (120) (195) (238)
- ---------------------------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT
OF A CHANGE IN ACCOUNTING PRINCIPLE 343 382 659 596
INCOME TAXES 138 151 263 236
- ---------------------------------------------------------------------------------------------------------------------------
INCOME BEFORE CUMULATIVE EFFECT OF A CHANGE IN
ACCOUNTING PRINCIPLE 205 231 396 360
CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING
PRINCIPLE (net of income taxes of $0) -- -- 5 --
- ---------------------------------------------------------------------------------------------------------------------------
NET INCOME 205 231 401 360
- ---------------------------------------------------------------------------------------------------------------------------
OTHER COMPREHENSIVE INCOME (LOSS) (net of income taxes)
Cash flow hedge adjustment (3) (9) 28 (6)
Unrealized gain (loss) on marketable securities 1 (2) 1 (2)
Foreign currency translation adjustment 1 -- 2 --
- ---------------------------------------------------------------------------------------------------------------------------
Total other comprehensive income (loss) (1) (11) 31 (8)
- ---------------------------------------------------------------------------------------------------------------------------
TOTAL COMPREHENSIVE INCOME $ 204 $ 220 $ 432 $ 352
===========================================================================================================================
See Condensed Combined Notes to Consolidated Financial Statements
9
COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended June 30,
-------------------------
(in millions) 2003 2002
- -------------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 401 $ 360
Adjustments to reconcile net income to net cash flows provided by
operating activities:
Depreciation and amortization 190 268
Cumulative effect of a change in accounting principle (net of income taxes) (5) --
Provision for uncollectible accounts 20 11
Deferred income taxes 60 75
Other operating activities 25 29
Changes in assets and liabilities:
Accounts receivable 9 (158)
Inventories 2 --
Accounts payable, accrued expenses and other current liabilities (115) 51
Changes in receivables and payables to affiliates (94) 63
Other current assets (2) (1)
Pension and non-pension postretirement benefits obligations (72) 15
Other noncurrent assets and liabilities 11 27
- -------------------------------------------------------------------------------------------------------------------------
Net cash flows provided by operating activities 430 740
- -------------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (355) (372)
Notes receivable from affiliates (165) 13
Other investing activities 14 7
- -------------------------------------------------------------------------------------------------------------------------
Net cash flows used in investing activities (506) (352)
- -------------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt 1,135 701
Retirement of long-term debt (662) (481)
Issuance of mandatorily redeemable preferred securities 200 --
Retirement of mandatorily redeemable preferred securities (200) --
Change in short-term debt (71) --
Dividends paid on common stock (211) (235)
Change in restricted cash (18) (32)
Settlement of cash flow hedges (51) (10)
Other financing activities (28) --
- -------------------------------------------------------------------------------------------------------------------------
Net cash flows provided by (used in) financing activities 94 (57)
- ---------------------------------------------------------------------------------------------------------------------------
INCREASE IN CASH AND CASH EQUIVALENTS 18 331
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 16 23
- -------------------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 34 $ 354
=========================================================================================================================
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)
June 30, December 31,
(in millions) 2003 2002
- -------------------------------------------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 34 $ 16
Restricted cash 83 65
Accounts receivable, net
Customer 747 782
Other 78 72
Inventories, at average cost 63 65
Deferred income taxes 19 20
Receivables from affiliates 177 15
Other 16 14
- -------------------------------------------------------------------------------------------------------------------------
Total current assets 1,217 1,049
- -------------------------------------------------------------------------------------------------------------------------
PROPERTY, PLANT AND EQUIPMENT, NET 7,944 7,756
DEFERRED DEBITS AND OTHER ASSETS
Regulatory assets -- 447
Investments 35 42
Goodwill 4,711 4,916
Receivables from affiliates 2,397 1,300
Other 373 320
- -------------------------------------------------------------------------------------------------------------------------
Total deferred debits and other assets 7,516 7,025
- -------------------------------------------------------------------------------------------------------------------------
TOTAL ASSETS $ 16,677 $ 15,830
=========================================================================================================================
See Condensed Combined Notes to Consolidated Financial Statements
11
COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
June 30, December 31,
(in millions) 2003 2002
- -------------------------------------------------------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Notes payable $ -- $ 71
Long-term debt due within one year 869 698
Accounts payable 158 201
Accrued expenses 456 538
Payables to affiliates 209 416
Customer deposits 79 81
Other 19 18
- -------------------------------------------------------------------------------------------------------------------------
Total current liabilities 1,790 2,023
- -------------------------------------------------------------------------------------------------------------------------
LONG-TERM DEBT 5,584 5,268
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred income taxes 1,741 1,650
Unamortized investment tax credits 50 51
Pension obligation 1 91
Non-pension postretirement benefits obligation 156 138
Payables to affiliates 26 224
Regulatory liabilities 810 --
Other 345 297
- -------------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 3,129 2,451
- -------------------------------------------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES
MANDATORILY REDEEMABLE PREFERRED SECURITIES 344 330
SHAREHOLDERS' EQUITY
Common stock 1,588 1,588
Preference stock 7 7
Other paid in capital 4,029 4,239
Receivable from parent (554) (615)
Retained earnings 767 577
Accumulated other comprehensive income (loss) (7) (38)
- -------------------------------------------------------------------------------------------------------------------------
Total shareholders' equity 5,830 5,758
- -------------------------------------------------------------------------------------------------------------------------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 16,677 $ 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 June 30, Six Months Ended June 30,
--------------------------- ------------------------
(in millions) 2003 2002 2003 2002
- -----------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES
Operating revenues $ 958 $ 992 $ 2,173 $ 2,008
Operating revenues from affiliates 3 3 5 7
- -----------------------------------------------------------------------------------------------------------------------
Total operating revenues 961 995 2,178 2,015
- -----------------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES
Purchased power 62 59 127 107
Purchased power from affiliate 324 346 681 649
Fuel 67 53 257 188
Operating and maintenance 110 114 236 225
Operating and maintenance from affiliates 11 17 25 42
Depreciation and amortization 116 109 236 221
Taxes other than income 47 63 110 122
- -----------------------------------------------------------------------------------------------------------------------
Total operating expenses 737 761 1,672 1,554
- -----------------------------------------------------------------------------------------------------------------------
OPERATING INCOME 224 234 506 461
- -----------------------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest expense (83) (92) (168) (187)
Distributions on mandatorily redeemable preferred securities (2) (2) (5) (5)
Other, net 1 2 10 2
- -----------------------------------------------------------------------------------------------------------------------
Total other income and deductions (84) (92) (163) (190)
- -----------------------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 140 142 343 271
INCOME TAXES 52 49 119 90
- -----------------------------------------------------------------------------------------------------------------------
NET INCOME 88 93 224 181
Preferred stock dividends (2) (2) (3) (4)
- -----------------------------------------------------------------------------------------------------------------------
NET INCOME ON COMMON STOCK $ 86 $ 91 $ 221 $ 177
=======================================================================================================================
OTHER COMPREHENSIVE INCOME (LOSS) (net of income taxes)
Net income $ 88 $ 93 $ 224 $ 181
Other comprehensive income (loss) (net of income taxes):
Cash flow hedge adjustment -- (6) -- (4)
- -----------------------------------------------------------------------------------------------------------------------
Total other comprehensive income (loss) -- (6) -- (4)
- -----------------------------------------------------------------------------------------------------------------------
TOTAL COMPREHENSIVE INCOME $ 88 $ 87 $ 224 $ 177
=======================================================================================================================
See Condensed Combined Notes to Consolidated Financial Statements
13
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended June 30,
-------------------------
(in millions) 2003 2002
- -----------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 224 $ 181
Adjustments to reconcile net income to net cash flows provided by
operating activities:
Depreciation and amortization 236 221
Provision for uncollectible accounts 21 32
Deferred income taxes (28) (19)
Other operating activities 5 --
Changes in assets and liabilities:
Accounts receivable 48 (4)
Changes in receivables and payables to affiliates 27 34
Inventories (1) 14
Accounts payable, accrued expenses and other current liabilities 11 44
Prepaid taxes (91) (98)
Deferred energy costs (24) 49
Other current assets (4) (3)
Pension and non-pension postretirement benefits obligations 16 8
Other noncurrent assets and liabilities (15) 9
- -----------------------------------------------------------------------------------------------------------------------
Net cash flows provided by operating activities 425 468
- -----------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (132) (132)
Other investing activities 6 10
- -----------------------------------------------------------------------------------------------------------------------
Net cash flows used in investing activities (126) (122)
- -----------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt 450 --
Issuance of mandatorily redeemable preferred securities 100 --
Retirement of long-term debt (592) (207)
Retirement of mandatorily redeemable preferred securities (50) --
Retirement of preferred stock (50) --
Change in short-term debt (30) 74
Dividends paid on preferred and common stock (168) (174)
Contribution from parent 17 --
Change in restricted cash 28 1
Other financing activities (6) --
- -----------------------------------------------------------------------------------------------------------------------
Net cash flows used in financing activities (301) (306)
- -----------------------------------------------------------------------------------------------------------------------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (2) 40
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 63 32
- -----------------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 61 $ 72
=======================================================================================================================
See Condensed Combined Notes to Consolidated Financial Statements
14
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
June 30, December 31,
(in millions) 2003 2002
- -----------------------------------------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 61 $ 63
Restricted cash 303 331
Accounts receivable, net
Customer 300 379
Other 51 39
Inventories, at average cost
Fossil fuel 67 67
Materials and supplies 9 8
Deferred energy costs 55 31
Prepaid taxes 92 1
Other 10 8
- -----------------------------------------------------------------------------------------------------------------------
Total current assets 948 927
- -----------------------------------------------------------------------------------------------------------------------
PROPERTY, PLANT AND EQUIPMENT, NET 4,213 4,159
DEFERRED DEBITS AND OTHER ASSETS
Regulatory assets 5,414 5,546
Investments 19 19
Prepaid pension asset 56 41
Other 22 28
- -----------------------------------------------------------------------------------------------------------------------
Total deferred debits and other assets 5,511 5,634
- -----------------------------------------------------------------------------------------------------------------------
TOTAL ASSETS $ 10,672 $ 10,720
=======================================================================================================================
See Condensed Combined Notes to Consolidated Financial Statements
15
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
June 30, December 31,
(in millions) 2003 2002
- -----------------------------------------------------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Notes payable $ 170 $ 200
Payables to affiliates 137 170
Long-term debt due within one year 264 689
Accounts payable 70 87
Accrued expenses 361 332
Deferred income taxes 27 27
Other 32 33
- -----------------------------------------------------------------------------------------------------------------------
Total current liabilities 1,061 1,538
- -----------------------------------------------------------------------------------------------------------------------
LONG-TERM DEBT 5,230 4,951
MANDATORILY REDEEMABLE PREFERRED SECURITIES 100 --
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred income taxes 2,891 2,903
Unamortized investment tax credits 23 24
Non-pension postretirement benefits obligation 282 251
Payable to affiliate 16 --
Other 149 164
- -----------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 3,361 3,342
- -----------------------------------------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES
MANDATORILY REDEEMABLE PREFERRED SECURITIES 78 128
SHAREHOLDERS' EQUITY
Common stock 1,993 1,976
Receivable from parent (1,698) (1,758)
Preferred stock 87 137
Retained earnings 455 401
Accumulated other comprehensive income 5 5
- -----------------------------------------------------------------------------------------------------------------------
Total shareholders' equity 842 761
- -----------------------------------------------------------------------------------------------------------------------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 10,672 $ 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 June 30, Six Months Ended June 30,
--------------------------- --------------------------
(in millions) 2003 2002 2003 2002
- ------------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES
Operating revenues $ 990 $ 606 $ 1,876 $ 1,175
Operating revenues from affiliates 896 953 1,889 1,845
- ------------------------------------------------------------------------------------------------------------------------
Total operating revenues 1,886 1,559 3,765 3,020
- ------------------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES
Purchased power 675 634 1,436 1,186
Purchased power from affiliates 125 71 206 137
Fuel 348 224 706 433
Operating and maintenance 411 374 861 750
Operating and maintenance from affiliates 40 37 82 94
Depreciation and amortization 46 65 91 128
Taxes other than income 40 41 88 90
- ------------------------------------------------------------------------------------------------------------------------
Total operating expenses 1,685 1,446 3,470 2,818
- ------------------------------------------------------------------------------------------------------------------------
OPERATING INCOME 201 113 295 202
- ------------------------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest expense (16) (10) (30) (27)
Interest expense - affiliates (4) (1) (8) (1)
Equity in earnings of unconsolidated affiliates 18 9 37 32
Other, net 34 24 (134) 40
- ------------------------------------------------------------------------------------------------------------------------
Total other income and deductions 32 22 (135) 44
- ------------------------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT
OF CHANGES IN ACCOUNTING PRINCIPLES 233 135 160 246
INCOME TAXES 91 51 71 96
- ------------------------------------------------------------------------------------------------------------------------
INCOME BEFORE CUMULATIVE EFFECT OF CHANGES IN
ACCOUNTING PRINCIPLES 142 84 89 150
CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING
PRINCIPLES (net of income taxes of $70 and $9 for the six
months ended June 30, 2003 and 2002, respectively) -- -- 108 13
- ------------------------------------------------------------------------------------------------------------------------
NET INCOME 142 84 197 163
- ------------------------------------------------------------------------------------------------------------------------
OTHER COMPREHENSIVE INCOME (LOSS) (net of income taxes)
Unrealized gain (loss) on marketable securities 2 (74) (3) (83)
SFAS No. 143 transition adjustment -- -- 168 --
Cash flow hedge adjustment 64 6 (116) (67)
Interest in other comprehensive income (loss) of unconsolidated
affiliates 17 (7) 8 (1)
- ------------------------------------------------------------------------------------------------------------------------
Total other comprehensive income (loss) 83 (75) 57 (151)
- ------------------------------------------------------------------------------------------------------------------------
TOTAL COMPREHENSIVE INCOME $ 225 $ 9 $ 254 $ 12
========================================================================================================================
See Condensed Combined Notes to Consolidated Financial Statements
17
EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended June 30,
-------------------------
(in millions) 2003 2002
- ------------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 197 $ 163
Adjustments to reconcile net income to net cash flows provided by
operating activities:
Depreciation, amortization and accretion, including nuclear fuel 388 312
Cumulative effect of changes in accounting principles (net of income taxes) (108) (13)
Provision for uncollectible accounts 1 17
Deferred income taxes (107) (4)
Equity in earnings of unconsolidated affiliates (37) (32)
Impairment of investment 200 --
Impairment of long-lived assets 5 --
Net realized (gains) losses on nuclear decommissioning trust funds (12) 21
Other operating activities (39) 53
Changes in assets and liabilities:
Accounts receivable (116) (136)
Changes in receivables and payables to affiliates, net 238 (93)
Inventories (19) (15)
Accounts payable, accrued expenses and other current liabilities 91 307
Other current assets (104) (87)
Pension and non-pension postretirement benefits obligations (59) (4)
Other noncurrent assets and liabilities 20 30
- ------------------------------------------------------------------------------------------------------------------------
Net cash flows provided by operating activities 539 519
- ------------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (510) (475)
Proceeds from liquidated damages 86 --
Proceeds from nuclear decommissioning trust funds 1,262 889
Investment in nuclear decommissioning trust funds (1,368) (943)
Note receivable from unconsolidated affiliate 35 (75)
Acquisition of generating plants -- (443)
Other investing activities (1) (1)
- ------------------------------------------------------------------------------------------------------------------------
Net cash flows used in investing activities (496) (1,048)
- ------------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt 211 --
Retirement of long-term debt (3) (2)
Payment on acquisition note payable to Sithe Energies, Inc. (210) --
Change in payables to affiliates 58 331
Distribution to member (45) --
Change in restricted cash (38) --
- ------------------------------------------------------------------------------------------------------------------------
Net cash flows (used in) provided by financing activities (27) 329
- ------------------------------------------------------------------------------------------------------------------------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 16 (200)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 58 224
- ------------------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 74 $ 24
========================================================================================================================
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)
June 30, December 31,
(in millions) 2003 2002
- ------------------------------------------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 74 $ 58
Restricted cash 38 --
Accounts receivable, net
Customer 656 587
Other 83 57
Receivables from affiliates 334 594
Inventories, at average cost
Fossil fuel 96 97
Materials and supplies 235 217
Deferred income taxes 7 7
Other 288 188
- ------------------------------------------------------------------------------------------------------------------------
Total current assets 1,811 1,805
- ------------------------------------------------------------------------------------------------------------------------
PROPERTY, PLANT AND EQUIPMENT, NET 7,884 4,800
DEFERRED DEBITS AND OTHER ASSETS
Nuclear decommissioning trust funds 3,316 3,053
Investments 484 657
Receivable from affiliate 35 220
Deferred income taxes 102 271
Prepaid pension asset 55 --
Other 226 201
- ------------------------------------------------------------------------------------------------------------------------
Total deferred debits and other assets 4,218 4,402
- ------------------------------------------------------------------------------------------------------------------------
TOTAL ASSETS $ 13,913 $ 11,007
========================================================================================================================
See Condensed Combined Notes to Consolidated Financial Statements
19
EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
June 30, December 31,
(in millions) 2003 2002
- ------------------------------------------------------------------------------------------------------------------------
LIABILITIES AND MEMBER'S EQUITY
CURRENT LIABILITIES
Long-term debt due within one year $ 1,252 $ 5
Accounts payable 1,408 1,126
Payables to affiliates 45 10
Notes payable to affiliates 717 863
Accrued expenses 431 482
Other 93 108
- ------------------------------------------------------------------------------------------------------------------------
Total current liabilities 3,946 2,594
- ------------------------------------------------------------------------------------------------------------------------
LONG-TERM DEBT 1,111 2,132
DEFERRED CREDITS AND OTHER LIABILITIES
Unamortized investment tax credits 222 226
Nuclear decommissioning liability for retired plants -- 1,395
Asset retirement obligation 2,440 --
Pension obligation -- 37
Non-pension postretirement benefits obligation 443 410
Spent nuclear fuel obligation 863 858
Payable to affiliate 1,094 --
Other 438 402
- ------------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 5,500 3,328
- ------------------------------------------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES
MINORITY INTEREST OF CONSOLIDATED SUBSIDIARY 54 54
MEMBER'S EQUITY
Membership interest 2,489 2,296
Undistributed earnings 1,077 924
Accumulated other comprehensive income (loss) (264) (321)
- ------------------------------------------------------------------------------------------------------------------------
Total member's equity 3,302 2,899
- ------------------------------------------------------------------------------------------------------------------------
TOTAL LIABILITIES AND MEMBER'S EQUITY $ 13,913 $ 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 accompanying consolidated financial statements as of June 30,
2003 and for the three and six months then ended are unaudited, but in the
opinion of management of Exelon Corporation (Exelon), Commonwealth Edison
Company (ComEd), PECO Energy Company (PECO) and Exelon Generation Company,
LLC (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 Report 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
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 lives projected to be from 2029
through 2056. These nuclear plants 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 of $3,316 million and
$3,053 million as of June 30, 2003 and December 31, 2002, respectively, in
trust accounts. Exelon and Generation anticipate that all trust fund assets
will ultimately be used to decommission Generation's nuclear plants.
21
After considering interpretations of the transitional guidance
included in SFAS No. 143, Exelon recorded income of $112 million (after
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, after income taxes, are 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.
Accretion expense for the three months and six months ended June 30, 2003
for Exelon was $39 million and $78 million, respectively. Accretion expense
for the three months and six months ended June 30, 2003 for Generation was
$38 million and $77 million, respectively. The following table provides a
reconciliation of the AROs reflected on the balance sheet at December 31,
2002 and June 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
- -------------------------------------------------------------------------------
Decommissioning obligation at January 1, 2003 2,363 2,366
Accretion expense for six months ended June 30, 2003 77 78
- -------------------------------------------------------------------------------
Asset retirement obligation at June 30, 2003 $2,440 $2,444
================================================================================
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 Exelon's decommissioning obligation
at the time of adoption of SFAS No. 143.
22
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 six months ended June 30, 2002 adjusted
as if SFAS No. 143 had been applied effective January 1, 2002.
Three Months Ended Six Months Ended
June 30, 2002 June 30, 2002
- ---------------------------------------------------------------------------------------------------------------------------
Reported income before cumulative effect
of changes in accounting principles $ 485 $ 722
Adjustment as if SFAS No. 143 had been applied
effective January 1, 2002 10 20
- ---------------------------------------------------------------------------------------------------------------------------
Adjusted income before cumulative effect
of changes in accounting principles $ 495 $ 742
===========================================================================================================================
Three Months Ended Six Months Ended
June 30, 2002 June 30, 2002
- ---------------------------------------------------------------------------------------------------------------------------
Reported net income $ 485 $ 492
Adjustment as if SFAS No. 143 had been applied
effective January 1, 2002:
Adjustment to income before cumulative effect
of changes in accounting principles 10 20
Cumulative effect of changes in accounting principles -- 132
- ---------------------------------------------------------------------------------------------------------------------------
Adjusted net income $ 495 $ 644
===========================================================================================================================
Three Months Ended June 30, 2002
--------------------------------
Basic earnings per common share: Reported Adjustment (1) Adjusted
- ---------------------------------------------------------------------------------------------------------------------------
Income before cumulative effect
of changes in accounting principles $ 1.50 $ 0.03 $ 1.53
Net income $ 1.50 $ 0.03 $ 1.53
- ---------------------------------------------------------------------------------------------------------------------------
Three Months Ended June 30, 2002
--------------------------------
Diluted earnings per common share: Reported Adjustment (1) Adjusted
- ---------------------------------------------------------------------------------------------------------------------------
Income before cumulative effect
of changes in accounting principles $ 1.50 $ 0.03 $ 1.53
Net income $ 1.50 $ 0.03 $ 1.53
- ---------------------------------------------------------------------------------------------------------------------------
(1) The adjustment represents the earnings impact as if SFAS No. 143 had been applied effective January 1, 2002.
Six Months Ended June 30, 2002
------------------------------
Basic earnings per common share: Reported Adjustment (1) Adjusted
- ---------------------------------------------------------------------------------------------------------------------------
Income before cumulative effect
of changes in accounting principles $ 2.24 $ 0.06 $ 2.30
Net income $ 1.53 $ 0.47 $ 2.00
- ---------------------------------------------------------------------------------------------------------------------------
23
Six Months Ended June 30, 2002
------------------------------
Diluted earnings per common share: Reported Adjustment (1) Adjusted
- ---------------------------------------------------------------------------------------------------------------------------
Income before cumulative effect
of changes in accounting principles $ 2.23 $ 0.06 $ 2.29
Net income $ 1.52 $ 0.47 $ 1.99
- ---------------------------------------------------------------------------------------------------------------------------
(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 June 30, 2003,
the regulatory liability and corresponding receivable from Generation
totaled $1,094 million. Exelon believes that all of the decommissioning
assets, including up to $73 million of annual collections 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 June 30, 2003, the regulatory asset and corresponding payable to
Generation totaled $16 million. Exelon believes that all of the
decommissioning assets, including the $29 million of annual collections,
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.
In accordance with regulatory accounting, the net plant balances
of Exelon, ComEd and PECO include recoveries for removal costs, which are
included as a component of accumulated depreciation. The adoption of SFAS
No. 143 had no impact on the accounting for removal costs not associated
with AROs.
24
Prior to the adoption of SFAS No. 143, Generation's accumulated
depreciation included $2,845 million for decommissioning liabilities
related to the active 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 PECO ARO in accordance with
SFAS No. 143. The ARC will be 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 and ComEd concluded that had SFAS
No. 143 been in effect, ComEd would not have recorded an impairment on 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, Exelon and 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 and Generation recorded a SFAS No. 143
transition adjustment to accumulated other comprehensive income to
reclassify $168 million of 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 six months ended June 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 Six Months Ended
ComEd June 30, 2002 June 30, 2002
- -------------------------------------------------------------------------------------------------------------
Reported net income $ 231 $ 360
Adjustment as if SFAS No. 143 had been applied
effective January 1, 2002:
Cumulative effect of changes in accounting principles -- 5
- -------------------------------------------------------------------------------------------------------------
Adjusted net income $ 231 $ 365
=============================================================================================================
25
Three Months Ended Six Months Ended
Generation June 30, 2002 June 30, 2002
- ------------------------------------------------------------------------------------------------------------
Reported income before cumulative effect
of changes in accounting principles $ 84 $ 150
Adjustment as if SFAS No. 143 had been applied
effective January 1, 2002 10 20
- ------------------------------------------------------------------------------------------------------------
Adjusted income before cumulative effect
of changes in accounting principles $ 94 $ 170
=============================================================================================================
Three Months Ended Six Months Ended
Generation June 30, 2002 June 30, 2002
- ------------------------------------------------------------------------------------------------------------
Reported net income $ 84 $ 163
Adjustment as if SFAS No. 143 had been applied
effective January 1, 2002:
Adjustment to income before cumulative effect
of changes in accounting principles 10 20
Cumulative effect of changes in accounting principles -- 128
- ------------------------------------------------------------------------------------------------------------
Adjusted net income $ 94 $ 311
=============================================================================================================
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
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 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 of decommissioning costs, 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.
26
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 are 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 June 30, 2003, Exelon had goodwill of $4,735 million of which
$4,711 million relates to ComEd and the remaining goodwill relates to
Enterprises' reporting units. See Note 3 - Acquisitions, Dispositions and
Retirements for a further discussion of Enterprises' goodwill. Consistent
with SFAS No. 142, the remaining 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. The annual update
impairment review during the fourth quarter of 2002 did not identify any
goodwill impairment.
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
unaffected by the adoption SFAS No. 146.
27
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 six months ended June 30, 2003 are reflected in
Note 8 - Commitments and Contingencies.
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 six months
ended June 30, 2003 and 2002:
28
Exelon
Three Months Ended June 30,
---------------------------
2003 2002
- ------------------------------------------------------------------------------------------------------------
Net income - as reported $ 372 $ 485
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 $ 367 $ 477
============================================================================================================
Earnings per share:
Basic - as reported $ 1.14 $ 1.50
Basic - pro forma $ 1.13 $ 1.48
Diluted - as reported $ 1.14 $ 1.50
Diluted - pro forma $ 1.12 $ 1.47
- ------------------------------------------------------------------------------------------------------------
Six Months Ended June 30,
-------------------------
2003 2002
- ------------------------------------------------------------------------------------------------------------
Net income - as reported $ 733 $ 492
Deduct: Total stock-based compensation expense
determined under fair value based method for all
awards, net of income taxes (10) (17)
- ------------------------------------------------------------------------------------------------------------
Pro forma net income $ 723 $ 475
============================================================================================================
Earnings per share:
Basic - as reported $ 2.26 $ 1.53
Basic - pro forma $ 2.23 $ 1.48
Diluted - as reported $ 2.24 $ 1.52
Diluted - pro forma $ 2.21 $ 1.47
- ------------------------------------------------------------------------------------------------------------
ComEd
Three Months Ended June 30,
-------------------------
2003 2002
- ------------------------------------------------------------------------------------------------------------
Net income - as reported $ 205 $ 231
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 $ 204 $ 228
============================================================================================================
Six Months Ended June 30,
-------------------------
2003 2002
- ------------------------------------------------------------------------------------------------------------
Net income - as reported $ 401 $ 360
Deduct: Total stock-based compensation expense
determined under fair value based method for all
awards, net of income taxes (2) (6)
- ------------------------------------------------------------------------------------------------------------
Pro forma net income $ 399 $ 354
============================================================================================================
29
PECO
Three Months Ended June 30,
-------------------------
2003 2002
- ------------------------------------------------------------------------------------------------------------
Net income on common stock- as reported $ 86 $ 91
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 $ 85 $ 88
============================================================================================================
Six Months Ended June 30,
-------------------------
2003 2002
- ------------------------------------------------------------------------------------------------------------
Net income on common stock- as reported $ 221 $ 177
Deduct: Total stock-based compensation expense
determined under fair value based method for all
awards, net of income taxes (1) (7)
- ------------------------------------------------------------------------------------------------------------
Pro forma net income on common stock $ 220 $ 170
============================================================================================================
Generation
Three Months Ended June 30,
-------------------------
2003 2002
- ------------------------------------------------------------------------------------------------------------
Net income - as reported $ 142 $ 84
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 $ 139 $ 80
============================================================================================================
Six Months Ended June 30,
-------------------------
2003 2002
- ------------------------------------------------------------------------------------------------------------
Net income - as reported $ 197 $ 163
Deduct: Total stock-based compensation expense
determined under fair value based method for all
awards, net of income taxes (5) (7)
- ------------------------------------------------------------------------------------------------------------
Pro forma net income $ 192 $ 156
============================================================================================================
FIN No. 46
In January 2003, the FASB issued FIN No. 46, "Consolidation of
Variable Interest Entities" (FIN No. 46). FIN No. 46 addresses
consolidating certain variable interest entities and applies immediately to
variable interest entities created after January 31, 2003. FIN No. 46
requires Exelon to consolidate pre-existing variable interest entities as
of July 1, 2003.
Based on management's interpretation of the provisions of FIN No.
46, it is reasonably possible that Generation will consolidate Sithe
Energies, Inc. (Sithe) as of July 1, 2003. Generation is a 49.9% owner of
Sithe and has accounted for this entity as an unconsolidated equity
investment through June 30, 2003. Sithe owns and operates power generating
facilities. Refer to Note 17 - Unconsolidated Equity Investments in
Generation's Form 10-K for the year ended December 31, 2002 and Note 10 -
Unconsolidated Investments for further information related to Generation's
investment in Sithe. FIN No. 46 is a complex accounting standard and
requires management to exercise judgment in analyzing entities with which
Exelon and its
30
subsidiaries have business arrangements to determine if those entities are
variable interest entities and, if so, whether consolidation is required.
This accounting standard is the subject of continuing discussions by the
FASB and others. The final determination of entities that may be considered
variable interest entities will be completed in the third quarter of 2003.
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
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 is 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 will 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 will have 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.
Most of the guidance in SFAS No. 150 is effective for all
financial instruments entered into or modified after May 31, 2003, and
otherwise is effective for Exelon as of July 1, 2003.
During June 2003, PECO issued $100 million of trust preferred
securities. These securities were recorded as liabilities (see Note 9 -
Long-Term Debt and Preferred Securities).
31
Effective July 1, 2003, Exelon, ComEd and PECO will reclassify mandatorily
redeemable shares that were issued prior to May 31, 2003 as liabilities on
their respective balance sheets. The total amounts to be reclassified will
be $422 million, $344 million and $78 million, respectively. The adoption
of SFAS No. 150 will have no impact on Generation.
Change in Accounting 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, after income
taxes). As a result of the change, operating income for the three and six
months ended June 30, 2003 increased approximately $24 million and $48
million, respectively ($14 million and $29 million, respectively, after
income taxes) compared to the three and six months ended June 30, 2002.
3. ACQUISITIONS, DISPOSITIONS AND RETIREMENTS (Exelon and Generation)
InfraSource Sale
On June 18, 2003, Enterprises entered into an agreement to sell
the electric construction and services, underground and telecom businesses
of InfraSource, Incorporated (InfraSource). The net cash proceeds to Exelon
from the sale are expected to be $211 million plus a $30 million
subordinated note maturing with interest in 2011. The interest rate on the
note is 8% annually if paid in cash and 10% if paid in kind. In connection
with this transaction, Enterprises will enter into an agreement at closing
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. Enterprises anticipates
incurring approximately $5 million in closing costs associated with the
transaction. Closing of the transaction is subject to the satisfaction of a
number of conditions, including regulatory approvals from state utility
commissions in Pennsylvania, Delaware, New Jersey, Virginia, Maryland and
Washington, D.C. and other conditions, the satisfaction of which cannot be
assured. Early termination of the Hart Scott Rodino waiting period was
granted effective July 17, 2003. If all closing conditions are satisfied,
the transaction is expected to close in the third or fourth quarter of
2003.
Exelon classified the assets and liabilities of InfraSource that
are subject to the agreement of sale 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 June 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 June 30, 2003 consist of the following (in millions):
32
- ------------------------------------------------------------------------------
Cash $ 26
Accounts receivable, net 82
Inventory 13
Property, plant and equipment, net 122
Deferred income taxes 62
Other assets 47
- ------------------------------------------------------------------------------
Total assets classified as held for sale $ 352
==============================================================================
- ------------------------------------------------------------------------------
Accounts payable $ 13
Accrued expenses and other current liabilities 53
Other liabilities 15
- ------------------------------------------------------------------------------
Total liabilities classified as held for sale $ 81
==============================================================================
In connection with the sale, Exelon recorded an impairment charge
of approximately $47 million (before income taxes) pursuant to SFAS No. 142
related to the goodwill recorded within the InfraSource reporting unit.
Management of Exelon and Enterprises primarily considered the negotiated
sales price of InfraSource in determining the amount of the goodwill
impairment charge. This impairment charge was recorded as an operating and
maintenance expense within the Consolidated Statements of Income and
Comprehensive Income.
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
(after income taxes) on the $84 million investment in other income and
deductions on 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. 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 (2) pay certain taxes, and/or (3) contribute to
certain reserve funds.
33
EBG has a $1.25 billion credit facility (EBG Facility), which was
entered into primarily to finance the construction of the Mystic 8 and 9
and Fore River generating units. The approximately $1.1 billion of debt
outstanding under the credit facility at June 30, 2003 is reflected in
Exelon and Generation's Consolidated Balance Sheets as a current liability
due to certain events of default described below. Generation made a cash
payment to Sithe of approximately $210 million during the second quarter of
2003 related to the note payable associated with the acquisition. See Note
9 - Long-Term Debt and Preferred Securities for additional information
regarding this note.
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
================================================================================
The EBG Facility requires 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 are 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
are in commercial operation, although construction has not progressed to
the point of Project Completion. Construction of Fore River is
substantially complete and the unit is currently undergoing testing. EBG
does not anticipate that the projects will achieve Project Completion by
August 29, 2003. The EBG Facility is non-recourse to Exelon and 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.
As a result of Exelon's continuing evaluation of the projects and
discussions with the lenders in July 2003, 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 Exelon's 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.
Exelon expects Generation will incur an impairment of its EBG
related assets, which, in aggregate, could reach approximately $550 million
after income taxes.
34
Retirement of Power Plants
Generation filed a request with the New England ISO to retire
Exelon New England's Mystic 4, 5 and 6 and New Boston units based upon
management's view of the ongoing financial viability of the units due to
the start up of Mystic Units 8 and 9. Pursuant to SFAS No. 144, Generation
performed a fair value analysis associated with the pending retirement of
Mystic Units 4, 5, and 6 and New Boston. Based on a probability-weighted
undiscounted cash flow model, Generation determined that the book value
exceeded the fair value by $5 million for Mystic Units 4, 5 and 6.
Therefore, an impairment charge of $5 million was recorded as operating and
maintenance expense in Exelon and Generation's Consolidated Statements of
Income and Comprehensive Income for the three months ended June 30, 2003.
Acquisition of Generating Plants from TXU
On April 25, 2002, Generation acquired two natural-gas and
oil-fired plants from TXU Corp. (TXU) for an aggregate purchase price of
$443 million. The purchase included the 893-MW Mountain Creek Steam
Electric Station in Dallas, Texas and the 1,441-MW Handley Steam Electric
Station in Fort Worth, Texas. The transaction included a purchased power
agreement for TXU to purchase power during the months of May through
September from 2002 through 2006. During the periods covered by the
purchased power agreement, TXU has agreed to fixed capacity and variable
expense payments, and to provide fuel to Exelon in return for exclusive
rights to the energy and capacity of the generation plants. Substantially
all of the purchase price was allocated to property, plant and equipment.
4. 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 purchased power
agreement (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
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
35
was $29 million (before income taxes). In accordance with the Agreement,
ComEd made payments of $17 million during the second quarter of 2003.
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, a total of 375,000 residential customers may be transferred
to alternative electric generation suppliers in December 2003. Customers
transferred will 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.
5. 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 June 30, Six Months Ended June 30,
-------------------------- --------------------------
2003 2002 2003 2002
- ------------------------------------------------------------------------------------------------------------------------
Average Common Shares Outstanding 325 322 324 322
Assumed Exercise of Stock Options 2 2 3 2
- ------------------------------------------------------------------------------------------------------------------------
Average Dilutive Common Shares Outstanding 327 324 327 324
========================================================================================================================
The number of stock options not included in average common shares
used in calculating diluted earnings per share due to their antidilutive
effect were five million for the three and six months ended June 30, 2003
and three million for the three and six months ended June 30, 2002.
36
6. 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 six months ended
June 30, 2003 and 2002 and at June 30, 2003 and December 31, 2002 is as
follows:
Three Months Ended June 30, 2003 and 2002
Corporate and
Energy Intersegment
Delivery Generation Enterprises Eliminations Consolidated
- ------------------------------------------------------------------------------------------------------------------------
Total Revenues (1):
2003 $ 2,322 $ 1,886 $ 443 $ (930) $ 3,721
2002 2,476 1,559 476 (992) 3,519
Intersegment Revenues:
2003 $ 19 $ 896 $ 16 $ (931) $ --
2002 15 953 24 (992) --
Income (Loss) Before Income Taxes:
2003 $ 481 $ 233 $ (95) $ (25) $ 594
2002 522 135 142 (35) 764
Income Taxes:
2003 $ 190 $ 91 $ (34) $ (25) $ 222
2002 200 51 59 (31) 279
Net Income (Loss):
2003 $ 291 $ 142 $ (61) $ -- $ 372
2002 322 84 83 (4) 485
- ------------------------------------------------------------------------------------------------------------------------
(1) $51 million and $57 million in utility taxes are included in the
Revenues and Expenses for the three months ended June 30, 2003 and
2002, respectively, for ComEd. $47 million and $49 million in utility
taxes are included in the Revenues and Expenses for the three months
ended June 30, 2003 and 2002, respectively, for PECO.
37
Six Months Ended June 30, 2003 and 2002, June 30, 2003, and December 31,
2002
Corporate and
Energy Intersegment
Delivery Generation Enterprises Eliminations Consolidated
- ------------------------------------------------------------------------------------------------------------------------
Total Revenues (1):
2003 $ 4,964 $ 3,765 $ 1,022 $ (1,956) $ 7,795
2002 4,811 3,020 966 (1,921) 6,876
Intersegment Revenues:
2003 $ 35 $ 1,889 $ 35 $ (1,959) $ --
2002 29 1,845 47 (1,921) --
Income (Loss) Before Income Taxes and the Cumulative Effect of Changes in Accounting Principles:
2003 $ 998 $ 160 $ (125) $ (42) $ 991
2002 864 246 95 (56) 1,149
Income Taxes:
2003 $ 382 $ 71 $ (47) $ (36) $ 370
2002 326 96 40 (35) 427
Cumulative Effect of Changes in Accounting Principles:
2003 $ 5 $ 108 $ (1) $ -- $ 112
2002 -- 13 (243) -- (230)
Net Income (Loss):
2003 $ 621 $ 197 $ (79) $ (6) $ 733
2002 538 163 (188) (21) 492
Total Assets:
June 30, 2003 $ 27,349 $ 13,913 $ 1,166 $ (2,140) $ 40,288
December 31, 2002 26,550 11,007 1,297 (1,369) 37,485
- ------------------------------------------------------------------------------------------------------------------------
(1) $113 million and $114 million in utility taxes are included in the
Revenues and Expenses for the six months ended June 30, 2003 and 2002,
respectively, for ComEd. $98 million and $93 million in utility taxes
are included in the Revenues and Expenses for the six months ended
June 30, 2003 and 2002, respectively, for PECO.
7. FAIR VALUE OF FINANCIAL ASSETS AND LIABILITIES (Exelon, ComEd,
PECO and Generation)
During the three and six months ended June 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 June 30, 2003 $ (6) $ 2 $ 103 $ 3 $ 102
Three months ended June 30, 2002 (14) (6) 10 (3) (13)
Six months ended June 30, 2003 (5) 5 (191) 7 (184)
Six months ended June 30, 2002 (16) (1) (108) 14 (111)
- ------------------------------------------------------------------------------------------------------------------------
38
During the three and six months ended June 30, 2003 and 2002,
Generation recognized net MTM gains on non-trading energy derivative
contracts not designated as cash flow hedges, in purchased power as
follows:
2003 2002
- --------------------------------------------------------------------------------
Three months ended June 30, $ 32 $ 4
Six months ended June 30, 1 10
- --------------------------------------------------------------------------------
During the three and six months ended June 30, 2003 and 2002,
Generation recognized net MTM losses on proprietary trading contracts in
operating revenues as follows:
2003 2002
- --------------------------------------------------------------------------------
Three months ended June 30, $ (2) $ (9)
Six months ended June 30, (4) (13)
- --------------------------------------------------------------------------------
During the three and six months ended June 30, 2003 and 2002, no
amounts were reclassified to other income in the Consolidated Statements of
Income and Comprehensive Income as a result of the discontinuance of cash
flow hedges related to certain forecasted financing transactions that were
no longer probable of occurring.
During the three and six months ended June 30, 2003 and 2002,
Generation did not reclassify any amounts from accumulated other
comprehensive income into earnings as a result of forecasted energy
commodity transactions no longer being probable.
As of June 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 $ (281) $ 8 $ (262)
- ------------------------------------------------------------------------------------------------------------------
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 June 30, 2003, ComEd expects to amortize during the next
twelve months $7 million of regulatory assets for settled cash flow swaps.
During the three and six months ended June 30, 2003 and 2002, ComEd
reclassified amounts from other comprehensive income to regulatory assets
for cash flow swaps settled as follows:
2003 2002
- ------------------------------------------------------------------------------------------------------
Three months ended June 30, (net of tax of $0 and $0, respectively) $ -- $ 1
Six months ended June 30, (net of tax of $21 and $4, respectively) 30 6
- ------------------------------------------------------------------------------------------------------
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 will be recorded in
39
earnings. However, as long as the hedge remains effective, changes in the
fair value of the swaps will be 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 June
30, 2003, these swaps had an aggregate fair market value of $46 million,
which was classified as other deferred debits and other assets within the
Consolidated Balance Sheets.
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 anticipated debt issuance. In connection with the
2003 issuances of certain First Mortgage Bonds, forward-starting interest
rate swaps with an aggregate notional amount of $870 million were settled
with net proceeds to counterparties of $51 million ($30 million, after
income taxes) that has been deferred in regulatory assets and is being
amortized over the life of the First Mortgage Bonds as an increase to
interest expense. See Note 9 - Long-Term Debt and Preferred Securities for
additional information regarding the issuance of the First Mortgage Bonds.
On June 30, 2003, ComEd's remaining forward-starting swaps had an aggregate
notional amount of $200 million and an aggregate fair market value of $6
million.
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 June 30, 2003, these
interest rate swaps had an aggregate fair market value exposure of $17
million based on the present value difference between the contract and
market rates at June 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 in 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 9 - 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 June 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 at June 30, 2003. The fair
market value exposure of these swaps, designated as cash flow hedges, is
$105 million.
Generation has also entered into interest rate swaps with an
aggregate notional amount of $200 million to manage interest rate exposures
associated with an anticipated debt issuance. As of June 30, 2003, these
swaps had an aggregate fair market value of $4 million based on the present
value difference between the contract and market rates at June 30, 2003,
which was classified as deferred debits and other assets within the
Consolidated Balance Sheets.
40
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
bases for the securities held in these trust accounts.
June 30, 2003
- -----------------------------------------------------------------------------------------------------------------------
Gross Gross
Amortized Unrealized Unrealized Estimated
Cost Gains Losses Fair Value
- -----------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents $ 171 $ -- $ -- $ 171
Equity securities 1,909 124 (387) 1,646
Debt securities
Government obligations 1,015 71 (2) 1,084
Other debt securities 410 32 (27) 415
- -----------------------------------------------------------------------------------------------------------------------
Total debt securities 1,425 103 (29) 1,499
- -----------------------------------------------------------------------------------------------------------------------
Total available-for-sale securities $ 3,505 $ 227 $ (416) $ 3,316
=======================================================================================================================
December 31, 2002
- -----------------------------------------------------------------------------------------------------------------------
Gross Gross
Amortized Unrealized Unrealized Estimated
Cost Gains Losses Fair Value
- -----------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents $ 184 $ -- $ -- $ 184
Equity securities 1,763 72 (482) 1,353
Debt securities
Government obligations 938 62 -- 1,000
Other debt securities 514 32 (30) 516
- -----------------------------------------------------------------------------------------------------------------------
Total debt securities 1,452 94 (30) 1,516
- -----------------------------------------------------------------------------------------------------------------------
Total available-for-sale securities $ 3,399 $ 166 $ (512) $ 3,053
=======================================================================================================================
Net unrealized losses of $189 million were recognized in
regulatory assets, regulatory liabilities or accumulated other
comprehensive income in Exelon's Consolidated Balance Sheet at June 30,
2003. Net unrealized losses of $189 million were recognized in noncurrent
affiliate payables, noncurrent affiliate receivables or accumulated other
comprehensive income in Generation's Consolidated Balance Sheet as of June
30, 2003. Net unrealized losses of $346 million were recognized in
accumulated depreciation and accumulated other comprehensive income in the
Consolidated Balance Sheets of Exelon and Generation at December 31, 2002.
During the three and six months ended June 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 June 30, Six Months Ended June 30,
-------------------------- -------------------------
2003 2002 2003 2002
- --------------------------------------------------------------------------------------------------------
Proceeds from sales $ 690 $ 309 $ 1,262 $ 889
Gross realized gains 51 13 65 31
Gross realized losses (45) (24) (53) (56)
- --------------------------------------------------------------------------------------------------------
Net realized gains of $6 million and net realized losses of $11
million for the three months ended June 30, 2003 and 2002, respectively,
were recorded in other income and deductions. Net realized gains of $12
million and net realized losses of $21 million for the six months ended
June 30, 2003 and 2002, respectively, were recorded in other income and
41
deductions. Net realized losses of $4 million were recognized in
accumulated depreciation at June 30, 2002. The available-for-sale
securities held at June 30, 2003 have an average maturity of eight to ten
years. The cost of these securities was determined on the basis of specific
identification.
8. 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 for the year ended December 31, 2002. See Note 2 - New
Accounting Principles and Accounting Changes for further discussion of
nuclear decommissioning commitments and contingencies.
Environmental Liabilities
As of June 30, 2003, Exelon had accrued $131 million for
environmental investigation and remediation costs that currently can be
reasonably estimated, including $108 million for manufactured gas plant
(MGP) investigation and remediation. Exelon has identified 71 sites where
former MGP activities have or may have resulted in actual site
contamination.
As of June 30, 2003, ComEd had accrued $86 million for
environmental investigation and remediation costs that currently can be
reasonably estimated. This reserve included $82 million (discounted) for
MGP investigation and remediation.
As of June 30, 2003, PECO had accrued $35 million (undiscounted)
for environmental investigation and remediation costs that currently can be
reasonably estimated, including $26 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 12 - Supplemental Financial Information).
As of June 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.
Energy Commitments
Exelon and Generation had long-term commitments as of June 30,
2003 relating to the net purchase and sale of energy, capacity and
transmission rights from unaffiliated utilities,
42
including Midwest Generation, LLC (Midwest Generation), and others,
including AmerGen, 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 $ 531 $2,012 $ 231 $1,306 $ 38
2004 822 1,708 492 1,066 103
2005 509 536 386 296 84
2006 476 169 398 223 3
2007 458 61 404 212 --
Thereafter 3,802 1 1,826 845 --
- ------------------------------------------------------------------------------------------------------------------------------
Total $6,598 $4,487 $3,737 $3,948 $ 228
==============================================================================================================================
(1) Net Capacity Purchases includes Midwest Generation commitments as of
June 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. Net Capacity Purchases in 2004 include 3,474 MWs of
optional capacity from Midwest Generation. Net Capacity Purchases also
include capacity sales to 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 Nuclear Power
Station (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 has
agreed to purchase all of the residual energy from Clinton Nuclear
Power Station (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.
(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. Prices for this 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, which could include
Generation. The PPA for 2005 and 2006 may be extended to a full
requirements contract as a result of the Agreement (see Note 4 - Regulatory
Issues).
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. 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 (Class
Period). The complaints allege that Exelon violated Federal securities laws
by issuing a series of materially false and misleading statements relating
to its 2001 earnings expectations during the Class Period. The court
consolidated the pending cases into one lawsuit and appointed two lead
plaintiffs as well as lead counsel.
On October 1, 2002, the plaintiffs filed a consolidated amended
complaint, which contained allegations of new facts and several new
theories of liability. On June 13, 2003, the court dismissed the amended
complaint with prejudice. The plaintiffs have agreed not to appeal 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
Federal Energy Regulatory Commission (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. ComEd and
the municipal customers have executed a settlement agreement ending the
litigation. Under the settlement, ComEd will pay a total of approximately
$3 million to the three municipalities.
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
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
44
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.
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.
The Court preliminarily approved the settlement on June 23, 2003, and a
final hearing is set for October 2, 2003. The settlement, when approved,
will release ComEd from all claims arising from the 1999 power outages. A
portion of any settlement or verdict may be covered by insurance.
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 total $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.
Cotter intends to vigorously defend each case.
On February 18, 2000, ComEd sold Cotter to an unaffiliated third
party. As part of the
45
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.
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.
Raytheon Arbitration. 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 contract. Hearings by the
Arbitration Court with respect to damages are scheduled and a final
decision is expected in September 2003. Generation believes that Sithe New
England properly rejected Raytheon's request for a change order and that
Raytheon's damages claims are inflated. In addition to its asserted claims,
Raytheon has indicated that it will bring additional claims for damages.
Exelon will continue to vigorously defend its position in the arbitration
and contest any additional claims that may be asserted.
46
Clean Air Act. On June 1, 2001, the EPA issued to EBG a Notice of
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 Mystic Station in Everett, Massachusetts. 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 Sithe 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 units at the plant.
Mystic Station also undertook an extensive opacity monitoring and testing
program for all four 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 units to a lower sulfur
fuel oil by September 1, 2002. The Compliance Order does 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.
Real Estate Tax Appeals. Generation is involved in tax appeals
regarding a number of its nuclear facilities, Limerick Generating Station
(Montgomery County, PA), Peach Bottom Atomic Power Station (York County,
PA) and Quad Cities Station (Rock Island County, IL). Generation is also
involved in the tax appeal for Three Mile Island (Dauphin County, PA)
through AmerGen. Generation does not believe the outcome of these matters
will have a material adverse effect on Generation's results of operations
or financial condition.
Exelon, ComEd, PECO and Generation
Exelon, ComEd, PECO and Generation are involved in various other
litigation matters. 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.
47
Commercial Commitments
Exelon, ComEd, PECO and Generation's commercial commitments as of
June 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, are as follows:
Expiration within
-----------------------------------------------------------------------
2008
Exelon Total 2003 2004-2005 2006-2007 and beyond
- -----------------------------------------------------------------------------------------------------------------------
Related to Obligations Recorded on the Balance Sheet
- ---------------------------------------------------------
Credit Facility (a) $ 1,500 $ 1,500 $ -- $ -- $ --
Letters of Credit (non-debt) (b) 119 45 74 -- --
Letters of Credit (long-term debt) (c) 456 158 298 -- --
Preferred Securities Guarantee (d, e) 528 -- -- -- 528
Guarantees of Long-Term Debt (f) 41 -- 2 -- 39
Midwest Generation Capacity
Reservation Agreement Guarantee (g) 34 2 7 7 18
Other
-----
Guarantees of Letters of Credit (h) 93 77 16 -- --
Performance Guarantees (i) 101 -- -- -- 101
Surety Bonds (j) 681 241 286 3 151
Energy Marketing Contract
Guarantees (k) 207 92 115 -- --
Nuclear Insurance Guarantees (l) 1,380 -- -- -- 1,380
Lease Guarantees (m) 13 -- -- 2 11
EBG Equity Guarantee (n) 38 38 -- -- --
Fuel purchase agreements (o) 2,169 308 690 637 534
- -----------------------------------------------------------------------------------------------------------------------
Total $ 7,360 $ 2,461 $ 1,488 $ 649 $ 2,762
=======================================================================================================================
Expiration within
-----------------------------------------------------------------------
2008
ComEd Total 2003 2004-2005 2006-2007 and beyond
- -----------------------------------------------------------------------------------------------------------------------
Related to Obligations Recorded on the Balance Sheet
----------------------------------------------------
Credit Facility (a) $ 100 $ 100 $ -- $ -- $ --
Letters of Credit (non-debt) (b) 23 4 19 -- --
Letters of Credit (long-term debt) (c) 92 92 -- -- --
Preferred Securities Guarantees (e) 350 -- -- -- 350
Midwest Generation Capacity
Reservation Agreement Guarantee (g) 34 2 7 7 18
Other
-----
Surety Bonds (j) 21 -- 3 -- 18
- -----------------------------------------------------------------------------------------------------------------------
Total $ 620 $ 198 $ 29 $ 7 $ 386
=======================================================================================================================
48
Expiration within
-----------------------------------------------------------------------
2008
PECO Total 2003 2004-2005 2006-2007 and beyond
- -----------------------------------------------------------------------------------------------------------------------
Related to Obligations Recorded on the Balance Sheet
----------------------------------------------------
Credit Facility (a) $ 400 $ 400 $ -- $ -- $ --
Letters of Credit (non-debt) (b) 31 1 30 -- --
Preferred Securities Guarantees (d) 178 -- -- -- 178
Other
-----
Surety Bonds (j) 45 1 44 -- --
- ----------------------------------------------------------------------------------------------------------------------
Total $ 654 $ 402 $ 74 $ -- $ 178
=======================================================================================================================
Expiration within
-----------------------------------------------------------------------
2008
Generation Total 2003 2004-2005 2006-2007 and beyond
- ----------------------------------------------------------------------------------------------------------------------
Related to Obligations Recorded on the Balance Sheet
----------------------------------------------------
Credit Facility (a) $ -- $ -- $ -- $ -- $ --
Letters of Credit (non-debt) (b) 16 9 7 -- --
Letters of Credit (long-term debt) (c) 364 66 298 -- --
Other
-----
Guarantees of Letters of Credit (h) 66 66 -- -- --
Performance Guarantees (i) 101 -- -- -- 101
Surety Bonds (j) 43 -- -- -- 43
Energy Marketing Contract
Guarantees (k) 24 24 -- -- --
Nuclear Insurance Guarantee (p) 134 -- -- -- 134
EBG Equity Guarantee (n) 38 38 -- -- --
Fuel purchase agreements (o) 2,169 308 690 637 534
- ----------------------------------------------------------------------------------------------------------------------
Total $ 2,955 $ 511 $ 995 $ 637 $ 812
=======================================================================================================================
(a) Credit Facility - Exelon, along with ComEd, PECO and Generation,
maintain a $1.5 billion 364-day credit facility to support
commercial paper issuances. At June 30, 2003, there were no
borrowings against the credit facility. Additionally, at June 30,
2003, commercial paper outstanding was as follows:
Exelon Corporate $ 411
ComEd --
PECO 170
Generation --
(b) 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.
(c) 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.
(d) Preferred Securities Guarantee - Guarantees issued to guarantee the
preferred securities of the subsidiary trusts of PECO.
(e) Preferred Securities Guarantees - Guarantees issued to guarantee the
preferred securities of the subsidiary trusts of ComEd.
(f) Guarantees of Long-Term Debt - Issued to guarantee payment of
Enterprises' debt.
(g) 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 fair value of this guarantee under FIN 45
of $4 million is included as a liability on Exelon and ComEd's
Consolidated Balance Sheets. Additional information regarding this
liability is included within this section under the heading
"General" below.
(h) 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.
(i) Performance Guarantees - Guarantees issued to ensure performance
under specific contracts.
(j) Surety Bonds - Guarantees issued related to contract and commercial
surety bonds, excluding bid bonds.
49
(k) Energy Marketing Contract Guarantees - Guarantees issued to ensure
performance under energy commodity contracts.
(l) Nuclear Insurance Guarantees - Guarantees of nuclear insurance
required under the Price-Anderson Act. $1.1 billion of this total
exposure is exempt from the $4.5 billion PUHCA guarantee limit by
SEC rule.
(m) Lease Guarantees - Guarantees issued to ensure payments on building
leases.
(n) 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.
(o) Fuel Purchase Agreements - Commitments to purchase fuel supplies for
nuclear generation.
(p) 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 $1.2 billion guarantee relating to Generation's
directly owned plants that is not included in this amount.
Credit Contingencies
Generation is a counterparty to Dynegy in various energy
transactions. In early July 2002, the credit ratings of Dynegy were
downgraded to below investment grade by two credit rating agencies. As of
June 30, 2003, Generation had a net receivable from Dynegy of approximately
$4 million and, consistent with the terms of the existing credit
arrangement, has received collateral in support of this receivable.
Generation also 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 June 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 terms 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 $17
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.
In connection with ComEd's sale of assets to Midwest Generation
prior to the Merger, ComEd had entered into an Agency Agreement with
Midwest Generation and certain of Midwest Generation's related parties (the
"Guarantors") whereby the Guarantors assumed the benefits and liabilities
of a coal purchase contract. ComEd remained the signatory to the coal
contract, and in connection with the Merger and subsequent restructuring,
Generation assumed the signatory obligation on this contract from ComEd.
Midwest Generation's credit ratings have recently been downgraded by
certain credit rating agencies. In the event of Midwest Generation and the
Guarantors non-performance under the coal purchase contract, Generation
would be required to fulfill the purchase commitments which 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 contract years 2003 to 2012 are
estimated to be approximately $81 million related to this agreement.
Generation and ComEd have entered
50
into other agreements with Midwest Generation in which the non-performance
by Midwest Generation is currently not anticipated to result in significant
contingent obligations to Generation or ComEd.
Spent Fuel Storage
In connection with a July 2000 agreement between PECO and the U.S.
Department of Energy (DOE) relating to the Peach Bottom Station Nuclear
Waste Fund and interim spent nuclear fuel storage costs, Generation is
currently in discussions with the DOE regarding possible repayment of
amounts received as credits against contributions to the Nuclear Waste
Fund. Based upon discussions with the DOE, Generation estimates the range
of potential liability to be $0 to $20 million, excluding any additional
recoveries. At June 30, 2003, based upon the status of the discussions and
uncertainty surrounding the amounts to be repaid, if any, no amounts have
been accrued. See Note 9 - Nuclear Decommissioning and Spent Nuclear Fuel
Storage in Generation's Form 10-K for the year ended December 31, 2002 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 from
Midwest Generation $22 million 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). 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, ComEd and PECO would have positive net cash
flows related to these agreements if any fees are paid to the tax
consultant. 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.
51
In the second quarter of 2003, Exelon progressed in its plans to
implement its new business model referred to as The Exelon Way. The Exelon
Way is focused on improving operating cash flows while meeting service and
financial commitments through improved integration of operations and
consolidation of support functions. Exelon is working to meet its goals of
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 anticipates incurring expenses
associated with the rationalization of certain business functions and
employee separation costs. These expenses may be significant and are
expected to be incurred during the remaining half of 2003 through 2005.
However, these costs cannot be reasonably estimated at this time.
9. LONG-TERM DEBT AND PREFERRED SECURITIES (Exelon, ComEd, PECO and Generation)
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 redeemed $200 million of its trust
preferred securities at a redemption price of 100% of the principal amount,
plus accrued distributions. 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 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.
52
During the six months ended June 30, 2003, Exelon and ComEd
retired $267 million and $52 million of commercial paper classified as
long-term debt, respectively.
During the six months ended June 30, 2003, ComEd recorded
prepayment premiums of $15 million and net unamortized premiums, discounts
and debt issuance expenses of $31 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.
On June 24, 2003, PECO issued $100 million of trust preferred
securities with an annual distribution rate of 5.75% that are mandatorily
redeemable in 2033. These securities were recorded as liabilities in
accordance with SFAS No. 150 (see Note 2 - New Accounting Principles and
Accounting Changes). The proceeds of the issue were used to redeem the
trust preferred securities and preferred stock discussed below.
Also on June 24, 2003, 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.
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 13, 2003, Generation closed on a $550 million revolving
credit facility. 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 from Sithe. This note was restructured in June 2003 to provide
for a payment of $210 million of the principal on June 16, 2003 and the
remaining principal on the earlier of December 1, 2003 or change of
control.
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. 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.
See Note 7 - Fair Value of Financial Assets and Liabilities for
additional information regarding interest rate swaps of ComEd, PECO and
Generation.
53
10. UNCONSOLIDATED INVESTMENTS (Exelon and Generation)
During the three months ended June 30, 2003, Exelon recorded an
impairment charge of $35 million (before income taxes) in other income and
deductions within the Consolidated Statements of Income and Comprehensive
Income related to an other-than-temporary decline in value of certain
investments held by Enterprises. Management of Exelon and Enterprises
considered various factors in the decision to record an impairment of these
investments, including recent valuations of the investments. This
impairment reduced the book value of these investments from $42 million at
December 31, 2002 to $7 million at June 30, 2003.
Generation
Generation is a 49.9% owner of Sithe and has accounted for the
investment as an unconsolidated equity investment through June 30, 2003. In
the first quarter of 2003, Exelon and Generation recorded an impairment
charge of $200 million (before income taxes) in other income and
deductions, associated with a decline in the Sithe investment fair value,
which was considered to be other than temporary. Exelon and Generation's
management considered various factors in the decision to record an
impairment of this investment, including management's recent experience of
exploring the sale of 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 charge was required. The book
value of Generation's investment in Sithe was $209 million at June 30,
2003. For the six months ended June 30, 2003, Sithe had revenues of $356
million. Generation recorded $1.6 million of equity method losses for Sithe
for the six months ended June 30, 2003. See Note 2 - New Accounting
Principles and Accounting Changes for 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 35.2%
interest in Sithe owned by Apollo Energy, LLC and the 14.9% interest owned
by subsidiaries of Marubeni Corporation. The total call price was based on
the terms of the existing Put and Call Agreement (PCA) among the parties
and approximated $650 million. The transfer of ownership requires various
regulatory approvals, including FERC, the state environmental agency in New
Jersey, and expiration of the Hart Scott Rodino waiting period.
Under the terms of the PCA, the call must be funded within six
months of the call notice being issued. Additionally, because the Federal
Power Act restricts Exelon's ownership of 50% or more of qualifying
facilities, the qualifying facilities owned by Sithe must be sold or
restructured before closing to preserve their status as qualifying
facilities. Despite the issuance of the call notice, Generation continues
to pursue options to sell its investment in Sithe in its entirety.
Generation is a 50% owner of AmerGen and has accounted for the
investment as an unconsolidated equity investment through June 30, 2003.
The book value of Generation's investment in AmerGen was $260 million at
June 30, 2003. For the six months ended June 30, 2003, AmerGen had revenues
of $307 million. Generation recorded $29 million of equity method earnings
for AmerGen for the six months ended June 30, 2003.
54
11. RELATED-PARTY TRANSACTIONS (Exelon, ComEd, PECO and Generation)
Exelon's financial statements reflect related-party transactions
with unconsolidated affiliates as reflected in the tables below.
Three Months Ended June 30, Six Months Ended June 30,
--------------------------- -------------------------
2003 2002 2003 2002
- -----------------------------------------------------------------------------------------------------------------------
Purchased power from AmerGen (1) $ 110 $ 60 $ 177 $ 116
Interest income from AmerGen (2) -- -- 1 1
Interest expense to Sithe (3) 3 -- 6 --
Services provided to AmerGen (4) 18 16 35 30
Services provided to Sithe (5) -- -- 1 --
Services provided by Sithe (6,7) 2 -- 5 1
- -----------------------------------------------------------------------------------------------------------------------
June 30, 2003 December 31, 2002
- -----------------------------------------------------------------------------------------------------------------------
Net receivable from AmerGen (1,2,4) $ -- $ 39
Net payable to AmerGen (1,2,4) 17 --
Net payable to Sithe (5,6,7) 5 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 has agreed
to purchase all of the residual energy from Clinton through December
31, 2004. Currently, the residual output is approximately 31% of the
total output of Clinton.
(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. As of June 30, 2003, the principal balance of
the loan was paid in full.
(3) Under the terms of the agreement to acquire Exelon New England dated
November 1, 2002, Generation issued a $534 million note to be paid in
full 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 and the
balance of the note is to be paid by December 1, 2003 or upon change of
control. The note bears interest at the rate equal to LIBOR plus
0.875%. Interest accrued on the note as of June 30, 2003 was $0.3
million.
(4) Under a service agreement dated March 1, 1999, Generation provides
AmerGen with 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. Exelon
also provides AmerGen with certain payroll processing services.
(5) Under a service agreement dated December 18, 2000, Generation provides
certain 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 certain 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
New England acquisition that occurred on November 1, 2002.
55
ComEd
ComEd's financial statements reflect related-party transactions as
reflected in the tables below.
Three Months Ended June 30, Six Months Ended June 30,
-------------------------- ------------------------
2003 2002 2003 2002
- ---------------------------------------------------------------------------------------------------------
Operating revenues from affiliates
Generation (1) $ 15 $ 10 $ 26 $ 19
Enterprises (1) 1 2 3 4
Purchased power from affiliate
Generation (2) 528 547 1,099 1,079
Operating & maintenance from affiliates
BSC (3) 25 26 52 65
Enterprises (4,5) 3 3 6 6
Interest income from affiliates
UII (6) 6 7 12 15
Generation (11) 1 -- 1 --
Other -- 1 -- 1
Capitalized costs
BSC (3) 1 2 2 3
Enterprises (5) 6 6 12 13
Cash dividends paid to parent 91 117 211 235
- ---------------------------------------------------------------------------------------------------------
June 30, 2003 December 31, 2002
- ---------------------------------------------------------------------------------------------------------
Receivables from affiliates (current)
UII (6) $ 12 $ 15
Generation (11) 165 --
Receivables from affiliates (noncurrent)
UII (6) 1,284 1,284
Generation (9) 1,094 --
Other 19 16
Payables to affiliates (current)
Generation decommissioning (8) 11 59
Generation (1, 2, 7) 185 339
BSC (3, 7) 11 18
Other 2 --
Payables to affiliates (noncurrent)
Generation decommissioning obligation (8) 19 218
Other 7 6
Shareholders' equity - receivable from parent (10) 554 615
- ---------------------------------------------------------------------------------------------------------
(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 8 - 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 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.
(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.
56
(7) In order to benefit from economies of scale, ComEd processes certain
invoice payments on behalf of Generation and BSC.
(8) 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.
(9) 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.
(10) 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.
(11) ComEd participates in Exelon's intercompany money pool. ComEd had
various notes to and earned interest from Generation under the money
pool.
PECO
PECO's financial statements reflect a number of related-party
transactions as reflected in the table below.
Three Months Ended June 30, Six Months Ended June 30,
--------------------------- -------------------------
2003 2002 2003 2002
- --------------------------------------------------------------------------------------------------------
Operating revenues from affiliate
Generation (1) $ 3 $ 3 $ 5 $ 7
Purchased power from affiliate
Generation (2) 324 346 681 649
Operating & maintenance from affiliates
BSC (3) 10 9 22 26
Enterprises (4) 1 8 3 16
Capitalized costs
BSC (3) 2 5 5 6
Enterprises (4) 7 -- 13 10
Cash dividends paid to parent 76 85 165 170
- --------------------------------------------------------------------------------------------------------
June 30, 2003 December 31, 2002
- --------------------------------------------------------------------------------------------------------
Payables to affiliates (current)
Generation (2) $ 121 $ 124
BSC (3) 12 26
Enterprises (4) 3 19
Other 1 1
Payable to affiliate (noncurrent)
Generation (5) 16 --
Shareholders' equity - receivable from parent (6) 1,698 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 8 - Commitments and Contingencies for further information
regarding the PPA.
(3) PECO provides services to BSC related to invoice processing. 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 deployment 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.
57
Generation
Generation's financial statements reflect related-party
transactions with unconsolidated affiliates as reflected in the tables
below.
Three Months Ended June 30, Six Months Ended June 30,
--------------------------- -------------------------
2003 2002 2003 2002
- -----------------------------------------------------------------------------------------------------------------------
Purchased power from AmerGen (1) $ 110 $ 60 $ 177 $ 116
Interest income from AmerGen (2) -- -- 1 1
Interest expense to Sithe (3) 3 -- 6 --
Services provided to AmerGen (4) 18 16 35 30
Services provided to Sithe (5) -- -- 1 --
Services provided by Sithe (6,7) 2 -- 5 1
- ----------------------------------------------------------------------------------------------------------------------
June 30, 2003 December 31, 2002
- ----------------------------------------------------------------------------------------------------------------------
Net receivable from AmerGen (1,2,4) $ -- $ 39
Net payable to AmerGen (1,2,4) 19 --
Net payable to Sithe (5,6,7) 5 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.
(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. As of June 30, 2003, the principal balance of
the loan was paid in full. Total interest earned on the loan was less
than $1 million during the three and six months ended June 30, 2003 and
2002.
(3) Under the terms of the agreement to acquire Exelon New England dated
November 1, 2002, Generation issued a $534 million note to be paid in
full 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 and the
balance of the note is to be paid by December 1, 2003 or upon change of
control. The note bears interest at the rate equal to LIBOR plus
0.875%. Interest accrued on the note as of June 30, 2003 was $0.3
million.
(4) Under a service agreement dated March 1, 1999, Generation provides
AmerGen with 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
certain engineering and environmental services for fossil facilities
owned by Sithe and for certain developmental projects. Generation is
compensated for these services at cost. Total revenue earned under this
service agreement was less than $1 million for the three and six months
ended June 30, 2003 and 2002.
(6) Under a service agreement dated December 18, 2000, Sithe provides
Generation certain 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 1, 2002.
58
In addition to the transactions with unconsolidated affiliates
described above, Generation's financial statements reflect a number of
related-party transactions as reflected in the tables below.
Three Months Ended June 30, Six Months Ended June 30,
-------------------------- -------------------------
2003 2002 2003 2002
- -------------------------------------------------------------------------------------------------------------------------
Operating revenues from affiliates
ComEd (1) $ 528 $ 547 $ 1,099 $ 1,079
PECO (1) 324 346 681 649
Exelon Energy Company (2) 44 60 109 117
Purchased power from affiliates
ComEd (4) 13 8 20 14
PECO (4) -- 3 -- 5
Exelon Energy Company (4) 2 -- 9 2
Operating & maintenance from affiliates
ComEd (4) 2 2 6 5
PECO (4) 3 -- 5 2
BSC (6) 35 35 71 87
Interest expense - affiliate
ComEd (8) 1 -- 1 --
Exelon (3) -- 1 1 1
Cash distribution paid to member 45 -- 45 --
- -------------------------------------------------------------------------------------------------------------------------
June 30, 2003 December 31, 2002
- -------------------------------------------------------------------------------------------------------------------------
Receivables from affiliates (current)
ComEd (1) $ 185 $ 339
ComEd decommissioning receivable (7) 11 59
PECO (1) 121 124
BSC (6) -- 14
Exelon Energy Company (2) 16 19
Other 1 --
Receivables from affiliates (noncurrent)
ComEd decommissioning receivable (7) 19 218
PECO decommissioning receivable (5) 16 --
Other -- 2
Payables to affiliates (current)
Exelon (3) 3 3
BSC (6) 18 --
Payable to affiliate (noncurrent)
ComEd decommissioning (5) 1,094 --
Notes payable to affiliate - Exelon (3) 226 329
Notes payable to affiliates - ComEd (8) 165 --
- -----------------------------------------------------------------------------------------------------------------------
<FN>
(1) Effective January 1, 2001, Generation entered into PPAs with ComEd and
PECO. See Note 8 - Commitments and Contingencies for further information on
the PPAs.
(2) Generation sells power to Exelon Energy Company (an Enterprises company).
(3) Generation has a payable to Exelon related to certain compensation plans.
(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.
(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.
59
(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 has a note payable to ComEd related to Generation's short-term
liquidity requirements.
</FN>
12. SUPPLEMENTAL FINANCIAL INFORMATION (Exelon, ComEd and PECO)
June 30, December 31,
ComEd 2003 2002
- -----------------------------------------------------------------------------------------------------------------------
Regulatory Assets (Liabilities)
Nuclear decommissioning
(see Note 2 - New Accounting Principles and Accounting Changes) $ (1,094) $ --
Nuclear decommissioning costs for retired plants -- 248
Recoverable transition costs 153 175
Reacquired debt costs and interest rate swap settlements 173 84
Recoverable deferred income taxes (64) (68)
Other 22 8
- -----------------------------------------------------------------------------------------------------------------------
Total $ (810) $ 447
=======================================================================================================================
June 30, December 31,
PECO 2003 2002
- -----------------------------------------------------------------------------------------------------------------------
Regulatory Assets
Competitive transition charge $ 4,478 $ 4,639
Recoverable deferred income taxes 744 729
Non-pension postretirement benefits 62 64
Reacquired debt costs 51 53
Nuclear decommissioning and decontamination funds 29 32
Nuclear decommissioning
(see Note 2 - New Accounting Principles and Accounting Changes) 16 --
MGP regulatory asset (see Note 8 - Commitments and Contingencies) 16 20
Compensated absences 15 6
Post-employment benefits 3 3
- -----------------------------------------------------------------------------------------------------------------------
Long-term regulatory assets 5,414 5,546
Deferred energy costs (current asset) 55 31
- -----------------------------------------------------------------------------------------------------------------------
Total $ 5,469 $ 5,577
=======================================================================================================================
Exelon's long-term regulatory assets and liabilities as of June 30, 2003
were $5,414 million and $810 million, respectively. Exelon's long-term
regulatory assets as of December 31, 2002 were $5,993 million.
60
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
(Dollars in millions, unless otherwise noted)
EXELON CORPORATION
- ------------------
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 6 of the Condensed Combined Notes to Consolidated Financial
Statements for further segment information.
RESULTS OF OPERATIONS
Three Months Ended June 30, 2003 Compared To Three Months Ended June 30, 2002
Net Income and Earnings Per Share
Exelon's net income for the three months ended June 30, 2003 decreased $113
million or 23%, compared to the same period in 2002. Diluted earnings per common
share on the same basis decreased $0.36 per share, or 24%. The decrease in net
income was due to unfavorable weather impacts at Energy Delivery due to cooler
spring weather and a goodwill impairment charge recorded at the InfraSource,
Inc. reporting unit within Enterprises during the second quarter 2003. Also, a
gain was recorded in the second quarter of 2002 due to the sale of an investment
in AT&T Wireless held by Enterprises. These decreases were partially offset by
increased market sales and mark-to-market activity at Generation, reduced
depreciation expense resulting from lower depreciation rates at Energy Delivery
and decreased interest expense at Energy Delivery due to refinancing of
outstanding debt at lower interest rates.
61
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 June 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 June 30,
---------------------------
2003 2002 Variance % Change
- ------------------------------------------------------------------------------------------------------------------------
Energy Delivery $ 291 $ 322 $ (31) (9.6%)
Generation 142 84 58 69.0%
Enterprises (61) 83 (144) (173.5%)
Corporate -- (4) 4 (100.0%)
- ------------------------------------------------------------------------------------------------------
Total $ 372 $ 485 $ (113) (23.3%)
======================================================================================================
Results of Operations - Energy Delivery
Three Months Ended June 30,
---------------------------
Energy Delivery 2003 2002 Variance % Change
- ------------------------------------------------------------------------------------------------------------------------
Operating revenues $ 2,322 $ 2,476 $ (154) (6.2%)
Revenue, net of purchased power & fuel expense 1,336 1,465 (129) (8.8%)
Operating income 666 736 (70) (9.5%)
Income before income taxes 481 522 (41) (7.9%)
Net income 291 322 (31) (9.6%)
- -------------------------------------------------------------------------------------------------------------------------
The changes in Energy Delivery's revenue, net of purchased power and fuel
expense, for the three months ended June 30, 2003 compared to the same period in
2002, included the following:
o unfavorable weather impacts of $66 million, primarily the result of
cooler spring weather,
o unfavorable pricing changes of $22 million related to ComEd's Power
Purchase Agreement (PPA) with Generation,
o net unfavorable changes due to customer choice of $20 million,
including ComEd's customers electing to purchase energy from
alternative energy suppliers or electing ComEd's Power Purchase Option
(PPO), under which non-residential customers can purchase power from
ComEd at a market-based rate, and customers in PECO's service
territory selecting an alternative electric generation supplier,
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 were not recorded in purchased power in 2002 (see Note 2 of the
Condensed Combined Notes to Consolidated Financial Statements),
o changes in customer rates resulting in an $8 million unfavorable
variance, and
o lower PJM ancillary charges resulting in a favorable variance of $7
million.
The changes in operating income, other than changes in revenue net of
purchased power and fuel expense, for the three months ended June 30, 2003
compared to the same period in 2002, included the following:
o reduction in depreciation expense of $24 million due to the impact of
lower depreciation rates at ComEd effective July 1, 2002, partially
offset by increased depreciation expense in 2003 of $11 million due to
higher plant in service balances,
o reduction of amortization expense of $16 million for nuclear
decommissioning of retired plants at ComEd due to the adoption of SFAS
No. 143 (see Note 2 of the Condensed Combined Notes to Consolidated
Financial Statements),
o decreased costs of $7 million associated with the initial
implementation of automated meter reading services at PECO, and
o a reversal of $12 million of accrued use tax at PECO as a result of an
audit settlement.
The changes in income before income taxes for the three months ended June
30, 2003 compared to the same period in 2002 included a reduction in interest
expense primarily related to a decrease of $24 million attributable to less
outstanding debt and refinancing of existing debt at lower interest rates.
Energy Delivery's effective income tax rate was 39.5% for the three months
ended June 30, 2003, compared to 38.3% for the same period in 2002.
63
Energy Delivery Operating Statistics and Revenue Detail
Energy Delivery's electric sales statistics and revenue detail are as follows:
Three Months Ended June 30,
---------------------------
Retail Deliveries - (in gigawatthours (GWhs))(1) 2003 2002 Variance % Change
- -------------------------------------------------------------------------------------------------------------------
Bundled Deliveries (2)
Residential 7,437 7,977 (540) (6.8%)
Small Commercial & Industrial 6,646 7,481 (835) (11.2%)
Large Commercial & Industrial 5,378 6,049 (671) (11.1%)
Public Authorities & Electric Railroads 1,555 1,885 (330) (17.5%)
- -------------------------------------------------------------------------------------------------------
Total Bundled Deliveries 21,016 23,392 (2,376) (10.2%)
- -------------------------------------------------------------------------------------------------------
Unbundled Deliveries (3)
Alternative Energy Suppliers
- ----------------------------
Residential 186 557 (371) (66.6%)
Small Commercial & Industrial 1,580 1,179 401 34.0%
Large Commercial & Industrial 2,320 1,635 685 41.9%
Public Authorities & Electric Railroads 247 181 66 36.5%
- -------------------------------------------------------------------------------------------------------
4,333 3,552 781 22.0%
- -------------------------------------------------------------------------------------------------------
PPO (ComEd Only)
- ----------------
Small Commercial & Industrial 869 839 30 3.6%
Large Commercial & Industrial 1,318 1,392 (74) (5.3%)
Public Authorities & Electric Railroads 531 274 257 93.8%
- -------------------------------------------------------------------------------------------------------
2,718 2,505 213 8.5%
- -------------------------------------------------------------------------------------------------------
Total Unbundled Deliveries 7,051 6,057 994 16.4%
- -------------------------------------------------------------------------------------------------------
Total Retail Deliveries 28,067 29,449 (1,382) (4.7%)
=======================================================================================================
<FN>
(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 PPO.
</FN>
64
Three Months Ended June 30,
---------------------------
Electric Revenue 2003 2002 Variance % Change
- ------------------------------------------------------------------------------------------------------------------
Bundled Revenues (1)
Residential $ 769 $ 801 $ (32) (4.0%)
Small Commercial & Industrial 585 669 (84) (12.6%)
Large Commercial & Industrial 351 404 (53) (13.1%)
Public Authorities & Electric Railroads 102 121 (19) (15.7%)
- -------------------------------------------------------------------------------------------------------
Total Bundled Revenues 1,807 1,995 (188) (9.4%)
- -------------------------------------------------------------------------------------------------------
Unbundled Revenues (2)
Alternative Energy Suppliers
- ----------------------------
Residential 14 42 (28) (66.7%)
Small Commercial & Industrial 49 30 19 63.3%
Large Commercial & Industrial 48 33 15 45.5%
Public Authorities & Electric Railroads 8 5 3 60.0%
- -------------------------------------------------------------------------------------------------------
119 110 9 8.2%
- -------------------------------------------------------------------------------------------------------
PPO (ComEd Only)
- ----------------
Small Commercial & Industrial 59 55 4 7.3%
Large Commercial & Industrial 72 76 (4) (5.3%)
Public Authorities & Electric Railroads 28 17 11 64.7%
- -------------------------------------------------------------------------------------------------------
159 148 11 7.4%
- -------------------------------------------------------------------------------------------------------
Total Unbundled Revenues 278 258 20 7.8%
- -------------------------------------------------------------------------------------------------------
Total Electric Retail Revenues 2,085 2,253 (168) (7.5%)
- -------------------------------------------------------------------------------------------------------
Wholesale and Miscellaneous Revenue (3) 127 139 (12) (8.6%)
- -------------------------------------------------------------------------------------------------------
Total Electric Revenue $ 2,212 $ 2,392 $ (180) (7.5%)
=======================================================================================================
<FN>
(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 (CTC).
(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.
</FN>
The differences in electric retail revenues for the three months ended June
30, 2003 as compared to the same period in 2002 were attributable to the
following:
Variance
- -------------------------------------------------------------------------
Weather $ (129)
Customer choice (46)
Volume 18
Rate changes (8)
Other effects (3)
- -------------------------------------------------------------------------
Electric retail revenue $ (168)
=========================================================================
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 June
30, 2003 was unfavorable compared to the same period in 2002 as a result of
cooler spring weather in 2003. Cooling degree-days in the ComEd and PECO
service territories
65
were 63% lower and 40% lower, respectively, in 2003 as compared to 2002.
Heating degree-days in the ComEd and PECO service territories were 1% lower
and 38% higher, respectively, in 2003 as compared to 2002.
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 June 30, 2003, 15% 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 $38 million from customers in Illinois electing to
purchase energy from an ARES or ComEd's PPO, and a decrease in revenues of
$8 million from customers in Pennsylvania selecting an alternative electric
generation supplier. During the second quarter of 2003, approximately 2,500
customers temporarily returned to ComEd's PPO as a result of an ARES no
longer providing service in Illinois.
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. The auction for the second
phase of the residential customer MST plan is scheduled for September 2003 and
the selected customers would be transferred effective December 2003. Any
customer transferred would 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.
o Volume. Revenues from higher delivery sales, exclusive of the effect of
weather, increased $25 million at ComEd due to an increased number of
customers and increased usage per customer, primarily residential and
ComEd's PPO. Revenues from delivery sales, exclusive of the effect of
weather, decreased $7 million at PECO due to lower usage in the residential
and large commercial and industrial customer classes, partially offset by
an increase in usage by small commercial and industrial customers.
o Rate Changes. The decrease in revenues attributable to rate changes
reflects decreased wholesale market prices which decreased energy revenue
received under ComEd's PPO by
66
$48 million. This was partially offset by the collection of $40 million in
additional CTC's in 2003 by ComEd due to an increase in sales to customers
choosing an alternative energy supplier (ARES) or the ComEd PPO and an
increase in CTC rates due to lower wholesale market price of electricity,
net of increased mitigation factors.
Energy Delivery's gas sales statistics and revenue detail were as follows:
Three Months Ended June 30,
---------------------------
2003 2002 Variance % Change
- -------------------------------------------------------------------------------------------------------------------------
Deliveries in million cubic feet (mmcf) 15,001 14,286 715 5.0%
Revenue $ 110 $ 84 $ 26 31.0%
- -------------------------------------------------------------------------------------------------------------------------
The changes in gas revenue for the three months ended June 30, 2003 as
compared to the same period in 2002, were as follows:
Variance
- ------------------------------------------------------------------------------------------------------------------------
Weather $ 14
Rate changes 10
Volume 2
- ------------------------------------------------------------------------------------------------------------------------
Gas revenue $ 26
========================================================================================================================
o Weather. The demand for gas is impacted by weather conditions. Very cold
weather in non-summer months is referred to as "favorable weather
conditions," because these weather conditions result in increased sales of
gas. Conversely, mild weather reduces demand. The weather impact was
favorable compared to the prior year as a result of cooler spring weather.
Heating degree-days increased 38% in PECO's service territory for the three
months ended June 30, 2003 compared to the same period in 2002.
o Rate Changes. The favorable variance in rate changes is attributable to a
15% increase and a 7% increase 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 June 30, 2003 was 22%
higher than the rate in 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 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. Exclusive of weather impacts, delivery volume was consistent in the
three months ended June 30, 2003 compared to the same period in 2002 with
increased retail sales partially offset by lower transportation volumes.
Deliveries to customers, excluding transportation and the effects of
weather, increased 4% in the three months ended June 30, 2003 compared to
the same period in 2002.
67
Results of Operations - Generation
Three Months Ended June 30,
---------------------------
2003 2002 Variance % Change
- ------------------------------------------------------------------------------------------------------------------------
Operating revenues $ 1,886 $ 1,559 $ 327 21.0%
Revenue, net of purchased power & fuel expense 738 630 108 17.1%
Operating income 201 113 88 77.9%
Income before income taxes 233 135 98 72.6%
Net income 142 84 58 69.0%
- ------------------------------------------------------------------------------------------------------------------------
The changes in Generation's revenue, net of purchased power and fuel
expense, for the three months ended June 30, 2003 compared to the same period in
2002, included the following:
o increased market sales of $385 million primarily attributable to
regional demand and price increases, partially offset by increased
purchased power of $95 million and increased fuel expense of $124
million,
o increases of $31 million for generation from plants acquired during
2002 resulting in higher market sales,
o unfavorable weather conditions in the ComEd and PECO service
territories in 2003 resulted in a net volume decrease offset by
overall price increases of $57 million,
o increased revenue from ComEd of $16 million associated with the
adoption of SFAS No. 143, which was not included in revenue in 2002,
o mark-to-market gains on hedging activities of $32 million in 2003
compared to $4 million in 2002, and
o additional nuclear fuel amortization of $10 million resulting from
under performing fuel at the Quad Cities Unit 1.
The changes in operating income, other than changes in revenue net of
purchased power and fuel expense, for the three months ended June 30, 2003
compared to the same period in 2002, included the following:
o higher costs of $8 million for employee medical, pension and other
employee payroll and benefit costs in 2003,
o increased operating and maintenance (O&M) costs of $8 million due to
asset acquisitions made after the second quarter of 2002 and including
a $5 million impairment charge recorded in 2003 related to Mystic
Station Units 4, 5, and 6,
o reduced refueling outage costs of $21 million, including $17 million
at one of Generation's co-owned facilities, resulting from fewer
refueling outage days in 2003,
o additional depreciation of $4 million due to capital additions placed
in service and plant acquisitions made after the second quarter of
2002 and $7 million related to plant acquisitions made after the
second quarter of 2002, partially offset by $3 million of lower
depreciation due to life extensions of asset additions in 2002, and
o accretion expense of $43 million recognized in 2003 to accrete the
asset retirement obligation established at the adoption of SFAS No.
143, partially offset by the elimination of decommissioning expense of
$31 million, also as a result of the adoption of SFAS No. 143.
68
The changes in income before income taxes for the three months ended June
30, 2003 compared to the same period in 2002, included the following:
o increased decommissioning trust investment income of $15 million,
which is almost entirely offset by accretion expense recorded in O&M,
o increased equity in earnings of unconsolidated affiliates of $9
million, and
o increased interest expense of $9 million primarily due to reduced
capitalized interest in 2003 in addition to interest incurred on the
note payable to Sithe.
Generation's effective income tax rate was 39.2% for the three months ended
June 30, 2003 compared to 37.7% for the same period in 2002. This increase was
primarily attributable to an increase in taxes related to the nuclear
decommissioning trust funds.
Generation Operating Statistics
Generation's sales and the supply of these sales, excluding the trading
portfolio, were as follows:
Three Months Ended June 30,
---------------------------
Sales (in GWhs) 2003 2002 Variance % Change
- -----------------------------------------------------------------------------------------------------------------------
Energy Delivery and Exelon Energy Company 26,869 29,649 (2,780) (9.4%)
Market Sales 27,449 20,589 6,860 33.3%
- -----------------------------------------------------------------------------------------------------------
Total Sales 54,318 50,238 4,080 8.1%
===========================================================================================================
Three Months Ended June 30,
---------------------------
Supply of Sales (in GWhs) 2003 2002 Variance % Change
- -----------------------------------------------------------------------------------------------------------------------
Nuclear Generation (1) 29,619 28,776 843 2.9%
Purchases - non-trading portfolio (2) 19,344 17,978 1,366 7.6%
Fossil and Hydro Generation 5,355 3,484 1,871 53.7%
- -----------------------------------------------------------------------------------------------------------
Total Supply 54,318 50,238 4,080 8.1%
===========================================================================================================
<FN>
(1) Excluding AmerGen.
(2) Including purchased power agreements with AmerGen.
</FN>
Trading volume of 7,919 GWhs and 8,566 GWhs for the three months ended June
30, 2003 and 2002, respectively, is 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 Exelon's Risk Management Committee and approved
by the Board of Directors.
69
Generation's average margin and other operating data for the three months
ended June 30, 2003 and 2002 were as follows:
Three Months Ended June 30,
---------------------------
($/MWh) 2003 2002 % Change
- -----------------------------------------------------------------------------------------------------------------------
Average Revenue
Energy Delivery and Exelon Energy Company $ 32.67 $ 32.06 1.9%
Market Sales 34.98 30.69 14.0%
Total - excluding the trading portfolio 33.83 31.50 7.4%
Average Supply Cost (1) - excluding the trading portfolio $ 20.71 $ 18.79 10.2%
Average Margin - excluding the trading portfolio $ 13.12 $ 12.71 3.2%
- -----------------------------------------------------------------------------------------------------------------------
<FN>
(1) Average supply cost includes purchased power and fuel costs.
</FN>
Three Months Ended June 30,
---------------------------
2003 2002
- ------------------------------------------------------------------------------------------------------------------------
Nuclear fleet capacity factor (1) 94.0% 92.1%
Nuclear fleet production cost per MWh (1) $ 12.08 $ 12.54
Average purchased power cost for wholesale operations per MWh $ 43.15 $ 39.96
- ------------------------------------------------------------------------------------------------------------------------
<FN>
(1) Including AmerGen and excluding Salem.
</FN>
The factors below contributed to the overall increase in Generation's
average margin for the three months ended June 30, 2003 as compared to the same
period in 2002.
Generation's average revenue per MWh was affected by:
o increased weighted average on and off-peak prices per MWh for supply
agreements with ComEd,
o higher prices per MWh on sales under supply agreements with PECO, and
o higher market prices.
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 Sithe New England
(now known as Exelon New England) plants acquired in November 2002,
which in total account for an increase of 1,498 GWhs, and
o increased quantity of purchased power to service greater than
anticipated customer loads outside of the Energy Delivery service
areas.
Higher nuclear capacity factors and decreased nuclear production costs are
primarily due to 20 fewer planned refueling outage days, resulting in a $4
million decrease in outage costs, in the three months ended June 30, 2003 as
compared to the same period in 2002. Additionally, the three months ended June
30, 2003 included nine unplanned outages compared to eight unplanned outages
during the three months ended June 30, 2002.
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
70
factors. Problems that may occur at nuclear facilities that result in increased
costs include accelerated replacement of suspect fuel assemblies, generation
reductions to make repairs and mid-cycle outages. For example, in the second
quarter of 2003, the Quad Cities Unit 1 required a significant repair and is
unable to operate above an 85% capacity factor until the Nuclear Regulatory
Commission (NRC) inspects and approves the maintenance work. 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 anticipates NRC approval of the maintenance work
and to return the unit to its normal operating capacity in the near future.
Results of Operations - Enterprises
Three Months Ended June 30,
---------------------------
2003 2002 Variance % Change
- ---------------------------------------------------------------------------------------------------------------------
Operating revenues $ 443 $ 476 $ (33) (6.9%)
Operating loss (57) (15) (42) n.m.
Income (loss) before income taxes (95) 142 (237) (166.9%)
Net income (loss) (61) 83 (144) (173.5%)
- ---------------------------------------------------------------------------------------------------------------------
<FN>
n.m. - not meaningful
</FN>
The changes in Enterprises' operating loss for the three months ended June
30, 2003 compared to the same period in 2002, included the following:
o an impairment charge of $47 million before income taxes related to the
goodwill of InfraSource, Inc. The applicable assets and liabilities of
InfraSource, Inc. were classified as held for sale during the second
quarter of 2003,
o lower operating income at InfraSource, Inc. of $12 million primarily
resulting from a decrease in the electric line of business,
o higher operating income at Exelon Energy Company of $9 million
resulting from lower operating expense from the discontinuance of
retail sales in the PJM region including accelerated depreciation of
assets of $7 million and general and administrative costs of $2
million in 2002,
o higher operating income at Exelon Thermal of $3 million resulting from
lower production costs, and
o reductions in general and administrative expenses of $6 million.
The changes in income (loss) before income taxes for the three months ended
June 30, 2003 compared to the same period in 2002, include the following
additional impacts:
o a pre-tax gain of $198 million recorded on the AT&T Wireless sale in
2002,
o an impairment charge in 2003 of energy-related investments of $22
million and communications investments of $13 million due to an other
than temporary decline in value compared to an impairment charge in
2002 of communications investments of $27 million, energy related
investments of $9 million and a net impairment of other assets of $4
million, and
o lower equity in earnings of unconsolidated affiliates of $3 million
resulting from lower earnings at a communications joint venture.
71
The effective income tax rate was 35.8% for the three months ended June 30,
2003, compared to 41.5% for the same period in 2002. This decrease in the
effective tax rate was attributable to lower effective income tax rates on the
impairments.
Six Months Ended June 30, 2003 and Six Months Ended June 30, 2002
Net Income and Earnings Per Share
Exelon's net income for the six months ended June 30, 2003 increased $241
million or 49%, compared to the same period in 2002. Diluted earnings per common
share on the same basis increased $0.72 per share, or 47%. Net income for the
six months ended June 30, 2003 reflects $112 million of income for the
cumulative effect of a change in accounting principle as a result of the
adoption of Financial Accounting Standards Board (FASB) Statement of Financial
Accounting (SFAS) No. 143, "Asset Retirement Obligations" (SFAS No. 143), while
net income for the six months ended June 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
six months ended June 30, 2003 decreased $101 million, or 14%, compared to the
same period in 2002. Diluted earnings per common share on the same basis
decreased $0.33 per share, or 15%. The decrease in income before cumulative
effect of changes in accounting principles reflects an impairment of an
investment in Sithe held by Generation in the first quarter of 2003 and a
goodwill impairment charge recorded at the InfraSource, Inc. reporting unit
within Enterprises during the second quarter 2003. Also, Energy Delivery
recorded a one-time charge in the first quarter of 2003 as the result of an
agreement (see Note 4 of the Condensed Combined Notes to Consolidated Financial
Statements) and a gain was recorded in the second quarter of 2002 due to the
sale of an investment in AT&T Wireless held by Enterprises. These items were
partially offset by increased recoveries of competitive transition charges
(CTCs), increased market sales and mark-to-market activity at Generation,
reduced depreciation expense resulting from lower depreciation rates at Energy
Delivery and decreased interest expense at Energy Delivery due to refinancing of
outstanding debt at lower interest rates.
Results of Operations by Business Segment
The comparisons presented under this heading are comparisons of operating
results and other statistical information for the six months ended June 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.
72
Net Income (Loss) Before Cumulative Effect of Changes in Accounting Principles
by Business Segment
Six Months Ended June 30,
-------------------------
2003 2002 Variance % Change
- -------------------------------------------------------------------------------------------------------------------------
Energy Delivery $ 616 $ 538 $ 78 14.5%
Generation 89 150 (61) (40.7%)
Enterprises (78) 55 (133) n.m.
Corporate (6) (21) 15 (71.4%)
- ------------------------------------------------------------------------------------------------------
Total $ 621 $ 722 $ (101) (14.0%)
======================================================================================================
n.m. - not meaningful
Net Income (Loss) by Business Segment
Six Months Ended June 30,
-------------------------
2003 2002 Variance % Change
- -------------------------------------------------------------------------------------------------------------------------
Energy Delivery $ 621 $ 538 $ 83 15.4%
Generation 197 163 34 20.9%
Enterprises (79) (188) 109 (58.0%)
Corporate (6) (21) 15 (71.4%)
- ------------------------------------------------------------------------------------------------------
Total $ 733 $ 492 $ 241 49.0%
======================================================================================================
Results of Operations - Energy Delivery
Six Months Ended June 30,
-------------------------
Energy Delivery 2003 2002 Variance % Change
- ------------------------------------------------------------------------------------------------------------------------
Operating revenues $ 4,964 $ 4,811 $ 153 3.2%
Revenue, net of purchased power & fuel expense 2,789 2,777 12 0.4%
Operating income 1,360 1,296 64 4.9%
Income before income taxes and cumulative effect of a
change in accounting principle 998 864 134 15.5%
Income before cumulative effect of a change in
accounting principle 616 538 78 14.5%
Net income 621 538 83 15.4%
- ------------------------------------------------------------------------------------------------------------------------
The changes in Energy Delivery's revenue, net of purchased power and fuel
expense, for the six months ended June 30, 2003 compared to the same period in
2002, included the following:
o changes in customer rates resulting in a $75 million increase,
o increases in weather normalized volumes of $34 million as a result of
increases in the number of customers and additional average usage per
customer, primarily residential customers at ComEd, and small and
large commercial and industrial customers at PECO,
o net favorable weather impacts of $12 million, primarily the results of
colder winter weather, partially offset by cooler spring weather,
o net unfavorable changes due to customer choice of $28 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 unfavorable pricing changes of $39 million related to ComEd's PPA with
Generation,
73
o unfavorable variance of $31 million under the ComEd PPA with
Generation related to decommissioning collections associated with the
adoption of SFAS No. 143 in 2003, which were not recorded in purchased
power in 2002 (see Note 2 of the Condensed Combined Notes to
Consolidated Financial Statements), and
o higher PJM ancillary charges resulted in an unfavorable variance of $8
million.
The changes in operating income, other than changes in revenue net of
purchased power and fuel expense, for the six months ended June 30, 2003
compared to the same period in 2002, included the following:
o a net one-time charge of $41 million in 2003 at ComEd as the result of
an agreement described in Note 4 of Condensed Combined Notes to
Consolidated Financial Statements,
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 $20 million due to
higher plant in service balances,
o reduction of amortization expense of $31 million for nuclear
decommissioning of retired plants at ComEd due to the adoption of SFAS
No. 143 (see Note 2 of the Condensed Combined Notes to Consolidated
Financial Statements),
o lower amortization of ComEd's recoverable transition costs of $20
million in 2003,
o a reversal of $12 million of accrued use tax at PECO as a result of an
audit settlement, and
o additional amortization in 2003 of $15 million at PECO related to
PECO's competitive transition charge in accordance with the
Pennsylvania Competitive Act.
The changes in income before income taxes and cumulative effect of a change
in accounting principle for the six months ended June 30, 2003 compared to the
same period in 2002, included the following:
o a reduction in interest expense primarily related to a decrease of $45
million attributable to less outstanding debt and refinancing of
existing debt at lower interest rates, and
o the reversal in 2003 of a $12 million reserve for a potential capital
disallowance as the result of an agreement described in Note 4 of the
Condensed Combined Notes to Consolidated Financial Statements.
Energy Delivery's effective income tax rate was 38.3% for the six months
ended June 30, 2003, compared to 37.7% 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.
74
Energy Delivery Operating Statistics and Revenue Detail
Energy Delivery's electric sales statistics and revenue detail are as
follows:
Six Months Ended June 30,
-------------------------
Retail Deliveries - (GWhs) 2003 2002 Variance % Change
- ------------------------------------------------------------------------------------------------------------------------
Bundled Deliveries (1)
Residential 17,438 16,441 997 6.1%
Small Commercial & Industrial 14,053 14,687 (634) (4.3%)
Large Commercial & Industrial 10,344 11,357 (1,013) (8.9%)
Public Authorities & Electric Railroads 3,224 3,879 (655) (16.9%)
- -----------------------------------------------------------------------------------------------------------
Total Bundled Deliveries 45,059 46,364 (1,305) (2.8%)
- -----------------------------------------------------------------------------------------------------------
Unbundled Deliveries (2)
Alternative Energy Suppliers
----------------------------
Residential 450 1,348 (898) (66.6%)
Small Commercial & Industrial 3,131 2,280 851 37.3%
Large Commercial & Industrial 4,362 3,124 1,238 39.6%
Public Authorities & Electric Railroads 529 319 210 65.8%
- -----------------------------------------------------------------------------------------------------------
8,472 7,071 1,401 19.8%
- -----------------------------------------------------------------------------------------------------------
PPO (ComEd Only)
----------------
Small Commercial & Industrial 1,662 1,602 60 3.7%
Large Commercial & Industrial 2,750 2,703 47 1.7%
Public Authorities & Electric Railroads 1,069 517 552 106.8%
- -----------------------------------------------------------------------------------------------------------
5,481 4,822 659 13.7%
- -----------------------------------------------------------------------------------------------------------
Total Unbundled Deliveries 13,953 11,893 2,060 17.3%
- -----------------------------------------------------------------------------------------------------------
Total Retail Deliveries 59,012 58,257 755 1.3%
===========================================================================================================
<FN>
(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.
</FN>
75
Six Months Ended June 30,
-------------------------
Electric Revenue 2003 2002 Variance % Change
- -------------------------------------------------------------------------------------------------------------------------
Bundled Revenues (1)
Residential $ 1,673 $ 1,563 $ 110 7.0%
Small Commercial & Industrial 1,177 1,249 (72) (5.8%)
Large Commercial & Industrial 692 750 (58) (7.7%)
Public Authorities & Electric Railroads 207 230 (23) (10.0%)
- ------------------------------------------------------------------------------------------------------------
Total Bundled Revenues 3,749 3,792 (43) (1.1%)
- ------------------------------------------------------------------------------------------------------------
Unbundled Revenues (2)
Alternative Energy Suppliers
----------------------------
Residential 31 96 (65) (67.7%)
Small Commercial & Industrial 99 48 51 106.3%
Large Commercial & Industrial 103 45 58 128.9%
Public Authorities & Electric Railroads 17 7 10 142.9%
- ------------------------------------------------------------------------------------------------------------
250 196 54 27.6%
- ------------------------------------------------------------------------------------------------------------
PPO (ComEd Only)
----------------
Small Commercial & Industrial 109 98 11 11.2%
Large Commercial & Industrial 144 140 4 2.9%
Public Authorities & Electric Railroads 55 29 26 89.7%
- ------------------------------------------------------------------------------------------------------------
308 267 41 15.4%
- ------------------------------------------------------------------------------------------------------------
Total Unbundled Revenues 558 463 95 20.5%
- ------------------------------------------------------------------------------------------------------------
Total Electric Retail Revenues 4,307 4,255 52 1.2%
- ------------------------------------------------------------------------------------------------------------
Wholesale and Miscellaneous Revenue (3) 258 263 (5) (1.9%)
- ------------------------------------------------------------------------------------------------------------
Total Electric Revenue $ 4,565 $ 4,518 $ 47 1.0%
============================================================================================================
<FN>
(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.
</FN>
The differences in electric retail revenues for the six months
ended June 30, 2003 as compared to the same period in 2002 were
attributable to the following:
Variance
- -------------------------------------------------------------------------------------------------------------------------
Rate changes 75
Volume 68
Customer choice (66)
Weather (28)
Other effects 3
- -------------------------------------------------------------------------------------------------------------------------
Electric retail revenue $ 52
=========================================================================================================================
o Rate Changes. The increase in revenues attributable to rate changes
reflects the collection of additional CTC's in 2003 by ComEd of $146
million due to an increase in sales to customers choosing an ARES or the
ComEd PPO and an increase in CTC rates due to lower wholesale market price
of electricity, net of increased mitigation factors. Lower wholesale market
prices decreased energy revenue received under ComEd's PPO by $71 million.
76
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 customer class for ComEd
and in the small and large commercial and industrial customer classes for
PECO.
o Customer Choice. For the six months ended June 30, 2003, 14% 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 $77 million from customers in Illinois electing to
purchase energy from an ARES or ComEd's PPO, partially offset by an
increase in revenues of $11 million from customers in Pennsylvania
selecting or returning to PECO as their electric generation supplier.
o Weather. The weather impact for the six months ended June 30, 2003 was
unfavorable compared to the same period in 2002 as a result of cooler
spring weather in 2003, partially offset by colder winter weather. Cooling
degree-days in the ComEd and PECO service territories were 63% lower and
40% lower, respectively, in 2003 as compared to 2002. Heating degree-days
in the ComEd and PECO service territories were 13% higher and 34% higher,
respectively, in 2003 as compared to 2002.
Energy Delivery's gas sales statistics and revenue detail were as follows:
Six Months Ended June 30,
-------------------------
2003 2002 Variance % Change
- ------------------------------------------------------------------------------------------------------------------------
Deliveries in million cubic feet (mmcf) 54,627 45,643 8,984 19.7%
Revenue $ 399 $ 293 $ 106 36.2%
- ------------------------------------------------------------------------------------------------------------------------
The changes in gas revenue for the six months ended June 30, 2003
as compared to the same period in 2002, were as follows:
Variance
- ------------------------------------------------------------------------------------------------------------------------
Weather $ 73
Volume 17
Rate changes 13
Other 3
- ------------------------------------------------------------------------------------------------------------------------
Gas revenue $ 106
========================================================================================================================
o Weather. The weather impact was favorable compared to the prior year as a
result of colder winter weather. Heating degree-days increased 34% in
PECO's service territory for the six months ended June 30, 2003 compared to
the same period in 2002.
o Volume. Exclusive of weather impacts, higher delivery volume increased
revenue in the six months ended June 30, 2003 compared to the same period
in 2002 resulting from increased retail sales partially offset by lower
transportation volumes. Deliveries to customers, excluding transportation
and the effects of weather, increased 6% in the six months ended June 30,
2003 compared to the same period in 2002.
77
o Rate Changes. The favorable variance in rate changes is attributable to a
15% increase and a 7% increase 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 six months ended June 30, 2003 was 13%
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.
Results of Operations - Generation
Six Months Ended June 30,
-------------------------
2003 2002 Variance % Change
- ------------------------------------------------------------------------------------------------------------------------
Operating revenues $ 3,765 $ 3,020 $ 745 24.7%
Revenue, net of purchased power & fuel expense 1,417 1,264 153 12.1%
Operating income 295 202 93 46.0%
Income before income taxes and cumulative effect
of changes in accounting principles 160 246 (86) (35.0%)
Income before cumulative effect of changes in
accounting principles 89 150 (61) (40.7%)
Net income 197 163 34 20.9%
- ------------------------------------------------------------------------------------------------------------------------
The changes in Generation's revenue, net of purchased power and fuel
expense, for the six months ended June 30, 2003 compared to the same period in
2002, included the following:
o increased demand due to customers returning to PECO from alternative
energy suppliers and overall favorable weather conditions in the ComEd
and PECO service territories in 2003 resulting in net volume and price
increases of $22 million,
o increases of $63 million for generation from plants acquired during
2002 resulting in higher market sales,
o increased revenue from ComEd of $31 million associated with the
adoption of SFAS No. 143, which was not included in revenue in 2002,
o mark-to-market gains on hedging activities of $1 million in 2003
compared to $10 million in 2002, and
o additional nuclear fuel amortization of $16 million in 2003 resulting
from under performing fuel at the Quad Cities Unit 1.
The changes in operating income, other than changes in revenue net of
purchased power and fuel expense, for the six months ended June 30, 2003
compared to the same period in 2002, included the following:
o increased accretion expense of $103 million due to the adoption of
SFAS No. 143, partially offset by reduced decommissioning expense of
$64 million,
o higher costs of $36 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,
o increased O&M costs of $38 million due to asset acquisitions made
during 2002 and a $5 million impairment charge recorded in 2003
related to Mystic Station Units 4, 5, and 6,
o reduced refueling outage costs of $53 million, including $17 million
at one of Generation's co-owned facilities, resulting from fewer
refueling outage days in 2003,
78
o additional depreciation of $10 million due to capital additions placed
in service and plant acquisitions made during 2002 and $16 million due
to plant acquisitions made after the second quarter of 2002, partially
offset by a $10 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 income before income taxes and cumulative effect of changes
in accounting principles for the six months ended June 30, 2003 compared to the
same period in 2002, included the following:
o a pre-tax impairment charge of $200 million related to Generation's
equity investment in Sithe,
o increased decommissioning trust investment income of $33 million,
which is almost entirely offset with accretion expense recorded in
O&M,
o increased equity in earnings of unconsolidated affiliates of $5
million, and
o increased interest expense of $10 million primarily due to reduced
capitalized interest in 2003 in addition to interest incurred on the
note payable to Sithe.
Generation's effective income tax rate was 44.2% for the six months ended
June 30, 2003 compared to 39.0% for the same period in 2002. This increase was
primarily attributable to the impact of the impairment of Generation's
investment in Sithe, as well as an increase in taxes related to the nuclear
decommissioning trust funds.
Cumulative effect of changes in accounting principles recorded in the six
months ended June 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.
79
Generation Operating Statistics
Generation's sales and the supply of these sales, excluding the trading
portfolio, were as follows:
Six Months Ended June 30,
-------------------------
Sales (in GWhs) 2003 2002 Variance % Change
- -----------------------------------------------------------------------------------------------------------------------
Energy Delivery and Exelon Energy Company 57,463 58,649 (1,186) (2.0%)
Market Sales 51,264 39,913 11,351 28.4%
- -----------------------------------------------------------------------------------------------------------
Total Sales 108,727 98,562 10,165 10.3%
===========================================================================================================
Six Months Ended June 30,
-------------------------
Supply of Sales (in GWhs) 2003 2002 Variance % Change
- -----------------------------------------------------------------------------------------------------------------------
Nuclear Generation (1) 58,949 56,309 2,640 4.7%
Purchases - non-trading portfolio (2) 39,373 36,071 3,302 9.2%
Fossil and Hydro Generation 10,405 6,182 4,223 68.3%
- -----------------------------------------------------------------------------------------------------------
Total Supply 108,727 98,562 10,165 10.3%
===========================================================================================================
<FN>
(1) Excluding AmerGen.
(2) Including purchased power agreements with AmerGen.
</FN>
Trading volume of 17,446 GWhs and 22,805 GWhs for the six months ended June
30, 2003 and 2002, respectively, is 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 six months
ended June 30, 2003 and 2002 were as follows:
Six Months Ended June 30,
-------------------------
($/MWh) 2003 2002 % Change
- ------------------------------------------------------------------------------------------------------------------------
Average Revenue
Energy Delivery and Exelon Energy Company $ 32.06 $ 31.35 2.3%
Market Sales 35.94 29.44 22.1%
Total - excluding the trading portfolio 33.89 30.58 10.8%
Average Supply Cost (1) - excluding the trading portfolio $ 20.58 $ 17.78 15.7%
Average Margin - excluding the trading portfolio $ 13.31 $ 12.80 4.0%
- ------------------------------------------------------------------------------------------------------------------------
<FN>
(1) Average supply cost includes purchased power and fuel costs.
</FN>
Six Months Ended June 30,
-------------------------
2003 2002
- ---------------------------------------------------------------------------------------------------------------------------
Nuclear fleet capacity factor (1) 94.2% 91.2%
Nuclear fleet production cost per MWh (1) $ 12.40 $ 13.38
Average purchased power cost for wholesale operations per MWh $ 41.71 $ 36.76
- ---------------------------------------------------------------------------------------------------------------------------
<FN>
(1) Including AmerGen and excluding Salem.
</FN>
The factors below contributed to the overall increase in Generation's
average margin for the six months ended June 30, 2003 as compared to the same
period in 2002.
80
Generation's average revenue per MWh was affected by:
o increased weighted average on and off-peak prices per MWh for supply
agreements with ComEd,
o higher prices per MWh on sales under supply agreements with PECO, and
o higher market prices.
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 Sithe New
England (currently known as Exelon New England) plants acquired in
November 2002, which in total account for an increase of 2,995 GWhs,
and
o increased quantity of purchased power at higher prices.
Higher nuclear capacity factors and decreased nuclear production costs are
primarily due to 50 fewer planned refueling outage days, resulting in a $36
million decrease in outage costs, in the six months ended June 30, 2003 as
compared to the same period in 2002. Additionally, the six months ended June 30,
2003 included 11 unplanned outages compared to 13 unplanned outages during the
six months ended June 30, 2002.
Results of Operations - Enterprises
Six Months Ended June 30,
-------------------------
2003 2002 Variance % Change
- ------------------------------------------------------------------------------------------------------------------------
Operating revenues $ 1,022 $ 966 $ 56 5.8%
Operating loss (84) (50) (34) 68.0%
Income (loss) before income taxes and cumulative effect
of changes in accounting principles (125) 95 (220) n.m.
Income (loss) before cumulative effect of changes in
accounting principles (78) 55 (133) n.m.
Net loss (79) (188) 109 (58.0%)
- ------------------------------------------------------------------------------------------------------------------------
n.m. - not meaningful
The changes in Enterprises' operating loss for the six months ended June
30, 2003 compared to the same period in 2002, included the following:
o an impairment charge of $47 million before income taxes related to the
goodwill of InfraSource, Inc. The applicable assets and liabilities of
InfraSource, Inc. were classified as held for sale during the second
quarter of 2003,
o lower operating income at InfraSource Inc. of $5 million primarily
resulting from a decrease in the electric line of business of $13
million and a $2 million decrease in metering services partially
offset by lower costs of $7 million in the telecom line of business
and $3 million from bad debt expense recorded in 2002,
o higher operating income at Exelon Energy Company of $6 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
81
costs of $3 million. These costs were partially offset by lower gross
margins of $11 million in 2003. The lower gross margins resulted from
the reversal of mark-to-market adjustments of $11 million and
additional gas supply costs of $11 million attributable to gas
purchases at high rates in the Northeast, partially offset by higher
gross margins of $8 million in the Midwest attributable to increased
unit margins and higher volumes, and $2 million favorable related to
the wind-down of a contract,
o higher operating income at Exelon Thermal of $4 million resulting from
lower production costs, and
o reductions in general and administrative expenses of $9 million.
The changes in income (loss) before income taxes and cumulative effect of
changes in accounting principles for the six months ended June 30, 2003 compared
to the same period in 2002, include the following additional impacts:
o a pre-tax gain of $198 million in 2002 and higher equity in earnings
of unconsolidated affiliates of $4 million in 2003 primarily as a
result of the discontinuation of losses on the investment in AT&T
Wireless due to the sale of the investment in the second quarter of
2002, 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 37.6% for the six months ended June 30,
2003, compared to 42.1% 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 compared to the tax rate on the gain on the sale of
Enterprises' AT&T Wireless investment.
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 taxes (see Note 2 of the
Condensed Combined Notes to Consolidated Financial Statements).
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.
82
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.
In the second quarter of 2003, Exelon progressed in its plans to implement
its new business model referred to as The Exelon Way. The Exelon Way is focused
on improving operating cash flows while meeting service and financial
commitments through improved integration of operations and consolidation of
support functions. Exelon is working to meet its goals of 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 anticipates incurring expenses associated with the rationalization
of certain business functions and employee separation costs. These expenses may
be significant and are expected to be incurred during the remaining half of 2003
through 2005. However, these costs cannot be reasonably estimated at this time.
Cash Flows from Operating Activities
Cash flows provided by operations for the six months ended June 30, 2003
were $1.3 billion compared to $1.6 billion in the six months ended June 30,
2002. The decrease in cash flows was primarily attributable to a $229 million
decrease in working capital and the $240 million funding of the pension benefit
obligation. Energy Delivery's cash flow from operating activities primarily
results from sales of electricity and gas to a stable and diverse base of retail
83
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 and customer choice 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 six months ended June 30,
2003 were $1.0 billion, compared to $1.3 billion for the six months ended June
30, 2002. The decrease in cash flows is primarily attributable to a reduction in
plant acquisition costs of $443 million as a result of the acquisition of
generating plants during the six months ended June 30, 2002, a reduction of
capital expenditures of $9 million, the receipt of liquidating damages of $86
million from Raytheon during the six months ended June 30, 2003, partially
offset by increased investments in nuclear decommissioning trust funds of $52
million and a reduction of proceeds from the sale of investments of $279 million
primarily attributable to the sale of AT&T Wireless during the six months ended
June 30, 2002. Capital expenditures by business segment for the six months ended
June 30, 2003 and 2002 were as follows:
Six Months Ended June 30,
-------------------------
2003 2002
- ------------------------------------------------------------------------------------------------------------------
Energy Delivery $ 487 $ 495
Generation 424 475
Enterprises 11 28
Corporate and other 11 30
- ------------------------------------------------------------------------------------------------------------------
Total capital expenditures (net of liquidated damages received) $ 933 $ 1,028
==================================================================================================================
Energy Delivery's capital expenditures for 2003 reflect the continuation of
efforts to further improve the reliability of its distribution system. 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 Exelon New England generating facilities with projected capacity of 2,421
MWs of energy, additions to and upgrades of existing facilities (including
nuclear refueling outages), and nuclear fuel. During the six months ended June
30, 2003, Generation received $86 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 generating facilities. In
February 2002, Generation entered into an agreement to loan AmerGen up to $75
million at an interest rate of one-month LIBOR plus 2.25%. In July 2002, the
loan agreement and the loan were increased to $100 million and the maturity date
was extended to July 1, 2003. As of June 30, 2003, the loan has
84
been fully repaid by AmerGen. 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 $284 million for the six
months ended June 30, 2003 compared to $142 million for the same period in 2002.
The increase in cash flows is primarily attributable to debt and preferred
securities issuances of $2.1 billion and an increase of proceeds from the
exercise of employee stock options over the same period in 2002 of $31 million
partially offset by retirements and redemptions of debt and preferred securities
of $1.9 billion, the $210 million payment of the acquisition note payable to
Sithe and increased interest rate swap settlement payments of $41 million over
the same period in 2002. See Note 9 of the Condensed Combined Notes to
Consolidated Financial Statements for further discussion of Exelon's debt and
preferred securities financing activities in 2003.
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, PECO and Generation. 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. As of June 30,
2003, Exelon Corporate's sublimit was $1.0 billion, ComEd's was $100 million,
PECO's was $400 million and the sublimit for Generation was zero. The credit
facility is used principally to support the commercial paper programs of Exelon
Corporate, ComEd, PECO and Generation. At June 30, 2003, Exelon's Consolidated
Balance Sheet reflected $581 million of commercial paper outstanding. For the
six months ended June 30, 2003, the average interest rate on notes payable was
approximately 1.38%.
85
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
June 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 June 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's
subsidiary, Commonwealth Edison Company of Indiana, Inc., PECO, Generation and
Exelon Business Services Company (BSC) may participate in the money pool as
lenders and borrowers, and Exelon Corporate and ComEd as lenders. Contributions
to and permitted 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
six months ended June 30, 2003, ComEd had various loans to Generation under the
money pool. The maximum amount of loans outstanding at any time during the six
months ended June 30, 2003 was $342 million. As of June 30, 2003, the
outstanding loan balance was $165 million.
Exelon Boston Generating, LLC (EBG), an indirect subsidiary of Generation,
has approximately $1.1 billion of debt outstanding under a $1.25 billion credit
facility (EBG Facility) at June 30, 2003. The EBG Facility was entered into
primarily to finance the construction of the Mystic 8 and 9 and Fore River
generating units. The EBG Facility requires 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
are 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 are in commercial
operation, although construction has not progressed to the point of Project
Completion. Construction of Fore River is substantially complete and the unit is
currently undergoing testing. EBG does not anticipate that the projects will
achieve Project Completion by August 29, 2003. The EBG Facility is non-recourse
to Exelon and 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.
86
As a result of Exelon's continuing evaluation of the projects and
discussions with the lenders in July 2003, 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 Exelon's 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.
Exelon expects Generation will incur an impairment of its EBG related
assets, which, in aggregate, could reach approximately $550 million after income
taxes.
The debt outstanding under the EBG Facility of approximately $1.1 billion
at June 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
relating to the $536 million note that was used to purchase the EBG facilities.
This note was restructured in June 2003 to provide for a payment of $210 million
of the principal on June 16, 2003 and payment of the remaining principal on the
earlier of December 1, 2003 or change of control.
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.
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 June 30, 2003, there was $2.3 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
June 30, 2003, Exelon had provided $1.7 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 June 30, 2002 of not
less than 30%. At June 30, 2003, Exelon and ComEd's common
87
equity ratios were 34% and 46%, 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. 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 June 30, 2003, Exelon had retained
earnings of $2.5 billion, including ComEd's retained earnings of $767 million,
PECO's retained earnings of $455 million and Generation's undistributed earnings
of $1.1 billion. 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 June 30, 2003, Exelon had invested $2.2
billion in EWGs, leaving $1.8 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 June 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.
88
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.
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 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 and PECO have entered into several agreements with a tax
consultant related to the filing of refund claims with the Internal
Revenue Service (IRS). 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, ComEd and PECO would
have positive net cash flows related to these agreements if any fees
are paid to the tax consultant. 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 9 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 Nuclear Power Station (Oyster Creek) through April 9,
2009. See Note 8 of the Condensed Combined Notes to Consolidated
Financial Statements for commercial commitments tables 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
35.2% interest in Sithe owned by Apollo Energy, LLC and the 14.9%
interest owned by subsidiaries of Marubeni Corporation. The total call
price was based on the terms of the existing Put and Call Agreement
(PCA) among the parties and approximated $650 million. The transfer of
ownership requires various regulatory approvals including FERC, the
state environmental agency in New Jersey, and expiration of the Hart
Scott Rodino waiting period.
Under the terms of the PCA, the call must be funded within six
months of the call notice being issued. Additionally, because the
Federal Power Act restricts Exelon's ownership of 50% or more of
Qualifying Facilities (QFs), the QFs owned by Sithe must be sold or
restructured before closing to preserve their QF status. Despite the
issuance of the call notice, Generation continues to pursue options to
sell its investment in Sithe in its entirety.
o In June 2003, Generation entered an agreement with USEC Inc. to
purchase approximately $700 million of nuclear fuel from 2005 through
2010.
89
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 June 30, 2003 Compared to Three Months Ended June 30, 2002
Significant Operating Trends - ComEd
Three Months Ended June 30,
---------------------------
2003 2002 Variance % Change
- ------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES $ 1,361 $ 1,481 $ (120) (8.1%)
OPERATING EXPENSES
Purchased power 533 553 (20) (3.6%)
Operating and maintenance 221 220 1 0.5%
Depreciation and amortization 96 133 (37) (27.8%)
Taxes other than income 68 73 (5) (6.8%)
- ------------------------------------------------------------------------------------------------------
Total operating expenses 918 979 (61) (6.2%)
- ------------------------------------------------------------------------------------------------------
OPERATING INCOME 443 502 (59) (11.8%)
OTHER INCOME AND DEDUCTIONS
Interest expense (106) (127) 21 (16.5%)
Distributions on mandatorily redeemable preferred securities (6) (7) 1 (14.3%)
Other, net 12 14 (2) (14.3%)
- ------------------------------------------------------------------------------------------------------
Total other income and deductions (100) (120) 20 (16.7%)
- ------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 343 382 (39) (10.2%)
INCOME TAXES 138 151 (13) (8.6%)
- ------------------------------------------------------------------------------------------------------
NET INCOME $ 205 $ 231 $ (26) (11.3%)
======================================================================================================
Net Income
Net income decreased $26 million, or 11% for the three months ended June
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 customers purchasing energy from an ARES or the
PPO, partially offset by lower depreciation and amortization expense and
interest expense.
90
Operating Revenues
ComEd's electric sales statistics are as follows:
Three Months Ended June 30,
---------------------------
Retail Deliveries - (in GWhs) 2003 2002 Variance % Change
- -------------------------------------------------------------------------------------------------------------------
Bundled Deliveries (1)
Residential 5,163 5,862 (699) (11.9%)
Small Commercial & Industrial 5,114 5,600 (486) (8.7%)
Large Commercial & Industrial 1,683 2,122 (439) (20.7%)
Public Authorities & Electric Railroads 1,333 1,685 (352) (20.9%)
- ------------------------------------------------------------------------------------------------
13,293 15,269 (1,976) (12.9%)
- ------------------------------------------------------------------------------------------------
Unbundled Deliveries (2)
ARES
- ----
Small Commercial & Industrial 1,257 1,177 80 6.8%
Large Commercial & Industrial 2,128 1,622 506 31.2%
Public Authorities & Electric Railroads 247 181 66 36.5%
- ------------------------------------------------------------------------------------------------
3,632 2,980 652 21.9%
- ------------------------------------------------------------------------------------------------
PPO
- ---
Small Commercial & Industrial 869 839 30 3.6%
Large Commercial & Industrial 1,318 1,392 (74) (5.3%)
Public Authorities & Electric Railroads 531 274 257 93.8%
- ------------------------------------------------------------------------------------------------
2,718 2,505 213 8.5%
- ------------------------------------------------------------------------------------------------
Total Unbundled Deliveries 6,350 5,485 865 15.8%
- ------------------------------------------------------------------------------------------------
Total Retail Deliveries 19,643 20,754 (1,111) (5.4%)
================================================================================================
<FN>
(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.
</FN>
91
Three Months Ended June 30,
---------------------------
Electric Revenue 2003 2002 Variance % Change
- ------------------------------------------------------------------------------------------------------------------
Bundled Revenues (1)
Residential $ 472 $ 523 $ (51) (9.8%)
Small Commercial & Industrial 405 445 (40) (9.0%)
Large Commercial & Industrial 84 116 (32) (27.6%)
Public Authorities & Electric Railroads 81 102 (21) (20.6%)
- --------------------------------------------------------------------------------------------------
1,042 1,186 (144) (12.1%)
- --------------------------------------------------------------------------------------------------
Unbundled Revenues (2)
ARES
- ----
Small Commercial & Industrial 32 30 2 6.7%
Large Commercial & Industrial 43 32 11 34.4%
Public Authorities & Electric Railroads 8 5 3 60.0%
- --------------------------------------------------------------------------------------------------
83 67 16 23.9%
- --------------------------------------------------------------------------------------------------
PPO
- ---
Small Commercial & Industrial 59 55 4 7.3%
Large Commercial & Industrial 72 76 (4) (5.3%)
Public Authorities & Electric Railroads 28 17 11 64.7%
- --------------------------------------------------------------------------------------------------
159 148 11 7.4%
- --------------------------------------------------------------------------------------------------
Total Unbundled Revenues 242 215 27 12.6%
- --------------------------------------------------------------------------------------------------
Total Electric Retail Revenues 1,284 1,401 (117) (8.4)%
Wholesale and Miscellaneous Revenue (3) 77 80 (3) (3.8)%
- --------------------------------------------------------------------------------------------------
Total Electric Revenue $ 1,361 $ 1,481 $ (120) (8.1)%
- --------------------------------------------------------------------------------------------------
<FN>
(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.
</FN>
The changes in electric retail revenues for the three months ended June 30,
2003, as compared to the same period in 2002, are attributable to the following:
Variance
- -------------------------------------------------------------------------------------------------------------------
Weather $ (108)
Customer choice (38)
Volume 25
Rate changes (8)
Other effects 12
- -------------------------------------------------------------------------------------------------------------------
Electric retail revenue $ (117)
===================================================================================================================
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 June
30, 2003 was unfavorable compared to the same period in 2002 as a result of
cooler spring weather in 2003. Cooling degree-days decreased 63% in the
three months ended June 30, 2003 compared to the same period in 2002 and
were 49% lower than normal.
92
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 June 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 June 30, 2003, the energy provided by
alternative suppliers was 3,632 GWhs or 18.5% as compared to 2,980 GWhs or
14.4% for the three months ended June 30, 2002.
The decrease in revenues reflects customers in Illinois electing to
purchase energy from an ARES or the PPO. As of June 30, 2003, the number of
retail customers that had elected to purchase energy from an ARES or the
ComEd PPO was approximately 22,000 or 0.6% as compared to 22,700 or 0.6% as
of June 30, 2002. MWhs delivered to such customers increased from
approximately 5.5 million for the three months ended June 30, 2002 to 6.3
million for the three months ended June 30, 2003, or from 26% to 32% of
total quarterly retail deliveries. During the second quarter 2003,
approximately 2,500 customers temporarily came back to the ComEd PPO as a
result of an ARES no longer providing service in Illinois.
o Volume. Revenues from higher delivery volume, exclusive of weather,
increased due to an increased usage per customer, primarily residential and
PPO.
o Rate Changes. The decrease in revenues attributable to rate changes
reflects decreased wholesale market prices which decreased energy revenue
received under ComEd's PPO by $48 million. This was partially offset by the
collection of additional CTC's in 2003 by ComEd of $40 million due to an
increase in sales to customers choosing an ARES or the ComEd PPO and an
increase in the CTC rates due to lower wholesale market prices of
electricity, net of increased mitigation factors. 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 4 of the Condensed Combined Notes to Consolidated Financial
Statements, decreases the collection of CTC's as compared to the respective
period in 2002.
Wholesale and miscellaneous revenue for the three months ended June 30,
2003 were comparable to the three months ended June 30, 2002.
Purchased Power
Purchased power expense decreased $20 million, or 4% for the three months
ended June 30, 2003. The decrease in purchased power expense was primarily
attributable to a $47 million decrease due to unfavorable weather conditions, a
$21 million decrease as a result of customers choosing to purchase energy from
an ARES, partially offset by an increase of $10 million due to higher volume,
$22 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 that
were not included in purchased power in 2002. The $16 million increase in
purchased power expense related to SFAS No. 143 is offset by lower regulatory
asset amortization.
93
Operating and Maintenance
O&M expense increased $1 million for the three months ended June 30, 2003.
The increase in O&M expense was primarily attributable to an increase of $6
million in the reserve for manufactured gas plant (MGP) investigation and
remediation as a result of increased costs of a MGP site in Oak Park, Illinois,
partially offset by lower other O&M's.
Depreciation and Amortization
Depreciation and amortization expense decreased $37 million, or 28%, for
the three months ended June 30, 2003 as follows:
Three Months Ended June 30,
---------------------------
2003 2002 Variance % Change
- -------------------------------------------------------------------------------------------------------------------
Depreciation expense $ 76 $ 92 $ (16) (17.4%)
Recoverable transition costs amortization 12 20 (8) (40.0%)
Other amortization expense 8 21 (13) (61.9%)
- --------------------------------------------------------------------------------------------------
Total depreciation and amortization $ 96 $ 133 $ (37) (27.8%)
==================================================================================================
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 $24 million ($14 million, net of income taxes)
for the three months ended June 30, 2003.
Recoverable transition costs amortization decreased in the three months
ended June 30, 2003 compared to the same period in 2002. The decrease is a
result of the extension of the rate freeze through 2006 that occurred in June
2002. ComEd expects to fully recover its recoverable transition costs regulatory
asset balance of $153 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 is offset by
increased purchased power expense from Generation.
Taxes Other Than Income
Taxes other than income decreased by $5 million or 7%, as a result of a
2003 refund of $5 million for Illinois Electricity Distribution Taxes, a $5
million decrease in other taxes partially offset by a $5 million increase in
Illinois Public Utility Fund taxes, which were not charged in 2002.
94
Interest Charges
Interest charges consist of interest expense and distributions on
mandatorily redeemable preferred securities. Interest charges decreased $21
million, or 17%, for the three months ended June 30, 2003 as a result of
scheduled principal payments and refinancing existing debt at lower interest
rates.
Other, Net
Other, net decreased by $2 million for the three months ended June 30, 2003
as compared to the same period in 2002.
Income Taxes
The effective income tax rate was 40.2% for the three months ended June 30,
2003, compared to 39.5% for the three months ended June 30, 2002.
Six Months Ended June 30, 2003 Compared to Six Months Ended June 30, 2002
Significant Operating Trends - ComEd
Six Months Ended June 30,
-------------------------
2003 2002 Variance % Change
- -------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES $ 2,785 $ 2,796 $ (11) (0.4%)
OPERATING EXPENSES
Purchased power 1,110 1,091 19 1.7%
Operating and maintenance 483 457 26 5.7%
Depreciation and amortization 190 268 (78) (29.1%)
Taxes other than income 148 146 2 1.4%
- -------------------------------------------------------------------------------------------------------
Total operating expenses 1,931 1,962 (31) (1.6%)
- -------------------------------------------------------------------------------------------------------
OPERATING INCOME 854 834 20 2.4%
OTHER INCOME AND DEDUCTIONS
Interest expense (215) (252) 37 (14.7%)
Distributions on mandatorily redeemable preferred securities (14) (15) 1 (6.7%)
Other, net 34 29 5 17.2%
- -------------------------------------------------------------------------------------------------------
Total other income and deductions (195) (238) 43 (18.1%)
- -------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES AND CUMULATIVE
EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE 659 596 63 10.6%
INCOME TAXES 263 236 27 11.4%
- -------------------------------------------------------------------------------------------------------
NET INCOME BEFORE CUMULATIVE EFFECT OF
A CHANGE IN ACCOUNTING PRINCIPLE 396 360 36 10.0%
CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING
PRINCIPLE 5 -- 5 n.m.
- -------------------------------------------------------------------------------------------------------
NET INCOME $ 401 $ 360 $ 41 11.4%
=======================================================================================================
n.m. - not meaningful
95
Net Income
Net income increased $41 million, or 11% for the six months ended June 30,
2003 as compared to the same period in 2002. Net income was positively impacted
by lower depreciation and amortization expense and lower interest expense,
partially offset by lower operating revenues primarily due to unfavorable
weather and customers purchasing energy from an ARES or the PPO.
Operating Revenues
ComEd's electric sales statistics are as follows:
Six Months Ended June 30,
-------------------------
Retail Deliveries - (in GWhs) 2003 2002 Variance % Change
- -------------------------------------------------------------------------------------------------------------------
Bundled Deliveries (1)
Residential 12,049 12,271 (222) (1.8%)
Small Commercial & Industrial 10,741 11,049 (308) (2.8%)
Large Commercial & Industrial 3,167 4,078 (911) (22.3%)
Public Authorities & Electric Railroads 2,749 3,486 (737) (21.1%)
- -------------------------------------------------------------------------------------------------
28,706 30,884 (2,178) (7.1%)
- -------------------------------------------------------------------------------------------------
Unbundled Deliveries (2)
ARES
- ----
Small Commercial & Industrial 2,606 2,181 425 19.5%
Large Commercial & Industrial 3,960 3,008 952 31.6%
Public Authorities & Electric Railroads 529 319 210 65.8%
- -------------------------------------------------------------------------------------------------
7,095 5,508 1,587 28.8%
- -------------------------------------------------------------------------------------------------
PPO
- ---
Small Commercial & Industrial 1,662 1,602 60 3.7%
Large Commercial & Industrial 2,750 2,703 47 1.7%
Public Authorities & Electric Railroads 1,069 517 552 106.8%
- -------------------------------------------------------------------------------------------------
5,481 4,822 659 13.7%
- -------------------------------------------------------------------------------------------------
Total Unbundled Deliveries 12,576 10,330 2,246 21.7%
- -------------------------------------------------------------------------------------------------
Total Retail Deliveries 41,282 41,214 68 0.2%
=================================================================================================
<FN>
(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.
</FN>
96
Six Months Ended June 30,
-------------------------
Electric Revenue 2003 2002 Variance % Change
- ------------------------------------------------------------------------------------------------------------------
Bundled Revenues (1)
Residential $ 1,018 $ 1,041 $ (23) (2.2%)
Small Commercial & Industrial 802 836 (34) (4.1%)
Large Commercial & Industrial 158 218 (60) (27.5%)
Public Authorities & Electric Railroads 165 194 (29) (14.9%)
- -------------------------------------------------------------------------------------------------
2,143 2,289 (146) (6.4%)
- -------------------------------------------------------------------------------------------------
Unbundled Revenues (2)
ARES
- ----
Small Commercial & Industrial 73 43 30 69.8%
Large Commercial & Industrial 91 41 50 122.0%
Public Authorities & Electric Railroads 17 7 10 142.9%
- -------------------------------------------------------------------------------------------------
181 91 90 98.9%
- -------------------------------------------------------------------------------------------------
PPO
- ---
Small Commercial & Industrial 109 98 11 11.2%
Large Commercial & Industrial 144 140 4 2.9%
Public Authorities & Electric Railroads 55 29 26 89.7%
- -------------------------------------------------------------------------------------------------
308 267 41 15.4%
- -------------------------------------------------------------------------------------------------
Total Unbundled Revenues 489 358 131 36.6%
- -------------------------------------------------------------------------------------------------
Total Electric Retail Revenues 2,632 2,647 (15) (0.6%)
Wholesale and Miscellaneous Revenue (3) 153 149 4 2.7%
- -------------------------------------------------------------------------------------------------
Total Electric Revenue $ 2,785 $ 2,796 $ (11) (0.4%)
=================================================================================================
<FN>
(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.
</FN>
The changes in electric retail revenues for the six months ended June 30,
2003, as compared to the same period in 2002, are attributable to the following:
Variance
- ------------------------------------------------------------------------------------------------------------------
Customer choice $ (77)
Rate changes 75
Weather (54)
Volume 32
Other effects 9
- ------------------------------------------------------------------------------------------------------------------
Electric retail revenue $ (15)
==================================================================================================================
o Customer Choice. The decrease in revenues reflects customers in Illinois
electing to purchase energy from an ARES or the PPO.
For the six months ended June 30, 2003, the energy provided by
alternative suppliers was 7,095 GWhs or 17.2% as compared to 5,508 GWhs or
13.4% for the six months ended June 30, 2002.
As of June 30, 2003, the number of retail customers that had elected
to purchase energy from an ARES or the ComEd PPO was approximately 22,000
or 0.6% as compared to
97
22,700 or 0.6% as of June 30, 2002. MWhs delivered to such customers
increased from approximately 10.3 million for the six months ended June 30,
2002 to 12.6 million for the six months ended June 30, 2003, or from 25% to
30% of total year-to-date retail deliveries. During the second quarter
2003, approximately 2,500 customers temporarily came back to the ComEd PPO
as a result of an ARES no longer providing service in Illinois.
o Rate Changes. The increase in revenues attributable to rate changes
reflects the collection of additional CTC's in 2003 by ComEd of $146
million due to an increase in sales to customers choosing an ARES or the
ComEd PPO and an increase in CTC rates due to lower wholesale market price
of electricity, net of increased mitigation factors. Lower wholesale market
prices decreased revenue received under ComEd's PPO by $71 million.
o Weather. The weather impact for the six months ended June 30, 2003 was
unfavorable compared to the same period in 2002 as a result of cooler
spring weather in 2003. Cooling degree-days decreased 63% in the six months
ended June 30, 2003 compared to the same period in 2002 and were partially
offset by a 13% increase in heating degree days in the six months ended
June 30, 2003 compared to the same period in 2002.
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 PPO.
The $4 million increase in wholesale and miscellaneous revenue for the six
months ended June 30, 2003 was comparable to the six months ended June 30, 2002.
Purchased Power
Purchased power expense increased $19 million, or 2% for the six months
ended June 30, 2003. The increase in purchased power expense was primarily
attributable to an increase of $22 million due to higher volume, an increase of
$39 million due to pricing changes related to ComEd's PPA with Generation and an
increase of $31 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, partially offset by a $27 million decrease due to unfavorable
weather and a $49 million decrease as a result of customers choosing to purchase
energy from an ARES. The $31 million increase in purchased power expense related
to SFAS No. 143 is offset by lower regulatory asset amortization.
Operating and Maintenance
O&M expense increased $26 million, or 6%, for the six months ended June 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 4 of the Condensed Combined Notes to Consolidated Financial
Statements and an increase of $6 million in the reserve for MGP investigation
and remediation as a result of increased costs of a MGP site in Oak Park,
Illinois, partially offset by higher corporate allocations in 2002 due to
executive severance.
98
Depreciation and Amortization
Depreciation and amortization expense decreased $78 million, or 29%, for
the six months ended June 30, 2003 as follows:
Six Months Ended June 30,
-------------------------
2003 2002 Variance % Change
- ------------------------------------------------------------------------------------------------------------------
Depreciation expense $ 152 $ 183 $ (31) (16.9%)
Recoverable transition costs amortization 23 43 (20) (46.5%)
Other amortization expense 15 42 (27) (64.3%)
- -------------------------------------------------------------------------------------------------
Total depreciation and amortization $ 190 $ 268 $ (78) (29.1%)
=================================================================================================
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 six months ended June 30, 2003.
Recoverable transition costs amortization decreased in the six months ended
June 30, 2003 compared to the same period in 2002. The decrease is a result of
the extension of the rate freeze through 2006 that occurred in June 2002. ComEd
expects to fully recover its recoverable transition costs regulatory asset
balance of $153 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 is offset by
increased purchased power expense from Generation.
Taxes Other Than Income
Taxes other than income were comparable for the six months ended June 30,
2003 and 2002, primarily as a result of a $5 million refund in 2003 of Illinois
Electricity Distribution taxes offset by $6 million in Illinois Public Utility
Fund taxes that were not charged in 2002.
Interest Charges
Interest charges consist of interest expense and distributions on
mandatorily redeemable preferred securities. Interest charges decreased $37
million, or 15%, for the six months ended June 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
six months ended June 30, 2003 as compared to the six months ended June 30, 2002
and the annual retirement of $340 million in Transitional Trust Notes.
99
Other, Net
Other, net increased by $5 million for the six months ended June 30, 2003
as compared to the same period in 2002. The increase was primarily attributable
to the reversal of a $12 million reserve in 2003 for a potential plant
disallowance as the result of the Agreement as more fully described in Note 4 to
the Condensed Combined Notes to Consolidated Financial Statements.
Income Taxes
The effective income tax rate was 39.9% for the six months ended June 30,
2003, compared to 39.6% for the six months ended June 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.
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, 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 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.
In the second quarter of 2003, ComEd progressed in its plans to implement
the new business model referred to as The Exelon Way. The Exelon Way is focused
on improving operating cash flows while meeting service and financial
commitments through improved integration of operations and consolidation of
support functions. As part of the implementation of The Exelon Way, ComEd
anticipates incurring expenses associated with the rationalization of certain
business functions and employee separation costs. These expenses may be
significant and are expected to be incurred during the remaining half of 2003
through 2005. However, these costs cannot be reasonably estimated at this time.
100
Cash Flows from Operating Activities
Cash flows provided by operations were $430 million for the six months
ended June 30, 2003 compared to $740 million for the six months ended June 30,
2002. The decrease in cash flows in 2003 was primarily attributable to a $155
million decrease in working capital as a result of the paydown of intercompany
payables to affiliates and other outstanding liabilities, a decrease of $87
million for pension and non-pension postretirement benefits obligation, a
decrease in depreciation and amortization of $78 million partially offset by an
increase in net income of $41 million. ComEd's future cash flows will depend
upon the ability to achieve cost savings in operations and the impact of the
economy, weather, and customer choice 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 $506 million for the six
months ended June 30, 2003 compared to $352 million for the six months ended
June 30, 2002. The increase in cash flows used in investing activities in 2003
was primarily attributable to the $165 million loaned to Generation as part of
the 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.
Cash Flows from Financing Activities
Cash flows from financing activities were $94 million for the six months
ended June 30, 2003 as compared to cash flows used in financing of $57 million
for the six months ended June 30, 2002. Cash flows from financing activities
were primarily attributable to debt issuances partially offset by retirements
and redemptions and payments of dividends to Exelon. The increase in cash flows
from financing activities is primarily attributable to increased debt and
preferred securities issuances of $634 million partially offset by increased
debt and preferred securities redemptions of $452 million and increased interest
rate swap settlement payments of $41 million. See Note 9 of the Condensed
Combined Notes to Consolidated Financial Statements for further discussion of
ComEd's debt and preferred securities financing activities. ComEd paid a $211
million dividend to Exelon during the six months ended June 30, 2003 compared to
a $235 million dividend for the six months ended June 30, 2002.
101
Credit Issues
ComEd meets its short-term liquidity requirements primarily through the
issuance of commercial paper and borrowings from Exelon's intercompany money
pool. 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 June 30, 2003, ComEd's sublimit was $100 million. The credit facility is used
principally to support ComEd's commercial paper program. At June 30, 2003, ComEd
had no commercial paper outstanding. For the six months ended June 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 June 30, 2003. At June 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's subsidiary, Commonwealth Edison Company of Indiana, Inc., PECO,
Generation and BSC may participate in the money pool as lenders and borrowers,
and Exelon Corporate and ComEd as lenders. Funding of, and borrowings from, the
money pool are predicated on whether such funding results in mutual economic
benefits to each of the participants, although Exelon is not permitted to be a
net borrower from the money pool. 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 six
months ended June 30, 2003, ComEd had various loans to Generation under the
money pool. The maximum amount of outstanding loans at any time during 2003 was
$342 million. As of June 30, 2003, Generation owed ComEd $165 million on these
loans. For the six months ended June 30, 2003, ComEd earned $1 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 can only pay dividends from retained or current
earnings. 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
102
transitional trust notes). At June 30, 2003, ComEd had retained earnings of $767
million and its common equity ratio was 46%. Long-term debt included $1.8
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 June 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 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
103
$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. 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, ComEd would have positive
net cash flows related to these agreements if any fees are paid to the tax
consultant. 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 9 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 8 of the Condensed Combined Notes to Consolidated Financial
Statements for commercial commitments tables 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.
104
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 June 30, 2003 Compared to Three Months Ended June 30, 2002
Significant Operating Trends - PECO
Three Months Ended June 30,
---------------------------
2003 2002 Variance % Change
- -------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES $ 961 $ 995 $ (34) (3.4%)
OPERATING EXPENSES
Purchased power 386 405 (19) (4.7%)
Fuel 67 53 14 26.4%
Operating and maintenance 121 131 (10) (7.6%)
Depreciation and amortization 116 109 7 6.4%
Taxes other than income 47 63 (16) (25.4%)
- ------------------------------------------------------------------------------------------------------
Total operating expenses 737 761 (24) (3.2%)
- ------------------------------------------------------------------------------------------------------
OPERATING INCOME 224 234 (10) (4.3%)
- ------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest expense (83) (92) 9 (9.8%)
Distributions on mandatorily redeemable preferred securities (2) (2) -- --
Other, net 1 2 (1) (50.0%)
- ------------------------------------------------------------------------------------------------------
Total other income and deductions (84) (92) 8 (8.7%)
- ------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 140 142 (2) (1.4%)
INCOME TAXES 52 49 3 6.1%
- ------------------------------------------------------------------------------------------------------
NET INCOME 88 93 (5) (5.4%)
Preferred stock dividends (2) (2) -- --
- ------------------------------------------------------------------------------------------------------
NET INCOME ON COMMON STOCK $ 86 $ 91 $ (5) (5.5%)
======================================================================================================
105
Net Income
Net income on common stock decreased $5 million, or 6% for the three months
ended June 30, 2003 as compared to the same period in 2002. The decrease was a
result of lower sales volume and unfavorable weather conditions, partially
offset by lower operating and maintenance expenses, taxes other than income and
interest expense on debt.
Operating Revenue
PECO's electric sales statistics are as follows:
Three Months Ended June 30,
---------------------------
Retail Deliveries - (in GWhs) 2003 2002 Variance % Change
- ------------------------------------------------------------------------------------------------------------------
Bundled Deliveries (1)
Residential 2,274 2,115 159 7.5%
Small Commercial & Industrial 1,532 1,881 (349) (18.6%)
Large Commercial & Industrial 3,695 3,927 (232) (5.9%)
Public Authorities & Electric Railroads 222 200 22 11.0%
- ------------------------------------------------------------------------------------------------
7,723 8,123 (400) (4.9%)
- ------------------------------------------------------------------------------------------------
Unbundled Deliveries (2)
Residential 186 557 (371) (66.6%)
Small Commercial & Industrial 323 2 321 n.m.
Large Commercial & Industrial 192 13 179 n.m.
Public Authorities & Electric Railroads (3) -- -- -- --
- ------------------------------------------------------------------------------------------------
701 572 129 22.6%
- ------------------------------------------------------------------------------------------------
Total Retail Deliveries 8,424 8,695 (271) (3.1%)
================================================================================================
<FN>
(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.
n.m. - not meaningful
</FN>
Three Months Ended June 30,
---------------------------
Electric Revenue 2003 2002 Variance % Change
- ------------------------------------------------------------------------------------------------------------------
Bundled Revenue (1)
Residential $ 297 $ 278 $ 19 6.8%
Small Commercial & Industrial 180 224 (44) (19.6%)
Large Commercial & Industrial 267 288 (21) (7.3%)
Public Authorities & Electric Railroads 21 19 2 10.5%
- -------------------------------------------------------------------------------------------------
765 809 (44) (5.4%)
- -------------------------------------------------------------------------------------------------
Unbundled Revenue (2)
Residential 14 42 (28) (66.7%)
Small Commercial & Industrial 17 -- 17 100.0%
Large Commercial & Industrial 5 1 4 n.m.
Public Authorities & Electric Railroads (3) -- -- -- --
- -------------------------------------------------------------------------------------------------
36 43 (7) (16.3%)
- -------------------------------------------------------------------------------------------------
Total Electric Retail Revenues 801 852 (51) (6.0%)
Wholesale and Miscellaneous Revenue (4) 50 59 (9) (15.3%)
- -------------------------------------------------------------------------------------------------
Total Electric Revenue $ 851 $ 911 $ (60) (6.6%)
=================================================================================================
<FN>
(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.
106
(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.
</FN>
The changes in electric retail revenues for the three months ended June 30,
2003, as compared to the same period in 2002, are as follows:
Variance
- -------------------------------------------------------------------------------------------------------------------
Weather $ (21)
Customer choice (8)
Volume (7)
Other effects (15)
- -------------------------------------------------------------------------------------------------------------------
Retail revenue $ (51)
===================================================================================================================
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 spring weather during the quarter. Cooling
degree-days decreased 40% and heating degree-days increased 38% for the
three months ended June 30, 2003 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 three months ended June 30, 2003, the energy provided by
alternative suppliers was 701 GWhs or 8.3% as compared to 572 GWhs or 6.6%
for the three months ended June 30, 2002. As of June 30, 2003, the number
of customers served by alternative suppliers was 310,821 or 20.3% as
compared to 308,866 or 20.2% as of June 30, 2002. The decrease in retail
deliveries is primarily a result of customers selecting an alternative
electric generation supplier.
The PUC's 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
107
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. The auction for the second phase of the residential
customer MST plan is scheduled for September 2003 and the selected
customers would be transferred effective December 2003. Any customer
transferred would 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.
o Volume. Exclusive of weather impacts, lower delivery volume affected PECO's
revenue by $7 million compared to the same period in 2002 primarily related
to decreases in usage by the residential and large commercial and
industrial customer classes partially offset by an increase in usage by the
small commercial and industrial class.
o Other Effects. The decrease in revenues from other effects is attributable
to a decrease of $15 million in the average price mix related to all
customer classes as compared to the same period in 2002.
PECO's gas sales statistics for the three months ended June 30,
2003 as compared to the same period in 2002 are as follows:
Three Months Ended June 30,
---------------------------
2003 2002 Variance % Change
- ------------------------------------------------------------------------------------------------------------------------
Deliveries in mmcf 15,001 14,286 715 5.0%
Revenue $ 110 $ 84 $ 26 31.0%
- ------------------------------------------------------------------------------------------------------------
The changes in gas revenue for the three months ended June 30, 2003, as
compared to the same period in 2002, are as follows:
Variance
- -----------------------------------------------------------------------------------------------------------------------
Weather $ 14
Rate changes 10
Volume 2
- -----------------------------------------------------------------------------------------------------------------------
Gas revenue $ 26
=======================================================================================================================
o Weather. The demand for gas is impacted by weather conditions. Very cold
weather in non-summer months is referred to as "favorable weather
conditions," because these weather conditions result in increased sales of
gas. Conversely, mild weather reduces demand. The weather impact was
favorable compared to the prior year as a result of cooler spring weather
during the quarter. Heating degree-days increased 38% in the three months
ended June 30, 2003 compared to the same period in 2002.
o Rate Changes. The favorable variance in rate changes is attributable to a
15% increase and a 7% increase 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 June 30, 2003 was 22%
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.
108
o Volume. Exclusive of weather impacts, delivery volume was consistent in the
three months ended June 30, 2003 compared to the same period in 2002 with
increased retail sales, partially offset by lower transportation volumes.
Deliveries to customers, excluding transportation and the effects of
weather, increased 4% in the three months ended June 30, 2003 compared to
the same period in 2002.
Purchased Power
Purchased power expense for the three months ended June 30, 2003 decreased
$19 million, or 5%, as compared to the same period in 2002. The decrease in
purchased power expense was primarily attributable to $12 million as a result of
unfavorable weather conditions, $7 million related to lower PJM ancillary
charges and $5 million from customers in Pennsylvania selecting an alternative
electric generation supplier.
Fuel Fuel expense for the three months ended June 30, 2003 increased $14
million, or 26%, as compared to the same period in 2002. This increase was
primarily attributable to $11 million attributable to higher gas prices and $10
million as a result of favorable weather conditions partially offset by $8
million related to lower wholesale sales of gas.
Operating and Maintenance
O&M expense for the three months ended June 30, 2003 decreased $10 million,
or 8%, as compared to the same period in 2002. The decrease in O&M expense was
primarily attributable to $7 million of lower expense related to the allowance
for the uncollectible accounts, $7 million of lower costs associated with the
initial implementation of automated meter reading services, partially offset by
$2 million related to higher corporate allocations and $2 million of additional
severance costs.
Depreciation and Amortization
Depreciation and amortization expense for the three months ended June 30,
2003 increased $7 million, or 6%, as compared to the same period in 2002 as
follows:
Three Months Ended June 30,
---------------------------
2003 2002 Variance % Change
- -------------------------------------------------------------------------------------------------------------------
Competitive transition charge amortization $ 79 $ 72 $ 7 9.7%
Depreciation expense 33 32 1 3.1%
Other amortization expense 4 5 (1) (20.0%)
- --------------------------------------------------------------------------------------------------
Total depreciation and amortization $ 116 $ 109 $ 7 6.4%
==================================================================================================
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 June 30, 2003 decreased
$16 million, or 25%, as compared to the same period in 2002. The decrease was
primarily attributable to $12 million related to the reversal of a use tax
accrual resulting from an audit settlement and $2 million of lower gross
receipts tax related to lower revenues.
109
Interest Charges
Interest charges consist of interest expense and distributions on
mandatorily redeemable preferred securities. Interest charges decreased $9
million, or 10%, in the three months ended June 30, 2003 as compared to the same
period in 2002. The decrease was primarily attributable to lower interest
expense on long-term debt of $9 million as a result of scheduled principal
payments and refinancing of existing debt at lower interest rates.
Other, Net
Other, net decreased income by $1 million in the three months ended June
30, 2003 as compared to the same period in 2002. The decrease was attributable
to lower interest income of $1 million.
Income Taxes
The effective tax rate was 37.1% for the three months ended June 30, 2003
as compared to 34.5% 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 June 30, 2003 were
consistent as compared to the same period in 2002.
110
Six Months Ended June 30, 2003 Compared to Six Months Ended June 30, 2002
Significant Operating Trends - PECO
Six Months Ended June 30,
-------------------------
2003 2002 Variance % Change
- ------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES $ 2,178 $ 2,015 $ 163 8.1%
OPERATING EXPENSES
Purchased power 808 756 52 6.9%
Fuel 257 188 69 36.7%
Operating and maintenance 261 267 (6) (2.2%)
Depreciation and amortization 236 221 15 6.8%
Taxes other than income 110 122 (12) (9.8%)
- -------------------------------------------------------------------------------------------------------
Total operating expenses 1,672 1,554 118 7.6%
- -------------------------------------------------------------------------------------------------------
OPERATING INCOME 506 461 45 9.8%
- -------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest expense (168) (187) 19 (10.2%)
Distributions on mandatorily redeemable preferred securities (5) (5) -- --
Other, net 10 2 8 n.m.
- -------------------------------------------------------------------------------------------------------
Total other income and deductions (163) (190) 27 (14.2%)
- -------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 343 271 72 26.6%
INCOME TAXES 119 90 29 32.2%
- -------------------------------------------------------------------------------------------------------
NET INCOME 224 181 43 23.8%
Preferred stock dividends (3) (4) 1 (25.0%)
- -------------------------------------------------------------------------------------------------------
NET INCOME ON COMMON STOCK $ 221 $ 177 $ 44 24.9%
=======================================================================================================
<FN>
n.m. - not meaningful
</FN>
Net Income
Net income on common stock increased $44 million, or 25% for the six months
ended June 30, 2003 as compared to the same period in 2002. The increase was a
result of higher sales volume, favorable weather conditions and lower interest
expense on debt, partially offset by increased income taxes and depreciation and
amortization expense.
111
Operating Revenue
PECO's electric sales statistics are as follows:
Six Months Ended June 30,
-------------------------
Retail Deliveries (in GWhs) 2003 2002 Variance % Change
- ------------------------------------------------------------------------------------------------------------------
Bundled Deliveries (1)
Residential 5,389 4,171 1,218 29.2%
Small Commercial & Industrial 3,312 3,638 (326) (9.0%)
Large Commercial & Industrial 7,177 7,278 (101) (1.4%)
Public Authorities & Electric Railroads 475 393 82 20.9%
- -------------------------------------------------------------------------------------------------
16,353 15,480 873 5.6%
- -------------------------------------------------------------------------------------------------
Unbundled Deliveries (2)
Residential 450 1,348 (898) (66.6%)
Small Commercial & Industrial 525 99 426 n.m.
Large Commercial & Industrial 402 116 286 n.m.
Public Authorities & Electric Railroads (3) -- -- -- --
- -------------------------------------------------------------------------------------------------
1,377 1,563 (186) (11.9%)
- -------------------------------------------------------------------------------------------------
Total Retail Deliveries 17,730 17,043 687 4.0%
=================================================================================================
<FN>
(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.
n.m. - not meaningful
</FN>
Six Months Ended June 30,
-------------------------
Electric Revenue 2003 2002 Variance % Change
- -------------------------------------------------------------------------------------------------------------------
Bundled Revenue (1)
Residential $ 656 $ 522 $ 134 25.7%
Small Commercial & Industrial 374 413 (39) (9.4%)
Large Commercial & Industrial 534 532 2 0.4%
Public Authorities & Electric Railroads 42 37 5 13.5%
- --------------------------------------------------------------------------------------------------
1,606 1,504 102 6.8%
- --------------------------------------------------------------------------------------------------
Unbundled Revenue (2)
Residential 31 96 (65) (67.7%)
Small Commercial & Industrial 27 5 22 n.m.
Large Commercial & Industrial 11 3 8 n.m.
Public Authorities & Electric Railroads (3) -- -- -- --
- --------------------------------------------------------------------------------------------------
69 104 (35) (33.7%)
- --------------------------------------------------------------------------------------------------
Total Electric Retail Revenues 1,675 1,608 67 4.2%
Wholesale and Miscellaneous Revenue (4) 104 114 (10) (8.8%)
- --------------------------------------------------------------------------------------------------
Total Electric Revenue $ 1,779 $ 1,722 $ 57 3.3%
==================================================================================================
<FN>
(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.
</FN>
112
The changes in electric retail revenues for the six months ended June 30,
2003, as compared to the same period in 2002, are as follows:
Variance
- ------------------------------------------------------------------------------------------------------------------------
Volume $ 36
Weather 26
Customer choice 11
Other effects (6)
- ------------------------------------------------------------------------------------------------------------------------
Retail revenue $ 67
========================================================================================================================
o Volume. Exclusive of weather impacts, higher delivery volume affected
PECO's revenue by $36 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 spring weather.
Heating degree-days increased 34% and cooling degree-days decreased 40% for
the six months ended June 30, 2003 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 six months ended June 30, 2003, the energy provided by
alternative suppliers was 1,377 GWhs or 7.8% as compared to 1,563 GWhs or
9.2% for the six months ended June 30, 2002. As of June 30, 2003, the
number of customers served by alternative suppliers was 310,821 or 20.3% as
compared to 308,866 or 20.2% as of June 30, 2002. The increase in retail
deliveries is primarily a result of customers selecting or returning to
PECO as their electric generation supplier.
o Other Effects. The decrease in revenues from other effects is attributable
to a decrease of $6 million in the average price mix related to all
customer classes as compared to the same period in 2002.
113
PECO's gas sales statistics for the six months ended June 30, 2003 as
compared to the same period in 2002 are as follows:
Six Months Ended June 30,
-------------------------
2003 2002 Variance % Change
- -------------------------------------------------------------------------------------------------------------------
Deliveries in mmcf 54,627 45,643 8,984 19.7%
Revenue $ 399 $ 293 $ 106 36.2%
- -------------------------------------------------------------------------------------------------------
The changes in gas revenue for the six months ended June 30, 2003, as
compared to the same period in 2002, are as follows:
Variance
- ------------------------------------------------------------------------------------------------------------------
Weather $ 73
Volume 17
Rate changes 13
Other 3
- ------------------------------------------------------------------------------------------------------------------
Gas revenue $ 106
==================================================================================================================
o Weather. The weather impact was favorable compared to the prior year as a
result of colder winter weather. Heating degree-days increased 34% in the
six months ended June 30, 2003 compared to the same period in 2002.
o Volume. Exclusive of weather impacts, higher delivery volume increased
revenue in the six months ended June 30, 2003 compared to the same period
in 2002 resulting from increased retail sales partially offset by lower
transportation volumes. Deliveries to customers, excluding transportation
and the effects of weather, increased 6% in the six months ended June 30,
2003 compared to the same period in 2002.
o Rate Changes. The favorable variance in rates is attributable to a 15%
increase and a 7% increase 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 six months ended June 30, 2003 was 13%
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.
Purchased Power
Purchased power expense for the six months ended June 30, 2003 increased
$52 million, or 7%, as compared to the same period in 2002. The increase in
purchased power expense was primarily attributable to $21 million as a result of
higher electric delivery volume, $11 million from customers in Pennsylvania
selecting or returning to PECO as their electric generation supplier, $10
million as a result of favorable weather conditions and $10 million related to
higher PJM ancillary charges.
114
Fuel
Fuel expense for the six months ended June 30, 2003 increased $69 million,
or 40%, as compared to the same period in 2002. This increase was primarily
attributable to $50 million as a result of favorable weather conditions, $14
million from higher gas prices and $8 million attributable to higher delivery
volumes.
Operating and Maintenance
O&M expense for the six months ended June 30, 2003 decreased $6 million, or
2%, as compared to the same period in 2002. The decrease in O&M expense was
primarily attributable to $13 million of lower costs associated with the initial
implementation of automated meter reading services, $9 million of lower expense
related to the allowance for uncollectible accounts and $5 million related to
lower corporate allocations partially offset by $3 million of additional
employee benefits costs, $4 million of incremental storm costs in 2003, $2
million of additional severance costs and $5 million of additional miscellaneous
other net positive impacts.
Depreciation and Amortization
Depreciation and amortization expense for the six months ended June 30,
2003 increased $15 million, or 7%, as compared to the same period in 2002 as
follows:
Six Months Ended June 30,
-------------------------
2003 2002 Variance % Change
- ------------------------------------------------------------------------------------------------------------------
Competitive transition charge amortization $ 161 $ 146 $ 15 10.3%
Depreciation expense 66 63 3 4.8%
Other amortization expense 9 12 (3) (25.0%)
- --------------------------------------------------------------------------------------------------
Total depreciation and amortization $ 236 $ 221 $ 15 6.8%
==================================================================================================
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 six months ended June 30, 2003 decreased
$12 million, or 10%, as compared to the same period in 2002. The decrease was
primarily attributable to $12 million related to the reversal of the use tax
accrual resulting from an audit settlement and a $3 million decrease in real
estate taxes partially offset by $5 million of additional gross receipts tax
related to additional revenues.
Interest Charges
Interest charges consist of interest expense and distributions on
mandatorily redeemable preferred securities. Interest charges decreased $19
million, or 10%, in the six months ended June 30, 2003 as compared to the same
period in 2002. The decrease was primarily attributable to lower interest
expense on long-term debt of $19 million as a result of scheduled principal
payments and refinancing of existing debt at lower interest rates.
115
Other, Net
Other, net increased by $8 million in the six months ended June 30, 2003 as
compared to the same period in 2002. The increase was primarily attributable to
higher interest income of $4 million and the favorable settlement of a customer
contract of $3 million.
Income Taxes
The effective tax rate was 34.6% for the six months ended June 30, 2003 as
compared to 33.2% 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 six months ended June 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 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.
In the second quarter of 2003, PECO progressed in its plans to implement
the new business model referred to as The Exelon Way. The Exelon Way is focused
on improving operating cash flows while meeting service and financial
commitments through improved integration of operations and consolidation of
support functions. As part of the implementation of The Exelon Way, PECO
anticipates incurring expenses associated with the rationalization of certain
business functions and employee separation costs. These expenses may be
significant and are expected to be incurred during the remaining half of 2003
through 2005. However, these
116
costs cannot be reasonably estimated at this time.
Cash Flows from Operating Activities
Cash flows provided by operations for the six months ended June 30, 2003
and 2002 were $425 million and $468 million, respectively. The decrease in cash
flows was primarily attributable to a $73 million change in deferred energy
costs and a $4 million decrease in working capital, partially offset by a $43
million increase in net income. 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 and customer choice 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 six months ended June 30,
2003 and 2002 were $126 million and $122 million, respectively. The increase in
cash flows used in investing activities was primarily attributable to an
increase in other investing activities.
PECO's projected capital expenditures for 2003 are $265 million.
Approximately 60% of the budgeted 2003 expenditures are for capital additions
and upgrades to existing facilities and the remainder are for capital additions
to support customer load 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.
Cash Flows from Financing Activities
Cash flows used in financing activities for the six months ended June 30,
2003 and 2002 were $301 million and $306 million, respectively. Cash flows used
in financing activities are primarily attributable to debt service and payment
of dividends to Exelon. The decrease in cash flows used in financing activities
is primarily attributable to additional issuances of long-term debt of $550
million, partially offset by increased debt and preferred securities redemptions
of $485 million. See Note 9 of the Condensed Combined Notes to Consolidated
Financial Statements for further discussion of PECO's debt financing activities.
For the six months ended June 30, 2003, PECO paid Exelon $165 million in common
stock dividends compared to $170 million for the same period in 2002.
117
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 June 30, 2003, PECO's sublimit was $400 million. The credit facility is used
by PECO principally to support its commercial paper program. At June 30, 2003,
PECO's Consolidated Balance Sheet reflects $170 million in commercial paper
outstanding. For the six months ended June 30, 2003, the average interest rate
on notes payable was approximately 1.31%.
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 June 30, 2003. At June 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's
subsidiary, Commonwealth Edison Company of Indiana, Inc., PECO, Generation and
BSC may participate in the money pool as lenders and borrowers, and Exelon
Corporate and ComEd as lenders. Funding of, and borrowings from, the money pool
are predicated on whether such funding results in mutual economic benefits to
each of the participants, although Exelon is not permitted to be a net borrower
from the money pool. 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 by PECO during the six months ended
June 30, 2003.
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 can pay dividends only from retained or current earnings.
At June 30, 2003, PECO had retained earnings of $455 million.
Long-term debt included $4.1 billion of transition bonds.
118
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 June 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. 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, PECO would have positive
net cash flows related to these agreements if any fees are paid to the tax
consultant. 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 9 of the Condensed Combined Notes to Consolidated Financial
Statements for further discussion of material changes in PECO's debt
obligations from those set forth in the 2002 Form 10-K.
o See Note 8 of the Condensed Combined Notes to Consolidated Financial
Statements for commercial commitments tables 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.
119
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 June 30, 2003 Compared to Three Months Ended June 30, 2002
Significant Operating Trends - Generation
Three Months Ended June 30,
---------------------------
2003 2002 Variance % Change
- -------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES $ 1,886 $ 1,559 $ 327 21.0%
OPERATING EXPENSES
Purchased power 800 705 95 13.5%
Fuel 348 224 124 55.4%
Operating and maintenance 451 411 40 9.7%
Depreciation and amortization 46 65 (19) (29.2%)
Taxes other than income 40 41 (1) (2.4%)
- -------------------------------------------------------------------------------------------------------
Total operating expenses 1,685 1,446 239 16.5%
- -------------------------------------------------------------------------------------------------------
OPERATING INCOME 201 113 88 77.9%
- -------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest expense (20) (11) (9) (81.8%)
Equity in earnings of unconsolidated affiliates 18 9 9 100.0%
Other, net 34 24 10 41.7%
- -------------------------------------------------------------------------------------------------------
Total other income and deductions 32 22 10 45.5%
- -------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 233 135 98 72.6%
INCOME TAXES 91 51 40 78.4%
- -------------------------------------------------------------------------------------------------------
NET INCOME $ 142 $ 84 $ 58 69.0%
=======================================================================================================
Net Income
Generation's net income increased by $58 million, or 69%, for the three
months ended June 30, 2003 compared to the same period in 2002 primarily due to
a $328 million increase in market electric sales. The increase was partially
offset by an increase in fuel and purchased power expense related to the
increase in market sales, and a $74 million decrease in electric sales to other
Exelon businesses.
Operating Revenues
Revenues increased by $327 million, or 21% for the three months ended June
30, 2003 compared to the same period in 2002. For the three months ended June
30, 2003 and 2002, Generation's sales were as follows:
120
Three Months Ended June 30,
---------------------------
Revenue (in millions) 2003 2002 Variance % Change
- -------------------------------------------------------------------------------------------------------------------
Energy Delivery and Exelon Energy Company $ 877 $ 951 $ (74) (7.8%)
Market Sales 960 632 328 51.9%
- ------------------------------------------------------------------------------------------------------
Total Energy Sales Revenue 1,837 1,583 254 16.0%
Trading Portfolio (1) (16) 15 93.8%
Other Revenue 50 (8) 58 n.m.
- ------------------------------------------------------------------------------------------------------
Total Revenue $ 1,886 $ 1,559 $ 327 21.0%
======================================================================================================
n.m. - not meaningful
Three Months Ended June 30,
---------------------------
Sales (in GWhs) 2003 2002 Variance % Change
- -------------------------------------------------------------------------------------------------------------------
Energy Delivery and Exelon Energy Company 26,869 29,649 (2,780) (9.4%)
Market Sales 27,449 20,589 6,860 33.3%
- ------------------------------------------------------------------------------------------------------
Total Sales 54,318 50,238 4,080 8.1%
======================================================================================================
Trading volume of 7,919 GWhs and 8,566 GWhs for the three months ended June
30, 2003 and 2002, respectively, is 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 June 30, 2003 and 2002 is as follows:
Three Months Ended June 30,
---------------------------
($/MWh) 2003 2002 % Change
- -------------------------------------------------------------------------------------------------------------------
Average Revenue
Energy Delivery and Exelon Energy Company $ 32.67 $ 32.06 1.9%
Market Sales 34.98 30.69 14.0%
Total - excluding the trading portfolio 33.83 31.50 7.4%
- -------------------------------------------------------------------------------------------------------------------
Energy Delivery and Exelon Energy Company. Sales to Energy Delivery
decreased by $57 million primarily due to unfavorable weather in ComEd and
PECO's service territories during the three months ended June 30, 2003 compared
to the same period in 2002. Generation's average revenue per MWh was affected by
increased prices per MWh for supply agreements with ComEd and PECO. Sales to
Exelon Energy Company decreased $17 million for the three months ended June 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 $328 million resulted primarily from
increased production from generating assets acquired during 2002, as well as
lower load requirements to affiliates and higher wholesale market prices, which
were primarily attributable to increased fossil fuel prices.
Trading Revenues. Trading activity decreased revenue by $1 million during
the three months ended June 30, 2003 compared to $16 million for the same period
in 2002 due to reduced trading volume.
Other Revenues. Other revenues in the three months ended June 30, 2003
included $21 million from market gas sales, and $18 million from ComEd related
to nuclear decommissioning cost recoveries, and $7 million of cost recoveries
from PECO.
121
Purchased Power and Fuel
Generation's supply source of its sales and average supply costs are
summarized below:
Three Months Ended June 30,
---------------------------
Supply of Sales (in GWhs) 2003 2002 Variance % Change
- -------------------------------------------------------------------------------------------------------------------
Purchases - non-trading portfolio (1) 19,344 17,978 1,366 7.6%
Nuclear Generation (2) 29,619 28,776 843 2.9%
Fossil and Hydro Generation 5,355 3,484 1,871 53.7%
- -----------------------------------------------------------------------------------------------------
Total Supply 54,318 50,238 4,080 8.1%
=====================================================================================================
<FN>
(1) Including purchased power agreements with AmerGen.
(2) Excluding AmerGen.
</FN>
Three Months Ended June 30,
---------------------------
($/MWh) 2003 2002 % Change
- ------------------------------------------------------------------------------------------------------------------
Average Supply Cost (1) - excluding trading portfolio $ 20.71 $ 18.79 10.2%
- ------------------------------------------------------------------------------------------------------------------
<FN>
(1) Average supply cost includes purchased power and fuel costs.
</FN>
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
1,498 GWhs, and
o increased quantity of purchased power at higher prices to serve expected
affiliate load obligations. In addition, Generation entered into a new
purchase power agreement with AmerGen in the second quarter of 2003. As a
result, 1,258 GWhs were purchased from Oyster Creek nuclear facility in the
second quarter of 2003.
Purchased power increased $95 million, or 14%, for the three months ended
June 30, 2003 compared to the same period in 2002 due to a $125 million increase
related to higher market prices and the delay of Exelon New England commercial
operations commencement dates. The increase in purchased power was partially
offset by a $32 million gain on mark-to-market hedging activity for the three
months ended June 30, 2003 compared to a $4 million gain in the same period in
2002.
Fuel expense increased $124 million, or 55%, for the three months ended
June 30, 2003 compared to the same period in 2002, as summarized below:
Three Months Ended June 30,
---------------------------
(in millions) 2003 2002 Variance % Change
- -------------------------------------------------------------------------------------------------------------------
Nuclear Generation (1) $ 132 $ 120 $ 12 10.0%
Fossil and Hydro Generation 216 104 112 107.7%
- -----------------------------------------------------------------------------------------------------
Total $ 348 $ 224 $ 124 55.4%
=====================================================================================================
<FN>
(1) Excluding AmerGen
</FN>
This increase is primarily due to a $92 million increase in fossil fuel
generation resulting from the acquisition of plant assets in 2002. In addition,
fuel expense increased $10 million due to additional nuclear fuel amortization
resulting from under performing fuel at the Quad Cities Unit 1, which was
completely replaced in May 2003.
122
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, generation reductions to make repairs and mid-cycle outages. For
example, in the second quarter of 2003, the Quad Cities Unit 1 required a
significant repair and is unable to operate above an 85% capacity factor until
the Nuclear Regulatory Commission (NRC) inspects and approves the maintenance
work. 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 anticipates NRC
approval of the maintenance work and to return the unit to its normal operating
capacity in the near future.
Operating and Maintenance
O&M expense increased $40 million, or 10%, for the three months ended June
30, 2003 compared to the same period in 2002. The increase in O&M expense was
primarily attributable to $46 million of accretion expense related to SFAS No.
143, which includes $39 million of accretion of the asset retirement obligation
and $7 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, $8 million of
additional employee payroll and benefits costs, and $19 million of additional
expenses due to asset acquisitions made after the second 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. This increase was
partially offset by $21 million of lower nuclear refueling outage costs,
including $17 million for Generation's ownership in Salem, which is operated by
the co-owner, and other nonrecurring charges in 2002. For a further discussion
of SFAS No. 143 see Note 2 of the Condensed Combined Notes to Consolidated
Financial Statements.
Three Months Ended June 30,
---------------------------
2003 2002
- ---------------------------------------------------------------------------------------------------------------------
Nuclear fleet capacity factor (1) 94.0% 92.1%
Nuclear fleet production cost per MWh (1) $ 12.08 $ 12.54
Average purchased power cost for wholesale operations per MWh $ 43.15 $ 39.96
- ---------------------------------------------------------------------------------------------------------------------
<FN>
(1) Including AmerGen and excluding Salem.
</FN>
The higher nuclear capacity factor and decreased nuclear production costs
are primarily due to 20 fewer planned refueling outage days, resulting in a $4
million decrease in outage costs, in the three months ended June 30, 2003 as
compared to the same period in 2002. Additionally, the three months ended June
30, 2003 included nine unplanned outages compared to eight unplanned outages
during the same period in 2002.
Depreciation and Amortization
Depreciation and amortization expense decreased $19 million, or 29%, for
the three months ended June 30, 2003 compared to the same period in 2002. The
decrease was primarily attributable to a $31 million reduction in
decommissioning expense 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, partially offset by $4 million of
additional depreciation expense on capital additions placed in service after the
second quarter of 2002, $7 million related to plant acquisitions made after the
second quarter of 2002, and $1
123
million of depreciation for the ARC asset related to SFAS No. 143. 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 $1 million, or 2%, for the three months
ended June 30, 2003 compared to the same period in 2002 primarily due to a $1
million decrease in property taxes.
Interest Expense
Interest expense increased $9 million, or 82%, for the three months ended
June 30, 2003 compared to the same period in 2002. The increase was primarily
due to a $7 million decrease in capitalized interest, $2 million of interest
expense on the $536 million note payable issued to Sithe in November 2002 and $2
million of interest expense on the long-term debt obtained as a part of the
Sithe New England asset acquisition. 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.
Equity in Earnings of Unconsolidated Affiliates
Equity in earnings of unconsolidated affiliates increased $9 million, or
100%, for the three months ended June 30, 2003 compared to the same period in
2002. The increase was due to a $18 million increase in Generation's equity
earnings of AmerGen. AmerGen's earnings were primarily affected by increased
power sales, reduced outage costs, and favorable impacts of SFAS 143. The
increase was partially offset by a $9 million decrease in Generation's equity
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 for the period at Sithe.
Other, Net
Other, net increased $10 million, or 42%, for the three months ended June
30, 2003 compared to the same period in 2002. The increase is primarily due to
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
operating and maintenance expense.
Income Taxes
The effective income tax rate was 39.2% for the three months ended June 30,
2003 compared to 37.7% for the same period in 2002. This increase was primarily
attributable to an increase in taxes related to the nuclear decommissioning
trust funds.
124
Six Months Ended June 30, 2003 Compared to Six Months Ended June 30, 2002
Significant Operating Trends - Generation
Six Months Ended June 30,
-------------------------
2003 2002 Variance % Change
- -------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES $ 3,765 $ 3,020 $ 745 24.7%
OPERATING EXPENSES
Purchased power 1,642 1,323 319 24.1%
Fuel 706 433 273 63.0%
Operating and maintenance 943 844 99 11.7%
Depreciation and amortization 91 128 (37) (28.9%)
Taxes other than income 88 90 (2) (2.2%)
- ------------------------------------------------------------------------------------------------------
Total operating expenses 3,470 2,818 652 23.1%
- ------------------------------------------------------------------------------------------------------
OPERATING INCOME 295 202 93 46.0%
- ------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS
Interest expense (38) (28) (10) (35.7%)
Equity in earnings of unconsolidated affiliates 37 32 5 15.6%
Other, net (134) 40 (174) n.m.
- ------------------------------------------------------------------------------------------------------
Total other income and deductions (135) 44 (179) n.m.
- ------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES AND CUMULATIVE
EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES 160 246 (86) (35.0%)
INCOME TAXES 71 96 (25) (26.0%)
- ------------------------------------------------------------------------------------------------------
INCOME BEFORE CUMULATIVE EFFECT OF CHANGES IN
ACCOUNTING PRINCIPLES 89 150 (61) (40.7%)
CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING
PRINCIPLES, NET OF INCOME TAXES 108 13 95 n.m.
- ------------------------------------------------------------------------------------------------------
NET INCOME $ 197 $ 163 $ 34 20.9%
======================================================================================================
n.m. - not meaningful
Net Income
Generation's net income increased by $34 million, or 21%, for the six
months ended June 30, 2003 compared to the same period in 2002. Income before
cumulative effect of changes in accounting principles decreased by $61 million
for the six months ended June 30, 2003 compared to the same period in 2002
primarily due to the after-tax impairment charge for Generation's equity
investment in Sithe of $130 million, partially offset by higher revenue due to
increased market electric sales.
125
Operating Revenues
Revenues increased by $745 million, or 25% for the six months ended June
30, 2003 compared to the same period in 2002. For the six months ended June 30,
2003 and 2002, Generation's sales were as follows:
Six Months Ended June 30,
-------------------------
Revenue (in millions) 2003 2002 Variance % Change
- -------------------------------------------------------------------------------------------------------------------
Energy Delivery and Exelon Energy Company $ 1,842 $ 1,839 $ 3 0.2%
Market Sales 1,863 1,175 688 58.6%
- ------------------------------------------------------------------------------------------------------
Total Energy Sales Revenue 3,705 3,014 691 22.9%
- ------------------------------------------------------------------------------------------------------
Trading Portfolio (2) (15) 13 (86.7%)
Other Revenue 62 21 41 195.2%
- ------------------------------------------------------------------------------------------------------
Total Revenue $ 3,765 $ 3,020 $ 745 24.7%
======================================================================================================
n.m. - not meaningful
Six Months Ended June 30,
-------------------------
Sales (in GWhs) 2003 2002 Variance % Change
- -------------------------------------------------------------------------------------------------------------------
Energy Delivery and Exelon Energy Company 57,463 58,649 (1,186) (2.0%)
Market Sales 51,264 39,913 11,351 28.4%
- ------------------------------------------------------------------------------------------------------
Total Sales 108,727 98,562 10,165 10.3%
======================================================================================================
Trading volume of 17,446 GWhs and 22,805 GWhs for the six months ended June
30, 2003 and 2002, respectively, is 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 June 30, 2003 and 2002 is as follows:
Six Months Ended June 30,
-------------------------
($/MWh) 2003 2002 % Change
- -------------------------------------------------------------------------------------------------------------------
Average Revenue
Energy Delivery and Exelon Energy Company $ 32.06 $ 31.35 2.3%
Market Sales 35.94 29.44 22.1%
Total - excluding the trading portfolio 33.89 30.58 10.8%
- -------------------------------------------------------------------------------------------------------------------
Energy Delivery and Exelon Energy Company. Sales to Energy Delivery
increased by $22 million as a result of increased prices per MWh for supply
agreements with ComEd and PECO, partially offset by a net overall reduction in
volume demand resulting from unfavorable weather and customers choosing
alternative suppliers under the customer choice program. Sales to Exelon Energy
Company decreased by $19 million for the six months ended June 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 $688 million resulted primarily from
increased production from generating assets acquired during 2002, as well as
lower load requirements to affiliates and higher wholesale market prices,
primarily attributable to higher fossil fuel prices.
Trading Revenues. Trading activity reduced revenue by $2 million during the
six months ended June 30, 2003 compared to $15 million during the same period in
2002 due to lower trading activity.
126
Other Revenues. Other revenues in the six months ended June 30, 2003
included $31 million from ComEd related to nuclear decommissioning cost
recoveries associated with the adoption of SFAS No. 143 that was not included in
revenues in 2002 and $27 million in gas sales.
Purchased Power and Fuel
Generation's supply source of its sales and average supply costs are
summarized below:
Six Months Ended June 30,
-------------------------
Supply of Sales (in GWhs) 2003 2002 Variance % Change
- -------------------------------------------------------------------------------------------------------------------
Purchases - non-trading portfolio (1) 39,373 36,071 3,302 9.2%
Nuclear Generation (2) 58,949 56,309 2,640 4.7%
Fossil and Hydro Generation 10,405 6,182 4,223 68.3%
- -----------------------------------------------------------------------------------------------------
Total Supply 108,727 98,562 10,165 10.3%
=====================================================================================================
<FN>
(1) Including purchased power agreements with AmerGen.
(2) Excluding AmerGen.
</FN>
Six Months Ended June 30,
-------------------------
($/MWh) 2003 2002 % Change
- ------------------------------------------------------------------------------------------------------------------
Average Supply Cost (1) - excluding trading portfolio $ 20.58 $ 17.78 15.7%
- ------------------------------------------------------------------------------------------------------------------
<FN>
(1) Average supply cost includes purchased power and fuel costs.
</FN>
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 2,995
GWhs, and
o increased quantity of purchased power at higher prices. In addition,
Generation entered into a new purchase power agreement with AmerGen in the
second quarter of 2003. As a result, 1,258 GWhs were purchased from Oyster
Creek nuclear facility in the second quarter of 2003.
Purchased power increased $319 million, or 24%, for the six months ended
June 30, 2003 compared to the same period in 2002 due to $185 million related to
higher market prices and the delay of Exelon New England commercial operations
commencement dates. The increase in purchased power also reflects mark-to-market
hedging gains of $1 million for the six months ended June 30, 2003 compared to
$10 million in the same period in 2002.
Fuel expense increased $273 million, or 63%, for the six months ended June
30, 2003 compared to the same period in 2002, as summarized below:
Six Months Ended June 30,
-------------------------
(in millions) 2003 2002 Variance % Change
- -----------------------------------------------------------------------------------------------------------------
Nuclear Generation (1) $ 260 $ 237 $ 23 9.7%
Fossil and Hydro Generation 446 196 250 127.6%
- -------------------------------------------------------------------------------------------------------
Total $ 706 $ 433 $ 273 63.0%
=======================================================================================================
<FN>
(1) Excluding AmerGen
</FN>
127
This increase is primarily due to the increase in fossil fuel generated
energy required to meet increased market demand for energy and operation of new
base load plants in New England as well as demand in all regions during the
first quarter of 2003. Fossil and other fuel expense increased $267 million, as
a result of operating the generation plants acquired after the second quarter of
2002. Increased fossil fuel expense includes $149 million related to increased
market sales from the generating plants acquired after the second quarter of
2002. Nuclear fuel expense increased $23 million, including $7 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. These increases in fuel expense were partially
offset by a $4 million loss on emissions allowance sales recorded in 2002.
Operating and Maintenance
O&M expense increased $99 million, or 12%, for the six months ended June
30, 2003 compared to the same period in 2002. The increase in O&M expense was
primarily attributable to $103 million of accretion expense related to SFAS No.
143, which includes $77 million of accretion of the asset retirement obligation
and $26 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, $36 million of
additional employee payroll and benefits costs, and $38 million of additional
expenses due to asset acquisitions made after the second 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. This increase was
partially offset by $53 million of lower nuclear refueling outage costs,
including $17 million for Generation's ownership interest in Salem, which is
operated by the co-owner, a one-time executive severance expense recorded in
2002 of $19 million, an $8 million reduction in worker's compensation expense
and other non-recurring items. For a further discussion of SFAS No. 143 see Note
2 of the Condensed Combined Notes to Consolidated Financial Statements.
Six Months Ended June 30,
-------------------------
2003 2002
- ---------------------------------------------------------------------------------------------------------------------
Nuclear fleet capacity factor (1) 94.2% 91.2%
Nuclear fleet production cost per MWh (1) $ 12.40 $ 13.38
Average purchased power cost for wholesale operations per MWh $ 41.71 $ 36.76
- ---------------------------------------------------------------------------------------------------------------------
<FN>
(1) Including AmerGen and excluding Salem.
</FN>
The higher nuclear capacity factor and decreased nuclear production costs
are primarily due to 50 fewer planned refueling outage days, resulting in a $36
million decrease in outage costs, in the six months ended June 30, 2003 as
compared to the same period in 2002. Additionally, the six months ended June 30,
2003 included 11 unplanned outages compared to 13 unplanned outages during the
same period in 2002.
Depreciation and Amortization
Depreciation and amortization expense decreased $37 million, or 29%, for
the six months ended June 30, 2003 compared to the same period in 2002. The
decrease was primarily attributable to a $64 million reduction in
decommissioning expense as these costs are included in operating and maintenance
expense after the adoption of SFAS No. 143 and a $10 million decrease due to
life extensions of asset additions in 2002. The decrease was partially offset by
$10 million of additional depreciation expense on capital additions placed in
service after the
128
second quarter of 2002, $16 million of expense related to plant acquisitions
made after the second quarter of 2002, and $2 million of depreciation for the
ARC asset related to SFAS No. 143. 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 $2 million, or 2%, for the six months
ended June 30, 2003 compared to the same period in 2002 primarily due to a $4
million decrease in payroll taxes partially offset by a $2 million increase in
property taxes related to asset acquisitions made after the second quarter of
2002.
Interest Expense
Interest expense increased $10 million, or 36%, for the six months ended
June 30, 2003 compared to the same period in 2002. The increase was primarily
due to a $7 million decrease in capitalized interest. In addition, the increase
was due to $5 million of additional interest expense on the $536 million note
payable issued to Sithe in November 2002 and $2 million of interest expense on
the long term debt obtained as a part of the Sithe New England asset
acquisition. This increase is partially offset by a $2 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 increased $5 million, or
16%, for the six months ended June 30, 2003 compared to the same period in 2002.
This increase was due to a $20 million increase in Generation's equity earnings
in AmerGen. AmerGen's earnings were primarily affected by increased power sales,
reduced outage costs, and lower accretion expense resulting from the adoption of
SFAS No. 143. The increase was partially offset by a $15 million decrease in
Generation's equity earnings of Sithe. Sithe's earnings were primarily affected
by Generation's purchase of Sithe New England's assets and unfavorable
mark-to-market losses for the period at Sithe.
Other, Net
Other, net decreased $174 million for the six months ended June 30, 2003
compared to the same period in 2002. This decrease is primarily a result of the
$200 million impairment charge related to Generation's equity investment in
Sithe due to an other than temporary decline in value. This charge was partially
offset by $26 million of higher net realized gains and investment income related
to the decommissioning trust funds. These net realized gains and investment
income are almost entirely offset with accretion expense in 2003, which is
included in operating and maintenance expense.
Income Taxes
The effective income tax rate was 44.2% for the six months ended June 30,
2003 compared to 39.0% for the same period in 2002. The increase was primarily
attributed to the impact of the impairment of Generation's investment in Sithe
as well as the increase in taxes related to the nuclear decommissioning trust
funds.
129
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.
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.
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 the issuance of commercial paper, participation in
the intercompany money pool 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
dividends. Any future acquisitions could require external financing or
borrowings or capital contributions from Exelon.
In the second quarter of 2003, Generation progressed in its plans to
implement the new business model referred to as The Exelon Way. The Exelon Way
is focused on improving operating cash flows while meeting service and financial
commitments through improved integration of operations and consolidation of
support functions. As part of the implementation of The Exelon Way, Generation
anticipates incurring expenses associated with the rationalization of certain
business functions and employee separation costs. These expenses may be
significant and are expected to be incurred during the remaining half of 2003
through 2005. However, these costs cannot be reasonably estimated at this time.
Cash Flows from Operating Activities
Cash flows provided by operations were $539 million for the six months
ended June 30, 2003, compared to $519 million for the same period in 2002. The
increase in cash flows from operating activities was primarily attributable to a
$114 million increase in working capital. Cash flows used in operating
activities for collateral were $136 million as of June 30, 2003,
130
compared to $30 million for the same period in 2002. The decrease in cash
flows from collateral activities of $106 million was attributable to Generation
exceeding its negotiated credit positions with counterparties. Cash flow used
for collateral will depend upon future market prices for energy and to the
extent forward energy deals are done under agreements with negotiated collateral
provisions. When power prices return to previous levels or when Generation
delivers the power under its forward conracts, 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 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 $496 million for the six
months ended June 30, 2003, compared to $1,048 million for the same period in
2002. The decrease in cash flows used in investing activities was primarily
attributable to a reduction in plant acquisition cost of $443 million as a
result of the acquisition of generating plants during the six months ended June
30, 2002, and $86 million for liquidated damages received from Raytheon in 2003
(see Note 8 of the Condensed Combined Notes to Consolidated Financial
Statements). Generation's proposed capital expenditures and other investments
are subject to periodic review and revision to reflect changes in economic
conditions and other factors.
Generation's capital expenditures for 2003 reflect the construction of
three Exelon New England 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 six months ended June
30, 2003, Generation received $86 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
the Mystic 8 and 9 and Fore River nuclear generating plants. In February 2002,
Generation entered into an agreement to loan AmerGen up to $75 million at an
interest rate of one-month LIBOR plus 2.25%. In July 2002, the loan agreement
and the loan were increased to $100 million and the maturity date was extended
to July 1, 2003. As of June 30, 2003, AmerGen has repaid the balance of the
loan. 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 $27 million for the six months
ended June 30, 2003, compared to cash flows provided by financing activities of
$329 million for the same period in 2002. The decrease in cash provided by
financing was primarily due to a $273 million decrease in cash receipts from
affiliates, $45 million dividend to Exelon Corporation, the $210 million partial
payment of the acquisition note payable to Sithe, and a $38 million decrease in
restricted cash as a result of liquidated damages received from Raytheon in
2003. The decrease in cash provided by financing activities was partially offset
by $211 million of borrowings under the revolving credit facility. See Note 9 of
the Condensed Combined Notes to Consolidated Financial Statements for further
discussion of Generation's debt financing activities.
131
Credit Issues
Generation meets its short-term liquidity requirements primarily through
intercompany borrowings from Exelon, the issuance of commercial paper 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 June 30, 2003, the
sublimit for Generation was zero. The credit facility is expected to be used by
Generation principally to support its commercial paper program.
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 June
30, 2003. At June 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's subsidiary, Commonwealth Edison Company of Indiana, Inc., PECO,
Generation and BSC may participate in the money pool as lenders and borrowers,
and Exelon Corporate and ComEd as lenders. Funding of, and borrowings from, the
money pool are predicated on whether such funding results in mutual economic
benefits to each of the participants, although Exelon is not permitted to be a
net borrower from the money pool. Interest on borrowings is based on short-term
market rates of interest, or, if from an external source, specific borrowing
rates. During the six months ended June 30, 2003, Generation had various
borrowings from ComEd under the money pool. The maximum amount of loans
outstanding at any time during the quarter was $342 million. As of June 30,
2003, Generation owed ComEd $165 million on these loans. For the six months
ended June 30, 2003, Generation paid $1 million in interest to ComEd
EBG, an indirect subsidiary of Generation, has approximately $1.1 billion
of debt outstanding under the EBG Facility at June 30, 2003. The EBG Facility
was entered into primarily to finance the construction of the Mystic 8 and 9 and
Fore River generating units. The EBG Facility requires that all of the projects
achieve "Project Completion," as defined in the EBG Facility, 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 are 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 are in commercial operation,
although construction has not
132
progressed to the point of Project Completion. Construction of Fore River is
substantially complete and the unit is currently undergoing testing. EBG does
not anticipate that the projects will achieve Project Completion by August 29,
2003. The EBG Facility is non-recourse to Exelon and 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.
As a result of Exelon's continuing evaluation of the projects and
discussions with the lenders in July 2003, 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 Exelon's 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.
Exelon expects Generation will incur an impairment of its EBG related
assets, which, in aggregate, could reach approximately $550 million after income
taxes.
The debt outstanding under the EBG Facility of approximately $1.1 billion
at June 30, 2003 is reflected in Generation's Consolidated Balance Sheet as a
current liability.
On June 13, 2003, Generation entered into a $550 million revolving credit
facility. Generation used the facility to make the first payment to Sithe
relating to the $536 million note that was used to purchase the EBG facilities.
This note was restructured in June 2003 to provide for a payment of $210 million
of the principal on June 16, 2003 and payment of the remaining principal on the
earlier of December 1, 2003 or change of control.
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.
Under PUHCA, Generation can only pay dividends from undistributed or
current earnings. Generation is precluded from lending or extending credit or
indemnity to Exelon. At June 30, 2003, Generation had undistributed earnings of
$1.1 billion.
133
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 June 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 8 of the Condensed
Combined Notes to Consolidated Financial Statements for commercial
commitments tables 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 for the
35.2% interest in Sithe owned by Apollo Energy, LLC and the 14.9%
interest owned by subsidiaries of Marubeni Corporation. The total call
price was based on the terms of the existing Put and Call Agreement
(PCA) among the parties and approximated $650 million. The transfer of
ownership requires various regulatory approvals including FERC, the
state environmental agency in New Jersey, and expiration of the Hart
Scott Rodino waiting period.
Under the terms of the PCA, the call must be funded within six
months of the call notice being issued. Additionally, because the
Federal Power Act restricts Exelon's ownership of 50% or more of
Qualifying Facilities (QFs), the QFs owned by Sithe must be sold or
restructured before closing to preserve their QF status. Despite the
issuance of the call notice, Generation continues to pursue options to
sell its investment in Sithe in its entirety.
o In June 2003, Generation entered an agreement with USEC Inc. to
purchase approximately $700 million of nuclear fuel from 2005 through
2010.
As discussed in Note 2 of the Condensed Combined Notes to Consolidated
Financial Statements, it is reasonably possible that Generation will consolidate
Sithe as of July 1, 2003 pursuant to FIN No. 46, "Consolidation of Variable
Interest Entities."
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 approximately $1.0 billion and incurred a net
134
loss of approximately $348 million. Exelon 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.
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 91% 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. 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 $37 million
decrease in net income, or approximately $0.11 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.
135
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.
136
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 six months ended June 30, 2003. Normal operations and hedging
activities represent the marketing of electricity available from Generation's
owned or contracted generation, including ComEd and PECO's retail load, sold
into the wholesale market. 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 June 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 109 (1) 108
Changes in valuation techniques and assumptions -- -- --
Reclassification to realized at settlement of contracts (77) (1) (78)
- -------------------------------------------------------------------------------------------------------------------
Total change in unrealized fair value 32 (2) 30
Realized net settlement of transactions subject to mark-to-market 77 1 78
- -------------------------------------------------------------------------------------------------------------------
Total mark-to-market activities gross margin $ 109 $ (1) $ 108
- -------------------------------------------------------------------------------------------------------------------
Accrual activities:
- -------------------
Accrual activities revenue $ 1,107 $ -- $ 1,107
Hedge gains/(losses) reclassified from OCI 616 -- 616
- -------------------------------------------------------------------------------------------------------------------
Total revenue - accrual activities 1,723 -- 1,723
- -------------------------------------------------------------------------------------------------------------------
Purchased power and fuel 388 -- 388
Hedges of purchased power and fuel reclassified from OCI 705 -- 705
- -------------------------------------------------------------------------------------------------------------------
Total purchased power and fuel 1,093 -- 1,093
- -------------------------------------------------------------------------------------------------------------------
Total accrual activities gross margin 630 -- 630
- -------------------------------------------------------------------------------------------------------------------
Total gross margin $ 739 $ (1) $ 738 (b)
===================================================================================================================
<FN>
(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.
</FN>
137
Six Months Ended June 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 135 (3) 132
Changes in valuation techniques and assumptions -- -- --
Reclassification to realized at settlement of contracts (134) (1) (135)
- ------------------------------------------------------------------------------------------------------------------
Total change in unrealized fair value 1 (4) (3)
Realized net settlement of transactions subject to mark-to-market 134 1 135
- ------------------------------------------------------------------------------------------------------------------
Total mark-to-market activities gross margin $ 135 $ (3) $ 132
- ------------------------------------------------------------------------------------------------------------------
Accrual activities:
- -------------------
Accrual activities revenue $ 2,459 $ -- $ 2,459
Hedge gains/(losses) reclassified from OCI 1,014 -- 1,014
- ------------------------------------------------------------------------------------------------------------------
Total revenue - accrual activities 3,473 -- 3,473
- ------------------------------------------------------------------------------------------------------------------
Purchased power and fuel 980 -- 980
Hedges of purchased power and fuel reclassified from OCI 1,208 -- 1,208
- ------------------------------------------------------------------------------------------------------------------
Total purchased power and fuel 2,188 -- 2,188
- ------------------------------------------------------------------------------------------------------------------
Total accrual activities gross margin 1,285 -- 1,285
- ------------------------------------------------------------------------------------------------------------------
Total gross margin $ 1,420 $ (3) $ 1,417 (b)
==================================================================================================================
<FN>
(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.
</FN>
138
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 June 30, 2003. It indicates the drivers behind changes in the balance
sheet amounts. This table will incorporate the mark-to-market activities that
are immediately 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
June 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 six months ended June 30, 2003
of contracts recorded in earnings 135 (3) 132
Reclassification to realized at settlement of contracts recorded in earnings (134) (1) (135)
Reclassification to realized at settlement from OCI 194 -- 194
Effective portion of changes in fair value - recorded in OCI (367) -- (367)
Purchase/sale of existing contracts or portfolios subject to mark-to-market -- -- --
- ------------------------------------------------------------------------------------------------------------------
Total mark-to-market energy contract net assets (liabilities)
at June 30, 2003 $ (340) $ 1 $ (339)
==================================================================================================================
The following table details the balance sheet classification of the
mark-to-market energy contract net assets recorded as of June 30, 2003:
Normal Operations and Proprietary
Hedging Activities Trading Total
- ------------------------------------------------------------------------------------------------------------------
Current assets $ 251 $ 2 $ 253
Noncurrent assets 68 -- 68
- ------------------------------------------------------------------------------------------------------------------
Total mark-to-market energy contract assets 319 2 321
- ------------------------------------------------------------------------------------------------------------------
Current liabilities (490) -- (490)
Noncurrent liabilities (169) (1) (170)
- ------------------------------------------------------------------------------------------------------------------
Total mark-to-market energy contract liabilities (659) (1) (660)
- ------------------------------------------------------------------------------------------------------------------
Total mark-to-market energy contract net assets (liabilities) $ (340) $ 1 $ (339)
==================================================================================================================
139
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 June 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.
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 $(190) $(150) $ (11) $ (7) $ -- $ -- $ (358)
- ---------------------------------------------------------------------------------------------------------------------
Total $(190) $(150) $ (11) $ (7) $ -- $ -- $ (358)
- ---------------------------------------------------------------------------------------------------------------------
Normal Operations, other derivative contracts (2):
Actively quoted prices $ 18 $ 8 $ -- $ -- $ -- $ -- $ 26
Prices provided by other external sources 6 16 5 4 -- -- 31
Prices based on model or other valuation methods 12 (34) (5) (9) (3) -- (39)
- ---------------------------------------------------------------------------------------------------------------------
Total $ 36 $ (10) $ -- $ (5) $ (3) $ -- $ 18
- ---------------------------------------------------------------------------------------------------------------------
Proprietary Trading, other derivative contracts (3):
Actively quoted prices $ 1 $ 2 $ -- $ -- $ -- $ -- $ 3
Prices provided by other external sources (1) (5) -- -- -- -- (6)
Prices based on model or other valuation methods 3 1 -- -- -- -- 4
- ---------------------------------------------------------------------------------------------------------------------
Total $ 3 $ (2) $ -- $ -- $ -- $ -- $ 1
- ---------------------------------------------------------------------------------------------------------------------
Average tenor of proprietary trading portfolio (4) 1.5 years
=====================================================================================================================
<FN>
(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.
</FN>
140
The table below provides details of effective cash flow hedges under SFAS
No. 133 included in the balance sheet as of June 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 six months ended June 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, January 1, 2003 $ (114) $ (5) $ (119)
Changes in fair value (223) (12) (235)
Reclassifications from OCI to net income 119 -- 119
- ----------------------------------------------------------------------------------------------------------------------
Accumulated OCI derivative gain/(loss)
at June 30, 2003 $ (218) $ (17) $ (235)
======================================================================================================================
<FN>
(1) Includes interest rate hedges at Generation.
</FN>
Generation uses a Value-at-Risk (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
141
liquidate the portfolio. A two-tailed test considers potential upside in the
portfolio in addition to the potential downside in the portfolio considered in
the one-tailed test. The following table provides the VaR for all proprietary
trading positions of Generation as of June 30, 2003.
Proprietary
Trading VaR
- ---------------------------------------------------------------------------
95% Confidence Level, One-Day Holding Period, One-Tailed
Period end $ 0.0
Average for the period 0.1
High 0.2
Low 0.0
95% Confidence Level, Ten-Day Holding Period, Two-Tailed
Period End $ 0.6
Average for the period 0.5
High 0.8
Low 0.3
99% Confidence Level, One-Day Holding Period, Two-Tailed
Period end $ 0.2
Average for the period 0.2
High 0.3
Low 0.1
- ---------------------------------------------------------------------------
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.
142
The following table provides information on Generation's credit exposure,
net of collateral, as of June 30, 2003. It further delineates that exposure by
the credit rating of the counterparties and provides 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 table below does 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 $ 158 $ -- $ 158 3 $ 81
Split rating -- -- -- -- --
Non-investment grade 10 9 1 -- --
No external ratings
Internally rated - investment grade 12 -- 12 3 10
Internally rated - non-investment grade 13 1 12 3 12
- -------------------------------------------------------------------------------------------------------------------
Total $ 193 $ 10 $ 183 9 $ 103
====================================================================================================================
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 $ 148 $ 10 $ -- $ 158
Split rating -- -- -- --
Non-investment grade 10 -- -- 10
No external ratings
Internally rated - investment grade 11 1 -- 12
Internally rated - non-investment grade 13 -- -- 13
- ------------------------------------------------------------------------------------------------------------------
Total $ 182 $ 11 $ -- $ 193
==================================================================================================================
Generation is a counterparty to Dynegy in various energy transactions. In
early July 2002, the credit ratings of Dynegy were downgraded to below
investment grade by two credit rating agencies. As of June 30, 2003, Generation
had a net receivable from Dynegy of approximately $4 million and, consistent
with the terms of the existing credit arrangement, has received collateral in
support of this receivable. Generation also 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 June 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 terms 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 $17 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.
143
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.
In connection with ComEd's sale of assets to Midwest Generation prior to
the Merger, ComEd had entered into an Agency Agreement with Midwest Generation
and certain of Midwest Generation's related parties (the "Guarantors") whereby
the Guarantors assumed the benefits and liabilities of a coal purchase contract.
ComEd remained the signatory to the coal contract, and in connection with the
Merger and subsequent restructuring, Generation assumed the signatory obligation
on this contract from ComEd. Midwest Generation's credit ratings have recently
been downgraded by certain credit rating agencies. In the event of Midwest
Generation and the Guarantors non-performance under the coal purchase contract,
Generation would be required to fulfill the purchase commitments which 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 contract years 2003 to 2012 are
estimated to be approximately $81 million related to this agreement. Generation
and ComEd have entered into other agreements with Midwest Generation in which
the non-performance by Midwest Generation is currently not anticipated to result
in significant contingent obligations to Generation or ComEd.
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 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 June 30, 2003, these interest rate
swaps with an aggregate notional amount of $200 million, designated as cash flow
hedges, had an aggregate fair market value exposure of $6 million based on the
present value of the difference between the contract and market rates at June
30, 2003. If these derivative instruments had been terminated at June 30, 2003,
this estimated fair value represents the amount to be paid by ComEd 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 June 30, 2003 is estimated to be $13 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 June 30, 2003 is estimated to be less than $1
million in the counterparties favor.
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 June 30,
2003, these interest rate swaps, designated as fair value hedges, had an
aggregate fair market value of $46 million based on the present value difference
between the contract and market rates at June 30, 2003. If these derivative
144
instruments had been terminated at June 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 June 30, 2003 is estimated to be $53 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 June 30, 2003 is estimated to be $39 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 June 30, 2003, these interest rate
swaps had an aggregate fair market value exposure of $17 million based on the
present value difference between the contract and market rates at June 30, 2003.
If these derivative instruments had been terminated at June 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
June 30, 2003 is estimated to be $18 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
June 30, 2003 is estimated to be $15 million in the counterparties favor.
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.
145
As of June 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 six months ended June 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 June 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
at June 30, 2003. The fair market value exposure of these swaps, designated as
cash flow hedges, is $105 million. If these derivative instruments had been
terminated at June 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 June 30, 2003 is estimated to be $119 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 June 30, 2003 is estimated to be $91 million in
the counterparties favor.
In June 2003, Generation entered into forward-starting interest rate swaps
in the aggregate amount of $200 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 June 30, 2003, these interest rate
swaps, designated as cash flow hedges, had an aggregate fair market value of $4
million based on the present value of the difference between the contract and
market rates at June 30, 2003. If these derivative instruments had been
terminated at June 30, 2003, this estimated fair value represents the amount to
be paid by the counterparties to Generation.
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 June 30, 2003 is estimated to be $4 million in the
counterparties favor.
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 June 30, 2003 is estimated to be $12 million in Generation's
favor.
146
Equity Price Risk
Generation
Generation maintains trust funds, as required by the NRC, to fund certain
costs of decommissioning its nuclear plants. As of June 30, 2003,
decommissioning trust funds are reflected at fair value on Exelon and
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 $175 million reduction in the fair value of the trust
assets.
ITEM 4. CONTROLS AND PROCEDURES
Exelon
During the second 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.
As of June 30, 2003, these officers concluded that, subject to limitations
noted above, the design of the disclosure controls and procedures provides
reasonable assurance that the disclosure controls and procedures can 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.
147
In the second quarter of 2003, Exelon implemented a new general ledger
accounting system. The new general ledger system was implemented in order to
provide a consistent system platform for the affiliated Exelon companies and to
enhance management reporting and analysis. This change in systems was subject to
thorough testing and review by internal and external parties both before and
after final implementation. Exelon continually strives to improve its internal
control over financial reporting to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements
for external purposes in accordance with generally accepted accounting
principles.
ComEd
During the second 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.
As of June 30, 2003, these officers concluded that, subject to limitations
noted above, the design of the disclosure controls and procedures provides
reasonable assurance that the disclosure controls and procedures can 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.
In the second quarter of 2003, ComEd implemented a new general ledger
accounting system. The new general ledger system was implemented in order to
provide a consistent system platform for the affiliated Exelon companies and to
enhance management reporting and analysis. This change in systems was subject to
thorough testing and review by internal and external parties both before and
after final implementation. ComEd continually strives to improve its internal
control over financial reporting to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements
for external purposes in accordance with generally accepted accounting
principles.
PECO
During the second quarter of 2003, PECO's management, including the
principal executive officer and principal financial officer, evaluated PECO's
disclosure controls and
148
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.
As of June 30, 2003, these officers concluded that, subject to limitations
noted above, the design of the disclosure controls and procedures provides
reasonable assurance that the disclosure controls and procedures can accomplish
their 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.
In the second quarter of 2003, PECO implemented a new general ledger
accounting system. The new general ledger system was implemented in order to
provide a consistent system platform for the affiliated Exelon companies and to
enhance management reporting and analysis. This change in systems was subject to
thorough testing and review by internal and external parties both before and
after final implementation. PECO continually strives to improve its internal
control over financial reporting to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements
for external purposes in accordance with generally accepted accounting
principles.
Generation
During the second 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
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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.
As of June 30, 2003, these officers concluded that, subject to limitations
noted above, the design of the disclosure controls and procedures provides
reasonable assurance that the disclosure controls and procedures can 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.
In the second quarter of 2003, Generation implemented a new general ledger
accounting system. The new general ledger system was implemented in order to
provide a consistent system platform for the affiliated Exelon companies and to
enhance management reporting and analysis. This change in systems was subject to
thorough testing and review by internal and external parties both before and
after final implementation. Generation continually strives to improve its
internal control over financial reporting to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with generally accepted
accounting principles.
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
ComEd
As previously reported in the 2002 Form 10-K and the March 2003 Form 10-Q,
three of ComEd's wholesale municipal customers had filed a complaint and request
for refund with FERC alleging that ComEd failed to properly adjust its rates
pursuant to the terms of the respective electric service contracts. ComEd and
the municipal customers have executed a settlement agreement ending the
litigation. Under the settlement, ComEd will pay a total of approximately $3
million to the three municipalities.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Exelon
On April 29, 2003, Exelon held its 2003 Annual Meeting of Shareholders.
Proposal 1 was the election of five Class III directors to serve three-year
terms expiring in 2006. The following directors were elected:
Votes For Votes Withheld
M. Walter D'Alessio 259,812,777 5,103,938
Rosemarie B. Greco 259,802,051 5,114,664
John M. Palms 257,952,983 6,963,732
John W. Rogers, Jr. 256,121,360 8,795,355
Richard L. Thomas 259,607,872 5,308,843
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Proposal 2 was the ratification of PricewaterhouseCoopers LLP as
independent accountants for Exelon and its subsidiaries for 2003. The
shareholders approved the proposal with 253,274,833 votes cast for, 9,037,160
votes cast against and 2,604,722 votes abstaining.
Proposal 3 described in the proxy statement was a non-binding shareholder
proposal made by the AFL-CIO Reserve Fund that urged the Board of Directors of
Exelon to seek shareholder approval of any extraordinary pension benefits for
executives. The proponent withdrew the proposal after Exelon agreed to make
certain changes in its compensation practices. As a result, the proposal was not
voted on at the Exelon annual meeting. Recognizing shareholder concern about
executive compensation, Exelon agreed that after January 1, 2004, it would not
grant additional unearned service credits for current executives in the Exelon
pension plans without shareholder approval. It also agreed that it would not
provide more than two years' service credit under new change-in-control
agreements without shareholder approval. If Exelon should need to offer new
executives more than the pension benefits that they would give up to come work
for Exelon, the additional pension benefits would be performance-based and not
guaranteed. The agreement does not affect benefits or compensation under
existing agreements, arrangements or change-in-control provisions. It does not
limit Exelon's rights to provide compensation or benefits outside the pension
plans.
ComEd
On May 29, 2003 ComEd held its 2003 Annual Meeting of Shareholders.
Proposal 1 was the election of 5 directors to serve a term of one year. The
following directors were elected:
Votes For Votes Withheld
John W. Rowe 127,002,904 --
Pamela B. Strobel 127,002,904 --
Kenneth G. Lawrence 127,002,904 --
Frank M. Clark 127,002,904 --
Robert S. Shapard 127,002,904 --
Proposal 2 was to amend the Articles of Incorporate to add the practice of
professional engineering to the purposes for which ComEd has been organized. The
amendment was approved with 127,002,904 votes cast for, 0 votes cast against,
and 0 votes abstaining.
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PECO
On May 29, 2003 PECO Energy Company held its Annual Meeting of
Shareholders.
Proposal 1 was the election of 5 directors into three classes in compliance
with the Bylaws. The three-year terms of each class were staggered so that the
term of one class will expire at each annual meeting. The following directors
were elected:
Votes For Votes Withheld
Class I, with term expiring in 2006:
John W. Rowe 170,478,507 --
Class II, with term expiring in 2005:
Pamela B. Strobel 170,478,507 --
Kenneth G. Lawrence 170,478,507 --
Class III, with term expiring in 2004:
Frank M. Clark 170,478,507 --
Robert S. Shapard 170,478,507 --
ITEM 5. OTHER INFORMATION
ComEd
As previously reported in the 2002 Form 10-K, in July 2002, FERC
conditionally approved ComEd's decision to join PJM. On April 1, 2003, ComEd
received approval from FERC to transfer control of ComEd's transmission assets
to PJM. 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.
ComEd expects to transfer functional control of its transmission assets to PJM
and to integrate fully into PJM's energy market structures on November 1, 2003.
PECO
As previously reported in the 2002 Form 10-K and the March 2003 Form 10-Q,
on August 15, 2002, the International Brotherhood of Electrical Workers (IBEW)
filed a petition with the National Labor Relations Board (NLRB) to conduct a
unionization vote of certain of PECO's employees. On May 21, 2003, the PECO
union election was held and a majority of PECO workers voted against union
representation. The results of the election have not been certified due to
pending challenges and objections.
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, a total of 375,000 residential customers may be transferred to
alternative electric generation suppliers in December 2003. Customers
transferred will have the right to return to PECO at any time.
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Generation
As previously reported in the 2002 Form 10-K, on April 9, 2003, the IBEW
filed a petition with the NLRB to represent all production and maintenance
employees in Generation's fossil and hydroelectric operations in the
Mid-Atlantic operating group. These approximate 300 employees had not been
covered by a collective bargaining agreement. . Pursuant to an election held on
June 18, 2003, the employees voted to become represented by the IBEW.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits:
4.1 - Indenture to Subordinated Debt Securities dated as of
June 24, 2003 between PECO Energy Company, as Issuer,
and Wachovia Bank National Association, as Trustee.
4.2 - Preferred Securities Guarantee Agreement between PECO
Energy Company, as Guarantor, and Wachovia Trust
Company, National Association, as Trustee, dated as
of June 24, 2003.
4.3 - PECO Energy Capital Trust IV Amended and Restated
Declaration of Trust among PECO Energy Company, as
Sponsor, Wachovia Trust Company, National
Association, as Delaware Trustee and Property
Trustee, and J. Barry Mitchell, George R. Shicora and
Charles S. Walls as Administrative Trustees dated as
of June 24, 2003.
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 June 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 June 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
- --------------------------------------------------------------------------------
153
(b) Reports on Form 8-K:
Exelon, ComEd, PECO and/or Generation filed Current Reports on Form 8-K during
the three months ended June 30, 2003 regarding the following items:
Date of Earliest
Event Reported Description of Item Reported
- ----------------------------------------------------------------------------------------------
April 3, 2003 "ITEM 9. REGULATION FD DISCLOSURE" filed for Exelon, ComEd, PECO
and Generation regarding a presentation by John W. Rowe, Chairman
and CEO, at the Berenson & Company and The Williams Capital Group
Midwest Utilities Seminar. The exhibits include the slides used
during the presentation.
April 7, 2003 "ITEM 5. OTHER EVENTS" filed by ComEd regarding the issuance of
$395 million in First Mortgage Bonds.
April 28, 2003 "ITEM 9. REGULATION FD DISCLOSURE" filed under Item 9 in compliance
with Item 12 for Exelon, ComEd, PECO and Generation regarding the
first quarter 2003 earnings release and items discussed during the
earnings conference call. Also included as an exhibit to this
report was a new release regarding the "Exelon Way" business
model.
May 2, 2003 "ITEM 5. OTHER EVENTS" filed for Exelon regarding Richard H.
Glanton's acceptance of the position of Senior Vice President,
Corporate Development and his relinquishment of his directorship on
the Exelon Board.
May 7, 2003 "ITEM 5. OTHER EVENTS" filed for Exelon, PECO and Generation
announcing that the U.S. Nuclear Regulatory Commission approved a
20-year extension of the operating licenses for Exelon Nuclear's
Peach Bottom Atomic Power Station.
May 20, 2003 "ITEM 9. REGULATION FD DISCLOSURE" filed for Exelon regarding a
presentation by Robert S. Shapard, Executive Vice President and
CFO. The exhibit includes the slides used during the presentation.
May 29, 2003 "ITEM 5. OTHER EVENTS" filed for Exelon and Generation announcing
the issuance of a call notice for the remaining 50.1% interest in
Sithe Energies, Inc.
June 2, 2003 "ITEM 5. OTHER EVENTS" filed for Exelon and Generation regarding a
request for an amendment to the Exelon Boston
154
Generating, LLC credit facility and the construction of the Mystic 8
and 9 and Fore River generating units.
June 2, 2003 "ITEM 5. OTHER EVENTS" filed for Exelon and Generation regarding
the approval of an amendment to the Exelon Boston Generating, LLC
credit facility.
June 11, 2003 "ITEM 9. REGULATION FD DISCLOSURE" filed for Exelon, ComEd, PECO
and Generation regarding a presentation by Robert S. Shapard,
Executive Vice President and CFO. The exhibits include the slides
and handouts used during the presentation.
June 13, 2003 "ITEM 5. OTHER EVENTS" filed for Exelon regarding the dismissal of
a class action lawsuit.
June 18, 2003 "ITEM 5. OTHER EVENTS" filed for Exelon announcing an agreement to
sell certain businesses of its subsidiary InfraSource, Inc.
June 18, 2003 "ITEM 5. OTHER EVENTS" filed for Exelon, ComEd, PECO and
Generation regarding the sale of certain businesses of InfraSource,
Inc.
June 25, 2003 "ITEM 5. OTHER EVENTS" filed for Exelon, ComEd, and Generation
regarding the exercise of Generation's call option under an
existing purchase power agreement with Midwest Generation, LLC.
- ----------------------------------------------------------------------------------------------
155
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)
July 30, 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
- ----------------------------------
DUANE M. DESPARTE
Vice President and Controller, Exelon Energy Delivery
(Principal Accounting Officer)
July 30, 2003
156
- --------------------------------------------------------------------------------
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
- ----------------------------------
DUANE M. DESPARTE
Vice President and Controller, Exelon Energy Delivery
(Principal Accounting Officer)
July 30, 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)
July 30, 2003
157