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Consolidated Statements of Operations and Comprehensive Income - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2009	Dec. 31, 2008	Dec. 31, 2007
EXELON CORP
Operating revenues
Total operating revenues	$ 17,318	$ 18,859	$ 18,916
Operating expenses
Purchased power	3,215	4,270	5,282
Fuel	2,066	2,312	2,360
Operating and maintenance	4,612	4,538	4,289
Operating and maintenance for regulatory required programs	63	28	0
Depreciation and amortization	1,834	1,634	1,520
Taxes other than income	778	778	797
Total operating expenses	12,568	13,560	14,248
Operating income	4,750	5,299	4,668
Other income and deductions
Interest expense	(654)	(699)	(647)
Interest expense to affiliates, net	(77)	(133)	(203)
Equity in earnings (losses) of investments	(27)	(26)	(106)
Other, net	426	(407)	460
Total other income and deductions	(332)	(1,265)	(496)
Income before income taxes	4,418	4,034	4,172
Income taxes	1,712	1,317	1,446
Income from continuing operations	2,706	2,717	2,726
Discontinued operations
Income (loss) from discontinued operations (net of taxes of $0, $1 and $3, respectively)	1	(1)	6
Gain on disposal of discontinued operations (net of taxes)	0	21	4
Income from discontinued operations, net	1	20	10
Net income	$ 2,707	$ 2,737	$ 2,736
Average shares of common stock outstanding:
Basic	659	658	670
Diluted	662	662	676
Earnings per average common share-basic:
Income from continuing operations	$ 4.10	$ 4.13	$ 4.06
Income from discontinued operations	0.00	0.03	0.02
Net income	4.10	4.16	4.08
Earnings per average common share-diluted:
Income from continuing operations	4.09	4.10	4.03
Income from discontinued operations	0.00	0.03	0.02
Net income	4.09	4.13	4.05
Dividends per common share	$ 2.10	$ 2.03	$ 1.76
EXELON GENERATION CO LLC
Operating revenues
Operating revenues	$ 6,231	$ 7,168	$ 7,211
Operating revenues from affiliates	3,472	3,586	3,538
Total operating revenues	9,703	10,754	10,749
Operating expenses
Purchased power	1,338	1,867	2,705
Fuel	1,594	1,705	1,746
Operating and maintenance	2,632	2,432	2,190
Operating and maintenance from affiliate	306	285	264
Depreciation and amortization	333	274	267
Taxes other than income	205	197	185
Total operating expenses	6,408	6,760	7,357
Operating income	3,295	3,994	3,392
Other income and deductions
Interest expense	(113)	(136)	(161)
Equity in earnings (losses) of investments	(3)	(1)	1
Other, net	376	(469)	155
Total other income and deductions	260	(606)	(5)
Income before income taxes	3,555	3,388	3,387
Income taxes	1,433	1,130	1,362
Income from continuing operations	2,122	2,258	2,025
Discontinued operations
Gain on disposal of discontinued operations (net of taxes)	0	20	4
Income from discontinued operations, net	0	20	4
Net income	2,122	2,278	2,029
COMMONWEALTH EDISON CO
Operating revenues
Operating revenues	5,772	6,129	6,099
Operating revenues from affiliates	2	7	5
Total operating revenues	5,774	6,136	6,104
Operating expenses
Purchased power	1,609	2,077	2,270
Purchased power from affiliate	1,456	1,505	1,477
Operating and maintenance	863	929	895
Operating and maintenance for regulatory required programs	63	28	0
Operating and maintenance from affiliate	165	168	196
Depreciation and amortization	494	464	440
Taxes other than income	281	298	314
Total operating expenses	4,931	5,469	5,592
Operating income	843	667	512
Other income and deductions
Interest expense	(306)	(327)	(265)
Interest expense to affiliates, net	(13)	(21)	(53)
Equity in earnings (losses) of investments	0	(8)	(7)
Other, net	79	18	58
Total other income and deductions	(240)	(338)	(267)
Income before income taxes	603	329	245
Income taxes	229	128	80
Discontinued operations
Net income	374	201	165
PECO ENERGY CO
Operating revenues
Operating revenues	5,302	5,553	5,596
Operating revenues from affiliates	9	14	17
Total operating revenues	5,311	5,567	5,613
Operating expenses
Purchased power	269	328	307
Purchased power from affiliate	2,005	2,083	2,059
Fuel	472	607	617
Operating and maintenance	545	641	513
Operating and maintenance from affiliate	95	90	117
Depreciation and amortization	952	854	773
Taxes other than income	276	265	280
Total operating expenses	4,614	4,868	4,666
Operating income	697	699	947
Other income and deductions
Interest expense	(124)	(112)	(94)
Interest expense to affiliates, net	(63)	(114)	(154)
Equity in earnings (losses) of investments	(24)	(16)	(7)
Other, net	13	18	45
Total other income and deductions	(198)	(224)	(210)
Income before income taxes	499	475	737
Income taxes	146	150	230
Discontinued operations
Net income	353	325	507
Earnings per average common share-diluted:
Preferred security dividends	4	4	4
Net income on common stock	$ 349	$ 321	$ 503

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2009	Dec. 31, 2008	Dec. 31, 2007
EXELON CORP
Cash flows from operating activities
Net income	$ 2,707	$ 2,737	$ 2,736
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion	2,601	2,308	2,183
Impairment of long-lived assets	223	0	0
Deferred income taxes and amortization of investment tax credits	756	374	(104)
Net fair value changes related to derivatives	(95)	(515)	102
Net realized and unrealized (gains) losses on nuclear decommissioning trust fund investments	(207)	363	(70)
Other non-cash operating activities	652	870	734
Changes in assets and liabilities:
Accounts receivable	234	67	(585)
Inventories	51	(109)	9
Accounts payable, accrued expenses and other current liabilities	(254)	(44)	146
Option premiums (paid) received, net	(40)	(124)	27
Counterparty collateral received (posted), net	196	1,027	(516)
Income taxes	(29)	(38)	160
Pension and non-pension postretirement benefit contributions	(588)	(230)	(204)
Other assets and liabilities	(113)	(135)	(122)
Net cash flows provided by operating activities	6,094	6,551	4,496
Cash flows from investing activities
Capital expenditures	(3,273)	(3,117)	(2,674)
Proceeds from nuclear decommissioning trust fund sales	22,905	17,202	7,312
Investment in nuclear decommissioning trust funds	(23,144)	(17,487)	(7,527)
Proceeds from sales of investments	41	0	95
Purchases of investments	(28)	0	0
Change in restricted cash	35	29	(45)
Other investing activities	6	(5)	(70)
Net cash flows used in investing activities	(3,458)	(3,378)	(2,909)
Cash flows from financing activities
Changes in short-term debt	(56)	(405)	311
Issuance of long-term debt	1,987	2,265	1,621
Retirement of long-term debt	(1,773)	(1,398)	(262)
Retirement of long-term debt to financing affiliates	(709)	(1,038)	(1,020)
Dividends paid on common stock	(1,385)	(1,335)	(1,180)
Proceeds from employee stock plans	42	130	215
Purchase of treasury stock	0	(436)	(1,208)
Purchase of forward contract in relation to certain treasury stock	0	(64)	(79)
Other financing activities	(3)	68	102
Net cash flows (used in) provided by financing activities	(1,897)	(2,213)	(1,500)
Increase (decrease) in cash and cash equivalents	739	960	87
Cash and cash equivalents at beginning of period	1,271	311	224
Cash and cash equivalents at end of period	2,010	1,271	311
EXELON GENERATION CO LLC
Cash flows from operating activities
Net income	2,122	2,278	2,029
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion	1,098	947	928
Impairment of long-lived assets	223	0	0
Deferred income taxes and amortization of investment tax credits	671	327	(31)
Net fair value changes related to derivatives	(95)	(515)	139
Net realized and unrealized (gains) losses on nuclear decommissioning trust fund investments	(207)	363	(70)
Other non-cash operating activities	104	332	256
Changes in assets and liabilities:
Accounts receivable	172	79	(204)
Receivables from and payables to affiliates, net	(54)	(51)	288
Inventories	(29)	(60)	(38)
Accounts payable, accrued expenses and other current liabilities	(43)	(91)	(22)
Option premiums (paid) received, net	(40)	(124)	27
Counterparty collateral received (posted), net	195	1,029	(518)
Income taxes	79	115	269
Pension and non-pension postretirement benefit contributions	(265)	(103)	(99)
Other assets and liabilities	(1)	(81)	40
Net cash flows provided by operating activities	3,930	4,445	2,994
Cash flows from investing activities
Capital expenditures	(1,977)	(1,699)	(1,269)
Proceeds from nuclear decommissioning trust fund sales	22,905	17,202	7,312
Investment in nuclear decommissioning trust funds	(23,144)	(17,487)	(7,527)
Proceeds from sales of investments	0	0	95
Changes in Exelon intercompany money pool	0	0	13
Change in restricted cash	17	25	(45)
Other investing activities	(21)	(8)	(3)
Net cash flows used in investing activities	(2,220)	(1,967)	(1,424)
Cash flows from financing activities
Issuance of long-term debt	1,546	0	746
Retirement of long-term debt	(1,065)	(13)	(11)
Distribution to member	(2,276)	(1,545)	(2,357)
Contribution from member	57	86	54
Other financing activities	(8)	2	(3)
Net cash flows (used in) provided by financing activities	(1,746)	(1,470)	(1,571)
Increase (decrease) in cash and cash equivalents	(36)	1,008	(1)
Cash and cash equivalents at beginning of period	1,135	127	128
Cash and cash equivalents at end of period	1,099	1,135	127
COMMONWEALTH EDISON CO
Cash flows from operating activities
Net income	374	201	165
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion	495	465	441
Deferred income taxes and amortization of investment tax credits	265	258	82
Other non-cash operating activities	309	264	206
Changes in assets and liabilities:
Accounts receivable	29	(133)	(103)
Receivables from and payables to affiliates, net	(27)	112	(132)
Inventories	4	(4)	6
Accounts payable, accrued expenses and other current liabilities	(48)	43	120
Income taxes	(105)	(95)	(93)
Pension and non-pension postretirement benefit contributions	(214)	(55)	(53)
Other assets and liabilities	(62)	23	(119)
Net cash flows provided by operating activities	1,020	1,079	520
Cash flows from investing activities
Capital expenditures	(854)	(953)	(1,040)
Proceeds from sales of investments	41	0	0
Purchases of investments	(28)	0	0
Other investing activities	20	(5)	25
Net cash flows used in investing activities	(821)	(958)	(1,015)
Cash flows from financing activities
Changes in short-term debt	95	(310)	310
Issuance of long-term debt	191	1,324	705
Retirement of long-term debt	(208)	(760)	(147)
Retirement of long-term debt to financing affiliates	0	(429)	(349)
Contributions from parent	8	14	28
Dividends paid on common stock	(240)	0	0
Other financing activities	(1)	0	0
Net cash flows (used in) provided by financing activities	(155)	(161)	547
Increase (decrease) in cash and cash equivalents	44	(40)	52
Cash and cash equivalents at beginning of period	47	87	35
Cash and cash equivalents at end of period	91	47	87
PECO ENERGY CO
Cash flows from operating activities
Net income	353	325	507
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion	952	854	773
Deferred income taxes and amortization of investment tax credits	(210)	(220)	(186)
Other non-cash operating activities	141	194	86
Changes in assets and liabilities:
Accounts receivable	36	(120)	(158)
Receivables from and payables to affiliates, net	45	(1)	(58)
Inventories	76	(45)	40
Accounts payable, accrued expenses and other current liabilities	(123)	46	78
Income taxes	(18)	(12)	(51)
Pension and non-pension postretirement benefit contributions	(52)	(38)	(31)
Other assets and liabilities	(34)	(14)	(20)
Net cash flows provided by operating activities	1,166	969	980
Cash flows from investing activities
Capital expenditures	(388)	(392)	(339)
Change in restricted cash	1	1	1
Other investing activities	10	14	1
Net cash flows used in investing activities	(377)	(377)	(337)
Cash flows from financing activities
Changes in short-term debt	(95)	(151)	151
Issuance of long-term debt	250	941	172
Retirement of long-term debt	0	(604)	(17)
Retirement of long-term debt to financing affiliates	(709)	(609)	(671)
Changes in Exelon intercompany money pool	0	0	(45)
Repayment of receivable from parent	320	284	306
Contributions from parent	27	36	32
Dividends paid on common stock	(312)	(480)	(562)
Dividends paid on preferred securities	(4)	(4)	(4)
Other financing activities	(2)	0	0
Net cash flows (used in) provided by financing activities	(525)	(587)	(638)
Increase (decrease) in cash and cash equivalents	264	5	5
Cash and cash equivalents at beginning of period	39	34	29
Cash and cash equivalents at end of period	$ 303	$ 39	$ 34

Consolidated Balance Sheets - USD ($) $ in Millions	12 Months Ended
Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2009	Dec. 31, 2008
EXELON CORP
Current assets
Cash and cash equivalents	$ 2,010	$ 1,271
Restricted cash and investments	40	75
Accounts receivable, net
Customer	1,563	1,928
Other	486	324
Mark-to-market derivative assets	376	480
Inventories, net
Fossil fuel	198	315
Materials and supplies	559	528
Other	209	209
Total current assets	5,441	5,130
Property, plant and equipment, net	27,341	25,813
Deferred debits and other assets
Regulatory assets	4,872	5,940
Nuclear decommissioning trust funds	6,669	5,500
Investments	704	670
Investments in affiliates	20	45
Goodwill	2,625	2,625
Mark-to-market derivative assets	649	679
Other	859	1,144
Total deferred debits and other assets	16,398	16,603
Total assets	49,180	47,546
Current liabilities
Short-term borrowings	155	211
Long-term debt due within one year	639	29
Long-term debt to PECO Energy Transition Trust due within one year	415	319
Accounts payable	1,345	1,416
Mark-to-market derivative liabilities	198	212
Accrued expenses	923	1,151
Deferred income taxes	152	77
Other	411	396
Total current liabilities	4,238	3,811
Long-term debt	10,995	11,397
Long-term debt to PECO Energy Transition Trust	0	805
Long-term debt to financing trust	390	390
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	5,750	4,939
Asset retirement obligations	3,434	3,734
Pension obligations	3,625	4,111
Non-pension postretirement benefit obligations	2,180	2,255
Spent nuclear fuel obligation	1,017	1,015
Regulatory liabilities	3,492	2,520
Mark-to-market derivative liabilities	23	23
Other	1,309	1,412
Total deferred credits and other liabilities	20,830	20,009
Total liabilities	$ 36,453	$ 36,412
Commitments and contingencies
Preferred securities	$ 87	$ 87
Shareholders' equity
Common stock	8,923	8,816
Treasury stock, at cost (35 and 35 shares held at December 31, 2009 and December 31, 2008, respectively)	(2,328)	(2,338)
Retained earnings	8,134	6,820
Accumulated other comprehensive income (loss), net	(2,089)	(2,251)
Total shareholders' equity	12,640	11,047
Total liabilities and shareholders' equity	49,180	47,546
EXELON GENERATION CO LLC
Current assets
Cash and cash equivalents	1,099	1,135
Restricted cash	5	22
Accounts receivable, net
Customer	495	673
Other	112	108
Mark-to-market derivative assets	376	480
Mark-to-market derivative assets with affiliate	302	111
Receivables from affiliates	297	277
Inventories, net
Fossil fuel	102	143
Materials and supplies	470	435
Other	102	102
Total current assets	3,360	3,486
Property, plant and equipment, net	9,809	8,907
Deferred debits and other assets
Nuclear decommissioning trust funds	6,669	5,500
Investments	46	33
Receivable from affiliate	1	1
Mark-to-market derivative assets	639	662
Mark-to-market derivative assets with affiliate	671	345
Prepaid pension asset	1,027	949
Other	184	201
Total deferred debits and other assets	9,237	7,691
Total assets	22,406	20,084
Current liabilities
Long-term debt due within one year	26	12
Accounts payable	826	792
Mark-to-market derivative liabilities	198	212
Accrued expenses	670	761
Payables to affiliates	80	78
Deferred income taxes	399	256
Other	63	57
Total current liabilities	2,262	2,168
Long-term debt	2,967	2,502
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	2,707	1,968
Asset retirement obligations	3,316	3,536
Pension obligations	0	63
Non-pension postretirement benefit obligations	659	576
Spent nuclear fuel obligation	1,017	1,015
Payables to affiliates	2,228	1,336
Mark-to-market derivative liabilities	21	23
Other	437	331
Total deferred credits and other liabilities	10,385	8,848
Total liabilities	$ 15,614	$ 13,518
Commitments and contingencies
Member's equity
Membership interest	$ 3,464	$ 3,407
Undistributed earnings	2,169	2,323
Accumulated other comprehensive income, net	1,157	835
Total member's equity	6,790	6,565
Noncontrolling interest	2	1
Total equity	6,792	6,566
Total liabilities and equity	22,406	20,084
COMMONWEALTH EDISON CO
Current assets
Cash and cash equivalents	91	47
Restricted cash	2	1
Accounts receivable, net
Customer	676	798
Other	318	162
Inventories, net
Inventories, net	71	75
Regulatory assets	358	169
Deferred income taxes	39	32
Other	24	25
Total current assets	1,579	1,309
Property, plant and equipment, net	12,125	11,655
Deferred debits and other assets
Regulatory assets	1,096	858
Investments	28	34
Goodwill	2,625	2,625
Receivable from affiliate	1,920	1,291
Prepaid pension asset	907	847
Other	417	618
Total deferred debits and other assets	6,993	6,273
Total assets	20,697	19,237
Current liabilities
Short-term borrowings	155	60
Long-term debt due within one year	213	17
Accounts payable	274	307
Accrued expenses	282	306
Payables to affiliates	177	179
Customer deposits	131	119
Mark-to-market derivative liability with affiliate	302	111
Other	63	54
Total current liabilities	1,597	1,153
Long-term debt	4,498	4,709
Long-term debt to financing trust	206	206
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	2,648	2,369
Asset retirement obligations	95	174
Non-pension postretirement benefit obligations	241	203
Regulatory liabilities	3,145	2,440
Mark-to-market derivative liabilities with affiliate	669	345
Other	716	903
Total deferred credits and other liabilities	7,514	6,434
Total liabilities	$ 13,815	$ 12,502
Commitments and contingencies
Shareholders' equity
Common stock	$ 1,588	$ 1,588
Other paid-in capital	4,990	4,982
Retained earnings	304	170
Accumulated other comprehensive income (loss), net	0	(5)
Total shareholders' equity	6,882	6,735
Total liabilities and shareholders' equity	20,697	19,237
PECO ENERGY CO
Current assets
Cash and cash equivalents	303	39
Restricted cash	1	2
Accounts receivable, net
Customer	392	457
Other	120	39
Inventories, net
Fossil fuel	96	172
Materials and supplies	18	18
Deferred income taxes	65	78
Other	11	14
Total current assets	1,006	819
Property, plant and equipment, net	5,297	5,074
Deferred debits and other assets
Regulatory assets	1,834	2,597
Investments	18	15
Investments in affiliates	13	39
Receivable from affiliate	311	47
Other	540	578
Total deferred debits and other assets	2,716	3,276
Total assets	9,019	9,169
Current liabilities
Short-term borrowings	0	95
Long-term debt to PECO Energy Transition Trust due within one year	415	319
Accounts payable	164	204
Accrued expenses	74	120
Payables to affiliates	189	144
Customer deposits	65	74
Other	32	25
Total current liabilities	939	981
Long-term debt	2,221	1,971
Long-term debt to PECO Energy Transition Trust	0	805
Long-term debt to financing trust	184	184
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	2,241	2,451
Asset retirement obligations	24	24
Non-pension postretirement benefit obligations	296	283
Regulatory liabilities	317	49
Mark-to-market derivative liabilities	2	0
Mark-to-market derivative liabilities with affiliate	2	0
Other	141	152
Total deferred credits and other liabilities	3,023	2,959
Total liabilities	$ 6,367	$ 6,900
Commitments and contingencies
Preferred securities	$ 87	$ 87
Shareholders' equity
Common stock	2,318	2,291
Receivable from parent	(180)	(500)
Retained earnings	426	389
Accumulated other comprehensive income (loss), net	1	2
Total shareholders' equity	2,565	2,182
Total liabilities and shareholders' equity	$ 9,019	$ 9,169

Consolidated Statement of Changes in Equity - USD ($) shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2009	Dec. 31, 2008	Dec. 31, 2007
EXELON CORP
Statement [Line Items]
Beginning Balance	$ 11,047	$ 10,137	$ 10,007
Net income	2,707	2,737	2,736
Long-term incentive plan activity	112	217	328
Employee stock purchase plan issuances		19	16
Common stock purchases		(499)	(1,287)
Common stock dividends	(1,388)	(1,007)	(1,219)
Adoption of the fair value option for financial assets and liabilities, net of income taxes		0
Adoption of accounting for uncertain tax positions			(13)
Other comprehensive (loss) income, net of income taxes	162	(557)	(431)
Ending Balance	$ 12,640	$ 11,047	$ 10,137
EXELON CORP \| Common Stock
Statement [Line Items]
Beginning Balance (in shares)	692,953	689,183	682,474
Beginning Balance	$ 8,816	$ 8,579	$ 8,314
Long-term incentive plan activity (in shares)	1,612	3,452	6,455
Long-term incentive plan activity	$ 107	$ 217	$ 328
Employee stock purchase plan issuances (in shares)		318	254
Employee stock purchase plan issuances		$ 19	$ 16
Common stock purchases		$ 1	$ (79)
Ending Balance (in shares)	694,565	692,953	689,183
Ending Balance	$ 8,923	$ 8,816	$ 8,579
EXELON CORP \| Treasury Stock
Statement [Line Items]
Beginning Balance	(2,338)	(1,838)	(630)
Long-term incentive plan activity	10
Common stock purchases		(500)	(1,208)
Ending Balance	(2,328)	(2,338)	(1,838)
EXELON CORP \| Retained Earnings
Statement [Line Items]
Beginning Balance	6,820	4,930	3,426
Net income	2,707	2,737	2,736
Long-term incentive plan activity	(5)
Common stock dividends	(1,388)	(1,007)	(1,219)
Adoption of the fair value option for financial assets and liabilities, net of income taxes		160
Adoption of accounting for uncertain tax positions			(13)
Ending Balance	8,134	6,820	4,930
EXELON CORP \| Accumulated Other Comprehensive (Loss) Income
Statement [Line Items]
Beginning Balance	(2,251)	(1,534)	(1,103)
Adoption of the fair value option for financial assets and liabilities, net of income taxes		(160)
Other comprehensive (loss) income, net of income taxes	162	(557)	(431)
Ending Balance	(2,089)	(2,251)	(1,534)
EXELON GENERATION CO LLC
Statement [Line Items]
Beginning Balance	6,566	4,370	5,484
Net income	2,122	2,278	2,029
Adjustment of the adoption of accounting for uncertain tax positions		1
Distribution to member	(2,276)	(1,545)	(2,357)
Allocation of tax benefit from member	57	86	54
Adoption of the fair value option for financial assets and liabilities, net of income taxes		0
Adoption of accounting for uncertain tax positions			(43)
Transfer of AmerGen pension and non-pension postretirement benefit plans to Exelon, net of income taxes	20
Other comprehensive (loss) income, net of income taxes	302	1,376	(797)
Noncontrolling interest in income of consolidated entity	1
Ending Balance	6,792	6,566	4,370
EXELON GENERATION CO LLC \| Retained Earnings
Statement [Line Items]
Beginning Balance	2,323	1,429	1,800
Net income	2,122	2,278	2,029
Adjustment of the adoption of accounting for uncertain tax positions		1
Distribution to member	(2,276)	(1,545)	(2,357)
Adoption of the fair value option for financial assets and liabilities, net of income taxes		160
Adoption of accounting for uncertain tax positions			(43)
Ending Balance	2,169	2,323	1,429
EXELON GENERATION CO LLC \| Accumulated Other Comprehensive (Loss) Income
Statement [Line Items]
Beginning Balance	835	(381)	416
Adoption of the fair value option for financial assets and liabilities, net of income taxes		(160)
Transfer of AmerGen pension and non-pension postretirement benefit plans to Exelon, net of income taxes	20
Other comprehensive (loss) income, net of income taxes	302	1,376	(797)
Ending Balance	1,157	835	(381)
EXELON GENERATION CO LLC \| Membership Interest
Statement [Line Items]
Beginning Balance	3,407	3,321	3,267
Allocation of tax benefit from member	57	86	54
Ending Balance	3,464	3,407	3,321
EXELON GENERATION CO LLC \| Noncontrolling Interest
Statement [Line Items]
Beginning Balance	1	1	1
Noncontrolling interest in income of consolidated entity	1
Ending Balance	2	1	1
COMMONWEALTH EDISON CO
Statement [Line Items]
Beginning Balance	6,735	6,528	6,298
Net income	374	201	165
Allocation of tax benefit from parent	8	14	28
Appropriation of retained earnings for future dividends	0	0	0
Adjustment of the adoption of accounting for uncertain tax positions		(2)
Common stock dividends	(240)
Adoption of accounting for uncertain tax positions			33
Other comprehensive (loss) income, net of income taxes	5	(6)	4
Ending Balance	6,882	6,735	6,528
COMMONWEALTH EDISON CO \| Common Stock
Statement [Line Items]
Beginning Balance	1,588	1,588	1,588
Ending Balance	1,588	1,588	1,588
COMMONWEALTH EDISON CO \| Accumulated Other Comprehensive (Loss) Income
Statement [Line Items]
Beginning Balance	(5)	1	(3)
Other comprehensive (loss) income, net of income taxes	5	(6)	4
Ending Balance	0	(5)	1
COMMONWEALTH EDISON CO \| Other Paid-In Capital
Statement [Line Items]
Beginning Balance	4,982	4,968	4,906
Allocation of tax benefit from parent	8	14	28
Adoption of accounting for uncertain tax positions			34
Ending Balance	4,990	4,982	4,968
COMMONWEALTH EDISON CO \| Retained (Deficit) Earnings Unappropriated
Statement [Line Items]
Beginning Balance	(1,639)	(1,639)	(1,632)
Net income	374	201	165
Appropriation of retained earnings for future dividends	(374)	(199)	(171)
Adjustment of the adoption of accounting for uncertain tax positions		(2)
Adoption of accounting for uncertain tax positions			(1)
Ending Balance	(1,639)	(1,639)	(1,639)
COMMONWEALTH EDISON CO \| Retained Earnings Appropriated
Statement [Line Items]
Beginning Balance	1,809	1,610	1,439
Appropriation of retained earnings for future dividends	374	199	171
Common stock dividends	(240)
Ending Balance	1,943	1,809	1,610
PECO ENERGY CO
Statement [Line Items]
Beginning Balance	2,182	2,023	1,722
Net income	353	325	507
Preferred security dividends	(4)	(4)	(4)
Allocation of tax benefit from parent	27	36	32
Repayment of receivable from parent	320	284	306
Common stock dividends	(312)	(480)	(562)
Adoption of accounting for uncertain tax positions			23
Other comprehensive (loss) income, net of income taxes	(1)	(2)	(1)
Ending Balance	2,565	2,182	2,023
PECO ENERGY CO \| Common Stock
Statement [Line Items]
Beginning Balance	2,291	2,255	2,223
Allocation of tax benefit from parent	27	36	32
Ending Balance	2,318	2,291	2,255
PECO ENERGY CO \| Retained Earnings
Statement [Line Items]
Beginning Balance	389	548	584
Net income	353	325	507
Preferred security dividends	(4)	(4)	(4)
Common stock dividends	(312)	(480)	(562)
Adoption of accounting for uncertain tax positions			23
Ending Balance	426	389	548
PECO ENERGY CO \| Accumulated Other Comprehensive (Loss) Income
Statement [Line Items]
Beginning Balance	2	4	5
Other comprehensive (loss) income, net of income taxes	(1)	(2)	(1)
Ending Balance	1	2	4
PECO ENERGY CO \| Receivable from Parent
Statement [Line Items]
Beginning Balance	(500)	(784)	(1,090)
Repayment of receivable from parent	320	284	306
Ending Balance	$ (180)	$ (500)	$ (784)

Significant Accounting Policies (Exelon, Generation, ComEd and PECO)

12 Months Ended

Dec. 31, 2009

Statement [Line Items]

Significant Accounting Policies (Exelon, Generation, ComEd and PECO)

1. Significant Accounting Policies (Exelon, Generation, ComEd and PECO)

Description of Business (Exelon, Generation, ComEd and PECO)

Exelon is a utility services holding company engaged, through its subsidiaries, in the generation and energy delivery businesses discussed below. The generation business consists of the electric generating facilities, the wholesale energy marketing operations and competitive retail supply operations of Generation. The energy delivery businesses include the purchase and regulated retail sale of electricity and the provision of transmission and distribution services by ComEd in northern Illinois, including the City of Chicago, and by PECO in southeastern Pennsylvania, including the City of Philadelphia, and the purchase and regulated retail sale of natural gas and the provision of distribution services by PECO in the Pennsylvania counties surrounding the City of Philadelphia.

Basis of Presentation (Exelon, Generation, ComEd and PECO)

Through its business services subsidiary, BSC, Exelon provides its subsidiaries with a variety of support services at cost, including legal, human resources, financial, information technology and supply management services. The costs of BSC, including support services, are directly charged or allocated to the applicable subsidiaries using a cost-causative allocation method. Corporate governance type costs that cannot be directly assigned are allocated based on a Modified Massachusetts formula, which is a method that utilizes a combination of gross revenues, total assets and direct labor costs for the allocation base. The results of Exelon’s corporate operations are presented as “Other” within the consolidated financial statements and include intercompany eliminations unless otherwise disclosed.

Exelon owns 100% of all of its significant consolidated subsidiaries, either directly or indirectly, except for ComEd, of which Exelon owns more than 99%, and PECO, of which Exelon owns 100% of the common stock but none of PECO’s preferred securities. Exelon has reflected the third-party interests in ComEd, which totaled less than $1 million at December 31, 2009 and December 31, 2008 as equity and PECO’s preferred securities as preferred securities of subsidiaries in its consolidated financial statements.

Generation owns 100% of all of its significant consolidated subsidiaries, either directly or indirectly, except for Exelon SHC, Inc., of which Generation owns 99% and the remaining 1% is indirectly owned by Exelon, which is eliminated in Exelon’s consolidated financial statements. AmerGen, a wholly owned subsidiary of Generation through January 8, 2009, owned and operated the Clinton, Three Mile Island (TMI) Unit No. 1 and Oyster Creek generating stations. Effective January 8, 2009, AmerGen was merged into Generation, and Generation now holds the operating licenses for Clinton, TMI and Oyster Creek and owns and operates those plants.

Each of Generation’s, ComEd’s and PECO’s consolidated financial statements includes the accounts of their subsidiaries. All intercompany transactions have been eliminated.

Certain prior year amounts in Exelon’s, Generation’s and ComEd’s Consolidated Statements of Cash Flows, in Exelon’s and ComEd’s Consolidated Statements of Operations and in Exelon’s and Generation’s Consolidated Balance Sheets have been reclassified between line items for comparative purposes. The reclassifications did not affect net income or cash flows from operating activities of the Registrants. See Note 8—Derivative Financial Instruments for further discussion of the reclassifications to Exelon’s and Generation’s Consolidated Balance Sheets. The Registrants performed an evaluation of subsequent events for the accompanying financial statements and notes included in Part 2, ITEM 8 of this report through February 5, 2010, the date this Report was issued, to determine whether the circumstances warranted recognition and disclosure of those events or transactions in the financial statements as of December 31, 2009.

Use of Estimates (Exelon, Generation, ComEd and PECO)

The preparation of financial statements of each of the Registrants in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Areas in which significant estimates have been made include, but are not limited to, the accounting for nuclear decommissioning costs and other AROs, pension and other postretirement benefits, inventory reserves, allowance for uncollectible accounts, goodwill and asset impairments, derivative instruments, fixed asset depreciation, environmental costs, taxes and unbilled energy revenues.

Accounting for the Effects of Regulation (Exelon, ComEd and PECO)

Exelon, ComEd and PECO account for their regulated operations in accordance with accounting policies prescribed by the regulatory authorities having jurisdiction, principally the ICC and the PAPUC under state public utility laws and the FERC under various Federal laws. Exelon, ComEd and PECO apply the authoritative guidance for accounting for certain types of regulation, which requires ComEd and PECO to record in their consolidated financial statements the effects of rate regulation for utility operations that meet the following criteria: (1) third-party regulation of rates; (2) cost-based rates; and (3) a reasonable expectation that all costs will be recoverable from customers through rates. Exelon believes that it is probable that its currently recorded regulatory assets and liabilities will be recovered in future rates. However, Exelon, ComEd and PECO continue to evaluate their respective abilities to apply the authoritative guidance for accounting for certain types of regulation, including consideration of current events in their respective regulatory and political environments. If a separable portion of ComEd’s or PECO’s business was no longer able to meet the criteria discussed above, Exelon, ComEd and PECO would be required to eliminate from their consolidated financial statements the effects of regulation for that portion, which would have a material impact on their results of operations and financial positions. See Note 2—Regulatory Issues for additional information.

Segment Information (Generation, ComEd and PECO)

Exelon has three operating and reportable segments: Generation, ComEd and PECO. See Note 20—Segment Information for additional information regarding Exelon’s segments. Generation, ComEd and PECO each represent a single reportable segment. PECO has two operating segments, electric and gas delivery, which are aggregated into one reportable segment primarily due to their similar economic characteristics and the regulatory environments in which they operate.

Variable Interest Entities (Exelon, Generation, ComEd and PECO)

Exelon’s consolidated financial statements include the accounts of entities in which Exelon has a controlling financial interest, other than certain financing trusts of ComEd and PECO, and Generation’s and PECO’s proportionate interests in jointly owned electric utility property, after the elimination of intercompany transactions. A controlling financial interest is evidenced by either a voting interest greater than 50% or a risk and rewards model that identifies Exelon or one of its subsidiaries as the primary beneficiary of the VIE. Investments and joint ventures in which Exelon does not have a controlling financial interest and certain financing trusts of ComEd and PECO are accounted for under the equity or cost method of accounting.

Generation’s wholesale operations include the physical delivery and marketing of power obtained through its generating capacity, and long-, intermediate- and short-term contracts. Generation also has contracts to purchase fuel supplies for nuclear and fossil generation. These contracts and Generation’s membership in NEIL are discussed in further detail in Generation’s Note 18—Commitments and Contingencies. Generation has evaluated these contracts and determined that either, it has no variable interest in an entity, or where Generation does have a variable interest in an entity, it is not the primary beneficiary and, therefore, consolidation is not required.

Several of Generation’s long-term PPAs have been determined to be operating leases that have no residual value guarantees, bargain purchase options or other provisions that would cause these operating leases to be variable interests. For contracts where Generation has a variable interest, Generation has considered which interest holder has the power to direct the activities that most significantly impact the economics of the VIE and thus be considered the primary beneficiary and required to consolidate the entity. The primary beneficiary must also have exposure to significant losses or the right to receive significant benefits from the VIE. In general, the most significant activity of the VIEs is the operation and maintenance of the facilities providing the power to direct the entities’ activities. Facilities represent power plants, sources of uranium and fossil fuels, or plants used in the uranium conversion, enrichment and fabrication process. Generation does not have control over the operation and maintenance of the facilities considered VIEs and it does not bear operational risk of the facilities. Furthermore, Generation has no debt or equity investments in the entities, under the contracts Generation receives less than the majority of the output of the remaining expected useful life of the facilities, and Generation does not provide any other financial support through liquidity arrangements, guarantees or other commitments other than purchase commitments described in Generation’s Note 18—Commitments and Contingencies. Upon consideration of these factors, Generation does not consider it to be the primary beneficiary of these VIEs.

Generation has aggregated its contracts with VIEs into two categories, energy commitments and fuel purchase obligations, based on the similar risk characteristics and significance to Generation. As of the balance sheet date, the carrying amount of assets and liabilities in Generation’s Consolidated Balance Sheet that relate to its involvement with VIEs are predominately related to working capital accounts and generally represent the amounts owed by Generation for the deliveries associated with the current billing cycle under the contracts. Further, Generation has not provided or guaranteed any debt or equity support, liquidity arrangements, performance guarantees or other commitments associated with these contracts, so there is no significant potential exposure to loss as a result of its involvement with the VIEs.

The financing trust of ComEd, ComEd Financing III, and the financing trusts of PECO, namely PECO Trust III, PECO Trust IV and PETT, are not consolidated in Exelon’s, ComEd’s and PECO’s financial statements. PETT was created for the sole purpose of issuing debt obligations to securitize intangible transition property of PECO; and the other entities were created to issue mandatorily redeemable trust preferred securities.

ComEd and PECO have concluded that they do not have a variable interest in ComEd Financing III, PECO Trust III or PECO Trust IV as each Registrant financed its equity interest in the financing trusts through the issuance of subordinated debt. PECO has concluded that it is not the primary beneficiary of PETT because investors in the trust’s securities, not PECO, bear the majority of risk of loss related to those securities. See further discussion regarding the future consolidation of VIEs below under New Accounting Pronouncements.

ComEd and PECO, as the sponsors of the financing trusts are obligated to pay the operating expenses of the trusts. ComEd’s and PECO’s balance sheets include payable to affiliate amounts due to their respective financing trusts as well as investments in their respective trusts. See Note 21—Related-Party Transactions regarding information on the amounts recorded with respect to the financing trusts within the Consolidated Financial Statements.

The maximum exposure to loss as a result of PECO’s involvement with PETT was $7 million at December 31, 2009 and $30 million at December 31, 2008. PECO’s maximum exposure to loss is determined based on the current carrying value of investments made in PETT. PECO has not provided any non-contractually required financial support to PETT during the years ended December 31, 2009 and December 31, 2008. PECO had net undistributed losses of equity method investments related to PETT of $97 million and $73 million at December 31, 2009 and 2008, respectively.

Revenues (Exelon, Generation, ComEd and PECO)

Operating Revenues. Operating revenues are recorded as service is rendered or energy is delivered to customers. At the end of each month, the Registrants accrue an estimate for the unbilled amount of energy delivered or services provided to customers. See Note 3—Accounts Receivable for further information.

RTOs and ISOs. In RTO and ISO markets that facilitate the dispatch of energy and energy-related products, Exelon and Generation report sales and purchases conducted on a net hourly basis in either revenues or purchased power on Exelon’s and Generation’s Consolidated Statements of Operations, the classification of which depends on the net hourly activity. ComEd nets its spot market purchases against its spot market sales on an hourly basis, with the result recorded in purchased power expense. In 2009 and 2008, ComEd recorded an immaterial amount associated with hours where it had net spot market sales. ComEd did not record any net spot market sales during 2007.

Option Contracts, Swaps, and Commodity Derivatives. Certain option contracts and swap arrangements that meet the definition of derivative instruments are recorded at fair value with subsequent changes in fair value recognized as revenue or expenses, unless hedge accounting is applied. Premiums received and paid on option contracts are recognized as revenue or expensed over the terms of the contracts. If the derivatives meet hedging criteria, changes in fair value are recorded in OCI. ComEd has not elected hedge accounting for its financial swap contract with Generation. Since ComEd is entitled to full recovery of the costs of the financial swap contract in rates, ComEd records the fair value of the swap as well as an offsetting regulatory asset or liability on its Consolidated Balance Sheets.

Trading Activities. Exelon and Generation account for their trading activities under the provisions of the authoritative guidance for accounting for contracts involved in energy trading and risk management activities, which requires revenue and energy costs related to energy trading contracts to be presented on a net basis in the income statement. Commodity derivatives used for trading purposes are accounted for using the mark-to-market method with unrealized gains and losses recognized in operating revenues.

Income Taxes (Exelon, Generation, ComEd and PECO)

Deferred Federal and state income taxes are provided on all significant temporary differences between the book basis and the tax basis of assets and liabilities and for tax benefits carried forward. Investment tax credits previously utilized for income tax purposes have been deferred on the Registrants’ Consolidated Balance Sheets and are recognized in book income over the life of the related property. The Registrants account for uncertain income tax positions using a benefit recognition model with a two-step approach, a more-likely-than-not recognition criterion and a measurement attribute that measures the position as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement, in accordance with the authoritative guidance for accounting for uncertain tax positions. If it is not more likely than not that the benefit will be sustained on its technical merits, no benefit is recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. The Registrants recognize accrued interest related to unrecognized tax benefits in interest expense or interest income in other income and deductions on their Consolidated Statements of Operations.

Pursuant to the IRC and relevant state taxing authorities, Exelon and its subsidiaries file consolidated or combined income tax returns for Federal and certain state jurisdictions where allowed or required. See Note 10—Income Taxes for further information.

Taxes Directly Imposed on Revenue-Producing Transactions (Exelon, ComEd and PECO)

Exelon, ComEd and PECO present any tax assessed by a governmental authority that is directly imposed on a revenue-producing transaction between a seller and a customer on a gross (included in revenues and costs) basis. See Note 19—Supplemental Financial Information for ComEd’s and PECO’s utility taxes that are presented on a gross basis.

Losses on Reacquired and Retired Debt (Exelon, Generation, ComEd and PECO)

Consistent with rate recovery for ratemaking purposes, ComEd’s and PECO’s recoverable losses on reacquired long-term debt related to regulated operations are deferred and amortized to interest expense over the life of the new debt issued to finance the debt redemption or over the life of the original debt issuance if the debt is not refinanced. Losses on Exelon’s and Generation’s reacquired debt are recognized as incurred in the Registrants’ Consolidated Statements of Operations.

Cash and Cash Equivalents (Exelon, Generation, ComEd and PECO)

The Registrants consider investments purchased with an original maturity of three months or less to be cash equivalents.

Restricted Cash and Investments (Exelon, Generation, ComEd and PECO)

As of December 31, 2009 and 2008, Exelon Corporate’s restricted cash and investments primarily represented restricted funds for payment of medical, dental, vision and long-term disability benefits. As of December 31, 2009 and December 31, 2008, Generation’s restricted cash and investments primarily represented restricted funds for qualifying design, engineering and construction costs related to pollution control notes issued by Generation for an emissions-control facilities project and for payment of certain environmental liabilities. As of December 31, 2009 and 2008, PECO’s restricted cash primarily represented funds from the sales of assets that were subject to PECO’s mortgage indenture.

Restricted cash and investments not available to satisfy current liabilities are classified as noncurrent assets. As of December 31, 2009 and 2008, Exelon and Generation had restricted cash and investments in the NDT funds classified as noncurrent assets. As of December 31, 2009 and 2008, ComEd had short-term investments in Rabbi trusts classified as noncurrent assets.

Allowance for Uncollectible Accounts (Exelon, Generation, ComEd and PECO)

The allowance for uncollectible accounts reflects the Registrants’ best estimates of losses on the accounts receivable balances. The allowance is based on accounts receivable agings, historical experience and other currently available evidence. ComEd and PECO customers’ accounts are generally considered delinquent if the amount billed is not received by the time the next bill is issued, which normally occurs on a monthly basis. ComEd and PECO customers’ accounts are written off consistent with approved regulatory requirements. See Note 2—Regulatory Issues for additional information regarding the regulatory recovery of uncollectible accounts receivable at ComEd.

The following table summarizes the provision for uncollectible accounts for the years ended December 31, 2009, 2008 and 2007:


For the Year Ended December 31,	Exelon		Generation		ComEd		PECO
2009	$	149	$	2	$	85	$	63
2008		247		17		71		160
2007		132		4		58		71

Inventories (Exelon, Generation, ComEd and PECO)

Inventory is recorded at the lower of cost or market. Provisions are recorded for excess and obsolete inventory.

Fossil Fuel. Fossil fuel inventory includes the weighted average costs of stored natural gas, propane, coal and oil. The costs of natural gas, propane, coal and oil are generally included in inventory when purchased and charged to fuel expense when used or sold.

Materials and Supplies. Materials and supplies inventory generally includes the average costs of transmission, distribution and generating plant materials. Materials are generally charged to inventory when purchased and expensed or capitalized to plant, as appropriate, when installed or used.

Emission Allowances. Emission allowances are included in inventory and other deferred debits and are carried at the lower of weighted average cost or market and charged to fuel expense as they are used in operations. The Exelon and Generation emission allowance balances as of December 31, 2009 and 2008 were $78 million and $80 million, respectively.

Marketable Securities (Exelon, Generation, ComEd and PECO)

All marketable securities are reported at fair value. Marketable securities held in the NDT funds are classified as trading securities and all securities that are not held by the NDT funds are classified as available-for-sale securities. Realized and unrealized gains and losses, net of tax, on Generation’s NDT funds associated with the former ComEd and former PECO nuclear generating units (Regulatory Agreement Units) are included in regulatory liabilities at Exelon, ComEd, and PECO and in noncurrent payables to affiliates at Generation and in noncurrent receivables from affiliates at ComEd and PECO. Realized and unrealized gains and losses, net of tax, on Generation’s NDT funds associated with the former AmerGen nuclear generating units and the unregulated portions of the Peach Bottom nuclear generating units (Non-Regulatory Agreement Units) are included in earnings at Exelon and Generation. Unrealized gains and losses, net of tax, for ComEd’s and PECO’s available-for-sale securities are reported in OCI. Any decline in the fair value of ComEd’s and PECO’s available-for-sale securities below the cost basis is reviewed to determine if such decline is other-than-temporary. If the decline is determined to be other-than-temporary, the cost basis of the available-for-sale securities is written down to fair value as a new cost basis and the amount of the write-down is included in earnings. See Note 7—Fair Value of Financial Assets and Liabilities for further information regarding the other-than-temporary impairment recorded in the second quarter of 2009 by Exelon and ComEd related to ComEd’s Rabbi trust investments. See Note 11—Asset Retirement Obligations for information regarding marketable securities held by NDT funds and Note 19—Supplemental Financial Information for additional information regarding ComEd’s and PECO’s regulatory assets and liabilities.

Deferred Energy Costs (Exelon, ComEd and PECO)

ComEd’s electricity and transmission costs are recoverable or refundable under ComEd’s ICC and/or FERC approved retail rates. ComEd recovers or refunds the difference between the actual cost of electricity and transmission and the amount included in rates charged to its customers. Differences between the amounts billed to customers and the actual costs recoverable are deferred and recovered or refunded in future periods by means of prospective monthly adjustments to rates.

PECO’s natural gas rates are subject to a purchased gas cost adjustment clause designed to recover or refund the difference between the actual cost of purchased gas and the amount included in rates. Differences between the amounts billed to customers and the actual costs recoverable are deferred and recovered or refunded in future periods by means of prospective quarterly adjustments to rates.

See Note 19—Supplemental Financial Information for additional information regarding deferred energy costs for Exelon, ComEd and PECO.

Leases (Exelon, Generation, ComEd and PECO)

At the inception of a contract determined to be a lease, or as a result of a subsequent modification, the Registrants determine whether the lease is an operating or capital lease based upon its terms and characteristics. Several of Generation’s long-term PPAs, which have been determined to be operating leases, have significant contingent rental payments that are dependent on the future operating characteristics of the associated plants, such as plant availability. Generation recognizes contingent rental expense when it becomes probable of payment.

Property, Plant and Equipment (Exelon, Generation, ComEd and PECO)

Property, plant and equipment is recorded at original cost. Original cost includes labor and materials, construction overhead, when appropriate, capitalized interest and AFUDC, for regulated property at ComEd and PECO. The cost of repairs and maintenance, including planned major maintenance activities and minor replacements of property, is charged to maintenance expense as incurred.

For Generation, upon retirement, the cost of property is charged to accumulated depreciation in accordance with the composite method of depreciation. Upon replacement of an asset, the costs to remove the asset, net of salvage, is capitalized when incurred to gross plant as part cost of the newly installed asset and recorded to depreciation expense over the life of the new asset. Removal costs and salvage incurred for property that will not be replaced is charged to expense as incurred.

For ComEd and PECO, upon retirement, the cost of property, net of salvage, is charged to accumulated depreciation in accordance with the composite method of depreciation. ComEd’s depreciation expense includes the estimated cost of dismantling and removing plant from service upon retirement as these costs, as well as depreciation expense, are included in cost of service for rate-making purposes. ComEd’s removal costs reduce the related regulatory liability. PECO’s removal costs are capitalized to accumulated depreciation when incurred and recorded to depreciation expense over the life of the new asset constructed consistent with PECO’s regulatory recovery method.

See Note 4—Property, Plant and Equipment, Note 5—Jointly Owned Electric Utility Plant and Note 19—Supplemental Financial Information for additional information regarding property, plant and equipment.

Nuclear Fuel (Exelon and Generation)

The cost of nuclear fuel is capitalized and charged to fuel expense using the unit-of-production method. The estimated cost of disposal of SNF is established per the Standard Waste Contract with the DOE and is expensed through fuel expense at one mill ($.001) per kWh of net nuclear generation. On-site SNF storage costs are capitalized or expensed as incurred based upon the nature of the work performed. A portion of the storage costs are being reimbursed by the DOE since a DOE (or government owned) long-term storage facility has not been completed. See Note 12—Spent Nuclear Fuel Obligation for additional information.

Nuclear Outage Costs (Exelon and Generation)

Costs associated with nuclear outages, including planned major maintenance activities, are recorded in the period incurred.

New Site Development Costs (Exelon and Generation)

New site development costs represent the costs incurred in the assessment, design and construction of new power generating stations. Such costs are capitalized when management considers project completion to be likely, primarily based on management’s determination that the project is economically and operationally feasible, management and the Board of Directors have approved the project and have committed to a plan to develop it, and Exelon and Generation have received the required regulatory approvals or management believes the receipt of required regulatory approvals is probable. Through the year ended December 31, 2009, there have been no significant costs capitalized related to new site development; however, approximately $23 million, $26 million and $48 million of costs were expensed by Generation for the years ended December 31, 2009, 2008 and 2007, respectively, related to the possible construction of a new nuclear plant in Texas.

Capitalized Software Costs (Exelon, Generation, ComEd and PECO)

Costs incurred during the application development stage of software projects that are developed or obtained for internal use are capitalized. Such capitalized amounts are amortized ratably over the expected lives of the projects when they become operational, generally not to exceed five years. Certain other capitalized software costs are being amortized over longer lives, pursuant to regulatory approval or requirement. The following table presents net unamortized capitalized software costs and amortization of capitalized software costs by year:


Net unamortized software costs	Exelon		Generation		ComEd		PECO
December 31, 2009	$	279	$	67	$	123	$	55
December 31, 2008		259		45		106		55


Amortization of capitalized software costs	Exelon		Generation		ComEd		PECO
2009	$	105	$	24	$	29	$	15
2008		91		21		29		13
2007		79		19		24		11

Depreciation and Amortization (Exelon, Generation, ComEd and PECO)

Except for the amortization of nuclear fuel, depreciation is generally recorded over the estimated service lives of property, plant and equipment on a straight-line basis using the composite method. ComEd’s depreciation includes a provision for estimated removal costs as authorized by the ICC. The estimated service lives for ComEd and PECO are primarily based on the average service lives from the most recent depreciation study for each respective company. The estimated service lives of the nuclear-fuel generating facilities are based on the remaining useful lives of the stations, which assume a 20-year license renewal extension of the operating licenses (to the extent that such renewal has not yet been granted) for all of Generation’s operating nuclear generating stations. The estimated service lives of the fossil fuel generating facilities are based on the remaining useful lives of the stations, which Generation periodically evaluates based on feasibility assessments as well as economic and capital requirements. The estimated service lives of the hydroelectric generating facilities are based on the remaining useful lives of the stations, which assume a license renewal extension of the operating licenses. See Note 4—Property, Plant and Equipment for further information regarding depreciation.

Amortization of regulatory assets is provided over the recovery period specified in the related legislation or regulatory agreement. See Note 19—Supplemental Financial Information for additional information regarding Generation’s nuclear fuel, Generation’s ARC and the amortization of ComEd’s and PECO’s regulatory assets.

Asset Retirement Obligations (Exelon, Generation, ComEd and PECO)

The authoritative guidance for accounting for AROs requires the recognition of a liability for a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement is conditional on a future event. To estimate its decommissioning obligation related to its nuclear generating stations, Generation uses a probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple outcome scenarios based upon significant estimates and assumptions, including decommissioning cost studies, cost escalation studies, probabilistic cash flow models and discount rates. Decommissioning cost studies are updated, on a rotational basis, for each of Generation’s nuclear units at least every five years. Generation generally updates its ARO annually based on its review of updated cost studies and its annual evaluation of cost escalation factors and probabilities assigned to various scenarios. The liabilities associated with Exelon’s non-nuclear AROs are adjusted on an ongoing basis due to the passage of new laws and regulations and revisions to either the timing or amount of estimates of undiscounted cash flows and estimates of cost escalation factors. AROs are accreted each year to reflect the time value of money for these present value obligations through a charge to operating and maintenance expense in the Consolidated Statements of Operations or, in the case of the majority of ComEd’s and PECO’s accretion, through an increase to regulatory assets. See Note 11—Asset Retirement Obligations for additional information.

Capitalized Interest and AFUDC (Exelon, Generation, ComEd and PECO)

Exelon and Generation capitalize the costs of debt funds during construction used to finance non-regulated construction projects.

Exelon, ComEd and PECO apply the authoritative guidance for accounting for certain types of regulation to calculate AFUDC, which is the cost, during the period of construction, of debt and equity funds used to finance construction projects for regulated operations. AFUDC is recorded as a charge to construction work in progress and as a non-cash credit to AFUDC that is included in interest expense for debt-related funds and other income and deductions for equity-related funds. The rates used for capitalizing AFUDC are computed under a method prescribed by regulatory authorities.

The following table summarizes total cost incurred, capitalized interest and credits of AFUDC by year:


		Exelon		Generation		ComEd			PECO
2009	Total incurred interest ^(a)	$	786	$	162	$	322		$	189
	Capitalized interest		50		49		—			—
	Credits to AFUDC debt and equity		14		—		8			6

2008	Total incurred interest ^(a)	$	867	$	170	$	344		$	229
	Capitalized interest		34		33		—			—
	Credits to AFUDC debt and equity		2		—		(1	)		3

2007	Total incurred interest ^(a)	$	896	$	196	$	331		$	251
	Capitalized interest		30		30		—			—
	Credits to AFUDC debt and equity		19		—		16			3

(a)	Includes interest expense to affiliates.

Guarantees (Exelon, Generation, ComEd and PECO)

The Registrants recognize, at the inception of a guarantee, a liability for the fair market value of the obligations they have undertaken in issuing the guarantee, including the ongoing obligation to perform over the term of the guarantee in the event that the specified triggering events or conditions occur.

The liability that is initially recognized at the inception of the guarantee is reduced as the Registrants are released from risk under the guarantee. Depending on the nature of the guarantee, the release from risk of the Registrant may be recognized only upon the expiration or settlement of the guarantee or by a systematic and rational amortization method over the term of the guarantee. See Note 18—Commitments and Contingencies for additional information.

Asset Impairments (Exelon, Generation, ComEd and PECO)

Long-Lived Assets. Exelon, Generation, ComEd, and PECO evaluate the carrying value of their long-lived assets, excluding goodwill, when circumstances indicate the carrying value of those assets may not be recoverable. Conditions that could have an adverse impact on the cash flows and fair value of the long-lived assets are deteriorating business climate, including current energy and market conditions, condition of the asset, specific regulatory disallowance or plans to dispose of a long-lived asset significantly before the end of its useful life. The review of long-lived assets for impairment requires significant assumptions about operating strategies and estimates of future cash flows, which require assessments of current and projected market conditions. For the generation business, forecasting future cash flows requires assumptions regarding forecasted commodity prices for the sale of power, costs of fuel and the expected operations of assets. A variation in the assumptions used could lead to a different conclusion regarding the realizability of an asset and, thus, could have a significant effect on the consolidated financial statements. An impairment evaluation is based on an undiscounted cash flow analysis at the lowest level at which cash flows of the long-lived assets are largely independent of other groups of assets and liabilities. For the generation business, the lowest level of independent cash flows is determined by evaluation of several factors, including the geographic dispatch of the generation units and the hedging strategies related to those units. For ComEd and PECO, the lowest level of independent cash flows is determined by evaluation of several factors including the ratemaking jurisdiction in which they operate and the type of service or commodity. For ComEd the lowest level of independent cash flows is transmission and distribution and for PECO, the lowest level of independent cash flows is transmission, distribution and gas. Impairment may occur when the carrying value of the asset or asset group exceeds the future undiscounted cash flows. When the undiscounted cash flow analysis indicates a long-lived asset or asset group is not recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value. An impairment would require the affected Registrant to reduce both the long-lived asset and current period earnings by the amount of the impairment. See Note 4—Property, Plant and Equipment for a discussion of asset impairment evaluations made by Generation.

Exelon holds certain investments in direct financing leases. Exelon determines the investment in direct financing leases by incorporating an estimate of the residual values of the leased assets. On an annual basis, Exelon reviews the estimated residual values of these leased assets to determine if the current estimate of their residual value is lower than the one used at the start of the lease. In determining the estimate of the residual value the expectation of future market conditions, including commodity prices, is considered. If the estimated residual value is lower than at the start of the lease and the decline is considered to be other than temporary, a loss will be recognized with a corresponding reduction to the carrying amount of the investment. To date, no such losses have been recognized.

Goodwill. Goodwill represents the excess of the purchase price paid over the estimated fair value of the assets acquired and liabilities assumed in the acquisition of a business. Goodwill is not amortized, but is tested for impairment at least annually or on an interim basis if an event occurs or circumstances change that could reduce the fair value of a reporting unit below its carrying value. See Note 6—Intangible Assets for additional information regarding Exelon’s and ComEd’s goodwill.

Derivative Financial Instruments (Exelon, Generation, ComEd and PECO)

All derivatives are recognized on the balance sheet at their fair value unless they qualify for certain exceptions, including the normal purchases and normal sales exception. Additionally, derivatives that qualify and are designated for hedge accounting are classified as either hedges of the fair value of a recognized asset or liability or of an unrecognized firm commitment (fair value hedge) or hedges of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (cash flow hedge). For fair value hedges, changes in fair values for both the derivative and the underlying hedged exposure are recognized in earnings each period. For cash flow hedges, the portion of the derivative gain or loss that is effective in offsetting the change in the cost or value of the underlying exposure is deferred in accumulated OCI and later reclassified into earnings when the underlying transaction occurs. Gains and losses from the ineffective portion of any hedge are recognized in earnings immediately. For other derivative contracts that do not qualify or are not designated for hedge accounting, changes in the fair value of the derivatives are recognized in earnings each period. For energy-related derivatives entered into for proprietary trading purposes, which are subject to Exelon’s Risk Management Policy, changes in the fair value of the derivatives are recognized in earnings each period. Amounts classified in earnings are included in revenue, purchased power and fuel, or other, net on the Consolidated Statements of Operations. Cash inflows and outflows related to derivative instruments are included as a component of operating, investing or financing cash flows in the Consolidated Statement of Cash Flows, depending on the underlying nature of the Registrants’ hedged items.

Revenues and expenses on contracts that qualify, and are designated, as normal purchases and normal sales are recognized when the underlying physical transaction is completed. While these contracts are considered derivative financial instruments, they are not required to be recorded at fair value, but on an accrual basis of accounting. Normal purchases and normal sales are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period of time and price is not tied to an unrelated underlying derivative. As part of Generation’s energy marketing business, Generation enters into contracts to buy and sell energy to meet the requirements of its customers. These contracts include short-term and long-term commitments to purchase and sell energy and energy-related products in the retail and wholesale markets with the intent and ability to deliver or take delivery. If it were determined that a transaction designated as a normal purchase or a normal sale no longer met the exceptions, the fair value of the related contract would be recorded on the balance sheet and immediately recognized through earnings at Generation or offset by a regulatory asset or liability at ComEd and PECO. See Note 8—Derivative Financial Instruments for additional information.

Retirement Benefits (Exelon, Generation, ComEd and PECO)

Exelon’s defined benefit pension plans and postretirement benefit plans are accounted for and disclosed in accordance with applicable authoritative guidance. Generation, ComEd and PECO participate in Exelon’s defined benefit pension plans and postretirement plans. AmerGen sponsored a separate defined benefit pension plan and postretirement plan for its employees until the merger of AmerGen into Generation on January 8, 2009. Exelon became the sponsor of those plans at that date.

The measurement of the plan obligations and costs of providing benefits under these plans involve various factors, including numerous assumptions and accounting elections. The assumptions are reviewed annually and at any interim remeasurement of the plan obligations. The impact of assumption changes on pension and other postretirement benefit obligations is generally recognized over the expected average remaining service period of the employees rather than immediately recognized in the income statement.

Exelon calculates the expected return on pension and other postretirement benefit plan assets by multiplying the EROA by the MRV of plan assets at the beginning of the year, taking into consideration anticipated contributions and benefit payments to be made during the year. In determining MRV, the authoritative guidance for pensions and postretirement benefits allows the use of either fair value or a calculated value that recognizes changes in fair value in a systematic and rational manner over not more than five years. For pension plan assets, Exelon uses a calculated value that adjusts for 20% of the difference between fair value and expected MRV of plan assets. Use of this calculated value approach enables less volatile expected asset returns to be recognized as a component of pension cost from year to year. For other postretirement benefit plan assets, Exelon uses fair value to calculate the MRV. See Note 13—Retirement Benefits for additional discussion of Exelon’s accounting for retirement benefits.

Treasury Stock (Exelon)

Treasury shares are recorded at cost. Any shares of common stock repurchased are held as treasury shares unless cancelled or reissued.

New Accounting Pronouncements (Exelon, Generation, ComEd and PECO)

Exelon has identified the following new accounting pronouncements that have been recently adopted or issued that may affect the Registrants upon adoption.

Noncontrolling Interests in Consolidated Financial Statements

In December 2007 (and clarified in January 2010), the FASB issued authoritative guidance clarifying that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. With certain exceptions, this guidance requires that a change in a parent’s ownership interest in a subsidiary be reported as an equity transaction in the consolidated financial statements when it does not result in a change in control of the subsidiary. When a change in a parent’s ownership interest results in deconsolidation, a gain or loss should be recognized in the consolidated financial statements. This guidance was applied prospectively as of January 1, 2009, except for the presentation and disclosure requirements, which were applied retrospectively for all periods presented.

The adoption had no impact on Exelon’s consolidated financial statements. Generation reclassified its noncontrolling interest of a consolidated subsidiary from mezzanine equity to equity in its Consolidated Balance Sheets and Statements of Changes in Member’s Equity for all periods presented. The noncontrolling interest is eliminated in Exelon’s consolidated financial statements as it is owned by Exelon.

PECO reclassified preferred securities from shareholders’ equity to mezzanine equity within its Consolidated Balance Sheets for all periods presented and separately reflects its preferred security dividends on its Statement of Operations. On Exelon’s Consolidated Statements of Operations and Comprehensive Income, the dividends on PECO’s preferred securities are included in interest expense and have not been reflected separately as the amounts are not considered significant.

Derivative Instrument and Hedging Activity Disclosures

In March 2008, the FASB amended and expanded the disclosure requirements related to derivative instruments and hedging activities by requiring enhanced disclosures about how and why an entity uses derivative instruments, how an entity accounts for derivative instruments and related hedged items and how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. The revised guidance requires qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts of and gains and losses on derivative instruments and disclosures about credit-risk-related contingent features in derivative agreements. This guidance was effective for the Registrants as of January 1, 2009. Since this guidance provides only disclosure requirements, the adoption of this standard did not impact the Registrants’ results of operations, cash flows or financial positions. See Note 8—Derivative Financial Instruments for further information.

Pension and Other Postretirement Benefit Plan Asset Disclosures

In December 2008, the FASB issued authoritative guidance requiring additional disclosures for employers’ pension and other postretirement benefit plan assets. This guidance requires employers to disclose information about fair value measurements of plan assets, the investment policies and strategies for the major categories of plan assets, and significant concentrations of risk within plan assets. This guidance became effective for the Registrants as of December 31, 2009. As this guidance provides only disclosure requirements, the adoption of this standard did not impact the Registrants’ results of operations, cash flows or financial positions. See Note 13—Retirement Benefits for further information.

Fair Value Measurements

The FASB’s fair value measurement and disclosure guidance for all nonrecurring fair value measurements of nonfinancial assets and liabilities became effective for the Registrants as of January 1, 2009. See Note 7—Fair Value of Financial Assets and Liabilities for further information.

In April 2009, the FASB issued authoritative guidance clarifying that fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants under current market conditions. This new guidance requires an evaluation of whether there has been a significant decrease in the volume and level of activity for the asset or liability in relation to normal market activity for the asset or liability. If there has, transactions or quoted prices may not be indicative of fair value and an adjustment may need to be made to those prices to estimate fair value. Additionally, an entity must consider whether the observed transaction was orderly (i.e. not distressed or forced). If the transaction was orderly, the obtained price can be considered a relevant observable input for determining fair value. If the transaction is not orderly, other valuation techniques must be used when estimating fair value. This guidance was adopted for the period ending June 30, 2009. The adoption of this guidance did not have a material impact to the Registrants’ results of operations, cash flows or financial positions.

In August 2009, the FASB issued authoritative guidance clarifying the measurement of the fair value of a liability in circumstances when a quoted price in an active market for an identical liability is not available. The guidance emphasizes that entities should maximize the use of observable inputs in the absence of quoted prices when measuring the fair value of liabilities. This guidance became effective for the Registrants as of October 1, 2009 and did not have a material impact on the Registrants’ results of operations, cash flows or financial positions.

In September 2009, the FASB issued authoritative guidance that provides further clarification for measuring the fair value of investments in entities that meet the FASB’s definition of an investment company. This guidance permits a company to estimate the fair value of an investment using the NAV per share of the investment if the NAV is determined in accordance with the FASB’s guidance for investment companies as of the company’s measurement date. This creates a practical expedient to determining a fair value estimate and allows certain attributes of the investment (such as redemption restrictions) to not be considered in measuring fair value. Additionally, companies with investments within the scope of this guidance must disclose additional information related to the nature and risks of the investments. This guidance became effective for the Registrants as of December 31, 2009 and is required to be applied prospectively. Exelon’s pension and other postretirement benefit plan assets and Generation’s NDT fund investments contain certain investments, including alternative investments and commingled funds, which are within the scope of this guidance. As a result of the issuance of this guidance, Exelon and Generation reclassified investments in NDT commingled funds from Level 3 in the fair value hierarchy to Level 2 in the fair value hierarchy. However, as the fair value of these investments was already determined based on NAVs per fund share, this guidance did not have a material impact on the Registrants’ results of operations, cash flows or financial positions. See Note 13—Retirement Benefits and Note 7—Fair Value of Financial Assets and Liabilities for further information.

Fair Value of Financial Instruments Disclosures

In April 2009, the FASB issued revised authoritative guidance requiring disclosures about fair value of financial instruments, currently provided annually, to be included in interim financial statements. This guidance was adopted by the Registrants for the period ended June 30, 2009. Since this guidance provides only disclosure requirements, the adoption of this standard did not impact the Registrants’ results of operations, cash flows or financial positions. See Note 7—Fair Value of Financial Assets and Liabilities for further information.

Recognition and Presentation of Other-Than-Temporary Impairments

In April 2009, the FASB amended authoritative guidance related to accounting for certain investments in debt and equity securities and accounting for certain investments held by not-for-profit organizations. This revised guidance establishes a new method of recognizing and reporting other-than-temporary impairments of debt securities. If it is more likely than not that an impaired debt security will be sold before the recovery of its cost basis, either due to the investor’s intent to sell or because it will be required to sell the security, the entire impairment is recognized in earnings. Otherwise, only the portion of the impaired debt security related to estimated credit losses is recognized in earnings, while the remainder of the impairment is recorded in OCI and recognized over the remaining life of the debt security. In addition, the guidance expands the presentation and disclosure requirements for other- than-temporary impairments for both debt and equity securities. This guidance was adopted for the period ended June 30, 2009 and did not have a material impact on the Registrants’ results of operations, cash flows or financial positions. See Note 7—Fair Value of Financial Assets and Liabilities for further information.

Subsequent Events

In May 2009, the FASB issued authoritative guidance which incorporates the principles and accounting guidance for recognizing and disclosing subsequent events that originated as auditing standards into the body of authoritative literature issued by the FASB and prescribes disclosures regarding the date through which subsequent events have been evaluated. The Registrants are required to evaluate subsequent events through the date the financial statements are issued. This guidance was effective for the Registrants for the period ended June 30, 2009. Since this guidance is not intended to significantly change the current practice of reporting subsequent events, it did not have an impact on the Registrants’ results of operations, cash flows or financial positions.

Transfers of Financial Assets

In June 2009, the FASB issued authoritative guidance amending the accounting for the transfers of financial assets. Key provisions include (i) the removal of the concept of qualifying special purpose entities, (ii) the introduction of the concept of a participating interest, in circumstances in which a portion of a financial asset has been transferred and (iii) the requirement that to qualify for sale accounting, the transferor must evaluate whether it maintains effective control over transferred financial assets either directly or indirectly. Furthermore, this guidance requires enhanced disclosures about transfers of financial assets and a transferor’s continuing involvement. This guidance is effective for the Registrants beginning January 1, 2010 and is required to be applied prospectively. Currently, PECO’s agreement related to the sale of accounts receivable is accounted for as a sale. Under the new guidance, this agreement will be accounted for as a secured borrowing. As a result, beginning in the first quarter of 2010, the transferred accounts receivable of $225 million under this agreement will be recorded on PECO’s balance sheet with an offsetting short-term note payable of $225 million.

Consolidation of Variable Interest Entities

In June 2009, the FASB issued authoritative guidance to amend the manner in which entities evaluate whether consolidation is required for VIEs. The model for determining which enterprise has a controlling financial interest and is the primary beneficiary of a VIE has changed significantly under the new guidance. Previously, variable interest holders had to determine whether they had a controlling financial interest in a VIE based on a quantitative analysis of the expected gains and/or losses of the entity. In contrast, the new guidance requires an enterprise with a variable interest in a VIE to qualitatively assess whether it has a controlling financial interest in the entity, and if so, whether it is the primary beneficiary. Furthermore, this guidance requires that companies continually evaluate VIEs for consolidation rather than assessing based upon the occurrence of triggering events. This revised guidance also requires enhanced disclosures about how a company’s involvement with a VIE affects its financial statements and exposure to risks. This guidance became effective for the Registrants on January 1, 2010. As a result of the issuance of this new guidance, PECO consolidated PETT effective January 1, 2010. The consolidation of PETT had no impact on PECO’s results of operations. As of January 1, 2010, Exelon’s and PECO’s Consolidated Balance Sheets reflect PETT’s restricted cash of $413 million and $805 million for PETT’s long-term debt due to bondholders. PECO’s investment in PETT and long-term debt to PETT was eliminated in consolidation. The new guidance had no effect on ComEd. Generation does not anticipate a significant impact from the adoption of this accounting standard; however, due to evolving interpretations of this guidance, Generation has not fully completed its assessment.

Accounting Standards Codification

In June 2009, the FASB issued authoritative guidance which replaced the previous hierarchy of GAAP and establishes the FASB Codification as the single source of authoritative GAAP recognized by the FASB to be applied by nongovernmental entities. SEC rules and interpretive releases are also sources of authoritative GAAP for SEC registrants. This guidance modifies the GAAP hierarchy to include only two levels of GAAP: authoritative and nonauthoritative. This guidance was effective for the Registrants as of September 30, 2009. The adoption of this guidance did not impact the Registrants’ results of operations, cash flows or financial positions since the FASB Codification is not intended to change or alter existing GAAP.

Revenue Arrangements with Multiple Deliverables

In October 2009, the FASB issued authoritative guidance that amends existing guidance for identifying separate deliverables in a revenue-generating transaction where multiple deliverables exist, and provides guidance for allocating and recognizing revenue based on those separate deliverables. The guidance is expected to result in more multiple-deliverable arrangements being separable than under current guidance. This guidance is effective for the Registrants beginning on January 1, 2011 and is required to be applied prospectively to new or significantly modified revenue arrangements. The Registrants are currently assessing the impacts this guidance may have on their consolidated financial statements.

Fair Value Measurements Disclosures

In January 2010, the FASB issued authoritative guidance intended to improve disclosures about fair value measurements. The guidance requires entities to disclose significant transfers in and out of fair value hierarchy levels and the reasons for the transfers and to present information about purchases, sales, issuances and settlements separately in the reconciliation of fair value measurements using significant unobservable inputs (Level 3). Additionally, the guidance clarifies that a reporting entity should provide fair value measurements for each class of assets and liabilities and disclose the inputs and valuation techniques used for fair value measurements using significant other observable inputs (Level 2) and significant unobservable inputs (Level 3). This guidance is effective for interim and annual periods beginning after December 15, 2009 except for the disclosures about purchases, sales, issuances and settlements in the Level 3 reconciliation, which will be effective for interim and annual periods beginning after December 15, 2010. As this guidance provides only disclosure requirements, the adoption of this standard will not impact the Registrants’ results of operations, cash flows or financial positions.

Regulatory Issues (Exelon, Generation, ComEd and PECO)	12 Months Ended
Regulatory Issues (Exelon, Generation, ComEd and PECO)	Dec. 31, 2009
Statement [Line Items]
Regulatory Issues (Exelon, Generation, ComEd and PECO)	<div> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px; TEXT-INDENT: 4%"> </p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px"><font style="FONT-FAMILY: ARIAL" size="2"><b>2. Regulatory Issues (Exelon, Generation, ComEd and PECO)</b></font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: -6px"><font size="1"> </font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px; TEXT-INDENT: 4%"> <font style="FONT-FAMILY: ARIAL" size="2"><b><i>Illinois Settlement Agreement (Exelon, Generation and ComEd).</i></b> In July 2007, following extensive discussions with legislative leaders in Illinois, ComEd, Generation and other utilities and generators in Illinois reached an agreement (Illinois Settlement) with various parties concluding discussions of measures to address concerns about higher electric bills in Illinois without rate freeze, generation tax or other legislation that Exelon believes would be harmful to consumers of electricity, electric utilities, generators of electricity and the State of Illinois. Legislation reflecting the Illinois Settlement (Illinois Settlement Legislation) was signed into law in August 2007. The Illinois Settlement and the Illinois Settlement Legislation provide for the following, among other things:</font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px"><font size="1"> </font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px; MARGIN-LEFT: 4%"> <font style="FONT-FAMILY: ARIAL" size="2"><i>Rate Relief Programs</i></font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: -6px"><font size="1"> </font></p> <table style="BORDER-COLLAPSE: collapse" cellspacing="0" cellpadding="0" width="100%" border="0"> <tr> <td width="4%"><font size="1"> </font></td> <td valign="top" align="left" width="2%"><font style="FONT-FAMILY: ARIAL" size="2">•</font></td> <td valign="top" width="1%"> </td> <td valign="top" align="left"> <p align="left"><font style="FONT-FAMILY: ARIAL" size="2">Various Illinois electric utilities, their affiliates and generators of electricity in Illinois agreed to contribute approximately $1 billion over a period of four years (2007-2010) to programs to provide rate relief to Illinois electricity customers and funding for the IPA created by the Illinois Settlement Legislation. ComEd committed to issue $64 million in rate relief credits to customers or to fund various programs to assist customers. Generation committed to contribute an aggregate of $747 million, consisting of $435 million to pay ComEd for rate relief programs for ComEd customers, $307.5 million for rate relief programs for customers of other Illinois utilities and $4.5 million for partially funding operations of the IPA. The contributions are recognized in the financial statements of Generation and ComEd as rate relief credits are applied to customer bills by ComEd and other Illinois utilities or as operating expenses associated with the programs are incurred.</font></p> </td> </tr> </table> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: -6px"><font size="1"> </font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px; MARGIN-LEFT: 7%"> <font style="FONT-FAMILY: ARIAL" size="2">During the years ended December 31, 2009, 2008 and 2007, Generation and ComEd recognized net costs from their contributions pursuant to the Illinois Settlement in their Consolidated Statements of Operations as follows:</font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px"><font size="1"> </font></p> <table cellspacing="0" cellpadding="0" width="100%" align="center" border="0"> <tr> <td width="65%"></td> <td valign="bottom" width="10%"></td> <td></td> <td></td> <td valign="bottom" width="10%"></td> <td></td> <td></td> <td valign="bottom" width="10%"></td> <td></td> <td></td> </tr> <tr> <td valign="bottom" nowrap="nowrap"> <p style="WIDTH: 118pt; BORDER-BOTTOM: #000000 1px solid"> <font style="FONT-FAMILY: ARIAL" size="1"><b>Year Ended December 31, 2009</b></font></p> </td> <td valign="bottom"><font size="1"> </font></td> <td style="BORDER-BOTTOM: #000000 1px solid" valign="bottom" align="center" colspan="2"><font style="FONT-FAMILY: ARIAL" size="1"><b>Generation</b></font></td> <td valign="bottom"><font size="1"> </font></td> <td style="BORDER-BOTTOM: #000000 1px solid" valign="bottom" align="center" colspan="2"><font style="FONT-FAMILY: ARIAL" size="1"><b>ComEd</b></font></td> <td valign="bottom"><font size="1"> </font></td> <td style="BORDER-BOTTOM: #000000 1px solid" valign="bottom" align="center" colspan="2"><font style="FONT-FAMILY: ARIAL" size="1"><b>Total Credits Issued<br /> to ComEd Customers</b></font></td> </tr> <tr bgcolor="#CCEEFF"> <td valign="top"> <p style="MARGIN-LEFT: 1em; TEXT-INDENT: -1em"><font style="FONT-FAMILY: ARIAL" size="2">Credits to ComEd customers</font> <font style="FONT-FAMILY: ARIAL" size="1"><sup style="VERTICAL-ALIGN: baseline; BOTTOM: 0.8ex; POSITION: relative">(a)</sup></font></p> </td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: ARIAL" size="2">$</font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: ARIAL" size="2">45</font></td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: ARIAL" size="2">$</font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: ARIAL" size="2">8</font></td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: ARIAL" size="2">$</font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: ARIAL" size="2">53</font></td> </tr> <tr> <td valign="top"> <p style="MARGIN-LEFT: 1em; TEXT-INDENT: -1em"><font style="FONT-FAMILY: ARIAL" size="2">Credits to other Illinois utilities’ customers</font> <font style="FONT-FAMILY: ARIAL" size="1"><sup style="VERTICAL-ALIGN: baseline; BOTTOM: 0.8ex; POSITION: relative">(a)</sup></font></p> </td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: ARIAL" size="2"> </font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: ARIAL" size="2">53</font></td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: ARIAL" size="2"> </font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: ARIAL" size="2">n/a</font></td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: ARIAL" size="2"> </font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: ARIAL" size="2">n/a</font></td> </tr> <tr bgcolor="#CCEEFF"> <td valign="top"> <p style="MARGIN-LEFT: 1em; TEXT-INDENT: -1em"><font style="FONT-FAMILY: ARIAL" size="2">Other rate relief programs</font> <font style="FONT-FAMILY: ARIAL" size="1"><sup style="VERTICAL-ALIGN: baseline; BOTTOM: 0.8ex; POSITION: relative">(b)</sup></font></p> </td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: ARIAL" size="2"> </font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: ARIAL" size="2">— </font></td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: ARIAL" size="2"> </font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: ARIAL" size="2">1</font></td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: ARIAL" size="2"> </font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: ARIAL" size="2">n/a</font></td> </tr> <tr style="FONT-SIZE: 1px"> <td valign="bottom"></td> <td valign="bottom"> </td> <td style="BORDER-TOP: #000000 1px solid" valign="bottom"> </td> <td style="BORDER-TOP: #000000 1px solid" valign="bottom"> </td> <td valign="bottom"> </td> <td style="BORDER-TOP: #000000 1px solid" valign="bottom"> </td> <td style="BORDER-TOP: #000000 1px solid" valign="bottom"> </td> <td valign="bottom"> </td> <td style="BORDER-TOP: #000000 1px solid" valign="bottom"> </td> <td style="BORDER-TOP: #000000 1px solid" valign="bottom"> </td> </tr> <tr> <td valign="top"> <p style="MARGIN-LEFT: 1em; TEXT-INDENT: -1em"><font style="FONT-FAMILY: ARIAL" size="2">Total incurred costs</font></p> </td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: ARIAL" size="2">$</font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: ARIAL" size="2">98</font></td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: ARIAL" size="2">$</font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: ARIAL" size="2">9</font></td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: ARIAL" size="2">$</font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: ARIAL" size="2">53</font></td> </tr> <tr style="FONT-SIZE: 1px"> <td valign="bottom"></td> <td valign="bottom"> </td> <td style="BORDER-TOP: #000000 3px double" valign="bottom"> </td> <td style="BORDER-TOP: #000000 3px double" valign="bottom"> </td> <td valign="bottom"> </td> <td style="BORDER-TOP: #000000 3px double" valign="bottom"> </td> <td style="BORDER-TOP: #000000 3px double" valign="bottom"> </td> <td valign="bottom"> </td> <td style="BORDER-TOP: #000000 3px double" valign="bottom"> </td> <td style="BORDER-TOP: #000000 3px double" valign="bottom"> </td> </tr> </table> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px"><font size="1"> </font></p> <table cellspacing="0" cellpadding="0" width="100%" align="center" border="0"> <tr> <td width="65%"></td> <td valign="bottom" width="9%"></td> <td></td> <td></td> <td valign="bottom" width="9%"></td> <td></td> <td></td> <td valign="bottom" width="9%"></td> <td></td> <td></td> </tr> <tr> <td valign="bottom" nowrap="nowrap"> <p style="WIDTH: 118pt; BORDER-BOTTOM: #000000 1px solid"> <font style="FONT-FAMILY: ARIAL" size="1"><b>Year Ended December 31, 2008</b></font></p> </td> <td valign="bottom"><font size="1"> </font></td> <td style="BORDER-BOTTOM: #000000 1px solid" valign="bottom" align="center" colspan="2"><font style="FONT-FAMILY: ARIAL" size="1"><b>Generation</b></font></td> <td valign="bottom"><font size="1"> </font></td> <td style="BORDER-BOTTOM: #000000 1px solid" valign="bottom" align="center" colspan="2"><font style="FONT-FAMILY: ARIAL" size="1"><b>ComEd</b></font></td> <td valign="bottom"><font size="1"> </font></td> <td style="BORDER-BOTTOM: #000000 1px solid" valign="bottom" align="center" colspan="2"><font style="FONT-FAMILY: ARIAL" size="1"><b>Total Credits Issued<br /> to ComEd Customers</b></font></td> </tr> <tr bgcolor="#CCEEFF"> <td valign="top"> <p style="MARGIN-LEFT: 1em; TEXT-INDENT: -1em"><font style="FONT-FAMILY: ARIAL" size="2">Credits to ComEd customers</font> <font style="FONT-FAMILY: ARIAL" size="1"><sup style="VERTICAL-ALIGN: baseline; BOTTOM: 0.8ex; POSITION: relative">(a)</sup></font></p> </td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: ARIAL" size="2">$</font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: ARIAL" size="2">131</font></td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: ARIAL" size="2">$</font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: ARIAL" size="2">6</font></td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: ARIAL" size="2">$</font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: ARIAL" size="2">137</font></td> </tr> <tr> <td valign="top"> <p style="MARGIN-LEFT: 1em; TEXT-INDENT: -1em"><font style="FONT-FAMILY: ARIAL" size="2">Credits to other Illinois utilities’ customers</font> <font style="FONT-FAMILY: ARIAL" size="1"><sup style="VERTICAL-ALIGN: baseline; BOTTOM: 0.8ex; POSITION: relative">(a)</sup></font></p> </td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: ARIAL" size="2"> </font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: ARIAL" size="2">90</font></td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: ARIAL" size="2"> </font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: ARIAL" size="2">n/a</font></td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: ARIAL" size="2"> </font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: ARIAL" size="2">n/a</font></td> </tr> <tr bgcolor="#CCEEFF"> <td valign="top"> <p style="MARGIN-LEFT: 1em; TEXT-INDENT: -1em"><font style="FONT-FAMILY: ARIAL" size="2">Other rate relief programs</font> <font style="FONT-FAMILY: ARIAL" size="1"><sup style="VERTICAL-ALIGN: baseline; BOTTOM: 0.8ex; POSITION: relative">(b)</sup></font></p> </td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: ARIAL" size="2"> </font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: ARIAL" size="2">— </font></td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: ARIAL" size="2"> </font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: ARIAL" size="2">7</font></td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: ARIAL" size="2"> </font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: ARIAL" size="2">n/a</font></td> </tr> <tr style="FONT-SIZE: 1px"> <td valign="bottom"></td> <td valign="bottom"> </td> <td style="BORDER-TOP: #000000 1px solid" valign="bottom"> </td> <td style="BORDER-TOP: #000000 1px solid" valign="bottom"> </td> <td valign="bottom"> </td> <td style="BORDER-TOP: #000000 1px solid" valign="bottom"> </td> <td style="BORDER-TOP: #000000 1px solid" valign="bottom"> </td> <td valign="bottom"> </td> <td style="BORDER-TOP: #000000 1px solid" valign="bottom"> </td> <td style="BORDER-TOP: #000000 1px solid" valign="bottom"> </td> </tr> <tr> <td valign="top"> <p style="MARGIN-LEFT: 1em; TEXT-INDENT: -1em"><font style="FONT-FAMILY: ARIAL" size="2">Total incurred costs</font></p> </td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: ARIAL" size="2">$</font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: ARIAL" size="2">221</font></td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: ARIAL" size="2">$</font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: ARIAL" size="2">13</font></td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: ARIAL" size="2">$</font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: ARIAL" size="2">137</font></td> </tr> <tr style="FONT-SIZE: 1px"> <td valign="bottom"></td> <td valign="bottom"> </td> <td style="BORDER-TOP: #000000 3px double" valign="bottom"> </td> <td style="BORDER-TOP: #000000 3px double" valign="bottom"> </td> <td valign="bottom"> </td> <td style="BORDER-TOP: #000000 3px double" valign="bottom"> </td> <td style="BORDER-TOP: #000000 3px double" valign="bottom"> </td> <td valign="bottom"> </td> <td style="BORDER-TOP: #000000 3px double" valign="bottom"> </td> <td style="BORDER-TOP: #000000 3px double" valign="bottom"> </td> </tr> </table> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px"><font size="1"> </font></p> <table cellspacing="0" cellpadding="0" width="100%" align="center" border="0"> <tr> <td width="65%"></td> <td valign="bottom" width="9%"></td> <td></td> <td></td> <td valign="bottom" width="9%"></td> <td></td> <td></td> <td valign="bottom" width="9%"></td> <td></td> <td></td> </tr> <tr> <td valign="bottom" nowrap="nowrap"> <p style="WIDTH: 118pt; BORDER-BOTTOM: #000000 1px solid"> <font style="FONT-FAMILY: ARIAL" size="1"><b>Year Ended December 31, 2007</b></font></p> </td> <td valign="bottom"><font size="1"> </font></td> <td style="BORDER-BOTTOM: #000000 1px solid" valign="bottom" align="center" colspan="2"><font style="FONT-FAMILY: ARIAL" size="1"><b>Generation</b></font></td> <td valign="bottom"><font size="1"> </font></td> <td style="BORDER-BOTTOM: #000000 1px solid" valign="bottom" align="center" colspan="2"><font style="FONT-FAMILY: ARIAL" size="1"><b>ComEd</b></font></td> <td valign="bottom"><font size="1"> </font></td> <td style="BORDER-BOTTOM: #000000 1px solid" valign="bottom" align="center" colspan="2"><font style="FONT-FAMILY: ARIAL" size="1"><b>Total Credits Issued<br /> to ComEd Customers</b></font></td> </tr> <tr bgcolor="#CCEEFF"> <td valign="top"> <p style="MARGIN-LEFT: 1em; TEXT-INDENT: -1em"><font style="FONT-FAMILY: ARIAL" size="2">Credits to ComEd customers</font> <font style="FONT-FAMILY: ARIAL" size="1"><sup style="VERTICAL-ALIGN: baseline; BOTTOM: 0.8ex; POSITION: relative">(a)</sup></font></p> </td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: ARIAL" size="2">$</font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: ARIAL" size="2">246</font></td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: ARIAL" size="2">$</font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: ARIAL" size="2">33</font></td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: ARIAL" size="2">$</font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: ARIAL" size="2">279</font></td> </tr> <tr> <td valign="top"> <p style="MARGIN-LEFT: 1em; TEXT-INDENT: -1em"><font style="FONT-FAMILY: ARIAL" size="2">Credits to other Illinois utilities’ customers</font> <font style="FONT-FAMILY: ARIAL" size="1"><sup style="VERTICAL-ALIGN: baseline; BOTTOM: 0.8ex; POSITION: relative">(a)</sup></font></p> </td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: ARIAL" size="2"> </font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: ARIAL" size="2">157</font></td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: ARIAL" size="2"> </font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: ARIAL" size="2">n/a</font></td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: ARIAL" size="2"> </font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: ARIAL" size="2">n/a</font></td> </tr> <tr bgcolor="#CCEEFF"> <td valign="top"> <p style="MARGIN-LEFT: 1em; TEXT-INDENT: -1em"><font style="FONT-FAMILY: ARIAL" size="2">Other rate relief programs</font> <font style="FONT-FAMILY: ARIAL" size="1"><sup style="VERTICAL-ALIGN: baseline; BOTTOM: 0.8ex; POSITION: relative">(b)</sup></font></p> </td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: ARIAL" size="2"> </font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: ARIAL" size="2">— </font></td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: ARIAL" size="2"> </font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: ARIAL" size="2">8</font></td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: ARIAL" size="2"> </font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: ARIAL" size="2">n/a</font></td> </tr> <tr> <td valign="top"> <p style="MARGIN-LEFT: 1em; TEXT-INDENT: -1em"><font style="FONT-FAMILY: ARIAL" size="2">Funding of the IPA</font> <font style="FONT-FAMILY: ARIAL" size="1"><sup style="VERTICAL-ALIGN: baseline; BOTTOM: 0.8ex; POSITION: relative">(a)</sup></font></p> </td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: ARIAL" size="2"> </font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: ARIAL" size="2">5</font></td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: ARIAL" size="2"> </font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: ARIAL" size="2">— </font></td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: ARIAL" size="2"> </font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: ARIAL" size="2">n/a</font></td> </tr> <tr style="FONT-SIZE: 1px"> <td valign="bottom"></td> <td valign="bottom"> </td> <td style="BORDER-TOP: #000000 1px solid" valign="bottom"> </td> <td style="BORDER-TOP: #000000 1px solid" valign="bottom"> </td> <td valign="bottom"> </td> <td style="BORDER-TOP: #000000 1px solid" valign="bottom"> </td> <td style="BORDER-TOP: #000000 1px solid" valign="bottom"> </td> <td valign="bottom"> </td> <td style="BORDER-TOP: #000000 1px solid" valign="bottom"> </td> <td style="BORDER-TOP: #000000 1px solid" valign="bottom"> </td> </tr> <tr bgcolor="#CCEEFF"> <td valign="top"> <p style="MARGIN-LEFT: 1em; TEXT-INDENT: -1em"><font style="FONT-FAMILY: ARIAL" size="2">Total incurred costs</font></p> </td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: ARIAL" size="2">$</font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: ARIAL" size="2">408</font></td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: ARIAL" size="2">$</font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: ARIAL" size="2">41</font></td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: ARIAL" size="2">$</font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: ARIAL" size="2">279</font></td> </tr> <tr style="FONT-SIZE: 1px"> <td valign="bottom"></td> <td valign="bottom"> </td> <td style="BORDER-TOP: #000000 3px double" valign="bottom"> </td> <td style="BORDER-TOP: #000000 3px double" valign="bottom"> </td> <td valign="bottom"> </td> <td style="BORDER-TOP: #000000 3px double" valign="bottom"> </td> <td style="BORDER-TOP: #000000 3px double" valign="bottom"> </td> <td valign="bottom"> </td> <td style="BORDER-TOP: #000000 3px double" valign="bottom"> </td> <td style="BORDER-TOP: #000000 3px double" valign="bottom"> </td> </tr> </table> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 2px; WIDTH: 10%; LINE-HEIGHT: 8px; BORDER-BOTTOM: #000000 0.5pt solid"> </p> <table style="BORDER-COLLAPSE: collapse" cellspacing="0" cellpadding="0" width="100%" border="0"> <tr> <td valign="top" align="left" width="3%"><font style="FONT-FAMILY: ARIAL" size="1">(a)</font></td> <td valign="top" align="left"><font style="FONT-FAMILY: ARIAL" size="1">Recorded as a reduction in operating revenues</font></td> </tr> </table> <table style="BORDER-COLLAPSE: collapse" cellspacing="0" cellpadding="0" width="100%" border="0"> <tr> <td valign="top" align="left" width="3%"><font style="FONT-FAMILY: ARIAL" size="1">(b)</font></td> <td valign="top" align="left"><font style="FONT-FAMILY: ARIAL" size="1">Recorded as a charge to operating and maintenance expense</font></td> </tr> </table> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px"><font size="1"> </font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px; TEXT-INDENT: 4%"> <font style="FONT-FAMILY: ARIAL" size="2">As of December 31, 2009, Generation’s remaining costs to be recognized related to the rate relief commitment are $20 million, consisting of $13 million related to programs for ComEd customers and $7 million for programs for customers of other Illinois utilities. ComEd’s remaining costs to be recognized related to the rate relief commitment are $1 million as of December 31, 2009.</font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px"><font size="1"> </font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px; MARGIN-LEFT: 4%"> <font style="FONT-FAMILY: ARIAL" size="2"><i>Energy Efficiency and Renewable Energy</i></font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: -6px"><font size="1"> </font></p> <table style="BORDER-COLLAPSE: collapse" cellspacing="0" cellpadding="0" width="100%" border="0"> <tr> <td width="4%"><font size="1"> </font></td> <td valign="top" align="left" width="2%"><font style="FONT-FAMILY: ARIAL" size="2">•</font></td> <td valign="top" width="1%"> </td> <td valign="top" align="left"> <p align="left"><font style="FONT-FAMILY: ARIAL" size="2">Electric utilities in Illinois are required to include cost-effective energy efficiency resources in their plans to meet an incremental annual program energy savings requirement of 0.2% of energy delivered to retail customers for the year ended June 1, 2009, which increases annually to 2% of energy delivered in the year commencing June 1, 2015 and each year thereafter. Additionally, during the ten year period that began June 1, 2008, electric utilities must implement cost-effective demand response measures to reduce peak demand by 0.1% over the prior year for eligible retail customers. The energy efficiency and demand response goals are subject to rate impact caps each year. Utilities are allowed recovery of costs for energy efficiency and demand response programs, subject to approval by the ICC. In February 2008, the ICC issued an order approving substantially all of ComEd’s Energy Efficiency and Demand Response Plan, including cost recovery. This plan began in June 2008 and is designed to meet the Illinois Settlement Legislation’s energy efficiency and demand response goals for an initial three-year period, including reductions in delivered energy to all retail customers and in the peak demand of eligible retail customers. During the years ended December 31, 2009 and 2008, expenses related to energy efficiency and demand response programs consisted of $59 million and $25 million, respectively.</font></p> </td> </tr> </table> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: -6px"><font size="1"> </font></p> <table style="BORDER-COLLAPSE: collapse" cellspacing="0" cellpadding="0" width="100%" border="0"> <tr> <td width="4%"><font size="1"> </font></td> <td valign="top" align="left" width="2%"><font style="FONT-FAMILY: ARIAL" size="2">•</font></td> <td valign="top" width="1%"> </td> <td valign="top" align="left"> <p align="left"><font style="FONT-FAMILY: ARIAL" size="2">Since June 1, 2008, utilities have been required to procure cost-effective renewable energy resources in amounts that equal or exceed 2% of the total electricity that each electric utility supplies to its eligible retail customers. ComEd is also required to acquire amounts of renewable energy resources that will cumulatively increase this percentage to at least 10% by June 1, 2015, with an ultimate target of at least 25% by June 1, 2025, subject to customer rate cap limitations. All goals are subject to rate impact criteria set forth in the Illinois Settlement Legislation. Under a May 2008 ICC-approved RFP, ComEd procured RECs for the period June 2008 through May 2009. On May 13, 2009, the ICC approved the results of an RFP to procure RECs for the period June 2009 through May 2010. ComEd currently retires all RECs immediately upon purchase. Since June 2008, ComEd recovers procurement costs of RECs through rates. See Note 18—Commitments and Contingencies for further information regarding ComEd’s procurement of RECs.</font></p> </td> </tr> </table> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px"><font size="1"> </font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px; TEXT-INDENT: 4%"> <font style="FONT-FAMILY: ARIAL" size="2"><b><i>Illinois Procurement Proceedings (Exelon, Generation and ComEd).</i></b> ComEd is permitted to recover its electricity procurement costs from retail customers without mark-up. Beginning on January 1, 2007, ComEd procured 100% of energy to meet its load service requirements through ICC-approved staggered SFCs with various suppliers, including Generation. For the period from June 2008 to May 2009, the ICC approved an interim procurement plan under which ComEd procured energy to meet its load service requirements through an RFP for standard wholesale products, existing SFC and spot market purchases hedged by a five-year variable to fixed financial swap contract with Generation.</font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px"><font size="1"> </font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px; TEXT-INDENT: 4%"> <font style="FONT-FAMILY: ARIAL" size="2">Beginning in June 2009, under the Illinois Settlement Legislation, the IPA designs, and the ICC approves, an electricity supply portfolio for ComEd and administers a competitive process under which ComEd procures its electricity supply. On January 7, 2009, the ICC approved the IPA’s plan for procurement of ComEd’s expected energy requirements from June 2009 through May 2010, which includes approximately 38% of ComEd’s expected energy requirements purchased through the spot market and hedged by the financial swap contract with Generation. The remainder of ComEd’s expected energy requirements will be met through the existing SFC and standard products purchased as a result of the 2009 RFP process completed in May 2009. In addition, approximately 9% of ComEd’s energy requirements from June 2010 through May 2011 were procured through the 2009 RFP process.</font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px"><font size="1"> </font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px; TEXT-INDENT: 4%"> <font style="FONT-FAMILY: ARIAL" size="2">On September 30, 2009, the IPA filed its procurement plan with the ICC covering June 2010 through May 2015. On December 28, 2009, the ICC approved this plan which will result in approximately 66% of ComEd’s expected energy purchases for the June 2010 to May 2011 period being purchased through the spot market and hedged by the financial swap contract with Generation. The remainder of ComEd’s expected energy purchases would be met through the purchases of standard products in the 2009 and 2010 RFP processes. The IPA’s plan also includes a provision for procurement of approximately 3.5% of ComEd’s fixed-price load requirements from renewable energy resources utilizing long-term contracts beginning June 2012. The long term renewables purchased would count towards satisfying ComEd’s obligation under the state’s RPS. See Note 8—Derivative Financial Instruments for further discussion on the financial swap contract.</font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px"><font size="1"> </font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px; TEXT-INDENT: 4%"> <font style="FONT-FAMILY: ARIAL" size="2">The ICC has initiated a proceeding to reconcile the actual costs of power purchased in the January 2007 through May 2008 period with the costs for power that flowed through ComEd’s tariffs and were collected from customers. Because the Illinois Settlement Legislation has already deemed such costs to be prudently incurred, the reconciliation proceeding is not expected to have a significant impact on ComEd.</font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px"><font size="1"> </font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px; TEXT-INDENT: 4%"> <font style="FONT-FAMILY: ARIAL" size="2"><b><i>2005 Rate Case (Exelon and ComEd).</i></b> In August 2005, ComEd filed a rate case with the ICC to comprehensively revise its tariffs and to adjust rates for delivering electricity effective January 2007 (2005 Rate Case). ComEd proposed a revenue increase of $317 million. During 2006, the ICC issued various orders associated with this case, which resulted in a total annual rate increase of $83 million effective January 2007. ComEd and various other parties appealed the rate order to the courts. In September 2009, the Appellate Court of Illinois affirmed the ICC’s order and denied the appeals. Several parties have asked the Appellate Court to rehear various rate design issues addressed in the opinion. There is no set time in which the Court must act.</font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px"><font size="1"> </font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px; TEXT-INDENT: 4%"> <font style="FONT-FAMILY: ARIAL" size="2"><b><i>Original Cost Audit (Exelon and ComEd).</i></b> In connection with ComEd’s 2005 Rate Case proceeding, the ICC, with ComEd’s concurrence, ordered an “original cost” audit of ComEd’s distribution assets. In December 2007, the consulting firm completed the audit. The consulting firm’s results of the audit were reported to the ICC in April 2008, which presented its findings regarding accounting methodology, documentation and other matters, along with proposed adjustments. The audit report recommended gross plant disallowances of approximately $350 million, before reflecting accumulated depreciation. The basis for the disallowance recommendation on approximately $80 million of the costs was that the assets were misclassified between ComEd’s distribution and transmission operations. ComEd reclassified these costs in September 2007 and they were reflected correctly in ComEd’s rate case filed in October 2007 (2007 Rate Case).</font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px"><font size="1"> </font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px; TEXT-INDENT: 4%"> <font style="FONT-FAMILY: ARIAL" size="2">In April 2008, ComEd and the ICC Staff reached a stipulation (the stipulation) regarding various portions of contested issues in the Original Cost Audit as well as the 2007 Rate Case and agreed to make various joint recommendations to the ICC in the 2007 Rate Case. In September 2008, the ICC issued an order in the 2007 Rate Case, which reflected the joint recommendations made by the ICC Staff and ComEd and required ComEd to incur a charge of approximately $19 million (pre-tax) related to various items identified in the Original Cost Audit.</font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px"><font size="1"> </font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px; TEXT-INDENT: 4%"> <font style="FONT-FAMILY: ARIAL" size="2">The ICC opened a proceeding on the Original Cost Audit in May 2008. Under the terms of the stipulation, the ICC Staff agreed not to advocate that any of the proposed adjustments in the audit report be adopted other than those reflected in the 2007 Rate Case; however, the stipulation does not preclude other parties to the rate case or to the Original Cost Audit proceeding from taking positions contrary to the stipulation. The Illinois Attorney General submitted testimony and legal briefs suggesting that ComEd improperly changed the way it capitalized certain cable faults during the rate freeze period and therefore the rate base should be reduced by $121 million and ComEd should refund at least $42 million to customers. On January 12, 2010, the ICC issued an order rejecting the Illinois Attorney General’s recommendations in their entirety. The order is subject to rehearing and appeal.</font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px"><font size="1"> </font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px; TEXT-INDENT: 4%"> <font style="FONT-FAMILY: ARIAL" size="2"><b><i>2007 Rate Case (Exelon and ComEd).</i></b> ComEd filed the 2007 Rate Case with the ICC for approval to increase its delivery service revenue requirement by approximately $360 million. The ICC issued an order in the rate case approving a $274 million increase in ComEd’s annual revenue requirement, which became effective in September 2008. ComEd and several other parties have filed appeals of the rate order with the courts. ComEd cannot predict the timing of resolution or the results of the appeals. In the event the order is ultimately changed, the changes are expected to be prospective.</font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px"><font size="1"> </font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px; TEXT-INDENT: 4%"> <font style="FONT-FAMILY: ARIAL" size="2">The 2007 Rate Case filing also included a system modernization rider, which the ICC approved for the limited purpose of implementing a pilot program for AMI. The rider permits investments in AMI to be reflected in rates on a quarterly basis instead of waiting for the next rate case to begin recovery. On June 1, 2009, ComEd filed its proposed AMI pilot program with the ICC, which included revisions to the system modernization rider. On October 14, 2009, the ICC approved ComEd’s proposed AMI pilot program, with minor modifications, and recovery of substantially all program costs under the rider. The AMI pilot program allows ComEd to study the costs and benefits related to automated metering and to develop the cost estimate of full system-wide implementation of AMI. In addition, the program allows customers the ability to manage energy use, improve energy efficiency and lower energy bills. The Illinois Attorney General has appealed the ICC order approving the plan. The matter is not yet briefed.</font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px"><font size="1"> </font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px; TEXT-INDENT: 4%"> <font style="FONT-FAMILY: ARIAL" size="2">In August 2009, ComEd filed a request for $175 million of matching Federal stimulus grants with the DOE under the ARRA of 2009 to help finance AMI and Smart Grid technologies in Illinois; however, ComEd did not receive any of the matching grant awards announced by DOE in October 2009.</font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px"><font size="1"> </font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px; TEXT-INDENT: 4%"> <font style="FONT-FAMILY: ARIAL" size="2"><b><i>Transmission Rate Case (Exelon and ComEd).</i></b> ComEd’s transmission rates are established based on a formula that was approved by FERC in January 2008. FERC’s order establishes the agreed-upon treatment of costs and revenues in the determination of network service transmission rates and the process for updating the formula rate calculation on an annual basis.</font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px"><font size="1"> </font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px; TEXT-INDENT: 4%"> <font style="FONT-FAMILY: ARIAL" size="2">ComEd’s most recent annual formula rate update filed in May 2009 reflects actual 2008 expenses and investments plus forecasted 2009 capital additions. The time for parties to challenge the update has expired; no parties have raised challenges and ComEd will move to close the docket. The update resulted in a revenue requirement of $436 million resulting in an increase of approximately $6 million from the 2008 revenue requirement, plus an additional $4 million related to the 2008 true-up of actual costs. The 2009 revenue requirement of $440 million, which includes the 2008 true-up, became effective June 1, 2009 and is recovered over the period extending through May 31, 2010. The regulatory asset associated with the true-up is being amortized as the associated revenues are received. ComEd will continue to reflect its best estimate of its anticipated true-up in the financial statements.</font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px"><font size="1"> </font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px; TEXT-INDENT: 4%"> <font style="FONT-FAMILY: ARIAL" size="2"><b><i>Illinois Legislation for Recovery of Uncollectible Accounts (Exelon and ComEd).</i></b> Comprehensive legislation has been enacted in Illinois that provides utilities the ability to adjust their rates annually through a rider mechanism to reflect the increases or decreases in annual uncollectible accounts expenses starting with 2008 and prospectively. ComEd under-collected approximately $26 million during 2008 and approximately $44 million during 2009. On September 8, 2009, ComEd filed a proposed tariff in accordance with the legislation. On February 2, 2010, the ICC issued an order adopting ComEd’s proposed tariffs, with minor modifications.</font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px"><font size="1"> </font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px; TEXT-INDENT: 4%"> <font style="FONT-FAMILY: ARIAL" size="2">With the ICC approval of the tariff, ComEd is required to make a one-time contribution of approximately $10 million to the Supplemental Low-Income Energy Assistance Fund (the Fund). The Fund is used to assist low-income residential customers. As one way to assist such customers, the legislation creates a new percentage of income payment program (PIPP) that includes an arrearage reduction component for participating customers. The program will be paid for from the Fund and other state monies.</font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px"><font size="1"> </font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px; TEXT-INDENT: 4%"> <font style="FONT-FAMILY: ARIAL" size="2">As a result of the ICC order, ComEd will record the $70 million benefit and the $10 million one-time charge in the first quarter of 2010. ComEd will record a regulatory asset and an offsetting reduction in operating and maintenance expense for the cumulative under-collections from 2008 and 2009. Recovery of the initial regulatory asset will take place over an approximate 14-month time frame beginning in April 2010.</font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px"><font size="1"> </font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px; TEXT-INDENT: 4%"> <font style="FONT-FAMILY: ARIAL" size="2"><b><i>Pennsylvania Gas Distribution Rate Case (Exelon and PECO).</i></b> In October 2008, the PAPUC voted to approve the joint settlement related to PECO’s March 2008 filing providing for an increase of $77 million to its annual natural gas distribution revenue. As part of the settlement, PECO agreed to enhance its low-income programs as well as provide funding for new energy-efficiency programs to help customers manage their energy usage and gas bills. Additionally, PECO agreed not to file a new base rate case for natural gas distribution service before January 1, 2010. The approved rate adjustment became effective on January 1, 2009.</font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px"><font size="1"> </font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px; TEXT-INDENT: 4%"> <font style="FONT-FAMILY: ARIAL" size="2"><b><i>Pennsylvania Transition-Related Legislative and Regulatory Matters (Exelon, Generation and PECO).</i></b> In Pennsylvania, despite the recent decline in wholesale electricity market prices, there has been some continuing interest from elected officials in mitigating the potential impact of electric generation price increases on customers when rate caps expire. While PECO’s retail electric generation rate cap transition period does not end until December 31, 2010, transition periods have ended for seven other Pennsylvania electric distribution companies and, in most instances, post-transition electric generation price increases occurred. Over the past few years, elected officials in Pennsylvania have worked on developing legislation to address concerns over post-transition electric generation price increases. Measures suggested by legislators include rate-increase deferrals and phase-ins, rate-cap extensions, a generation tax and contributions of value by Pennsylvania utility companies toward rate-relief programs.</font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px"><font size="1"> </font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px; TEXT-INDENT: 4%"> <font style="FONT-FAMILY: ARIAL" size="2">On March 12, 2009, the PAPUC approved the settlement of PECO’s Market Rate Transition Phase-In Program. The program allows eligible residential and small-business electric-service customers to transition to market-priced generation through pre-payments made through 2010 that accrue interest at the statutory rate of 6% and are to be applied as credits to their bills in 2011 and 2012. Total collections under this program were not significant as of December 31, 2009.</font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px"><font size="1"> </font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px; TEXT-INDENT: 4%"> <font style="FONT-FAMILY: ARIAL" size="2">On June 9, 2009, the PAPUC entered an order instituting an investigation into whether PECO’s nuclear decommissioning cost adjustment clause, which is a mechanism that allows PECO to recover costs from customers for the decommissioning of seven former PECO nuclear units now owned by Generation, should continue after the termination of PECO’s competitive transition cost collections on December 31, 2010 and assigned the matter for alternative dispute resolution or the prompt scheduling of such hearings as may be necessary. On October 14, 2009, a prehearing conference was held and PECO agreed to report to the ALJ on settlement progress. Settlement discussions continue and PECO has been providing the ALJ with periodic reports on settlement progress. See Note 11—Asset Retirement Obligations for additional information.</font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px"><font size="1"> </font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px; TEXT-INDENT: 4%"> <font style="FONT-FAMILY: ARIAL" size="2"><b><i>Pennsylvania Procurement Proceedings (Exelon and PECO).</i></b> On June 2, 2009, the PAPUC entered an order approving the settlement of PECO’s DSP Program, under which PECO will provide default electric service following the expiration of electric generation rate caps on December 31, 2010. The DSP Program, which has a 29-month term beginning January 1, 2011 and ending May 31, 2013, complies with electric supply procurement guidelines set forth in Act 129. Under the settlement, PECO will also expand its low-income assistance initiatives and offer a market rate deferral program under which certain customers can elect to phase-in, with interest, any post-electric generation rate cap increases in 2011 if they exceed 25%.</font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px"><font size="1"> </font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px; TEXT-INDENT: 4%"> <font style="FONT-FAMILY: ARIAL" size="2">PECO’s default electric service customers have been divided into four procurement classes: a residential class, a small commercial class (for non-residential customers with peak demand up to 100 kW), a medium commercial class (for non-residential customers with peak demand of greater than 100 kW up to 500 kW) and a large commercial and industrial class (for non-residential customers with peak demand in excess of 500 kW).</font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px"><font size="1"> </font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px; TEXT-INDENT: 4%"> <font style="FONT-FAMILY: ARIAL" size="2">Seventy-five percent of the residential class load, 90% of the small commercial class load and 85% of the medium commercial class load will be served through competitively procured contracts for load-following, fixed price full requirements default electric supply. For the remaining portion of the residential class load, PECO will competitively procure through block contracts, which represent 20% of the load and will balance the remaining load through sales and purchases of energy in the PJM day-ahead wholesale “spot” energy market (spot market). For the remaining portion of the small commercial and medium commercial class loads, as well as the large commercial and industrial class load, PECO will competitively procure contracts for load-following, full requirements default electric supply with the price for energy in each contract set to be the hourly price of the spot market during the term of delivery. In addition, PECO will offer large commercial and industrial customers a fixed-price optional service during the first year of PECO’s DSP Program.</font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px"><font size="1"> </font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px; TEXT-INDENT: 4%"> <font style="FONT-FAMILY: ARIAL" size="2">In 2009, PECO completed two competitive procurements in accordance with the DSP Program for electric supply for default electric service customers commencing January 2011. As of December 31, 2009, PECO has entered into contracts with terms of 17 to 29 months covering 49% of planned full requirements contracts for the residential customer class, contracts with 17-month terms covering 24% of planned full requirements contracts for the small commercial customer class and contracts with 17-month terms covering 16% of planned full requirements contracts for the medium commercial customer class. PECO also entered into block contracts with 12-month terms for a total of 80 MW for service to the residential customer class in 2011. PECO will conduct seven additional competitive procurements in accordance with the DSP Program.</font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px"><font size="1"> </font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px; TEXT-INDENT: 4%"> <font style="FONT-FAMILY: ARIAL" size="2"><b><i>Smart Meter and Smart Grid Investments (Exelon and PECO).</i></b> PECO is planning to spend up to approximately $650 million on its smart meter and smart grid infrastructure. On November 25, 2009, PECO filed a joint petition for partial settlement of its $550 million Smart Meter Procurement and Installation Plan with the PAPUC, which was filed on August 14, 2009 in accordance with the requirements of Act 129. PECO is requesting PAPUC approval to install more than 1.6 million smart meters and deploy advanced communication networks over a 15 year period. The first phase of the plan includes the procurement and deployment of automated meter infrastructure and an initial deployment of 100,000 smart meters over the next three years. On January 28, 2010, the ALJ issued an initial decision approving the partial settlement and determining remaining cost allocation issues subject to final PAPUC approval. PECO plans to file for PAPUC approval of an initial dynamic pricing and customer acceptance program in June 2010 and for approval of a universal meter deployment plan for its remaining customers in 2012.</font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px"><font size="1"> </font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px; TEXT-INDENT: 4%"> <font style="FONT-FAMILY: ARIAL" size="2">On August 6, 2009, PECO filed with the DOE an application seeking $200 million in ARRA of 2009 matching grant funds under the Smart Grid Investment Grant Program. PECO’s “Smart Future Greater Philadelphia” project will increase the number of smart meters initially installed to 600,000, accelerate universal smart meter deployment by five years and increase Smart Grid investments up to approximately $100 million over the next three years. On October 27, 2009, the DOE announced its intent to award PECO a $200 million stimulus grant to fund its smart meter and smart grid investments. Assuming successful completion of the DOE negotiations and PECO’s receipt of the full award on reasonable terms, PECO is committed to implementing expanded initial deployment of 600,000 smart meters within three years and then accelerating universal smart meter deployment from 15 years to 10 years.</font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px"><font size="1"> </font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px; TEXT-INDENT: 4%"> <font style="FONT-FAMILY: ARIAL" size="2"><b><i>Energy Efficiency and Alternative Energy Programs (Exelon and PECO).</i></b></font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px; TEXT-INDENT: 4%"> <font style="FONT-FAMILY: ARIAL" size="2"><i>Energy Efficiency Programs.</i> Pursuant to Act 129’s energy efficiency and conservation/demand (EE&C) reduction targets, PECO filed its EE&C plan with the PAPUC on July 1, 2009. The plan set forth how PECO will reduce electric consumption by at least 1% in its service territory by May 31, 2011 from expected consumption for the period June 1, 2009 through May 31, 2010 and by 3% by May 31, 2013. In accordance with Act 129, PECO also plans to reduce peak demand by a minimum of 4.5% of PECO’s annual system peak demand in the 100 hours of highest demand by May 31, 2013, measured against its peak demand during the period of June 1, 2007 through May 31, 2008. If PECO fails to achieve the required reductions in consumption within the stated deadlines, PECO will be subject to civil penalties of up to $20 million, which would not be recoverable from ratepayers. Act 129 mandates that the total cost of any EE&C plan may not exceed 2% of the electric company’s total annual revenue as of December 31, 2006. On October 28, 2009, the PAPUC issued an order providing partial approval of PECO’s EE&C plan. The approved plan totals more than $330 million and includes the CFL program, weatherization programs, an energy efficiency appliance rebate and trade-in program, rebates and energy efficiency programs for non-profit, educational, governmental and business customers, customer incentives for energy management programs and incentives to help customers reduce energy demand during peak periods. On December 24, 2009, PECO filed revisions to the portions of the plan not approved based on PAPUC feedback.</font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px"><font size="1"> </font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px; TEXT-INDENT: 4%"> <font style="FONT-FAMILY: ARIAL" size="2"><i>Alternative Energy Portfolio Standards.</i> In November 2004, Pennsylvania adopted the AEPS Act. The AEPS Act mandated that beginning in 2007, or following the end of an electric distribution company’s retail electric generation rate cap transition period, certain percentages of electric energy sold by an electric distribution company or electric generation supplier to Pennsylvania retail electric customers shall be generated from certain alternative energy resources as measured in AECs. The requirement for electric energy that must come from Tier I alternative energy resources (including solar or wind power, low-impact hydropower, geothermal energy, biologically derived methane gas, fuel cells, biomass energy generated within Pennsylvania and coal mine methane) ranges from 1.5% to 8.0% and the requirement for Tier II alternative energy resources (including waste coal, biomass energy generated outside of Pennsylvania, demand-side management, large-scale hydropower, municipal solid waste, generation of electricity utilizing by-products of the pulping process and wood, distributed generation systems and integrated combined coal gasification technology) ranges from 4.2% to 10.0%. These Tier I and Tier II alternative energy resources include acceptable energy sources as set forth in Act 129 in addition to those outlined in the AEPS Act. The AEPS Act mandates the 8.0% requirement for Tier I resources and the 10.0% requirement for Tier II resources must be met by the year ending May 31, 2021.</font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px"><font size="1"> </font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px; TEXT-INDENT: 4%"> <font style="FONT-FAMILY: ARIAL" size="2">The Pennsylvania Legislature is currently considering HB 80, which, if enacted into law, would increase the minimum required percentage of electric energy purchased and sold to retail electric customers from alternative energy resources and extend the period for such purchases and sales. HB 80 would increase the Tier 1 and solar purchase and sale requirements, limit eligible solar purchases to Pennsylvania generating sources and incorporate advanced coal combustion with limited carbon emissions as an acceptable alternative energy resource. Generation has proposed amendments to include extended nuclear uprates as a qualifying alternative energy source.</font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px"><font size="1"> </font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px; TEXT-INDENT: 4%"> <font style="FONT-FAMILY: ARIAL" size="2">In 2007, the PAPUC approved PECO’s plan to acquire and bank approximately 450,000 non-solar Tier I AECs (corresponding to the expected annual output of approximately 240 MW of wind power) annually for a five-year term in order to prepare for 2011, the first year of PECO’s required compliance following the completion of its electric generation rate cap transition period. The banked AECs may be used in either of the two consecutive AEPS reporting periods after PECO’s electric generation rate cap transition period. All costs incurred in connection with AEC procurement prior to 2011 are being deferred as a regulatory asset with a return on the unamortized balance and will be recovered from customers in 2011. Those costs, and PECO’s AEPS Act compliance costs incurred thereafter, will be recovered from customers on a full and current basis through a reconcilable ratemaking mechanism as contemplated by the AEPS Act. In conformance with the approved plan, PECO has entered into five-year agreements with accepted bidders, including Generation, totaling 452,000 AECs to be purchased annually.</font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px"><font size="1"> </font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px; TEXT-INDENT: 4%"> <font style="FONT-FAMILY: ARIAL" size="2">On August 27, 2009, the PAPUC approved a settlement of PECO’s petition for early procurement and banking of up to 8,000 solar Tier 1 AECs annually for ten years. PECO’s procurement would employ the same surcharge cost-recovery mechanism that the PAPUC previously approved for non-solar Tier 1 AECs. The settlement provides for no cap on bid price, provides the PAPUC a 10 calendar day review period, permits facilities capable of generating a minimum of 300 AECs annually to bid and provides that no changes to the agreement with AEC suppliers will be accepted after PAPUC approval. On January 25, 2010, the PAPUC approved the fixed-price agreement solar AEC procurement results. PECO plans to enter into the fixed-price agreements by February 8, 2010.</font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px"><font size="1"> </font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px; TEXT-INDENT: 4%"> <font style="FONT-FAMILY: ARIAL" size="2"><b><i>PJM Transmission Rate Design (Exelon, ComEd and PECO).</i></b> PJM Transmission Rate Design specifies the rates for transmission service charged to customers within PJM. Currently, ComEd and PECO incur costs based on the existing rate design, which charges customers based on the cost of the existing transmission facilities within their load zone and the cost of new transmission facilities based on those who benefit. In April 2007, FERC issued an order concluding that PJM’s current rate design for existing facilities is just and reasonable and should not be changed. In the same order, FERC held that the costs of new facilities 500 kV and above should be socialized across the entire PJM footprint and that the costs of new facilities less than 500 kV should be allocated to the customers of the new facilities who caused the need for those facilities. In the short term, based on new transmission facilities approved by PJM, it is likely that allocating across PJM the costs of new facilities 500 kV and above will increase charges to ComEd and reduce charges to PECO, as compared to the allocation methodology in effect before the FERC order. After FERC ultimately denied all requests for rehearing on all issues, several parties filed petitions in the U.S. Court of Appeals for the Seventh Circuit for review of the decision. On August 6, 2009, the court issued its decision affirming FERC’s order with regard to the costs of existing facilities but reversing and remanding to FERC for further consideration its decision with regard to the costs of new facilities 500 kV and above. On September 21, 2009, two parties filed a petition for rehearing by the full court concerning the court’s decision to remand to FERC the part of the decision regarding the allocation of the costs of new facilities 500 kV and above. On October 20, 2009, the court denied the rehearing petition. On January 21, 2010, FERC issued an order establishing paper hearing procedures to supplement the record. ComEd anticipates that all impacts of any rate design changes effective after December 31, 2006 should be recoverable through retail rates and, thus, the rate design changes are not expected to have a material impact on ComEd’s results of operations, cash flows or financial position. PECO also has the right to file with the PAPUC for a change in retail rates to reflect changes in its wholesale transmission costs. PECO cannot predict the long-term impact of any rate design changes due to the uncertainty as to whether new facilities will be built and how the costs of new facilities less than 500 kV will be allocated; however, the impact may be material to its results of operations, cash flows, or financial position.</font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px"><font size="1"> </font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px; TEXT-INDENT: 4%"> <font style="FONT-FAMILY: ARIAL" size="2"><b><i>PJM-MISO Regional Rate Design (Exelon, ComEd and PECO).</i></b> The current PJM-MISO Regional Rate Design is used to specify the pricing of transmission service between PJM and MISO and impacts ComEd and PECO due to purchases by suppliers from MISO. In August 2007, ComEd and PECO and several other transmission owners in PJM and MISO, as directed by a FERC order, filed with FERC to continue the existing transmission rate design between PJM and MISO. Additional transmission owners and certain other entities filed protests urging FERC to reject the filing. In September 2007, a complaint was filed asking FERC to find that the PJM-MISO rate design was unjust and unreasonable and to substitute a rate design that socializes the costs of all existing and new transmission facilities of 345 kV and above across PJM and MISO. In December 2008, FERC denied a request for rehearing of these orders and an appeal was filed in the United States Court of Appeals. On November 9, 2009, the court dismissed the appeal at the request of the appellant.</font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px"><font size="1"> </font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px; TEXT-INDENT: 4%"> <font style="FONT-FAMILY: ARIAL" size="2"><b><i>Authorized Return on Rate Base (Exelon, ComEd and PECO).</i></b> In the September 2008 order in the 2007 Rate Case, the ICC authorized a return on ComEd’s distribution rate base using a weighted average debt and equity return of 8.36%, an increase over the 8.01% return previously authorized in the 2005 Rate Case. ComEd’s formula transmission rate currently provides for a weighted average debt and equity return on transmission rate base of 9.43%, an increase over the 9.37% return previously authorized. As part of the FERC-approved settlement of ComEd’s 2007 transmission rate case, the rate of return on common equity is 11.5% and the common equity component of the ratio used to calculate the weighted average debt and equity return for the formula transmission rate is currently capped at 57%. This equity cap is reduced to 56% in June 2010 and 55% in June 2011 and subsequent years. This transmission rate base return is updated annually in accordance with the formula-based rate calculation discussed above.</font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px"><font size="1"> </font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px; TEXT-INDENT: 4%"> <font style="FONT-FAMILY: ARIAL" size="2">PECO’s transition period includes caps on electric generation rates that will expire on December 31, 2010 pursuant to the Competition Act. The electric distribution and transmission components of PECO’s rates continue to be regulated. PECO’s most recently approved weighted average debt and equity return on electric rate base, which included electric generation, was 11.23% (approved in 1990). PECO’s purchased gas cost rates are not subject to caps and do not earn a return. As part of the gas distribution rate case filed in March 2008, PECO requested that the PAPUC authorize it to establish base rates for natural gas distribution service using a weighted average debt and equity return on gas rate base of 8.90%. The joint settlement petition in that matter, approved in October 2008 by the PAPUC, did not specify the rate of return upon which the settlement rates are based, but rather provided for an increase in annual revenue. Prior to the 2008 gas distribution rate case, the most recently approved weighted average debt and equity return on gas rate base was 11.45% (approved in 1988).</font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px"><font size="1"> </font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px; TEXT-INDENT: 4%"> <font style="FONT-FAMILY: ARIAL" size="2"><b><i>Market-Based Rates (Exelon, Generation, ComEd and PECO).</i></b> Generation, ComEd and PECO are public utilities for purposes of the Federal Power Act and are required to obtain FERC’s acceptance of rate schedules for wholesale electricity sales. Currently, Generation, ComEd and PECO have authority to execute wholesale electricity sales at market-based rates. As is customary with market-based rate schedules, FERC has reserved the right to suspend market-based rate authority on a retroactive basis if it subsequently determines that Generation, ComEd or PECO has violated the terms and conditions of its tariff or the Federal Power Act. FERC is also authorized to order refunds if it finds that the market-based rates are not just and reasonable under the Federal Power Act.</font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px"><font size="1"> </font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px; TEXT-INDENT: 4%"> <font style="FONT-FAMILY: ARIAL" size="2">In June 2007, FERC issued a Final Rule on Market-Based Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary Services by Public Utilities (Order No. 697), which updated and modified the tests that FERC had implemented in 2004. That order was clarified in December 2007. Subsequently, Order No. 697 was largely affirmed and further clarified in Order No. 697-A, Order No. 697-B and Order No. 697-C. The Registrants do not expect that the Final Rule will have a material effect on their results of operations in the short-term. The longer-term impact will depend on the future application by FERC of Order Nos. 697 and future actions involving market-based rates.</font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px"><font size="1"> </font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px; TEXT-INDENT: 4%"> <font style="FONT-FAMILY: ARIAL" size="2">During 2008, Generation, ComEd and PECO filed an analysis for generation in the Northeast region covering generation in PJM and ISO-New England and Generation filed an analysis for generation in the Southeast region covering generation in the Southern Company and Entergy areas; and in 2009, Generation filed an analysis for generation in the Central region covering generation in the MISO market. In each case, the filing used FERC’s updated screening tests, as required by the Final Rule. These analyses demonstrated that Exelon does not have market power in those areas and, therefore, is entitled to continue to sell at market-based rates in them. FERC accepted the 2008 filings on January 15, 2009 and September 2, 2009 and accepted the 2009 filing on October 26, 2009, affirming Exelon’s affiliates’ continued right to make sales at market-based rates.</font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px"><font size="1"> </font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px; TEXT-INDENT: 4%"> <font style="FONT-FAMILY: ARIAL" size="2"><b><i>Reliability Pricing Model (Exelon and Generation).</i></b> On August 31, 2005, PJM submitted a proposal to FERC for a new capacity payment construct to replace PJM’s then-existing capacity obligation rules. The proposal provided for a forward capacity procurement auction to establish capacity and payment obligations using a demand curve and locational deliverability zones for capacity. The FERC affirmed PJM’s proposal for forward commitments and other matters, but encouraged PJM and the parties to that FERC proceeding to resolve other RPM issues by settlement. A settlement was reached on September 29, 2006 and was approved by FERC on December 22, 2006. The settlement provided for an auction 36 months in advance of each delivery year beginning with the delivery year ending May 31, 2012 and an expedited phase-in process for four transitional auctions covering delivery years ending on May 31 in 2008 through 2011. All but one appeal of FERC’s order approving RPM were withdrawn on February 27, 2009 and the remaining appeal was denied by the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit) on March 17, 2009.</font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px"><font size="1"> </font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px; TEXT-INDENT: 4%"> <font style="FONT-FAMILY: ARIAL" size="2">PJM’s four transitional RPM auctions took place in April 2007, July 2007, October 2007 and January 2008 and established prices for the period from June 1, 2007 through May 31, 2011. Subsequent auctions will take place 36 months ahead of the scheduled delivery year. The auction for the delivery year ending May 31, 2012 and May 31, 2013 occurred in May 2008 and May 2009, respectively. Thus far, the RPM capacity auctions have secured capacity for the PJM market through 2013. While auction results produced varying prices, as anticipated, the RPM has been beneficial for owners of generation facilities, particularly for such facilities located in constrained zones, as compared to the prior capacity-payment construct.</font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px"><font size="1"> </font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px; TEXT-INDENT: 4%"> <font style="FONT-FAMILY: ARIAL" size="2">On May 30, 2008, a group of PJM load-serving entities, state commissions, consumer advocates and trade associations (referred to collectively as the RPM Buyers) filed a complaint at FERC against PJM alleging that three of the four transitional RPM auctions yielded prices that are unjust and unreasonable under the Federal Power Act. Most of the parties comprising the RPM Buyers group were parties to the settlement approved by FERC that established RPM. In the complaint, the RPM Buyers requested that the total projected payments to RPM sellers for the three auctions at issue be materially reduced. On September 19, 2008, FERC dismissed the complaint finding that no party violated PJM’s tariff and the prices determined during the initial auctions implementing the RPM were in accord with the tariff provisions governing the auctions. On June 18, 2009, FERC denied the RPM Buyers’ request for rehearing of FERC’s September 19, 2008 order. On August 14, 2009, RPM Buyers filed a petition with the U.S. Court of Appeals for the Fourth Circuit for review of the FERC’s September 19, 2008 order, rejecting their complaint that RPM resulted in unjust and unreasonable capacity prices. On September 17, 2009, PJM filed a motion to transfer the case to the D.C. Circuit on the grounds that the Fourth Circuit was an improper venue. On November 12, 2009, the court granted the motion. If the D.C. Circuit were to reverse FERC’s decision, FERC would be required to conduct additional proceedings regarding the substantive allegations in the complaint. Exelon and Generation believe that it is remote that the ultimate outcome of this matter will have a material adverse impact on their respective results of operations, cash flows or financial position.</font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px"><font size="1"> </font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px; TEXT-INDENT: 4%"> <font style="FONT-FAMILY: ARIAL" size="2">In a companion order also issued on September 19, 2008, FERC directed PJM and its stakeholders to evaluate whether prospective changes should be made to RPM and, if a consensus is reached, file such a consensus with FERC in time to be in effect for the May 2009 RPM Auction. PJM filed a report with FERC on December 12, 2008 summarizing the discussions and explaining that a consensus was not reached. PJM also filed its own proposal with FERC on December 12, 2008. On March 26, 2009, FERC issued an order accepting in part and rejecting in part PJM’s December 12 filing, as amended by an Offer of Settlement filed by PJM and some members of PJM in response to the December 12 filing. A number of parties filed for rehearing and/or clarification of the March 26, 2009 Order. On August 14, 2009, the Commission granted in part and denied in part requests for rehearing and clarification. Any order may then be subject to review in the United States Court of Appeals.</font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px"><font size="1"> </font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px; TEXT-INDENT: 4%"> <font style="FONT-FAMILY: ARIAL" size="2"><b><i>License Renewals (Exelon and Generation).</i></b> In July 2005, Generation applied for license renewal for Oyster Creek on a timeline consistent and integrated with the other planned license renewal filings for the Generation nuclear fleet. The application was challenged by a coalition of citizen groups (citizen groups) and the NJDEP, including filings made with the NRC’s ASLB, the NRC Commissioners and the U.S. Court of Appeals for the Third Circuit. These filings and appeals were rejected or denied. On April 8, 2009, the NRC issued the renewed operating license for Oyster Creek that expires in April 2029. On May 29, 2009, the citizen groups filed a Petition for Review of the NRC’s renewal of Oyster Creek’s operating license in the U.S. Court of Appeals for the Third Circuit. If the appeal is successful, it is unlikely that it would result in a revocation of the renewed license; however, it could cause the NRC to impose additional conditions over the course of the period of extended operation.</font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px"><font size="1"> </font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px; TEXT-INDENT: 4%"> <font style="FONT-FAMILY: ARIAL" size="2">On January 8, 2008, AmerGen submitted an application to the NRC to extend the operating license of TMI Unit 1 for an additional 20 years. On October 22, 2009, the NRC issued the renewed operating license for TMI Unit 1 that expires in April 2034.</font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px"><font size="1"> </font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px; TEXT-INDENT: 4%"> <font style="FONT-FAMILY: ARIAL" size="2">On August 18, 2009, PSEG submitted an application to the NRC to extend the operating license of Salem Units 1 and 2 by 20 years. Exelon is part owner of the Salem Units. The NRC is expected to spend a total of 22 to 30 months to review the application before making a decision. The current operating licenses expire in 2016 and 2020, respectively.</font></p> </div>

Fair Value of Financial Assets and Liabilities (Exelon, Generation, ComEd and PECO)

12 Months Ended

Dec. 31, 2009

Statement [Line Items]

Fair Value of Financial Assets and Liabilities (Exelon, Generation, ComEd and PECO)

7. Fair Value of Financial Assets and Liabilities (Exelon, Generation, ComEd and PECO)

Non-Derivative Financial Assets and Liabilities. As of December 31, 2009 and 2008, the Registrants’ carrying amounts of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities are representative of fair value because of the short-term nature of these instruments.

Fair Value of Financial Liabilities Recorded at the Carrying Amount

Exelon

The carrying amounts and fair values of Exelon’s long-term debt and SNF obligation as of December 31, 2009 and 2008 were as follows:


	2009				2008
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt (including amounts due within one year)	$	11,634	$	12,223	$	11,426	$	10,803
Long-term debt to PETT (including amounts due within one year)		415		426		1,124		1,193
Long-term debt to other financing trusts		390		325		390		200
Spent nuclear fuel obligation		1,017		832		1,015		544
Preferred securities of subsidiary		87		63		87		63

Fair values of long-term debt are determined by a valuation model, which is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. The fair value of preferred securities of subsidiaries is determined using observable market prices as these securities are actively traded. The carrying amount of Exelon’s and Generation’s SNF obligation resulted from a contract with the DOE to provide for disposal of SNF from Generation’s nuclear generating stations. Exelon’s and Generation’s obligation to the DOE accrues at the 13-week Treasury rate and fair value was determined by comparing the carrying amount of the obligation at the 13-week Treasury rate to the present value of the obligation discounted using the prevailing Treasury rate for a long-term obligation with an estimated maturity of 2020 (after being adjusted for Generation’s credit risk).

Generation

The carrying amounts and fair values of Generation’s long-term debt and SNF obligation as of December 31, 2009 and 2008 were as follows:


	2009				2008
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt (including amounts due within one year)	$	2,993	$	3,132	$	2,514	$	2,402
Spent nuclear fuel obligation		1,017		832		1,015		544

ComEd

The carrying amounts and fair values of ComEd’s long-term debt as of December 31, 2009 and 2008 were as follows:


	2009				2008
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt (including amounts due within one year)	$	4,711	$	5,062	$	4,726	$	4,510
Long-term debt to financing trust		206		167		206		100

PECO

The carrying amounts and fair values of PECO’s long-term debt and preferred securities as of December 31, 2009 and 2008 were as follows:


	2009				2008
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt (including amounts due within one year)	$	2,221	$	2,346	$	1,971	$	1,954
Long-term debt to PETT (including amounts due within one year)		415		426		1,124		1,193
Long-term debt to other financing trusts		184		158		184		100
Preferred securities		87		63		87		63

Recurring Fair Value Measurements

To increase consistency and comparability in fair value measurements, the FASB established a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:

•

Level 1—quoted prices (unadjusted) in active markets for identical assets or liabilities that the Registrants have the ability to access as of the reporting date. Financial assets and liabilities utilizing Level 1 inputs include active exchange-traded equity securities, exchange-based derivatives, mutual funds and money market funds.

•

Level 2—inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data. Financial assets and liabilities utilizing Level 2 inputs include fixed income securities, non-exchange-based derivatives, commingled investment funds priced at NAV per fund share and fair value hedges.

•

Level 3—unobservable inputs, such as internally developed pricing models for the asset or liability due to little or no market activity for the asset or liability. Financial assets and liabilities utilizing Level 3 inputs include infrequently traded non-exchange-based derivatives.

Upon Exelon’s and Generation’s initial adoption of the authoritative guidance for fair value measurements, and in periods since adoption, Exelon and Generation have classified investments in NDT commingled funds, reported at NAV, within Level 3 of the fair value hierarchy. The FASB issued authoritative guidance in September 2009, effective for periods ending after December 15, 2009, indicating that if a reporting entity has the ability to redeem its investment at NAV at the measurement date or at a future date, it shall be classified as Level 2 in the fair value hierarchy. As of December 31, 2009, Exelon and Generation continue to report these investments at NAV without adjustment and have classified them within Level 2 of the fair value hierarchy.

See Note 13—Retirement Benefits for further information regarding the fair value and related valuation techniques for pension and postretirement plan assets.

Exelon

The following table presents assets and liabilities measured and recorded at fair value on Exelon’s Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2009 and 2008:


As of December 31, 2009	Level 1			Level 2			Level 3			Total
Assets
Cash equivalents ^(a)	$	1,845		$	—		$	—		$	1,845
Nuclear decommissioning trust fund investments
Cash equivalents		2			120			—			122
Equity securities ^(b)		1,528			—			—			1,528
Commingled funds ^(c)		—			2,086			—			2,086
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies		511			119			—			630
Debt securities issued by states of the United States and political subdivisions of the states		—			454			—			454
Corporate debt securities		—			710			—			710
Federal agency mortgage-backed securities		—			887			—			887
Commercial mortgage-backed securities (non-agency)		—			91			—			91
Residential mortgage-backed securities (non-agency)		—			9			—			9
Other debt obligations		—			76			—			76

Nuclear decommissioning trust fund investments subtotal ^(d)		2,041			4,552			—			6,593

Rabbi trust investments
Cash equivalents		28			—			—			28
Mutual funds ^(e)(f)		13			—			—			13

Rabbi trust investments subtotal		41			—			—			41

Mark-to-market derivative net (liabilities) assets ^(g)(h)		(4	)		852			(44	)		804

Total assets		3,923			5,404			(44	)		9,283

Liabilities
Deferred compensation		—			(82	)		—			(82	)
Servicing liability		—			—			(2	)		(2	)

Total liabilities		—			(82	)		(2	)		(84	)

Total net assets (liabilities)	$	3,923		$	5,322		$	(46	)	$	9,199


As of December 31, 2008	Level 1		Level 2			Level 3			Total
Assets
Cash equivalents ^(a)	$	1,228	$	—		$	—		$	1,228
Nuclear decommissioning trust fund investments
Cash equivalents		13		—			—			13
Equity securities ^(b)		903		—			—			903
Commingled funds ^(c)		—		94			1,220			1,314
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies		419		91			—			510
Debt securities issued by states of the United States and political subdivisions of the states		—		414			—			414
Corporate debt securities		—		764			—			764
Federal agency mortgage-backed securities		6		1,495			—			1,501
Commercial mortgage-backed securities (non-agency)		—		111			—			111
Other debt obligations		—		107			—			107

Nuclear decommissioning trust fund investments subtotal ^(d)		1,341		3,076			1,220			5,637

Rabbi trust investments
Cash equivalents		2		—			—			2
Mutual funds ^(e)(f)		43		—			—			43

Rabbi trust investments subtotal		45		—			—			45

Mark-to-market derivative net assets ^(g)(h)(i)		12		806			106			924

Total assets		2,626		3,882			1,326			7,834

Liabilities
Deferred compensation		—		(85	)		—			(85	)
Servicing liability		—		—			(2	)		(2	)

Total liabilities		—		(85	)		(2	)		(87	)

Total net assets	$	2,626	$	3,797		$	1,324		$	7,747

(a)	Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value.

(b)	Generation’s NDT funds hold equity portfolios whose performance is benchmarked against the S&P 500 Index, Russell 3000 Index or Morgan Stanley Capital International Europe, Australasia and Far East (EAFE) Index.

(c)

Generation’s NDT funds own commingled funds that invest in both equity and fixed income securities. The commingled funds that invest in equity securities seek to track the performance of the S&P 500 Index, Morgan Stanley Capital International EAFE Index and Russell 3000 Index. The commingled funds that hold fixed income securities invest primarily in a diversified portfolio of high grade money market instruments and other short-term fixed income securities.

(d)	Excludes net assets of $76 million and net liabilities of $137 million consisting of payables related to pending securities purchases net of cash, interest receivables and receivables related to pending securities sales at December 31, 2009 and December 31, 2008, respectively.

(e)	The mutual funds held by the Rabbi trusts invest in large cap equity securities and municipal debt securities. During the second quarter of 2009, Exelon and ComEd recorded an other-than-temporary impairment of $7 million (pre-tax) related to Rabbi trust investments in other income and deductions.

(f)	Excludes $23 million and $19 million of the cash surrender value of life insurance investments at December 31, 2009 and December 31, 2008, respectively.

(g)

Includes both current and noncurrent mark-to-market derivative assets and interest rate swaps, and is net of current and noncurrent mark-to-market derivative liabilities. In addition, the Level 3 balance does not include current and noncurrent assets for Generation and current and noncurrent liabilities for ComEd of $302 million and $669 million at December 31, 2009 and $111 million and $345 million at December 31, 2008, respectively, related to the fair value of Generation’s financial swap contract with ComEd, and a noncurrent asset of $2 million at December 31, 2009 related to the fair value of Generation’s block contracts with PECO, which eliminate upon consolidation in Exelon’s Consolidated Financial Statements.

(h)

Includes collateral postings received from and paid to counterparties. Collateral received from counterparties, net of collateral paid to counterparties, totaled $3 million, $941 million and $3 million that are netted against Level 1, Level 2 and Level 3 mark-to-market derivative net assets, respectively, as of December 31, 2009. Collateral received from counterparties, net of collateral paid to counterparties, totaled $11 million, $741 million and $1 million that are netted against Level 1, Level 2 and Level 3 mark-to-market derivative net assets, respectively, as of December 31, 2008.

(i)

Exelon and Generation reclassified certain assets and liabilities with respect to option premiums into the mark-to-market net asset and liability accounts to conform with the current year presentation. Refer to Note 8-Derivative Financial Instruments for further discussion. The impact of the reclassification was an increase of $245 million to Level 2 mark-to-market derivative net assets.

The following table presents the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the years ended December 31, 2009 and 2008:


For the Year Ended December 31, 2009	Nuclear Decommissioning Trust Fund Investments			Mark-to-Market Derivatives			Servicing Liability			Total
Balance as of January 1, 2009	$	1,220		$	106		$	(2	)	$	1,324
Total realized / unrealized gains (losses)
Included in income		119			(134	)^(a)		—			(15	)
Included in other comprehensive income		—			5	^(b)		—			5
Included in regulatory assets/liabilities		275			(2	)		—			273
Change in collateral		—			(2	)					(2	)
Purchases, sales and issuances, net		337			—			—			337
Transfers out of Level 3		(1,951	)^(c)		(17	)		—			(1,968	)

Balance as of December 31, 2009	$	—		$	(44	)	$	(2	)	$	(46	)

The amount of total losses included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held as of December 31, 2009	$	—		$	(79	)	$	—		$	(79	)

(a)	Includes the reclassification of $55 million of realized losses due to the settlement of derivative contracts recorded in results of operations.

(b)

Excludes $782 million of changes in the fair value and $267 million of realized losses due to settlements associated with Generation’s financial swap contract with ComEd, and $2 million of changes in the fair value of Generation’s block contracts with PECO. All items eliminate upon consolidation in Exelon’s Consolidated Financial Statements.

(c)	As of December 31, 2009, investments in NDT commingled funds, stated at NAV, were transferred out of Level 3 and into Level 2 in accordance with FASB issued authoritative guidance noted above.


For the Year Ended December 31, 2008	Nuclear Decommissioning Trust Fund Investments			Mark-to-Market Derivatives			Servicing Liability			Total
Balance as of January 1, 2008	$	2,019		$	52		$	(1	)	$	2,070
Total realized / unrealized (losses) gains
Included in income		(321	)		35	^(a)		(1	)		(287	)
Included in other comprehensive income		—			(32	)^(b)		—			(32	)
Included in regulatory liabilities		(553	)		—			—			(553	)
Change in collateral		—			(1	)		—			(1	)
Purchases, sales and issuances, net		109			—			—			109
Transfers into (out of ) Level 3		(34	)		52			—			18

Balance as of December 31, 2008	$	1,220		$	106		$	(2	)	$	1,324

The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held as of December 31, 2008	$	(310	)	$	125		$	—		$	(185	)

(a)	Includes the reclassification of $90 million of realized losses due to the settlement of derivative contracts recorded in results of operations.

(b)	Excludes $888 million of changes in the fair value and $24 million of realized gains due to settlements associated with Generation’s financial swap contract with ComEd. All items eliminate upon consolidation in Exelon’s Consolidated Financial Statements.

The following table presents total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis during the years ended December 31, 2009 and 2008:


	Operating Revenue			Purchased Power			Fuel			Other, net
Total (losses) gains included in income for the year ended December 31, 2009	$	(86	)	$	(11	)	$	(37	)	$	119
Change in the unrealized losses relating to assets and liabilities held as of the year ended December 31, 2009	$	(2	)	$	(8	)	$	(69	)	$	—


	Operating Revenue		Purchased Power			Fuel			Other, net
Total gains (losses) included in income for the year ended December 31, 2008	$	63	$	(12	)	$	(16	)	$	(321	)
Change in the unrealized gains (losses) relating to assets and liabilities held as of the year ended December 31, 2008	$	107	$	(34	)	$	52		$	(310	)

Generation

The following table presents assets and liabilities measured and recorded at fair value on Generation’s Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2009 and December 31, 2008:


As of December 31, 2009	Level 1			Level 2			Level 3		Total
Assets
Cash equivalents ^(a)	$	1,040		$	—		$	—	$	1,040
Nuclear decommissioning trust fund investments
Cash equivalents		2			120			—		122
Equity securities ^(b)		1,528			—			—		1,528
Commingled funds ^(c)		—			2,086			—		2,086
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies		511			119			—		630
Debt securities issued by states of the United States and political subdivisions of the states		—			454			—		454
Corporate debt securities		—			710			—		710
Federal agency mortgage-backed securities		—			887			—		887
Commercial mortgage-backed securities (non-agency)		—			91			—		91
Residential mortgage-backed securities (non-agency)		—			9			—		9
Other debt obligations		—			76			—		76

Nuclear decommissioning trust fund investments subtotal ^(d)		2,041			4,552			—		6,593

Rabbi trust investments ^(e)(f)		4			—			—		4
Mark-to-market derivative net (liabilities) assets ^(g)(h)		(4	)		842			931		1,769

Total assets		3,081			5,394			931		9,406

Liabilities
Deferred compensation		—			(23	)		—		(23	)

Total liabilities		—			(23	)		—		(23	)

Total net assets	$	3,081		$	5,371		$	931	$	9,383


As of December 31, 2008	Level 1		Level 2			Level 3		Total
Assets
Cash equivalents ^(a)	$	1,103	$	—		$	—	$	1,103
Nuclear decommissioning trust fund investments
Cash equivalents		13		—			—		13
Equity securities ^(b)		903		—			—		903
Commingled funds ^(c)		—		94			1,220		1,314
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies		419		91			—		510
Debt securities issued by states of the United States and political subdivisions of the states		—		414			—		414
Corporate debt securities		—		764			—		764
Federal agency mortgage-backed securities		6		1,495			—		1,501
Commercial mortgage-backed securities (non-agency)		—		111			—		111
Other debt obligations		—		107			—		107

Nuclear decommissioning trust fund investments subtotal ^(d)		1,341		3,076			1,220		5,637

Rabbi trust investments ^(e)(f)		—		4			—		4
Mark-to-market derivative net assets ^(g)(h)(i)		12		789			562		1,363

Total assets		2,456		3,869			1,782		8,107

Liabilities
Deferred compensation		—		(25	)		—		(25	)

Total liabilities		—		(25	)		—		(25	)

Total net assets	$	2,456	$	3,844		$	1,782	$	8,082

(a)	Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value.

(b)	Generation’s NDT funds hold equity portfolios whose performance is benchmarked against the S&P 500 Index, Russell 3000 Index or Morgan Stanley Capital International EAFE Index.

(c)

Generation’s NDT funds own commingled funds that invest in both equity and fixed income securities. The commingled funds that invest in equity securities seek to match the performance of the S&P 500 Index, Morgan Stanley Capital International EAFE Index and Russell 3000 Index. The commingled funds that hold fixed income securities invest primarily in a diversified portfolio of high grade money market instruments and other short-term fixed income securities.

(d)

Excludes net assets of $76 million and net liabilities of $137 million at December 31, 2009 and December 31, 2008, respectively. These items consist of payables related to pending securities purchases net of cash, interest and dividend receivables and receivables related to pending securities sales.

(e)	The mutual funds held by the Rabbi trusts that are invested in common stock of S&P 500 companies and Pennsylvania municipal bonds that are primarily rated as investment grade.

(f)	Excludes $7 million and $6 million of the cash surrender value of life insurance investments at December 31, 2009 and December 31, 2008, respectively.

(g)

Includes both current and noncurrent mark-to-market derivative assets, and is net of current and noncurrent mark-to-market derivative liabilities. In addition, the Level 3 balance includes current and noncurrent assets for Generation of $302 million and $669 million at December 31, 2009 and $111 million and $345 million at December 31, 2008, respectively, related to the fair value of Generation’s financial swap contract with ComEd, and a noncurrent asset of $2 million at December 31, 2009 related to the fair value of Generation’s block contracts with PECO. All of the mark-to-market balances Generation carries associated with the financial swap contract with ComEd and the block contracts with PECO eliminate upon consolidation in Exelon’s Consolidated Financial Statements.

(h)

(i)

Exelon and Generation retrospectively reclassified certain assets and liabilities with respect to option premiums into the mark-to-market net asset and liability accounts to conform with the current year presentation. Refer to Note 8-Derivative Financial Instruments for further discussion. The impact of the reclassification was an increase of $245 million to Level 2 mark-to-market derivative net assets.

The following table presents the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the years ended December 31, 2009 and 2008:


Year Ended December 31, 2009	Nuclear Decommissioning Trust Fund Investments			Mark-to-Market Derivatives			Total
Balance as of January 1, 2009	$	1,220		$	562		$	1,782
Total unrealized / realized gains (losses)
Included in income		119			(134	)^(a)		(15	)
Included in other comprehensive income		—			522	^(b)		522
Included in noncurrent payables to affiliates		275			—			275
Change in Collateral		—			(2	)		(2	)
Purchases, sales, issuances and settlements, net		337			—			337
Transfers out of Level 3		(1,951	)^(c)		(17	)		(1,968	)

Balance as of December 31, 2009	$	—		$	931		$	931

The amount of total gains losses included in income attributed to the change in unrealized losses related to assets and liabilities held as of December 31, 2009	$	—		$	(79	)	$	(79	)

(a)	Includes the reclassification of $55 million of realized losses due to the settlement of derivative contracts recorded in results of operations.

(b)

Includes $782 million of changes in the fair value and $267 million of realized losses due to settlements associated with Generation’s financial swap with ComEd. Also includes $2 million of changes in the fair value of Generation’s block contracts with PECO. All items eliminate upon consolidation in Exelon’s Consolidated Financial Statements.

(c)	As of December 31, 2009, investments in NDT commingled funds, stated at NAV, were transferred out of Level 3 and into Level 2, in accordance with FASB issued authoritative guidance noted above.


Year Ended December 31, 2008	Nuclear Decommissioning Trust Fund Investments			Mark-to-Market Derivatives			Total
Balance as of January 1, 2008	$	2,019		$	(403	)	$	1,616
Total unrealized / realized (losses) gains
Included in income		(321	)		35	^(a)		(286	)
Included in other comprehensive income		—			879	^(b)		879
Included in noncurrent payables to affiliates		(553	)		—			(553	)
Change in Collateral		—			(1	)		(1	)
Purchases, sales, issuances and settlements, net		109			—			109
Transfers into or (out of) Level 3		(34	)		52			18

Balance as of December 31, 2008	$	1,220		$	562		$	1,782

The amount of total (losses) gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held as of December 31, 2008	$	(310	)	$	125		$	(185	)

(a)	Includes the reclassification of $90 million of realized losses due to the settlement of derivative contracts recorded in results of operations.

(b)	Includes $888 million of changes in the fair value and $24 million of realized gains due to settlements associated with Generation’s financial swap with ComEd. All items eliminate upon consolidation in Exelon’s Consolidated Financial Statements.


	Operating Revenue			Purchased Power			Fuel			Other, net
Total gains (losses) included in income for the year ended December 31, 2009	$	(86	)	$	(11	)	$	(37	)	$	119
Change in the unrealized losses relating to assets and liabilities held as of the year ended December 31, 2009	$	(2	)	$	(8	)	$	(69	)	$	—


	Operating Revenue		Purchased Power			Fuel			Other, net
Total gains (losses) included in income for the year ended December 31, 2008	$	63	$	(12	)	$	(16	)	$	(321	)
Change in the unrealized gains (losses) relating to assets and liabilities held as of the year ended December 31, 2008	$	107	$	(34	)	$	52		$	(310	)

ComEd

The following table presents assets measured and recorded at fair value on ComEd’s Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2009 and 2008:


As of December 31, 2009	Level 1		Level 2			Level 3			Total
Assets
Cash equivalents ^(a)	$	25	$	—		$	—		$	25
Rabbi trust investments ^(b)
Cash equivalents		28		—			—			28

Total assets		53		—			—			53

Liabilities
Deferred compensation obligation		—		(8	)		—			(8	)
Mark-to-market derivative liabilities ^(c)		—		—			(971	)		(971	)

Total liabilities		—		(8	)		(971	)		(979	)

Total net assets (liabilities)	$	53	$	(8	)	$	(971	)	$	(926	)


As of December 31, 2008	Level 1		Level 2			Level 3			Total
Assets
Cash equivalents ^(a)	$	16	$	—		$	—		$	16
Rabbi trust investments
Cash equivalents		2		—			—			2
Mutual funds ^(d)		32		—			—			32
Rabbi trust investment subtotal		34		—			—			34

Total assets		50		—			—			50

Liabilities
Deferred compensation obligation		—		(7	)		—			(7	)
Mark-to-market derivative liabilities ^(c)		—		—			(456	)		(456	)

Total liabilities		—		(7	)		(456	)		(463	)

Total net assets (liabilities)	$	50	$	(7	)	$	(456	)	$	(413	)

(a)	Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value.

(b)	During the second quarter of 2009, ComEd recorded an other-than-temporary impairment of $7 million (pre-tax) related to Rabbi trust investments in other income and deductions.

(c)

The Level 3 balance is comprised of the current and noncurrent liability of $302 million and $669 million at December 31, 2009, respectively, and $111 million and $345 million at December 31, 2008, respectively, related to the fair value of ComEd’s financial swap contract with Generation which eliminates upon consolidation in Exelon’s Consolidated Financial Statements.

(d)	The mutual funds held by the Rabbi trusts invest in stocks in the Russell 1000 index and municipal securities that are primarily rated as investment grade.

The following tables present the fair value reconciliation of Level 3 assets measured at fair value on a recurring basis during the years ended December 31, 2009 and 2008:


For the Year Ended December 31, 2009	Mark-to-Market Derivatives
Balance as of January 1, 2009	$	(456	)
Total realized / unrealized gains (losses) included in regulatory assets ^(a)		(515	)

Balance as of December 31, 2009	$	(971	)

(a)	Includes $782 million of changes in the fair value and $267 million of realized gains due to settlements associated with ComEd’s financial swap with Generation. All items eliminate upon consolidation in Exelon’s Consolidated Financial Statements.


For the Year Ended December 31, 2008	Mark-to-Market Derivatives
Balance as of January 1, 2008	$	456
Total realized / unrealized losses included in regulatory assets ^(a)		(912	)

Balance as of December 31, 2008	$	(456	)

(a)	Includes $888 million of changes in the fair value and $24 million of realized losses due to settlements associated with ComEd’s financial swap with Generation. All items eliminate upon consolidation in Exelon’s Consolidated Financial Statements.

PECO

The following table presents assets and liabilities measured and recorded at fair value on PECO’s Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2009 and 2008:


December 31, 2009	Level 1		Level 2			Level 3			Total
Assets
Cash equivalents ^(a)	$	281	$	—		$	—		$	281
Rabbi trust investments—mutual funds ^(b)(c)		7		—			—			7

Total assets		288		—			—			288

Liabilities
Deferred compensation obligation		—		(25	)		—			(25	)
Mark-to-market derivative liabilities ^(d)		—		—			(4	)		(4	)
Servicing liability		—		—			(2	)		(2	)

Total liabilities		—		(25	)		(6	)		(31	)

Total net assets (liabilities)	$	288	$	(25	)	$	(6	)	$	257


As of December 31, 2008	Level 1		Level 2			Level 3			Total
Assets
Cash equivalents ^(a)	$	26	$	—		$	—		$	26
Rabbi trust investments—mutual funds ^(b)(c)		6		—			—			6

Total assets		32		—			—			32

Liabilities
Deferred compensation obligation		—		(28	)		—			(28	)
Servicing liability		—		—			(2	)		(2	)

Total liabilities		—		(28	)		(2	)		(30	)

Total net assets (liabilities)	$	32	$	(28	)	$	(2	)	$	2

(a)	Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value.

(b)	The mutual funds held by the Rabbi Trust invest in the common stock of S&P 500 companies and Pennsylvania municipal bonds that are primarily rated as investment grade.

(c)	Excludes $12 million and $10 million of the cash surrender value of life insurance investments at December 31, 2009 and December 31, 2008, respectively.

(d)

The Level 3 balance represents a noncurrent liability of $4 million at December 31, 2009 related to the fair value of PECO’s block contracts, which includes a $2 million noncurrent liability related to the fair value of PECO’s block contracts with Generation that eliminates upon consolidation in Exelon’s Consolidated Financial Statements.

The following table presents the fair value reconciliation of Level 3 assets measured at fair value on a recurring basis during the years ended December 31, 2009 and 2008:


For the Year Ended December 31, 2009	Mark-to-Market Derivatives			Servicing Liability			Total
Balance as of January 1, 2009	$	—		$	(2	)	$	(2	)
Total unrealized losses included in regulatory assets		(4	)		—			(4	)

Balance as of December 31, 2009	$	(4	)	$	(2	)	$	(6	)


For the Year Ended December 31, 2008	Mark-to-Market Derivatives			Servicing Liability			Total
Balance as of January 1, 2008	$	—		$	(1	)	$	(1	)
Total unrealized losses included in net income		—			(1	)		(1	)

Balance as of December 31, 2008	$	—		$	(2	)	$	(2	)

Valuation Techniques Used to Determine Fair Value

The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the tables above.

Cash Equivalents (Exelon, Generation, ComEd and PECO). The Registrants’ cash equivalents include investments with maturities of three months or less when purchased. The cash equivalents shown in the fair value table are comprised of investments in mutual and money market funds. The fair values of the shares of these funds are based on observable market prices and, therefore, have been categorized in Level 1 in the fair value hierarchy.

Nuclear Decommissioning Trust Fund Investments (Exelon and Generation). The trust fund investments have been established to satisfy Exelon’s and Generation’s nuclear decommissioning obligations. The NDT funds hold debt and equity securities directly and indirectly through commingled funds. Generation’s investment policies place limitations on the types and investment grade ratings of the securities that may be held by the trusts. These policies restrict the trust funds from holding alternative investments and limit the trust funds’ exposures to investments in highly illiquid markets. Investments with maturities of three months or less when purchased, including certain short-term fixed income securities, are considered cash equivalents and included in the recurring fair value measurements hierarchy as Level 1 or Level 2.

With respect to individually held equity securities, the trustees obtain prices from pricing services, whose prices are obtained from direct feeds from market exchanges, which Generation is able to independently corroborate. The fair values of equity securities held directly by the trust funds are based on quoted prices in active markets and are categorized in Level 1. Equity securities held individually are primarily traded on the New York Stock Exchange and NASDAQ—Global Select Market, which contain only actively traded securities due to the volume trading requirements imposed by these exchanges.

For fixed income securities, multiple prices and price types are obtained from pricing vendors whenever possible, which enables cross-provider validations in addition to checks for unusual daily movements. A primary price source is identified based on asset type, class or issue for each security. The trustees monitor prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the portfolio managers challenge an assigned price and the trustees determine that another price source is considered to be preferable. Generation has obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, Generation selectively corroborates the fair values of securities by comparison to other market-based price sources. U.S. Treasury securities are categorized as Level 1 because they trade in a highly liquid and transparent market. The fair values of fixed income securities, excluding U.S. Treasury securities, are based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences and are categorized in Level 2. To draw parallels from the trading and quoting of fixed income securities with similar features, pricing services consider various characteristics including the issuer, maturity, purpose of loan, collateral attributes, prepayment speeds, interest rates and credit ratings in order to properly value these securities.

Commingled funds, which are similar to mutual funds, are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives. The fair values of short-term commingled funds held within the trust funds, which generally hold short-term fixed income securities and are not subject to restrictions regarding the purchase or sale of shares, are derived from observable prices. The objectives of the remaining commingled funds in which Exelon and Generation invest primarily seek to track the performance of certain equity indices by purchasing equity securities to replicate the capitalization and characteristics of the indices. In general, equity commingled funds are redeemable on the 15th of the month and the last business day of the month, however, the fund manager may designate any day as a valuation date for the purpose of purchasing or redeeming units. Commingled funds are categorized in Level 2 at December 31, 2009 because the fair value of the funds are based on NAVs per fund share (the unit of account), primarily derived from the quoted prices in active markets of the underlying equity securities and because they are offered to a limited group of investors and, therefore, not traded in an active market. See Note 11—Asset Retirement Obligations for further discussion on the NDT fund investments.

Rabbi Trust Investments (Exelon, Generation, ComEd and PECO). The Rabbi trusts were established to hold assets related to deferred compensation plans existing for certain active and retired members of Exelon’s executive management and directors. The investments in the Rabbi trusts are included in investments in the Registrants’ Consolidated Balance Sheets. The fair values of the shares of the funds are based on observable market prices and, therefore, have been categorized in Level 1 in the fair value hierarchy.

The Registrants evaluate the securities held in their Rabbi trusts for other-than-temporary impairment by analyzing the historical performance, cost basis and market value of securities in unrealized loss positions in comparison to related market indices. During June 2009, ComEd concluded that certain investments were other-than-temporarily impaired based on various factors assessed in the aggregate, including the duration and severity of the impairment, the anticipated recovery of the securities and considerations of ComEd’s ability and intent to hold the investments until the recovery of their cost basis. This analysis resulted in an impairment charge of $7 million (pre-tax) recorded in other income and deductions associated with ComEd’s investments held in Rabbi trusts.

Mark-to-Market Derivatives (Exelon, Generation, ComEd and PECO). Derivative contracts are traded in both exchange-based and non-exchange-based markets. Exchange-based derivatives that are valued using unadjusted quoted prices in active markets are categorized in Level 1 in the fair value hierarchy. Certain non-exchange-based derivatives are valued using indicative price quotations available through brokers or over-the-counter, on-line exchanges and are categorized in Level 2. These price quotations reflect the average of the bid-ask, mid-point prices and are obtained from sources that the Registrants believe provide the most liquid market for the commodity. The price quotations are reviewed and corroborated to ensure the prices are observable and representative of an orderly transaction between market participants. This includes consideration of actual transaction volumes, market delivery points, bid-ask spreads and contract duration. The remainder of non-exchange-based derivative contracts is valued using the Black model, an industry standard option valuation model. The Black model takes into account inputs such as contract terms, including maturity, and market parameters, including assumptions of the future prices of energy, interest rates, volatility, credit worthiness and credit spread. For non-exchange-based derivatives that trade in liquid markets, such as generic forwards, swaps and options, model inputs are generally observable. Such instruments are categorized in Level 2. The Registrants’ non-exchange-based derivatives are predominately at liquid trading points. For non-exchange-based derivatives that trade in less liquid markets with limited pricing information, such as the financial swap contract between Generation and ComEd, model inputs generally would include both observable and unobservable inputs. These valuations may include an estimated basis adjustment from an illiquid trading point to a liquid trading point for which active price quotations are available. For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility and contract duration. Such instruments are categorized in Level 3 as the model inputs generally are not observable. The Registrants consider credit and nonperformance risk in the valuation of derivative contracts categorized in Level 1, 2 and 3, including both historical and current market data in their assessment of credit and nonperformance risk. The impacts of credit and nonperformance risk were not material to the financial statements.

Exelon may utilize fixed-to-floating interest rate swaps, which are typically designated as fair value hedges, as a means to achieve its targeted level of variable-rate debt as a percent of total debt. In addition, the Registrants may utilize interest rate derivatives to lock in interest rate levels in anticipation of future financings, which are typically designated as cash flow hedges. Exelon uses a calculation of future cash inflows and estimated future outflows related to the swap agreements, which are discounted and netted to determine the current fair value. Additional inputs to the present value calculation include the contract terms, counterparty credit risk and market parameters such as interest rates and volatility. As these inputs are based on observable data and valuations of similar instruments, the interest rate swaps are categorized in Level 2 in the fair value hierarchy. See Note 8—Derivative Financial Instruments for further discussion on mark-to-market derivatives.

Deferred Compensation Obligations (Exelon, Generation, ComEd and PECO). The Registrants’ deferred compensation plans allow participants to defer certain cash compensation into a notional investment account. The Registrants include such plans in other current and noncurrent liabilities in their Consolidated Balance Sheets. The value of the Registrants’ deferred compensation obligations is based on the market value of the participants’ notional investment accounts. The notional investments are comprised primarily of mutual funds, which are based on observable market prices. However, since the deferred compensation obligations themselves are not exchanged in an active market, they are categorized in Level 2 in the fair value hierarchy.

Servicing Liability (Exelon and PECO). PECO is party to an agreement with a financial institution under which it sold an undivided interest, adjusted daily, in up to $225 million of designated accounts receivable. A servicing liability was recorded for the agreement in accordance with the current authoritative guidance for servicing of assets and extinguishment of liabilities. The servicing liability is included in other current liabilities in Exelon’s and PECO’s Consolidated Balance Sheets. The fair value of the liability has been determined using internal estimates based on provisions in the agreement, which are categorized as Level 3 inputs in the fair value hierarchy. See Note 18—Commitments and Contingencies for further discussion on the accounts receivable agreement.

Non-recurring Fair Value Measurements

Asset Impairment (Exelon and Generation)

As discussed in Note 4—Property, Plant and Equipment, as of March 31, 2009, Generation tested its Texas plants for potential impairment and recognized an impairment charge of $223 million in the first quarter of 2009 to reduce the carrying value of the Handley and Mountain Creek stations to fair value.

The impairment charge recorded by Generation for the Handley and Mountain Creek stations incorporated the fair values of the plants using unobservable inputs falling within Level 3 of the fair value hierarchy. Generation determined fair value considering multiple valuation techniques including the income (discounted cash flow), market (available comparables) and cost (replacement cost) valuation approaches. The results were evaluated and weighted, considering the reasonableness of the range indicated by those results. Significant inputs used under the income approach included forecasted cash flows based on forecasted generation, forward prices of natural gas and electricity, overall generation availability ERCOT and discount rate assumptions. Significant inputs under the transaction approach included market multiples that were derived from comparable transactions for peaking plants in ERCOT and other market regions and discount rate assumptions.

Derivative Financial Instruments (Exelon, Generation, ComEd and PECO)

12 Months Ended

Dec. 31, 2009

Statement [Line Items]

Derivative Financial Instruments (Exelon, Generation, ComEd and PECO)

8. Derivative Financial Instruments (Exelon, Generation, ComEd and PECO)

The Registrants are exposed to certain risks related to ongoing business operations. The primary risks managed by using derivative instruments are commodity price risk and interest rate risk. To the extent the amount of energy Exelon generates differs from the amount of energy it has contracted to sell, the Registrants are exposed to market fluctuations in the prices of electricity, fossil fuels, and other commodities. The Registrants employ established policies and procedures to manage their risks associated with market fluctuations by entering into physical contracts as well as financial derivative contracts including swaps, futures, forwards, options and short-term and long-term commitments to purchase and sell energy and energy-related products. The Registrants believe these instruments, which are classified as either economic hedges or non-derivatives, mitigate exposure to fluctuations in commodity prices. Exposure to interest rate risk exists as a result of the issuance of variable and fixed-rate debt, commercial paper and lines of credit.

Derivative accounting guidance requires that derivative instruments be recognized as either assets or liabilities at fair value. Under these provisions, economic hedges are recognized on the balance sheet at their fair value unless they qualify for the normal purchases and normal sales scope exception. The Registrants have applied the normal purchases and normal sales scope exception to certain derivative contracts for the forward sale of generation, power procurement agreements, and natural gas supply agreements. For economic hedges that qualify and are designated as cash flow hedges, the portion of the derivative gain or loss that is effective in offsetting the change in value of the underlying exposure is deferred in accumulated OCI and later reclassified into earnings when the underlying transaction occurs. For economic hedges that do not qualify or are not designated as cash flow hedges, changes in the fair value of the derivative are recognized in earnings each period and are classified as other derivatives in the following tables. Non-derivative contracts for access to additional generation and for sales to load-serving entities are accounted for primarily under the accrual method of accounting, which is further discussed in Note 18 – Commitments and Contingencies. Additionally, Generation is exposed to certain market risks through its proprietary trading activities. The proprietary activities are a complement to Generation’s energy marketing portfolio but represent a small portion of Generation’s overall energy marketing activities.

Commodity Price Risk (Exelon, Generation, ComEd and PECO)

Economic Hedging. The Registrants are exposed to commodity price risk primarily relating to changes in the market price of electricity, fossil fuels, and other commodities associated with price movements resulting from changes in supply and demand, fuel costs, market liquidity, weather conditions, governmental regulatory and environmental policies, and other factors. Within Exelon, Generation has the most exposure to commodity price risk. Generation uses a variety of derivative and non-derivative instruments to manage the commodity price risk of its electric generation facilities, including power sales, fuel and energy purchases, and other energy-related products marketed and purchased. In order to manage these risks, Generation may enter into fixed-price derivative or non-derivative contracts to hedge the variability in future cash flows from forecasted sales of energy and purchases of fuel and energy. The objectives for entering into such hedges include fixing the price for a portion of anticipated future electricity sales at a level that provides an acceptable return on electric generation operations, fixing the price of a portion of anticipated fuel purchases for the operation of power plants, and fixing the price for a portion of anticipated energy purchases to supply load-serving customers. The portion of forecasted transactions hedged may vary based upon management’s policies and hedging objectives, the market, weather conditions, operational and other factors. Generation is also exposed to differences between the locational settlement prices of certain economic hedges and the hedged generating units. This price difference is actively managed through other instruments which include financial transmission rights, whose changes in fair value are recognized in earnings each period, and auction revenue rights.

In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on Generation’s owned and contracted generation positions which have not been hedged. Generation hedges commodity risk on a ratable basis over three-year periods. As of December 31, 2009, the percentage of expected generation hedged was 91%—94%, 69%—72 %, and 37%—40 % for 2010, 2011 and 2012, respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation represents the amount of energy estimated to be generated or purchased through owned or contracted capacity. Equivalent sales represent all hedging products, which include cash flow hedges, other derivatives and certain non-derivative contracts including sales to ComEd and PECO to serve their retail load.

ComEd has locked in a fixed price for a significant portion of its commodity price risk through the five-year financial swap contract with Generation that expires on May 31, 2013, which is discussed in more detail below. In addition, the contracts that Generation has entered into with ComEd and that ComEd has entered into with Generation and other suppliers as part of the ComEd power procurement agreements, which are further discussed in Note 2—Regulatory Issues, qualify for the normal purchases and normal sales scope exception. Based on the Illinois Settlement Legislation and ICC-approved procurement methodologies permitting ComEd to recover its electricity procurement costs from retail customers with no mark-up, ComEd’s price risk related to power procurement is limited.

In order to fulfill a requirement of the Illinois Settlement, Generation and ComEd entered into a five-year financial swap contract effective August 28, 2007. The financial swap is designed to hedge spot market purchases, which along with ComEd’s remaining energy procurement contracts, meet its load service requirements. The remaining swap contract volumes are 2,000 MW for the period extending June 2009 through May 2010 and 3,000 MW from June 2010 through May 2013. The terms of the financial swap contract require Generation to pay the market price for a portion of ComEd’s electricity supply requirement, while ComEd pays a fixed price. The contract is to be settled net, for the difference between the fixed and market pricing, and the financial terms only cover energy costs and do not cover capacity or ancillary services. The financial swap contract is a derivative financial instrument that has been designated by Generation as a cash flow hedge. Consequently, Generation records the fair value of the swap on its balance sheet and records changes in fair value to OCI. ComEd has not elected hedge accounting for this derivative financial instrument and records the fair value of the swap on its balance sheet. However, since the financial swap contract was deemed prudent by the Illinois Settlement Legislation, ComEd receives full cost recovery for the contract in rates and the change in fair value each period is recorded by ComEd as a regulatory asset or liability. See Note 2—Regulatory Issues for additional information regarding the Illinois Settlement. In Exelon’s consolidated financial statements, all financial statement effects of the financial swap recorded by Generation and ComEd are eliminated.

PECO has transferred substantially all of its commodity price risk related to its procurement of electric supply to Generation through a PPA that expires December 31, 2010. The PPA is not considered a derivative under current derivative authoritative guidance.

As part of the preparation for the expiration of the PPA, PECO has entered into derivative contracts to procure electric supply through a competitive RFP process as outlined in its PAPUC-approved DSP Program, which is further discussed in Note 2—Regulatory Issues. Based on Pennsylvania legislation and the DSP Program permitting PECO to recover its electric supply procurement costs from retail customers with no mark-up, PECO’s price risk related to electric supply procurement will be limited. PECO will lock in fixed prices for a significant portion of its commodity price risk following the expiration of the electric generation rate caps through full requirements contracts and block contracts. PECO’s full requirements fixed price contracts qualify for the normal purchases and normal sales scope exception. PECO accounts for the block contracts as other derivatives, which are recorded on its balance sheet at fair value and the change in fair value each period is recorded as a regulatory asset or liability.

PECO’s natural gas procurement policy is designed to achieve a reasonable balance of long-term and short-term gas purchases under different pricing approaches in order to achieve system supply reliability at the least cost. PECO’s reliability strategy is two-fold. First, PECO must assure that there is sufficient transportation capacity to satisfy deliverability requirements. Second, PECO must ensure that a firm source of supply exists to utilize the capacity resources. All of PECO’s natural gas supply and management agreements that are derivatives qualify for the normal purchases and normal sales exception. Additionally, in accordance with the 2009 PAPUC PGC settlement and to reduce the exposure of PECO and its customers to natural gas price volatility, PECO has continued its program to purchase natural gas for both winter and summer supplies using a layered approach of locking-in prices ahead of each season with long-term gas purchase agreements (those with primary terms of at least twelve months). Under the terms of the 2009 PGC settlement, PECO is required to lock in (i.e. economically hedge) the price of a minimum volume of its long-term gas commodity purchases. PECO’s gas-hedging program covers 22% to 29% of planned natural gas purchases in support of projected firm sales. The hedging program for natural gas procurement has no direct impact on PECO’s financial position or results of operations as natural gas costs are fully recovered from customers under the PGC.

Proprietary Trading. Generation also enters into certain energy-related derivatives for proprietary trading purposes. Proprietary trading includes all contracts entered into purely to profit from market price changes as opposed to hedging an exposure and is subject to limits established by Exelon’s RMC. The proprietary trading activities which included volumes of 7,578 GWh, 8,891 GWh and 20,323 GWh for years ended December 31, 2009, 2008 and 2007, respectively, are a complement to Generation’s energy marketing portfolio but represent a small portion of Generation’s revenue from energy marketing activities. Neither ComEd nor PECO enter into derivatives for proprietary trading purposes.

Interest Rate Risk (Exelon, Generation and ComEd)

The Registrants use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. The Registrants may also utilize fixed-to-floating interest rate swaps, which are typically designated as fair value hedges, as a means to manage their interest rate exposure. In addition, the Registrants may utilize interest rate derivatives to lock in interest rate levels in anticipation of future financings, which are typically designated as cash flow hedges. These strategies are employed to achieve a lower cost of capital. A hypothetical 10% increase in the interest rates associated with variable-rate debt would result in less than a $1 million decrease in Exelon’s, Generation’s, and ComEd’s pre-tax income for the year ended December 31, 2009.

Fair Value Hedges. For derivative instruments that are designated and qualify as fair value hedges, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item attributable to the hedged risk are recognized in current earnings. Exelon includes the gain or loss on the hedged items and the offsetting loss or gain on the related interest rate swaps in interest expense as follows for the year ended December 31, 2009:


Income Statement Classification	Loss on Swaps			Gain on Borrowings
Interest expense	$	(7	)	$	7

At December 31, 2009 and 2008, Exelon had $100 million of notional amounts of fair value hedges outstanding related to interest rate swaps, with fair value assets of $10 million and $17 million, respectively. During the years ended December 31, 2009 and 2008, there was no impact on the results of operations as a result of ineffectiveness from fair value hedges.

Cash Flow Hedges. At December 31, 2009 and 2008, the Registrants did not have any interest rate swaps designated as cash flow hedges outstanding. In connection with Generation’s September 2009 $1.5 billion debt issuance, Generation entered into forward-starting interest rate swaps in the aggregate notional amount of $1.1 billion. The interest rate swaps were settled on September 16, 2009 with Generation recording a $7 million pre-tax gain. The gain was recorded to OCI within Generation’s Consolidated Balance Sheets and will be amortized to income over the life of the related debt as a reduction in interest expense.

Fair Value Measurement (Exelon, Generation, ComEd and PECO)

Fair value accounting guidance requires the fair value of derivative instruments to be shown in the Notes to the Consolidated Financial Statements on a gross basis, even when the derivative instruments are subject to master netting agreements and qualify for net presentation in the Consolidated Balance Sheet. In the table below, Generation’s cash flow hedges, other derivatives and proprietary trading derivatives are shown gross and the impact of the netting of fair value balances with the same counterparty, as well as netting of collateral, is aggregated in the collateral and netting column. Excluded from the tables below are economic hedges that qualify for the normal purchases and normal sales exception and other non-derivative contracts that are accounted for under the accrual method of accounting.

The following table provides a summary of the derivative fair value balances recorded by Exelon, Generation, ComEd and PECO as of December 31, 2009:


	Generation															ComEd			PECO			Other					Exelon
Derivatives	Cash Flow Hedges ^(a,d)			Other Derivatives			Proprietary Trading			Collateral and Netting ^(b)			Subtotal^(c)			IL Settlement Swap ^(a)			Other Derivatives ^(d)			Other Derivatives		Inter- company Eliminations ^(a)			Total Derivatives
Mark-to-market derivative assets (current assets)	$	576		$	913		$	193		$	(1,306	)	$	376		$	—		$	—		$	—	$	—		$	376
Mark-to-market derivative assets with affiliate (current assets)		302			—			—			—			302			—			—			—		(302	)		—
Mark-to-market derivative assets (noncurrent assets)		423			792			102			(678	)		639			—			—			10		—			649
Mark-to-market derivative assets with affiliate (noncurrent assets)		671			—			—			—			671			—			—			—		(671	)		—

Total mark-to-market derivative assets	$	1,972		$	1,705		$	295		$	(1,984	)	$	1,988		$	—		$	—		$	10	$	(973	)	$	1,025

Mark-to-market derivative liabilities (current liabilities)	$	(18	)	$	(743	)	$	(172)		$	735		$	(198)		$	—			—		$	—	$	—		$	(198)
Mark-to-market derivative liability with affiliate (current liabilities)		—			—			—			—			—			(302	)		—			—		302			—
Mark-to-market derivative liabilities (noncurrent liabilities)		(42	)		(183	)		(98	)		302			(21	)		—			(2	)		—		—			(23	)
Mark-to-market derivative liabilities with affiliate (noncurrent liabilities)		—			—			—			—			—			(669	)		(2	)		—		671			—

Total mark-to-market derivative liabilities		(60	)		(926	)		(270	)		1,037			(219	)		(971	)		(4	)		—		973			(221	)

Total mark-to-market derivative net assets (liabilities)	$	1,912		$	779		$	25		$	(947	)	$	1,769		$	(971	)	$	(4	)	$	10	$	—		$	804

(a)	Includes current and noncurrent assets for Generation and current and noncurrent liabilities for ComEd of $302 million and $669 million, respectively, related to the fair value of Generation’s and ComEd’s five-year financial swap contract, as described above.

(b)	Represents the netting of fair value balances with the same counterparty and the application of collateral.

(c)

Current and noncurrent assets are shown net of collateral of $502 million and $376 million, respectively, and current liabilities are shown inclusive of collateral of $69 million, respectively. The allocation of collateral had no impact to noncurrent liabilities. The total cash collateral received net of cash collateral posted and offset against mark-to-market assets and liabilities was $947 million at December 31, 2009.

(d)	Includes a noncurrent liability for PECO and a noncurrent asset for Generation of $2 million related to the fair value of PECO’s block contracts with Generation. There were no netting adjustments or collateral received as of December 31, 2009.

The following table provides a summary of the derivative fair value balances recorded by Exelon, Generation and ComEd as of December 31, 2008:


	Generation															ComEd			Other					Exelon
Derivatives	Cash Flow Hedges^(a)(d)			Other Derivatives ^(d)			Proprietary Trading ^(d)			Collateral and Netting^(b)(d)			Subtotal ^(c)(d)			IL Settlement Swap ^(a)			Other Derivatives		Inter- company Eliminations ^(a)			Total Derivatives
Mark-to-market derivative assets (current assets)	$	610		$	1,295		$	376		$	(1,801	)	$	480		$	—		$	—	$	—		$	480
Mark-to-market derivative assets with affiliate (current assets)		111			—			—			—			111			—			—		(111	)		—
Mark-to-market derivative assets (noncurrent assets)		438			752			123			(651	)		662			—			17		—			679
Mark-to-market derivative assets with affiliate (noncurrent assets)		345			—			—			—			345			—			—		(345	)		—

Total mark-to-market derivative assets	$	1,504		$	2,047		$	499		$	(2,452	)	$	1,598		$	—		$	17	$	(456	)	$	1,159

Mark-to-market derivative liabilities (current liabilities)	$	(47	)	$	(1,253	)	$	(291	)	$	1,379		$	(212	)	$	—		$	—	$	—		$	(212	)
Mark-to-market derivative liability with affiliate (current liabilities)		—			—			—			—			—			(111	)		—		111			—
Mark-to-market derivative liabilities (noncurrent liabilities)		(20	)		(223	)		(100	)		320			(23	)		—			—		—			(23	)
Mark-to-market derivative liability with affiliate (noncurrent liabilities)		—			—			—			—			—			(345	)		—		345			—

Total mark-to-market derivative liabilities		(67	)		(1,476	)		(391	)		1,699			(235	)		(456	)		—		456			(235	)

Total mark-to-market derivative net assets (liabilities)	$	1,437		$	571		$	108		$	(753	)	$	1,363		$	(456	)	$	17	$	—		$	924

(a)

Includes current and noncurrent assets for Generation and current and noncurrent liabilities for ComEd of $111 million and $345 million, respectively, related to the fair value of Generation’s and ComEd’s five-year financial swap contract, as described above. At Exelon, the fair value balances are eliminated upon consolidation.

(b)	Represents the netting of fair value balances with the same counterparty and the application of collateral.

(c)

Current and noncurrent assets are shown net of collateral of $355 million and $333 million, respectively and current liabilities are shown inclusive of collateral of $65 million, respectively. The allocation of collateral had no impact to noncurrent liabilities. The total cash collateral received net of cash collateral posted and offset against mark-to-market assets and liabilities was $753 million at December 31, 2008.

(d)	Exelon and Generation retrospectively reclassified certain assets and liabilities with respect to option premiums into the mark-to-market net asset and liability accounts to conform with current year presentation, as discussed within this footnote.

Cash Flow Hedges (Exelon and Generation). Economic hedges that qualify as cash flow hedges primarily consist of forward power sales and power swaps on base load generation. At December 31, 2009, Generation had net unrealized pre-tax gains on effective cash flow hedges of $1,912 million being deferred within accumulated OCI, including approximately $971 million related to the financial swap with ComEd. Amounts recorded in accumulated OCI related to changes in energy commodity cash flow hedges are reclassified to results of operations when the forecasted purchase or sale of the energy commodity occurs. Reclassifications from OCI are included in operating revenues, purchased power and fuel in Exelon’s and Generation’s Consolidated Statements of Operations, depending on the commodities involved in the hedged transaction. Based on market prices at December 31, 2009, approximately $860 million of these net pre-tax unrealized gains within accumulated OCI are expected to be reclassified from accumulated OCI during the next twelve months by Generation, including approximately $302 million related to the financial swap with ComEd. However, the actual amount reclassified from accumulated OCI could vary due to future changes in market prices. Generation expects the settlement of the majority of its cash flow hedges will occur during 2010 through 2012, and the ComEd financial swap contract during 2010 through 2013.

Exelon discontinues hedge accounting prospectively when it determines that the derivative is no longer effective in offsetting changes in the cash flows of a hedged item, in the case of forward-starting hedges, or when it is no longer probable that the forecasted transaction will occur. For the year ended December 31, 2009, amounts reclassified into earnings as a result of the discontinuance of cash flow hedges were immaterial.

The table below provides the activity of accumulated OCI related to cash flow hedges for the year ended December 31, 2009 and 2008, containing information about the changes in the fair value of cash flow hedges and the reclassification from accumulated OCI into results of operations. The amounts reclassified from accumulated OCI, when combined with the impacts of the actual physical power sales, result in the ultimate recognition of net revenues at the contracted price.


	Income Statement Location	Total Cash Flow Hedge OCI Activity, Net of Income Tax
		Generation		Exelon
		Energy Related Hedges		Total Cash Flow Hedges
Accumulated OCI derivative gain (loss) at January 1, 2008		$(548	)^(a)	$	(292	)
Effective portion of changes in fair value		1,101	^(b)		567
Reclassifications from accumulated OCI to net income	Operating Revenue	328	^(c)		314
Ineffective portion recognized in income	Purchased Power	(26	)		(26	)
Accumulated OCI derivative gain at December 31, 2008		$855	^(a)	$	563
Effective portion of changes in fair value		1,227	^(b)		757
Reclassifications from accumulated OCI to net income	Operating Revenue	(939	)^(c)		(778	)
Ineffective portion recognized in income	Purchased Power	9			9

Accumulated OCI derivative gain (loss) at December 31, 2009		$1,152	^(a)(d)	$	551

(a)

Includes $585 million gain, $275 million gain and $275 million loss, net of taxes, related to the fair value of the five-year financial swap contract with ComEd for the years ended December 31, 2009, 2008 and 2007, respectively, and $1 million of gains, net of taxes, related to the fair value of the block contracts with PECO as of December 31, 2009.

(b)

Includes $471 million and $535 million of gains, net of taxes, of the effective portion of changes in fair value of the five-year financial swap contract with ComEd for the years ended December 31, 2009 and 2008, respectively, and $1 million of gain, net of taxes, of the effective portion of changes in fair value of the block contracts with PECO for the year ended December 31, 2009.

(c)	Includes $161 million loss and $15 million gain, net of taxes, of reclassifications from accumulated OCI to net income related to the settlements of the five-year financial swap contract with ComEd for the years ended December 31, 2009 and 2008, respectively.

(d)	Excludes $5 million of gains, net of taxes, related to interest rate swaps settled in 2009. See Note 9 – Debt and Credit Agreements for further information.

During the years ended December 31, 2009, 2008 and 2007, Generation’s cash flow hedge activity impact to pre-tax earnings based on the reclassification adjustment from accumulated OCI to earnings was a $1,559 million pre-tax gain, a $544 million pre-tax loss and a $15 million pre-tax gain, respectively. Given that the cash flow hedges primarily consist of forward power sales and power swaps and do not include gas options or sales, the ineffectiveness of Generation’s cash flow hedges is primarily the result of differences between the locational settlement prices of the cash flow hedges and the hedged generating units. This price difference is actively managed through other instruments which include financial transmission rights, whose changes in fair value are recognized in earnings each period, and auction revenue rights. Changes in cash flow hedge ineffectiveness, primarily due to changes in market prices, were $15 million, $44 million and $29 million for the years ended December 31, 2009, 2008, and 2007, respectively. At December 31, 2008 cash flow hedge ineffectiveness resulted in an adjustment of $15 million to accumulated OCI on the balance sheet in order to reflect the effective portion of derivative gains or losses. At December 31, 2009, cash flow hedge ineffectiveness was not significant.

Exelon’s energy related cash flow hedge activity impact to pre-tax earnings based on the reclassification adjustment from accumulated OCI to earnings was a $1,292 million pre-tax gain, $521 million pre-tax loss and $10 million pre-tax gain for the years ended December 31, 2009, 2008 and 2007, respectively. Changes in cash flow hedge ineffectiveness, primarily due to changes in market prices, were $15 million, $44 million and $29 million for the years ended December 31, 2009, 2008 and 2007, respectively.

Other Derivatives (Exelon and Generation). Other derivative contracts are those that do not qualify or are not designated for hedge accounting. These instruments represent economic hedges that mitigate exposure to fluctuations in commodity prices and include financial options, futures, swaps, and forward sales. For the years ended December 31, 2009, 2008 and 2007, the following net pre-tax mark-to-market gains (losses) of certain purchase and sale contracts were reported in fuel and purchased power expense at Exelon and Generation in the Consolidated Statements of Operations and are included in net fair value changes related to derivatives in Exelon’s and Generation’s Consolidated Statements of Cash Flows. In the tables below, “Change in fair value” represents the change in fair value of the derivative contracts held at the reporting date. The “Reclassification to realized at settlement” represents the recognized change in fair value that was reclassified to realized due to settlement of the derivative during the period.


	Exelon and Generation
For the Year Ended December 31, 2009	Purchased Power			Fuel			Total
Change in fair value	$	206		$	(72	)	$	134
Reclassification to realized at settlement		(97	)		159			62

Net mark-to-market gains (losses)	$	109		$	87		$	196


	Exelon and Generation
For the Year Ended December 31, 2008	Purchased Power			Fuel			Total
Change in fair value	$	315		$	180		$	495
Reclassification to realized at settlement		55			(143	)		(88	)

Net mark-to-market gains (losses)	$	370		$	37		$	407


	Exelon and Generation
For the Year Ended December 31, 2007 ^(a)	Purchased Power			Fuel			Total
Change in fair value	$	(6	)	$	(37	)	$	(43	)
Reclassification to realized at settlement		(218	)		118			(100	)

Net mark-to-market gains (losses)	$	(224	)	$	81		$	(143	)

(a)	Table excludes $4 million related to ComEd included within revenue and $27 million related to other included within fuel expense.

Proprietary Trading Activities (Exelon and Generation). For the years ended December 31, 2009, 2008 and 2007, Exelon and Generation recognized the following net pre-tax mark-to-market gains (losses) of certain purchase and sale contracts entered into for proprietary trading purposes. Gains and losses associated with proprietary trading are reported as revenue in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income and are included in Net fair value changes related to derivatives in Exelon’s and Generation’s Consolidated Statements of Cash Flows. In the tables below, “Change in fair value” represents the change in fair value of the derivative contracts held at the reporting date. The “Reclassification to realized at settlement” represents the recognized change in fair value that was reclassified to realized due to settlement of the derivative during the period.


	Location on Income Statement	For the Year Ended December 31,
	Location on Income Statement	2009			2008			2007
Change in fair value	Operating Revenue	$	3		$	106		$	42
Reclassification to realized at settlement	Operating Revenue		(86	)		(43	)		(8	)

Net mark-to-market gains (losses)	Operating Revenue	$	(83	)	$	63		$	34

Credit Risk (Exelon, Generation, ComEd and PECO)

The Registrants would be exposed to credit-related losses in the event of non-performance by counterparties that enter into derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date. For energy-related derivative instruments, Generation enters into enabling agreements that allow for payment netting with its counterparties, which reduces Generation’s exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. Typically, each enabling agreement is for a specific commodity and so, with respect to each individual counterparty, netting is limited to transactions involving that specific commodity product, except where master netting agreements exist with a counterparty that allow for cross-product netting. In addition to payment netting language in the enabling agreement, Generation’s credit department establishes credit limits, margining thresholds and collateral requirements for each counterparty, which are defined in the derivative contracts. Counterparty credit limits are based on an internal credit review that considers a variety of factors, including the results of a scoring model, leverage, liquidity, profitability, credit ratings and risk management capabilities. To the extent that a counterparty’s margining thresholds are exceeded, the counterparty is required to post collateral with Generation as specified in each enabling agreement. Generation’s credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis.

The following tables provide information on Generation’s credit exposure for all derivative instruments, which includes contracts that qualify for the normal purchases and normal sales exception, and applicable payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of December 31, 2009. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties and an indication of the maturity of a company’s credit risk by credit rating of the counterparties. The figures in the tables below do not include credit risk exposure from uranium procurement contracts or exposure through RTOs, ISOs and NYMEX and ICE commodity exchanges, which are discussed below. Additionally, the figures in the tables below do not include exposures with affiliates, including net receivables with ComEd and PECO of $123 million and $174 million, respectively. See Note 21—Related-Party Transactions for further information.


Rating as of December 31, 2009	Total Exposure Before Credit Collateral		Credit Collateral		Net Exposure		Number of Counterparties Greater than 10% of Net Exposure	Net Exposure of Counterparties Greater than 10% of Net Exposure
Investment grade	$	1,183	$	464	$	719	1	$	76
Non-investment grade		15		5		10	—		—
No external ratings
Internally rated—investment grade		34		5		29	—		—
Internally rated—non-investment grade		1		1		—	—		—

Total	$	1,233	$	475	$	758	1	$	76


Net Credit Exposure by Type of Counterparty	December 31, 2009
Financial institutions	$	259
Investor-owned utilities, marketers and power producers		431
Other		68

Total	$	758

ComEd’s power procurement contracts provide suppliers with a certain amount of unsecured credit. The credit position is based on the price of energy in the spot market compared to the benchmark prices. The benchmark prices are the future prices of energy projected through the contract term and are set at the point of contract execution. If the price of energy in the spot market exceeds the benchmark price, the suppliers are required to post collateral for the secured credit portion. The unsecured credit used by the suppliers represents ComEd’s net credit exposure. As of December 31, 2009, ComEd’s net credit exposure to energy suppliers was immaterial and either did not exceed the allowed unsecured credit levels or did not exceed the allowed unsecured credit levels by an amount necessary to trigger a collateral call.

ComEd is permitted to recover its costs of procuring energy through the Illinois Settlement Legislation as well as the ICC-approved procurement tariffs. ComEd’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 2—Regulatory Issues for further information.

PECO has a PPA with Generation under which Generation has agreed to supply PECO with all of PECO’s electric supply needs through 2010 at prices that are below current market prices. The price for this electricity is essentially equal to the energy revenues earned from customers. PECO could be negatively affected if Generation could not perform under the PPA.

PECO’s supplier master agreements that govern the terms of its DSP program contracts, which define a supplier’s performance assurance requirements, allow a supplier to meet its credit requirements with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s lowest credit rating from S&P, Fitch or Moody’s and the supplier’s tangible net worth. The credit position is based on the initial market price, which is the forward price of energy on the day a transaction is executed, compared to the current forward price curve for energy. To the extent that the forward price curve for energy exceeds the initial market price, the supplier is required to post collateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. As of December 31, 2009, PECO had no net credit exposure to energy suppliers.

PECO is permitted to recover its costs of procuring electric generation following the expiration of its electric generation rate caps on December 31, 2010 through its PAPUC-approved DSP program. PECO’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 2—Regulatory Issues for further information.

PECO’s natural gas procurement plan is reviewed and approved annually on a prospective basis by the PAPUC. PECO’s counterparty credit risk under its natural gas supply and management agreements is mitigated by its ability to recover its natural gas costs through the PGC, which allows PECO to adjust rates quarterly to reflect realized natural gas prices. PECO does not obtain collateral from suppliers under its natural gas supply and management agreements. As of December 31, 2009, PECO had credit exposure of $13 million under its natural gas supply and management agreements.

Collateral and Contingent-Related Features (Exelon, Generation, ComEd, and PECO)

As part of the normal course of business, Generation routinely enters into physical and financial contracts for the purchase and sale of electricity, fossil fuels, and other commodities. Certain of Generation’s derivative instruments contain provisions that require Generation to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon Generation’s credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. These credit-risk-related contingent features stipulate that if Generation were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. Where applicable, this incremental collateral requirement allows for the offsetting of derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master netting agreements. Generation also enters into commodity transactions on NYMEX and ICE. The NYMEX and ICE clearing houses act as the counterparty to each trade. Transactions on the NYMEX and ICE must adhere to comprehensive collateral and margining requirements.

The aggregate fair value of all derivative instruments with credit-risk-related contingent features, excluding transactions on NYMEX and ICE that are fully collateralized, that are in a liability position and are not fully collateralized was $894 million and $1,299 million as of December 31, 2009 and December 31 2008, respectively. As of December 31, 2009 and 2008, Generation had the contractual right of offset of $778 million and $1,175 million, respectively, related to derivative instruments that are assets with the same counterparty under master netting agreements, resulting in a net liability position of $116 million and $124 million, respectively. If Generation had been downgraded to the investment grade rating of BBB- and Baa3, or lost its investment grade credit rating, it would have been required to provide incremental collateral of approximately $60 million or $673 million, respectively, as of December 31, 2009 and approximately $14 million or $612 million, respectively, as of December 31, 2008 related to its financial instruments, including derivatives, non-derivatives, normal purchase normal sales contracts and applicable payables and receivables, net of the contractual right of offset under master netting agreements and the application of collateral. See Note 18 of the Combined Notes to Consolidated Financial Statements for information regarding the letters of credit supporting the cash collateral.

Beginning in 2007, under the Illinois auction rules and the SFCs that ComEd entered into with counterparty suppliers, including Generation, collateral postings are one-sided from suppliers. Generation entered into similar SFCs with Ameren, with one-sided collateral postings only from Generation. If market prices fall below ComEd’s or Ameren’s benchmark price levels, ComEd or Ameren are not required to post collateral; however, when market prices rise above benchmark price levels with ComEd or Ameren, counterparty suppliers, including Generation, are required to post collateral once certain unsecured credit limits are exceeded. Under the terms of the five-year financial swap contract between Generation and ComEd, if a party is downgraded below investment grade by Moody’s or S&P, collateral postings would be required by that party depending on how market prices compare to the benchmark price levels. Under the terms of the financial swap contracts, collateral postings will never exceed $200 million from either ComEd or Generation. Beginning in June 2009, under the terms of ComEd’s standard block energy contracts, collateral postings are one-sided from suppliers, including Generation, should exposures between market prices and benchmark prices exceed established unsecured credit limits outlined in the contracts. As of December 31, 2009, there was no cash collateral or letters of credit posted between energy suppliers, including Generation, and ComEd, under any of the above-mentioned contracts. See Note 2—Regulatory Issues for further information.

There are no collateral-related provisions included in the PPA between PECO and Generation. PECO’s supplier master agreements that govern the terms of its DSP program contracts do not contain provisions that would require PECO to post collateral.

PECO’s natural gas procurement contracts contain provisions that could require PECO to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon PECO’s credit rating from Moody’s and S&P. The collateral and credit support requirements vary by contract and by counterparty. As of December 31, 2009, PECO was not required to post collateral for any of these agreements. If PECO lost its investment grade credit rating as of December 31, 2009, PECO could have been required to post approximately $49 million of collateral to its counterparties.

Exelon’s interest rate swaps contain provisions that, in the event of a merger, require that Exelon’s debt maintain an investment grade credit rating from Moody’s or S&P. If Exelon’s debt were to fall below investment grade, it would be in violation of these provisions, resulting in the ability of the counterparty to terminate the agreement prior to maturity. Collateralization would not be required under any circumstance. Termination of the agreement could result in a settlement payment by Exelon or the counterparty on any interest rate swap in a net liability position. The settlement amount would be equal to the fair value of the swap on the termination date. As of December 31, 2009, Exelon’s interest rate swap was in an asset position, with a fair value of $10 million.

Accounting for the Offsetting of Amounts Related to Certain Contracts (Exelon and Generation)

On January 1, 2008, Exelon and Generation adopted guidance permitting companies to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement. Exelon and Generation record cash flow hedges and other derivative and proprietary trading activities in the balance sheet on a net basis and offset the fair value amounts recognized for energy-related derivatives with cash collateral paid to or received from counterparties under master netting arrangements.

As of December 31, 2009 and 2008, $6 million and $5 million, respectively, of cash collateral received was not offset against net derivative positions, as they were not associated with energy-related derivatives.

Change in Balance Sheet Presentation of Option Premiums (Exelon and Generation)

Exelon and Generation have historically presented premiums received and paid on energy-related option contracts within other current assets, other current liabilities, other noncurrent assets or other noncurrent liabilities depending on the nature and term of the underlying option contract. The associated changes in the fair value of the option contracts were recorded in mark-to-market derivative balance sheet line items. Effective December 31, 2009, Exelon and Generation have reclassified the option premiums to the respective mark-to-market derivative asset and liability lines within the Consolidated Balance Sheets to reflect the combined fair value of the option contracts as of the balance sheet date. The December 31, 2008 balances were adjusted to reflect the impacts of this change in presentation, which is presented in the following table.


	Generation							Exelon
	As Previously Stated		Option Premium Adjustments			As Adjusted		As Previously Stated		Option Premium Adjustments			As Adjusted
Mark-to-market derivative current assets	$	410	$	70		$	480	$	410	$	70		$	480
Other		410		(308	)		102		517		(308	)		209

Total Current Assets		3,724		(238	)		3,486		5,368		(238	)		5,130

Mark-to-market derivative noncurrent assets		490		172			662		507		172			679
Other		406		(205	)		201		1,349		(205	)		1,144

Total Noncurrent Assets		7,724		(33	)		7,691		16,636		(33	)		16,603

Total Assets		20,355		(271	)		20,084		47,817		(271	)		47,546

Mark-to-market derivative current liabilities		214		(2	)		212		214		(2	)		212
Other		324		(267	)		57		663		(267	)		396

Total current liabilities		2,437		(269	)		2,168		4,080		(269	)		3,811

Mark-to-market derivative noncurrent liabilities		24		(1	)		23		24		(1	)		23
Other		332		(1	)		331		1,413		(1	)		1,412

Total Noncurrent Liabilities		8,850		(2	)		8,848		20,011		(2	)		20,009

Total Liabilities and Equity		20,355		(271	)		20,084		47,817		(271	)		47,546

Debt and Credit Agreements (Exelon, Generation, ComEd and PECO)

12 Months Ended

Dec. 31, 2009

Statement [Line Items]

Debt and Credit Agreements (Exelon, Generation, ComEd and PECO)

9. Debt and Credit Agreements (Exelon, Generation, ComEd and PECO)

Short-Term Borrowings

Exelon meets its short-term liquidity requirements primarily through the issuance of commercial paper. Generation and PECO meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the intercompany money pool. ComEd meets its short-term liquidity requirements primarily through borrowings under its credit facility.

Exelon, Generation, ComEd and PECO had the following amounts of commercial paper and credit facility borrowings outstanding at December 31, 2009 and 2008:


Commercial Paper Issuer	Maximum Program Size at December 31, 2009 ^(a)		Maximum Program Size at December 31, 2008 ^(a)		Outstanding Commercial Paper at December 31, 2009		Outstanding Commercial Paper at December 31, 2008
Exelon Corporate	$	957	$	957	$	—	$	56
Generation		4,834		4,834		—		—
ComEd ^(b)		952		952		—		—
PECO		574		574		—		95

Total	$	7,317	$	7,317	$	—	$	151

(a)	Equals aggregate bank commitments under revolving credit agreements.

(b)

Prior to July 22, 2009, ComEd was unable to access the commercial paper market given the market environment. On July 22, 2009, ComEd’s commercial paper rating was upgraded giving it limited access to the commercial paper market. However, ComEd did not issue commercial paper due to more favorable rates available to it on credit facility draws.


Credit facility borrowings	December 31, 2009		December 31, 2008
ComEd	$	155	$	60

In order to maintain their respective commercial paper programs in the amounts indicated above, each Registrant must have revolving credit facilities in place, at least equal to the amount of its commercial paper program. While the amount of its commercial paper outstanding does not reduce available capacity under a Registrant’s credit agreement, each Registrant cannot issue commercial paper in an aggregate amount exceeding the available capacity under its credit agreement.

The following tables present the short-term borrowings activity for Exelon, Generation, ComEd and PECO during 2009, 2008 and 2007:

Exelon


	2009			2008			2007
Average borrowings	$	132		$	636		$	500
Maximum borrowings outstanding		523			1,646			1,210
Average interest rates, computed on a daily basis		0.73	%		3.22	%		5.55	%
Average interest rates, at December 31		0.69	%		0.93	%		5.44	%

Generation


	2009		2008			2007
Average borrowings	$	—	$	340		$	44
Maximum borrowings outstanding		—		1,211			740
Average interest rates, computed on a daily basis		n.a.		3.13	%		5.51	%
Average interest rates, at December 31		n.a.		n.a.			n.a.

ComEd


	2009			2008			2007
Average borrowings	$	82		$	140		$	291
Maximum borrowings outstanding		265			568			605
Average interest rates, computed on a daily basis		0.79	%		3.91	%		6.01	%
Average interest rates, at December 31		0.69	%		0.96	%		5.63	%

PECO


	2009			2008			2007
Average borrowings	$	11		$	82		$	76
Maximum borrowings outstanding		290			284			374
Average interest rates, computed on a daily basis		0.67	%		3.22	%		5.09	%
Average interest rates, computed at December 31		n.a.			0.9	%		5.41	%

n.a.	Not applicable.

Credit Agreements

As of December 31, 2009, Exelon Corporate, Generation and PECO had access to separate unsecured credit facilities with aggregate bank commitments of $957 million, $4.8 billion and $574 million, respectively. The credit agreements expire on October 26, 2012 unless extended in accordance with their terms. Under their credit facilities, Exelon Corporate, Generation and PECO may request additional one-year extensions of that term. In addition, Exelon Corporate, Generation and PECO may request increases in the aggregate bank commitments under their credit facilities up to an additional $250 million, $1 billion and $200 million, respectively. Generation also had additional letter of credit facilities used solely to enhance tax-exempt variable rate debt as discussed further below.

As of December 31, 2009, ComEd had access to an unsecured credit facility with aggregate bank commitments of $952 million. The credit facility expires February 16, 2011. ComEd expects to extend or refinance the facility up to $1 billion in 2010. Any increases in aggregate bank commitments are subject to identifying lenders, whether existing or new, willing to provide the additional commitments and, in the case of any new lenders, the consent of the Administrative Agent (appointed and authorized by credit facility lenders to exercise powers delegated in the credit agreement) and certain of the lenders under the credit facility.

The Registrants may use the credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit. The obligation of each lender to make any credit extension to a Registrant under its credit facilities is subject to various conditions including, among other things, that no event of default has occurred for the Registrant or would result from such credit extension. An event of default under any of the Registrants’ credit facilities will not constitute an event of default under any of the other Registrants’ credit facilities, except that a bankruptcy or other event of default in the payment of principal, premium or indebtedness in principal amount in excess of $100 million in the aggregate by Generation under its credit facility will constitute an event of default under the Exelon corporate credit facility.

At December 31, 2009, the Registrants had the following aggregate bank commitments, credit facility borrowings and available capacity under the credit agreements:


Borrower	Aggregate Bank Commitment ^(a)		Outstanding Borrowings/ Facility Draws		Outstanding Letters of Credit		Available Capacity under Revolving Credit Agreements
Exelon Corporate	$	957	$	—	$	5	$	952
Generation		4,834		—		167		4,667
ComEd		952		155		251		546
PECO		574		—		10		564

Total	$	7,317	$	155	$	433	$	6,729

(a)	Excludes $67 million of credit facility agreements arranged with minority and community banks in October 2009, which are primarily for issuing letters of credit.

Interest rates on advances under the credit facilities are based on the prime rate or LIBOR plus an adder based on the credit rating of the borrower as well as the total outstanding amounts under the agreement at the time of borrowing. In the cases of Exelon, Generation and PECO, the maximum LIBOR adder is 65 basis points; and in the case of ComEd, it is 162.5 basis points.

Each credit agreement requires the affected borrower 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 and Generation, interest on the debt of its project subsidiaries. The following table summarizes the minimum thresholds reflected in the credit agreements for the year ended December 31, 2009:


	Exelon	Generation	ComEd	PECO
Credit agreement threshold	2.50 to 1	3.00 to 1	2.00 to 1	2.00 to 1

At December 31, 2009 the interest coverage ratios at the Registrants were as follows:


	Exelon	Generation	ComEd	PECO
Interest coverage ratio	13.97	35.65	5.52	5.65

Variable Rate Debt

Generation repurchased $46 million in unenhanced tax-exempt variable-rate debt on February 23, 2009 due to a failed remarketing. In June 2009, Generation refinanced the debt with $46 million in bonds at a term rate through May 2012 with a maturity of 2042.

During the second quarter of 2009, ComEd repurchased $191 million of its credit enhanced variable-rate tax-exempt debt. This debt was then remarketed with credit enhancement provided by letters of credit issued under ComEd’s unsecured revolving credit facility. The letters of credit expire shortly before the expiration of the credit facility in 2011.

Generation had letters of credit that expired during the third quarter of 2009, which were used to credit enhance variable-rate long-term tax-exempt debt totaling $307 million, with maturities ranging from 2021 – 2034. Generation could not find alternative letters of credit at reasonable terms, and therefore repurchased the $307 million in tax-exempt debt during September 2009. Generation has the ability to remarket these bonds whenever it determines it to be economically advantageous given market conditions. In addition, Generation has letter of credit facilities that will expire in the second quarter of 2010, which are used to credit enhance variable-rate long-term tax-exempt debt totaling $213 million, of which $189 million will mature between 2016 – 2034. Generation intends to extend or replace the expiring letters of credit with new letters of credit at reasonable terms, or remarket the bonds with an interest rate term not requiring letter of credit support. If Generation is unable to remarket these bonds at reasonable terms, Generation will repurchase them.

Under the terms of Generation’s and ComEd’s variable-rate tax-exempt debt agreements, Generation or ComEd may be required to repurchase any outstanding debt before its stated maturity unless supported by sufficient letters of credit. If either Generation or ComEd were required to repurchase the debt, it would reassess its options to obtain new letters of credit or remarket the bonds in a manner that does not require letter of credit support. Generation and ComEd have classified certain amounts outstanding under these debt agreements as long-term based on management’s intent and ability to either renew or replace the letters of credit, refinance the debt at reasonable terms on a long-term fixed-rate basis or utilize the capacity under existing long-term credit facilities.

Long-Term Debt

The following tables present the outstanding long-term debt at Exelon, Generation, ComEd and PECO as of December 31, 2009 and 2008:

Exelon


	Rates	Maturity Date	December 31,
	Rates	Maturity Date	2009			2008
Long-term debt
First Mortgage Bonds ^(a) (b):
Fixed rates	4.70%-7.625%	2010-2038	$	6,630		$	6,396
Floating rates	0.22%-0.26%	2017-2021		191			191
Notes payable and other ^(c)	4.45%-7.83%	2010-2039		4,578			4,290
Pollution control notes:
Floating rates	0.29%-0.35%	2016-2034		213			566
Fixed rates	5.00%	2042		46			—
Sinking fund debentures	4.75%	2011		2			4

Total long-term debt				11,660			11,447
Unamortized debt discount and premium, net				(35	)		(37	)
Unamortized settled fair value hedge, net				(1	)		(1	)
Fair value hedge carrying value adjustment, net				10			17
Long-term debt due within one year				(639	)		(29	)

Long-term debt			$	10,995		$	11,397

Long-term debt to financing trusts ^(d)
Payable to PETT	6.52%	2010		415			1,124
Subordinated debentures to ComEd Financing III	6.35%	2033		206			206
Subordinated debentures to PECO Trust III	7.38%	2028		81			81
Subordinated debentures to PECO Trust IV	5.75%	2033		103			103

Total long-term debt to financing trusts				805			1,514
Long-term debt due to financing trusts due within one year				(415	)		(319	)

Long-term debt to financing trusts			$	390		$	1,195

(a)	Substantially all of ComEd’s assets other than expressly excepted property and substantially all of PECO’s assets are subject to the liens of their respective mortgage indentures.

(b)	Includes First Mortgage Bonds issued under the ComEd and PECO mortgage indentures securing pollution control bonds and notes.

(c)	Includes capital lease obligations of $38 million and $40 million at December 31, 2009 and 2008, respectively. Lease payments of $2 million, $2 million, $3 million, $3 million, $3 million and $25 million will be made in 2010, 2011, 2012, 2013, 2014 and thereafter, respectively.

(d)	Amounts owed to these financing trusts are recorded as debt to financing trusts within Exelon’s Consolidated Balance Sheets.

On September 23, 2009, Generation issued and sold $1.5 billion of Senior Notes. In connection with this debt issuance, Generation entered into forward-starting interest rate swaps in the aggregate notional amount of $1.1 billion. The interest rate swaps were settled on September 16, 2009 with Generation recording a pre-tax gain of approximately $7 million. The gain was recorded to OCI within Generation’s Consolidated Balance Sheet and is being amortized over the life of the related debt as a reduction in interest expense.

Additionally, during 2009, Exelon retired $1.2 billion of Senior Notes of which $500 million consisted of 6.75% Exelon Corporate Senior Notes due May 1, 2011 and $700 million consisted of 6.95% Generation Senior Notes due June 15, 2011. In connection with these retirements, Exelon incurred losses associated with the early retirement of debt of approximately $117 million, which consisted of $46 million at Exelon Corporate and $71 million at Generation. The expense related to the charges is included within Other, net in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

Generation


	Rates	Maturity Date	December 31,
	Rates	Maturity Date	2009			2008
Long-term debt
Senior unsecured notes	5.20%-6.25%	2014-2039	$	2,700		$	1,900
Pollution control notes, floating rates	0.29%-0.35%	2016-2034		213			566
Pollution control notes, fixed rates	5.00%	2042		46			—
Notes payable and other ^(a)	7.83%	2010-2020		38			50

Total long-term debt				2,997			2,516
Unamortized debt discount and premium, net				(4	)		(2	)
Long-term debt due within one year				(26	)		(12	)

Long-term debt			$	2,967		$	2,502

(a)	Includes Generation’s capital lease obligations of $38 million and $40 million at December 31, 2009 and 2008, respectively. Generation will make lease payments of $2 million, $2 million, $3 million, $3 million, $3 million and $25 million in 2010, 2011, 2012, 2013, 2014 and thereafter, respectively.

ComEd


	Rates	Maturity Date	December 31,
	Rates	Maturity Date	2009			2008
Long-term debt
First Mortgage Bonds ^(a)(b):
Fixed rates	4.70%-7.625%	2010-2038	$	4,405		$	4,421
Floating rates	0.22%-0.26%	2017-2021		191			191
Notes payable
Fixed rates	6.95%	2018		140			140
Sinking fund debentures	4.75%	2011		2			4

Total long-term debt				4,738			4,756
Unamortized debt discount and premium, net				(26	)		(29	)
Unamortized settled fair value hedge, net				(1	)		(1	)
Long-term debt due within one year				(213	)		(17	)

Long-term debt			$	4,498		$	4,709

Long-term debt to financing trust ^(c)
Subordinated debentures to ComEd Financing III	6.35%	2033	$	206		$	206

(a)	Substantially all of ComEd’s assets other than expressly excepted property are subject to the lien of its mortgage indenture.

(b)	Includes First Mortgage Bonds issued under the ComEd mortgage indenture securing pollution control bonds and notes.

(c)	Amount owed to this financing trust is recorded as debt to financing trust within ComEd’s Consolidated Balance Sheets.

PECO


	Rates		Maturity Date	December 31,
	Rates		Maturity Date	2009			2008
Long-term debt
First Mortgage Bonds ^(a)(b):
Fixed rates	4.00%-5.95%		2011-2037	$	2,225		$	1,975

Total long-term debt					2,225			1,975
Unamortized debt discount and premium, net					(4	)		(4	)

Long-term debt				$	2,221		$	1,971

Long-term debt to financing trusts ^(c)
PETT Series 2000-A	7.65	%	2009	$	—		$	319
PETT Series 2001	6.52	%	2010		415			805
Subordinated debentures to PECO Trust III	7.38	%	2028		81			81
Subordinated debentures to PECO Trust IV	5.75	%	2033		103			103

Total long-term debt to financing trusts					599			1,308
Long-term debt due to financing trusts due within one year					(415	)		(319	)

Long-term debt to financing trusts				$	184		$	989

(a)	Substantially all of PECO’s assets are subject to the lien of its mortgage indenture.

(b)	Includes First Mortgage Bonds issued under the PECO mortgage indenture securing pollution control bonds and notes.

(c)	Amounts owed to these financing trusts are recorded as debt to financing trusts within PECO’s Consolidated Balance Sheets.

Long-term debt maturities at Exelon, Generation, ComEd and PECO in the periods 2010 through 2014 and thereafter are as follows:


Year	Exelon			Generation		ComEd			PECO
2010	$	1,054	^(a)	$	26	$	213		$	415	^(c)
2011		599			2		347			250
2012		828			3		450			375
2013		555			3		252			300
2014		770			503		17			250
Thereafter		8,659	^(a)		2,460		3,665	^(b)		1,234	^(c)

Total	$	12,465		$	2,997	$	4,944		$	2,824

(a)	Includes $415 million and $390 million due in 2010 and thereafter, respectively, due to ComEd and PECO financing trusts.

(b)	Includes $206 million due to ComEd financing trust.

(c)	Includes $415 million and $184 million due in 2010 and thereafter, respectively, due to PECO financing trusts.

See Note 3—Accounts Receivable for information regarding PECO’s accounts receivable agreement.

See Note 8—Derivative Financial Instruments for additional information regarding interest rate swaps.

See Note 15—Preferred Securities for additional information regarding preferred securities.

Income Taxes (Exelon, Generation, ComEd and PECO)

12 Months Ended

Dec. 31, 2009

Statement [Line Items]

Income Taxes (Exelon, Generation, ComEd and PECO)

10. Income Taxes (Exelon, Generation, ComEd and PECO)

Income tax expense (benefit) from continuing operations is comprised of the following components:


For the Year Ended December 31, 2009	Exelon			Generation			ComEd			PECO
Included in operations:
Federal
Current	$	803		$	631		$	(39	)	$	329
Deferred		775			648			228			(143	)
Investment tax credit amortization		(12	)		(7	)		(3	)		(2	)
State
Current		154			131			4			26
Deferred		(8	)		30			39			(64	)

Total	$	1,712		$	1,433		$	229		$	146


For the Year Ended December 31, 2008	Exelon			Generation			ComEd			PECO
Included in operations:
Federal
Current	$	790		$	669		$	(125	)	$	327
Deferred		341			229			230			(147	)
Investment tax credit amortization		(12	)		(7	)		(3	)		(2	)
State
Current		169			150			(7	)		43
Deferred		29			89			33			(71	)

Total	$	1,317		$	1,130		$	128		$	150


For the Year Ended December 31, 2007	Exelon			Generation			ComEd			PECO
Included in operations:
Federal
Current	$	1,269		$	1,144		$	2		$	372
Deferred		34			(20	)		65			(133	)
Investment tax credit amortization		(12	)		(7	)		(3	)		(2	)
State
Current		285			249			(3	)		45
Deferred		(130	)		(4	)		19			(52	)

Total	$	1,446		$	1,362		$	80		$	230

The effective income tax rate from continuing operations varies from the U.S. Federal statutory rate principally due to the following:


For the Year Ended December 31, 2009	Exelon		Generation		ComEd		PECO
U.S. Federal statutory rate	35.0	%	35.0	%	35.0	%	35.0	%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	2.1		3.0		4.7		(5.0	)
Qualified nuclear decommissioning trust fund income	3.1		3.8		—		—
Domestic production activities deduction	(0.9	)	(1.1	)	—		—
Tax exempt income	(0.1	)	(0.2	)	—		—
Nontaxable postretirement benefits	(0.2	)	(0.2	)	(0.5	)	(0.3	)
Amortization of investment tax credit	(0.2	)	(0.1	)	(0.5	)	(0.4	)
Plant basis differences	—		—		(0.3	)	(0.1	)
Other	—		0.1		(0.4	)	0.1

Effective income tax rate	38.8	%	40.3	%	38.0	%	29.3	%


For the Year Ended December 31, 2008	Exelon		Generation		ComEd		PECO
U.S. Federal statutory rate	35.0	%	35.0	%	35.0	%	35.0	%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	3.2		4.6		5.0		(3.9	)
Qualified nuclear decommissioning trust fund losses	(3.2	)	(3.8	)	—		—
Domestic production activities deduction	(1.3	)	(1.6	)	—		—
Tax exempt income	(0.2	)	(0.3	)	—		—
Nontaxable postretirement benefits	(0.3	)	(0.2	)	(0.8	)	(0.3	)
Amortization of investment tax credit	(0.2	)	(0.1	)	(0.9	)	(0.5	)
Plant basis differences	—		—		—		0.3
Other	(0.4	)	(0.2	)	0.6		1.0

Effective income tax rate	32.6	%	33.4	%	38.9	%	31.6	%


For the Year Ended December 31, 2007	Exelon		Generation		ComEd		PECO
U.S. Federal statutory rate	35.0	%	35.0	%	35.0	%	35.0	%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	2.5		4.8		4.0		(0.6	)
Synthetic fuel-producing facilities credit	(1.9	)	—		—		—
Qualified nuclear decommissioning trust fund income	1.0		1.2		—		—
Domestic production activities deduction	(1.4	)	(1.7	)	—		—
Tax exempt income	(0.3	)	(0.4	)	—		—
Nontaxable postretirement benefits	(0.3	)	(0.2	)	(1.2	)	(0.3	)
Amortization of investment tax credit	(0.3	)	(0.1	)	(1.2	)	(0.3	)
Indirect cost capitalization method change	—		1.0		(4.6	)	(3.0	)
Research and development credit charge (refund)	0.6		0.7		—		—
Plant basis differences	—		—		—		0.3
Other	(0.2	)	(0.1	)	0.7		0.1

Effective income tax rate	34.7	%	40.2	%	32.7	%	31.2	%

The tax effects of temporary differences, which give rise to significant portions of the deferred tax assets (liabilities), as of December 31, 2009 and 2008 are presented below:


For the Year Ended December 31, 2009	Exelon			Generation			ComEd			PECO
Plant basis differences	$	(5,838	)	$	(1,638	)	$	(2,333	)	$	(1,710	)
Stranded cost recovery		(567	)		—			—			(567	)
Unrealized gains on derivative financial		(613	)		(971	)		(5	)		(1	)
instruments					—			—
Deferred pension and post-retirement obligation ^(a)		1,312			(161	)		(248	)		26
Emission allowances		(24	)		(24	)		—			—
Nuclear decommissioning activities ^(a)		(334	)		(334	)		—			—
Deferred debt refinancing costs		(59	)		(3	)		(47	)		(9	)
Goodwill		4			(1	)		—			—
Other, net ^(a)		441			210			56			94

Deferred income tax liabilities (net)	$	(5,678	)	$	(2,922	)	$	(2,577	)	$	(2,167	)
Unamortized investment tax credits		(224	)		(184	)		(32	)		(9	)

Total deferred income tax liabilities (net) and unamortized investment tax credits	$	(5,902	)	$	(3,106	)	$	(2,609	)	$	(2,176	)


For the Year Ended December 31, 2008	Exelon			Generation			ComEd			PECO
Plant basis differences	$	(5,139	)	$	(1,289	)	$	(2,067	)	$	(1,609	)
Stranded cost recovery		(896	)		—			—			(896	)
Unrealized gains on derivative financial instruments		(561	)		(749	)		(5	)		(1	)
Deferred pension and post-retirement obligation		1,542			(93	)		(218	)		32
Emission allowances		(31	)		(31	)		—			—
Nuclear decommissioning activities		(87	)		(87	)		—			—
Deferred debt refinancing costs		(65	)		—			(55	)		(10	)
Goodwill		4			—			—			—
Other, net		453			215			43			122

Deferred income tax liabilities (net)	$	(4,780	)	$	(2,034	)	$	(2,302	)	$	(2,362	)
Unamortized investment tax credits		(236	)		(190	)		(35	)		(11	)

Total deferred income tax liabilities (net) and unamortized investment tax credits	$	(5,016	)	$	(2,224	)	$	(2,337	)	$	(2,373	)

(a)

As of December 31, 2008, prior to the dissolution of AmerGen on January 8, 2009, the tax effects of temporary differences related to the partnership investment of the former AmerGen nuclear generating units were classified as an investment in AmerGen, and presented in Other, net. Subsequent to the dissolution of AmerGen in 2009, the tax effects of those temporary differences were allocated to the underlying deferred tax assets and liabilities making up the temporary differences, resulting in a reclassification from Other, net to Nuclear decommissioning activities and Deferred pension and post-retirement obligation.

The following table provides the Registrants’ carryforwards and any corresponding valuation allowances as of December 31, 2009. ComEd does not have any carryforwards as of December 31, 2009:


As of December 31, 2009	Exelon			Generation			PECO
State net operating loss carryforward	$	735	(a)	$	145		$	—
Deferred taxes		34			9			—
Valuation allowance		16			—			—
State capital loss carryforward		455			435	(b)		20
Deferred taxes		20			18			1
Valuation allowance		19			18			1

(a)	Exelon’s state net operating loss carryforwards will expire beginning in 2019

(b)	Generation’s state capital loss carryforwards for income tax purposes will expire in 2010

Tabular reconciliation of unrecognized tax benefits

The following table provides a reconciliation of the Registrants’ unrecognized tax benefits as of December 31, 2009:


	Exelon			Generation			ComEd			PECO
Unrecognized tax benefits at January 1, 2009	$	1,495		$	468		$	635		$	365
Decreases based on tax positions related to 2009		(2	)		(2	)		—			—
Change to positions that only affect timing		19			172			(154	)		7
Increases based on tax positions prior to 2009		4			3			—			—
Decreases related to settlements with taxing authorities		(18	)		(8	)		(10	)		—

Unrecognized tax benefits at December 31, 2009	$	1,498		$	633		$	471		$	372

The following table provides a reconciliation of the Registrants’ unrecognized tax benefits as of December 31, 2008:


	Exelon			Generation			ComEd			PECO
Unrecognized tax benefits at January 1, 2008	$	1,582		$	431		$	688		$	424
Increases based on tax positions prior to 2008		18			5			12			—
Change to positions that only affect timing		(74	)		32			(65	)		(59	)
Increases based on tax positions related to 2008		3			3			—			—
Decreases related to settlements with taxing authorities		(25	)		(3	)		—			—
Decrease from expiration of statute of limitations		(9	)		—			—			—

Unrecognized tax benefits at December 31, 2008	$	1,495		$	468		$	635		$	365

Included in Exelon’s unrecognized tax benefits balance at December 31, 2009 and December 31, 2008 is approximately $1.4 billion of tax positions for which the ultimate tax benefit is highly certain, but for which there is uncertainty about the timing of such benefits. The disallowance of such positions would not materially affect the annual effective tax rate but would accelerate the payment of cash to or defer the receipt of the cash tax benefit from the taxing authority to an earlier or later period respectively.

Unrecognized tax benefits that if recognized would affect the effective tax rate

Exelon, Generation and ComEd have $95 million, $33 million and $62 million, respectively, of unrecognized tax benefits at December 31, 2009 that, if recognized, would decrease the effective tax rate. Exelon, Generation and ComEd had $93 million, $28 million and $65 million, respectively, of unrecognized tax benefits at December 31, 2008 that, if recognized, would decrease the effective tax rate.

Total amounts of interest and penalties recognized

Exelon, Generation, ComEd and PECO have reflected in their Consolidated Balance Sheets as of December 31, 2009 a net interest receivable (payable) of $28 million, $(17) million, $(28) million and $54 million, respectively, related to their uncertain tax positions. Exelon, Generation, ComEd and PECO reflected in their Consolidated Balance Sheets as of December 31, 2008 a net interest receivable (payable) of $(16) million, $(10) million, $(90) million and $48 million, respectively, related to their uncertain tax positions. The Registrants recognize accrued interest related to uncertain tax positions in interest expense (income) in other income and deductions on their Consolidated Statements of Operations. Exelon, Generation, ComEd and PECO have reflected in their Consolidated Statements of Operations net interest expense (income) of $(42) million, $9 million, $(62) million and $(5) million, respectively, related to their uncertain tax positions for the twelve months ended December 31, 2009. For the twelve months ended December 31, 2008, Exelon, Generation, ComEd and PECO reflected in their Consolidated Statements of Operations net interest expense (income) of $(31) million, $(11) million, $(2) million and $(12) million, respectively, related to their uncertain tax positions. For the twelve months ended December 31, 2007, Exelon, Generation, ComEd and PECO reflected in their Consolidated Statements of Operations net interest expense (income) of $(49) million, $24 million, $(41) million and $(20) million, respectively, related to their uncertain tax positions. The Registrants have not accrued any penalties with respect to uncertain tax positions.

Reasonably possible that total amount of unrecognized tax benefits could significantly increase or decrease within 12 months after the reporting date

Nuclear Decommissioning Liabilities (Exelon and Generation)

AmerGen filed income tax refund claims taking the position that nuclear decommissioning liabilities assumed as part of its acquisition of nuclear power plants are taken into account in determining the tax basis in the assets it acquired. The additional basis results primarily in reduced capital gains or increased capital losses on the sale of assets in nonqualified decommissioning funds and increased tax depreciation and amortization deductions. The IRS disagrees with this position and has disallowed the claims. In November of 2008, Generation received a final determination from the Appeals division of the IRS (IRS Appeals) disallowing AmerGen’s refund claims. On February 20, 2009, Generation filed a complaint in the United States Court of Federal Claims to contest this determination. In August 2009, the DOJ filed its answer denying the allegations made by Generation in its complaint.

The trial judge assigned to the case has noted the availability of the court’s Alternative Dispute Resolution (ADR) program as an alternative to a trial, but the parties have not yet met with the ADR judge. The ADR program is a non-binding process that utilizes a variety of techniques such as mediation, neutral evaluation, and non-binding arbitration that allow the parties to better understand their differences and their prospects for settlement. While it is unclear when the parties might meet with the ADR judge, the process could result in an expedited conclusion of the matter. As a result, Generation believes that it is reasonably possible that the total amount of unrecognized tax benefits may significantly decrease in the next twelve months.

Tax Method of Accounting for Repairs

In 2009, Exelon received approval from the IRS to change its method of accounting for repair costs associated with Generation’s power plants. The new tax method of accounting resulted in net positive cash flow for 2009 of approximately $420 million. Although the IRS granted Exelon approval to change its method of accounting, the approval did not affirm the methodology used to calculate the deduction. Exelon has requested the IRS to review its methodology through its Pre-Filing Agreement program. If that request is granted it is reasonably possible that the total amount of unrecognized tax benefits could increase or decrease within the next 12 months.

See 1999 Sale of Fossil Generating Assets in Other Tax Matters section below for information regarding the amount of unrecognized tax benefits associated with this matter that could change significantly within the next 12 months.

See Competitive Transition Charges in Other Tax Matters section below for information regarding the amount of unrecognized tax benefits associated with this matter that could change significantly within the next 12 months.

Description of tax years that remain subject to examination by major jurisdiction


Taxpayer		Open Years
Exelon (and predecessors) and subsidiaries consolidated Federal income tax returns		1989-2008
Exelon (and predecessors) and subsidiaries Illinois unitary income tax returns		2004-2008
Exelon Ventures Company, LLC Pennsylvania corporate net income tax returns		2004-2008
PECO Pennsylvania corporate net income tax returns		2003-2008

Exelon expects the IRS to complete the audit of its 2002 through 2006 taxable years in the first quarter of 2010. Exelon does not expect there to be any material unresolved issues from that audit except for the carryover effects from ComEd’s deferral of gain positions taken on the sale of its fossil generating assets (discussed below).

Other Tax Matters

1999 Sale of Fossil Generating Assets (Exelon and ComEd)

Exelon, through its ComEd subsidiary, took two positions on its 1999 income tax return to defer approximately $2.8 billion of tax gain on the 1999 sale of ComEd’s fossil generating assets. Exelon deferred approximately $1.6 billion of the gain under the involuntary conversion provisions of the IRC. Exelon believes that it was economically compelled to dispose of ComEd’s fossil generating plants as a result of the Illinois Act. The proceeds from the sale of the fossil plants were properly reinvested in qualifying replacement property such that the gain was deferred over the lives of the replacement property under the involuntary conversion provisions. Approximately $1.2 billion of the gain was deferred by reinvesting the proceeds from the sale in qualifying replacement property under the like-kind exchange provisions of the IRC. The like-kind exchange replacement property purchased by Exelon included interests in three municipal-owned electric generation facilities which were properly leased back to the municipalities.

Exelon received the IRS audit report for 1999 through 2001, which reflected the full disallowance of the deferral of gain associated with both the involuntary conversion position and the like-kind exchange transaction. Specifically, the IRS has asserted that ComEd was not forced to sell the fossil generating plants and the sales proceeds were therefore not received in connection with an involuntary conversion of certain ComEd property rights. Accordingly, the IRS has asserted that the gain on the sale of the assets was fully subject to tax. The IRS also asserted that the Exelon purchase and leaseback transaction is substantially similar to a leasing transaction, known as a SILO, which the IRS does not respect as the acquisition of an ownership interest in property. A SILO is a “listed transaction” that the IRS has identified as a potentially abusive tax shelter under guidance issued in 2005. Accordingly, the IRS has asserted that the sale of the fossil plants followed by the purchase and leaseback of the municipal owned generation facilities does not qualify as a like-kind exchange and the gain on the sale is fully subject to tax.

In addition to attempting to impose tax on the transactions, the IRS has asserted penalties of approximately $196 million for a substantial understatement of tax. Because Exelon believes it is unlikely that the penalty assertion will ultimately be sustained, Exelon and ComEd have not recorded a liability for penalties. However, should the IRS prevail in asserting the penalty it would result in an after-tax charge of $196 million to Exelon’s and ComEd’s results of operations.

Exelon disagrees with the IRS disallowance of the deferral of gain and specifically with the characterization of its purchase and leaseback as a SILO. Exelon has been in discussions with IRS Appeals for several months in an attempt to reach a settlement on both the involuntary conversion and like-kind exchange, in a manner commensurate with Exelon’s and the IRS’ respective hazards of litigation with respect to each issue. During the second quarter of 2009, Exelon determined that a settlement with IRS Appeals was unlikely and that Exelon would be required to initiate litigation in order to resolve the issues.

Accordingly, Exelon concluded that it had sufficient new information that a change in measurement was required during the second quarter of 2009. As a result of the required remeasurement of these two positions in the second quarter, Exelon recorded a $31 million (after-tax) interest benefit of which $40 million (after-tax) was recorded at ComEd. The difference in amounts recorded at Exelon and ComEd is due to the method of allocating interest to the Registrants.

Due to the fact that tax litigation often results in a negotiated settlement, Exelon believes that an eventual settlement on the involuntary conversion position remains a likely outcome. Exelon and ComEd have established a liability for an unrecognized tax benefit consistent with their view as to a likely settlement. Management has considered the progress of the ongoing discussions with the IRS Appeals and determined that there were no new developments during the fourth quarter of 2009 that require a remeasurement of the amounts recorded. Based on management’s expectations as to the ongoing potential of a settlement, it is reasonably possible that the unrecognized tax benefits related to this issue may significantly increase or decrease within the next 12 months. It is not possible at this time to predict the amount, if any, of such a change.

With regard to the like-kind exchange transaction, Exelon does not currently believe it is possible to reach a negotiated settlement with either IRS Appeals or the Government’s lawyers prior to a trial. While Exelon has been and remains willing to settle the issue in a manner generally commensurate with its hazards of litigation, the IRS has indicated that it will only settle the issue in a manner consistent with published settlement guidelines for SILO transactions. Those guidelines require a nearly complete concession of the issue by Exelon. Exelon does not believe that its transaction is the same as or substantially similar to a SILO and does not believe that the concession demanded by the IRS reflects the strength of Exelon’s position. Accordingly, Exelon currently believes it is likely that the issue will be fully litigated. Given that Exelon has determined settlement is no longer a realistic outcome, it has assessed in accordance with accounting standards whether it will prevail in litigation. While Exelon recognizes the complexity and hazards of this litigation, it believes that it is more likely than not that it will prevail in such litigation and has therefore eliminated any liability for unrecognized tax benefits.

A fully successful IRS challenge to Exelon’s and ComEd’s involuntary conversion position and like-kind exchange transaction would accelerate income tax payments and increase interest expense related to the deferred tax gain that becomes currently payable. As of December 31, 2009, Exelon’s and ComEd’s potential tax and interest that could become currently payable in the event of a successful IRS challenge could be as much as $1.1 billion. Any payments ultimately determined to be due to the IRS related to the involuntary conversion position and the like-kind exchange transaction would be partially offset by the approximately $300 million refund due from the settlement of the 2001 tax method of accounting change for certain overhead costs under the SSCM. A favorable settlement of the tax position related to the CTCs (discussed below) for the 1999-2001 years could also offset a portion of any tax liability due with respect to the final outcome on these positions. If the IRS were to prevail in litigation on both tax positions, Exelon’s and ComEd’s results of operations could be negatively affected by as much as $300 million (after-tax) related to interest expense.

Competitive Transition Charges (Exelon, ComEd and PECO)

Exelon contends that the Illinois Act and the Competition Act resulted in the taking of certain of ComEd’s and PECO’s assets used in their respective businesses of providing electricity services in their defined service areas. Exelon has filed refund claims with the IRS taking the position that CTCs collected during ComEd’s and PECO’s transition periods represent compensation for that taking and, accordingly, are excludible from taxable income as proceeds from an involuntary conversion. If Exelon is successful in its claims, it will be required to reduce the tax basis of property acquired with the funds provided by the CTCs such that the benefits of the position are temporary in nature. The IRS has disallowed the refund claims for the 1999-2001 tax years. Exelon has protested the disallowance and is currently discussing the refund claims with IRS Appeals. The years 2002-2006 are currently under IRS audit and Exelon expects the claims for those years to be disallowed.

Under the Illinois Act, ComEd was required to allow competitors the use of its distribution system resulting in the taking of ComEd’s assets and lost asset value (stranded costs). As compensation for the taking, ComEd was permitted to collect a portion of the stranded costs through the collection of CTCs from those customers electing to purchase electricity from providers other than ComEd. ComEd collected approximately $1.2 billion in CTCs for the years 1999-2006.

Similarly, under the Competition Act, PECO was required to allow others the use of its distribution system resulting in the taking of PECO’s assets and the stranded costs. Pennsylvania permitted PECO to collect CTCs as compensation for its stranded costs. The PAPUC determined the total amount of stranded costs that PECO was permitted to collect through the CTCs to be $5.3 billion. PECO has collected approximately $4.4 billion in CTCs for the period 2000 through December 31, 2009. PECO will continue billing CTCs through 2010.

ComEd and PECO have recognized tax benefits associated with the CTC refund claims and have accrued interest on this tax position. Exelon’s, ComEd’s and PECO’s management believe that the issue has been appropriately recognized; however, the ultimate outcome of this matter could result in unfavorable or favorable impacts to the results of operations and financial positions as well as potential favorable impacts to cash flows, and such impacts could be material. Management has considered the progress of this matter before IRS Appeals and determined that there are no new developments that lead to a remeasurement of the amounts recorded. Based on management’s expectations as to the length of the appeal, it is reasonably possible that the unrecognized tax benefits related to this issue may significantly increase or decrease within the next 12 months. It is not possible at this time to predict the amount, if any, of such a change.

Indirect Cost Capitalization (Exelon, Generation, ComEd and PECO)

In 2001, Exelon filed a request with the IRS to change its tax method of accounting for certain overhead costs under the SSCM effective for years 2001-2004. The tax method change resulted in the deduction of certain overhead costs previously capitalized. In the fourth quarter of 2007, Exelon and the IRS agreed to apply industry-wide guidelines for settling the amount of indirect overhead costs previously capitalized. Based on acceptance of the settlement guidelines, Exelon recorded, in the fourth quarter of 2007, an estimated interest benefit of approximately $40 million (after tax) net of a contingent tax consulting fee of $6 million (after tax). ComEd and PECO recorded an estimated interest benefit (after tax and net of fee) of approximately $26 million and $8 million, respectively. ComEd and PECO recorded a current tax benefit of $13 million and $26 million, respectively, offset with a deferred tax expense recorded at Generation of $38 million. In the second quarter of 2008, Exelon reached final settlement with the IRS as to the amounts of the benefit determined through the application of the IRS settlement guidelines. As a result, Exelon recognized an additional interest benefit of $10 million (after tax) of which $7 million and $2 million of the interest benefit was attributable to ComEd and PECO, respectively. ComEd and PECO recorded a current tax benefit of $4 million and $2 million, respectively, offset with a deferred tax expense recorded at Generation of $6 million.

For years beginning after 2004, Exelon, ComEd and PECO were required to discontinue use of the SSCM and adopt a new method of capitalizing indirect costs. In the third quarter of 2007, ComEd and PECO developed a new indirect cost capitalization method. As a result, Exelon recorded an estimated interest benefit of $5 million (after tax). ComEd and PECO recorded an estimated interest benefit (after tax) of $2 million and $3 million, respectively. During the fourth quarter of 2008, the IRS indicated its agreement with this new method of capitalizing indirect overhead costs. Therefore, Exelon recorded an additional interest benefit (after tax) of $12 million of which $15 million and $2 million was attributable to ComEd and PECO, respectively. In 2009, the IRS industry director issued a new directive for determining the amount of indirect costs capitalized to inventory and self-constructed property, which was consistent with Exelon’s methodology.

Illinois Replacement Investment Tax Credits (Exelon, Generation and ComEd)

On February 20, 2009, the Illinois Supreme Court ruled in Exelon’s favor in a case involving refund claims for Illinois investment tax credits. Consequently, Exelon recorded approximately $42 million (after tax) of income in results of operations in the first quarter of 2009 to reflect the refund claims for investment tax credits and associated interest for the years 1995 – 2008; $35 million and $8 million were recorded at ComEd and Generation, respectively.

Responding to the Illinois Attorney General’s petition for rehearing, on July 15, 2009, the Illinois Supreme Court modified its opinion to indicate that it was to be applied only prospectively, beginning in 2009. Exelon filed a Petition for Rehearing with the Illinois Supreme Court on August 4, 2009. The Petition for Rehearing was denied by the Illinois Supreme Court on September 28, 2009. As a result, Exelon, Generation and ComEd recorded a charge to third quarter 2009 results of operations to reverse the income previously recognized.

On December 22, 2009, Exelon filed a Petition of Writ for Certiorari with the United States Supreme Court appealing the Illinois Supreme Court’s July 15, 2009 modified opinion. In the third quarter of 2009 Exelon, Generation and ComEd decreased their unrecognized tax benefits related to this position. However, as a result of the filing of the United States Supreme Court petition the unrecognized tax benefits continue to be reported.

Research and Development Settlement (Exelon, Generation and ComEd)

In 2007, ComEd and the IRS reached an agreement to settle a research and development claim for tax years 1989 -1998. The incremental impact recorded by ComEd in the fourth quarter of 2007, above the amount recorded with the adoption of the authoritative guidance for accounting for uncertain income tax positions, resulted in a reduction to goodwill of $35 million, interest income of $15 million (after tax) and a contingent tax consulting fee of $8 million (after tax). Generation recorded a deferred tax liability and tax expense of $27 million related to the reduction of future depreciation due to the basis reduction of the related assets transferred from ComEd. The contingent fee was accounted for in accordance with the authoritative guidance for accounting for contingent liabilities and recognized in the fourth quarter of 2007.

Long-Term State Tax Apportionment (Exelon and Generation)

Exelon and Generation periodically review events that may significantly impact how income is apportioned among the states and, therefore, the calculation of Exelon’s and Generation’s deferred state income taxes. On April 16, 2009, the PAPUC approved PECO’s electricity procurement proposal that will have an impact on Exelon’s and Generation’s apportionment of income among the states. Accordingly, Exelon and Generation reevaluated the impacts to deferred state taxes in the second quarter of 2009. The effect of such evaluations resulted in the recording of a non-cash deferred state tax benefit in the amount of $34.7 million, net of taxes. Exelon and Generation have treated electricity as tangible personal property for this purpose which is consistent with the February and July 2009 Illinois Supreme Court decisions.

Tax Restructuring (Exelon)

In the fourth quarter of 2007, Exelon completed a tax restructuring to allow the utilization of separate company losses for state income tax purposes. As a result of the restructuring, Exelon recorded a deferred tax benefit of approximately $63 million related primarily to temporary differences originating through OCI. The effect of the tax restructuring in the fourth quarter of 2007 and its impact on the deferred tax assets at Exelon were recorded in net income.

Investments in Synthetic Fuel-Producing Facilities (Exelon)

Exelon, through three separate wholly owned subsidiaries, owned interests in two limited liability companies and one limited partnership (collectively, the sellers) that own synthetic fuel-producing facilities. Prior to December 31, 2007, Section 45K (formerly Section 29) of the IRC provided tax credits for the sale of synthetic fuel produced from coal. The ability to earn these synthetic fuel tax credits expired on December 31, 2007 and, as such, the synthetic fuel-producing facilities that Exelon had interests in ceased operations on or before December 31, 2007. The agreements with the Sellers terminated in 2008.

Interests in synthetic fuel-producing facilities did not have any net impact on Exelon’s net income for the years ended December 31, 2009 and December 31, 2008 and increased Exelon’s net income by $87 million during the year ended December 31, 2007. Net income from interests in synthetic fuel-producing facilities is reflected in the Consolidated Statements of Operations in income taxes, operating and maintenance expense, depreciation and amortization expense, interest expense, equity in losses of unconsolidated affiliates and other, net.

Tax Sharing Agreement (Exelon, Generation, ComEd and PECO)

Generation, ComEd and PECO are all party to an agreement with Exelon and other subsidiaries of Exelon that provides for the allocation of consolidated tax liabilities and benefits (Tax Sharing Agreement). The Tax Sharing Agreement provides that each party is allocated an amount of tax similar to that which would be owed had the party been separately subject to tax. In addition, any net benefit attributable to Exelon is reallocated to the other Registrants. That allocation is treated as a contribution to the capital of the party receiving the benefit. During 2009, Generation, ComEd and PECO recorded an allocation of Federal tax benefits from Exelon under the Tax Sharing Agreement of $57 million, $8 million and $27 million, respectively.

Asset Retirement Obligations (Exelon, Generation, ComEd and PECO)

12 Months Ended

Dec. 31, 2009

Statement [Line Items]

Asset Retirement Obligations (Exelon, Generation, ComEd and PECO)

11. Asset Retirement Obligations (Exelon, Generation, ComEd and PECO)

Nuclear Decommissioning Asset Retirement Obligations

Generation has a legal obligation to decommission its nuclear power plants following the expiration of their operating licenses. Generation will pay for its respective obligations using trust funds that have been established for this purpose. The following table provides a rollforward of the nuclear decommissioning ARO reflected on Exelon’s and Generation’s Consolidated Balance Sheets, from January 1, 2008 to December 31, 2009:


	Exelon and Generation
Nuclear decommissioning ARO at January 1, 2008	$	3,578
Net decrease resulting from updates to estimated future cash flows		(300	)
Accretion expense		221
Payments to decommission retired plants		(14	)

Nuclear decommissioning ARO at December 31, 2008 ^(a)		3,485
Net decrease resulting from updates to estimated future cash flows		(409	)
Accretion expense		203
Payments to decommission retired plants		(19	)

Nuclear decommissioning ARO at December 31, 2009 ^(a)	$	3,260

(a)	Includes $17 million and $13 million as the current portion of the ARO at December 31, 2009 and 2008, respectively, which is included in other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets.

During 2009, Generation recorded a net decrease in the ARO of $409 million, primarily due to an update in the third quarter of 2009, which reflected updated decommissioning cost studies received for six nuclear units and a decline from the previous year in the cost escalation factor assumptions used to estimate future undiscounted decommissioning costs. This decrease in the ARO resulted in the recognition of $47 million of income (pre-tax), which is included in operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations, representing the reduction in the ARO in excess of the existing ARC balances for the Non-Regulatory Agreement Units.

During 2008, Generation recorded a net decrease in the ARO of $300 million, primarily due to an update in the third quarter of 2008, which reflected updated decommissioning cost studies received for seven nuclear units, a decline from the previous year in the cost escalation factor assumptions used to estimate future undiscounted decommissioning costs and a change in management’s expectation of the year in which the DOE will begin accepting SNF (from the previous estimate of 2018 to 2020), partially offset by a change in the probabilities assigned to decommissioning alternatives for Zion Station to reflect a revised probability for accelerated decommissioning. The decrease in the ARO resulted in the recognition of $19 million of income (pre-tax), which is included in operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations, representing the reduction in the ARO in excess of the existing ARC balances for the Non-Regulatory Agreement Units.

Overview of Trust Funds. Trust funds have been established for each generating station unit to satisfy Generation’s nuclear decommissioning obligations. Trust funds established for a particular unit may not be used to fund the decommissioning obligations of any other unit.

The trusts funds associated with the former ComEd, former PECO and former AmerGen units have been funded with amounts collected from ComEd customers, PECO customers and the previous owners of the former AmerGen plants, respectively. Based on an ICC order, ComEd ceased collecting amounts from its customers to pay for decommissioning costs. PECO currently collects funds, in revenues, for decommissioning the former PECO nuclear plants through regulated rates, and these collections are expected to continue through the operating lives of the plants. The amounts collected from PECO customers are remitted to Generation and deposited into the trust funds. Every five years, the PAPUC reviews the adequacy of the annual amount that PECO is allowed to collect from its customers. Based on this review, the PAPUC may adjust PECO’s collections upward or downward. Based on the most recent PAPUC review, effective January 1, 2008, the annual collection amount was set at $29 million. The next five-year adjustment is expected to be reflected in rates charged to PECO customers effective January 1, 2013. With respect to the former AmerGen units, Generation does not collect any amounts, nor is there any mechanism by which Generation can seek to collect additional amounts, from customers. Apart from the contributions made to the trust funds from amounts collected from ComEd and PECO customers, Generation has not made contributions to the trust funds.

Any shortfall of funds necessary for decommissioning, determined for each generating station unit, is ultimately required to be funded by Generation. Generation has recourse to collect additional amounts from PECO customers related to a shortfall of trust funds for the former PECO units, subject to certain limitations and thresholds, as prescribed by an order from the PAPUC. Generally, PECO will not be allowed to collect amounts associated with the first $50 million of any shortfall of trust funds, on an aggregate basis for all former PECO units, compared to decommissioning obligations, as well as 5% of any additional shortfalls. This initial $50 million and up to 5% of any additional shortfalls would be borne by Generation. No recourse exists to collect additional amounts from ComEd customers for the former ComEd units or from the previous owners of the former AmerGen units. With respect to the former ComEd and PECO units, any funds remaining in the trusts after decommissioning has been completed are required to be refunded to ComEd’s or PECO’s customers, subject to certain limitations that allow sharing of excess funds with Generation related to the former PECO units. With respect to the former AmerGen units, Generation retains any funds remaining in the trusts after decommissioning.

Accounting Implications of the Regulatory Agreements with ComEd and PECO. Based on the regulatory agreement with the ICC that dictates Generation’s obligations related to the shortfall or excess of trust funds necessary for decommissioning the former ComEd units on a unit-by-unit basis, as long as funds held in the NDT funds exceed the total estimated decommissioning obligation, decommissioning-related activities, including realized and unrealized income and losses on the trust funds and accretion of the decommissioning obligation, are generally offset within Exelon’s and Generation’s Consolidated Statements of Operations. The offset of decommissioning-related activities within the Consolidated Statement of Operations results in an equal adjustment to the noncurrent payables to affiliates at Generation and an adjustment to the regulatory liabilities at Exelon. Likewise, ComEd has recorded an equal noncurrent affiliate receivable from Generation and corresponding regulatory liability. Should the value of the trust fund for any former ComEd unit fall below the amount of the estimated decommissioning obligation for that unit, the accounting to offset decommissioning-related activities in the Consolidated Statement of Operations for that unit would be discontinued, the decommissioning-related activities would be recognized in the Consolidated Statements of Operations and the adverse impact to Exelon’s and Generation’s results of operations and financial position could be material. At December 31, 2009, the trust funds of each of the former ComEd units exceeded the related decommissioning obligation for each of the units. For the purposes of making this determination, the decommissioning obligation referred to is the ARO reflected on Generation’s Consolidated Balance Sheet at December 31, 2009 and is different from the calculation used in the NRC minimum funding obligation filings based on NRC guidelines.

Based on the regulatory agreement supported by the PAPUC that dictates Generation’s rights and obligations related to the shortfall or excess of trust funds necessary for decommissioning the seven former PECO nuclear units, regardless of whether the funds held in the NDT funds exceed or fall short of the total estimated decommissioning obligation, decommissioning-related activities are generally offset within Exelon’s and Generation’s Consolidated Statements of Operations. The offset of decommissioning-related activities within the Consolidated Statement of Operations results in an equal adjustment to the noncurrent payables to affiliates at Generation and an adjustment to the regulatory liabilities at Exelon. Likewise, PECO has recorded an equal noncurrent affiliate receivable from Generation and a corresponding regulatory liability. Any changes to the PECO regulatory agreements could impact Exelon’s and Generation’s ability to offset decommissioning-related activities within the Consolidated Statement of Operations, and the impact to Exelon’s and Generation’s results of operations and financial position could be material. See Note 2—Regulatory Issues for information regarding a PAPUC investigation to determine if PECO’s decommissioning cost collections from customers should continue after December 31, 2010.

The decommissioning-related activities related to the Clinton, Oyster Creek and Three Mile Island nuclear plants (the former AmerGen units) and the portions of the Peach Bottom nuclear plants that are not subject to regulatory agreements with respect to the NDT funds are reflected in Exelon’s and Generation’s Consolidated Statements of Operations, as there are no regulatory agreements associated with these units. Refer to Note 19—Supplemental Financial Information and Note 21—Related Party Transactions for information regarding regulatory liabilities at ComEd and PECO and intercompany balances between Generation, ComEd and PECO reflecting the obligation to refund the customers any decommissioning-related assets in excess of the related decommissioning obligations.

NRC Minimum Funding Requirements. NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in specified minimum amounts at the end of the life of the facility to decommission the facility. During 2008, the value of the trust funds declined significantly due to unrealized losses as a result of adverse financial market conditions. Despite this decline in value, Generation believes that the decommissioning trust funds for the nuclear generating stations formerly owned by ComEd, PECO and AmerGen, the expected earnings thereon and, in the case of the former PECO stations, the remaining amounts to be collected from PECO’s customers will ultimately be sufficient to fully fund Generation’s decommissioning obligations for its nuclear generating stations in accordance with NRC regulations.

Generation is required to provide to the NRC a biennial report by unit (annually for units that have been retired or are within five years of the current approved license life), based on values as of December 31, addressing Generation’s ability to meet the NRC minimum funding levels. Depending on the value of the trust funds, Generation may be required to take steps, such as providing financial guarantees through letters of credit or parent company guarantees or make additional contributions to the trusts, which could be significant, to ensure that the trusts are adequately funded and that NRC minimum funding requirements are met. As a result, Exelon’s and Generation’s cash flows and financial position may be significantly adversely affected.

Generation’s most recent report was filed with the NRC on March 31, 2009, based on trust fund values and estimated decommissioning obligations as of December 31, 2008. The estimated decommissioning obligations for the NRC report were calculated in accordance with NRC regulations, and differ from the ARO recorded on Generation’s and Exelon’s Consolidated Balance Sheets at December 31, 2008, primarily due to differences in assumptions regarding the decommissioning alternatives to be used and potential license renewals.

On July 13, 2009, the NRC published a summary of decommissioning trust fund shortfalls at industry nuclear units, which for Generation’s nuclear generating stations set forth an aggregate underfunded position of approximately $1.0 billion. The NRC calculation assumes one scenario where decommissioning activities are completed within seven years after the cessation of plant operations. Under NRC regulations, nuclear unit owners have up to 60 years to complete decommissioning after the cessation of operations, during which time decommissioning funds would continue to be invested. The NRC did not publish any calculations for alternative scenarios where decommissioning activities are completed at a later time during the 60-year window. Generation, consistent with NRC regulations, makes its calculations based upon the 60-year decommissioning scenario. Consistent with studies approved by the NRC and assuming that decommissioning activities are completed within the permissible 60-year regulatory time period, Generation believes that six units at three nuclear generating stations were in an underfunded position by approximately $185 million in total relative to the NRC minimum funding requirement as of December 31, 2008. Over 90% of this total is attributable to Generation’s four units at Braidwood and Byron, where Generation has not yet filed for license extensions. Although the NRC does not allow for potential license extensions to be credited in calculating NRC minimum funding requirements, to the extent that license extensions are granted for these units, decommissioning funds will continue to be invested for an additional 20-year period. Generation presently anticipates that it will file for license extensions for these units consistent with its ongoing business plan.

Generation and other industry members are engaged in ongoing discussions with the NRC regarding the NRC’s calculations. On July 31, 2009, Generation submitted its plan to the NRC to remediate the remaining underfunded position. The multi-step plan is expected to fully remediate any underfunded positions calculated as of December 31, 2009 by April 1, 2010. Additionally, the plan provides for an annual assessment of Generation’s remediation of any underfunded position. Based on the latest calculations and trust fund values, Generation believes that the underfunded position is $45 million as of December 31, 2009. Generation does not expect that any cash contributions to the funds will be required; instead, Generation anticipates that any underfunded position will be addressed through other financial guarantee methods as allowed by NRC regulations and laid out in the plan submitted to the NRC by Generation.

As the future values of trust funds change due to market conditions, the NRC minimum funding status of Generation’s units will change. In addition, if changes occur to the regulatory agreement with the PAPUC that currently allows amounts to be collected from PECO customers for decommissioning the former PECO nuclear plants, the NRC minimum funding status of those plants could change at subsequent NRC filing dates. At present, Generation anticipates that it will remedy any underfunded position remaining after full implementation of its funding assurance plan as submitted to the NRC through the issuance of a limited guarantee from Exelon in the amount of up to $45 million, rather than through cash contributions to the decommissioning trust funds.

Nuclear Decommissioning Trust Fund Investments

At December 31, 2009 and December 31, 2008, Exelon and Generation had NDT fund investments totaling $6,669 million and $5,500 million, respectively.

In the first quarter of 2009, Generation performed a rebalancing of its NDT fund investments in order to bring the mix of equity and fixed income investments into alignment with targeted ratios. At December 31, 2009, approximately 53% of the funds were invested in equity and 47% were invested in fixed income securities. At December 31, 2008, approximately 39% of the funds were invested in equity and 61% were invested in fixed income securities.

Generation’s NDT funds participate in a securities lending program with the trustees of the funds. The program authorizes the trustees to loan securities that are assets of the trust funds to approved borrowers. The trustees require borrowers, pursuant to a security lending agreement, to deliver collateral to secure each loan. The securities are required to be collateralized by cash, U.S. Government securities or irrevocable bank letters of credit. Initial collateral levels are no less than 102% and 105% of the market value of the borrowed securities for collateral denominated in U.S. and foreign currency, respectively. Subsequent collateral levels, which are adjusted daily, must be maintained at a level no less than 100% of the market value of borrowed securities. Cash collateral received is primarily invested in a short-term collateral fund, but may also be invested in assets with maturities matching, or approximating, the duration of the loan of the related securities. Collateral may not be sold or re-pledged by the trustees; however, the borrowers may sell or re-pledge the securities loaned. Generation bears the risk of loss with respect to its invested cash collateral. Such losses may result from a decline in fair value of specific investments or liquidity impairments resulting from current market conditions. Generation, the trustees and the borrowers have the right to terminate the lending agreement at their discretion, upon which borrowers would return securities to Generation in exchange for their cash collateral. If the short-term collateral funds do not have adequate liquidity, Generation may incur losses upon the withdrawal of amounts from the funds to repay the borrowers’ collateral. Losses recognized by Generation, whether the result of declines in fair value or liquidity impairments, have not been significant to date. Management continues to monitor the performance of the invested collateral and to work closely with the trustees to limit any potential further losses.

In the fourth quarter of 2008, Generation decided to end its participation in the securities lending program and chose to initiate a gradual withdrawal of the trusts’ investments in order to minimize potential losses due to the lack of liquidity in the market. As part of its withdrawal plan and in order to minimize realized losses, Generation temporarily increased its securities on loan during 2009. This temporary increase does not change Generation’s intent to end its participation in the securities lending program. Currently, the weighted average maturity of the securities within the collateral pools is approximately 4 months. At December 31, 2008, Generation had $380 million of loaned securities outstanding and held $386 million of related collateral under its lending agreements. At December 31, 2009, Generation had $357 million of loaned securities outstanding and held $366 million of related collateral under its lending agreements, representing a decrease in loaned securities outstanding since December 31, 2008 of $23 million primarily due to the return of loaned securities.

A portion of the income generated through the investment of cash collateral is remitted to the borrowers, and the remainder is allocated between the trust funds and the trustees in their capacity as security agents. Securities lending income allocated to the NDT funds is included in NDT fund earnings and classified as Other, net in Exelon’s and Generation’s Consolidated Statements of Operations and was not significant during the years ended December 31, 2009 and 2008.

The following table provides unrealized gains (losses) on NDT funds and other-than-temporary impairment of NDT funds for the years ended 2009, 2008 and 2007:


	Exelon and Generation
	For the Years Ended December 31,
	2009			2008			2007
Net unrealized gains (losses) on decommissioning trust funds—Regulatory Agreement Units ^(a)	$	799		$	(1,023	)	$	43
Net unrealized gains (losses) on decommissioning trust funds—Non-Regulatory Agreement Units ^(b)		227	^(d)		(324	)^(d)		(14	)^(e)
Other-than-temporary impairment of decommissioning trust funds—Regulatory Agreement Units ^(c)		n/a			n/a			(84	)^(a)^(b)
Other-than-temporary impairment of decommissioning trust funds—Non-Regulatory Agreement Units ^(c)		n/a			n/a			(9	) ^(d)

(a)

Generation’s NDT funds associated with the former ComEd and former PECO nuclear generating units that are subject to regulatory agreements with respect to NDT funding are subject to contractual elimination pursuant to regulatory accounting and included in regulatory liabilities on Exelon’s Consolidated Balance Sheets and noncurrent payables to affiliates on Generation’s Consolidated Balance Sheets.

(b)	Generation’s NDT funds that are not subject to a regulatory agreement with respect to NDT funding are included within Other, net in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

(c)

As a result of certain NRC restrictions, Exelon and Generation were unable to demonstrate the ability and intent to hold the NDT fund investments through a recovery period and, in accordance with other-than-temporary impaired investment authoritative guidance, recognized any unrealized holding losses immediately.

(d)	Included in Other, net in Exelon’s and Generation’s Consolidated Statement of Operations.

(e)	Included in accumulated OCI on Exelon’s and Generation’s Consolidated Balance Sheet.

Interest and dividends on NDT fund investments are recognized when earned and are included in Other, net in Exelon’s and Generation’s Consolidated Statements of Operations. Interest and dividends earned on the NDT fund investments for the Regulatory Agreement Units, which are subject to regulatory accounting, are eliminated within Other, net in Exelon and Generation’s Consolidated Statement of Operations.

Non-Nuclear Asset Retirement Obligations (Exelon, Generation, ComEd, and PECO)

Generation has AROs for plant closure costs associated with its fossil and hydroelectric generating stations, including asbestos abatement, removal of certain storage tanks and other decommissioning-related activities. ComEd and PECO have AROs primarily associated with the abatement and disposal of equipment and buildings contaminated with asbestos and PCBs.

The following table presents the activity of the non-nuclear AROs reflected on the Registrants’ Consolidated Balance Sheets from January 1, 2008 to December 31, 2009:


	Exelon			Generation			ComEd			PECO
Non-nuclear AROs at January 1, 2008	$	250		$	64		$	163		$	22
Net increase resulting from updates to estimated future cash flows		8			5			2			1
Accretion ^(a)		14			4			10			1
Payments		(10	)		(9	)		(1	)		—

Non-nuclear AROs at December 31, 2008		262			64			174			24
Net increase (decrease) resulting from updates to estimated future cash flows		(81	)		5			(85	)		(1	)
Accretion ^(a)		12			4			8			1
Payments		(2	)		—			(2	)		—

Non-nuclear AROs at December 31, 2009	$	191		$	73		$	95		$	24

(a)	For ComEd and PECO, the majority of the accretion is recorded as an increase to a regulatory asset due to the associated regulations.

During 2009, ComEd recorded an $85 million reduction to its ARO liabilities and offsetting credits to the associated regulatory accounts based on management’s revised assumptions. This change in estimate did not have an impact on ComEd’s results of operations or cash flows.

Retirement Benefits (Exelon, Generation, ComEd and PECO)

12 Months Ended

Dec. 31, 2009

Statement [Line Items]

Retirement Benefits (Exelon, Generation, ComEd and PECO)

13. Retirement Benefits (Exelon, Generation, ComEd and PECO)

As of December 31, 2009, Exelon sponsored seven defined benefit pension plans and three postretirement benefit plans for essentially all Generation, ComEd, PECO and BSC employees.

Exelon’s traditional and cash balance pension plans are intended to be tax-qualified defined benefit plans. Substantially all non-union employees and electing union employees hired on or after January 1, 2001 participate in cash balance pension plans. Effective January 1, 2009, substantially all newly hired union-represented employees participate in cash balance pension plans. Exelon has elected that the trusts underlying the plans be treated under the IRC as qualified trusts. If certain conditions are met, Exelon can deduct payments made to the qualified trusts, subject to certain IRC limitations. Exelon also sponsors certain non-qualified pension plans.

Benefit Obligations and Plan Assets, and Funded Status

Exelon recognizes the overfunded or underfunded status of defined benefit pension and other postretirement plans as an asset or liability on its balance sheet, with offsetting entries to Accumulated Other Comprehensive Income (AOCI) and regulatory assets, in accordance with the applicable authoritative guidance. The impact of changes in assumptions used to measure pension and other postretirement benefit obligations is generally recognized over the expected average remaining service period of the plan participants, rather than immediately recognized. The measurement date for the plans is December 31. The obligations reflect the impact of Exelon’s 2009 restructuring activities and changes in certain plans related to some union participants. The following table provides a rollforward of the changes in the benefit obligations and plan assets for the most recent two years for all plans combined:


	Pension Benefits						Other Postretirement Benefits
	2009			2008			2009			2008
Change in benefit obligation:
Net benefit obligation at beginning of year	$	10,788		$	10,427		$	3,480		$	3,335
Service cost		178			163			113			108
Interest cost		651			635			205			208
Plan participants’ contributions		—			—			18			22
Actuarial loss (gain)		479			176			31			(14	)
Plan Amendments		2			16			—			—
Curtailments/settlements		2			1			—			—
Special termination benefits		—			—			4			—
Gross benefits paid		(618	)		(630	)		(203	)		(189	)
Federal subsidy on benefits paid		—			—			10			10

Net benefit obligation at end of year	$	11,482		$	10,788		$	3,658		$	3,480

Change in plan assets:
Fair value of net plan assets at beginning of year	$	6,664		$	9,634		$	1,224		$	1,616
Actual return on plan assets		1,352			(2,420	)		280			(388	)
Employer contributions		441			80			157			163
Plan participants’ contributions		—			—			18			22
Gross benefits paid		(618	)		(630	)		(203	)		(189	)

Fair value of net plan assets at end of year	$	7,839		$	6,664		$	1,476		$	1,224

Exelon presents its benefit obligations and plan assets net on its balance sheet within the following line items:


	Pension Benefits				Other Postretirement Benefits
	As of December 31,				As of December 31,
	2009		2008		2009		2008
Other current liabilities	$	18	$	13	$	2	$	1
Pension obligations		3,625		4,111		—		—
Non-pension postretirement benefit obligations		—		—		2,180		2,255

Unfunded status (net benefit obligation less net plan assets)	$	3,643	$	4,124	$	2,182	$	2,256

The funded status of the pension and other postretirement benefit obligations refers to the difference between plan assets and estimated obligations of the plan. During 2008, Exelon’s unfunded status increased significantly, primarily due to lower than expected 2008 asset returns. The unfunded balance of the plans decreased to $5.83 billion as of December 31, 2009 as compared to $6.38 billion at 2008. While a decrease in discount rates and other factors resulted in an increase in the pension and other postretirement obligation, it was more than offset by the significant increase in asset values during 2009. The funded status may change over time due to several factors, including contribution levels, assumed discount rates and actual returns on plan assets.

The following table provides the projected benefit obligations (PBO), accumulated benefit obligation (ABO) and fair value of plan assets for all pension plans with an ABO in excess of plan assets.


	December 31,
	2009		2008
Projected benefit obligation	$	11,482	$	10,788
Accumulated benefit obligation		10,695		10,017
Fair value of net plan assets		7,839		6,664

The following table provides the PBO, ABO and fair value of all pension plans with a PBO in excess of plan assets.


	December 31,
	2009		2008
Projected benefit obligation	$	11,482	$	10,788
Accumulated benefit obligation		10,695		10,017
Fair value of net plan assets		7,839		6,664

On an ABO basis, the plans were funded at 73% at December 31, 2009 compared to 67% at December 31, 2008. On a PBO basis, the plans were funded at 68% at December 31, 2009 compared to 62% at December 31, 2008. The ABO differs from the PBO in that it includes no assumption about future compensation levels.

Components of Net Periodic Benefit Costs

The following table provides the components of the net periodic benefit costs for the years ended December 31, 2009, 2008 and 2007 for all plans combined. The table reflects a reduction in 2009, 2008 and 2007 of net periodic postretirement benefit costs of approximately $38 million, $38 million and $44 million, respectively, related to a Federal subsidy provided under the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Prescription Drug Act), discussed further below.


	Pension Benefits									Other Postretirement Benefits
	2009			2008			2007			2009			2008			2007
Components of net periodic benefit cost:
Service cost	$	178		$	163		$	163		$	113		$	108		$	106
Interest cost		651			635			603			205			208			192
Expected return on assets		(778	)		(836	)		(816	)		(94	)		(121	)		(115	)
Amortization of:
Transition obligation		—			—			—			9			10			10
Prior service cost (credit)		14			15			16			(56	)		(57	)		(56	)
Actuarial loss		197			127			148			87			53			63
Curtailment/settlement charges		6			9			5			—			—			—
Special termination benefits		—			—			1			4			—			—

Net periodic benefit cost	$	268		$	113		$	120		$	268		$	201		$	200

Through Exelon’s postretirement benefit plans, the Registrants provide retirees with prescription drug coverage. The Prescription Drug Act, enacted on December 8, 2003, introduced a prescription drug benefit under Medicare as well as a Federal subsidy to sponsors of retiree healthcare benefit plans that provide a benefit that is at least actuarially equivalent to the Medicare prescription drug benefit. Management believes the prescription drug benefit provided under Exelon’s postretirement benefit plans meets the requirements for the subsidy.

The effect of the subsidy on the components of net periodic postretirement benefit cost for 2009, 2008 and 2007 included in the consolidated financial statements was as follows:


	2009		2008		2007
Amortization of the actuarial experience loss	$	11	$	11	$	16
Reduction in current period service cost		9		9		10
Reduction in interest cost on the APBO		18		18		18

Components of OCI and Regulatory Assets

Under the authoritative guidance for regulatory accounting, a portion of net periodic benefit costs is capitalized within Exelon’s Consolidated Balance Sheets to reflect the expected regulatory recovery of these amounts, which would otherwise be charged to OCI. The following tables provide the components of OCI and regulatory assets for the years ended December 31, 2009, 2008 and 2007 for all plans combined.


	Pension Benefits									Other Postretirement Benefits
	2009			2008			2007			2009			2008			2007
Changes in plan assets and benefit obligations recognized in OCI and regulatory assets:
Current year actuarial (gain) loss	$	(94	)	$	3,432		$	127		$	(154	)	$	495		$	(109	)
Amortization of actuarial gain (loss)		(197	)		(127	)		(148	)		(87	)		(53	)		(63	)
Current year prior service cost		2			16			—			—			—			—
Amortization of prior service cost (credit)		(14	)		(15	)		(16	)		56			57			56
Amortization of transition obligation		—			—			—			(9	)		(10	)		(10	)
Settlements		(6	)		(9	)		(5	)		—			—			—

Total recognized in OCI and regulatory assets	$	(309	)	$	3,297		$	(42	)	$	(194	)	$	489		$	(126	)

The following table provides the components of Exelon’s gross accumulated other comprehensive loss and regulatory assets that have not been recognized as components of periodic benefit cost as of December 31, 2009 and 2008, respectively, for all plans combined:


	Pension Benefits				Other Postretirement Benefits
	As of December 31,				As of December 31,
	2009		2008		2009			2008
Transition obligation	$	—	$	—	$	29		$	38
Prior service cost (credit)		118		130		(110	)		(166	)
Actuarial loss		5,838		6,135		1,029			1,270

Total ^(a)	$	5,956	$	6,265	$	948		$	1,142

(a)

Of the $5,956 million related to pension benefits, $3,819 million and $2,137 million are included in AOCI and regulatory assets, respectively, as of December 31, 2009. Of the $948 million related to other postretirement benefits, $470 million and $478 million are included in AOCI and regulatory assets, respectively, as of December 31, 2009. Of the $6,265 million related to pension benefits, $4,023 million and $2,242 million are included in AOCI and regulatory assets, respectively, as of December 31, 2008. Of the $1,142 million related to other postretirement benefits, $555 million and $587 million are included in AOCI and regulatory assets, respectively, as of December 31, 2008.

The following table provides the components of Exelon’s AOCI and regulatory assets as of December 31, 2009 (included in the table above) that are expected to be amortized as components of periodic benefit cost in 2010. These estimates are subject to the completion of a valuation report of Exelon’s pension and other postretirement benefit obligations. This valuation report will reflect actual census data as of January 1, 2010 and actual claims activity as of December 31, 2009 and is expected to be completed by the first quarter of 2010.


	Pension Benefits		Other Postretirement Benefits
Transition obligation	$	—	$	9
Prior service cost (credit)		14		(56	)
Actuarial loss		256		73

Total ^(a)	$	270	$	26

(a)

Of the $270 million related to pension benefits, $166 million and $104 million are included in AOCI and regulatory assets, respectively, as of December 31, 2009. Of the $26 million related to other postretirement benefits, $11 million and $15 million are expected to be included in AOCI and regulatory assets, respectively, as of December 31, 2009.

Assumptions

The measurement of the plan obligations and costs of providing benefits under Exelon’s defined benefit or other postretirement plans involves various factors, including the development of valuation assumptions and accounting elections. When determining the various assumptions that are required, Exelon considers historical information as well as future expectations. The measurement of benefit costs is affected by the actual rate of return on plan assets and assumptions including the long-term expected rate of return on plan assets, the discount rate applied to benefit obligations, Exelon’s expected level of contributions to the plans, the incidence of mortality, the expected remaining service period of plan participants, level of compensation and rate of compensation increases, employee age, length of service, the long-term expected investment rate credited to employees of certain plans, the anticipated rate of increase of healthcare costs and the level of benefits provided to employees and retirees, among other factors. The impact of changes in assumptions used to measure pension and other postretirement benefit obligations is generally recognized over the expected average remaining service period of the plan participants, rather than immediately recognized.

Expected Rate of Return. In selecting the expected rate of return on plan assets, Exelon considers historical returns for the types of investments that its plans hold in addition to expectations regarding future long-term asset returns, weighted by Exelon’s target asset class allocation. In general, equity securities, real estate and private equity investments are forecasted to have higher returns than fixed income securities. Historical returns and volatilities are modeled to determine asset allocations that best meet the objectives of the investment trusts that hold the plan assets. A change in asset allocations could significantly impact the expected rate of return on plan assets.

The following weighted average assumptions were used to determine the benefit obligations for all of the plans at December 31, 2009, 2008 and 2007:

Pension Benefits

Other Postretirement Benefits

2009 ^(a)

2008

2007

2009 ^(a)

2008

2007

Discount rate

5.83%

6.09%

6.20%

5.83%

6.09%

6.20%

Rate of
compensation increase

4.00%

Mortality table

IRS required
mortality table
for 2010
funding
valuation

IRS required
mortality table
for 2009
funding
valuation

IRS required
mortality table
for 2008
funding
valuation

IRS required
mortality table
for 2010
funding
valuation

IRS required
mortality table
for 2009
funding
valuation

IRS required
mortality table
for 2008
funding
valuation

Healthcare cost
trend on covered
charges

N/A

7.5%

decreasing to
ultimate
trend of 5.0%

in 2015

7.5%

decreasing to
ultimate
trend of 5.0%

in 2014

8.00%

decreasing to
ultimate
trend of 5.0%

in 2014

(a)	Assumptions used to determine year-end 2009 benefit obligations are the assumptions used to estimate the 2010 net periodic benefit cost.

The following weighted average assumptions were used to determine the net periodic benefit costs for all the plans for the years ended December 31, 2009, 2008 and 2007:

Pension Benefits

Other Postretirement Benefits

2009

2008

2007

2009

2008

2007

Discount rate

6.09%

6.20%

5.90%

6.09%

6.20%

5.85%

Expected return on plan assets

8.50%

8.75%

8.10%^(a)

7.80%^(a)

7.85%^(a)

Rate of compensation increase

4.00%

Mortality table

IRS required
mortality
table for
2009
funding
valuation

IRS required
mortality
table for
2008
funding
valuation

RP 2000 with
10-year
projection of
mortality
improvements

IRS required
mortality
table for
2009 funding
valuation

IRS required
mortality
table for
2008 funding
valuation

RP 2000 with
10-year
projection of
mortality
improvements

Healthcare cost
trend on covered
charges

N/A

7.50%

decreasing
to ultimate
trend of 5.0%

in 2014

8.00%

decreasing
to ultimate
trend of 5.0%

in 2014

9.00%

decreasing to
ultimate trend
of 5.0%

in 2012

(a)	Not applicable to the Exelon-sponsored former-AmerGen other postretirement benefit plan, as this plan does not have any plan assets.

Assumed healthcare cost trend rates have a significant effect on the costs reported for the healthcare plans. A one percentage point change in assumed healthcare cost trend rates would have the following effects:


Effect of a one percentage point increase in assumed healthcare cost trend
on 2009 total service and interest cost components	$	49
on postretirement benefit obligation at December 31, 2009		448
Effect of a one percentage point decrease in assumed healthcare cost trend on 2009 total service and interest cost components		(40	)
on postretirement benefit obligation at December 31, 2009		(372	)

Contributions

The following table provides contributions made by Generation, ComEd, PECO and BSC to the pension and other postretirement benefit plans:


	Pension Benefits									Other Postretirement Benefits
	2009			2008			2007			2009 ^(a)		2008 ^(a)		2007 ^(a)
Generation	$	201		$	37		$	24		$	64	$	71	$	78
ComEd		164			9			3			50		49		52
PECO		31			11			1			21		29		31
BSC		45	(b)		23	(b)		8	(b)		12		14		18

Exelon	$	441		$	80		$	36		$	147	$	163	$	179

(a)

The Registrants present the cash contributions above net of Federal subsidy payments received on each of their respective Consolidated Statements of Cash Flows. Exelon, Generation, ComEd and PECO received Federal subsidy payments of $10 million, $5 million, $3 million and $1 million, respectively, in 2009, $12 million, $5 million, $3 million and $2 million, respectively, in 2008, and $6 million, $3 million, $2 million and $1 million, respectively, in 2007.

(b)	$1 million and $5 million of this amount was deferred under Exelon’s deferred compensation plan as of 2008 and 2007. None of the amount was deferred as of December 31, 2009.

Funding is based upon actuarially determined contributions that take into account the minimum contribution required under ERISA, as amended, for the pension plans and the amount deductible for income tax purposes for the other postretirement benefit plans. Management considers these and other factors when making funding decisions. The calculation of funding requirements for pension plans requires election of a methodology to determine the actuarial value of assets and the interest rate used to measure the pension liabilities. Recent pension funding guidance has modified some of those elections.

The Pension Protection Act of 2006 (the Act) became effective January 1, 2008 and requires companies to, among other things, maintain certain defined minimum funding thresholds (or face plan benefit restrictions). Generally, effective January 1, 2008 (January 1, 2009 for most union-represented employees), Exelon prospectively amended the vesting schedule, benefit crediting rate and investment crediting rate of its relevant cash balance pension plans in accordance with interim guidance issued by the U.S. Treasury Department pursuant to the Act. These changes to the cash balance pension plans did not have a significant impact on Exelon’s results of operations or cash flows. In March and September 2009, the U.S. Treasury Department provided guidance on the selection of the corporate bond yield curve for determining the interest rate used to calculate plan liabilities and determine pension funding requirements. There are other legislative and regulatory funding relief proposals also being discussed. Exelon is monitoring the progress of these initiatives and evaluating their potential impact on funding requirements and strategies.

The Worker, Retiree, and Employer Recovery Act of 2008 (WRERA) was signed into law in December 2008. WRERA grants plan sponsors relief from certain funding requirements and benefit restrictions, and also provides some technical corrections to the Act. There are two primary provisions that impact funding results for Exelon. First, required contributions will be based on a percentage of the funding target for years beginning before 2011, rather than a funding target of 100%. These percentages are 92%, 94% and 96% in 2008, 2009 and 2010, respectively. Second, one of the technical corrections, referred to as asset smoothing, allows the use of average asset amounts, including expected returns (subject to certain limitations), for a 24-month period prior to the measurement date, in the determination of funding requirements. Exelon has elected to utilize asset smoothing for its largest pension plan and market value of assets for its remaining plans. These elections are expected to provide Exelon the opportunity to defer certain contributions to later years and potentially mitigate future contributions through investment market recovery.

During September 2009, Exelon made a discretionary pension contribution of $350 million to its largest pension plan. The contribution, combined with funding elections for the 2009 and 2010 plan years, is expected to reduce future contribution requirements.

Exelon allocates pension contributions to its subsidiaries in proportion to active service costs recognized. In addition, Exelon allocates other postretirement contributions to its subsidiaries in proportion to total costs recognized. Exelon expects to contribute approximately $417 million to the benefit plans in 2010, of which Generation, ComEd and PECO expect to contribute $198 million, $92 million and $67 million, respectively. Exelon’s expected 2010 benefit plan contributions of $417 million include $261 million of minimum required pension contributions (including contributions to avoid benefit restrictions) and other postretirement contributions of $156 million (of which approximately $100 million is discretionary). These estimates are subject to the completion of a valuation report of Exelon’s pension and other postretirement benefit obligations. This valuation report will reflect actual census data as of January 1, 2010 and claims activity as of December 31, 2009.

Estimated Future Benefit Payments

Estimated future benefit payments to participants in all of the pension plans and postretirement benefit plans as of December 31, 2009 were:


	Pension Benefits		Other Postretirement Benefits
2010	$	708	$	190
2011		639		199
2012		651		205
2013		677		212
2014		677		219
2015 through 2019		3,873		1,256

Total estimated future benefits payments through 2019	$	7,225	$	2,281

(a)

Estimated future benefit payments do not reflect an anticipated Federal subsidy provided through the Prescription Drug Act. The Federal subsidies to be received by Exelon in the years 2010, 2011, 2012, 2013, 2014 and from 2015 through 2019 are estimated to be $10 million, $11 million, $12 million, $13 million, $14 million and $89 million, respectively.

Allocation to Exelon Subsidiaries

Generation, ComEd and PECO account for their participation in Exelon’s pension and other postretirement benefit plans by applying multiemployer accounting. Employee-related assets and liabilities, including both pension and postretirement liabilities, were allocated by Exelon to its subsidiaries based on the number of active employees as of January 1, 2001 as part of Exelon’s corporate restructuring. Exelon allocates the components of pension and other postretirement costs to the participating employers based upon several factors, including the measures of active employee participation in each participating unit. The obligation for Generation, ComEd and PECO reflects the initial allocation and the cumulative costs incurred and contributions made since January 1, 2001.

The following approximate amounts were included in capital and operating and maintenance expense during 2009, 2008 and 2007, respectively, for Generation’s, ComEd’s, PECO’s and BSC’s allocated portion of the Exelon-sponsored pension and other postretirement benefit plans:


	Generation		ComEd		PECO		BSC^(a)		Exelon
2009	$	240	$	192	$	47	$	57	$	536
2008		139		101		32		42		314
2007		142		101		32		45		320

(a)	These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations.

Plan Assets

Investment Strategy. Exelon’s overall investment strategy is to achieve a mix of investments for long-term growth and for near-term benefit payments with diversification of asset types, fund strategies, and fund managers. Exelon seeks to achieve optimal asset returns while balancing the liquidity requirements of the plans’ liabilities. Exelon utilizes a diversified, strategic asset allocation to efficiently and prudently generate investment returns that will meet the objectives of the investment trusts that hold the plan assets. Asset/liability studies are utilized to determine the specific asset allocations for the trusts. In general, Exelon’s investment strategy reflects the belief that equities are expected to outperform fixed-income investments and are well-suited to bear the risk of added volatility over the long-term. Accordingly, the asset allocations of the trusts usually reflect a higher allocation to equities as compared to fixed-income securities. Equity securities primarily include investments in diversified portfolios of domestic large cap and small cap firms. Equity securities also include non-U.S. equity securities, which are used to diversify some of the volatility of the U.S. equity market while providing comparable long-term returns. Fixed-income securities include diversified portfolios invested across a broad spectrum of primarily investment-grade securities. These portfolios have the Barclays Aggregate Bond Index as their benchmark. In the pension trusts, Exelon generally maintains approximately 10% of its plan assets in alternative asset classes. Alternative asset classes are utilized to provide additional diversification and return potential and include investments in private equity and real estate. On a quarterly basis, Exelon reviews the actual asset allocations and follows a rebalancing procedure in order to remain within an allowable range, as defined by its policy, of its targeted allocation percentages. Exelon’s investment guidelines limit the amount of allowed exposure to investments in more volatile sectors and limit concentrations based on established criteria. A change in the overall investment strategy could significantly impact the expected rate of return on plan assets.

Exelon’s pension plan’s weighted average asset allocations at December 31, 2009 and 2008 and target allocation for 2009 were as follows:


Asset Category	Target Allocation at December 31, 2009		Percentage of Plan Assets at December 31,
Asset Category	Target Allocation at December 31, 2009		2009		2008
Equity securities
Large Cap	30-35	%	32	%	26	%
Small Cap	10		9		8
International	15		15		13
Private Equity	5		6		6

Total Equity Securities	60-65	%	62	%	53	%

Fixed Income Securities	35-40	%	34	%	42	%
Real Estate	5	%	4	%	5	%

Total			100	%	100	%

Exelon’s other postretirement benefit plan’s weighted-average asset allocations at December 31, 2009 and 2008 and target allocation for 2009 were as follows:


Asset Category	Target Allocation at December 31, 2009		Percentage of Plan Assets at December 31,
Asset Category	Target Allocation at December 31, 2009		2009		2008
Equity securities
Large Cap	30-40	%	39	%	35	%
Small Cap	5-10	%	10		9
International	15		15		14

Total Equity Securities	60-65	%	64	%	58	%

Fixed Income Securities	35-40	%	36	%	42	%

Total			100	%	100	%

Securities Lending Programs. The majority of the benefit plans participate in a securities lending program with the trustees of the plans’ investment trusts. The program authorizes the trustee of the particular trust to lend securities, which are assets of the plan, to approved borrowers. The trustees require borrowers, pursuant to a security lending agreement, to deliver collateral to secure each loan. The loaned securities are required to be collateralized by cash, U.S. Government securities or irrevocable bank letters of credit. Initial collateral levels are no less than 102% and 105% of the market value of the borrowed securities for collateral denominated in U.S. and foreign currency, respectively. Subsequent collateral levels, which are adjusted daily, must be maintained at a level no less than 100% of the market value of borrowed securities. Cash collateral received is invested in collateral funds comprised primarily of short term investment vehicles. Collateral may not be sold or re-pledged by the trustees, however, the borrowers may sell or re-pledge the loaned securities. Exelon’s benefit plans bear the risk of loss with respect to unfavorable changes in the fair value of the invested cash collateral. Such losses may result from a decline in the fair value of specific investments or due to liquidity impairments resulting from current market conditions. Exelon, the trustees and the borrowers have the right to terminate the lending agreement at any time. In the event of termination, the borrowers must return the loaned securities or surrender the collateral. Losses recognized by the trust were not material during the years ended December 31, 2009 and 2008. Management continues to monitor the performance of the invested collateral and work closely with the trustees to limit any potential losses.

In the fourth quarter of 2008, Exelon decided to end its participation in the securities lending program and chose to initiate a gradual withdrawal of the trusts’ investments in order to minimize potential losses due to the absence of liquidity in the market. As part of its withdrawal plan and in order to minimize losses, Exelon temporarily increased its securities on loan during 2009. This temporary increase does not change Exelon’s intent to end its participation in the securities lending program. Currently, the weighted average maturity of the securities within the collateral funds is approximately 4 months. The fair value of securities on loan was approximately $356 million and $269 million at December 31, 2009 and 2008, respectively. The fair value of the cash and non-cash collateral received for these loaned securities was $365 million at December 31, 2009 and $274 million at December 31, 2008. A portion of the income generated through the investment of cash collateral is remitted to the borrowers, and the remainder is allocated between the trusts and the trustees in their capacity as security agents.

Concentrations of Credit Risk. Exelon evaluated its pension and other postretirement benefit plans’ asset portfolios for the existence of significant concentrations of credit risk as of December 31, 2009. Types of concentrations that were evaluated include, but are not limited to, investment concentrations in a single entity, type of industry, foreign country, and individual fund. As of December 31, 2009, there were no significant concentrations (defined as greater than 10 percent of plan assets) of risk in Exelon’s pension and other postretirement benefit plan assets.

Fair Value Measurements

The following table presents Exelon’s pension and other postretirement benefit plan assets measured and recorded at fair value on Exelon’s Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2009:


As of December 31, 2009 (In millions) ^(a) (f)	Level 1		Level 2		Level 3		Total
Pension Plan Assets
Cash equivalents	$	37	$	—	$	—	$	37
Equity securities		1,357		—		—		1,357	^(b)
Commingled funds		515		3,641		450		4,606	^(c)
Fixed Income
Debt securities issued by the U.S. Treasury and other								—	^(d)
U.S. government corporations and agencies		140		23		—		163	^(d)
Debt securities issued by states of the United States and by political subdivisions of the states		—		11		—		11	^(d)
Corporate debt securities		—		245		—		245	^(d)
Federal agency mortgage-backed securities		—		825		—		825	^(e)
Non-federal agency mortgage-backed securities		—		342		—		342	^(e)

Fixed Income subtotal		140		1,446		—		1,586

Real Estate		154		—		156		310

Pension Plan Assets subtotal	$	2,203	$	5,087	$	606	$	7,896

Other postretirement benefit plan assets
Cash equivalents		4		—		—		4
Equity securities		199		—		—		199	^(b)
Commingled funds		112		894		—		1,006	^(c)
Fixed Income
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies		14		2		—		16
Debt securities issued by states of the United States and by political subdivisions of the states		—		103		—		103	^(d)
Corporate debt securities		—		20		—		20	^(d)
Federal agency mortgage-backed securities		—		94		—		94	^(e)
Non-federal agency mortgage-backed securities		—		34		—		34	^(e)

Fixed Income subtotal		14		253		—		267

Real Estate		1		—		—		1

Postretirement benefit plan subtotal	$	330	$	1,147	$	—	$	1,477

Total pension and other postretirement benefit plan assets	$	2,533	$	6,234	$	606	$	9,373

(a)	See Note 7—Fair Value of Assets and Liabilities for a description of levels within the fair value hierarchy.

(b)

The performance of equity portfolios is benchmarked against the Standard and Poor’s (S&P) 500 Index, Russell 2000 Index or the Morgan Stanley Capital International Europe, Australasia and Far East (EAFE) Index. Excludes a $210 million payable for collateral on loaned securities in connection with the benefit plans’ participation in securities lending programs.

(c)

The benefit plans own commingled funds that invest in equity and fixed income securities, private equity, and real estate. The commingled funds that invest in equity securities seek to out-perform the S&P 500 Index, Morgan Stanley Capital International EAFE Index and Russell 2000 Index. The commingled funds that hold fixed income securities invest primarily in domestic investment grade securities. Including corporate, municipal, and U.S. Treasury securities. The commingled funds that hold private equity investments seek to track the Russell 2000 plus 300 basis points. The commingled funds that hold direct investments in real estate are diversified by geography and type of property. These funds are benchmarked to the National Council of Real Estate Investment Fiduciaries (NCREIF) index.

(d)	This category predominantly represents diverse issues of domestic, investment-grade fixed income securities. Excludes a $148 million payable for collateral on loaned securities in connection with the benefit plans’ participation in securities lending programs.

(e)

This category represents investments in federal agency, commercial and residential mortgage-backed securities that seek to out-perform the Barclays Capital Aggregate Index. Excludes a $7 million payable for collateral on loaned securities in connection with the benefit plans’ participation in securities lending programs.

(f)	The total fair value of pension and other postretirement benefit plan assets excludes $20 million of interest and dividends receivable and $40 million related to pending sales transactions.

The following table presents the fair value reconciliation of Level 3 assets and liabilities measured at fair value for pension and other postretirement benefit plans during the year ended December 31, 2009:


(in millions)	Commingled funds in private equity Investments			Commingled funds in direct real estate			Total
Pension Assets
Balance as of January 1, 2009	$	808		$	232		$	1,040
Actual return on plan assets:
Relating to assets still held at the reporting date		57			(88	)		(31	)
Relating to assets sold during the period		35			—			35
Purchases, sales and settlements		136			12			148
Transfers into (out of) Level 3		(586	)		—			(586	)

Balance as of December 31, 2009	$	450		$	156		$	606

Other Postretirement Benefits
Balance as of January 1, 2009	$	53		$	—		$	53
Relating to assets sold during the period		23			—			23
Transfers into (out of) Level 3		(76	)		—			(76	)

Balance as of December 31, 2009	$	—		$	—		$	—

Valuation Techniques Used to Determine Fair Value

Cash equivalents. Investments with maturities of three months or less when purchased, including certain short-term fixed-income securities, are considered cash equivalents and are included in the recurring fair value measurements hierarchy as Level 1 or Level 2.

Equity securities. With respect to individually held equity securities, the trustees obtain prices from pricing services, whose prices are obtained from direct feeds from market exchanges, which Exelon is able to independently corroborate. Preferred and common corporate stocks are valued based on quoted prices in active markets and are categorized in Level 1. Equity securities held individually are primarily traded on exchanges which contain only actively traded securities due to the volume trading requirements imposed by these exchanges.

Commingled funds. Commingled funds are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives, which are consistent with Exelon’s overall investment strategy. The values of the majority of commingled funds are not publically quoted and must trade through a broker. For equity and fixed-income commingled fund traded through a broker, the fund administrator values the fund using the NAV per fund share, derived from the quoted prices in active markets of the underlying securities. These funds have been categorized in Level 2. Equity and fixed-income funds with publically quoted prices have been categorized in Level 1. Private equity commingled funds are generally partnerships in which a benefit plan is a limited partner. These partnerships generate capital returns through investing in enterprises such as other limited partnerships or other pooled investment vehicles which, in turn, make equity-oriented investments in venture capital companies. Private equity commingled funds are valued by investment managers on a periodic basis using pricing models that use market, income, and cost valuation methods. Since these valuation inputs are not highly observable, private equity funds have been categorized as Level 3.

Fixed-income securities. For fixed income securities, multiple prices and price types are obtained from pricing vendors whenever possible, which enables cross-provider validations in addition to checks for unusual daily movements. A primary price source is identified based on asset type, class or issue for each security. The trustees monitor prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the portfolio managers challenge an assigned price and the trustees determine that another price source is considered to be preferable. Exelon has obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, Exelon selectively corroborates the fair values of securities by comparison to other market-based price sources. Investments in U.S. Treasury securities have been categorized in Level 1 because they trade in highly-liquid and transparent markets. The fair values of fixed income securities, excluding U.S. Treasury securities, are based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences and are categorized as Level 2. To draw parallels from the trading and quoting of fixed income securities with similar features, pricing services consider various characteristics including the issuer, maturity, purpose of loan, collateral attributes, prepayment speeds, interest rates and credit ratings in order to properly value these securities.

Real Estate. Real estate investment trusts are valued daily based on quoted prices in active markets and are categorized in Level 1. Real estate commingled funds are funds with a direct investment in a pool of real estate properties. These funds are valued by investment managers on a periodic basis using pricing models that use independent appraisals from sources with professional qualifications. Since these valuation inputs are not highly observable, real estate investments have been categorized as Level 3 investments.

401(k) Savings Plan (Exelon, Generation, ComEd and PECO)

Exelon, Generation, ComEd and PECO participate in a 401(k) savings plan sponsored by Exelon. The plan allows employees to contribute a portion of their pre-tax income in accordance with specified guidelines. Exelon, Generation, ComEd and PECO match a percentage of the employee contribution up to certain limits. The cost of matching contributions to the savings plan totaled the following:


For the Years Ended	Exelon		Generation		ComEd		PECO
2009	$	70	$	36	$	20	$	8
2008		66		33		19		7
2007		63		30		18		6

Common Stock (Exelon, Generation, ComEd and PECO)

12 Months Ended

Dec. 31, 2009

Statement [Line Items]

Common Stock (Exelon, Generation, ComEd and PECO)

16. Common Stock (Exelon, Generation, ComEd and PECO)

At December 31, 2009 and 2008, Exelon’s common stock without par value consisted of 2,000,000,000 shares authorized and 659,798,515 and 658,154,642 shares outstanding, respectively. At December 31, 2009 and 2008, ComEd’s common stock with a $12.50 par value consisted of 250,000,000 shares authorized and 127,016,519 shares outstanding. At December 31, 2009 and 2008, PECO’s common stock without par value consisted of 500,000,000 shares authorized and 170,478,507 shares outstanding.

ComEd had 75,294 and 75,410 warrants outstanding to purchase ComEd common stock as of December 31, 2009 and 2008, respectively. The warrants entitle the holders to convert such warrants into common stock of ComEd at a conversion rate of one share of common stock for three warrants. At December 31, 2009 and 2008, 25,098 and 25,137 shares of common stock, respectively, were reserved for the conversion of warrants.

Share Repurchases

Share Repurchase Programs. In April 2004, Exelon’s Board of Directors approved a discretionary share repurchase program that allows Exelon to repurchase shares of its common stock on a periodic basis in the open market. The share repurchase program is intended to mitigate, in part, the dilutive effect of shares issued under Exelon’s employee stock option plan and Exelon’s ESPP. The aggregate value of the shares of common stock repurchased pursuant to the program cannot exceed the economic benefit received after January 1, 2004 due to stock option exercises and share purchases pursuant to Exelon’s ESPP. The economic benefit consists of the direct cash proceeds from purchases of stock and the tax benefits associated with exercises of stock options. The 2004 share repurchase program has no specified limit on the number of shares that may be repurchased and no specified termination date. Any shares repurchased are held as treasury shares unless cancelled or reissued at the discretion of Exelon’s management. During 2008, 6.6 million shares of common stock were purchased under this share repurchase program for $500 million.

On August 31 and December 19, 2007, Exelon’s Board of Directors approved a share repurchase program for up to $1.25 billion and $500 million of Exelon’s outstanding common stock, respectively. In 2007, Exelon entered into agreements to repurchase a total of $1.25 billion of Exelon’s common shares under the first accelerated share repurchase (ASR) program, and 2008, Exelon entered into an agreement to repurchase a total of $500 million of Exelon’s common shares under the second ASR program. Exelon accounted for each ASR program as two distinct transactions, as shares of common stock acquired in a treasury stock transaction and as a forward contract indexed to Exelon’s own common stock. The ASR agreements include a pricing collar, which establishes a minimum and maximum number of shares that can be repurchased. In September 2007 and February 2008. Exelon received the minimum number of shares, as determined by each of the ASR agreements, which amounted to 15.1 million shares and 5.8 million shares, respectively. These initial shares were recorded as treasury stock, at cost, for $1.17 billion and $436 million in September 2007 and February 2008, respectively.

The forward contract issued in September 2007 was settled in February 2008 when Exelon received 525,666 shares valued at $42 million. The ultimate settlement of this forward contract was based on changes in the price of Exelon’s common stock from September 24, 2007 through the date of settlement. The forward contract issued in February 2008 was settled in May 2008 when Exelon received 260,086 shares valued at $22 million. The ultimate settlement of this forward contract was based on changes in the price of Exelon’s common stock from February 29, 2008 through the date of settlement.

In the third quarter of 2008, Exelon’s board of directors approved a share repurchase program for up to $1.5 billion of Exelon’s outstanding common stock. Subsequently, Exelon management determined to defer indefinitely any share repurchases. This decision was made in light of a variety of factors, including: developments affecting the world economy and commodity markets, including those for electricity and gas; the continued uncertainty in capital and credit markets and the potential impact of those events on Exelon’s future cash needs; projected cash needs to support investment in the business, including maintenance capital and nuclear uprates; and value-added growth opportunities.

Under the share repurchase programs, 34.8 million shares of common stock are held as treasury stock with a cost of $2.3 billion as of December 31, 2009. During 2009, Exelon had no common stock repurchases.

Stock-Based Compensation Plans

Exelon grants stock-based awards through its LTIP, which primarily includes performance share awards, stock options and restricted stock units. At December 31, 2009, there were approximately 23 million shares authorized for issuance under the LTIP. During the years ended December 31, 2009, 2008 and 2007, exercised and distributed stock-based awards were primarily issued from authorized but unissued common stock shares.

As the LTIP sponsor, Exelon is the sole issuer of all stock-based compensation awards. All awards are recorded as equity or a liability in Exelon’s Consolidated Balance Sheets. The stock-based compensation expense specifically attributable to the employees of Generation, ComEd and PECO is directly recorded to operating and maintenance expense within each of their respective Consolidated Statements of Operations. Stock-based compensation expense attributable to BSC employees is allocated to the Registrants using a cost-causative allocation method.

The following table presents the stock-based compensation expense included in Exelon’s Consolidated Statements of Operations during the years ended December 31, 2009, 2008 and 2007:


	Year Ended December 31,
Components of Stock-Based Compensation Expense	2009			2008			2007
Performance shares	$	31		$	28		$	76
Stock options		20			24			34
Restricted stock units		26			20			13
Other stock-based awards		4			4			2

Total stock-based compensation included in operating and maintenance expense		81			76			125

Income tax benefit		(32	)		(29	)		(48	)

Total after-tax stock-based compensation expense	$	49		$	47		$	77

The following table presents stock-based compensation expense (pre-tax) during the years ended December 31, 2009, 2008 and 2007:


	Year Ended December 31,
Subsidiaries	2009		2008		2007
Generation	$	38	$	38	$	47
ComEd		4		4		8
PECO		6		6		5
BSC ^(a)		33		28		65

Total	$	81	$	76	$	125

(a)	These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations.

There were no significant stock-based compensation costs capitalized during the years ended December 31, 2009, 2008 and 2007.

Exelon receives a tax deduction based on the intrinsic value of the award on the exercise date for stock options and distribution date for performance share awards and restricted stock units. For each award, throughout the requisite service period, Exelon recognizes the tax benefit related to compensation costs. The tax deductions in excess of the benefits recorded throughout the requisite service period are recorded to common stock and are included in other financing activities within Exelon’s Consolidated Statements of Cash Flows. The following table presents information regarding Exelon’s tax benefits during the years ended December 31, 2009, 2008 and 2007:


	Year Ended December 31,
	2009		2008		2007
Realized tax benefit when exercised/distributed:
Stock options	$	6	$	59	$	93
Restricted stock units		7		4		7
Performance share awards		19		27		28
Stock deferral plan		1		10		25
Excess tax benefits included in other financing activities of Exelon’s Consolidated Statements of Cash Flows:
Stock options		4		51		77
Restricted stock units		—		1		4
Performance share awards		—		2		1
Stock deferral plan		—		6		15

Stock Options

Non-qualified stock options to purchase shares of Exelon’s common stock are granted under the LTIP. The exercise price of the stock options is equal to the fair market value of the underlying stock on the date of option grant. Stock options granted under the LTIP generally become exercisable upon a specified vesting date. The vesting period of stock options is generally four years. All stock options expire ten years from the date of grant.

The value of stock options at the date of grant is expensed over the requisite service period using the straight-line method. The requisite service period for stock options is generally four years. However, certain stock options become fully vested upon the employee reaching retirement-eligibility. The value of the stock options granted to retirement-eligible employees is either recognized immediately upon the date of grant or through the date at which the employee reaches retirement eligibility.

Exelon grants most of its stock options in the first quarter of each year. Stock options granted during the remaining quarters of 2009, 2008 and 2007 were not significant.

The fair value of each option is estimated on the date of grant using the Black-Scholes-Merton option-pricing model. The following table presents the weighted average assumptions used in the pricing model for grants and the resulting weighted average grant date fair value of stock options granted for the years ended December 31, 2009, 2008 and 2007:


	Year Ended December 31,
	2009			2008			2007
Dividend yield		3.72	%		2.73	%		2.94	%
Expected volatility		36.70	%		29.30	%		22.00	%
Risk-free interest rate		2.01	%		3.17	%		4.71	%
Expected life (years)		6.25			6.25			6.25
Weighted average grant date fair value	$	14.43		$	18.36		$	13.05

The dividend yield is based on several factors, including Exelon’s most recent dividend payment at the grant date and the average stock price over the previous year. Expected volatility is based on implied volatilities of traded stock options in Exelon’s common stock and historical volatility over the estimated expected life of the stock options. The risk-free interest rate for a security with a term equal to the expected life is based on a yield curve constructed from U.S. Treasury strips at the time of grant. For each year presented, the expected life represents the period of time the stock options are expected to be outstanding and is based on the simplified method. Exelon believes that the simplified method is appropriate due to several factors that result in historical exercise data not being sufficient to determine a reasonable estimate of expected term. Exelon uses historical data to estimate employee forfeitures, which are compared to actual forfeitures on a quarterly basis and adjusted as necessary.

The following table presents information with respect to stock option activity during the year ended December 31, 2009:


	Shares		Weighted Average Exercise Price (per share)		Weighted Average Remaining Contractual Life (years)	Aggregate Intrinsic Value
Balance of shares outstanding at December 31, 2008	11,341,728		$	45.17
Options granted	1,180,280			56.39
Options exercised	(686,059	)		29.29
Options forfeited	(213,510	)		60.71
Options expired	(184,898	)		36.95

Balance of shares outstanding at December 31, 2009	11,437,541		$	47.12	5.42	$	83

Exercisable at December 31, 2009 ^(a)	9,888,686		$	45.00	5.05	$	83

(a)	Includes stock options issued to retirement eligible employees.

The following table summarizes additional information regarding stock options exercised during the years ended December 31, 2009, 2008 and 2007:


	Year Ended December 31,
Stock Options Exercised	2009		2008		2007
Intrinsic value ^(a)	$	15	$	147	$	231
Cash received for exercise price		20		108		186

(a)	The difference between the market value on the date of exercise and the strike price.

The following table summarizes Exelon’s nonvested stock option activity for the year ended December 31, 2009:


	Shares		Weighted Average Exercise Price (per share)
Nonvested at December 31, 2008 ^(a)	2,951,737		$	56.42
Granted ^(b)	1,180,280			56.39
Vested ^(b)	(2,369,652	)		53.23
Forfeited	(213,510	)		60.71

Nonvested at December 31, 2009 ^(a)	1,548,855		$	60.69

(a)	Excludes 1,213,909 and 953,175 of stock options issued to retirement-eligible employees at December 31, 2009 and December 31, 2008, respectively, as they are fully vested.

(b)	Includes 492,100 of stock options issued to retirement eligible employees that vested immediately on the date of grant.

As of December 31, 2009, $9 million of total unrecognized compensation costs related to nonvested stock options are expected to be recognized over the remaining weighted-average period of 2.53 years.

Restricted Stock Units

Exelon grants restricted stock units under the LTIP. The majority of Exelon’s restricted stock units will be settled in common stock. In accordance with the authoritative guidance for share-based payments, the cost of services received from employees in exchange for the issuance of restricted stock units to be settled in stock is required to be measured based on the grant date fair value of the restricted stock unit issued. On a very limited basis, Exelon has granted restricted stock units to certain ComEd executives that will be settled in cash. The obligations related to these restricted stock units have been classified as liabilities on Exelon’s Consolidated Balance Sheets and are remeasured each reporting period throughout the requisite service period.

The value of the restricted stock units is expensed over the requisite service period using the straight-line method. The requisite service period for restricted stock units is generally three to five years. However, certain restricted stock unit awards become fully vested upon the employee reaching retirement-eligibility. The value of the restricted stock units granted to retirement-eligible employees is either recognized immediately upon the date of grant or through the date at which the employee reaches retirement eligibility. Exelon uses historical data to estimate employee forfeitures, which are compared to actual forfeitures on a quarterly basis and adjusted if necessary.

The following table summarizes Exelon’s nonvested restricted stock unit activity for the year ended December 31, 2009:


	Shares		Weighted Average Grant Date Fair Value (per share)
Nonvested at December 31, 2008 ^(a)	899,510		$	64.26
Granted	517,569			56.08
Vested	(268,812	)		55.31
Forfeited	(75,370	)		62.96
Undistributed vested awards ^(b)	(144,955	)		58.45

Nonvested at December 31, 2009 ^(a)	927,942		$	63.30

(a)	Excludes 211,246 and 118,948 of restricted stock units issued to retirement-eligible employees at December 31, 2009 and December 31, 2008, respectively, as they are fully vested.

(b)	Represents restricted stock units granted to retirement-eligible participants in 2009.

The weighted average grant date fair value of restricted stock units granted during the years ended December 31, 2009, 2008 and 2007 was $56.08, $74.83 and $63.89, respectively. As of December 31, 2009 and 2008, Exelon had obligations related to outstanding restricted stock units not yet settled of $42 million and $33 million, respectively, which are included in common stock in Exelon’s Consolidated Balance Sheets. In addition, Exelon had obligations related to outstanding restricted stock units that will be settled in cash of $1 million at December 31, 2009 and 2008, which are included in deferred credits and other liabilities in Exelon’s Consolidated Balance Sheets. During the years ended December 31, 2009, 2008 and 2007, Exelon settled restricted stock units with fair value totaling $17 million, $10 million and $18 million, respectively. As of December 31, 2009, $27 million of total unrecognized compensation costs related to nonvested restricted stock units are expected to be recognized over the remaining weighted-average period of 2.23 years.

Performance Share Awards

Exelon grants performance share awards under the LTIP. The number of performance shares granted is determined based on the performance of Exelon’s common stock relative to certain stock market indices during the three-year period through the end of the year of grant. These performance share awards generally vest and settle over a three-year period. The holders of performance share awards receive shares of common stock and/or cash annually during the vesting period. Participants are eligible for partial or full distributions in cash if they meet certain stock ownership requirements.

Performance share awards to be settled in stock are recorded as common stock within the Consolidated Balance Sheets and are recorded at fair value at the date of grant. The grant date fair value of equity classified performance share awards granted during the year ended December 31, 2009 was estimated using historical data for the previous two plan years and a Monte Carlo simulation model for the current plan year. This model requires assumptions regarding Exelon’s total shareholder return relative to certain stock market indices and the stock beta and volatility of Exelon’s common stock and all stocks represented in these indices. Volatility for Exelon and all comparable companies is based on historical volatility over one year using daily stock price observation. Performance share awards expected to be settled in cash are recorded as liabilities within the Consolidated Balance Sheets. The grant date fair value of liability classified performance share awards granted during the year ended December 31, 2009 was based on historical data for the previous two plan years and actual results for the current plan year. The liabilities are remeasured each reporting period throughout the requisite service period and as a result, the compensation costs for cash-settled awards are subject to volatility.

For non retirement-eligible employees, stock-based compensation costs are recognized over the vesting period of three years using the graded-vesting method, a method in which the compensation cost is recognized over the requisite service period for each separately vesting tranche of the award as though the award were multiple awards. For performance shares granted to retirement-eligible employees, the value of the performance shares is recognized ratably over the vesting period which is the year of grant.

The following table summarizes Exelon’s nonvested performance share awards activity for the year ended December 31, 2009:


	Shares		Weighted Average Grant Date Fair Value (per share)
Nonvested at December 31, 2008 ^(a)	924,373		$	66.47
Granted	475,972			57.34
Vested	(478,589	)		64.24
Forfeited	(25,536	)		66.15
Undistributed vested awards ^(b)	(265,962	)		59.58

Nonvested at December 31, 2009 ^(a)	630,258		$	64.20

(a)	Excludes 551,558 and 640,453 of performance share awards issued to retirement-eligible employees at December 31, 2009 and December 31, 2008, respectively, as they are fully vested.

(b)	Represents performance share awards granted to retirement-eligible participants in 2009.

The weighted average grant date fair value of performance share awards granted during the years ended December 31, 2009, 2008 and 2007 was $57.34, $72.89 and $59.94, respectively. During the years ended December 31, 2009, 2008 and 2007, Exelon settled performance shares with a fair value totaling $47 million, $69 million and $65 million, respectively, of which $30 million, $44 million and $39 million was paid in cash, respectively. As of December 31, 2009, $10 million of total unrecognized compensation costs related to nonvested performance shares are expected to be recognized over the remaining weighted-average period of 1.72 years.

The following table presents the balance sheet classification of obligations related to outstanding performance share awards not yet settled:


	As of December 31,
Obligation Related to Outstanding Performance Share Awards	2009		2008
Current liabilities ^(a)	$	20	$	28
Deferred credits and other liabilities ^(b)		14		21
Common stock		26		26

Total	$	60	$	75

(a)	Represents the current liability related to performance share awards expected to be settled in cash.

(b)	Represents the long-term liability related to performance share awards expected to be settled in cash.

Commitments and Contingencies (Exelon, Generation, ComEd and PECO)

12 Months Ended

Dec. 31, 2009

Statement [Line Items]

Commitments and Contingencies (Exelon, Generation, ComEd and PECO)

18. Commitments and Contingencies (Exelon, Generation, ComEd and PECO)

Nuclear Insurance

The Price-Anderson Act was enacted to limit the liability of nuclear reactor owners for claims that could arise from a single incident at any of the U.S. licensed nuclear facilities and to ensure the availability of funds for claims arising in the event of an incident. As of December 31, 2009, the current liability limit per incident was $12.6 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactors. As required by the Price-Anderson Act, Generation maintains a primary level of financial protection by carrying the maximum available amount of nuclear liability insurance for claims that could arise in the event of an incident. As of January 1, 2010, the required amount of nuclear liability insurance is $375 million for each operating site. Additionally, the Price-Anderson Act requires a second layer of protection through the mandatory participation in a secondary financial protection pool by the operators of all U.S. licensed reactors (currently 104 reactors) resulting in an additional $12.2 billion in funds available for claims. Participation in the financial protection pool requires the operator of each reactor to fund its proportionate share of costs for any single incident that exceeds the primary layer of insurance coverage. Under the Price-Anderson Act, the maximum assessment, in the event of an incident for each nuclear operator per reactor per incident (including a 5% surcharge) is $117.5 million, payable at no more than $17.5 million per reactor per incident per year. Exelon’s maximum liability per incident is approximately $2.0 billion. In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay claims. The Price-Anderson Act, as amended, requires an inflation adjustment be made at least once each 5 years. The last inflation adjustment was effective October 29, 2008.

Generation is a member of an industry mutual insurance company, Nuclear Electric Insurance Limited (NEIL), which provides property damage, decontamination and premature decommissioning insurance for each station for losses resulting from damage to its nuclear plants, either due to accidents or acts of terrorism. Generation’s current limit for this coverage is $2.1 billion (except for Zion, which is $100 million). For property limits in excess of the first $1.25 billion of that limit, Generation participates in an $850 million single limit blanket policy shared by all the Generation operating nuclear sites and the Salem and Hope Creek nuclear sites. This blanket limit is not subject to automatic reinstatement in the event of a loss. In the event of an accident, insurance proceeds must first be used for reactor stabilization and site decontamination. If the decision is made to decommission the facility, a portion of the insurance proceeds will be allocated to a fund, which Generation is required by the NRC to maintain, to provide for decommissioning the facility. Generation is unable to predict the timing of the availability of insurance proceeds to Generation and the amount of such proceeds that would be available. Under the terms of the various insurance agreements, Generation could be assessed up to $163 million per year for losses incurred at any plant insured by the insurance company (the retrospective premium obligation). In the event that one or more acts of terrorism cause accidental property damage within a twelve-month period from the first accidental property damage under one or more policies for all insured plants, the maximum recovery for all losses by all insureds will be an aggregate of $3.2 billion plus such additional amounts as the insurer may recover for all such losses from reinsurance, indemnity and any other source, applicable to such losses. The $3.2 billion maximum recovery limit is not applicable, however, in the event of a “certified act of terrorism” as defined in the Terrorism Risk Insurance Act of 2002, as amended by the Terrorism Risk Insurance Program Reauthorization Act of 2007. The Terrorism Risk Insurance Act expires on December 31, 2014.

Additionally, NEIL provides replacement power cost insurance in the event of a major accidental outage at an insured nuclear station. The premium for this coverage is subject to assessment for adverse loss experience. Generation’s maximum share of any assessment is $44 million per year (the retrospective premium obligation). NEIL may require financial assurance of the ability to satisfy the obligation to pay this assessment. Recovery under this insurance for terrorist acts is subject to the $3.2 billion aggregate limit and secondary to the property insurance described above. This limit would not apply in cases of certified acts of terrorism under the Terrorism Risk Insurance Act of 2002, as amended by the Terrorism Risk Insurance Program Reauthorization Act of 2007, as described above.

Effective April 1, 2009, NEIL requires its members to maintain an investment grade credit rating or to ensure collectability of their annual retrospective premium obligation by providing a financial guarantee, letter of credit, deposit premium, or some other means of assurance. The current aggregate annual retrospective premium obligation for Generation is $207 million.

In addition, Generation participates in the Master Worker Program, which provides coverage for worker tort claims filed for bodily injury caused by a nuclear energy accident. This program was modified, effective January 1, 1998, to provide coverage to all workers whose “nuclear-related employment” began on or after the commencement date of reactor operations. Generation will not be liable for a retrospective assessment under this policy.

For its insured losses, Generation is self-insured to the extent that losses are within the policy deductible or exceed the amount of insurance maintained. Such losses could have a material adverse effect on Exelon’s and Generation’s financial condition, results of operations and liquidity.

Energy Commitments

Generation’s wholesale operations include the physical delivery and marketing of power obtained through its generation capacity, and long-, intermediate- and short-term contracts. Generation maintains a net positive supply of energy and capacity, through ownership of generation assets and power purchase and lease agreements, to protect it from the potential operational failure of one of its owned or contracted power generating units. Generation has also contracted for access to additional generation through bilateral long-term PPAs. These agreements are firm commitments related to power generation of specific generation plants and/or are dispatchable in nature. Generation enters into PPAs with the objective of obtaining low-cost energy supply sources to meet its physical delivery obligations to its customers. Generation has also purchased firm transmission rights to ensure that it has reliable transmission capacity to physically move its power supplies to meet customer delivery needs. The primary intent and business objective for the use of its capital assets and contracts is to provide Generation with physical power supply to enable it to deliver energy to meet customer needs. Generation primarily uses financial contracts in its wholesale marketing activities for hedging purposes. Generation also uses financial contracts to manage the risk surrounding trading for profit activities.

Generation has entered into bilateral long-term contractual obligations for sales of energy to load-serving entities, including electric utilities, municipalities, electric cooperatives and retail load aggregators. Generation also enters into contractual obligations to deliver energy to wholesale market participants who primarily focus on the resale of energy products for delivery. Generation provides delivery of its energy to these customers through rights for firm transmission.

At December 31, 2009, Generation’s short- and long-term commitments, relating to the purchase from and sale to unaffiliated utilities and others of energy, capacity and transmission rights as indicated in the following tables:


	Net Capacity Purchases ^(a)		Power Only Purchases ^(b)		Power Only Sales		Transmission Rights Purchases ^(c)
2010	$	305	$	91	$	1,307	$	10
2011		291		49		1,046		9
2012		274		22		568		9
2013		151		—		238		6
2014		145		—		120		—
Thereafter		1,105		—		761		—

Total	$	2,271	$	162	$	4,040	$	34

(a)

Net capacity purchases include PPAs and other capacity contracts that are accounted for as operating leases. Amounts presented in the commitments represent Generation’s expected payments under these arrangements at December 31, 2009. Expected payments include certain capacity charges which are contingent on plant availability.

(b)	Excludes renewable energy PPA contracts that are contingent in nature.

(c)	Transmission rights purchases include estimated commitments for additional transmission rights that will be required to fulfill firm sales contracts.

On April 4, 2007, Generation agreed to sell its rights to 942 MW of capacity, energy, and ancillary services supplied from its existing long-term contract with Tenaska Georgia Partners, LP through a tolling agreement with Georgia Power, a subsidiary of Southern Company, commencing June 1, 2010 and lasting for 20 years. The transaction was approved by the Georgia Public Service Commission (GPSC) in October of 2007. Exelon and Generation recognized a non-cash after-tax loss of approximately $72 million during the fourth quarter of 2007, which is included in purchased power on Exelon’s and Generation’s Consolidated Statements of Operations. The transaction provides Generation with approximately $43 million in annual revenue in the form of capacity payments over the term of the tolling agreement.

On October 15, 2007, Generation entered into an agreement (Termination Agreement) with State Line Energy, L.L.C. (State Line), an indirect wholly owned subsidiary of Dominion Resources Inc., to terminate the PPA dated as of April 17, 1996 (as amended, the State Line PPA) between State Line and Generation relating to the State Line generating facility in Hammond, Indiana. Under the State Line PPA, Generation controlled 515 MW of electric energy and capacity from the State Line facility. FERC approved the Termination Agreement on October 18, 2007. The conditions to the effectiveness of the Termination Agreement were subsequently satisfied and Generation recorded income of approximately $223 million in the fourth quarter of 2007, which is included in operating revenues on Exelon’s and Generation’s Consolidated Statements of Operations.

Pursuant to a PPA with Public Service Company of Oklahoma, a subsidiary of American Electric Power, dated as of April 17, 2009, Generation agreed to sell its rights to up to 520 MW, or approximately two-thirds of the capacity, energy and ancillary services supplied under its existing long-term contract with Green Country Energy, LLC. The delivery of power under the PPA is to commence June 1, 2012 and run through February 28, 2022.

On December 17, 2009, Generation entered into a PPA with Entergy Texas, Inc. (ETI) to sell 150 MWs through April 30, 2011 and 300 MWs thereafter of capacity and energy from the Frontier Generating Station located in Grimes County, Texas. The approximate ten year PPA is not included within the Net Capacity table above because it is contingent upon ETI waiving or obtaining regulatory approvals, which may occur after the commencement of the PPA on May 1, 2010.

ComEd purchases a portion of its expected energy requirements through various SFCs resulting from ICC-approved auctions and a competitive procurement process designed by the IPA and approved by the ICC. On January 7, 2009, the ICC approved the IPA’s plan for procurement of ComEd’s expected energy requirements from June 2009 through May 2010 which includes purchases through the spot market hedged by the financial swap contract with Generation, existing SFCs, and standard products purchased as a result of the 2009 RFP process completed in May 2009. On December 28, 2009, the ICC approved the IPA’s latest procurement plan which will result in additional contracts for standard products in the 2010 RFP process expected to be completed in the first half of 2010. See Note 2—Regulatory Issues for further information.

PECO has a long-term PPA with Generation under which PECO obtains all of its electric supply from Generation through 2010. The price for this electricity is essentially equal to the energy revenues earned from customers as specified by PECO’s 1998 restructuring settlement mandated by the Competition Act. Subsequent to 2010, PECO expects to procure all of its electric supply from market sources, which will include Generation.

During 2009, PECO entered into procurement contracts to enable PECO to meet a portion of its customers’ electric supply requirements for 2011, 2012 and 2013.

ComEd and PECO are also subject to requirements established by the Illinois Settlement Legislation and the AEPS Act, respectively, related to alternative energy resources. See Note 2—Regulatory Issues for additional information relating to electric generation procurement and alternative energy resources.

ComEd’s and PECO’s electric supply procurement, REC and AEC purchase commitments as of December 31, 2009 are as follows :


	Total		Expiration within
	Total		2010		2011-2012		2013-2014		2015 and beyond
ComEd
Electric supply procurement	$	645	$	615	$	30	$	—	$	—
RECs	$	8	$	8	$	—	$	—	$	—
PECO
Electric supply procurement	$	938	$	—	$	888	$	50	$	—
AECs	$	37	$	9	$	19	$	9	$	—

Fuel Purchase Obligations

In addition to the energy commitments described above, Generation has commitments to purchase fuel supplies for nuclear and fossil generation (and with respect to coal, commitments to sell coal) and PECO has commitments to purchase natural gas, related transportation, storage capacity and services. As of December 31, 2009, these net commitments were as follows:


	Total		Expiration within
	Total		2010		2011-2012		2013-2014		2015 and beyond
Generation	$	10,105	$	1,085	$	2,162	$	1,950	$	4,908
PECO		574		152		173		123		126

Commercial Commitments

Exelon’s commercial commitments as of December 31, 2009, representing commitments potentially triggered by future events, were as follows:


	Total		Expiration within
	Total		2010		2011-2012		2013-2014		2015 and beyond
Letters of credit (non-debt) ^(a)	$	297	$	289	$	8	$	—	$	—
Letters of credit (long-term debt)—interest coverage ^(b)		14		11		3		—		—
Surety bonds ^(c)		76		7		—		—		69
Performance guarantees ^(d)		96		—		—		95		1
Energy marketing contract guarantees ^(e)		218		193		25		—		—
Nuclear insurance premiums ^(f)		2,204		—		—		—		2,204
Lease guarantees ^(g)		125		—		—		15		110
2007 City of Chicago Settlement ^(h)		6		3		3		—		—
Midwest Generation Capacity Reservation Agreement guarantee ⁽ⁱ⁾		10		4		6		—		—
Rate relief commitments—Settlement Legislation ^(j)		25		25		—		—		—

Total commercial commitments	$	3,071	$	532	$	45	$	110	$	2,384

(a)

Letters of credit (non-debt)—Exelon and certain of its subsidiaries maintain non-debt letters of credit to provide credit support for certain transactions as requested by third parties. As of December 31, 2009, guarantees of $9 million have been issued to provide support for certain letters of credit as required by third parties.

(b)

Letters of credit (long-term debt) interest coverage—Reflects the interest coverage portion of letters of credit supporting floating-rate pollution control bonds. The principal amounts of the floating-rate pollution control bonds of $213 million at Generation and $191 million at ComEd are reflected in long-term debt in Exelon’s Consolidated Balance Sheet.

(c)	Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.

(d)	Performance guarantees—Guarantees issued to ensure performance under specific contracts.

(e)	Energy marketing contract guarantees—Guarantees issued to ensure performance under energy commodity contracts.

(f)

Nuclear insurance premiums—Represent the maximum amount that Generation would be required to pay for retrospective premiums in the event of nuclear disaster at any domestic site under the Secondary Financial Protection pool as required under the Price-Anderson Act as well as the current aggregate annual retrospective premium obligation that could be imposed by NEIL. See Nuclear Insurance section within this note for additional details on Generation’s nuclear insurance premiums.

(g)	Lease guarantees—Guarantees issued to ensure payments on building leases.

(h)	2007 City of Chicago Settlement—In December 2007, ComEd entered into an agreement with the City of Chicago. Under the terms of the agreement, ComEd will pay $55 million over six years, of which $8 million, $18 million and $23 million was paid in December 2009, 2008 and 2007, respectively.

(i)

Midwest Generation Capacity Reservation Agreement guarantee—In connection with ComEd’s agreement with the City of Chicago entered into on February 20, 2003, Midwest Generation assumed from the City of Chicago a Capacity Reservation Agreement that the City of Chicago had entered into with Calumet Energy Team, LLC. ComEd has agreed to reimburse the City of Chicago for any nonperformance by Midwest Generation under the Capacity Reservation Agreement.

(j)	See Note 3—Regulatory Issues for additional detail related to Generation’s and ComEd’s rate relief commitments.

Generation’s commercial commitments as of December 31, 2009, representing commitments potentially triggered by future events, were as follows:


	Total		Expiration within
	Total		2010		2011-2012		2013-2014		2015 and beyond
Letters of credit (non-debt) ^(a) (b)	$	172	$	172	$	—	$	—	$	—
Letters of credit (long-term debt)—interest coverage ^(c)		11		11		—		—		—
Surety bonds ^(d)		3		—		—		—		3
Performance guarantees ^(e)		96		—		—		95		1
Energy marketing contract guarantees ^(f)		218		193		25		—		—
Nuclear insurance premiums ^(g)		2,204		—		—		—		2,204
Rate relief commitments—Settlement Legislation ^(h)		24		24		—		—		—

Total commercial commitments	$	2,728	$	400	$	25	$	95	$	2,208

(a)	Letters of credit (non-debt)—Non-debt letters of credit maintained to provide credit support for certain transactions as requested by third parties. Guarantees of $8 million have been issued to provide support for certain letters of credit as required by third parties.

(b)	The amount includes letters of credit that are posted to ComEd related to the 2006 Illinois procurement auction.

(c)

Letters of credit (long-term debt)—interest coverage—Reflects the interest coverage portion of letters of credit supporting floating-rate pollution control bonds. The principal amount of the floating-rate pollution control bonds of $213 million is reflected in long-term debt in Generation’s Consolidated Balance Sheet.

(d)	Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.

(e)	Performance guarantees—Guarantees issued to ensure performance under specific contracts.

(f)	Energy marketing contract guarantees—Guarantees issued to ensure performance under energy commodity contracts.

(g)

(h)	See Note 2—Regulatory Issues for additional detail related to Generation’s rate relief commitments.

ComEd’s commercial commitments as of December 31, 2009, representing commitments potentially triggered by future events, were as follows:


	Total		Expiration within
	Total		2010		2011-2012		2013-2014		2015 and beyond
Letters of credit (non-debt) ^(a)	$	80	$	80	$	—	$	—	$	—
Letters of credit (long-term debt)—interest coverage ^(b)		3		—		3		—		—
2007 City of Chicago Settlement ^(c)		6		3		3		—		—
Midwest Generation Capacity Reservation Agreement guarantee ^(d)		10		4		6		—		—
Surety bonds ^(e)		2		2		—		—		—
Rate relief commitments—Settlement Legislation ^(f)		1		1		—		—		—

Total commercial commitments	$	102	$	90	$	12	$	—	$	—

(a)	Letters of credit (non-debt)—ComEd maintains non-debt letters of credit to provide credit support for certain transactions as requested by third parties.

(b)

Letters of credit (long-term debt)—interest coverage—Reflects the interest coverage portion of letters of credit supporting floating-rate pollution control bonds. The principal amount of the floating-rate pollution control bonds of $191 million is reflected in long-term debt in ComEd’s Consolidated Balance Sheet.

(c)	2007 City of Chicago Settlement—In December 2007, ComEd entered into an agreement with the City of Chicago. Under the terms of the agreement, ComEd will pay $55 million over six years, of which $8 million, $18 million and $23 million was paid in December 2009, 2008 and 2007, respectively.

(d)

(e)	Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.

(f)	See Note 2—Regulatory Issues for additional detail related to ComEd’s rate relief commitments.

PECO’s commercial commitments as of December 31, 2009, representing commitments potentially triggered by future events, were as follows:


	Total		Expiration within
	Total		2010		2011-2012		2013-2014		2015 and beyond
Letters of credit (non-debt) ^(a)	$	39	$	32	$	7	$	—	$	—
Surety bonds ^(b)		3		3		—		—		—

Total commercial commitments	$	42	$	35	$	7	$	—	$	—

(a)	Letters of credit (non-debt)—PECO maintains non-debt letters of credit to provide credit support for certain transactions as requested by third parties.

(b)	Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.

Construction Commitments

Under their operating agreements with PJM, ComEd and PECO are committed to construct transmission facilities. ComEd and PECO will work with PJM to continue to evaluate the scope and timing of any required construction projects. ComEd’s and PECO’s estimated commitments are as follows:


	Total		2010		2011-2012		2013-2014
ComEd	$	91	$	16	$	23	$	52
PECO		105		35		45		25

Leases

Minimum future operating lease payments, including lease payments for vehicles, real estate, computers, rail cars, operating equipment and office equipment, as of December 31, 2009 were:


	Exelon			Generation			ComEd ^(b)		PECO ^(b)
2010	$	67		$	27		$	17	$	15
2011		65			26			16		15
2012		65			26			16		15
2013		58			24			14		14
2014		53			24			12		13
Remaining years		358			298			20		1

Total minimum future lease payments	$	666	^(a)	$	425	^(a)	$	95	$	73

(a)	Excludes Generation’s PPAs and other capacity contracts that are accounted for as contingent operating lease payments.

(b)

Amounts related to certain real estate leases and railroad licenses effectively have indefinite payment periods. As a result, ComEd and PECO have excluded these payments from the Remaining years as such amounts would not be meaningful. ComEd’s and PECO’s annual obligation for these agreements, included in each of the years 2010 – 2014, was $2 million and $2 million, respectively.

The Registrants’ rental expense under operating leases was as follows:


	Exelon		Generation ^(a)		ComEd		PECO
2009	$	691	$	637	$	21	$	27
2008		867		817		23		27
2007		869		819		25		24

(a)

Includes Generation’s PPAs and other capacity contracts that are accounted for as operating leases and are reflected as net capacity purchases in the energy commitments table above. These agreements are considered contingent operating lease payments and are not included in the minimum future operating lease payments table above. Payments made under Generation’s PPAs and other capacity contracts totaled $616 million, $787 million and $785 million during 2009, 2008 and 2007, respectively.

For information regarding capital lease obligations, see Note 9–Debt and Credit Agreements.

Indemnifications Related to Sithe (Exelon and Generation)

On January 31, 2005, subsidiaries of Generation completed a series of transactions that resulted in Generation’s sale of its investment in Sithe. Specifically, subsidiaries of Generation consummated the acquisition of Reservoir Capital Group’s 50% interest in Sithe and subsequently sold 100% of Sithe to Dynegy, Inc. (Dynegy).

In connection with the sale, Generation recorded liabilities related to certain indemnifications provided to Dynegy and other guarantees directly resulting from the transaction. Any activity related to Sithe recorded in Exelon’s Consolidated Statement of Operations is recorded as discontinued operations. During 2008, Generation reduced its guarantee liabilities and recognized $38 million of income in discontinued operations related to the expiration of tax indemnifications. As of December 31, 2009, Generation had $6 million in guarantee liabilities remaining. The estimated maximum possible exposure to Exelon related to the guarantees provided as part of the sales transaction to Dynegy was approximately $200 million at December 31, 2009.

Indemnifications Related to Sale of TEG and TEP (Exelon and Generation)

On February 9, 2007, Tamuin International Inc. (TII), a wholly owned subsidiary of Generation, sold its 49.5% ownership interests in TEG and TEP to a subsidiary of AES Corporation for $95 million in cash plus certain purchase price adjustments. In connection with the transaction, Generation entered into a guarantee agreement under which Generation guarantees the timely payment of TII’s obligations to the subsidiary of AES Corporation pursuant to the terms of the purchase and sale agreement relating to the sale of TII’s ownership interests. Generation would be required to perform in the event that TII does not pay any obligation covered by the guarantee that is not otherwise subject to a dispute resolution process. Generation’s maximum obligation under the guarantee is $95 million. Generation has not recorded a liability associated with this guarantee. The exposures covered by this guarantee expired in part during 2008.

Environmental Issues

General. The Registrants’ operations have in the past and may in the future require substantial expenditures in order to comply with environmental laws. Additionally, under Federal and state environmental laws, the Registrants are generally liable for the costs of remediating environmental contamination of property now or formerly owned by them and of property contaminated by hazardous substances generated by them. The Registrants own or lease a number of real estate parcels, including parcels on which their operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. ComEd and PECO have identified 42 and 27 sites, respectively, where former MGP activities have or may have resulted in actual site contamination. For almost all of these sites, ComEd or PECO is one of several PRPs which may be responsible for ultimate remediation of each location. Of the 42 sites identified by ComEd, the Illinois EPA or U.S. EPA have approved the cleanup of 11 sites and of the 27 sites identified by PECO, the PA DEP has approved the cleanup of 16 sites. Of the remaining sites identified by ComEd and PECO, 24 and 9 sites, respectively, are currently under some degree of active study and/or remediation. ComEd and PECO anticipate that the majority of the remediation at these sites will continue through at least 2015 and 2021, respectively. In addition, the Registrants are currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future.

ComEd and Nicor Gas Company, a subsidiary of Nicor Inc. (Nicor), were parties to an interim agreement under which they cooperated in remediation activities at 38 former MGP sites for which ComEd or Nicor, or both, have responsibility. In January 2008, ComEd and Nicor executed a definitive written agreement on the allocation of costs for the MGP sites, which was approved by the ICC on June 9, 2009. The approval of the settlement by the ICC did not have an impact on ComEd’s cash flows or results of operations. ComEd’s accrual as of December 31, 2009 for these environmental liabilities reflects the cost allocations defined in the agreement. ComEd will continue to pass through to customers these environmental cleanup costs pursuant to a rider approved by the ICC as discussed below.

Based on the final order received from the ICC, ComEd is recovering from customers a provision for environmental costs for the remediation of former MGP facility sites, including those incorporated in the Nicor Settlement, for which ComEd has recorded a regulatory asset. Based on the final order received from the PAPUC, PECO is currently recovering from customers a provision for environmental costs annually for the remediation of former MGP facility sites, for which PECO has recorded a regulatory asset. The gas distribution rate settlement approved in 2008 authorized the recovery, on an annual basis, of $3.5 million for the remediation of PECO’s former MGP sites based on an 8-year estimated remaining duration of PECO’s MGP remediation program. See Note 19—Supplemental Financial Information for additional information regarding regulatory assets and liabilities.

During the third quarter of 2009, ComEd and PECO completed an annual study of their future estimated MGP remediation requirements. The results of these studies indicated that additional remediation would be required at certain sites; accordingly, ComEd and PECO increased their reserves and regulatory assets by $9 million and $2 million, respectively. In January 2010, ComEd was notified by an MGP site owner of its intention to change the planned future use of its site. This change in the planned use of the site is expected to require additional costs for remediation. As a result, ComEd increased its reserve and regulatory asset for its share of the estimated increased remediation costs by an additional $22 million as of December 31, 2009.

As of December 31, 2009 and 2008, the Registrants had accrued the following undiscounted amounts for environmental liabilities in Other Deferred Credits and Other Liabilities within their Consolidated Balance Sheets:


December 31, 2009	Total environmental investigation and remediation reserve		Portion of total related to MGP investigation and remediation
Exelon	$	175	$	149
Generation		17		—
ComEd		113		107
PECO		45		42

December 31, 2008	Total environmental investigation and remediation reserve		Portion of total related to MGP investigation and remediation
Exelon	$	151	$	127
Generation		16		—
ComEd		89		83
PECO		46		44

The Registrants cannot reasonably estimate whether they will incur other significant liabilities for additional investigation and remediation costs at these or additional sites identified by the Registrants, environmental agencies or others, or whether such costs will be recoverable from third parties, including customers.

Section 316(b) of the Clean Water Act. In July 2004, the U.S. EPA issued the final Phase II rule implementing Section 316(b) of the Clean Water Act. The Clean Water Act requires that the cooling water intake structures at electric power plants reflect the best technology available to minimize adverse environmental impacts. The Phase II rule provided each facility with a number of compliance options and permitted site-specific variances based on a cost-benefit analysis. The requirements were intended to be implemented through state-level NPDES permit programs. All of Generation’s power generation facilities with cooling water systems are subject to the regulations. Facilities without closed- cycle recirculating systems (e.g., cooling towers) are potentially most affected. Those facilities are Clinton, Cromby, Dresden, Eddystone, Fairless Hills, Handley, Mountain Creek, Oyster Creek, Peach Bottom, Quad Cities, Salem and Schuylkill. Since promulgation of the rule, Generation has been evaluating compliance options at its affected plants and meeting interim compliance deadlines.

On January 25, 2007, the U.S. Second Circuit Court of Appeals issued its opinion in a challenge to the final Phase II rule. The court found that with respect to a number of significant provisions of the rule the EPA exceeded its authority under the Clean Water Act, failed to adequately set forth its rationale for the rule, or failed to follow required procedures for public notice and comment. The court remanded the rule back to the EPA for revisions consistent with the court’s opinion. By its action, the court invalidated compliance measures which were supported by the utility industry because they were cost-effective and provided existing plants with needed flexibility in selecting the compliance option appropriate to its location and operations. On July 9, 2007, the EPA formally suspended the Phase II rule. Until the EPA finalizes the rule on remand (which could take several years), the state permitting agencies will continue the current practice of applying their best professional judgment to address impingement and entrainment requirements at plant cooling water intake structures.

On April 14, 2008, the U.S. Supreme Court granted a petition filed by the industry parties on the issue of whether Section 316(b) of the Clean Water Act authorizes the EPA to compare costs with benefits in determining the best technology available for minimizing adverse environmental impact at cooling water intake structures. On April 1, 2009, the Supreme Court issued a ruling that the EPA has the discretion to use a cost-benefit analysis under Section 316(b) and reversed the decision of the U.S. Second Circuit Court of Appeals that had invalidated the use of a cost-benefit test. The EPA will now take up consideration of the rule on remand and take further action consistent with the opinions of the Supreme Court and the Court of Appeals, including whether to exercise its discretion to retain or modify the cost-benefit rule as it appeared in the initial regulation. It is expected that the EPA will issue a proposed rule on remand in 2010. The Courts’ opinions have created significant uncertainty about the specific nature, scope and timing of the final compliance requirements.

In a draft permit issued on July 19, 2005, as part of the pending NPDES permit renewal process for Oyster Creek, the NJDEP preliminarily determined that closed-cycle cooling and environmental restoration are the only viable compliance options for Section 316(b) compliance at Oyster Creek. In light of the suspension of the Phase II rule by the EPA, the NJDEP advised Generation that it will issue a new draft permit, and reiterated its preference for cooling towers as the best technology available in the exercise of its best professional judgment. On January 7, 2010, the NJDEP issued a draft NPDES permit for Oyster Creek that would require the installation of cooling towers within seven years after the effective date of the permit. Oyster Creek will continue to operate under its current permit, issued in 1994, until the draft permit is finalized after a period of public comment. Generation believes the public comment period and regulatory process could take up to two years before a final permit is issued. Should the permit be issued in its current form, Generation estimates it would be required to have cooling towers in operation by 2019.

Generation estimates that the cost to retrofit Oyster Creek with closed cycle cooling towers would be approximately $700 million to $800 million. This cost estimate includes construction materials and labor, lost capacity and energy revenue during construction, and other ongoing incremental operating and maintenance costs. Generation believes that these additional costs would call into question the economic viability of operating Oyster Creek until the expiration of its current operating license in 2029, and Generation would close Oyster Creek if either the final Section 316(b) regulations or NJDEP requirements have performance standards that require the installation of cooling towers. Closure of Oyster Creek could result in reliability issues associated with the transmission system. Generation believes the period allowed for compliance will be sufficient to address any transmission reliability issues before operations at Oyster Creek are shut down. If PJM requires the plant to operate under a “reliability-must-run” order, Generation would be allowed full recovery of its costs to operate until the transmission issues are resolved.

In June 2001, the NJDEP issued a renewed NDPES permit for Salem, allowing for the continued operation of Salem with its existing cooling water system. NJDEP advised PSEG in July 2004 that it strongly recommended reducing cooling water intake flow commensurate with closed-cycle cooling as a compliance option for Salem. PSEG submitted an application for a renewal of the permit on February 1, 2006. In the permit renewal application, PSEG analyzed closed-cycle cooling and other options and demonstrated that the continuation of the Estuary Enhancement Program, an extensive environmental restoration program at Salem, is the best technology to meet the Section 316(b) requirements. PSEG continues to operate Salem under the approved June 2001 NDPES permit while the NDPES permit renewal application is being reviewed. If the final permit or Section 316(b) regulations ultimately requires the retrofitting of Salem’s cooling water intake structure to reduce cooling water intake flow commensurate with closed-cycle cooling, Exelon’s and Generation’s share of the total cost of the retrofit and any resulting interim replacement power would likely be in excess of $500 million and could result in increased depreciation expense related to the retrofit investment.

Generation will contest the requirement to install cooling towers throughout the administrative permitting process and is optimistic that any final regulations or permits will not require closed-cycle cooling at Oyster Creek or Salem. In addition, the economic viability of Generation’s other power generation facilities without closed-cycle cooling water systems will be called into question by any requirement to construct cooling towers. Given the uncertainties associated with these proceedings and the time required for their resolution, Generation cannot predict the eventual outcome of the proceedings or estimate the effect that compliance with any resulting Section 316(b) or interim state requirements will have on the operation of its generating facilities and its future results of operations, cash flows and financial position.

Cotter Corporation. The U.S. EPA has advised Cotter Corporation (Cotter), a former ComEd subsidiary, that it is potentially liable in connection with radiological contamination at a site known as the West Lake Landfill in Missouri. On February 18, 2000, ComEd sold Cotter to an unaffiliated third party. As part of the sale, ComEd agreed to indemnify Cotter for any liability incurred by Cotter as a result of any liability arising in connection with the West Lake Landfill. In connection with Exelon’s 2001 corporate restructuring, this responsibility to indemnify Cotter was transferred to Generation. 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. On May 29, 2008, the U.S. EPA issued a Record of Decision approving the remediation option submitted by Cotter and the two other PRPs that required additional landfill cover. The current estimated cost of the anticipated landfill cover remediation for the site is $37 million, which will be allocated among all PRPs. Generation has accrued what it believes to be an adequate amount to cover its anticipated share of such liability. By letter dated January 11, 2010, the EPA requested that the PRPs perform a supplemental feasibility study for a remediation alternative that would involve excavation of the radiological contamination. An excavation remedy would be significantly more expensive than the previously selected additional cover remedy. Generation cannot determine at this time whether the alternative remedy will be required, and if it is, Generation’s share of the cost for such alternative remedy.

Air. On July 11, 2008, the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court) vacated the CAIR, which had been promulgated by the U.S. EPA to reduce power plant emissions of SO₂ and NO_x. The Court later remanded the CAIR to the U.S. EPA, without invalidating the entire rulemaking, so that the U.S. EPA may remedy “CAIR’s flaws” in accordance with the Court’s July 11, 2008 opinion. This decision allows the CAIR to remain in effect until it is replaced by a rule consistent with the Court’s July 11 opinion. The U.S. EPA is expected to issue a new proposed CAIR rulemaking in early 2010.

On March 5, 2009, the D.C. Circuit Court remanded Sierra Club and Environment North Carolina vs. EPA to the U.S. EPA for reconsideration of its denial of North Carolina’s Section 126 petition, originally filed in 2004, that requested that the U.S. EPA impose NO_x and SO₂ emission reduction requirements on various named upwind states (including Illinois and Pennsylvania) whose air emissions North Carolina contended were contributing significantly to nonattainment in North Carolina. The U.S. EPA has agreed to re-visit North Carolina’s Section 126 petition for potential rulemaking and could attempt to address North Carolina’s concerns as part of its CAIR revisions or via a separate rulemaking.

At this time, Exelon is unable to predict the exact approach that will be utilized by the U.S. EPA to revise its CAIR regulation, how long the current CAIR program will remain in effect, or what steps individual states may take in response to the CAIR situation. Due to the uncertainty as to any of the potential outcomes related to CAIR and North Carolina’s Section 126 petition, Exelon cannot estimate the effect of the decision on its operations and its future competitive position, results of operations, earnings, cash flows and financial position.

In March 2005, the U.S. EPA finalized the CAMR, which is a national program to cap mercury emissions from fossil-fired generating units starting in 2010, with a second reduction in the mercury emission cap level scheduled for 2018. The D.C. Circuit Court later vacated the CAMR on the basis that the U.S. EPA had failed to properly de-list mercury as a hazardous air pollutant (HAP) under Section 112(c)(1) of the Clean Air Act. The result of this decision is that mercury emissions from electric generating stations are subject to the more stringent requirements of maximum achievable control technology applicable to hazardous air pollutants. On February 23, 2009, the U.S. Supreme Court declined to review the D.C. Circuit Court’s CAMR decision. The U.S. EPA is now expected to propose a new rulemaking, likely in the first quarter of 2010, to address HAP emissions from electric generation power plants. In addition to regulation at the national level, Exelon had been subject to more stringent mercury regulation enacted in 2006 at the state level in Pennsylvania (PA Mercury Rule). However, on January 30, 2009, the Commonwealth Court of Pennsylvania ruled that the PA Mercury Rule is unlawful and invalid and enjoined the state from continued implementation and enforcement of the rule. On December 23, 2009, the Supreme Court of Pennsylvania upheld the Commonwealth Court decision, and therefore mercury emissions are not regulated by the state. The nature and extent of future regulatory controls on HAP emissions at electric generation power plants will not be determined until the Federal regulations are finalized by the U.S. EPA.

The EPA has announced that it will complete a review of the national ambient air quality standards by the end of 2011 for ozone (nitrogen oxide and volatile organic chemicals), particulate matter, carbon monoxide, nitrogen dioxide, sulfur dioxide, and lead. This review could result in more stringent emissions limits on fossil-fired electric generating stations.

Notices and Finding of Violations Related to Electric Generation Stations. On August 6, 2007, ComEd received an NOV, addressed to it and Midwest Generation, LLC (Midwest Generation) from the U.S. EPA, alleging that ComEd and Midwest Generation have violated and are continuing to violate several provisions of the Federal Clean Air Act as a result of the modification and/or operation of six electric generation stations located in northern Illinois that have been owned and operated by Midwest Generation since 1999. The U.S. EPA requested information related to the stations in 2003, and ComEd has been cooperating with the U.S. EPA since then. The NOV states that the U.S. EPA may issue an order requiring compliance with the relevant Clean Air Act provisions and may seek injunctive relief and/or civil penalties, all pursuant to the U.S. EPA’s enforcement authority under the Clean Air Act.

The generating stations that are the subject of the NOV are currently owned and operated by Midwest Generation, which purchased the stations in December 1999 from ComEd. Under the terms of the sale agreement, Midwest Generation and its affiliate, Edison Mission Energy (EME), assumed responsibility for environmental liabilities associated with the ownership, occupancy, use and operation of the stations, including responsibility for compliance of the stations with environmental laws before the purchase of the stations by Midwest Generation. Midwest Generation and EME additionally agreed to indemnify and hold ComEd and its affiliates harmless from claims, fines, penalties, liabilities and expenses arising from third party claims against ComEd resulting from or arising out of the environmental liabilities assumed by Midwest Generation and EME under the terms of the agreement governing the sale.

In connection with Exelon’s 2001 corporate restructuring, Generation assumed ComEd’s rights and obligations with respect to its former generation business. Exelon, Generation and ComEd are unable to predict the ultimate resolution of the claims alleged in the NOV, the costs that might be incurred or the amount of indemnity that may be available from Midwest Generation and EME; however, Exelon, Generation and ComEd have concluded that a loss is not probable or estimable and accordingly, have not recorded a reserve for the NOV.

On January 14, 2009, Generation received an NOV, addressed to it, the other owners of Keystone Generating Station (Keystone) and Reliant Energy Northeast Management Company (the operator of Keystone) from the U.S. EPA, alleging past and continuing violations of several provisions of the Federal Clean Air Act as a result of the modification and/or operation of Keystone, as well as two other stations currently owned and operated by Reliant Energy in which Generation has no ownership interest. Generation has been cooperating with the U.S. EPA since the time of requests for information in 2000, 2001 and 2007. The NOV states that the U.S. EPA may issue an order requiring compliance with the relevant Clean Air Act provisions and may seek injunctive relief and/or civil penalties, all pursuant to the U.S. EPA’s enforcement authority under the Clean Air Act. At this time, Exelon and Generation are unable to predict the ultimate resolution of the claims alleged in the NOV or the costs that might be incurred by Generation; however, Exelon and Generation have concluded that a loss is not probable or estimable and, accordingly, have not recorded a reserve for the NOV.

On April 16, 2009, the U.S. EPA issued an NOV to ComEd and Dominion Resources Services, Inc. (Dominion) alleging past and continuing violations of several provisions of the Federal Clean Air Act as a result of the modification and/or operation of Kincaid electric generating station located in Illinois and State Line electric generating station located in Indiana. Kincaid was sold by ComEd in 1998 and State Line was sold by Commonwealth Edison of Indiana, a wholly owned subsidiary of ComEd, in 1997. Both stations are currently owned and operated by Dominion. The U.S. EPA requested information related to the stations in 2009, and ComEd has been cooperating with the U.S. EPA since the time of that request. The NOV states that the U.S. EPA may issue an order requiring compliance with the relevant Clean Air Act provisions and may seek injunctive relief and/or civil penalties, all pursuant to the U.S. EPA’s enforcement authority under the Clean Air Act.

Under the terms of the sales agreements for the Kincaid and State Line stations, each party agreed to indemnify the other for certain environmental activities, events, conditions or occurrences arising before and after the purchase of the stations; however, Exelon, Generation, and ComEd are unable at this time to determine how those provisions may apply to any liability or cost that may eventually arise out of the NOV or any resulting enforcement action.

In connection with Exelon’s 2001 corporate restructuring, Generation assumed ComEd’s rights and obligations related to ComEd’s former generation business, which would include any responsibility under the indemnification provisions contained in the sale agreements related to Kincaid and State Line stations. At this time, Exelon, Generation and ComEd are unable to predict the ultimate resolution of the claims alleged in the NOV or the costs that might be incurred by Generation or ComEd; however, Exelon, Generation and ComEd have concluded that a loss is not probable or estimable and, accordingly, have not recorded a reserve for the NOV.

Climate Change Regulation. Exelon is subject to climate change regulation or legislation at the international, Federal, regional and state levels.

International Climate Change Regulation. At the international level, the United States is currently not a party to the Kyoto Protocol, which is a protocol to the United Nations Framework Convention on Climate Change (UNFCCC) and became effective for signatories on February 16, 2005. The United Nations’ Kyoto Protocol process generally requires developed countries to cap GHG emissions at certain levels during the 2008-2012 time period. At the conclusion of the December 2007 United Nations Climate Change Conference in Bali, Indonesia, the Bali Action Plan was adopted, which identifies a work group, process and timeline for the consideration of possible post-2012 international actions to further address climate change. In December 2009, the United States agreed to the non-binding Copenhagen Accord at the conclusion of the 15th Conference of the Parties under the UNFCCC. Under the Copenhagen Accord, the United States agreed to undertake a number of voluntary measures, including the establishment of a goal to reduce GHG emissions and contributions toward a fund to assist developing nations to address their GHG emissions. The next Conference of the Parties is scheduled for Mexico in late 2010.

Federal Climate Change Legislation and Regulation. Various stakeholders, including Exelon, legislators and regulators, shareholders and non-governmental organizations, as well as other companies in many business sectors are considering ways to address the climate change issue. Mandatory programs to reduce GHG emissions are likely to evolve in the future. If these programs become effective, Exelon may incur costs either to further limit or offset the GHG emissions from its operations or procure emission allowances or credits.

Numerous bills have been introduced in Congress that address climate change from different perspectives, including direct regulation of GHG emissions and the establishment of Federal RPS. Exelon supports the enactment, through Federal legislation, of a cap-and-trade program for GHG emissions that is mandatory, economy-wide and designed in a way to limit potential harm to the economy and protect consumers. Exelon believes that any mechanism for allocation of GHG emission allowances should include significant free grants of allowances to electric (and potentially gas) distribution companies to help offset the cost impact of GHG regulation to the end-use consumer. Over the last few years, Exelon has worked with other businesses and environmental organizations that participate in the United States Climate Action Partnership to support the development of an integrated package of recommendations for the Federal government to address the climate change issue through Federal legislation, including aggressive emission reduction targets for total U.S. emissions and robust cost containment measures to ensure that program costs are reasonable.

Federal climate change legislation is currently under consideration in the U.S. Congress. H.R. 2454, “The American Clean Energy and Security Act of 2009,” which Exelon supported, was approved by the U.S. House of Representatives on June 26, 2009 and would affect electric generation and electric and natural gas distribution companies. A key provision of H.R. 2454 is the establishment of mandatory, economy-wide GHG reduction targets and goals via a Federal emissions cap-and-trade program. The program would begin in 2012 and calls for a three percent reduction below 2005 levels in 2012, with the reduction requirement increasing to 17% below 2005 levels by 2020 and ultimately 83% below 2005 levels by 2050. The legislation also contains several energy efficiency and clean energy requirements. Of particular note for electric retail supply companies, there is a proposed requirement that 20% of electricity sold by retail suppliers be met by energy efficiency and renewable energy by 2020. The requirement begins to phase-in starting in 2012 at a six percent level and escalates every two years until it reaches 20% in 2020. On September 30, 2009, S. 1733, the Clean Energy Jobs and American Power Act, was introduced in the U.S. Senate. S.1733 sets forth a cap-and-trade program and contains other provisions to regulate GHGs that are similar to those contained in H.R. 2454, but does not yet provide the specific details regarding the allocation of allowances. It is uncertain when the Senate will take up consideration of S. 1733.

In 2007, the U.S. Supreme Court ruled that GHG emissions are pollutants subject to regulation under the new motor vehicle provisions of the Clean Air Act. In response to the decision, on July 11, 2008, the U.S. EPA issued an Advance Notice of Proposed Rulemaking to solicit public comments on legal and regulatory analyses and policy alternatives regarding GHG effects and regulation under the Clean Air Act. On December 7, 2009, the U.S. EPA issued an endangerment finding under Section 202 of the Clean Air Act regarding GHGs from new motor vehicles and is expected to finalize regulations in March 2010. While such regulations would not specifically address stationary sources, such as a generating plant, it is the U.S. EPA’s position that the regulation of GHGs under the mobile source provisions of the Clean Air Act will trigger permitting requirements for stationary sources. Therefore, on September 30, 2009, the U.S. EPA issued proposed regulations for permitting for large stationary sources (greater than 25,000 tons per year of GHG emissions, on a CO₂ equivalent basis). Under the proposal, large stationary sources could be required to install Best Available Control Technology, to be determined on a case-by-case basis.

The issue of GHG regulation of stationary sources will likely be addressed either under the existing provisions of the Clean Air Act by U.S. EPA regulation, or by new and comprehensive Federal legislation. The Obama administration and the U.S. EPA have stated a preference for addressing the issue through Federal legislation. The extent to which GHG emissions will be regulated is currently unknown; however, potential regulation of GHG emissions from stationary sources could cause Exelon to incur material costs of compliance.

Pursuant to U.S. EPA regulations that will impose limits on certain future emissions by generation stations, the co-owners of the Keystone generating station formally approved on June 30, 2006 a capital plan to install SO₂ scrubbers at the station. The Keystone SO₂ scrubbers for Unit 1 and Unit 2 were placed in service September 25, 2009 and November 30, 2009, respectively. For the years ended December 31, 2009, 2008 and 2007, total costs incurred, including capitalized interest, were $48 million, $71 million and $27 million, respectively. Exelon anticipates spending approximately $2 million in 2010 related to this project.

Regional and State Climate Change Legislation and Regulation. At a regional level, on November 15, 2007, six Midwest state Governors (Illinois, Iowa, Kansas, Michigan, Minnesota, Wisconsin) signed the Midwestern Greenhouse Gas Accord (the Accord). Under the Accord, an inter-state work group was formed to establish a Midwestern GHG Reduction Program that will: (1) establish GHG reduction targets and timeframes consistent with member state targets; (2) develop a market-based and multi-sector cap-and-trade program to help achieve GHG reductions; and (3) develop other mechanisms and policies to assist in meeting GHG reduction targets (e.g. a low carbon fuel standard). In October 2009, the Governors decided to defer action on the regional GHG reduction initiatives pending resolution of federal legislation.

At the state level, the PCCA was signed into law in July 2008. The PCCA requires, among other things, that a Climate Change Advisory Committee be formed, that a report on the potential impact of climate change in Pennsylvania be developed, that the PA DEP develop a GHG inventory for Pennsylvania, that a voluntary GHG registry be identified, and that the PA DEP, in consultation with the Climate Change Advisory Committee, develop a Climate Change Action Plan for Pennsylvania to be reviewed with the Pennsylvania General Assembly. The Climate Change Advisory Committee issued its recommendations for an Action Plan on October 9, 2009 and they are currently being considered by the Pennsylvania legislature.

At this time, Exelon is unable to estimate the potential impacts of any future mandatory GHG legal or regulatory requirements on its businesses.

Litigation and Regulatory Matters

Exelon and Generation

Real Estate Tax Appeals. On January 19, 2010, Generation appealed the real estate tax assessment for the 2009 tax year concerning the value of its LaSalle Generating Station (LaSalle County, Illinois). The ultimate outcome of this matter is uncertain and could result in unfavorable or favorable impacts to the consolidated financial statements of Exelon and Generation. Generation has recorded the assessed real estate tax as of December 31, 2009.

Exelon and Generation

Asbestos Personal Injury Claims. Generation maintains a reserve for claims associated with asbestos-related personal injury actions in certain facilities that are currently owned by Generation or were previously owned by ComEd and PECO. The reserve is recorded on an undiscounted basis and excludes the estimated legal costs associated with handling these matters, which could be material. In the second quarter of 2008, Generation revised the period through which it estimates that claims will be presented from 2030 to 2050.

At December 31, 2009 and 2008, Generation had reserved approximately $49 million and $52 million, respectively, in total for asbestos-related bodily injury claims. As of December 31, 2009, approximately $13 million of this amount related to 147 open claims presented to Generation, while the remaining $36 million of the reserve is for estimated future asbestos-related bodily injury claims anticipated to arise through 2050 based on actuarial assumptions and analysis, which are updated on an annual basis. On a quarterly basis, Generation monitors actual experience against the number of forecasted claims to be received and expected claim payments and evaluates whether an adjustment to the reserve is necessary. During 2009, 2008 and 2007, the updates to this reserve, including the extension of future claims to be considered from 2030 to 2050, did not result in a material adjustment.

Exelon

Pension Claims. On July 11, 2006, a former employee of ComEd filed a purported class action lawsuit against the Exelon Corporation Cash Balance Pension Plan (Plan) in the Federal District Court for the Northern District of Illinois. The complaint alleges that the Plan, which covers certain management employees of Exelon’s subsidiaries, calculated lump sum distributions in a manner that does not comply with the ERISA. The plaintiff seeks compensatory relief from the Plan on behalf of participants who received lump sum distributions between 2001 and 2006 and injunctive relief with respect to future lump sum distributions. The District Court dismissed the lawsuit but allowed the plaintiff to file an administrative claim with the Plan with respect to the calculation of the portion of his lump sum benefit accrued under the Plan’s prior traditional formula. On July 2, 2009, the U.S. Court of Appeals for the Seventh Circuit affirmed the District Court’s ruling, and the plaintiff’s subsequent motion requesting rehearing of the case before the entire Seventh Circuit Court of Appeals was denied. On October 28, 2009, the plaintiff filed a petition requesting that the United States Supreme Court hear an appeal of the Seventh Circuit’s decision. In addition, on January 6, 2009, the plaintiff filed a complaint in the District Court challenging the Plan’s denial of his administrative claim, and on November 12, 2009 the Plan responded by filing a motion for summary judgment. The ultimate outcomes of these claims are uncertain and may have a material impact on Exelon’s results of operations, cash flows or financial position.

Savings Plan Claim. On September 11, 2006, five individuals claiming to be participants in the Exelon Corporation Employee Savings Plan, Plan #003 (Savings Plan), filed a putative class action lawsuit in the United States District Court for the Northern District of Illinois. The complaint names as defendants Exelon, its Director of Employee Benefit Plans and Programs, the Employee Savings Plan Investment Committee, the Compensation and the Risk Oversight Committees of Exelon’s Board of Directors and members of those committees. The complaint alleged that the defendants breached fiduciary duties under ERISA by, among other things, permitting fees and expenses to be incurred by the Savings Plan that allegedly were unreasonable and for purposes other than to benefit the Savings Plan and participants, and failing to disclose purported “revenue sharing” arrangements among the Savings Plan’s service providers. The plaintiffs sought declaratory, equitable and monetary relief on behalf of the Savings Plan and participants, including alleged investment losses. On August 19, 2009, the plaintiffs in the Exelon case filed an amended complaint in the District Court, which again alleged that defendants breached fiduciary duties under ERISA by, among other things, permitting the Savings Plan to pay excessive fees and expenses for administrative services, but eliminated the claim for investment losses and the allegations regarding “revenue sharing.” On December 9, 2009, the District Court granted the defendants’ motion to dismiss the amended complaint and enter judgment in favor of the defendants. The plaintiffs have filed a notice of their intent to appeal the District Court’s dismissal of their claims to the U.S. Court of Appeals for the Seventh Circuit. The ultimate outcome of the savings plan claim is uncertain and may have a material impact on Exelon’s results of operations, cash flows or financial position.

Retiree Healthcare Benefits Grievance. In 2006, IBEW Local 15 filed a demand for arbitration of a grievance challenging certain changes implemented in 2004 to the healthcare coverage provided to retirees who were members of IBEW Local 15 during their employment with Exelon, Generation and ComEd. Exelon then filed a lawsuit in the U.S. District Court for the Northern District of Illinois seeking a judicial determination that this grievance is not arbitrable because disputes regarding benefits provided to current retirees are not within the scope of the collective bargaining agreement. On December 3, 2007, the District Court ruled that, under the terms of the parties’ collective bargaining agreement, IBEW Local 15 could use the collective bargaining agreement’s grievance and arbitration procedure to challenge these changes with respect to retirees named in the grievance. On September 8, 2008, the U.S. Court of Appeals for the Seventh Circuit affirmed the decision of the District Court. A settlement agreement was reached between Exelon and IBEW Local 15 on February 19, 2009 that included certain prospective changes to the healthcare benefits provided to retirees who were members of IBEW Local 15 during their Exelon employment. These changes become effective at various times between May 1, 2009 and January 1, 2013 and resulted in withdrawal of the grievance. The settlement agreement will be treated as a plan amendment in the related welfare plan and reflected in the plan’s next measurement. The settlement agreement will not have a material impact on Exelon’s, Generation’s or ComEd’s results of operations, cash flows or financial position.

Exelon and ComEd

Reliability. On July 18, 2008, ComEd self-reported to ReliabilityFirst Corporation (RFC), its Regional Entity, that it failed to maintain vegetation clearance on a section of a transmission line, constituting a violation of a NERC reliability standard. ComEd is subject to potential fines for a violation of NERC reliability standards. ComEd and RFC reached a settlement for an immaterial amount. NERC approved the settlement agreement, and on October 23, 2009 FERC issued a Notice that it would not review the matter.

Fund Transfer Restrictions

Under applicable law, Exelon may borrow or receive any extension of credit or indemnity from its subsidiaries. Under the terms of Exelon’s intercompany money pool agreement, Exelon can lend to, but not borrow from the money pool.

The Federal Power Act declares it to be unlawful for any officer or director of any public utility “to participate in the making or paying of any dividends of such public utility from any funds properly included in capital account.” What constitutes “funds properly included in capital account” is undefined in the Federal Power Act or the related regulations; however, FERC has consistently interpreted the provision to allow dividends to be paid as long as (1) the source of the dividends is clearly disclosed, (2) the dividend is not excessive and (3) there is no self-dealing on the part of corporate officials. While these restrictions may limit the absolute amount of dividends that a particular subsidiary may pay, Exelon does not believe these limitations are materially limiting because, under these limitations, the subsidiaries are allowed to pay dividends sufficient to meet Exelon’s actual cash needs.

Under Illinois law, ComEd may not pay any dividend on its stock unless, among other things, “[its] earnings and earned surplus are sufficient to declare and pay same after provision is made for reasonable and proper reserves,” or unless it has specific authorization from the ICC. ComEd has also agreed in connection with financings arranged through ComEd Financing III that it will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debt securities issued to ComEd Financing III; (2) it defaults on its guarantee of the payment of distributions on the preferred trust securities of ComEd Financing III; or (3) an event of default occurs under the Indenture under which the subordinated debt securities are issued.

PECO’s Articles of Incorporation prohibit payment of any dividend on, or other distribution to the holders of, common stock if, after giving effect thereto, the capital of PECO represented by its common stock together with its retained earnings is, in the aggregate, less than the involuntary liquidating value of its then outstanding preferred securities. At December 31, 2009, such capital was $2.7 billion and amounted to about 31 times the liquidating value of the outstanding preferred securities of $87 million. Additionally, PECO may not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debentures which were issued to PEC L.P. or PECO Trust IV; (2) it defaults on its guarantee of the payment of distributions on the Series D Preferred Securities of PEC L.P. or the preferred trust securities of PECO Trust IV; or (3) an event of default occurs under the Indenture under which the subordinated debentures are issued.

Agreement Related to Sale of Accounts Receivable

PECO is party to an agreement with a financial institution under which it sold an undivided interest, adjusted daily, in up to $225 million of designated accounts receivable, which PECO accounted for as a sale as of December 31, 2009. Under new guidance effective January 1, 2010, this agreement will be accounted for as a secured borrowing. See Note 1—Significant Accounting Policies for additional information. PECO retains the servicing responsibility for the sold receivables and has recorded a servicing liability. The agreement terminates on September 16, 2010 unless extended in accordance with its terms. As of December 31, 2009, PECO is in compliance with the requirements of the agreement. In the event the agreement is not extended, PECO has sufficient short-term liquidity and will seek alternate financing. See Note 7—Fair Value of Financial Assets and Liabilities for additional information regarding the servicing liability.

Income Taxes

See Note 10—Income Taxes for information regarding the Registrants’ income tax refund claims and certain tax positions, including the 1999 sale of fossil generating assets.

Supplemental Financial Information (Exelon, Generation, ComEd and PECO)

12 Months Ended

Dec. 31, 2009

Statement [Line Items]

Supplemental Financial Information (Exelon, Generation, ComEd and PECO)

19. Supplemental Financial Information (Exelon, Generation, ComEd and PECO)

Supplemental Income Statement Information

The following tables provide additional information about the Registrants’ Consolidated Statements of Operations for the years ended December 31, 2009, 2008 and 2007.


For the Year Ended December 31, 2009	Exelon		Generation			ComEd		PECO
Operating revenues ^(a)
Wholesale	$	5,469	$	8,905		$	—	$	26
Retail electric and gas		11,099		838	^(b)		5,220		5,049
Other		750		(40	)^(c)		554		236

Total operating revenues	$	17,318	$	9,703		$	5,774	$	5,311


For the Year Ended December 31, 2008	Exelon		Generation			ComEd		PECO
Operating revenues ^(a)
Wholesale	$	6,394	$	9,934		$	—	$	45
Retail electric and gas		11,816		979	^(b)		5,563		5,278
Other		649		(159	)^(c)		573		244

Total operating revenues	$	18,859	$	10,754		$	6,136	$	5,567


For the Year Ended December 31, 2007	Exelon		Generation			ComEd		PECO
Operating revenues ^(a)
Wholesale	$	6,550	$	9,970		$	58	$	61
Retail electric and gas		11,750		909	^(b)		5,543		5,300
Other		616		(130	)^(c)^(d)		503		252

Total operating revenues	$	18,916	$	10,749		$	6,104	$	5,613

(a)	Includes operating revenues from affiliates.

(b)	Generation’s retail electric and gas operating revenues consist solely of Exelon Energy Company, LLC.

(c)	Includes amounts recorded related to the Illinois Settlement.

(d)	Includes income associated with the termination of Generation’s PPA with State Line.


For the Year Ended December 31, 2009	Exelon		Generation		ComEd		PECO
Depreciation, amortization and accretion
Property, plant and equipment	$	996	$	333	$	446	$	162
Regulatory assets ^(a)		838		—		48		790
Nuclear fuel ^(b)		558		558		—		—
ARO accretion ^(c)		209		207		1		—

Total depreciation, amortization and accretion	$	2,601	$	1,098	$	495	$	952


For the Year Ended December 31, 2008	Exelon		Generation		ComEd		PECO
Depreciation, amortization and accretion
Property, plant and equipment	$	898	$	274	$	424	$	158
Regulatory assets ^(a)		736		—		40		696
Nuclear fuel ^(b)		448		448		—		—
ARO accretion ^(c)		226		225		1		—

Total depreciation, amortization and accretion	$	2,308	$	947	$	465	$	854


For the Year Ended December 31, 2007	Exelon		Generation		ComEd		PECO
Depreciation, amortization and accretion
Property, plant and equipment	$	856	$	266	$	400	$	149
Regulatory assets ^(a)		664		—		40		624
Nuclear fuel ^(b)		431		431		—		—
ARO accretion ^(c)		232		231		1		—

Total depreciation, amortization and accretion	$	2,183	$	928	$	441	$	773

(a)	For PECO, reflects CTC amortization.

(b)	Included in fuel expense on the Registrants’ Consolidated Statements of Operations.

(c)	Included in operating and maintenance expense on the Registrants’ Consolidated Statements of Operations.


	Exelon and ComEd
	For the Year Ended December 31,
(In Millions)	2009		2008
Operating and maintenance for regulatory required programs ^(a)
Energy efficiency and demand response programs ^(b)	$	59	$	25
Purchased power administrative costs		4		3

Total operating and maintenance for regulatory required programs	$	63	$	28

(a)	Costs for various legislative and/or regulatory programs are recoverable from customers on a full and current basis through a reconcilable automatic adjustment clause for Exelon and ComEd. An equal and offsetting amount has been reflected in operating revenues during the period.

(b)	As a result of the Illinois Settlement, utilities are required to provide energy efficiency and demand response programs beginning June 1, 2008. See Note 2 —Regulatory Issues for additional information.


For the Year Ended December 31, 2009	Exelon		Generation		ComEd		PECO
Taxes other than income
Utility ^(a)	$	481	$	—	$	232	$	249
Real estate		157		127		20		10
Payroll		114		65		23		12
Other		26		13		6		5

Total taxes other than income	$	778	$	205	$	281	$	276


For the Year Ended December 31, 2008	Exelon		Generation		ComEd		PECO
Taxes other than income
Utility ^(a)	$	507	$	—	$	236	$	271
Real estate ^(b)		127		124		29		(26	)
Payroll		123		67		26		12
Other		21		6		7		8

Total taxes other than income	$	778	$	197	$	298	$	265


For the Year Ended December 31, 2007	Exelon		Generation		ComEd		PECO
Taxes other than income
Utility ^(a)	$	527	$	—	$	258	$	269
Real estate ^(c)		139		117		26		(4	)
Payroll		108		57		23		11
Other		23		11		7		4

Total taxes other than income	$	797	$	185	$	314	$	280

(a)	Municipal and state utility taxes are also recorded in revenues on the Registrants’ Consolidated Statements of Operations.

(b)	PECO reflected amortization of the regulatory liability recorded in connection with the 2007 PURTA settlement, partially offset by current year property taxes.

(c)	PECO reflected a $17 million reduction of a reserve related to the PURTA tax settlement, partially offset by current year property taxes.


For the Year Ended December 31, 2009	Exelon			Generation			ComEd			PECO
Loss in equity method investments
Financing trusts	$	(24	)	$	—		$	—		$	(24	)
NuStart Energy Development, LLC		(3	)		(3	)		—			—

Total loss in equity method investments	$	(27	)	$	(3	)	$	—		$	(24	)


For the Year Ended December 31, 2008	Exelon			Generation			ComEd			PECO
Loss in equity method investments
Financing trusts	$	(25	)	$	—		$	(8	)	$	(16	)
NuStart Energy Development, LLC		(1	)		(1	)		—			—

Total loss in equity method investments	$	(26	)	$	(1	)	$	(8	)	$	(16	)


For the Year Ended December 31, 2007	Exelon			Generation			ComEd			PECO
Income (loss) in equity method investments
Financing trusts	$	(14	)	$	—		$	(7	)	$	(7	)
TEG and TEP ^(a)		3			3			—			—
Synthetic fuel-producing facilities		(93	)		—			—			—
NuStart Energy Development, LLC		(2	)		(2	)		—			—

Total loss in equity method investments	$	(106	)	$	1		$	(7	)	$	(7	)

(a)	On February 9, 2007, Generation sold its ownership interests in TEG and TEP.


For the Year Ended December 31, 2009	Exelon			Generation			ComEd			PECO
Other, Net
Decommissioning-related activities:
Net realized income on decommissioning trust funds—Regulatory Agreement Units ^(a)	$	126		$	126		$	—		$	—
Net realized income on decommissioning trust funds—Non-Regulatory Agreement Units ^(a)		29			29			—			—
Net unrealized gains on decommissioning trust funds—Regulatory Agreement Units		801			801			—			—
Net unrealized gains on decommissioning trust funds—Non-Regulatory Agreement Units		227			227			—			—
Regulatory offset to decommissioning trust fund-related activities ^(b)		(746	)		(746	)		—			—

Total decommissioning-related activities		437			437			—			—

Investment income		5			—			1			4
Net direct financing lease income		26			—			—			—
Interest income related to uncertain income tax positions ^(c)		50			—			65			5
Realized gains on Rabbi trust investments		5			—			5			—
Other-than-temporary impairment to Rabbi trust investments ^(d)		(7	)		—			(7	)		—
Losses on early retirement of debt		(117	)		(71	)		—			—
Other		27			10			15			4

Other, net	$	426		$	376		$	79		$	13


For the Year Ended December 31, 2008	Exelon			Generation			ComEd		PECO
Other, Net
Decommissioning-related activities:
Net realized income on decommissioning trust funds—Regulatory Agreement Units ^(a)	$	43		$	43		$	—	$	—
Net realized income on decommissioning trust funds—Non-Regulatory Agreement Units ^(a)		16			16			—		—
Net unrealized losses on decommissioning trust funds—Regulatory Agreement Units		(1,022	)		(1,022	)		—		—
Net unrealized losses on decommissioning trust funds—Non-Regulatory Agreement Units		(324	)		(324	)		—		—
Regulatory offset to decommissioning trust fund-related activities ^(b)		777			777			—		—

Total decommissioning-related activities		(510	)		(510	)		—		—

Investment income		10			—			6		4
Net direct financing lease income		24			—			—		—
Interest income related to uncertain income tax positions		31			11			6		12
Income related to the termination of a gas supply guarantee		13			13			—		—
Other		25			17			6		2

Other, net	$	(407	)	$	(469	)	$	18	$	18


For the Year Ended December 31, 2007	Exelon			Generation			ComEd		PECO
Other, Net
Decommissioning-related activities:
Net realized income on decommissioning trust funds—Regulatory Agreement Units ^(a)	$	387		$	387		$	—	$	—
Net realized income on decommissioning trust funds—Non-Regulatory Agreement Units ^(a)		120			120			—		—
Other-than-temporary impairment on decommissioning trust funds—Regulatory Agreement Units ^(e)		(83	)		(83	)		—		—
Other-than-temporary impairment on decommissioning trust funds—Non-Regulatory Agreement Units ^(e)		(9	)		(9	)		—		—
Regulatory offset to decommissioning trust fund-related activities ^(b)		(300	)		(300	)		—		—

Total decommissioning-related activities		115			115			—		—

Investment income		10			—			6		4
Gain on disposition of assets and investments, net		23			18			3		2
Net direct financing lease income		24			—			—		—
Recovery of tax credits related to Exelon’s investments in synthetic fuel-producing facilities		178			—			—		—
Interest income related to settlement of PJM billing dispute		5			4			—		1
Interest income related to uncertain income tax positions		61			—			41		20
Interest income related to PURTA tax appeal^(f)		17			—			—		17
Other		27			18			8		1

Other, net	$	460		$	155		$	58	$	45

(a)	Includes investment income and realized gains and losses on sales of investments of the trust funds.

(b)

Includes the elimination of decommissioning trust fund-related activity for the Regulatory Agreement Units, which are subject to regulatory accounting, including the elimination of net realized income, other-than-temporary impairments and related income taxes. See Notes 7—Fair Value of Financial Assets and Liabilities and 11—Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning.

(c)	Primarily includes interest income at ComEd from the 2009 remeasurement of income tax uncertainties. See Note 10—Income Taxes for information regarding the Registrants’ tax positions.

(d)	ComEd recorded an other-than-temporary impairment to Rabbi trust investments during the second quarter of 2009. See Note 7—Fair Value of Assets and Liabilities for additional information regarding the impairment.

(e)	Includes net unrealized losses of the trust funds.

(f)	On March 27, 2007, PECO prevailed in a Pennsylvania Supreme Court case in which PECO had contested the assessment of PURTA taxes applicable to 1997. As a result, during the third quarter of 2007, PECO recognized approximately $17 million of interest income associated with this matter.

Supplemental Cash Flow Information

The following tables provide additional information regarding the Registrants’ Consolidated Statements of Cash Flows for the years ended December 31, 2009, 2008 and 2007.


For the Year Ended December 31, 2009	Exelon			Generation			ComEd			PECO
Cash paid (refunded) during the year
Interest (net of amount capitalized)	$	740		$	94		$	305		$	216
Income taxes (net of refunds)		982			668			63			368
Other non-cash operating activities:
Pension and non-pension postretirement benefits costs	$	536		$	240		$	192		$	47
Equity in losses of unconsolidated affiliates and investments		27			3			—			24
Provision for uncollectible accounts		149			2			85			63
Stock-based compensation costs		70			—			—			—
Other decommissioning-related activity ^(a)		(163	)		(163	)		—			—
Energy-related options ^(b)		46			46			—			—
ARO reduction ^(c)		(47	)		(47	)		—			—
Amortization of regulatory asset related to debt costs		25			—			21			4
Amortization of the regulatory liability related to the PURTA tax settlement ^(d)		(2	)		—			—			(2	)
Other-than-temporary impairment to Rabbi trust investments ^(e)		7			—			7			—
Inventory write-down related to plant retirements		17			17			—			—
Other		(13	)		6			4			5

Total other non-cash operating activities	$	652		$	104		$	309		$	141

Changes in other assets and liabilities:
Under/over-recovered energy and transmission costs		23			—			13			10
Other current assets		(2	)		—			—			3	^(g)
Other noncurrent assets and liabilities		(134	)		(1	)		(75	)^(f)		(47	)

Total changes in other assets and liabilities	$	(113	)	$	(1	)	$	(62	)	$	(34	)


	Exelon		Generation		ComEd		PECO
Non-cash investing and financing activities
Change in ARC	$	67	$	67	$	—	$	—
Capital expenditures not paid		70		97		37		4
Purchase accounting adjustments		9		9		—		—

(a)

Includes the elimination of decommissioning-related activity for the Regulatory Agreement Units, which are subject to regulatory accounting, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income and income taxes related to all trust fund activity. See Note 11—Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning.

(b)	Reclassification of energy-related option premiums to realized at settlement of contracts recorded in results of operations due to the settlement of the underlying transaction.

(c)	Represents the reduction in the ARO in excess of the existing ARC balances for Generation’s nuclear generating units that are not subject to regulatory agreement with respect to decommissioning trust funding (the former AmerGen units and the portions of the Peach Bottom units).

(d)

In March 2007, PECO prevailed in a Pennsylvania Supreme Court case in which PECO had contested the assessment of PURTA taxes applicable to 1997. As a result, PECO received approximately $38 million of real estate taxes previously remitted. This refund was recorded as a regulatory liability. PECO began amortizing this regulatory liability and refunding the amount to customers in January 2008. The regulatory liability associated with the PURTA settlement was fully amortized in January 2009.

(e)	ComEd recorded an other-than-temporary impairment to Rabbi trust investments during the second quarter of 2009. See Note 7—Fair Value of Assets and Liabilities for additional information regarding the impairment.

(f)	Relates primarily to a decrease in interest payable associated with the remeasurement of uncertain income tax positions. See Note 10—Income Taxes for additional information.

(g)	Relates primarily to prepaid utility taxes.


For the Year Ended December 31, 2008	Exelon			Generation			ComEd			PECO
Cash paid (refunded) during the year
Interest (net of amount capitalized)	$	716		$	107		$	300		$	216
Income taxes (net of refunds)		938			660			(41	)		379
Other non-cash operating activities:
Pension and non-pension postretirement benefits costs	$	314		$	139		$	101		$	32
Equity in losses of unconsolidated affiliates and investments		26			1			8			16
Provision for uncollectible accounts		247			17			71			160
Stock-based compensation costs		67			—			—			—
Other decommissioning-related activity ^(a)		219			219			—			—
Energy-related options		5			5			—			—
Amortization of regulatory asset related to debt costs		25			—			21			4
Amortization of the regulatory liability related to the PURTA tax settlement ^(b)		(36	)		—			—			(36	)
Net impact of the 2007 distribution rate case order ^(c)		22			—			22			—
Reduction of guarantees ^(d)		(55	)		(55	)		—			—
Other		36			6			41			18

Total other non-cash operating activities	$	870		$	332		$	264		$	194

Changes in other assets and liabilities:
Deferred/over-recovered energy costs	$	32		$	—		$	29		$	3
Other current assets		12			(11	)		14			(3	)^(e)
Other noncurrent assets and liabilities		(179	)		(70	)		(20	)		(14	)

Total changes in other assets and liabilities	$	(135	)	$	(81	)	$	23		$	(14	)


	Exelon		Generation		ComEd		PECO
Non-cash investing and financing activities
Change in ARC	$	128	$	128	$	—	$	—
Capital expenditures not paid		23		6		4		6
Capitalized employee incentives		4		—		3		1
Purchase accounting adjustments		10		10		—		—

(a)

Includes the elimination of decommissioning-related activity for the Regulatory Agreement Units, which are subject to regulatory accounting, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income and income taxes related to all trust fund activity. See Note 11-Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning.

(b)

In March 2007, PECO prevailed in a Pennsylvania Supreme Court case in which PECO had contested the assessment of PURTA taxes applicable to 1997. As a result, PECO received approximately $38 million of real estate taxes previously remitted. This refund was recorded as a regulatory liability and PECO began amortizing this liability and refunding customers in January 2008.

(c)

In September 2008, as a result of the 2007 Rate Case order, ComEd recorded $37 million of fixed asset disallowances; $35 million was recorded as operating and maintenance expense and $2 million was recorded as depreciation expense. In addition, ComEd established regulatory assets totaling approximately $13 million associated with reversing previously incurred expenses deemed recoverable in future rates. See Note 2—Regulatory Issues for more information.

(d)	Includes reversal of Sithe guarantee of $38 million and Distrigas guarantee of $13 million.

(e)	Relates primarily to prepaid utility taxes.


For the Year Ended December 31, 2007	Exelon			Generation			ComEd			PECO
Cash paid during the year
Interest (net of amount capitalized)	$	879		$	96		$	267		$	243
Income taxes (net of refunds)		1,298			1,174			93			456
Other non-cash operating activities:
Pension and non-pension postretirement benefits costs	$	320		$	142		$	101		$	32
Provision for uncollectible accounts		132			4			58			71
Equity in losses (gains) of unconsolidated affiliates		106			(1	)		7			7
Other decommissioning-related activity ^(a)		(75	)		(75	)		—			—
Energy-related options ^(b)		133			133			—			—
Gain on sale of investments, net		(18	)		(18	)		—			—
Loss on execution of sub-lease		72			72			—			—
Other		64			(1	)		40			(24	)

Total other non-cash operating activities	$	734		$	256		$	206		$	86

Changes in other assets and liabilities:
Under/over-recovered energy and transmission costs	$	(91	)		—		$	(97	)	$	6
Other current assets		(27	)		(7	)		(5	)		—
Other noncurrent assets and liabilities		(4	)		47			(17	)		(26	)

Total changes in other assets and liabilities	$	(122	)	$	40		$	(119	)	$	(20	)


	Exelon		Generation		ComEd		PECO
Non-cash investing and financing activities
Change in ARC	$	60	$	60	$	—	$	—
Declaration of dividend not paid as of December 31, 2007		331		—		—		—
Purchase accounting adjustments		11		11		—		—
Resolution of certain tax matters ^(c)		69		—		69		—
ComEd Transitional Funding Trust ^(d)(e)		25		—		25		—
Capital expenditures not paid		29		7		13		9

(a)

(b)	Reclassification of energy-related option premiums to realized at settlement of contracts recorded in results of operations due to the settlement of the underlying transaction.

(c)	Includes amounts recorded to goodwill resulting from the resolution of certain tax matters and the impact of adopting the current authoritative guidance for accounting for uncertain tax positions.

(d)	Amount includes $17 million previously reflected in prepaid interest. This amount did not impact ComEd’s Consolidated Statements of Operations or ComEd’s Consolidated Statements of Cash Flows.

(e)	ComEd applied $8 million of previously prepaid balances against the long-term debt to ComEd Transitional Funding Trust

Supplemental Balance Sheet Information

The following tables provide additional information about assets and liabilities of the Registrants as of December 31, 2009 and 2008.


December 31, 2009	Exelon		Generation		ComEd		PECO
Investments
Equity method investments:
Financing trusts ^(a)	$	20	$	—	$	6	$	13
Keystone Fuels, LLC		15		15		—		—
Conemaugh Fuels, LLC		19		19		—		—
NuStart Energy Development, LLC		1		1		—		—

Total equity method investments		55		35		6		13

Other investments:
Net investment in direct financing leases		602		—		—		—
Employee benefit trusts and investments ^(b)		67		11		28		18

Total investments	$	724	$	46	$	34	$	31

(a)	Includes investments in financing trusts which were not consolidated within the financial statements of Exelon. Investments in financing trusts were recorded in Other noncurrent assets on ComEd’s Consolidated Balance Sheets. See Note 1—Significant Accounting Policies for additional information.

(b)	The Registrants’ investments in these marketable securities are recorded at fair market value.


December 31, 2008	Exelon		Generation		ComEd		PECO
Investments
Equity method investments:
Financing trusts ^(a)	$	45	$	—	$	6	$	39
Keystone Fuels, LLC		8		8		—		—
Conemaugh Fuels, LLC		14		14		—		—
NuStart Energy Development, LLC		2		2		—		—

Total equity method investments		69		24		6		39

Other investments:
Net investment in direct financing leases		577		—		—		—
Employee benefit trusts and investments ^(b)		69		9		34		15

Total investments	$	715	$	33	$	40	$	54

(a)

Includes investments in financing trusts which were not consolidated within the financial statements of Exelon at December 31, 2008. Investments in financing trusts were recorded in Other noncurrent assets on ComEd’s Consolidated Balance Sheets. See Note 1—Significant Accounting Policies for additional information.

(b)	The Registrants’ investments in these marketable securities are recorded at fair market value.

Like-Kind Exchange Transaction (Exelon). Prior to the PECO/Unicom Merger in October 2000, UII, LLC (formerly Unicom Investments, Inc.) (UII), a wholly owned subsidiary of Exelon, entered into a like-kind exchange transaction pursuant to which approximately $1.6 billion was invested in passive generating station leases with two separate entities unrelated to Exelon. The generating stations were leased back to such entities as part of the transaction. For financial accounting purposes, the investments are accounted for as direct financing lease investments. UII holds the leasehold interests in the generating stations in several separate bankruptcy remote, special purpose companies it directly or indirectly wholly owns. The lease agreements provide the lessees with fixed purchase options at the end of the lease terms. If the lessees do not exercise the fixed purchase options, Exelon has the ability to require the lessees to return the leasehold interests or to arrange a service contract with a third party for a period following the lease term. If Exelon chooses the service contract option, the leasehold interests will be returned to Exelon at the end of the term of the service contract. In any event, Exelon will be subject to residual value risk if the lessees do not exercise the fixed purchase options. In the fourth quarter of 2000, under the terms of the lease agreements, UII received a prepayment of $1.2 billion for all rent, which reduced the investment in the leases. There are no minimum scheduled lease payments to be received over the remaining term of the leases. As of December 31, 2009 and 2008, the components of the net investment in the direct financing leases were as follows:


	December 31,
	2009		2008
Estimated residual value of leased assets	$	1,492	$	1,492
Less: unearned income		890		915

Net investment in direct financing leases	$	602	$	577

The following tables provide additional information about liabilities of the Registrants at December 31, 2009 and 2008.


December 31, 2009	Exelon		Generation		ComEd		PECO
Accrued expenses
Compensation-related accruals ^(a)	$	401	$	202	$	107	$	35
Taxes accrued		264		385		62		3
Interest accrued		170		48		88		30
Severance accrued		36		14		10		1
Other accrued expenses		52		21		15		5

Total accrued expenses	$	923	$	670	$	282	$	74


December 31, 2008	Exelon		Generation		ComEd		PECO
Accrued expenses
Compensation-related accruals ^(a)	$	464	$	250	$	114	$	36
Taxes accrued		439		434		80		49
Interest accrued		155		27		89		29
Severance accrued		17		5		4		1
Other accrued expenses		76		45		19		5

Total accrued expenses	$	1,151	$	761	$	306	$	120

(a)	Primarily includes accrued payroll, bonuses and other incentives, vacation and benefits.

The following tables provide information about accumulated OCI (loss) recorded (after tax) within Exelon’s Consolidated Balance Sheets as of December 31, 2009 and 2008:


December 31, 2009	Exelon			Generation			ComEd			PECO
Accumulated other comprehensive income (loss)
Net unrealized gain on cash flow hedges		551			1,157			—			1
Pension and non-pension postretirement benefit plans		(2,640	)		—			—			—

Total accumulated other comprehensive income (loss)	$	(2,089	)	$	1,157		$	—		$	1


December 31, 2008	Exelon			Generation			ComEd			PECO
Accumulated other comprehensive income (loss)
Net unrealized gain on cash flow hedges		564			855			—			2
Pension and non-pension postretirement benefit plans		(2,809	)		(20	)		—			—
Unrealized loss on marketable securities		(6	)		—			(5	)		—

Total accumulated other comprehensive income (loss)	$	(2,251	)	$	835		$	(5	)	$	2

The following tables provide information about the regulatory assets and liabilities of Exelon, ComEd and PECO as of December 31, 2009 and 2008.


December 31, 2009	Exelon		ComEd		PECO
Regulatory assets
Competitive transition charge	$	883	$	—	$	883
Pension and other postretirement benefits		2,634		—		19
Deferred income taxes		842		20		822
Debt costs		144		125		19
Severance		95		95		—
Asset retirement obligations		65		49		16
MGP remediation costs		143		103		40
Rate case costs		8		7		1
RTO start-up costs		12		12		—
Financial swap with Generation—noncurrent		—		669		—
Under-recovered universal service fund costs ^(a)		2		—		2
DSP Program electric procurement contracts ^(b)		2		—		4
Other		42		16		28

Noncurrent regulatory assets		4,872		1,096		1,834
Financial swap with Generation—current		—		302		—
Under-recovered energy and transmission costs current asset ^(d)		56		56		—

Total regulatory assets	$	4,928	$	1,454	$	1,834

Regulatory liabilities
Nuclear decommissioning	$	2,229	$	1,918	$	311
Removal costs		1,212		1,212		—
Refund of PURTA taxes ^(c)		4		—		4
Deferred taxes		30		—		—
Over-recovered universal service fund costs ^(a)		2		—		2
Energy efficiency and demand response programs		15		15		—

Noncurrent regulatory liabilities		3,492		3,145		317
Over-recovered energy and transmission costs current liability ^(d)		33		11		22

Total regulatory liabilities	$	3,525	$	3,156	$	339

(a)	The universal services fund cost is a recovery mechanism that allows for PECO to recover discounts issued to electric and gas customers enrolled in assistance programs. As of December 31, 2009, PECO was under-recovered for its electric program and over-recovered for its gas program.

(b)

PECO entered into block contracts to procure electric generation for its residential procurement class beginning January 1, 2011. As of December 31, 2009, PECO recorded a mark-to-market liability and this offsetting regulatory asset to account for changes in fair value. These block contracts were executed in accordance with the PAPUC-approved DSP Program and PECO will receive full cost recovery in rates.

(c)

In October 2009, PECO prevailed in a Pennsylvania Commonwealth Court case in which PECO had contested the assessment of a PURTA supplemental tax applicable to 1997. As a result, PECO will receive approximately $4 million of real estate taxes previously remitted in 2011. This refund is recorded as a regulatory liability. PECO will begin amortizing this regulatory liability and refunding the amount to customers in January 2011.

(d)

The ComEd under-recovered or over-recovered energy and transmission costs represent purchased power related costs recoverable or refundable to customers under ComEd’s regulatory approved rates. In addition, PECO’s over-recovered energy costs represent gas supply related costs refundable to customers under PECO’s PAPUC PGC. Over-recovered costs are included in other current liabilities in Exelon’s, ComEd’s and PECO’s Consolidated Balance Sheets. ComEd and PECO pay a rate of return on over-recovered energy costs. See Note 2—Regulatory Issues for additional information.


December 31, 2008	Exelon		ComEd		PECO
Regulatory assets
Competitive transition charge	$	1,666	$	—	$	1,666
Pension and other postretirement benefits		2,855		—		26
Deferred income taxes		826		16		810
Debt costs		169		146		23
Severance		116		116		—
Asset retirement obligations		128		112		16
MGP remediation costs		121		80		41
Rate case costs		15		14		1
RTO start-up costs		14		14		—
Financial swap with Generation—noncurrent		—		345		—
Other		30		15		14

Noncurrent regulatory assets		5,940		858		2,597
Financial swap with Generation—current		—		111		—
Under-recovered energy costs current asset ^(a)		58		58		—

Total regulatory assets	$	5,998	$	1,027	$	2,597

Regulatory liabilities
Nuclear decommissioning	$	1,336	$	1,289	$	47
Removal costs		1,145		1,145		—
Refund of PURTA taxes ^(b)		2		—		2
Deferred taxes		30		—		—
Energy efficiency and demand response programs		7		6		—

Noncurrent regulatory liabilities		2,520		2,440		49
Over-recovered energy costs current liability ^(a)		13		1		12

Total regulatory liabilities	$	2,533	$	2,441	$	61

(a)

(b)

Competitive Transition Charges. These charges represent PECO’s stranded costs that the PAPUC determined would be recoverable through regulated rates. These costs are related to the deregulation of the generation portion of the electric utility business in Pennsylvania. The CTCs include intangible transition property sold to PETT, an unconsolidated subsidiary of PECO, in connection with the securitization of PECO’s stranded cost recovery. These charges are being amortized through December 31, 2010 with a return on the unamortized balance of 10.75%.

Pension and other postretirement benefits. As of December 31, 2009, $2,615 million represents regulatory assets related to the recognition of ComEd’s and PECO’s respective shares of the underfunded status of Exelon’s defined benefit postretirement plans as a liability on Exelon’s balance sheet. The regulatory asset is amortized in proportion to the recognition of prior service costs (gains), transition obligations and actuarial losses attributable to ComEd’s pension plan and ComEd’s and PECO’s other postretirement benefit plans determined by the cost recognition provisions of the authoritative guidance for pensions and postretirement benefits. Exelon believes it is probable that these items will be recovered through rates by ComEd and PECO in future periods. See Note 13—Retirement Benefits for additional detail. In addition, $19 million is the result of PECO transitioning to the current authoritative guidance in 1993, which is recoverable in rates through 2012.

Deferred income taxes. These costs represent the difference between the method by which the regulator allows for the recovery of income taxes and how income taxes would be recorded by unregulated entities. Regulatory assets and liabilities associated with deferred income taxes, recorded in compliance with the authoritative guidance for accounting for certain types of regulation and income taxes, include the deferred tax effects associated principally with liberalized depreciation accounted for in accordance with the ratemaking policies of the ICC and PAPUC, as well as the revenue impacts thereon, and assume continued recovery of these costs in future rates. See Note 10—Income Taxes for additional information.

Debt costs. The reacquired debt costs represent premiums paid for the early extinguishment and refinancing of long-term debt, which are amortized over the life of the new debt issued to finance the debt redemption. Interest-rate swap settlements are deferred and amortized over the period that the related debt is outstanding.

Severance. These costs represent previously incurred severance costs that ComEd was granted recovery of in the December 20, 2006 ICC rehearing order. Recovery is over 7.5 years.

Asset retirement obligations. These costs represent future removal costs associated with retirement obligations which will be collected over the remaining lives of the underlying assets. See Note 11—Asset Retirement Obligations for additional information.

MGP remediation costs. Recovery of these items was granted to ComEd in the July 26, 2006 ICC rate order. For PECO, these costs represent estimated MGP-related environmental remediation costs which are recoverable through rates as prescribed in the 2008 joint settlement of the gas distribution rate case. The period of recovery for both ComEd and PECO will depend on the timing of the actual expenditures.

Rate case costs. The ICC generally allows ComEd to receive recovery of rate case costs over three years. The ICC has issued orders allowing recovery of these costs on July 26, 2006 and September 10, 2008. Pursuant to the joint settlement of the 2008 gas distribution rate case, PECO is allowed recovery of rate case costs over two years.

DSP Program electric procurement contracts. These amounts represent an offset to the mark-to-market liability position of PECO’s procurement contracts for electric supply following the expiration of its generation rate caps on December 31, 2010. Recovery of electric procurement costs was granted to PECO in the PAPUC approval of their DSP Program and will occur in 2011 when the transactions under the contract are executed.

Nuclear decommissioning. These amounts represent future nuclear decommissioning costs that exceed (regulatory asset) or are less than (regulatory liability) the associated decommissioning trust fund assets. Exelon believes the trust fund assets, including prospective earnings thereon and any future collections from customers, will equal the associated future decommissioning costs at the time of decommissioning. See Note 11—Asset Retirement Obligations for additional information.

Removal costs. These amounts represent funds received from customers to cover the future removal of property, plant and equipment which reduces rate base for ratemaking purposes.

Financial swap with Generation. To fulfill a requirement of the Illinois Settlement, ComEd entered into a five-year financial swap contract with Generation. Since the swap contract was deemed prudent by the Illinois Settlement Legislation, ensuring ComEd of full recovery in rates, the changes in fair value each period are recorded by ComEd as well as an offsetting regulatory asset or liability. ComEd recorded a regulatory asset related to its mark-to-market derivative liability position as of December 31, 2009 and 2008. The basis for the mark-to-market derivative position is based on the difference between the ComEd’s cost to purchase energy on the spot market and the contracted price. In Exelon’s consolidated financial statements, the fair value of the intercompany swap recorded by Generation and ComEd is eliminated. See Note 2—Regulatory Issues for additional information.

Deferred (over-recovered) energy costs current asset (liability). Starting in 2007, the ComEd costs are recoverable (refundable) under ComEd’s ICC and/or FERC-approved rates. ComEd’s deferred energy costs are earning (paying) a rate of return. The PECO costs represent gas supply related costs recoverable (refundable) under PECO’s PAPUC-approved rates. PECO’s deferred energy costs earn a rate of return. A return on over-recovered energy costs is paid to customers in addition to the over-recovered energy costs.

The regulatory assets related to pension and other postretirement benefits, deferred income taxes, MGP remediation costs, severance, financial swap with Generation, DSP Program and rate case costs are not earning a rate of return. Recovery of the regulatory assets for CTC, AROs, debt costs, RTO start-up costs, under-recovered universal service fund costs and deferred energy costs are earning a rate of return.

Related-Party Transactions (Exelon, Generation, ComEd and PECO)

12 Months Ended

Dec. 31, 2009

Statement [Line Items]

21. Related-Party Transactions (Exelon, Generation, ComEd and PECO)

Exelon

The financial statements of Exelon include related-party transactions as presented in the tables below:


	For the Years Ended December 31,
	2009			2008			2007
Operating revenues from affiliates
CTFT ^(a)	$	—		$	3		$	3
PETT		3			5			6
PECO ^(b)		9			—			—
Other		—			—			1

Total operating revenues from affiliates	$	12		$	8		$	10

Fuel purchases from related parties
Keystone Fuels, LLC	$	56		$	73		$	46
Conemaugh Fuels, LLC		69			54			46

Total fuel purchases from related parties	$	125		$	127		$	92

Charitable contribution to Exelon Foundation ^(d)	$	10		$	—		$	50
Interest expense to affiliates, net
CTFT ^(a)	$	—		$	6		$	27
ComEd Financing II ^(c)		—			2			13
ComEd Financing III		13			13			13
PETT		51			101			139
PECO Trust III		6			6			6
PECO Trust IV		6			6			6
Other		1			(1	)		(1	)

Total interest expense to affiliates, net	$	77		$	133		$	203

Equity in earnings (losses) of unconsolidated affiliates and investments
ComEd Funding ^(a)	$	—		$	(8	)	$	(7	)
PETT		(24	)		(16	)		(7	)
NuStart Energy Development, LLC		(3	)		—			—
TEG and TEP ^(e)		—			—			3
Investment in synthetic fuel-producing facilities		—			—			(93	)
Other		—			(2	)		(2	)

Total equity in losses of unconsolidated affiliates and investments	$	(27	)	$	(26	)	$	(106	)


	As of December 31, 2009		As of December 31, 2008
Investments in affiliates
ComEd Financing III	$	7	$	6
PETT		5		30
PECO Energy Capital Corporation		4		4
PECO Trust IV		4		5

Total investments in affiliates	$	20	$	45

Payables to affiliates (current)
ComEd Financing III	$	4	$	4
PECO Trust III		1		1

Total payables to affiliates (current)	$	5	$	5

Long-term debt to PETT and other financing trusts (including due within one year)
ComEd Financing III	$	206	$	206
PETT		415		1,124
PECO Trust III		81		81
PECO Trust IV		103		103

Total long-term debt due to financing trusts	$	805	$	1,514

(a)

During 2008, ComEd fully paid its long-term debt obligations to CTFT and received its current receivable from CTFT. ComEd Funding liquidated its investment in CTFT and ComEd liquidated its investment in ComEd Funding. This resulted in the elimination of operating revenues and interest expense applicable to CTFT, and equity in losses of the unconsolidated affiliate, ComEd Funding.

(b)	The intersegment profit associated with Generation’s sale of AECs to PECO is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. See Note 2—Regulatory Issues for additional information.

(c)	ComEd Financing II was liquidated and dissolved upon repayment of the debt in 2008.

(d)	Exelon Foundation is a nonconsolidated not-for-profit Illinois corporation. The Exelon Foundation was established in 2007 to serve educational and environmental philanthropic purposes and does not serve a direct business or political purpose of Exelon.

(e)	Generation’s ownership interest in TEG and TEP was sold in 2007.

Transactions involving Generation, ComEd, and PECO are further described in the tables below.

Generation

The financial statements of Generation include related-party transactions as presented in the tables below:


	For the Years Ended December 31,
	2009			2008			2007
Operating revenues from affiliates
ComEd ^(a)	$	1,456		$	1,505		$	1,477
PECO ^(b)		2,016			2,081			2,061

Total operating revenues from affiliates	$	3,472		$	3,586		$	3,538

Fuel expense from related parties
PECO	$	1		$	1		$	3
ComEd		—			3			—
Keystone Fuels, LLC		56			73			46
Conemaugh Fuels, LLC		69			54			46

Total fuel purchases from related parties	$	126		$	131		$	95

Operating and maintenance from affiliates
ComEd ^(c)	$	2		$	1		$	2
PECO ^(c)		6			9			8
BSC ^(d)		298			275			254

Total operating and maintenance from affiliates	$	306		$	285		$	264

Equity in earnings (losses) of investments
TEG and TEP ^(e)	$	—		$	—		$	3
NuStart Energy Development, LLC		(3	)		(1	)		(2	)

Total equity in earnings (losses) of investments	$	(3	)	$	(1	)	$	1

Cash distribution paid to member	$	2,276		$	1,545		$	2,357
Contribution from member	$	57		$	86		$	54


	As of December 31, 2009		As of December 31, 2008
Market-to-market derivative assets with affiliate (current)
ComEd ^(f)	$	302	$	111
Receivables from affiliates (current)
ComEd ^(a)(g)(h)		123		151
PECO ^(b)		174		126

Total receivables from affiliates (current)	$	297	$	277

Receivable from affiliate (noncurrent)
Exelon ⁽ⁱ⁾	$	1	$	1
Market-to-market derivative assets with affiliate (noncurrent)
ComEd ^(f)	$	669	$	345
PECO ^(l)		2		—
Prepaid voluntary employee beneficiary association trust
Generation ^(j)	$	—	$	2
Payables to affiliates (current)
Exelon ⁽ⁱ⁾	$	7	$	44
BSC ^(d)		73		34

Total payables to affiliates (current)	$	80	$	78

Payables to affiliates (noncurrent)
ComEd decommissioning ^(k)	$	1,917	$	1,289
PECO decommissioning ^(k)		311		47

Total payables to affiliates (noncurrent)	$	2,228	$	1,336

(a)

Generation has a SFC and an ICC-approved RFP contract with ComEd to provide a portion of ComEd’s electricity supply requirements. Generation also sells RECs to ComEd. In addition, Generation had revenue from ComEd associated with the settled portion of the financial swap contract established as part of the Illinois Settlement. See Note 2—Regulatory Issues for additional information.

(b)

Generation has a PPA with PECO, as amended, to provide the full energy requirements to PECO through 2010. See Note 18—Commitments and Contingencies for more information regarding the PPA. Generation has a five-year agreement with PECO to sell AECs. See Note 2—Regulatory Issues for additional information.

(c)	Generation requires electricity for its own use at its generating stations. Generation purchases electricity and distribution and transmission services from PECO and only distribution and transmission services from ComEd for the delivery of electricity to its generating stations.

(d)	Generation receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.

(e)	Generation’s ownership interest in TEG and TEP was sold in 2007.

(f)	Represents the fair value of Generation’s five-year financial swap contract with ComEd.

(g)

Under the Illinois Settlement Legislation, Generation is responsible to contribute to rate relief programs for ComEd customers, which are issued through ComEd. As of December 31, 2009 and 2008, Generation had a $0 million and $10 million payable, respectively, which is netted against the receivable from ComEd. See Note 2—Regulatory Issues for additional information.

(h)	As of December 31, 2009, Generation had a $24 million receivable from ComEd associated with the completed portion of the financial swap contract entered into as part of the Illinois Settlement. See Note 2—Regulatory Issues and Note 8—Derivative Financial Instruments for additional information.

(i)	In order to facilitate payment processing, Exelon processes certain invoice payments on behalf of Generation.

(j)

The voluntary employee beneficiary association trusts covering active employees are included in corporate operations and are funded by the operating segments. A prepayment to the active welfare plans accumulated at December 31, 2008 due to actuarially determined contribution rates, which are the basis for Generation’s contributions to the plans, being higher than actual claim expense incurred by the plans over time.

(k)

Generation has long-term payables to ComEd and PECO as a result of the nuclear decommissioning contractual construct whereby, to the extent NDT funds are greater than the underlying ARO at the end of decommissioning, such amounts are due back to ComEd and PECO, as applicable, for payment to their respective customers. See Note 11—Asset Retirement Obligations.

(l)	Represents the fair value of Generation’s block contracts with PECO.

ComEd

The financial statements of ComEd include related-party transactions as presented in the tables below:


	For the Years Ended December 31,
	2009		2008			2007
Operating revenues from affiliates
Generation	$	2	$	4		$	2
CTFT ^(a)		—		3			3

Total operating revenues from affiliates	$	2	$	7		$	5

Purchased power from affiliate
Generation ^(b)	$	1,456	$	1,505		$	1,477
Operating and maintenance from affiliate
BSC ^(c)	$	165	$	168		$	196
Interest expense to affiliates, net
CTFT ^(a)	$	—	$	6		$	27
ComEd Financing II ^(a)		—		2			13
ComEd Financing III		13		13			13

Total interest expense to affiliates, net	$	13	$	21		$	53

Equity in losses of unconsolidated affiliate
ComEd Funding ^(a)	$	—	$	(8	)	$	(7	)
Capitalized costs
BSC ^(c)	$	72	$	55		$	72
Cash dividends paid to parent	$	240	$	—		$	—
Contribution from parent	$	8	$	14		$	28


	As of December 31, 2009		As of December 31, 2008
Prepaid voluntary employee beneficiary association trust ^(d)	$	7	$	9
Investment in affiliate ^(e)
ComEd Financing III		6		6
Receivable from affiliates (noncurrent)
Generation ^(g)	$	1,917	$	1,289
Other		3		2

Total receivable from affiliates (noncurrent)	$	1,920	$	1,291

Payables to affiliates (current)
Generation ^(b)(h)(i)	$	123	$	151
BSC ^(c)		48		22
ComEd Financing III		4		4
Other		2		2

Total payables to affiliates (current)	$	177	$	179

Mark-to-market derivative liability with affiliate (current)
Generation ^(f)	$	302	$	111
Mark-to-market derivative liability with affiliate (noncurrent)
Generation ^(f)	$	669	$	345
Long-term debt to ComEd financing trust
ComEd Financing III	$	206	$	206

(a)

During 2008, ComEd fully paid its long-term debt obligations to CTFT and received its current receivable from the CTFT. ComEd Funding liquidated its investment in CTFT and ComEd liquidated its investment in ComEd Funding. This resulted in the elimination of operating revenues and interest expense applicable to CTFT, and equity in losses of the unconsolidated affiliate, ComEd Funding. In addition, ComEd Financing II was liquidated and dissolved upon repayment of the debt during 2008.

(b)

ComEd procures a portion of its electricity supply requirements from Generation under a SFC and an ICC-approved RFP contract. ComEd also purchases RECs from Generation. In addition, purchased power expense includes the settled portion of the financial swap contract with Generation established as part of the Illinois Settlement. See Note 2—Regulatory Issues and Note 8—Derivative Financial Instruments for additional information.

(c)	ComEd receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.

(d)

The voluntary employee benefit association trusts covering active employees are included in corporate operations and are funded by the operating segments. A prepayment to the active welfare plans has accumulated due to actuarially determined contribution rates, which are the basis for ComEd’s contributions to the plans, being higher than actual claim expense incurred by the plans over time. The prepayment is included in other current assets.

(e)	Investments in affiliates are included in other noncurrent assets.

(f)	To fulfill a requirement of the Illinois Settlement, ComEd entered into a five-year financial swap with Generation.

(g)

ComEd has a long-term receivable from Generation as a result of the nuclear decommissioning contractual construct for generating facilities previously owned by ComEd. To the extent the assets associated with decommissioning are greater than the applicable ARO at the end of decommissioning; such amounts are due back to ComEd for payment to ComEd’s customers.

(h)	As of December 31, 2009, ComEd had a $24 million payable to Generation associated with the completed portion of the financial swap contract entered into as part of the Illinois Settlement. See Note 2—Regulatory Issues and Note8— Derivative Financial Information for additional information.

(i)

Under the Illinois Settlement Legislation, Generation is responsible to contribute to rate relief programs for ComEd customers, which are issued through ComEd. As of December 31, 2009 and 2008, ComEd had a $0 million and $10 million receivable, respectively, which is netted against the payable to Generation. See Note 2—Regulatory Issues for additional information.

PECO

The financial statements of PECO include related-party transactions as presented in the tables below:


	For the Years Ended December 31,
	2009			2008			2007
Operating revenues from affiliates
Generation ^(a)	$	6		$	10		$	11
PETT ^(b)		3			4			6

Total operating revenues from affiliates	$	9		$	14		$	17

Purchased power from affiliate
Generation ^(c)	$	2,005		$	2,083		$	2,059
Operating and maintenance from affiliates
BSC ^(d)	$	94		$	92		$	115
Generation		1			(2	)		2

Total operating and maintenance from affiliates	$	95		$	90		$	117

Interest expense to affiliates, net
PETT	$	51		$	101		$	139
PECO Trust III		6			6			6
PECO Trust IV		6			6			6
Other		—			1			3

Total interest expense to affiliates, net	$	63		$	114		$	154

Equity in losses of unconsolidated affiliates
PETT	$	(24	)	$	(16	)	$	(7	)
Capitalized costs
BSC ^(d)	$	24		$	21		$	30
Cash dividends paid to parent	$	312		$	480		$	562
Repayment of receivable from parent	$	320		$	284		$	306
Contribution from parent	$	27		$	36		$	32


	As of December 31, 2009		As of December 31, 2008
Prepaid voluntary employee beneficiary association trust ^(e)	$	1	$	2
Investments in affiliates
PETT	$	5	$	30
PECO Energy Capital Corporation		4		4
PECO Trust IV		4		5

Total investments in affiliates	$	13	$	39

Receivable from affiliate (noncurrent)
Generation decommissioning ^(f)	$	311	$	47
Mark-to-market derivative liability with affiliate (noncurrent)
Generation ^(h)	$	2	$	—
Payables to affiliates (current)
Generation ⁽ⁱ⁾	$	174	$	126
BSC ^(d)		13		16
Exelon		1		1
PECO Trust III		1		1

Total payables to affiliates (current)	$	189	$	144

Long-term debt to PETT and other financing trusts (including due within one year)
PETT	$	415	$	1,124
PECO Trust III		81		81
PECO Trust IV		103		103

Total long-term debt to financing trusts	$	599	$	1,308

Shareholders’ equity—receivable from parent ^(g)	$	180	$	500

(a)	PECO provides energy to Generation for Generation’s own use.

(b)	PECO receives a monthly administrative servicing fee from PETT based on a percentage of the outstanding balance of all series of transition bonds.

(c)	PECO obtains all of its electric supply from Generation through 2010 under a PPA.

(d)	PECO receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.

(e)

The voluntary employee beneficiary association trusts covering active employees are included in corporate operations and are funded by the operating segments. A prepayment to the active welfare plans has accumulated due to actuarially determined contribution rates, which are the basis for PECO’s contributions to the plans, being higher than actual claim expense incurred by the plans over time.

(f)

PECO has a long-term receivable from Generation as a result of the nuclear decommissioning contractual construct, whereby, to the extent the assets associated with decommissioning are greater than the applicable ARO at the end of decommissioning, such amounts are due back to PECO for payment to PECO’s customers.

(g)	PECO has a non-interest bearing receivable from Exelon related to the 2001 corporate restructuring. The receivable is expected to be settled by December 31, 2010.

(h)	PECO entered into block contracts with Generation to procure electric generation for its residential procurement class beginning January 1, 2011 in accordance with its PAPUC-approved DSP Program.

(i)	PECO obtains all of its electric supply from Generation through 2010 under a PPA. In addition, PECO has a five-year agreement with Generation to purchase AECs. See Note 2—Regulatory Issues for additional information on AECs.

Schedule I Exelon Corporate Financial Statements (Exelon)

12 Months Ended

Dec. 31, 2009

EXELON CORP

Statement [Line Items]

Schedule I Exelon Corporate Financial Statements (Exelon)

EXELON CORPORATION AND SUBSIDIARY COMPANIES

Schedule I

Exelon Corporate

Statements of Operations


	For the Years Ended December 31,
(In millions)	2009			2008			2007
Operating expenses
Operating and maintenance	$	45		$	19		$	51
Operating and maintenance from affiliates		35			31			31

Total operating expenses		80			50			82
Operating loss		(80	)		(50	)		(82	)

Other income and (deductions)
Interest expense, net of amounts capitalized		(133	)		(127	)		(144	)
Equity in earnings of investments		2,835			2,817			2,806
Interest Income from affiliates, net		—			2			2
Other, net		(42	)		9			26

Total other income and deductions		2,660			2,701			2,690

Income from continuing operations before income taxes		2,580			2,651			2,608
Income taxes		(127	)		(86	)		(128	)

Net income	$	2,707		$	2,737		$	2,736

Exelon Corporate

Condensed Statements of Cash Flows


	For the Years Ended December 31,
(In millions)	2009			2008			2007
Net cash flows provided by operating activities	$	2,767		$	2,245		$	3,090

Cash flows from investing activities
Changes in Exelon intercompany money pool		31			(37	)		47
Change in note receivable from affiliate		—			—			67
Investment in affiliates		(454	)		(640	)		(871	)

Net cash flows used in investing activities		(423	)		(677	)		(757	)

Cash flows from financing activities
Change in short-term debt		(56	)		56			(150	)
Retirement of long-term debt		(500	)		—			—
Dividends paid on common stock		(1,385	)		(1,335	)		(1,180	)
Proceeds from employee stock plans		42			130			215
Purchase of treasury stock		—			(436	)		(1,208	)
Purchase of forward contract in relation to certain treasury stock		—			(64	)		(79	)
Other financing activities		7			61			105

Net cash flows used in financing activities		(1,892	)		(1,588	)		(2,297	)

Increase (decrease) in cash and cash equivalents		452			(20	)		36
Cash and cash equivalents at beginning of period		21			41			5

Cash and cash equivalents at end of period	$	473		$	21		$	41

Exelon Corporate

Balance Sheets


	December 31,
(In millions)	2009		2008
Assets
Current assets
Cash and cash equivalents	$	473	$	21
Accounts receivable, net
Other accounts receivable		108		105
Accounts receivable from affiliates		11		53
Notes receivables from affiliates		15		46

Total current assets		607		225

Property, plant and equipment, net		7		—
Deferred debits and other
Regulatory assets		2,613		2,829
Investments
Other investments		1		1
Investment in affiliates		16,313		15,848
Deferred income taxes		1,842		1,917
Mark-to-market derivative assets		10		17
Other		37		51

Total deferred debits and other assets		20,816		20,663

Total assets	$	21,430	$	20,888

Exelon Corporate

Balance Sheets


	December 31,
(In millions)	2009			2008
Current liabilities
Notes payable	$	—		$	56
Long-term debt due within one year		400			—
Accrued expenses		14			15
Other		56			53

Total current liabilities		470			124

Long-term debt		1,308			2,215
Deferred credits and other liabilities
Regulatory liabilities		30			30
Pension obligations		5,959			6,215
Non-pension postretirement benefit obligations		954			1,174
Other		69			83

Total deferred credits and other liabilities		7,012			7,502

Total liabilities		8,790			9,841

Shareholders’ equity
Common stock (No par value, 2,000 shares authorized, 660 and 658 shares outstanding at December 31, 2009 and 2008, respectively).		8,923			8,816
Retained earnings		8,134			6,820
Treasury stock, at cost (35 and 35 shares held at December 31, 2009 and 2008, respectively)		(2,328	)		(2,338	)
Accumulated other comprehensive loss, net		(2,089	)		(2,251	)

Total shareholders’ equity		12,640			11,047

Total liabilities and shareholders’ equity	$	21,430		$	20,888

1. Basis of Presentation

Exelon Corporate is a holding company and conducts substantially all of its business operations through its subsidiaries. These condensed financial statements and related footnotes have been prepared in accordance with Rule 12-04, Schedule I of Regulation S-X. These statements should be read in conjunction with the consolidated financial statements and notes thereto of Exelon Corporation.

Exelon Corporate owns 100% of all significant subsidiaries, either directly or indirectly, except for Commonwealth Edison Company (ComEd), of which Exelon Corporate owns more than 99%, and PECO Energy Company (PECO), of which Exelon Corporate owns 100% of the common stock but none of PECO’s preferred securities.

2. Debt and Credit Agreements

Short-Term Borrowings

Exelon Corporate meets its short-term liquidity requirements primarily through the issuance of commercial paper. Exelon Corporate had commercial paper borrowings at December 31, 2009 and December 31, 2008 of $0 and $56 million, respectively.

Credit Agreements

As of December 31, 2009, Exelon Corporate had access to separate unsecured credit facilities with aggregate bank commitments of $957 million and available capacity under those commitments of $952 million. The agreements are effective through October 26, 2012. See Note 9 of the Combined Notes to Consolidated Financial Statements for further information regarding Exelon Corporate’s credit agreements.

Long-Term Debt

Long-term debt maturities at Exelon Corporate in the periods 2010 through 2014 and thereafter are as follows:


	Exelon
2010	$	400
2011		—
2012		—
2013		—
2014		—
Remaining years		1,300

Total Long-term Debt	$	1,700
Unamortized debt discount and premium, net		(2	)
Fair value hedge carrying value adjustment, net		10

Long-term Debt	$	1,708

3. Commitments and Contingencies

See Note 18 of the Combined Notes to Consolidated Financial Statements for Exelon Corporate’s commitments and contingencies related to the voluntary GHG emissions reductions, pension claim, savings plan claim, retiree healthcare benefits grievance and fund transfer restrictions.

4. Related-Party Transactions

The financial statements of Exelon Corporate include related-party transactions as presented in the tables below:


	For the Years Ended December 31,
	2009			2008		2007
Operating and maintenance from affiliates
Business Services Company (a)	$	35		$	31	$	31
Interest income from affiliates, net
Business Services Company	$	—		$	2	$	1
Generation		—			—		1

Total interest income from affiliates, net	$	—		$	2	$	2

Earnings of affiliates
Exelon Energy Delivery Company, LLC	$	723		$	522	$	668
Exelon Ventures Company, LLC		2,113			2,282		2,133
Unicom Investment, Inc		1			13		5
Exelon Transmission Company, LLC		(2	)		—		—

Total earnings in affiliates	$	2,835		$	2,817	$	2,806

Charitable contributions to Exelon Foundation (b)	$	10		$	—	$	50
Cash contributions received from affiliates		2,841			2,397		3,208


	December 31,
	2009			2008
Accounts receivable from affiliates
URI	$	—		$	7
Generation		6			44
ComEd		1			1
PECO		1			1
Exelon Transmission Company, LLC.		3			—

Total receivables from affiliates (current)	$	11		$	53

Notes receivable from affiliate (current)
Business Services Company	$	15		$	46
Investments in affiliates
Business Services Company	$	237		$	202
Exelon Energy Delivery Company, LLC		9,438			8,907
Exelon Ventures Company, LLC		6,219			6,313
Unicom Investment, Inc.		419			418
Exelon Transmission Company, LLC		(2	)		—
VEBA		2			8

Total investments in affiliates	$	16,313		$	15,848

Payables to affiliate (current)
BSC		8			6

(a)	Exelon Corporate receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead.

(b)

Exelon Foundation is a nonconsolidated not-for-profit Illinois corporation. The Exelon Foundation was established in the fourth quarter of 2007 to serve educational and environmental philanthropic purposes and does not serve a direct business or political purpose of Exelon. Exelon contributes services (i.e. accounting, administrative, legal).

Document Information	12 Months Ended
Document Information	Dec. 31, 2009
Statement [Line Items]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2009

Entity Information - USD ($)	12 Months Ended
Entity Information - USD ($)	Dec. 31, 2009	Jan. 29, 2010	Jun. 30, 2009
Statement [Line Items]
Trading Symbol	EXC
Entity Registrant Name	EXELON CORP
Entity Central Index Key	0001109357
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		659,895,066
Entity Public Float			$ 33,730,940,743
COMMONWEALTH EDISON CO
Statement [Line Items]
Entity Registrant Name	COMMONWEALTH EDISON CO
Entity Central Index Key	0000022606
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		127,016,519
PECO ENERGY CO
Statement [Line Items]
Entity Registrant Name	PECO ENERGY CO
Entity Central Index Key	0000078100
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		170,478,507
EXELON GENERATION CO LLC
Statement [Line Items]
Entity Registrant Name	EXELON GENERATION CO LLC
Entity Central Index Key	0001168165
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Non-accelerated Filer

Consolidated Balance Sheets (Parenthetical) - EXELON CORP - $ / shares shares in Millions	Dec. 31, 2009	Dec. 31, 2008
Statement [Line Items]
Common stock, par value	$ 0	$ 0
Common stock, shares authorized	2,000	2,000
Common stock, shares outstanding	660	658
Treasury stock, shares held	35	35

Spent Nuclear Fuel Obligation (Exelon and Generation)	12 Months Ended
Spent Nuclear Fuel Obligation (Exelon and Generation)	Dec. 31, 2009
EXELON CORP
Statement [Line Items]
Spent Nuclear Fuel Obligation (Exelon and Generation)	12. Spent Nuclear Fuel Obligation (Exelon and Generation) Under the NWPA, the DOE is responsible for the development of a geologic repository for and the disposal of SNF and high-level radioactive waste. As required by the NWPA, Generation is a party to contracts with the DOE (Standard Contracts) to provide for disposal of SNF from Generation’s nuclear generating stations. In accordance with the NWPA and the Standard Contracts, Generation pays the DOE one mill ($.001) per kWh of net nuclear generation for the cost of SNF disposal. This fee may be adjusted prospectively in order to ensure full cost recovery. The NWPA and the Standard Contracts required the DOE to begin taking possession of SNF generated by nuclear generating units by no later than January 31, 1998. The DOE, however, failed to meet that deadline and its performance will be delayed significantly. In January 2009, the DOE issued its Draft National Transportation Plan for the proposed repository. The DOE’s press statement accompanying the release of the plan indicated that shipments to the repository are not expected to begin before 2020. The 2010 Federal budget (which became effective October 1, 2009) eliminated almost all funding for the creation of the Yucca Mountain repository while the Obama Administration devises a new strategy for long-term SNF management. Debate surrounding any new strategy likely will address centralized interim storage, permanent storage at multiple sites and/or SNF reprocessing. Given the program’s history of funding restrictions, it is possible that shipments to the repository may not begin by 2020. Because there is no particular date after 2020 that Generation can establish as having a higher probability as the start date for facility operations, Generation uses the 2020 date as its best estimate of when the DOE will begin accepting SNF. This extended delay in SNF acceptance by the DOE has led to Generation’s adoption of dry cask storage at its Dresden, Limerick, Oyster Creek, Peach Bottom, Byron, Braidwood, LaSalle and Quad Cities stations. Generation performed sensitivity analyses assuming that the estimated date for the DOE acceptance of SNF was delayed to 2025 and to 2035 and determined that Generation’s aggregate nuclear ARO would be reduced by an immaterial amount in each scenario. In August 2004, Generation and the U.S. DOJ, in close consultation with the DOE, reached a settlement under which the government agreed to reimburse Generation for costs associated with storage of SNF at Generation’s nuclear stations pending the DOE’s fulfillment of its obligations. Generation submits annual reimbursement requests to the DOE for costs associated with the storage of SNF. In all cases, reimbursement requests are made only after costs are incurred and only for costs resulting from DOE delays in accepting the SNF. Under the agreement, Generation has received cash reimbursements for costs incurred through April 30, 2009, totaling approximately $360 million ($282 million after considering amounts due to co-owners of certain nuclear stations and to the former owner of Oyster Creek). As of December 31, 2009, the amount of SNF storage costs for which reimbursement will be requested from the DOE under the settlement agreement is $69 million, which is recorded within accounts receivable, other. This amount is comprised of $17 million, which has been recorded as a reduction to operating and maintenance expense, and $49 million, which has been recorded as a reduction to capital expenditures. The remaining $3 million represents amounts owed to the co-owners of the Peach Bottom and Quad Cities generating facilities. The Standard Contracts with the DOE also required the payment to the DOE of a one-time fee applicable to nuclear generation through April 6, 1983. The fee related to the former PECO units has been paid. Pursuant to the Standard Contracts, ComEd previously elected to defer payment of the one-time fee of $277 million for its units (which are now part of Generation), with interest to the date of payment, until just prior to the first delivery of SNF to the DOE. As of December 31, 2009, the unfunded SNF liability for the one-time fee with interest was $1,017 million. Interest accrues at the 13-week Treasury Rate. The 13-week Treasury Rate in effect, for calculation of the interest accrual at December 31, 2009, was 0.061%. The liabilities for SNF disposal costs, including the one-time fee, were transferred to Generation as part of the 2001 corporate restructuring. The outstanding one-time fee obligation for the Oyster Creek and TMI units remains with the former owners. Clinton has no outstanding obligation. See Note 7—Fair Value of Assets and Liabilities for additional information.
EXELON GENERATION CO LLC
Statement [Line Items]
Spent Nuclear Fuel Obligation (Exelon and Generation)	12. Spent Nuclear Fuel Obligation (Exelon and Generation) Under the NWPA, the DOE is responsible for the development of a geologic repository for and the disposal of SNF and high-level radioactive waste. As required by the NWPA, Generation is a party to contracts with the DOE (Standard Contracts) to provide for disposal of SNF from Generation’s nuclear generating stations. In accordance with the NWPA and the Standard Contracts, Generation pays the DOE one mill ($.001) per kWh of net nuclear generation for the cost of SNF disposal. This fee may be adjusted prospectively in order to ensure full cost recovery. The NWPA and the Standard Contracts required the DOE to begin taking possession of SNF generated by nuclear generating units by no later than January 31, 1998. The DOE, however, failed to meet that deadline and its performance will be delayed significantly. In January 2009, the DOE issued its Draft National Transportation Plan for the proposed repository. The DOE’s press statement accompanying the release of the plan indicated that shipments to the repository are not expected to begin before 2020. The 2010 Federal budget (which became effective October 1, 2009) eliminated almost all funding for the creation of the Yucca Mountain repository while the Obama Administration devises a new strategy for long-term SNF management. Debate surrounding any new strategy likely will address centralized interim storage, permanent storage at multiple sites and/or SNF reprocessing. Given the program’s history of funding restrictions, it is possible that shipments to the repository may not begin by 2020. Because there is no particular date after 2020 that Generation can establish as having a higher probability as the start date for facility operations, Generation uses the 2020 date as its best estimate of when the DOE will begin accepting SNF. This extended delay in SNF acceptance by the DOE has led to Generation’s adoption of dry cask storage at its Dresden, Limerick, Oyster Creek, Peach Bottom, Byron, Braidwood, LaSalle and Quad Cities stations. Generation performed sensitivity analyses assuming that the estimated date for the DOE acceptance of SNF was delayed to 2025 and to 2035 and determined that Generation’s aggregate nuclear ARO would be reduced by an immaterial amount in each scenario. In August 2004, Generation and the U.S. DOJ, in close consultation with the DOE, reached a settlement under which the government agreed to reimburse Generation for costs associated with storage of SNF at Generation’s nuclear stations pending the DOE’s fulfillment of its obligations. Generation submits annual reimbursement requests to the DOE for costs associated with the storage of SNF. In all cases, reimbursement requests are made only after costs are incurred and only for costs resulting from DOE delays in accepting the SNF. Under the agreement, Generation has received cash reimbursements for costs incurred through April 30, 2009, totaling approximately $360 million ($282 million after considering amounts due to co-owners of certain nuclear stations and to the former owner of Oyster Creek). As of December 31, 2009, the amount of SNF storage costs for which reimbursement will be requested from the DOE under the settlement agreement is $69 million, which is recorded within accounts receivable, other. This amount is comprised of $17 million, which has been recorded as a reduction to operating and maintenance expense, and $49 million, which has been recorded as a reduction to capital expenditures. The remaining $3 million represents amounts owed to the co-owners of the Peach Bottom and Quad Cities generating facilities. The Standard Contracts with the DOE also required the payment to the DOE of a one-time fee applicable to nuclear generation through April 6, 1983. The fee related to the former PECO units has been paid. Pursuant to the Standard Contracts, ComEd previously elected to defer payment of the one-time fee of $277 million for its units (which are now part of Generation), with interest to the date of payment, until just prior to the first delivery of SNF to the DOE. As of December 31, 2009, the unfunded SNF liability for the one-time fee with interest was $1,017 million. Interest accrues at the 13-week Treasury Rate. The 13-week Treasury Rate in effect, for calculation of the interest accrual at December 31, 2009, was 0.061%. The liabilities for SNF disposal costs, including the one-time fee, were transferred to Generation as part of the 2001 corporate restructuring. The outstanding one-time fee obligation for the Oyster Creek and TMI units remains with the former owners. Clinton has no outstanding obligation. See Note 7—Fair Value of Assets and Liabilities for additional information.