View Filing Data

September 30, 2009

Total
Environmental
Investigation and
Remediation
Reserve

Portion of Total Related
to MGP Investigation
and Remediation

Generation

Consolidated Statements of Operations and Comprehensive Income - USD ($) shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2009	Sep. 30, 2008	Sep. 30, 2009	Sep. 30, 2008
EXELON CORP
Operating revenues
Operating revenues	$ 4,339	$ 5,228	$ 13,202	$ 14,366
Operating expenses
Purchased power	796	1,327	2,400	3,565
Fuel	404	718	1,640	1,608
Operating and maintenance	1,020	1,110	3,492	3,383
Operating and maintenance for regulatory required programs	19	11	44	17
Depreciation and amortization	485	431	1,360	1,230
Taxes other than income	212	218	592	597
Total operating expenses	2,936	3,815	9,528	10,400
Operating income	1,403	1,413	3,674	3,966
Other income and deductions
Interest expense	(170)	(172)	(493)	(532)
Interest expense to affiliates, net	(18)	(31)	(62)	(106)
Equity in losses of investments	(8)	(6)	(21)	(19)
Other, net	148	(158)	367	(256)
Total other income and deductions	(48)	(367)	(209)	(913)
Income before income taxes	1,355	1,046	3,465	3,053
Income taxes	598	346	1,339	1,022
Income from continuing operations	757	700	2,126	2,031
Discontinued operations
Loss on disposal of discontinued operations (net of taxes of $0, $0, $0 and $0 for the three and nine months ended September 30, 2009 and 2008, respectively)	0	0	0	(1)
Loss from discontinued operations, net	0	0	0	(1)
Net income	757	700	2,126	2,030
Comprehensive income, net of income taxes
Net income	757	700	2,126	2,030
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	(3)	(2)	(8)	(7)
Actuarial loss reclassified to periodic cost	26	16	72	47
Transition obligation reclassified to periodic cost	1	1	2	2
Pension and non-pension postretirement benefit plans valuation adjustment	0	0	28	2
Change in unrealized gain (loss) on cash-flow hedges	(128)	1,280	177	328
Change in unrealized gain (loss) on marketable securities	2	(1)	7	(3)
Other comprehensive income (loss)	(102)	1,294	278	369
Comprehensive income	$ 655	$ 1,994	$ 2,404	$ 2,399
Average shares of common stock outstanding:
Basic	660	658	659	658
Diluted	662	662	661	663
Earnings per average common share - basic:
Income from continuing operations	$ 1.15	$ 1.06	$ 3.22	$ 3.09
Net income	1.15	1.06	3.22	3.09
Earnings per average common share - diluted:
Income from continuing operations	1.14	1.06	3.21	3.06
Net income	1.14	1.06	3.21	3.06
Dividends per common share	$ 0.53	$ 0.50	$ 1.58	$ 1.50
EXELON GENERATION CO LLC
Operating revenues
Operating revenues	$ 1,534	$ 2,059	$ 4,737	$ 5,584
Operating revenues from affiliates	911	1,014	2,687	2,727
Total operating revenues	2,445	3,073	7,424	8,311
Operating expenses
Purchased power	303	528	962	1,704
Fuel	379	669	1,295	1,211
Operating and maintenance	522	557	1,975	1,811
Operating and maintenance from affiliate	70	68	235	212
Depreciation and amortization	74	58	223	202
Taxes other than income	51	53	150	153
Total operating expenses	1,399	1,933	4,840	5,293
Operating income	1,046	1,140	2,584	3,018
Other income and deductions
Interest expense	(24)	(34)	(77)	(108)
Equity in losses of investments	(1)	0	(2)	(1)
Other, net	192	(164)	325	(292)
Total other income and deductions	167	(198)	246	(401)
Income before income taxes	1,213	942	2,830	2,617
Income taxes	556	307	1,133	891
Income from continuing operations	657	635	1,697	1,726
Discontinued operations
Loss on disposal of discontinued operations (net of taxes of $0, $0, $0 and $0 for the three and nine months ended September 30, 2009 and 2008, respectively)	0	0	0	(1)
Loss from discontinued operations, net	0	0	0	(1)
Net income	657	635	1,697	1,725
Comprehensive income, net of income taxes
Net income	657	635	1,697	1,725
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	0	(1)	0	(1)
Pension and non-pension postretirement benefit plans valuation adjustment	0	0	0	(3)
Change in unrealized gain (loss) on cash-flow hedges	(98)	1,656	559	543
Other comprehensive income (loss)	(98)	1,655	559	539
Comprehensive income	559	2,290	2,256	2,264
COMMONWEALTH EDISON CO
Operating revenues
Operating revenues	1,474	1,728	4,415	4,591
Operating revenues from affiliates	1	1	2	3
Total operating revenues	1,475	1,729	4,417	4,594
Operating expenses
Purchased power	423	655	1,235	1,605
Purchased power from affiliate	353	413	1,138	1,124
Operating and maintenance	234	265	668	701
Operating and maintenance from affiliate	39	41	128	127
Operating and maintenance for regulatory required programs	19	11	44	17
Depreciation and amortization	125	119	371	343
Taxes other than income	79	87	215	227
Total operating expenses	1,272	1,591	3,799	4,144
Operating income	203	138	618	450
Other income and deductions
Interest expense	(79)	(83)	(231)	(261)
Interest expense to affiliates, net	(3)	(4)	(10)	(18)
Equity in losses of investments	0	(2)	0	(7)
Other, net	(19)	3	67	12
Total other income and deductions	(101)	(86)	(174)	(274)
Income before income taxes	102	52	444	176
Income taxes	56	19	169	66
Discontinued operations
Net income	46	33	275	110
Comprehensive income, net of income taxes
Net income	46	33	275	110
Pension and non-pension postretirement benefit plans:
Change in unrealized gain (loss) on marketable securities	2	(1)	7	(3)
Other comprehensive income (loss)	2	(1)	7	(3)
Comprehensive income	48	32	282	107
PECO ENERGY CO
Operating revenues
Operating revenues	1,325	1,438	4,038	4,185
Operating revenues from affiliates	2	3	7	10
Total operating revenues	1,327	1,441	4,045	4,195
Operating expenses
Purchased power	70	93	203	257
Purchased power from affiliate	555	600	1,539	1,602
Fuel	26	50	346	397
Operating and maintenance	132	169	409	487
Operating and maintenance from affiliate	22	23	72	70
Depreciation and amortization	272	243	726	653
Taxes other than income	78	73	213	203
Total operating expenses	1,155	1,251	3,508	3,669
Operating income	172	190	537	526
Other income and deductions
Interest expense	(32)	(27)	(93)	(81)
Interest expense to affiliates, net	(14)	(28)	(52)	(90)
Equity in losses of investments	(6)	(4)	(19)	(11)
Other, net	2	2	8	13
Total other income and deductions	(50)	(57)	(156)	(169)
Income before income taxes	122	133	381	357
Income taxes	30	43	106	111
Discontinued operations
Net income	92	90	275	246
Preferred security dividends	1	1	3	3
Net income on common stock	91	89	272	243
Comprehensive income, net of income taxes
Net income	92	90	275	246
Pension and non-pension postretirement benefit plans:
Amortization of realized loss on settled cash flow swaps	(1)	0	(1)	(1)
Other comprehensive income (loss)	(1)	0	(1)	(1)
Comprehensive income	$ 91	$ 90	$ 274	$ 245

Consolidated Statements of Cash Flows - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2009	Sep. 30, 2008
EXELON CORP
Cash flows from operating activities
Net income	$ 2,126	$ 2,030
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion	1,935	1,725
Impairment of long-lived assets	223	0
Deferred income taxes and amortization of investment tax credits	740	111
Net fair value changes related to derivatives and nuclear decommissioning trust funds	(257)	(115)
Other non-cash operating activities	464	658
Changes in assets and liabilities:
Accounts receivable	335	226
Inventories	41	(158)
Accounts payable, accrued expenses and other current liabilities	(463)	(261)
Counterparty collateral received, net	380	245
Income taxes	(176)	457
Pension and non-pension postretirement benefit contributions	(456)	(103)
Other assets and liabilities	(263)	(448)
Net cash flows provided by operating activities	4,629	4,367
Cash flows from investing activities
Capital expenditures	(2,252)	(2,282)
Proceeds from nuclear decommissioning trust fund sales	18,769	14,392
Investment in nuclear decommissioning trust funds	(18,949)	(14,621)
Change in restricted cash	32	28
Other investing activities	16	6
Net cash flows used in investing activities	(2,384)	(2,477)
Cash flows from financing activities
Changes in short-term debt	(71)	(431)
Issuance of long-term debt	1,987	1,969
Retirement of long-term debt	(1,515)	(1,397)
Retirement of long-term debt to financing affiliates	(533)	(862)
Dividends paid on common stock	(1,038)	(989)
Proceeds from employee stock plans	28	122
Purchase of treasury stock	0	(436)
Purchase of forward contract in relation to certain treasury stock	0	(64)
Other financing activities	0	69
Net cash flows used in financing activities	(1,142)	(2,019)
Increase (decrease) in cash and cash equivalents	1,103	(129)
Cash and cash equivalents at beginning of period	1,271	311
Cash and cash equivalents at end of period	2,374	182
EXELON GENERATION CO LLC
Cash flows from operating activities
Net income	1,697	1,725
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion	797	697
Impairment of long-lived assets	223	0
Deferred income taxes and amortization of investment tax credits	674	238
Net fair value changes related to derivatives and nuclear decommissioning trust funds	(257)	(113)
Other non-cash operating activities	29	234
Changes in assets and liabilities:
Accounts receivable	147	39
Inventories	(8)	(75)
Accounts payable, accrued expenses and other current liabilities	(105)	(93)
Counterparty collateral received, net	379	247
Income taxes	(22)	361
Pension and non-pension postretirement benefit contributions	(208)	(48)
Other assets and liabilities	(161)	(363)
Receivables from and payables to affiliates, net	(30)	(64)
Net cash flows provided by operating activities	3,155	2,785
Cash flows from investing activities
Capital expenditures	(1,330)	(1,204)
Proceeds from nuclear decommissioning trust fund sales	18,769	14,392
Investment in nuclear decommissioning trust funds	(18,949)	(14,621)
Changes in Exelon intercompany money pool	0	(288)
Change in restricted cash	14	19
Other investing activities	(1)	(3)
Net cash flows used in investing activities	(1,497)	(1,705)
Cash flows from financing activities
Issuance of long-term debt	1,546	0
Distribution to member	(1,800)	(1,244)
Contribution from member	58	86
Retirement of long-term debt	(920)	(12)
Other financing activities	(2)	2
Net cash flows used in financing activities	(1,118)	(1,168)
Increase (decrease) in cash and cash equivalents	540	(88)
Cash and cash equivalents at beginning of period	1,135	127
Cash and cash equivalents at end of period	1,675	39
COMMONWEALTH EDISON CO
Cash flows from operating activities
Net income	275	110
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion	372	343
Deferred income taxes and amortization of investment tax credits	205	41
Other non-cash operating activities	235	197
Changes in assets and liabilities:
Accounts receivable	102	(30)
Inventories	3	(3)
Accounts payable, accrued expenses and other current liabilities	(171)	(60)
Income taxes	(84)	83
Pension and non-pension postretirement benefit contributions	(161)	(7)
Other assets and liabilities	(22)	7
Receivables from and payables to affiliates, net	(43)	53
Net cash flows provided by operating activities	711	734
Cash flows from investing activities
Capital expenditures	(605)	(723)
Change in restricted cash	(1)	0
Other investing activities	15	13
Net cash flows used in investing activities	(591)	(710)
Cash flows from financing activities
Changes in short-term debt	80	(208)
Issuance of long-term debt	191	1,325
Retirement of long-term debt	(208)	(760)
Retirement of long-term debt to financing affiliates	0	(417)
Contributions from parent	8	13
Dividends paid on common stock	(180)	0
Net cash flows used in financing activities	(109)	(47)
Increase (decrease) in cash and cash equivalents	11	(23)
Cash and cash equivalents at beginning of period	47	87
Cash and cash equivalents at end of period	58	64
PECO ENERGY CO
Cash flows from operating activities
Net income	275	246
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion	726	653
Deferred income taxes and amortization of investment tax credits	(166)	(178)
Other non-cash operating activities	107	152
Changes in assets and liabilities:
Accounts receivable	86	(6)
Inventories	47	(80)
Accounts payable, accrued expenses and other current liabilities	(154)	(61)
Income taxes	27	76
Pension and non-pension postretirement benefit contributions	(41)	(25)
Other assets and liabilities	(77)	(16)
Receivables from and payables to affiliates, net	32	6
Net cash flows provided by operating activities	862	767
Cash flows from investing activities
Capital expenditures	(267)	(299)
Change in restricted cash	2	1
Other investing activities	2	7
Net cash flows used in investing activities	(263)	(291)
Cash flows from financing activities
Changes in short-term debt	(95)	(223)
Issuance of long-term debt	250	644
Retirement of long-term debt	0	(604)
Retirement of long-term debt to financing affiliates	(533)	(445)
Contributions from parent	27	36
Changes in Exelon intercompany money pool	0	288
Dividends paid on common stock	(247)	(382)
Dividends paid on preferred securities	(3)	(3)
Repayment of receivable from parent	240	213
Other financing activities	0	1
Net cash flows used in financing activities	(361)	(475)
Increase (decrease) in cash and cash equivalents	238	1
Cash and cash equivalents at beginning of period	39	34
Cash and cash equivalents at end of period	$ 277	$ 35

Consolidated Balance Sheets - USD ($) $ in Millions	9 Months Ended
Consolidated Balance Sheets - USD ($) $ in Millions	Sep. 30, 2009	Dec. 31, 2008	Sep. 30, 2008	Dec. 31, 2007
EXELON CORP
Current assets
Cash and cash equivalents	$ 2,374	$ 1,271	$ 182	$ 311
Restricted cash and investments	43	75
Accounts receivable, net
Customer	1,418	1,928
Other	442	324
Mark-to-market derivative assets	467	410
Inventories, net
Fossil fuel	216	315
Materials and supplies	568	528
Other	367	517
Total current assets	5,895	5,368
Property, plant and equipment, net	26,653	25,813
Deferred debits and other assets
Regulatory assets	5,137	5,940
Nuclear decommissioning trust funds	6,502	5,500
Investments	707	670
Investments in affiliates	25	45
Goodwill	2,625	2,625
Mark-to-market derivative assets	482	507
Other	1,476	1,349
Total deferred debits and other assets	16,954	16,636
Total assets	49,502	47,817
Current liabilities
Short-term borrowings	140	211
Long-term debt due within one year	873	29
Long-term debt to PECO Energy Transition Trust due within one year	591	319
Accounts payable	1,075	1,416
Mark-to-market derivative liabilities	206	214
Accrued expenses	888	1,151
Deferred income taxes	117	77
Other	554	663
Total current liabilities	4,444	4,080
Long-term debt	11,021	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	5,858	4,939
Asset retirement obligations	3,381	3,734
Pension obligations	3,782	4,111
Non-pension postretirement benefit obligations	2,248	2,255
Spent nuclear fuel obligation	1,017	1,015
Regulatory liabilities	3,395	2,520
Mark-to-market derivative liabilities	72	24
Other	1,317	1,413
Total deferred credits and other liabilities	21,070	20,011
Total liabilities	$ 36,925	$ 36,683
Commitments and contingencies	-	-
Preferred securities	$ 87	$ 87
Shareholders' equity
Common stock	8,896	8,816
Treasury stock, at cost (35 and 35 shares held at September 30, 2009 and December 31, 2008, respectively)	(2,338)	(2,338)
Retained earnings	7,905	6,820
Accumulated other comprehensive income (loss), net	(1,973)	(2,251)
Total shareholders' equity	12,490	11,047
Total liabilities and shareholders' equity	49,502	47,817
EXELON GENERATION CO LLC
Current assets
Cash and cash equivalents	1,675	1,135	39	127
Restricted cash	8	22
Accounts receivable, net
Customer	450	673
Other	180	108
Mark-to-market derivative assets	467	410
Mark-to-market derivative assets with affiliate	305	111
Receivables from affiliates	268	277
Inventories, net
Fossil fuel	90	143
Materials and supplies	478	435
Other	246	410
Total current assets	4,167	3,724
Property, plant and equipment, net	9,320	8,907
Deferred debits and other assets
Nuclear decommissioning trust funds	6,502	5,500
Investments	43	33
Mark-to-market derivative assets	470	490
Receivable from affiliate	1	1
Mark-to-market derivative assets with affiliate	780	345
Prepaid pension asset	1,046	949
Other	542	406
Total deferred debits and other assets	9,384	7,724
Total assets	22,871	20,355
Current liabilities
Long-term debt due within one year	147	12
Accounts payable	690	792
Mark-to-market derivative liabilities	206	214
Accrued expenses	559	761
Payables to affiliates	40	78
Deferred income taxes	405	256
Other	232	324
Total current liabilities	2,279	2,437
Long-term debt	2,992	2,502
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	2,878	1,968
Asset retirement obligations	3,262	3,536
Pension obligations	0	63
Non-pension postretirement benefit obligations	675	576
Spent nuclear fuel obligation	1,017	1,015
Payables to affiliates	2,153	1,336
Mark-to-market derivative liabilities	70	24
Other	445	332
Total deferred credits and other liabilities	10,500	8,850
Total liabilities	$ 15,771	$ 13,789
Commitments and contingencies	-	-
Member's equity
Membership interest	$ 3,465	$ 3,407
Undistributed earnings	2,220	2,323
Accumulated other comprehensive income, net	1,414	835
Total member's equity	7,099	6,565
Noncontrolling interest	1	1
Total equity	7,100	6,566
Total liabilities and equity	22,871	20,355
COMMONWEALTH EDISON CO
Current assets
Cash and cash equivalents	58	47	64	87
Restricted cash	2	1
Accounts receivable, net
Customer	637	798
Other	147	162
Inventories, net
Inventories, net	72	75
Regulatory assets	332	169
Deferred income taxes	58	32
Other	23	25
Total current assets	1,329	1,309
Property, plant and equipment, net	11,947	11,655
Deferred debits and other assets
Regulatory assets	1,191	858
Investments	40	34
Goodwill	2,625	2,625
Receivable from affiliate	1,863	1,291
Prepaid pension asset	931	847
Other	595	618
Total deferred debits and other assets	7,245	6,273
Total assets	20,521	19,237
Current liabilities
Short-term borrowings	140	60
Long-term debt due within one year	213	17
Accounts payable	201	307
Accrued expenses	265	306
Payables to affiliates	135	179
Customer deposits	127	119
Mark-to-market derivative liability with affiliate	305	111
Other	48	54
Total current liabilities	1,434	1,153
Long-term debt	4,497	4,709
Long-term debt to financing trust	206	206
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	2,606	2,369
Asset retirement obligations	95	174
Non-pension postretirement benefit obligations	270	203
Regulatory liabilities	3,078	2,440
Mark-to-market derivative liability with affiliate	779	345
Other	711	903
Total deferred credits and other liabilities	7,539	6,434
Total liabilities	$ 13,676	$ 12,502
Commitments and contingencies	-	-
Shareholders' equity
Common stock	$ 1,588	$ 1,588
Other paid-in capital	4,990	4,982
Retained earnings	265	170
Accumulated other comprehensive income (loss), net	2	(5)
Total shareholders' equity	6,845	6,735
Total liabilities and shareholders' equity	20,521	19,237
PECO ENERGY CO
Current assets
Cash and cash equivalents	277	39	$ 35	$ 34
Restricted cash	0	2
Accounts receivable, net
Customer	331	457
Other	52	39
Inventories, net
Fossil fuel	125	172
Materials and supplies	18	18
Deferred income taxes	70	78
Prepaid utility taxes	43	0
Other	16	14
Total current assets	932	819
Property, plant and equipment, net	5,207	5,074
Deferred debits and other assets
Regulatory assets	2,016	2,597
Investments	18	15
Investments in affiliates	19	39
Receivable from affiliate	292	47
Other	623	578
Total deferred debits and other assets	2,968	3,276
Total assets	9,107	9,169
Current liabilities
Short-term borrowings	0	95
Long-term debt to PECO Energy Transition Trust due within one year	591	319
Accounts payable	100	204
Accrued expenses	137	120
Payables to affiliates	176	144
Customer deposits	67	74
Other	27	25
Total current liabilities	1,098	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	2,287	2,451
Asset retirement obligations	24	24
Non-pension postretirement benefit obligations	294	283
Regulatory liabilities	295	49
Other	144	152
Total deferred credits and other liabilities	3,044	2,959
Total liabilities	$ 6,547	$ 6,900
Commitments and contingencies	-	-
Preferred securities	$ 87	$ 87
Shareholders' equity
Common stock	2,318	2,291
Receivable from parent	(260)	(500)
Retained earnings	414	389
Accumulated other comprehensive income (loss), net	1	2
Total shareholders' equity	2,473	2,182
Total liabilities and shareholders' equity	$ 9,107	$ 9,169

2. New Accounting Pronouncements (Exelon, Generation, ComEd and PECO)	9 Months Ended
	Sep. 30, 2009
Notes to Financial Statements [Abstract]
2. New Accounting Pronouncements (Exelon, Generation, ComEd and PECO)	2. New Accounting Pronouncements (Exelon, Generation, ComEd and PECO) *Noncontrolling Interests in Consolidated Financial Statements* In December 2007, 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. 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 Statement of Changes in 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 Statement 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. *Business Combinations* In December 2007, the FASB revised the authoritative guidance for business combinations. Transaction costs are now required to be expensed as incurred and adjustments to the acquired entity’s deferred tax assets and uncertain tax position balances occurring outside the measurement period are recorded as a component of income tax expense, rather than goodwill, among other changes. In April 2009, the FASB revised the authoritative guidance related to the initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a business combination. Generally, assets acquired and liabilities assumed in a business combination that arise from contingencies must be recognized at fair value at the acquisition date. This guidance became effective for the Registrants as of January 1, 2009. As this guidance is applied prospectively to business combinations with an acquisition date on or after the date the guidance became effective, the impact to the Registrants cannot be determined until the transactions occur. No such transactions have occurred during 2009. *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 will be effective for the Registrants as of December 31, 2009. 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. *Fair Value Measurements* In February 2008, the FASB delayed the effective date of fair value measurement and disclosure guidance for all nonrecurring fair value measurements of nonfinancial assets and liabilities until fiscal years beginning after November 15, 2008. The delayed guidance became effective for all nonrecurring nonfinancial assets and liabilities of the Registrants as of January 1, 2009. See Note 6 — Fair Value of 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 (that is, 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 their financial statements. 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 net asset value per share of the investment if the net asset value 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 certain attributes of the investment (such as redemption restrictions) will 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 will become effective for the Registrants as of December 31, 2009 and is required to be applied prospectively. Exelon’s pension and other postretirement plan assets and Generation’s nuclear decommissioning trust fund investments contain commingled funds, which are within the scope of this guidance. However, as the fair value of the commingled funds is already determined based on net asset values per fund share, this guidance will not have a material impact on the Registrants’ results of operations, cash flows, or financial positions. See Note 6 — Fair Value of Assets and Liabilities for further information regarding the fair value of Generation’s nuclear decommissioning trust fund investments. *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 6 — Fair Value of 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 other comprehensive income 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 6 — Fair Value of 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. See Note 1 — Basis of Presentation for further information. *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 is effective for the Registrants beginning January 1, 2010. The Registrants are currently assessing the impacts this may have on their financial statements. Information regarding the Registrants’ involvement with VIEs is included in Note 1 — Basis of Presentation. *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 U.S. 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 financial statements.

3. Regulatory Issues (Exelon, Generation, ComEd and PECO)	9 Months Ended
	Sep. 30, 2009
Notes to Financial Statements [Abstract]
3. Regulatory Issues (Exelon, Generation, ComEd and PECO)	<div> <p style="MARGIN-TOP: 6px; TEXT-INDENT: 4%; MARGIN-BOTTOM: 0px" align="justify"></p> <p style="MARGIN-TOP: 18px; MARGIN-BOTTOM: 0px"><font style="FONT-FAMILY: Times New Roman" size="2"><b>3. Regulatory Issues (Exelon, Generation, ComEd and PECO)</b></font></p> <p style="MARGIN-TOP: 6px; TEXT-INDENT: 4%; MARGIN-BOTTOM: 0px" align="justify"><font style="FONT-FAMILY: Times New Roman" size="2"><b><i>Illinois Settlement Agreement (Exelon, Generation and ComEd</i></b><i>).</i> 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: 18px; MARGIN-BOTTOM: 0px; MARGIN-LEFT: 4%"> <font style="FONT-FAMILY: Times New Roman" size="2"><i>Rate Relief Programs</i></font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px; FONT-SIZE: 6px"> </p> <table style="BORDER-COLLAPSE: collapse" border="0" cellspacing="0" cellpadding="0" width="100%"> <tr> <td width="4%"><font size="1"> </font></td> <td valign="top" width="1%" align="left"><font style="FONT-FAMILY: Times New Roman" size="2">•</font></td> <td valign="top" width="1%"><font size="1"> </font></td> <td valign="top" align="left"> <p align="justify"><font style="FONT-FAMILY: Times New Roman" 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 Illinois Power Agency (IPA) created by the Illinois Settlement Legislation. ComEd and Generation committed to contributing $811 million to rate relief programs over the four year period and partial funding for the IPA. 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: 0px"><font size="1"> </font></p> <p style="MARGIN-TOP: 0px; TEXT-INDENT: 4%; MARGIN-BOTTOM: 0px" align="justify"><font style="FONT-FAMILY: Times New Roman" size="2">During the three and nine months ended September 30, 2009, 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: 12px"> </p> <table border="0" cellspacing="0" cellpadding="0" width="92%" align="center"> <tr> <td width="60%"></td> <td valign="bottom" width="12%"></td> <td></td> <td></td> <td valign="bottom" width="12%"></td> <td></td> <td></td> <td valign="bottom" width="12%"></td> <td></td> <td></td> </tr> <tr> <td valign="bottom" nowrap="nowrap"> <p style="BORDER-BOTTOM: #000000 1px solid; WIDTH: 141pt"> <font style="FONT-FAMILY: Times New Roman" size="1"><b>Three Months Ended September 30, 2009</b></font></p> </td> <td valign="bottom"><font size="1"> </font></td> <td style="BORDER-BOTTOM: #000000 1px solid" valign="bottom" colspan="2" align="center"><font style="FONT-FAMILY: Times New Roman" size="1"><b>Generation</b></font></td> <td valign="bottom"><font size="1"> </font></td> <td style="BORDER-BOTTOM: #000000 1px solid" valign="bottom" colspan="2" align="center"><font style="FONT-FAMILY: Times New Roman" size="1"><b>ComEd</b></font></td> <td valign="bottom"><font size="1"> </font></td> <td style="BORDER-BOTTOM: #000000 1px solid" valign="bottom" colspan="2" align="center"><font style="FONT-FAMILY: Times New Roman" size="1"><b>Total Credits Issued<br /> to ComEd Customers</b></font></td> </tr> <tr bgcolor="#CCEEFF"> <td valign="top"> <p style="TEXT-INDENT: -1em; MARGIN-LEFT: 1em"><font style="FONT-FAMILY: Times New Roman" size="2">Credits to ComEd customers(a)</font></p> </td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: Times New Roman" size="2">$</font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: Times New Roman" size="2">1</font></td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: Times New Roman" size="2">$</font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: Times New Roman" size="2">2</font></td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: Times New Roman" size="2">$</font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: Times New Roman" size="2">3</font></td> </tr> <tr> <td valign="top"> <p style="TEXT-INDENT: -1em; MARGIN-LEFT: 1em"><font style="FONT-FAMILY: Times New Roman" size="2">Credits to other Illinois utilities’ customers(a)</font></p> </td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: Times New Roman" size="2"> </font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: Times New Roman" size="2">13</font></td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: Times New Roman" size="2"> </font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: Times New Roman" size="2">n/a</font></td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: Times New Roman" size="2"> </font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: Times New Roman" size="2">n/a</font></td> </tr> <tr bgcolor="#CCEEFF"> <td valign="top"> <p style="TEXT-INDENT: -1em; MARGIN-LEFT: 1em"><font style="FONT-FAMILY: Times New Roman" size="2">Other rate relief programs(b)</font></p> </td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: Times New Roman" size="2"> </font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: Times New Roman" size="2">—</font></td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: Times New Roman" size="2"> </font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: Times New Roman" size="2">1</font></td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: Times New Roman" size="2"> </font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: Times New Roman" 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="TEXT-INDENT: -1em; MARGIN-LEFT: 1em"><font style="FONT-FAMILY: Times New Roman" size="2">Total incurred costs</font></p> </td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: Times New Roman" size="2">$</font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: Times New Roman" size="2">14</font></td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: Times New Roman" size="2">$</font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: Times New Roman" size="2">3</font></td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: Times New Roman" size="2">$</font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: Times New Roman" size="2">3</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="BORDER-BOTTOM: #000000 0.5pt solid; LINE-HEIGHT: 8px; MARGIN-TOP: 0px; WIDTH: 10%; MARGIN-BOTTOM: 2px"> </p> <table style="BORDER-COLLAPSE: collapse" border="0" cellspacing="0" cellpadding="0" width="100%"> <tr> <td valign="top" width="3%" align="left"><font style="FONT-FAMILY: Times New Roman" size="2">(a)</font></td> <td valign="top" align="left"> <p align="justify"><font style="FONT-FAMILY: Times New Roman" size="2">Recorded as a reduction in operating revenues</font></p> </td> </tr> </table> <table style="BORDER-COLLAPSE: collapse" border="0" cellspacing="0" cellpadding="0" width="100%"> <tr> <td valign="top" width="3%" align="left"><font style="FONT-FAMILY: Times New Roman" size="2">(b)</font></td> <td valign="top" align="left"> <p align="justify"><font style="FONT-FAMILY: Times New Roman" size="2">Recorded as a charge to operating and maintenance expense</font></p> </td> </tr> </table> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px; FONT-SIZE: 12px"> </p> <table border="0" cellspacing="0" cellpadding="0" width="92%" align="center"> <tr> <td width="59%"></td> <td valign="bottom" width="12%"></td> <td></td> <td></td> <td valign="bottom" width="12%"></td> <td></td> <td></td> <td valign="bottom" width="12%"></td> <td></td> <td></td> </tr> <tr> <td valign="bottom" nowrap="nowrap"> <p style="BORDER-BOTTOM: #000000 1px solid; WIDTH: 137pt"> <font style="FONT-FAMILY: Times New Roman" size="1"><b>Nine Months Ended September 30, 2009</b></font></p> </td> <td valign="bottom"><font size="1"> </font></td> <td style="BORDER-BOTTOM: #000000 1px solid" valign="bottom" colspan="2" align="center"><font style="FONT-FAMILY: Times New Roman" size="1"><b>Generation</b></font></td> <td valign="bottom"><font size="1"> </font></td> <td style="BORDER-BOTTOM: #000000 1px solid" valign="bottom" colspan="2" align="center"><font style="FONT-FAMILY: Times New Roman" size="1"><b>ComEd</b></font></td> <td valign="bottom"><font size="1"> </font></td> <td style="BORDER-BOTTOM: #000000 1px solid" valign="bottom" colspan="2" align="center"><font style="FONT-FAMILY: Times New Roman" size="1"><b>Total Credits Issued<br /> to ComEd Customers</b></font></td> </tr> <tr bgcolor="#CCEEFF"> <td valign="top"> <p style="TEXT-INDENT: -1em; MARGIN-LEFT: 1em"><font style="FONT-FAMILY: Times New Roman" size="2">Credits to ComEd customers(a)</font></p> </td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: Times New Roman" size="2">$</font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: Times New Roman" size="2">39</font></td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: Times New Roman" size="2">$</font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: Times New Roman" size="2">4</font></td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: Times New Roman" size="2">$</font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: Times New Roman" size="2">43</font></td> </tr> <tr> <td valign="top"> <p style="TEXT-INDENT: -1em; MARGIN-LEFT: 1em"><font style="FONT-FAMILY: Times New Roman" size="2">Credits to other Illinois utilities’ customers(a)</font></p> </td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: Times New Roman" size="2"> </font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: Times New Roman" size="2">39</font></td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: Times New Roman" size="2"> </font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: Times New Roman" size="2">n/a</font></td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: Times New Roman" size="2"> </font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: Times New Roman" size="2">n/a</font></td> </tr> <tr bgcolor="#CCEEFF"> <td valign="top"> <p style="TEXT-INDENT: -1em; MARGIN-LEFT: 1em"><font style="FONT-FAMILY: Times New Roman" size="2">Other rate relief programs(b)</font></p> </td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: Times New Roman" size="2"> </font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: Times New Roman" size="2">—</font></td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: Times New Roman" size="2"> </font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: Times New Roman" size="2">2</font></td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: Times New Roman" size="2"> </font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: Times New Roman" 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="TEXT-INDENT: -1em; MARGIN-LEFT: 1em"><font style="FONT-FAMILY: Times New Roman" size="2">Total incurred costs</font></p> </td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: Times New Roman" size="2">$</font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: Times New Roman" size="2">78</font></td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: Times New Roman" size="2">$</font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: Times New Roman" size="2">6</font></td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: Times New Roman" size="2">$</font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: Times New Roman" size="2">43</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="BORDER-BOTTOM: #000000 0.5pt solid; LINE-HEIGHT: 8px; MARGIN-TOP: 0px; WIDTH: 10%; MARGIN-BOTTOM: 2px"> </p> <table style="BORDER-COLLAPSE: collapse" border="0" cellspacing="0" cellpadding="0" width="100%"> <tr> <td valign="top" width="3%" align="left"><font style="FONT-FAMILY: Times New Roman" size="2">(a)</font></td> <td valign="top" align="left"> <p align="justify"><font style="FONT-FAMILY: Times New Roman" size="2">Recorded as a reduction in operating revenues</font></p> </td> </tr> </table> <table style="BORDER-COLLAPSE: collapse" border="0" cellspacing="0" cellpadding="0" width="100%"> <tr> <td valign="top" width="3%" align="left"><font style="FONT-FAMILY: Times New Roman" size="2">(b)</font></td> <td valign="top" align="left"> <p align="justify"><font style="FONT-FAMILY: Times New Roman" size="2">Recorded as a charge to operating and maintenance expense</font></p> </td> </tr> </table> <p style="MARGIN-TOP: 6px; TEXT-INDENT: 4%; MARGIN-BOTTOM: 0px" align="justify"><font style="FONT-FAMILY: Times New Roman" size="2">During the three and nine months ended September 30, 2008, Generation and ComEd recognized net costs from their contributions pursuant to the Illinois Settlement in their respective Consolidated Statements of Operations as follows:</font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px; FONT-SIZE: 12px"> </p> <table border="0" cellspacing="0" cellpadding="0" width="92%" align="center"> <tr> <td width="59%"></td> <td valign="bottom" width="12%"></td> <td></td> <td></td> <td valign="bottom" width="12%"></td> <td></td> <td></td> <td valign="bottom" width="12%"></td> <td></td> <td></td> </tr> <tr> <td valign="bottom" nowrap="nowrap"> <p style="BORDER-BOTTOM: #000000 1px solid; WIDTH: 141pt"> <font style="FONT-FAMILY: Times New Roman" size="1"><b>Three Months Ended September 30, 2008</b></font></p> </td> <td valign="bottom"><font size="1"> </font></td> <td style="BORDER-BOTTOM: #000000 1px solid" valign="bottom" colspan="2" align="center"><font style="FONT-FAMILY: Times New Roman" size="1"><b>Generation</b></font></td> <td valign="bottom"><font size="1"> </font></td> <td style="BORDER-BOTTOM: #000000 1px solid" valign="bottom" colspan="2" align="center"><font style="FONT-FAMILY: Times New Roman" size="1"><b>ComEd</b></font></td> <td valign="bottom"><font size="1"> </font></td> <td style="BORDER-BOTTOM: #000000 1px solid" valign="bottom" colspan="2" align="center"><font style="FONT-FAMILY: Times New Roman" size="1"><b>Total Credits Issued<br /> to ComEd Customers</b></font></td> </tr> <tr bgcolor="#CCEEFF"> <td valign="top"> <p style="TEXT-INDENT: -1em; MARGIN-LEFT: 1em"><font style="FONT-FAMILY: Times New Roman" size="2">Credits to ComEd customers(a)</font></p> </td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: Times New Roman" size="2">$</font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: Times New Roman" size="2">20</font></td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: Times New Roman" size="2">$</font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: Times New Roman" size="2">2</font></td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: Times New Roman" size="2">$</font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: Times New Roman" size="2">22</font></td> </tr> <tr> <td valign="top"> <p style="TEXT-INDENT: -1em; MARGIN-LEFT: 1em"><font style="FONT-FAMILY: Times New Roman" size="2">Credits to other Illinois utilities’ customers(a)</font></p> </td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: Times New Roman" size="2"> </font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: Times New Roman" size="2">20</font></td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: Times New Roman" size="2"> </font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: Times New Roman" size="2">n/a</font></td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: Times New Roman" size="2"> </font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: Times New Roman" 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="TEXT-INDENT: -1em; MARGIN-LEFT: 1em"><font style="FONT-FAMILY: Times New Roman" size="2">Total incurred costs</font></p> </td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: Times New Roman" size="2">$</font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: Times New Roman" size="2">40</font></td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: Times New Roman" size="2">$</font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: Times New Roman" size="2">2</font></td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: Times New Roman" size="2">$</font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: Times New Roman" size="2">22</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="BORDER-BOTTOM: #000000 0.5pt solid; LINE-HEIGHT: 8px; MARGIN-TOP: 0px; WIDTH: 10%; MARGIN-BOTTOM: 2px"> </p> <table style="BORDER-COLLAPSE: collapse" border="0" cellspacing="0" cellpadding="0" width="100%"> <tr> <td valign="top" width="3%" align="left"><font style="FONT-FAMILY: Times New Roman" size="2">(a)</font></td> <td valign="top" align="left"> <p align="justify"><font style="FONT-FAMILY: Times New Roman" size="2">Recorded as a reduction in operating revenues.</font></p> </td> </tr> </table> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px; FONT-SIZE: 12px"> </p> <table border="0" cellspacing="0" cellpadding="0" width="92%" align="center"> <tr> <td width="60%"></td> <td valign="bottom" width="11%"></td> <td></td> <td></td> <td valign="bottom" width="11%"></td> <td></td> <td></td> <td valign="bottom" width="11%"></td> <td></td> <td></td> </tr> <tr> <td valign="bottom" nowrap="nowrap"> <p style="BORDER-BOTTOM: #000000 1px solid; WIDTH: 137pt"> <font style="FONT-FAMILY: Times New Roman" size="1"><b>Nine Months Ended September 30, 2008</b></font></p> </td> <td valign="bottom"><font size="1"> </font></td> <td style="BORDER-BOTTOM: #000000 1px solid" valign="bottom" colspan="2" align="center"><font style="FONT-FAMILY: Times New Roman" size="1"><b>Generation</b></font></td> <td valign="bottom"><font size="1"> </font></td> <td style="BORDER-BOTTOM: #000000 1px solid" valign="bottom" colspan="2" align="center"><font style="FONT-FAMILY: Times New Roman" size="1"><b>ComEd</b></font></td> <td valign="bottom"><font size="1"> </font></td> <td style="BORDER-BOTTOM: #000000 1px solid" valign="bottom" colspan="2" align="center"><font style="FONT-FAMILY: Times New Roman" size="1"><b>Total Credits Issued<br /> to ComEd Customers</b></font></td> </tr> <tr bgcolor="#CCEEFF"> <td valign="top"> <p style="TEXT-INDENT: -1em; MARGIN-LEFT: 1em"><font style="FONT-FAMILY: Times New Roman" size="2">Credits to ComEd customers(a)</font></p> </td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: Times New Roman" size="2">$</font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: Times New Roman" size="2">116</font></td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: Times New Roman" size="2">$</font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: Times New Roman" size="2">5</font></td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: Times New Roman" size="2">$</font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: Times New Roman" size="2">121</font></td> </tr> <tr> <td valign="top"> <p style="TEXT-INDENT: -1em; MARGIN-LEFT: 1em"><font style="FONT-FAMILY: Times New Roman" size="2">Credits to other Illinois utilities’ customers(a)</font></p> </td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: Times New Roman" size="2"> </font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: Times New Roman" size="2">68</font></td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: Times New Roman" size="2"> </font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: Times New Roman" size="2">n/a</font></td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: Times New Roman" size="2"> </font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: Times New Roman" size="2">n/a</font></td> </tr> <tr bgcolor="#CCEEFF"> <td valign="top"> <p style="TEXT-INDENT: -1em; MARGIN-LEFT: 1em"><font style="FONT-FAMILY: Times New Roman" size="2">Other rate relief programs(b)</font></p> </td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: Times New Roman" size="2"> </font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: Times New Roman" size="2">—</font></td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: Times New Roman" size="2"> </font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: Times New Roman" size="2">4</font></td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: Times New Roman" size="2"> </font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: Times New Roman" 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="TEXT-INDENT: -1em; MARGIN-LEFT: 1em"><font style="FONT-FAMILY: Times New Roman" size="2">Total incurred costs</font></p> </td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: Times New Roman" size="2">$</font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: Times New Roman" size="2">184</font></td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: Times New Roman" size="2">$</font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: Times New Roman" size="2">9</font></td> <td valign="bottom"><font size="1"> </font></td> <td valign="bottom"><font style="FONT-FAMILY: Times New Roman" size="2">$</font></td> <td valign="bottom" align="right"><font style="FONT-FAMILY: Times New Roman" size="2">121</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="BORDER-BOTTOM: #000000 0.5pt solid; LINE-HEIGHT: 8px; MARGIN-TOP: 0px; WIDTH: 10%; MARGIN-BOTTOM: 2px"> </p> <table style="BORDER-COLLAPSE: collapse" border="0" cellspacing="0" cellpadding="0" width="100%"> <tr> <td valign="top" width="3%" align="left"><font style="FONT-FAMILY: Times New Roman" size="2">(a)</font></td> <td valign="top" align="left"> <p align="justify"><font style="FONT-FAMILY: Times New Roman" size="2">Recorded as a reduction in operating revenues.</font></p> </td> </tr> </table> <table style="BORDER-COLLAPSE: collapse" border="0" cellspacing="0" cellpadding="0" width="100%"> <tr> <td valign="top" width="3%" align="left"><font style="FONT-FAMILY: Times New Roman" size="2">(b)</font></td> <td valign="top" align="left"> <p align="justify"><font style="FONT-FAMILY: Times New Roman" size="2">Recorded as a charge to operating and maintenance expense</font></p> </td> </tr> </table> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px"><font size="1"> </font></p> <p style="MARGIN-TOP: 0px; TEXT-INDENT: 4%; MARGIN-BOTTOM: 0px" align="justify"><font style="FONT-FAMILY: Times New Roman" size="2">As of September 30, 2009, Generation’s remaining costs to be recognized related to the rate relief commitment are $40 million, consisting of $19 million related to programs for ComEd customers and $21 million for programs for customers of other Illinois utilities. ComEd’s remaining costs to be recognized related to the rate relief commitment are $4 million as of September 30, 2009.</font></p> <p style="MARGIN-TOP: 18px; MARGIN-BOTTOM: 0px; MARGIN-LEFT: 4%"> <font style="FONT-FAMILY: Times New Roman" size="2"><i>Energy Efficiency and Renewable Energy</i></font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px; FONT-SIZE: 6px"> </p> <table style="BORDER-COLLAPSE: collapse" border="0" cellspacing="0" cellpadding="0" width="100%"> <tr> <td width="4%"><font size="1"> </font></td> <td valign="top" width="1%" align="left"><font style="FONT-FAMILY: Times New Roman" size="2">•</font></td> <td valign="top" width="1%"><font size="1"> </font></td> <td valign="top" align="left"> <p align="justify"><font style="FONT-FAMILY: Times New Roman" 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 is increasing 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 Illinois Commerce Commission (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 three and nine months ended September 30, 2009, expenses related to energy efficiency and demand response programs consisted of $18 million and $41 million, respectively. During the three and nine months ended September 30, 2008, expenses related to these programs consisted of $11 million and $16 million, respectively.</font></p> </td> </tr> </table> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px; FONT-SIZE: 6px"> </p> <table style="BORDER-COLLAPSE: collapse" border="0" cellspacing="0" cellpadding="0" width="100%"> <tr> <td width="4%"><font size="1"> </font></td> <td valign="top" width="1%" align="left"><font style="FONT-FAMILY: Times New Roman" size="2">•</font></td> <td valign="top" width="1%"><font size="1"> </font></td> <td valign="top" align="left"> <p align="justify"><font style="FONT-FAMILY: Times New Roman" size="2">Starting 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 request for proposal (RFP), ComEd procured renewable energy credits (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 14 — Commitments and Contingencies for further information regarding ComEd’s procurement of RECs.</font></p> </td> </tr> </table> <p style="MARGIN-TOP: 12px; TEXT-INDENT: 4%; MARGIN-BOTTOM: 0px" align="justify"><font style="FONT-FAMILY: Times New Roman" size="2"><b><i>Illinois Procurement Proceedings (Exelon, Generation and ComEd). </i></b>Beginning January 1, 2007, ComEd procured 100% of its load through staggered supplier forward contracts with various suppliers, including Generation. The supplier forward contracts resulted from an ICC-approved “reverse-auction” competitive bidding process, which permitted ComEd to recover its electricity procurement costs from retail customers without markup. The price for full requirements electric supply that resulted from the first auction was fixed through May 2008, at which time the auction contracts for one-third of the load expired. The auction contracts for an additional one-third of the load expired in May 2009 with auction contracts for the final third of the load expiring in May 2010.</font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px"><font size="1"> </font></p> <p style="MARGIN-TOP: 0px; TEXT-INDENT: 4%; MARGIN-BOTTOM: 0px" align="justify"><font style="FONT-FAMILY: Times New Roman" size="2">The IPA, under the oversight of the ICC, participates in the design of an electricity supply portfolio for ComEd and administers a competitive process under which ComEd procures its electricity supply resources for deliveries in the supply period which began in June 2009. During the interim, the ICC approved a plan under which ComEd procured power for the period from June 2008 through May 2009.</font></p> <p style="MARGIN-TOP: 12px; TEXT-INDENT: 4%; MARGIN-BOTTOM: 0px" align="justify"><font style="FONT-FAMILY: Times New Roman" size="2">In March 2008, ComEd completed its first RFP and the ICC voted to approve the lowest-cost package of bids received as recommended by the procurement administrator. ComEd’s purchases acquired through the RFP represented approximately 14% of its expected energy needs from June 2008 through May 2009. For the same period, approximately 19% of ComEd’s energy load was purchased on the spot market and was hedged with a variable to fixed financial swap with Generation. The remaining energy for the period came from the supplier forward contracts. See Note 8 — Derivative Financial Instruments for further discussion on the financial swap derivative.</font></p> <p style="MARGIN-TOP: 12px; TEXT-INDENT: 4%; MARGIN-BOTTOM: 0px" align="justify"><font style="FONT-FAMILY: Times New Roman" size="2">The ICC has also 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. Since 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: 12px; TEXT-INDENT: 4%; MARGIN-BOTTOM: 0px" align="justify"><font style="FONT-FAMILY: Times New Roman" size="2">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 with a significant portion of the purchases hedged by the financial swap contract with Generation, 33% being met through existing supplier forward contracts and the remaining energy requirements being met through the standard products purchased as a result of the 2009 RFP process completed in May 2009. Approximately 8% of ComEd’s energy requirements from June 2010 through May 2011 were also procured through the contracts entered into as a result of the 2009 RFP process. See Note 8 — Derivative Financial Instruments for further discussion on the financial swap derivative, and Note 14 — Commitments and Contingencies for further information regarding ComEd’s procurement of energy.</font></p> <p style="MARGIN-TOP: 12px; TEXT-INDENT: 4%; MARGIN-BOTTOM: 0px" align="justify"><font style="FONT-FAMILY: Times New Roman" size="2">On September 30, 2009, the IPA filed its revised procurement plan with the ICC. Similar to the plan approved by the ICC in January 2009, the IPA’s current plan calls for the procurement of standard block energy products but also includes two additional provisions: first, a procurement of approximately 3.5% of ComEd’s fixed-price load requirements from renewable energy resources utilizing long-term contracts and, second, the procurement of demand response resources as an alternative to traditional capacity. The costs of these contracts are expected to be fully recoverable from customers. The ICC is anticipated to rule on the plan by the end of 2009.</font></p> <p style="MARGIN-TOP: 12px; TEXT-INDENT: 4%; MARGIN-BOTTOM: 0px" align="justify"><font style="FONT-FAMILY: Times New Roman" size="2"><b><i>2005 Rate Case (Exelon and ComEd).</i></b><b> </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 some of the rate design issues addressed in the opinion. ComEd is considering its options regarding further proceedings.</font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px"><font size="1"> </font></p> <p style="MARGIN-TOP: 0px; TEXT-INDENT: 4%; MARGIN-BOTTOM: 0px" align="justify"><font style="FONT-FAMILY: Times New Roman" 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: 12px; TEXT-INDENT: 4%; MARGIN-BOTTOM: 0px" align="justify"><font style="FONT-FAMILY: Times New Roman" 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: 12px; TEXT-INDENT: 4%; MARGIN-BOTTOM: 0px" align="justify"><font style="FONT-FAMILY: Times New Roman" size="2">The ICC opened a proceeding on the Original Cost Audit in May 2008. Under the terms of the stipulation, the ICC Staff will not 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. ComEd filed testimony and legal briefs disputing these contentions and the ICC Staff filed testimony and briefs generally consistent with ComEd’s position and suggesting that no adjustment is warranted and a refund is improper under existing law. No other party made any recommendations regarding the Original Cost Audit. ComEd believes the Illinois Attorney General’s position is meritless. However, if it is accepted by the ICC, it could result in a material disallowance and related write-off of a portion of the original cost of ComEd’s delivery service assets and a refund to customers as described above.</font></p> <p style="MARGIN-TOP: 12px; TEXT-INDENT: 4%; MARGIN-BOTTOM: 0px" align="justify"><font style="FONT-FAMILY: Times New Roman" size="2"><b><i>2007 Rate Case (Exelon and ComEd).</i></b><b> </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: 12px; TEXT-INDENT: 4%; MARGIN-BOTTOM: 0px" align="justify"><font style="FONT-FAMILY: Times New Roman" 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 Advanced Metering Infrastructure (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 in terms of remote disconnect and outage restoration. In addition, the program allows customers the ability to manage energy use, improve energy efficiency and lower energy bills. ComEd cannot estimate the costs of a full system-wide implementation of AMI.</font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px"><font size="1"> </font></p> <p style="MARGIN-TOP: 0px; TEXT-INDENT: 4%; MARGIN-BOTTOM: 0px" align="justify"><font style="FONT-FAMILY: Times New Roman" size="2">On August 4, 2009, ComEd filed a request for $175 million of matching Federal stimulus grants with the Department of Energy (DOE) under the American Recovery & Reinvestment Act to help finance AMI and Smart Grid technologies in Illinois. If the request is approved and fully funded by the DOE, ComEd would expand its original AMI pilot proposal, including more than doubling the number of customers receiving new smart meters. The DOE is expected to select projects for funding later this year. No assurance can be given that ComEd will receive any Federal matching funds. On September 2, 2009, ComEd submitted a petition to the ICC requesting recovery of the remaining distribution related costs of the stimulus projects after receiving the matching funds from the DOE.</font></p> <p style="MARGIN-TOP: 12px; TEXT-INDENT: 4%; MARGIN-BOTTOM: 0px" align="justify"><font style="FONT-FAMILY: Times New Roman" size="2"><b><i>Transmission Rate Case (Exelon and ComEd).</i></b><b> </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: 12px; TEXT-INDENT: 4%; MARGIN-BOTTOM: 0px" align="justify"><font style="FONT-FAMILY: Times New Roman" 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 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 recorded 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: 12px; TEXT-INDENT: 4%; MARGIN-BOTTOM: 0px" align="justify"><font style="FONT-FAMILY: Times New Roman" size="2"><b><i>Illinois Legislation for Recovery of Uncollectible Accounts (Exelon and ComEd).</i></b><b> </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 $32 million during the nine months ended September 30, 2009. On September 8, 2009, ComEd filed a proposed tariff in accordance with the legislation. The ICC has 180 days to approve, or modify and approve, ComEd’s proposed tariff. ComEd does not know what modifications or conditions, if any, the ICC may include in ComEd’s proposed tariff at this time.</font></p> <p style="MARGIN-TOP: 12px; TEXT-INDENT: 4%; MARGIN-BOTTOM: 0px" align="justify"><font style="FONT-FAMILY: Times New Roman" size="2">Upon ICC approval of a satisfactory tariff, ComEd will be 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 program (PIP) 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: 12px; TEXT-INDENT: 4%; MARGIN-BOTTOM: 0px" align="justify"><font style="FONT-FAMILY: Times New Roman" size="2">ComEd currently anticipates that the potential benefit and the $10 million one-time charge will not be recorded until approval of the tariff by the ICC is deemed probable. If approval of the tariff is deemed probable, ComEd will record a regulatory asset and an offsetting reduction in operating and maintenance expense for the cumulative under collections from 2008 through the date of recognition. Recovery of the initial regulatory asset would take place over an approximate 17-month time frame assuming the tariff is approved by February 1, 2010.</font></p> <p style="MARGIN-TOP: 0px; MARGIN-BOTTOM: 0px"><font size="1"> </font></p> <p style="MARGIN-TOP: 0px; TEXT-INDENT: 4%; MARGIN-BOTTOM: 0px" align="justify"><font style="FONT-FAMILY: Times New Roman" size="2"><b><i>Pennsylvania Gas Distribution Rate Case (Exelon and PECO).</i></b> In October 2008, the Pennsylvania Public Utility Commission (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: 12px; TEXT-INDENT: 4%; MARGIN-BOTTOM: 0px" align="justify"><font style="FONT-FAMILY: Times New Roman" 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 six 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: 12px; TEXT-INDENT: 4%; MARGIN-BOTTOM: 0px" align="justify"><font style="FONT-FAMILY: Times New Roman" 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 will accrue interest at the statutory rate of 6% and then be applied as credits to their bills in 2011 and 2012.</font></p> <p style="MARGIN-TOP: 12px; TEXT-INDENT: 4%; MARGIN-BOTTOM: 0px" align="justify"><font style="FONT-FAMILY: Times New Roman" 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 assigning 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 administrative law judge on settlement progress no later than November 20, 2009. See Note 12 — Asset Retirement Obligations and Spent Nuclear Fuel Storage for additional information.</font></p> <p style="MARGIN-TOP: 12px; TEXT-INDENT: 4%; MARGIN-BOTTOM: 0px" align="justify"><font style="FONT-FAMILY: Times New Roman" size="2"><b><i>Pennsylvania Procurement Proceedings (Exelon and PECO).</i></b><b> </b>On June 2, 2009, the PAPUC entered a formal opinion and order approving the settlement of PECO’s default service provider program (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 generation procurement guidelines set forth in Act 129 of 2008 (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: 12px; TEXT-INDENT: 4%; MARGIN-BOTTOM: 0px" align="justify"><font style="FONT-FAMILY: Times New Roman" 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 kilowatts (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; TEXT-INDENT: 4%; MARGIN-BOTTOM: 0px" align="justify"><font style="FONT-FAMILY: Times New Roman" size="2">Seventy-five percent of the residential class, 90% of the small commercial class and 85% of the medium commercial class load will be served through competitively procured contracts for load-following, fixed price full requirements default electric generation. For the remaining portion of the residential class load, PECO will competitively procure forward purchases of forward purchase energy block contracts (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 generation 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 default service provider plan.</font></p> <p style="MARGIN-TOP: 12px; TEXT-INDENT: 4%; MARGIN-BOTTOM: 0px" align="justify"><font style="FONT-FAMILY: Times New Roman" size="2">On September 21, 2009, PECO concluded the second of its competitive procurements for electric generation for default electric service customers commencing January 2011 and, on September 23, 2009, the PAPUC approved the results of the RFP process. The September 2009 procurements were for default electric service to the residential, small commercial, and medium commercial classes. As of September 30, 2009, including the previous competitive procurement completed in June 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 in accordance with the DSP program. PECO also entered into block contracts with 12-month terms for a total of 80 megawatts (MW) for service to the residential customer class in 2011 in accordance with the DSP program. PECO will conduct seven additional competitive procurements in accordance with the plan approved by the PAPUC.</font></p> <p style="MARGIN-TOP: 18px; TEXT-INDENT: 4%; MARGIN-BOTTOM: 0px" align="justify"><font style="FONT-FAMILY: Times New Roman" size="2"><b><i>Energy Efficiency and Alternative Energy Programs (Exelon and PECO).</i></b></font></p> <p style="MARGIN-TOP: 6px; TEXT-INDENT: 4%; MARGIN-BOTTOM: 0px" align="justify"><font style="FONT-FAMILY: Times New Roman" size="2"><i>Energy Efficiency Programs. </i>In October 2008, Act 129 was signed into law. 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, adjusted for weather conditions and extraordinary loads, and by 3% by May 31, 2013. In accordance with Act 129, by May 31, 2013, 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, 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 August 7, 2009, the PAPUC voted to approve a partial settlement of PECO’s Petition for Approval of its EE&C plan providing for early implementation of PECO’s compact fluorescent light bulbs (CFL) initiative. The CFL program is one part of PECO’s four-year EE&C plan required by Act 129. On October 15, 2009, the PAPUC approved in part and denied in part PECO’s EE&C plan.</font></p> <p style="MARGIN-TOP: 12px; TEXT-INDENT: 4%; MARGIN-BOTTOM: 0px" align="justify"><font style="FONT-FAMILY: Times New Roman" size="2">PECO is planning to spend up to approximately $650 million on its smart meter and smart grid infrastructure. On August 14, 2009, PECO filed its $550 million Smart Meter Procurement and Installation Plan with the PAPUC 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. 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: 12px; TEXT-INDENT: 4%; MARGIN-BOTTOM: 0px" align="justify"><font style="FONT-FAMILY: Times New Roman" size="2">On August 6, 2009, PECO filed with the DOE an application seeking $200 million in American Recovery & Reinvestment Act 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 meter deployment by five years and increase Smart Grid investments up to approximately $100 million over the next three years. No assurance can be given that PECO will receive any Federal matching funds.</font></p> <p style="MARGIN-TOP: 12px; TEXT-INDENT: 4%; MARGIN-BOTTOM: 0px" align="justify"><font style="FONT-FAMILY: Times New Roman" size="2"><i>Alternative Energy Portfolio Standards.</i> In November 2004, Pennsylvania adopted the Alternative Energy Portfolio Standards Act (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 alternative energy credits (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: 12px; TEXT-INDENT: 4%; MARGIN-BOTTOM: 0px" align="justify"><font style="FONT-FAMILY: Times New Roman" size="2">The Pennsylvania Legislature is currently considering House Bill No. 80 (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 would 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: 12px; TEXT-INDENT: 4%; MARGIN-BOTTOM: 0px" align="justify"><font style="FONT-FAMILY: Times New Roman" 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 MWs 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 will be 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 plan approved in December 2007, PECO conducted two RFPs during 2008. Pursuant to the first RFP process, PECO entered into a five-year agreement in August 2008 with an accepted bidder for the purchase of 40,000 AECs annually. In April 2009, PECO entered into agreements with accepted bidders, including Generation, for the purchase of 412,000 AECs annually for five years beginning no later than December 31, 2009.</font></p> <p style="MARGIN-TOP: 12px; TEXT-INDENT: 4%; MARGIN-BOTTOM: 0px" align="justify"><font style="FONT-FAMILY: Times New Roman" size="2">On March 3, 2009, PECO filed a petition with the PAPUC for expedited approval of its early procurement and banking of up to 8,000 solar Tier 1 AECs annually for ten years. PECO’s proposed procurement would employ the same surcharge cost-recovery mechanism that the PAPUC previously approved for non-solar Tier 1 AECs. On July 2, 2009, PECO and various interveners filed a joint petition for settlement of the case that 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 August 27, 2009, the PAPUC unanimously approved the settlement. On October 8, 2009, PECO announced its RFP to procure 8,000 solar Tier 1 AECs annually for ten years. PECO plans to enter into the fixed-price agreements by February 2010.</font></p> <p style="MARGIN-TOP: 12px; TEXT-INDENT: 4%; MARGIN-BOTTOM: 0px" align="justify"><font style="FONT-FAMILY: Times New Roman" 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. That is consistent with Exelon’s position in the case. In the same order, FERC held that the costs of new facilities 500 kilovolts (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. Parties may file a petition for appeal to the U.S. Supreme Court after the rehearing request is resolved. 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: 12px; TEXT-INDENT: 4%; MARGIN-BOTTOM: 0px" align="justify"><font style="FONT-FAMILY: Times New Roman" 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 Midwest Independent Transmission System Operator, Inc. (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 has been filed in the United States Court of Appeals. ComEd and PECO cannot predict the outcome of this litigation.</font></p> <p style="MARGIN-TOP: 12px; TEXT-INDENT: 4%; MARGIN-BOTTOM: 0px" align="justify"><font style="FONT-FAMILY: Times New Roman" 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%. As part of the FERC-approved settlement of ComEd’s 2007 transmission rate case, ComEd’s formula transmission rate currently provides for a weighted average debt and equity return on transmission rate base of 9.43%, which is exclusive of the incentive ROE on ComEd’s largest transmission project. The weighted average debt and equity return on transmission rate base will be updated annually in accordance with the formula-based rate calculation discussed above.</font></p> <p style="MARGIN-TOP: 12px; TEXT-INDENT: 4%; MARGIN-BOTTOM: 0px" align="justify"><font style="FONT-FAMILY: Times New Roman" size="2">PECO’s transition period includes caps on electric generation rates that will expire on December 31, 2010 pursuant to the Pennsylvania Electric Generation Customer Choice and Competition Act (Competition Act). The 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 was 11.23% (approved in 1990). PECO’s gas rates are not subject to caps. 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: 12px; TEXT-INDENT: 4%; MARGIN-BOTTOM: 0px" align="justify"><font style="FONT-FAMILY: Times New Roman" size="2"><b><i>Market-Based Rates (Exelon, Generation, ComEd and PECO).</i></b><i> </i>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: 12px; TEXT-INDENT: 4%; MARGIN-BOTTOM: 0px" align="justify"><font style="FONT-FAMILY: Times New Roman" 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; TEXT-INDENT: 4%; MARGIN-BOTTOM: 0px" align="justify"><font style="FONT-FAMILY: Times New Roman" size="2">In January 2008, Generation, ComEd and PECO filed an analysis for generation in the Northeast region covering generation in PJM and ISO-New England using FERC’s updated screening tests, as required by the Final Rule. The filing demonstrated that under those tests, Generation, ComEd, and PECO should be permitted to continue to sell at market-based rates. In August 2008, Generation, ComEd and PECO made an updated filing based on the additional information requested by FERC and following FERC’s guidance in its July 2008 order.</font></p> <p style="MARGIN-TOP: 12px; TEXT-INDENT: 4%; MARGIN-BOTTOM: 0px" align="justify"><font style="FONT-FAMILY: Times New Roman" size="2">In March 2008, the ICC intervened in the proceeding and in September 2008 filed a protest. In its protest, the ICC did not object to Exelon’s request for continued authority to make market-based sales. Instead, the ICC repeated its contentions in an earlier docket in which ComEd had asked FERC to affirm that the procurement for its customers for the period June 1, 2008 through May 31, 2009 satisfied FERC standards, the ICC contended that existing waivers of FERC’s affiliate transaction rules should no longer apply between ComEd and its affiliates, including Generation, because ComEd has captive retail customers. In its response, Exelon reminded FERC that the ICC’s contention was the same as in the earlier ComEd procurement proceeding in which FERC had rejected the ICC’s position. Exelon also noted that the facts on which FERC based its previous finding have not changed.</font></p> <p style="MARGIN-TOP: 12px; TEXT-INDENT: 4%; MARGIN-BOTTOM: 0px" align="justify"><font style="FONT-FAMILY: Times New Roman" size="2">In December 2008, Generation filed an analysis for generation in the Southeast region covering generation in the Southern Company and Entergy areas using FERC’s updated screening tests, as required by the Final Rule. In June 2009, Generation filed an analysis for generation in the Central region covering generation in the MISO market using FERC’s updated screening tests, also 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 December 2008 filing on September 2, 2009.</font></p> <p style="MARGIN-TOP: 12px; TEXT-INDENT: 4%; MARGIN-BOTTOM: 0px" align="justify"><font style="FONT-FAMILY: Times New Roman" size="2">On January 15, 2009, FERC accepted Exelon’s analysis and filing, affirming Exelon’s affiliates’ continued right to make sales at market-based rates. FERC also rejected an ICC request for rehearing in the earlier ComEd procurement docket, in which the ICC had also asked FERC to reconsider its determination in that proceeding that the existing waiver of the affiliate restrictions should not be revoked.</font></p> <p style="MARGIN-TOP: 12px; TEXT-INDENT: 4%; MARGIN-BOTTOM: 0px" align="justify"><font style="FONT-FAMILY: Times New Roman" size="2"><b><i>Reliability Pricing Model (RPM) (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: 12px; TEXT-INDENT: 4%; MARGIN-BOTTOM: 0px" align="justify"><font style="FONT-FAMILY: Times New Roman" 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="PADDING-BOTTOM: 3px; MARGIN-TOP: 12px; TEXT-INDENT: 4%; MARGIN-BOTTOM: 0px" align="justify"><font style="FONT-FAMILY: Times New Roman" 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 (4</font><font style="FONT-FAMILY: Times New Roman" size="1"><sup style="POSITION: relative; BOTTOM: 0.8ex; VERTICAL-ALIGN: baseline">th</sup></font> <font style="FONT-FAMILY: Times New Roman" size="2">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 4</font> <font style="FONT-FAMILY: Times New Roman" size="1"><sup style="POSITION: relative; BOTTOM: 0.8ex; VERTICAL-ALIGN: baseline">th</sup></font> <font style="FONT-FAMILY: Times New Roman" size="2">Circuit was an improper venue, which is currently pending. While the 4</font><font style="FONT-FAMILY: Times New Roman" size="1"><sup style="POSITION: relative; BOTTOM: 0.8ex; VERTICAL-ALIGN: baseline">th</sup></font> <font style="FONT-FAMILY: Times New Roman" size="2">Circuit might be a slightly more favorable forum for petitioners, whether the case is heard in the 4</font><font style="FONT-FAMILY: Times New Roman" size="1"><sup style="POSITION: relative; BOTTOM: 0.8ex; VERTICAL-ALIGN: baseline">th</sup></font> <font style="FONT-FAMILY: Times New Roman" size="2">Circuit or D.C. Circuit, Generation believes FERC is more likely to prevail. If the 4</font><font style="FONT-FAMILY: Times New Roman" size="1"><sup style="POSITION: relative; BOTTOM: 0.8ex; VERTICAL-ALIGN: baseline">th</sup></font> <font style="FONT-FAMILY: Times New Roman" size="2">Circuit or 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: 12px; TEXT-INDENT: 4%; MARGIN-BOTTOM: 0px" align="justify"><font style="FONT-FAMILY: Times New Roman" 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. Any order may then be subject to review in the United States Court of Appeals.</font></p> <p style="MARGIN-TOP: 12px; TEXT-INDENT: 4%; MARGIN-BOTTOM: 0px" align="justify"><font style="FONT-FAMILY: Times New Roman" 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 various citizen groups and the New Jersey Department of Environmental Protection (NJDEP), including filings made with the Nuclear Regulatory Commission’s (NRC) Atomic Safety Licensing Board, the NRC Commissioners, and the U.S. Court of Appeals for the Third Circuit. These filings and appeals were rejected or denied, and the time for filing such appeals has passed. On April 8, 2009, the NRC issued the renewed operating license for Oyster Creek that expires in April 2029. On May 29, 2009, a coalition of six community groups filed a Petition for Review of the NRC’s renewal of Oyster Creek’s operating license in the Third Circuit Court of Appeals. 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: 12px; TEXT-INDENT: 4%; MARGIN-BOTTOM: 0px" align="justify"><font style="FONT-FAMILY: Times New Roman" 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></font></p> <p style="MARGIN-TOP: 12px; TEXT-INDENT: 4%; MARGIN-BOTTOM: 0px" align="justify"><font style="FONT-FAMILY: Times New Roman" 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.</font></p> </div>

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

9 Months Ended

Sep. 30, 2009

Notes to Financial Statements [Abstract]

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

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

Fair Value of Financial Liabilities Recorded at the Carrying Amount

Exelon

The carrying amounts and fair values of Exelon’s long-term debt and spent nuclear fuel obligation as of September 30, 2009 and December 31, 2008 were as follows:


	September 30, 2009				December 31, 2008
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt (including amounts due within one year)	$	11,894	$	12,562	$	11,426	$	10,803
Long-term debt to PETT (including amounts due within one year)		591		617		1,124		1,193
Long-term debt to other financing trusts		390		318		390		200
Spent nuclear fuel obligation		1,017		835		1,015		544
Preferred securities of subsidiary		87		64		87		63

Generation

The carrying amounts and fair values of Generation’s long-term debt and spent nuclear fuel obligation as of September 30, 2009 and December, 31, 2008 were as follows:


	September 30, 2009				December 31, 2008
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt (including amounts due within one year)	$	3,139	$	3,294	$	2,514	$	2,402
Spent nuclear fuel obligation		1,017		835		1,015		544

ComEd

The carrying amounts and fair values of ComEd’s long-term debt as of September 30, 2009 and December 31, 2008 were as follows:


	September 30, 2009				December 31, 2008
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt (including amounts due within one year)	$	4,710	$	5,102	$	4,726	$	4,510
Long-term debt to financing trust		206		163		206		100

PECO

The carrying amounts and fair values of PECO’s long-term debt and preferred securities as of September 30, 2009 and December 31, 2008 were as follows:


	September 30, 2009				December 31, 2008
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt (including amounts due within one year)	$	2,221	$	2,348	$	1,971	$	1,954
Long-term debt to PETT (including amounts due within one year)		591		617		1,124		1,193
Long-term debt to other financing trusts		184		155		184		100
Preferred securities		87		64		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 with observable market data 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 and commingled investment funds with unobservable market data and subject to purchase and sale restrictions.

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 September 30, 2009 and December 31, 2008:


As of September 30, 2009 (In millions)	Level 1			Level 2			Level 3			Total
Assets
Cash equivalents	$	2,307		$	—		$	—		$	2,307	(a)
Nuclear decommissioning trust fund investments
Cash equivalents		3			—			—			3
Equity securities		1,444			—			—			1,444	(b)
Commingled funds		—			113			1,951			2,064	(c)
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies		410			130			—			540
Debt securities issued by states of the United States and political subdivisions of the states		—			475			—			475
Corporate debt securities		—			699			—			699
Federal agency mortgage-backed securities		—			888			—			888
Commercial mortgage-back securities (non-agency)		—			100			—			100
Residential mortgage-backed securities (non-agency)		—			9			—			9
Other debt obligations		—			80			—			80

Nuclear decommissioning trust fund investments subtotal		1,857			2,494			1,951			6,302	(d)

Rabbi trust investments
Cash equivalents		3			—			—			3
Mutual funds		47			—			—			47	(e)(f)

Rabbi trust investments subtotal		50			—			—			50	(f)

Mark-to-market derivative net assets		(5	)		714			(38	)		671	(g)(h)

Total assets		4,209			3,208			1,913			9,330

Liabilities
Deferred compensation		—			(80	)		—			(80	)
Servicing liability		—			—			(2	)		(2	)

Total liabilities		—			(80	)		(2	)		(82	)

Total net assets	$	4,209		$	3,128		$	1,911		$	9,248


As of December 31, 2008 (In millions)	Level 1		Level 2			Level 3			Total
Assets
Cash equivalents	$	1,228	$	—		$	—		$	1,228	(a)
Nuclear decommissioning trust fund investments
Cash equivalents		13		—			—			13
Equity securities		903		—			—			903	(b)
Commingled funds		—		94			1,220			1,314	(c)
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-back securities (non-agency)		—		111			—			111
Other debt obligations		—		107			—			107

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

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

Rabbi trust investments subtotal		45		—			—			45	(f)

Mark-to-market derivative net assets		12		561			106			679	(g)(h)

Total assets		2,626		3,637			1,326			7,589

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

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

Total net assets	$	2,626	$	3,552		$	1,324		$	7,502

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

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

(c)

Generation’s nuclear decommissioning trust 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 $200 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 September 30, 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 September 30, 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 $305 million and $779 million at September 30, 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 $1 million at September 30, 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 $4 million, $1,130 million and $3 million that are netted against Level 1, Level 2 and Level 3 mark-to-market derivative net assets, respectively, as of September 30, 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.

The following table presents the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the three and nine months ended September 30, 2009 and 2008:


Three Months Ended September 30, 2009 (In millions)	Nuclear Decommissioning Trust Fund Investments		Mark-to-Market Derivatives			Servicing Liability			Total
Balance as of June 30, 2009	$	1,679	$	12		$	(2	)	$	1,689
Total realized / unrealized gains (losses)
Included in income		78		(31	)(a)(c)		—			47
Included in other comprehensive income		—		(4	)(b)		—			(4	)
Included in regulatory assets (liabilities)		191		(1	)		—			190
Purchases, sales and issuances, net		3		—			—			3
Transfers into or (out of) Level 3		—		(14	)		—			(14	)

Balance as of September 30, 2009	$	1,951	$	(38	)	$	(2	)	$	1,911

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 September 30, 2009	$	116	$	(18	)	$	—		$	98

(a)	Includes the reclassification of $11 million of realized losses due to the settlement of derivative contracts recorded in results of operations.

(b)	Excludes $140 million of changes in the fair value and $93 million of realized losses due to settlements associated with Generation’s financial swap contract with ComEd. All items eliminate upon consolidation in Exelon’s Consolidated Financial Statements.

(c)	Includes $2 million of changes in cash collateral received, net of cash collateral sent and offset against Level 3 mark-to-market assets and liabilities.


Nine Months Ended September 30, 2009 (In millions)	Nuclear Decommissioning Trust Fund Investments		Mark-to-Market Derivatives			Servicing Liability			Total
Balance as of December 31, 2008	$	1,220	$	106		$	(2	)	$	1,324
Total realized / unrealized gains (losses)
Included in income		119		(132	)(a)(c)		—			(13	)
Included in other comprehensive income		—		6	(b)(d)		—			6
Included in regulatory assets (liabilities)		275		(2	)		—			273
Purchases, sales and issuances, net		337		—			—			337
Transfers into or (out of) Level 3		—		(16	)		—			(16	)

Balance as of September 30, 2009	$	1,951	$	(38	)	$	(2	)	$	1,911

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 September 30, 2009	$	156	$	(89	)	$	—		$	67

(a)	Includes the reclassification of $41 million of realized losses due to the settlement of derivative contracts recorded in results of operations.

(b)

Excludes $808 million of changes in the fair value and $180 million of realized losses due to settlements associated with Generation’s financial swap contract with ComEd, and $1 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)	Includes $2 million of changes in cash collateral sent, net of cash collateral received and offset against Level 3 mark-to-market assets and liabilities.

(d)	Includes $1 million of changes in cash collateral sent, net of cash collateral received and offset against Level 3 mark-to-market assets and liabilities.


Three Months Ended September 30, 2008 (In millions)	Nuclear Decommissioning Trust Fund Investments			Mark-to-Market Derivatives			Servicing Liability			Total
Balance as of June 30, 2008	$	1,848		$	167		$	(1	)	$	2,014
Total realized / unrealized (losses) gains
Included in income		(92	)		(13	)(a)(c)		(1	)		(106	)
Included in other comprehensive income		—			(2	)(b)		—			(2	)
Included in regulatory liabilities		(194	)		—			—			(194	)
Purchases, sales and issuances, net		16			—			—			16
Transfers into or (out of) Level 3		(34	)		38			—			4

Balance as of September 30, 2008	$	1,544		$	190		$	(2	)	$	1,732

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 September 30, 2008	$	(91	)	$	6		$	—		$	(85	)

(a)	Includes the reclassification of $19 million of realized losses due to the settlement of derivative contracts recorded in results of operations.

(b)	Excludes $645 million of changes in the fair value and $31 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.

(c)	Includes $10 million of changes in cash collateral received, net of cash collateral sent and offset against Level 3 mark-to-market assets and liabilities.


Nine Months Ended September 30, 2008 (In millions)	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		(187	)		133	(a)		(1	)		(55	)
Included in other comprehensive income		—			(33	)(b)		—			(33	)
Included in regulatory liabilities		(352	)		—			—			(352	)
Purchases, sales and issuances, net		98			—			—			98
Transfers into (out of ) Level 3		(34	)		38			—			4

Balance as of September 30, 2008	$	1,544		$	190		$	(2	)	$	1,732

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 September 30, 2008	$	(176	)	$	193		$	—		$	17

(a)	Includes the reclassification of $60 million of realized losses due to the settlement of derivative contracts recorded in results of operations.

(b)	Excludes $320 million of changes in the fair value and $38 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 three and nine months ended September 30, 2009 and 2008:


(In millions)	Operating Revenue			Purchased Power			Fuel			Other, net
Total (losses) gains included in income for the three months ended September 30, 2009	$	(23	)	$	(11	)	$	3		$	78
Total (losses) gains included in income for the nine months ended September 30, 2009	$	(65	)	$	(17	)	$	(50	)	$	119
Change in the unrealized (losses) gains relating to assets and liabilities held as of September 30, 2009 for the three months ended September 30, 2009	$	(1	)	$	(8	)	$	(9	)	$	116
Change in the unrealized (losses) gains relating to assets and liabilities held as of September 30, 2009 for the nine months ended September 30, 2009	$	(1	)	$	(15	)	$	(73	)	$	156


(In millions)	Operating Revenue			Purchased Power			Fuel			Other, net
Total gains (losses) included in income for the three months ended September 30, 2008	$	(10	)	$	59		$	(62	)	$	(92	)
Total gains (losses) included in income for the nine months ended September 30, 2008	$	74		$	(8	)	$	67		$	(187	)
Change in the unrealized gains (losses) relating to assets and liabilities held as of September 30, 2008 for the three months ended September 30, 2008	$	1		$	41		$	(36	)	$	(91	)
Change in the unrealized gains (losses) relating to assets and liabilities held as of September 30, 2008 for the nine months ended September 30, 2008	$	107		$	(29	)	$	115		$	(176	)

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 September 30, 2009 and December 31, 2008:


As of September 30, 2009 (In millions)	Level 1			Level 2			Level 3		Total
Assets
Cash equivalents	$	1,628		$	—		$	—	$	1,628	(a)
Nuclear decommissioning trust fund investments
Cash equivalents		3			—			—		3
Equity securities		1,444			—			—		1,444	(b)
Commingled funds		—			113			1,951		2,064	(c)
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies		410			130			—		540
Debt securities issued by states of the United States and political subdivisions of the states		—			475			—		475
Corporate debt securities		—			699			—		699
Federal agency mortgage-backed securities		—			888			—		888
Commercial mortgage-backed securities (non-agency)		—			100			—		100
Residential mortgage-backed securities (non-agency)		—			9			—		9
Other debt obligations		—			80			—		80

Nuclear decommissioning trust fund investments subtotal		1,857			2,494			1,951		6,302	(d)

Rabbi trust investments		4			—			—		4	(e)(f)
Mark-to-market derivative net (liabilities) assets		(5	)		702			1,049		1,746	(g)(h)

Total assets		3,484			3,196			3,000		9,680

Liabilities
Deferred compensation		—			(23	)		—		(23	)

Total liabilities		—			(23	)		—		(23	)

Total net assets	$	3,484		$	3,173		$	3,000	$	9,657


As of December 31, 2008 (In millions)	Level 1		Level 2			Level 3		Total
Assets
Cash equivalents	$	1,103	$	—		$	—	$	1,103	(a)
Nuclear decommissioning trust fund investments
Cash equivalents		13		—			—		13
Equity securities		903		—			—		903	(b)
Commingled funds		—		94			1,220		1,314	(c)
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		1,341		3,076			1,220		5,637	(d)

Rabbi trust investments		—		4			—		4	(e)(f)
Mark-to-market derivative net assets		12		544			562		1,118	(g)(h)

Total assets		2,456		3,624			1,782		7,862

Liabilities
Deferred compensation		—		(25	)		—		(25	)

Total liabilities		—		(25	)		—		(25	)

Total net assets	$	2,456	$	3,599		$	1,782	$	7,837

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

(b)	Generation’s nuclear decommissioning trust 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)

(d)	Excludes net assets of $200 million and net liabilities of $137 million at September 30, 2009 and December 31, 2008, respectively. These items consist of payables related to pending securities purchases net of cash, interest 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 September 30, 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 $305 million and $779 million at September 30, 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 $1 million at September 30, 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)


Three Months Ended September 30, 2009 (In millions)	Nuclear Decommissioning Trust Fund Investments		Mark-to-Market Derivatives			Total
Balance as of June 30, 2009	$	1,679	$	1,051		$	2,730
Total unrealized / realized gains (losses)
Included in income		78		(31	)(a)(c)		47
Included in other comprehensive income		—		43	(b)		43
Included in noncurrent payables to affiliates		191		—			191
Purchases, sales, issuances and settlements, net		3		—			3
Transfers into or (out of) Level 3		—		(14	)		(14	)

Balance as of September 30, 2009	$	1,951	$	1,049		$	3,000

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 September 30, 2009	$	116	$	(18	)	$	98

(a)	Includes the reclassification of $11 million of realized losses due to the settlement of derivative contracts recorded in results of operations.

(b)	Includes $140 million of changes in the fair value and $93 million of realized losses due to settlements associated with Generation’s financial swap with ComEd. All items eliminate upon consolidation in Exelon’s Consolidated Financial Statements.

(c)	Includes $2 million of changes in cash collateral received, net of cash collateral sent and offset against Level 3 mark-to-market assets and liabilities.


Nine Months Ended September 30, 2009 (In millions)	Nuclear Decommissioning Trust Fund Investments		Mark-to-Market Derivatives			Total
Balance as of December 31, 2008	$	1,220	$	562		$	1,782
Total unrealized / realized gains (losses)
Included in income		119		(132	)(a)(c)		(13	)
Included in other comprehensive income		—		635	(b)(d)		635
Included in noncurrent payables to affiliates		275		—			275
Purchases, sales, issuances and settlements, net		337		—			337
Transfers into or (out of) Level 3		—		(16	)		(16	)

Balance as of September 30, 2009	$	1,951	$	1,049		$	3,000

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 September 30, 2009	$	156	$	(89	)	$	67

(a)	Includes the reclassification of $41 million of realized losses due to the settlement of derivative contracts recorded in results of operations.

(b)

Includes $808 million of changes in the fair value and $180 million of realized losses due to settlements associated with Generation’s financial swap with ComEd, and $1 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)	Includes $2 million of changes in cash collateral received, net of cash collateral sent and offset against Level 3 mark-to-market assets and liabilities.

(d)	Includes $1 million of changes in cash collateral sent, net of cash collateral received and offset against Level 3 mark-to-market assets and liabilities.


Three Months Ended September 30, 2008 (In millions)	Nuclear Decommissioning Trust Fund Investments			Mark-to-Market Derivatives			Total
Balance as of June 30, 2008	$	1,848		$	(607	)	$	1,241
Total unrealized / realized (losses) gains
Included in income		(92	)		(13	)(a)(c)		(105	)
Included in other comprehensive income		—			674	(b)		674
Included in noncurrent payables to affiliates		(194	)		—			(194	)
Purchases, sales, issuances and settlements, net		16			—			16
Transfers into or (out of) Level 3		(34	)		38			4

Balance as of September 30, 2008	$	1,544		$	92		$	1,636

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 September 30, 2008	$	(91	)	$	6		$	(85	)

(a)	Includes the reclassification of $19 million of realized losses due to the settlement of derivative contracts recorded in results of operations.

(b)	Includes $645 million of changes in the fair value and $31 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.

(c)	Includes $10 million of changes in cash collateral received, net of cash collateral sent and offset against Level 3 mark-to-market assets and liabilities.


Nine Months Ended September 30, 2008 (In millions)	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		(187	)		133	(a)		(54	)
Included in other comprehensive income		—			324	(b)		324
Included in noncurrent payables to affiliates		(352	)		—			(352	)
Purchases, sales, issuances and settlements, net		98			—			98
Transfers into or (out of) Level 3		(34	)		38			4

Balance as of September 30, 2008	$	1,544		$	92		$	1,636

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 September 30, 2008	$	(176	)	$	193		$	17

(a)	Includes the reclassification of $60 million of realized losses due to the settlement of derivative contracts recorded in results of operations.

(b)	Includes $320 million of changes in the fair value and $38 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.


(In millions)	Operating Revenue			Purchased Power			Fuel			Other, net
Total gains (losses) included in income for the three months ended September 30, 2009	$	(23	)	$	(11	)	$	3		$	78
Total gains (losses) included in income for the nine months ended September 30, 2009	$	(65	)	$	(17	)	$	(50	)	$	119
Change in the unrealized gains (losses) relating to assets and liabilities held as of September 30, 2009 during the three months ended September 30, 2009	$	(1	)	$	(8	)	$	(9	)	$	116
Change in the unrealized gains (losses) relating to assets and liabilities held as of September 30, 2009 during the nine months ended September 30, 2009	$	(1	)	$	(15	)	$	(73	)	$	156


(In millions)	Operating Revenue			Purchased Power			Fuel			Other, net
Total gains (losses) included in income for the three months ended September 30, 2008	$	(10	)	$	59		$	(62	)	$	(92	)
Total gains (losses) included in income for the nine months ended September 30, 2008	$	74		$	(8	)	$	67		$	(187	)
Change in the unrealized gains (losses) relating to assets and liabilities held as of September 30, 2008 during the three months ended September 30, 2008	$	1		$	41		$	(36	)	$	(91	)
Change in the unrealized gains (losses) relating to assets and liabilities held as of September 30, 2008 during the nine months ended September 30, 2008	$	107		$	(29	)	$	115		$	(176	)

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 September 30, 2009 and December 31, 2008:


As of September 30, 2009 (In millions)	Level 1		Level 2			Level 3			Total
Assets
Cash equivalents	$	35	$	—		$	—		$	35	(a)
Rabbi trust investments
Cash equivalents		3		—			—			3
Mutual funds		37		—			—			37	(b)
Rabbi trust investment subtotal		40		—			—			40

Total assets		75		—			—			75

Liabilities
Deferred compensation obligation		—		(7	)		—			(7	)
Mark-to-market derivative liabilities		—		—			(1,084	)		(1,084	)(c)

Total liabilities		—		(7	)		(1,084	)		(1,091	)

Total net assets (liabilities)	$	75	$	(7	)	$	(1,084	)	$	(1,016	)


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

Total assets		50		—			—			50

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

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)

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. 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 $305 million and $779 million at September 30, 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.

The following tables present the fair value reconciliation of Level 3 assets measured at fair value on a recurring basis during the three and nine months ended September 30, 2009 and 2008:


Three Months Ended September 30, 2009 (In millions)	Mark-to-Market Derivatives
Balance as of June 30, 2009	$	(1,037	)
Total realized / unrealized gains (losses) included in regulatory assets(a)		(47	)

Balance as of September 30, 2009	$	(1,084	)

(a)	Includes $140 million of changes in the fair value and $93 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.


Nine Months Ended September 30, 2009 (In millions)	Mark-to-Market Derivatives
Balance as of December 31, 2008	$	(456	)
Total realized / unrealized gains (losses) included in regulatory assets(a)		(628	)

Balance as of September 30, 2009	$	(1,084	)

(a)	Includes $808 million of changes in the fair value and $180 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.


Three Months Ended September 30, 2008 (In millions)	Mark-to-Market Derivatives
Balance as of June 30, 2008	$	774
Total realized / unrealized gains included in regulatory liabilities		(676	)

Balance as of September 30, 2008	$	98

(a)	Includes $645 million of changes in the fair value and $31 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.


Nine Months Ended September 30, 2008 (In millions)	Mark-to-Market Derivatives
Balance as of January 1, 2008	$	456
Total realized / unrealized gains included in regulatory liabilities		(358	)

Balance as of September 30, 2008	$	98

(a)	Includes $320 million of changes in the fair value and $38 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 September 30, 2009 and December 31, 2008:


As of September 30, 2009 (In millions)	Level 1		Level 2			Level 3			Total
Assets
Cash equivalents	$	263	$	—		$	—		$	263	(a)
Rabbi trust investments-mutual funds		6		—			—			6	(b)(c)

Total assets		269		—			—			269

Liabilities
Deferred compensation obligation		—		(25	)		—			(25	)
Mark-to-market derivative liabilities		—		—			(3	)		(3	)(d)
Servicing liability		—		—			(2	)		(2	)

Total liabilities		—		(25	)		(5	)		(30	)

Total net assets (liabilities)	$	269	$	(25	)	$	(5	)	$	239


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

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 September 30, 2009 and December 31, 2008, respectively.

(d)

The Level 3 balance is included in other deferred credits and other liabilities on PECO’s Consolidated Balance Sheets and represents a noncurrent liability of $3 million at September 30, 2009 related to the fair value of PECO’s block contracts, which includes a $1 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 three and nine months ended September 30, 2009:


Three Months Ended September 30, 2009 (In millions)	Mark-to-Market Derivatives			Servicing Liability			Total
Balance as of June 30, 2009	$	(2	)	$	(2	)	$	(4	)
Included in regulatory assets		(1	)		—			(1	)

Balance as of September 30, 2009	$	(3	)	$	(2	)	$	(5	)


Nine Months Ended September 30, 2009 (In millions)	Mark-to-Market Derivatives			Servicing Liability			Total
Balance as of December 31, 2008	$	—		$	(2	)	$	(2	)
Included in regulatory assets		(3	)		—			(3	)

Balance as of September 30, 2009	$	(3	)	$	(2	)	$	(5	)


Three Months Ended September 30, 2008 (In millions)	Mark-to-Market Derivatives			Servicing Liability			Total
Balance as of June 30, 2008	$	—		$	(1	)	$	(1	)
Total realized / unrealized gains included in net income		—			(1	)		(1	)

Balance as of September 30, 2008	$	—		$	(2	)	$	(2	)


Nine Months Ended September 30, 2008 (In millions)	Mark-to-Market Derivatives			Servicing Liability			Total
Balance as of January 1, 2008	$	—		$	(1	)	$	(1	)
Total realized / unrealized gains included in net income		—			(1	)		(1	)

Balance as of September 30, 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 nuclear decommissioning trust 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.

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. For fixed income securities, the trustees receive multiple prices from pricing services, which enable cross-provider validations by the trustees 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.

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. 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. In addition, 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, vintage, 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. However, because these short-term commingled funds are only offered to a limited group of investors and, therefore, not exchanged in an active market, they are categorized in Level 2 in the fair value hierarchy. The objectives of the remaining commingled funds in which Exelon and Generation invest primarily seek to track the performance of certain equity indices, specifically the S&P 500, the Russell 3000 and the Morgan Stanley Capital International EAFE indices, by purchasing equity securities to replicate the capitalization and characteristics of the indices. The fair value of these commingled funds are based on net asset values per fund share (the unit of account), primarily derived from the quoted prices in active markets of the underlying equity securities. However, because the shares of these commingled funds are not publicly quoted, not traded in an active market and are subject to certain restrictions regarding their purchase and sale, the commingled funds are categorized in Level 3. See Note 12 — Asset Retirement Obligations for further discussion on the nuclear decommissioning trust 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 are 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 its 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 14 — 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, and overall generation availability in the Electric Reliability Council of Texas (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.

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

9 Months Ended

Sep. 30, 2009

Notes to Financial Statements [Abstract]

8. 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, coal, natural gas, 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 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 other comprehensive income (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 of the Combined Notes to Consolidated Financial Statements within Exelon’s 2008 Annual Report on Form 10-K. 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, natural gas, coal, oil and emission allowances 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. Exelon seeks to mitigate its commodity price risk through the purchase and sale of electric capacity, energy and fossil fuels, including oil, natural gas, coal and emission allowances. 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 September 30, 2009, the percentage of expected generation hedged was 98% - 100%, 88% - 91%, and 63% - 66% for the remainder of 2009, 2010 and 2011, 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 3 — 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 markup, 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 coincide with ComEd’s remaining auction contracts for energy. 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 3 — 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 generation to Generation through a PPA that expires December 31, 2010. The PPA is not considered a derivative under the current derivative authoritative guidance.

In preparation for the expiration of the PPA, PECO has begun to procure electric generation through a competitive RFP process as outlined in its PAPUC-approved DSP Program, which is further discussed in Note 3 — Regulatory Issues. Based on Pennsylvania legislation and the DSP Program permitting PECO to recover its electric generation procurement costs from retail customers with no markup, PECO’s price risk related to electric generation 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 agreements that are derivatives qualify for the normal purchases and normal sales exception. Additionally, in accordance with the 2008 PAPUC purchased gas cost clause (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 2008 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 20% to 25% of planned gas purchases in support of projected firm sales. The hedging program for gas procurement has no direct impact on PECO’s financial position or results of operations as fuel 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 Risk Management Committee. The proprietary trading activities, which included volumes of 1,645 gigawatt hours (GWhs) and 5,979 GWhs for the three and nine months ended September 30, 2009 and 3,092 GWhs and 6,738 GWhs for the three and nine months ended September 30, 2008, 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 three and nine months ended September 30, 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. The Registrants include 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 nine months ended September 30, 2009:


Income Statement Classification	Loss on Swaps	Gain on Borrowings
Interest expense	$(5)	$5

At September 30, 2009 and December 31, 2008, Exelon had $100 million of notional amounts of fair value hedges outstanding related to interest rate swaps, with fair value assets of $12 million and $17 million, respectively. During the three and nine months ended September 30, 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 September 30, 2009 and December 31, 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 other comprehensive income 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 statement of financial position. 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 September 30, 2009:


Derivatives	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		Intercompany Eliminations (a)			Total Derivatives
Mark-to-market derivative assets (current assets)	$	780		$	1,132		$	302		$	(1,747	)	$	467		$	—		$	—		$	—	$	—		$	467
Mark-to-market derivative assets with affiliate (current assets)		305			—			—			—			305			—			—			—		(305	)		—
Mark-to-market derivative assets (noncurrent assets)		545			655			116			(846	)		470			—			—			12		—			482
Mark-to-market derivative assets with affiliate (noncurrent assets)		780			—			—			—			780			—			—			—		(780	)		—

Total mark-to-market derivative assets	$	2,410		$	1,787		$	418		$	(2,593	)	$	2,022		$	—		$	—		$	12	$	(1,085	)	$	949

Mark-to-market derivative liabilities (current liabilities)	$	(15	)	$	(985	)	$	(268	)	$	1,062		$	(206	)	$	—			—		$	—	$	—		$	(206	)
Mark-to-market derivative liability with affiliate (current liabilities)		—			—			—			—			—			(305	)		—			—		305			—
Mark-to-market derivative liabilities (noncurrent liabilities)		(51	)		(310	)		(103	)		394			(70	)		—			(2	)		—		—			(72	)
Mark-to-market derivative liability with affiliate (noncurrent liabilities)		—			—			—			—			—			(779	)		(1	)		—		780			—

Total mark-to-market derivative liabilities		(66	)		(1,295	)		(371	)		1,456			(276	)		(1,084	)		(3	)		—		1,085			(278	)

Total mark-to-market derivative net assets (liabilities)	$	2,344		$	492		$	47		$	(1,137	)	$	1,746		$	(1,084	)	$	(3)		$	12	$	—		$	671

(a)	Includes current and noncurrent assets for Generation and current and noncurrent liabilities for ComEd of $305 million and $779 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 $374 million and $375 million, respectively, and current and noncurrent liabilities are shown inclusive of collateral of $312 million and $76 million, respectively. The total cash collateral received net of cash collateral posted and offset against mark-to-market assets and liabilities was $1,137 million at September 30, 2009.

(d)

Includes a noncurrent liability for PECO and a noncurrent asset for Generation of $1 million related to the fair value of PECO’s block contracts with Generation. There were no netting adjustments or collateral received as of September 30, 2009. PECO’s block contracts are included in other deferred credits and other liabilities on PECO’s Consolidated Balance Sheets.

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)			Other Derivatives			Proprietary Trading			Collateral and Netting(b)			Subtotal(c)			IL Settlement Swap(a)			Other Derivatives		Intercompany Eliminations(a)			Total Derivatives
Mark-to-market derivative assets (current assets)	$	610		$	1,168		$	375		$	(1,743	)	$	410		$	—		$	—	$	—		$	410
Mark-to-market derivative assets with affiliate (current assets)		111			—			—			—			111			—			—		(111	)		—
Mark-to-market derivative assets (noncurrent assets)		437			552			124			(623	)		490			—			17		—			507
Mark-to-market derivative assets with affiliate (noncurrent assets)		345			—			—			—			345			—			—		(345	)		—

Total mark-to-market derivative assets	$	1,503		$	1,720		$	499		$	(2,366	)	$	1,356		$	—		$	17	$	(456	)	$	917

Mark-to-market derivative liabilities (current liabilities)	$	(47	)	$	(1,167	)	$	(291	)	$	1,291		$	(214	)	$	—		$	—	$	—		$	(214	)
Mark-to-market derivative liability with affiliate (current liabilities)		—			—			—			—			—			(111	)		—		111			—
Mark-to-market derivative liabilities (noncurrent liabilities)		(19	)		(227	)		(100	)		322			(24	)		—			—		—			(24	)
Mark-to-market derivative liability with affiliate (noncurrent liabilities)		—			—			—			—			—			(345	)		—		345			—

Total mark-to-market derivative liabilities		(66	)		(1,394	)		(391	)		1,613			(238	)		(456	)		—		456			(238	)

Total mark-to-market derivative net assets (liabilities)	$	1,437		$	326		$	108		$	(753	)	$	1,118		$	(456	)	$	17	$	—		$	679

(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 $177 million and $252 million, respectively, and current and noncurrent liabilities are shown inclusive of collateral of $274 million and $50 million, respectively. 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.

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 September 30, 2009, Generation had net unrealized pre-tax gains on effective cash-flow hedges of $2,339 million being deferred within accumulated OCI, including approximately $1,084 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 September 30, 2009, approximately $1,069 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 $305 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 2009 through 2011, and the ComEd financial swap contract during 2009 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 three and nine months ended September 30, 2009, amounts reclassified into earnings as a result of the discontinuance of cash-flow hedges were immaterial.

The tables below provide the activity of accumulated OCI related to cash-flow hedges for the three and nine months ended September 30, 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.


Three Months Ended September 30, 2009	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 at June 30, 2009		$	1,512	(a)	$	868
Effective portion of changes in fair value			177	(b)		96
Reclassifications from accumulated OCI to net income	Operating Revenue		(280	)(c)		(225	)
Ineffective portion recognized in income	Purchased Power		1			1

Accumulated OCI derivative gain at September 30, 2009		$	1,410	(a,d)	$	740

(a)

Includes $653 million and $624 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd, and $1 million and $1 million of gains, net of taxes, related to the fair value of the block contracts with PECO as of September 30, 2009 and June 30, 2009, respectively.

(b)	Includes an $85 million gain, net of taxes, of the effective portion of changes in fair value of the five-year financial swap contract with ComEd for the three months ended September 30, 2009.

(c)	Includes a $56 million loss, 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 three months ended September 30, 2009.

(d)	Excludes a $4 million gain, net of taxes, related to interest rate swaps settled in September 2009. See Note 7 – Debt and Credit Agreements for further information.


Nine Months Ended September 30, 2009	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 at December 31, 2008		$	855	(a)	$	563
Effective portion of changes in fair value			1,235	(b)		748
Reclassifications from accumulated OCI to net income	Operating Revenue		(686	)(c)		(577	)
Ineffective portion recognized in income	Purchased Power		6			6

Accumulated OCI derivative gain at September 30, 2009		$	1,410	(a,d)	$	740

(a)

Includes $653 million and $275 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd as of September 30, 2009 and December 31, 2008, respectively, and $1 million, net of taxes, related to the fair value of the block contracts with PECO as of September 30, 2009.

(b)	Includes a $487 million gain, net of taxes, of the effective portion of changes in fair value of the five-year financial swap contract with ComEd for the nine months ended September 30, 2009.

(c)	Includes a $109 million loss, 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 nine months ended September 30, 2009.

(d)	Excludes a $4 million gain, net of taxes, related to interest rate swaps settled in September 2009. See Note 7 — Debt and Credit Agreements for further information.


Three Months Ended September 30, 2008	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 loss at June 30, 2008		$	(1,661	)(a)	$	(1,244	)
Effective portion of changes in fair value			1,513	(b)		1,124
Reclassifications from accumulated OCI to net income	Operating Revenue		205	(c)		187
Ineffective portion recognized in income	Purchased Power		(62	)		(31	)

Accumulated OCI derivative gain (loss) at September 30, 2008		$	(5	)(a)	$	36

(a)	Includes $59 million and $436 million of losses, net of taxes, related to the fair value of the five-year financial swap contract with ComEd as of September 30, 2008 and June 30, 2008, respectively.

(b)	Includes a $358 million gain, net of taxes, of the effective portion of changes in fair value of the five-year financial swap contract with ComEd during the three months ended September 30, 2008.

(c)	Includes a $19 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 during the three months ended September 30, 2008.


Nine Months Ended September 30, 2008	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 loss at December 31, 2007		$	(548	)(a)	$	(292	)
Effective portion of changes in fair value			167	(b)		(26	)
Reclassifications from accumulated OCI to net income	Operating Revenue		388	(c)		366
Ineffective portion recognized in income	Purchased Power		(12	)		(12	)

Accumulated OCI derivative gain (loss) at September 30, 2008		$	(5	)(a)	$	36

(a)	Includes $59 million and $275 million of losses, net of taxes, related to the fair value of the five-year financial swap contract with ComEd as of September 30, 2008 and December 31, 2007, respectively.

(b)	Includes a $193 million gain, net of taxes, of the effective portion of changes in fair value of the five-year financial swap contract with ComEd during the nine months ended September 30, 2008.

(c)	Includes a $23 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 during the nine months ended September 30, 2008.

During the three and nine months ended September 30, 2009, Generation’s cash-flow hedge activity impact to pre-tax earnings based on the reclassification adjustment from accumulated OCI to earnings was a $464 million pre-tax gain and a $1,138 million pre-tax gain, respectively, and a ($341) million and ($645) million pre-tax loss for the three and nine months ended September 30, 2008, 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. During the three and nine months ended September 30, 2009, cash-flow hedge ineffectiveness changed by $2 million and $10 million due primarily to the change in market prices during the period, of which none was related to Generation’s financial swap contract with ComEd. At September 30, 2009, cash-flow hedge ineffectiveness resulted in an adjustment of $5 million to accumulated OCI on the balance sheet in order to reflect the effective portion of derivative gains or losses. During the three months ended September 30, 2008, cash-flow hedge ineffectiveness changed by $103 million due primarily to the change in market prices during the period, of which $51 million was related to Generation’s financial swap contract with ComEd. During the nine months ended September 30, 2008, cash flow ineffectiveness changed by $22 million, none of which was related to Generation’s financial swap contract with ComEd.

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 $371 million pre-tax gain and $958 million pre-tax gain for the three and nine months ended September 30, 2009, respectively, and a ($310) million pre-tax loss and ($608) million pre-tax loss for the three and nine months ended September 30, 2008. Changes in cash-flow hedge ineffectiveness, primarily due to changes in market prices, were $2 million and $10 million for the three and nine months ended September 30, 2009, and $52 million and $22 million for the three and nine months ended September 30, 2008.

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 three and nine months ended September 30, 2009 and 2008, the following net pre-tax mark-to-market gains (losses) relating to changes in the fair values 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 and nuclear decommissioning trust funds in Exelon’s and Generation’s Consolidated Statements of Cash Flows.


	Exelon and Generation
Three Months Ended September 30, 2009	Purchased Power			Fuel			Total
Three Months Ended September 30, 2009	Purchased Power			Fuel			Total
Unrealized mark-to-market gains (losses)	$	81		$	(10	)	$	71
Realized mark-to-market gains		10			47			57

Total net mark-to-market gains	$	91		$	37		$	128


	Exelon and Generation
Nine Months Ended September 30, 2009	Purchased Power			Fuel			Total
Nine Months Ended September 30, 2009	Purchased Power			Fuel			Total
Unrealized mark-to-market gains (losses)	$	211		$	(113	)	$	98
Realized mark-to-market gains (losses)		(72	)		122			50

Total net mark-to-market gains	$	139		$	9		$	148


	Exelon and Generation
Three Months Ended September 30, 2008	Purchased Power			Fuel			Total
Three Months Ended September 30, 2008	Purchased Power			Fuel			Total
Unrealized mark-to-market gains (losses)	$	252		$	(123	)	$	129
Realized mark-to-market gains (losses)		1			(75	)		(74	)

Total net mark-to-market gains (losses)	$	253		$	(198	)	$	55


	Exelon and Generation
Nine Months Ended September 30, 2008	Purchased Power			Fuel			Total
Nine Months Ended September 30, 2008	Purchased Power			Fuel			Total
Unrealized mark-to-market gains	$	137		$	224		$	361
Realized mark-to-market gains (losses)		51			(136	)		(85	)

Total net mark-to-market gains	$	188		$	88		$	276

Proprietary Trading Activities (Exelon and Generation). For the three and nine months ended September 30, 2009 and 2008, Exelon and Generation recognized the following net unrealized mark-to-market gains (losses), net realized mark-to-market gains (losses) and total net mark-to-market gains (losses) (before income taxes) relating to mark-to-market activity on derivative instruments 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 and nuclear decommissioning trust funds in Exelon’s and Generation’s Consolidated Statements of Cash Flows.


	Location on Income Statement	Three Months Ended September 30,						Nine Months Ended September 30,
	Location on Income Statement	2009			2008			2009			2008
Unrealized mark-to-market gains (losses)	Operating Revenue	$	(1	)	$	2		$	2		$	105
Realized mark-to-market losses	Operating Revenue		(21	)		(7	)		(63	)		(30	)

Total net mark-to-market gains (losses)	Operating Revenue	$	(22	)	$	(5	)	$	(61	)	$	75

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, normal purchase normal sales, and applicable payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of September 30, 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 Regional Transmission Organizations (RTOs), Independent System Operators (ISOs) and New York Mercantile Exchange (NYMEX) and Intercontinental Exchange (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 $111 million and $157 million, respectively. See Note 17 – Related-Party Transactions for further information.


Rating as of September 30, 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	$	1,395	$	543	$	852	$	—	$	—
Non-investment grade		7		7		—		—		—
No external ratings
Internally rated — investment grade		30		5		25		—		—
Internally rated — non-investment grade		2		1		1		—		—

Total	$	1,434	$	556	$	878	$	—	$	—


Net Credit Exposure by Type of Counterparty	As of September 30, 2009
Financial institutions	$	313
Investor-owned utilities, marketers and power producers		496
Other		69

Total	$	878

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 credit exposure. As of September 30, 2009, ComEd’s credit exposure to suppliers was immaterial and did not exceed the unsecured levels allowed by contract.

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 3 — 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. Generation supplies electricity to PECO from its portfolio of generation assets, PPAs and other market sources 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. If 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 September 30, 2009, PECO’s credit exposure to suppliers under its electric generation procurement contracts was immaterial and did not exceed unsecured levels allowed by the supplier master agreements.

See Note 3—Regulatory Issues for further information regarding the impact of regulatory matters on PECO’s procurement of electric generation.

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 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 agreements. As of September 30, 2009, PECO had no price exposure under its natural gas supply contracts as the fixed-contract obligation costs are greater than projected market prices.

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

As part of the normal course of business, Generation routinely enters into physical or financially settled contracts for the purchase and sale of electric capacity, energy, fuels and emissions allowances. 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, that is not fully collateralized as of September 30, 2009, was $1,262 million. Generation had the contractual right of offset of $1,068 million related to derivative instruments that are assets with the same counterparty under master netting agreements, resulting in a net liability position of $194 million. 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 $511 million, respectively, as of September 30, 2009, 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 14 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 supplier forward contracts that ComEd entered into with counterparty suppliers, including Generation, collateral postings are one-sided from suppliers. Generation entered into similar supplier forward contracts 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, there are no immediate collateral provisions on either party. However, the swap contract also provides that: (1) if ComEd is downgraded below investment grade by Moody’s Investor Service (Moody’s) or Standard & Poor’s (S&P), or (2) if Generation is downgraded below investment grade by Moody’s or S&P, collateral postings would be required by the applicable 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 September 30, 2009, there was no cash collateral or letters of credit posted between suppliers, including Generation, and ComEd, under any of the above-mentioned contracts. See Note 3 — 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. 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 September 30, 2009, PECO was not required to post collateral for any of these agreements. If the credit-risk-related contingent features underlying these agreements were triggered on September 30, 2009, PECO could have been required to post approximately $35 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 September 30, 2009, Exelon’s interest-rate swap was in an asset position, with a fair value of $12 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 September 30, 2009 and December 31, 2008, $1 million and $5 million, respectively, of cash collateral received, and $1 million of cash collateral sent as of September 30, 2009 was not offset against net derivative positions, because they were not associated with energy-related derivatives.

11. Income Taxes (Exelon, Generation, ComEd and PECO)	9 Months Ended
11. Income Taxes (Exelon, Generation, ComEd and PECO)	Sep. 30, 2009
Notes to Financial Statements [Abstract]
11. Income Taxes (Exelon, Generation, ComEd and PECO)	11. Income Taxes (Exelon, Generation, ComEd and PECO) Exelon’s effective income tax rate from continuing operations for the three and nine months ended September 30, 2009 was 44.1% and 38.6%, as compared to 33.1% and 33.5% for the three and nine months ended September 30, 2008. The increase in the effective tax rate for the three and nine months ended September 30, 2009 was primarily attributable to gains in 2009 compared to losses in 2008 generated in Generation’s nuclear decommissioning trust funds that are taxed at a higher statutory rate than Generation’s remaining income from operations and, to a lesser extent, a decrease in Generation’s Domestic Production Activities Deduction, which decreased primarily as a result of additional deductions for accelerated depreciation and a change in Generation’s tax method of accounting for repair costs. The increase for the nine months ended September 30, 2009 was partially offset by a change in deferred state income taxes. The effective income tax rate for the three months ended September 30, 2009 was further increased as a result of higher state income tax expenses driven by the charge to third quarter 2009 results of operations to reverse the state income tax benefit, previously recognized on the Illinois investment tax credits during the first quarter 2009. Generation’s effective income tax rate from continuing operations for the three and nine months ended September 30, 2009 was 45.8% and 40.0%, as compared to 32.6% and 34.1% for the three and nine months ended September 30, 2008. The increase in Generation’s effective tax rate for the three and nine months ended September 30, 2009 was primarily attributable to gains in 2009 compared to losses in 2008 generated in the nuclear decommissioning trust funds that are taxed at a higher statutory rate than Generation’s remaining income from operations and, to a lesser extent, a decrease in Generation’s Domestic Production Activities Deduction, which decreased primarily as a result of additional deductions for accelerated depreciation and a change in Generation’s tax method of accounting for repair costs. The increase for the nine months ended September 30, 2009 was partially offset by a change in deferred state income taxes. The effective income tax rate for the three months ended September 30, 2009 was further increased as a result of higher state income tax expenses driven by the charge to third quarter 2009 results of operations to reverse the state income tax benefit, previously recognized on the Illinois investment tax credits during the first quarter 2009. ComEd’s effective income tax rate for the three and nine months ended September 30, 2009 was 54.9% and 38.1%, as compared to 36.5% and 37.5% for the three and nine months ended September 30, 2008. For the three months ended September 30, 2009, the increase in the effective tax rate was primarily a result of an increase in state income tax expense driven by the charge to third quarter 2009 results of operations to reverse the state income tax benefit, previously recognized on the Illinois investment tax credits during the first quarter 2009. For the nine months ended September 30, 2009, the increase in the effective tax rate was primarily a result of increased income while permanent differences remained relatively constant. PECO’s effective income tax rate for the three and nine months ended September 30, 2009 was 24.6% and 27.8%, as compared to 32.3% and 31.1% for the three and nine months ended September 30, 2008, respectively. The decrease in the effective tax rate for the three and the nine months ended September 30, 2009 was primarily caused by a decrease in state income tax expense due to higher deductible interest expense and the tax expense recorded in the third quarter of 2008 related to a tax settlement with the Internal Revenue Service (IRS). Accounting for Uncertainty in Income Taxes Exelon, Generation, ComEd and PECO have $1.41 billion, $612 million, $424 million and $347 million, respectively, of unrecognized tax benefits as of September 30, 2009. Exelon’s, Generation’s, ComEd’s and PECO’s uncertain tax positions have not significantly changed since December 31, 2008 except for those relating to the 1999 sale of fossil generating assets discussed below. *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 Internal Revenue Code (the Code). Exelon believes that it was economically compelled to dispose of ComEd’s fossil generating plants as a result of the Illinois Electric Service Customer Choice and Rate Relief Law of 1997 (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 Code. 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 “sale-in, lease-out” (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 does not qualify as a like-kind exchange such that 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 the Appeals Division of the IRS (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 will 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 re-measurement 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 potential of a settlement and determined that there were no new developments during the third quarter of 2009 that led to a re-measurement 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 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 that it is likely that the issue will be fully litigated. Given that Exelon has determined that 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 September 30, 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 Simplified Service Cost Method. A favorable settlement of the tax position related to the competitive transition charges (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 impacted by as much as $300 million (after-tax) related to interest expense. *Competitive Transition Charges (Exelon, ComEd and PECO)* Exelon contends that the 1997 Illinois Act and the 1996 Pennsylvania Electricity Generation Customer Choice and Competition Act (the Pennsylvania 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 competitive transition charges (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 and Exelon has protested the disallowance to IRS Appeals. The years 2002-2006 are currently under IRS audit and Exelon expects the claims for those years to be disallowed when filed. 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 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 Pennsylvania 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 $5.26 billion. PECO has collected approximately $4.2 billion in CTCs for the period 2000 through September 2009 and will continue the collection of 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 the ongoing appeal and determined that there are no new developments that lead to a re-measurement of the amounts recorded. Based on management’s expectations as to the length of the IRS 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. *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 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. *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. During 2008, Generation had several discussions with IRS Appeals but was unable to reach a satisfactory settlement. In November of 2008, Generation received a final determination from 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 Department of Justice 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 will significantly decrease in the next twelve months. Other Tax Matters *Illinois Senate Bill 1544 and Senate Bill 783 (Exelon)* In August 2007, Illinois enacted Senate Bill (SB) 1544, which became effective January 1, 2008. SB 1544 provided for new rules related to the sourcing of receipts from services for Illinois income tax purposes. The rules provide for sourcing receipts from services based upon where the benefit of the service was realized. In January 2008, Illinois enacted SB 783, which amended certain provisions of SB 1544, including the rules pursuant to which receipts from services should be sourced for Illinois income tax purposes. Pursuant to SB 783, receipts from services generally should be sourced based upon where the services are received. SB 783 also expressly provides that the Illinois Department of Revenue shall adopt rules prescribing where utility services are received. On December 26, 2008, the Illinois Department of Revenue proposed regulations prescribing where utility services are received. As discussed above, on February 20, 2009, the Illinois Supreme Court ruled that electricity is tangible personal property and on July 15, 2009 dismissed the Attorney General’s petition for rehearing but modified its decision to apply only prospectively for tax years 2009 and beyond. On August 4, 2009, Exelon filed a Petition for Rehearing with the Illinois Supreme Court. The Petition for Rehearing was denied by the Illinois Supreme Court on September 28, 2009. With respect to the 2008 tax year, Exelon has treated electricity transactions as services for apportionment purposes pursuant to SB 1544 and SB 783. Furthermore, although the proposed regulations have not yet been finalized, they contain the only guidance available to Exelon with respect to the apportionment of its electricity sales for the 2008 tax year; accordingly, Exelon has prepared its 2008 Illinois tax return in a manner consistent with those proposed regulations. *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 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 the third quarter of 2009, Generation, ComEd and PECO recorded an allocation of Federal tax benefits from Exelon under the Tax Sharing Agreement of $58 million, $8 million and $27 million, respectively.

12. Asset Retirement Obligations and Spent Nuclear Fuel Storage (Exelon, Generation, ComEd and PECO)

9 Months Ended

Sep. 30, 2009

Notes to Financial Statements [Abstract]

12. Asset Retirement Obligations and Spent Nuclear Fuel Storage (Exelon, Generation, ComEd and PECO)

12. Asset Retirement Obligations and Spent Nuclear Fuel Storage (Exelon, Generation, ComEd and PECO)

Nuclear Decommissioning Asset Retirement Obligations (ARO)

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. 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.

During the third quarter of 2009, Generation recorded a net decrease in the ARO of $416 million. The reduction of the ARO in 2009 is primarily due to declines in expected long-term escalation rates for energy and labor costs as compared to prior study periods, partially offset by increased costs resulting from updated decommissioning cost studies received for six nuclear units. This overall decrease in the ARO also 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 asset retirement cost balances for Generation’s nuclear generating units that are not subject to regulatory agreements with respect to decommissioning trust funding (the former AmerGen units and the unregulated portions of the Peach Bottom units). During the third quarter of 2008, Generation recorded a net decrease in the ARO of $256 million, primarily due to 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 Department of Energy will establish a repository for and begin accepting spent nuclear fuel (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 its accelerated decommissioning. This decrease in the ARO also 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 asset retirement cost balances for Generation’s nuclear generating units that are not subject to regulatory agreements with respect to decommissioning trust funding. In addition to the $256 million net decrease to the ARO recognized in the third quarter of 2008, additional net decreases to the ARO of $39 million were recorded during the first half of 2008 related to changes to the estimated cash flows of several units. These net decreases to the ARO had no impact on Exelon’s and Generation’s Consolidated Statements of Operations.

The following table provides a rollforward of the nuclear decommissioning ARO reflected on Exelon’s and Generation’s Consolidated Balance Sheets, from December 31, 2008 to September 30, 2009:


	Exelon and Generation
Nuclear decommissioning ARO at December 31, 2008(a)	$	3,485
Accretion expense		157
Decrease due to changes in estimated cash flows		(411	)
Payments to decommission retired plants		(16	)

Nuclear decommissioning ARO at September 30, 2009(a)	$	3,215

(a)	Includes $13 million as the current portion of the ARO at September 30, 2009 and December 31, 2008, which is included in other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets.

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 nuclear decommissioning trust funds exceed the total estimated decommissioning obligation, decommissioning-related activities recognized in the Consolidated Statement of Operations, 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 September 30, 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 obligation reflected on Generation’s Consolidated Balance Sheet at September 30, 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 nuclear decommissioning trust funds exceed or fall short of the total estimated decommissioning obligation, decommissioning-related activities recognized in the Consolidated Statement of Operations 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 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 3 – 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 decommissioning trust funding are reflected in Exelon’s and Generation’s Consolidated Statements of Operations, as there are no regulatory agreements associated with these units.

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 may 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. In its NRC filing, Generation stated that it is evaluating the remedy to be utilized to address the underfunded status and such remedy will be in accordance with NRC regulations and guidance.

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. 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 $59 million as of September 30, 2009. Generation does not expect that any cash contributions to the funds will be required; instead, subject to the board of directors’ approval, 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, subject to board of directors approval, Generation anticipates that it will remedy any underfunded position remaining after full implementation of its funding assurance plan as submitted to and approved by the NRC through the issuance of some form of financial guarantee rather than through cash contributions to the decommissioning trust funds.

Non-Nuclear ARO (Exelon Generation, ComEd and PECO)

ComEd and PECO have ARO primarily associated with the abatement and disposal of equipment and buildings contaminated with asbestos and polychlorinated biphenyls (PCBs). ComEd and PECO periodically monitor and adjust their ARO due to the passage of time and revisions to either the timing or estimated amount for the undiscounted cash flows required to abate and dispose of asbestos and PCBs. In the third quarter of 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.

Generation has ARO 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. During the third quarter of 2009, Generation recorded a decrease in the ARO of $7 million. The reduction of the ARO is due to the declines in expected long-term escalation rates for labor costs as compared to prior study periods. This decrease in the ARO resulted in the recognition of $5 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 asset retirement cost balances for Generation’s fossil and hydroelectric generating sites. During the third quarter 2008, Generation recorded a decrease in the ARO of $10 million. The reduction of the ARO was due to the change in probabilities related to the estimated end-of-life dates for certain fossil facilities. This decrease in the ARO resulted in the recognition of $6 million of income (pre-tax), which was 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 asset retirement cost balances for Generation’s fossil and hydroelectric generating sites. At September 30, 2009 and December 31, 2008, Generation had an ARO balance of $60 million and $64 million, respectively.

Spent Nuclear Fuel Storage

Under the Nuclear Waste Policy Act of 1982 (NWPA), the Department of Energy (DOE) is responsible for the development of a repository for and the disposal of spent nuclear fuel (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 its nuclear generating stations. 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 June 2008, in conjunction with the DOE filing a license application with the NRC for the first national repository for SNF and high-level radioactive waste at Nevada’s Yucca Mountain, the DOE indicated that, based on the time required for the NRC’s review process and the construction of the repository, the earliest the repository could be in operation would be 2020. Also, in January 2009, the DOE issued its Draft National Transportation Plan for the proposed repository at Yucca Mountain. DOE’s press statement accompanying the release of the plan indicated that shipments to the repository are not expected to begin before 2020. Based on the foregoing, Generation has considered the 2020 date as its best estimate of when DOE will begin accepting SNF. Currently, the 2020 date is used in the estimate of Generation’s nuclear asset retirement obligation and the fair value disclosure of its SNF obligation.

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 SNF disposal. Debate surrounding any new strategy likely will address centralized interim storage, permanent storage at multiple sites and/or SNF reprocessing. Because there is no particular date after 2020 that Generation can establish as having a higher probability as the start date for the DOE acceptance of SNF and because management believes that 2020 is a reasonable date for the use of an alternative strategy such as centralized interim storage, Generation continues to use 2020 as its best estimate of when the DOE will begin accepting SNF. Generation performed sensitivity analyses assuming that the estimated date for the DOE acceptance of SNF was delayed to 2025 and 2035 and determined that Generation’s aggregate nuclear asset retirement obligation would be reduced by an immaterial amount in each scenario. See Note 6 – Fair Value of Assets and Liabilities and Notes 12 and 13 of the Combined Notes to Consolidated Financial Statements within Exelon’s 2008 Annual Report on Form 10-K for additional information.

Nuclear Decommissioning Trust Fund Investments

At September 30, 2009 and December 31, 2008, Exelon and Generation had nuclear decommissioning trust fund investments totaling $6,502 million and $5,500 million, respectively.

In the first quarter of 2009, Generation performed a rebalancing of its decommissioning trust fund investments in order to bring the mix of equity and fixed income investments into alignment with targeted ratios. At September 30, 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 decommissioning trust 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. Currently, the weighted average maturity of the securities within the collateral pools is approximately 5 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 September 30, 2009, Generation had $84 million of loaned securities outstanding and held $84 million of related collateral under its lending agreements, representing a decrease in loaned securities outstanding since December 31, 2008 of $296 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 trust funds is included in trust fund earnings and classified as Other, Net in Exelon’s and Generation’s Consolidated Statements of Operations and was not significant during the three and nine months ended September 30, 2009 and 2008.

The following table provides unrealized gains (losses) on decommissioning trust funds for the three and nine months ended September 30, 2009 and 2008:


	Exelon and Generation
	Three Months Ended September 30,					Nine Months Ended September 30,
	2009		2008			2009		2008
Net unrealized gains (losses) on decommissioning trust funds — Regulated Units(a)	$	454	$	(337	)	$	712	$	(672	)
Net unrealized gains (losses) on decommissioning trust funds — Unregulated Units(b)		153		(105	)		204		(204	)

(a)

Generation’s nuclear decommissioning trust funds associated with the former ComEd and former PECO nuclear generating units that are subject to regulatory agreements with respect to nuclear decommissioning trust 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 nuclear decommissioning trust funds that are not subject to a regulatory agreement with respect to nuclear decommissioning trust funding are included within other, net in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

Interest and dividends on nuclear decommissioning trust fund investments are recognized when earned and included in Other, net in Exelon and Generation’s Consolidated Statements of Operations. Interest and dividends earned on the nuclear decommissioning trust fund investments for the regulated units, which are subject to regulatory accounting, are eliminated within Other, net in Exelon and Generation’s Consolidated Statement of Operations.

Refer to Note 17 — Related Party Transactions for information regarding intercompany balances between Generation, ComEd and PECO reflecting the obligation to refund to customers any decommissioning-related assets in excess of the related decommissioning obligations.

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

9 Months Ended

Sep. 30, 2009

Notes to Financial Statements [Abstract]

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

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

For information regarding capital commitments at December 31, 2008, see Note 18 of the Combined Notes to Consolidated Financial Statements within Exelon’s 2008 Annual Report on Form 10-K. All significant contingencies are disclosed below.

Energy Commitments

Generation’s, ComEd’s and PECO’s short and long-term commitments relating to the sale to and purchase of energy, capacity and transmission rights as of September 30, 2009 changed from December 31, 2008 as follows:

•

Generation’s total commitments for future sales of energy to unaffiliated third-party utilities and others increased by approximately $205 million during the nine months ended September 30, 2009, reflecting increases of approximately $599 million, $748 million, $343 million, $88 million and $5 million related to 2010, 2011, 2012, 2013 and 2014 and beyond sales commitments, respectively, offset by the fulfillment of approximately $1,578 million of 2009 commitments during the nine months ended September 30, 2009. The increases were primarily due to increased overall hedging activity in the normal course of business. See Note 8 — Derivative Financial Instruments for additional information regarding Generation’s hedging program.

•

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 megawatts (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. An Order approving the PPA was entered by the Oklahoma Corporation Commission on September 11, 2009. The Order became final in October 2009.

•

In May 2009, ComEd entered into procurement contracts to enable ComEd to meet a portion of its customers’ electricity requirements for the period from June 2009 to May 2011. These contracts resulted in an increase in ComEd’s energy commitments of $88 million for the remainder of 2009, $269 million for 2010 and $31 million for 2011. See Note 3 — Regulatory Issues for further information.

•

In May 2009, ComEd entered into contracts for the procurement of RECs totaling approximately $31 million. Through September 30, 2009, $18 million had been purchased, with $13 million to be purchased by May 31, 2010. See Note 3 — Regulatory Issues for additional information.

•

In June and September 2009, PECO entered into procurement contracts to enable PECO to meet a portion of its customers’ electricity requirements for 2011, 2012 and 2013. PECO’s energy commitments related to these contracts are $594 million for 2011, $294 million for 2012 and $50 million for 2013. See Note 3 — Regulatory Issues for further information.

•

PECO’s AEC purchase commitments were not significant as of December 31, 2008. As of September 30, 2009, PECO’s AEC purchase commitments were $6 million for 2010, $9 million for 2011, 2012 and 2013 and $4 million for 2014. See Note 3 — Regulatory Issues for additional information.

Fuel and Natural Gas Purchase Obligations

Generation’s and PECO’s fuel purchase obligations as of September 30, 2009 changed from December 31, 2008 as follows:

•

Generation’s total fuel purchase obligations for nuclear and fossil generation increased by approximately $4,398 million during the nine months ended September 30, 2009, reflecting increases of approximately $108 million, $453 million, $406 million, $561 million and $3,782 million for 2010, 2011, 2012, 2013 and beyond, respectively, due to contracts entered into in the normal course of business, offset by the fulfillment of approximately $912 million of 2009 commitments during the nine months ended September 30, 2009.

•

PECO’s total natural gas purchase obligations increased by approximately $130 million during the nine months ended September 30, 2009, reflecting increases of $17 million, $41 million, $11 million, $18 million, $15 million and $28 million in 2009, 2010, 2011, 2012, 2013 and 2014 and beyond, respectively, primarily related to increased natural gas purchase commitments made in accordance with PECO’s PAPUC-approved procurement schedule.

Commercial and Construction Commitments

Exelon’s, Generation’s, ComEd’s and PECO’s commercial and construction commitments as of September 30, 2009, representing commitments potentially triggered by future events changed from December 31, 2008 as follows:

•

Exelon’s letters of credit decreased $143 million primarily related to ComEd as discussed below. Guarantees decreased by $194 million predominantly as a result of decreases in Generation’s guarantees as noted below.

•

Generation’s letters of credit increased by $36 million and guarantees decreased by $183 million primarily as a result of energy trading activities and the reorganization of AmerGen, which was merged into Generation effective January 8, 2009.

•

ComEd’s letters of credit decreased by $96 million, primarily due to reduction in the collateral requirement to PJM resulting from a change in the PJM billing cycle.

•

ComEd’s PJM regional transmission expansion plan (RTEP) baseline project commitments decreased by $47 million, $32 million and $5 million for 2009, 2010 and 2013, respectively and increased by $23 million for 2011 and 2012 driven by changes in estimated timing and amount of project spending.

•

PECO’s outstanding letters of credit decreased by $83 million primarily due to the reduction in the collateral requirement with PJM based on an agreement executed in February 2009 between PECO, Generation and PJM that changed the way that PECO and Generation administer their PPA for default service.

•

PECO’s PJM RTEP baseline project commitments increased by $7 million in 2009 due to PJM approved changes to project scope and service dates.

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, Exelon recorded liabilities related to certain indemnifications provided to Dynegy and other guarantees directly resulting from the transaction. As of September 30, 2009, Exelon’s accrued liabilities related to these indemnifications and guarantees were $7 million. 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 September 30, 2009.

Indemnifications Related to Sale of Termoeléctrica del Golfo (TEG) and Termoeléctrica Peñoles (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 guaranty 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 guaranty that is not otherwise subject to a dispute resolution process. Generation’s maximum obligation under the guaranty is $95 million as of September 30, 2009. Generation has not recorded a liability associated with this guarantee. The exposures covered by this guaranty began to expire in 2008.

Environmental Liabilities

General (Exelon, Generation, ComEd and PECO)

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 manufactured gas plant (MGP) activities have or may have resulted in actual site contamination. For almost all of these sites, ComEd or PECO is one of several Potentially Responsible Parties (PRPs) which may be responsible for ultimate remediation of each location. Of the 42 sites identified by ComEd, the Illinois Environmental Protection Agency has approved the clean up of ten sites and of the 27 sites identified by PECO, the Pennsylvania Department of Environmental Protection (PA DEP) has approved the cleanup of 16 sites. Of the remaining sites identified by ComEd and PECO, 24 and nine 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 during the three or nine months ended September 30, 2009. ComEd’s accrual as of September 30, 2009 for these environmental liabilities reflects the cost allocations defined in the agreement. ComEd will continue to pass through to customers these environmental clean up costs pursuant to a rider approved by the ICC as discussed below.

Based on the final order received in ComEd’s 2005 Rate Case, beginning in 2007, 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 15 — 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.

As of September 30, 2009 and December 31, 2008, Exelon, Generation, ComEd and PECO had accrued the following amounts for environmental liabilities:

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

Section 316(b) of the Clean Water Act. In July 2004, the United States Environmental Protection Agency (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 National Pollutant Discharge Elimination System (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.

Due to the regulatory uncertainties, Generation cannot estimate the effect that compliance with the Phase II rule requirements will have on the operation of its generating facilities and its future results of operations, financial condition and cash flows. If the final rule, or interim state requirements under best professional judgment, has performance standards that require the reduction of cooling water intake flow at the plants consistent with closed cycle cooling systems, then there could be a material adverse impact on the operation of the facilities and Exelon’s and Generation’s future results of operations, cash flows and financial positions.

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. Oyster Creek has operated and will continue to operate under the 1994 permit until a new permit is issued. Generation cannot predict with any certainty how the NJDEP will implement its best professional judgment nor how Oyster Creek will be affected by the final regulations once they are issued by the EPA as discussed above. In addition, the cost required to retrofit Oyster Creek with closed cycle cooling, if required by a new permit or the revised EPA regulations, would be material and would therefore negatively impact Generation’s decision to operate the plant after the NJDEP permit and Section 316(b) matters are ultimately 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 Public Service Enterprise Group (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 NJDPES permit while the NJDPES permit renewal application is being reviewed. If application of the final 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.

Nuclear Generating Station Groundwater. On December 16, 2005 and February 27, 2006, the Illinois EPA issued violation notices to Generation alleging violations of state groundwater standards as a result of historical discharges of liquid tritium from a line at the Braidwood Nuclear Generating Station (Braidwood).

In November 2005, Generation discovered that spills from the line in 1996, 1998 and 2000 have resulted in a tritium plume in groundwater that is both on and off the plant site. Levels in portions of the plume exceed Federal limits for drinking water. However, samples from drinking water wells on property adjacent to the plant showed that, with one exception, tritium levels in these wells were at levels that naturally occur. The tritium level in one drinking water well was elevated above levels that occur naturally, but was significantly below the state and Federal drinking water standards, and Generation believes that this level posed no threat to human health. Generation has investigated the causes of the releases and has taken the necessary corrective actions to prevent another occurrence. Generation notified the owners of 14 potentially affected adjacent properties that, upon sale of their property, Generation will reimburse the owners for any diminution in property value caused by the tritium release.

On March 16, 2006, the Attorney General of the State of Illinois and the State’s Attorney for Will County, Illinois filed a civil enforcement action against Exelon, Generation and ComEd in the Circuit Court of Will County relating to the releases of tritium discussed above and alleging that there have been tritium and other non-radioactive wastes discharged from Braidwood in violation of Braidwood’s NPDES permit, the Illinois Environmental Protection Act and regulations of the Illinois Pollution Control Board. The lawsuit seeks the maximum civil penalties allowed, injunctive relief relating to the discontinuation of the liquid tritium discharge line until additional court order, soil and groundwater testing, prevention of future releases and off-site migration, and provision of potable drinking water to area residents. On May 24, 2006, the Circuit Court entered an order resulting in Generation commencing remediation efforts in June 2006 for tritium in groundwater off of plant property. Any civil penalty will not be determined until the consent decree is finalized. Generation is unable to determine the amount of the penalty that it will ultimately be required to pay.

Generation detected small underground tritium leaks at the Dresden Nuclear Generating Station (Dresden) and at the Byron Nuclear Generating Station (Byron) in 2006. Neither of these discharges occurred outside the property lines of the plant, nor does Generation believe either of these matters poses health or safety threats to employees or to the public. Generation identified the source of the leaks and implemented repairs. On March 31, 2006 and April 12, 2006, the Illinois EPA issued a Notice of Violation (NOV) to Generation in connection with the Dresden and Byron leaks. The Illinois EPA has rejected the remediation plans submitted by Generation for each station and is currently pursuing legal action against Generation.

Generation is discussing the violation notices and Illinois Attorney General civil enforcement matters for Braidwood, Dresden and Byron, discussed above, with the Illinois EPA, the Illinois Attorney General and the State’s Attorney for the Counties in which the plants are located. Generation believes that appropriate reserves have been recorded for State of Illinois fines and remediation costs as of September 30, 2009 and December 31, 2008.

As part of its normal operations, Generation performs on-going environmental monitoring at its sites. Generation’s monitoring activities sometimes detect the release of measurable levels of tritium, a weak radioactive isotope of hydrogen that is produced and released at all nuclear sites and also is released naturally through the interaction of sunlight and water molecules. These releases do not pose a threat to Generation’s employees, the public, or the environment. Generation has reported, and may in the future report such tritium releases to soil or groundwater at its stations.

Exelon, Generation or ComEd cannot determine the outcome of the above-described matters but believe their ultimate resolution should not, after consideration of reserves established, have a significant impact on Exelon’s, Generation’s or ComEd’s financial position, results of operations or cash flows.

Cotter Corporation. The 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. The current estimated cost of the anticipated 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 the liability.

Air. During March 2005, the EPA finalized several new rulemakings designed to reduce power plant emissions of SO₂, NO_x and mercury. On July 11, 2008, the U.S. Court of Appeals for the District of Columbia Circuit vacated the Clean Air Interstate Rule (CAIR), which had been promulgated by the EPA to reduce power plant emissions of SO₂ and NO_x. On September 25, 2008, EPA petitioned the Court for re-hearing of the CAIR decision. In response to the September petition, on December 23, 2008, the Court elected to remand the CAIR to the EPA, without invalidating the entire rulemaking, so that 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. In its December opinion, the Court elected not to establish a particular schedule for EPA to revise its rulemaking; however, the Court indicated that its remand did not represent an indefinite stay of the Court’s original opinion and that petitioners retained the right to petition the Court to impose a deadline on the EPA in the event that EPA fails to modify its CAIR regulations as directed by the Court, on a timely basis. The EPA is expected to issue a new proposed CAIR rulemaking in early 2010. At this time, Exelon is unable to predict the exact approach that will be utilized by 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.

On March 5, 2009, the D.C. Circuit Court of Appeals remanded Sierra Club and Environment North Carolina vs. EPA back to the EPA for the EPA to reconsider its denial of North Carolina’s Section 126 petition, originally filed in 2004, that requested that the 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 EPA had originally taken the position that the CAIR would be satisfactory to provide North Carolina with needed upwind emission reductions and deferred action on North Carolina’s petition. With the Court remand of CAIR for revision, the 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. 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 a separate rulemaking issued in March 2005, the EPA finalized the Clean Air Mercury Rule (CAMR), which is a national program to cap mercury emissions from coal-fired generating units starting in 2010, with a second reduction in the mercury emission cap level scheduled for 2018. On February 8, 2008, the U.S. Court of Appeals for the District of Columbia Circuit vacated the CAMR on the basis that the 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 of Appeals’ CAMR decision. The EPA is now expected to propose a new rulemaking, likely in early 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 (PA Mercury Rule) enacted in 2006 at the state level in Pennsylvania. 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. The PA DEP has appealed to the Commonwealth Supreme Court seeking re-instatement of the rule. The nature and extent of future regulatory controls on HAP emissions at electric generation power plants will not be determined until the Federal and state regulations are finalized upon the completion of agency rulemakings and court appeals.

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 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 EPA requested information related to the stations in 2003, and ComEd has been cooperating with the EPA since then. The NOV states that the 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 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 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 EPA since the time of requests for information in 2000, 2001 and 2007. The NOV states that the 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 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 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 in 1997. Both stations are currently owned and operated by Dominion. The EPA requested information related to the stations in 2009, and ComEd has been cooperating with the EPA since the time of that request. The NOV states that the 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 EPA’s enforcement authority under the Clean Air Act.

Under the terms of the sales agreements, 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.

Voluntary Greenhouse Gas Emissions Reductions. Exelon announced on May 6, 2005 that it had established a voluntary goal to reduce its greenhouse gas (GHG) emissions by 8% from 2001 levels by the end of 2008. Exelon made this pledge under the United States EPA’s Climate Leaders program, a voluntary industry-government partnership addressing climate change. As of December 31, 2008, Exelon had achieved its 2008 voluntary GHG reduction goal through its planned GHG management efforts, including the previous closure of older, inefficient fossil power plants, reduced leakage of SF₆, increased use of renewable energy and its current energy efficiency initiatives. On March 12, 2009, Exelon submitted its final GHG inventory documentation, including a third-party verification report, to the EPA for final agency review. On April 6, 2009, the EPA notified Exelon that it had reviewed the documents submitted and confirmed that Exelon had exceeded its voluntary goal. The cost of achieving the voluntary GHG emissions reduction goal did not have a material effect on Exelon’s future competitive position, results of operations, earnings, financial position or cash flows.

On July 15, 2008, Exelon expanded its commitment to GHG reduction with the announcement of a comprehensive business and environmental plan. The plan, Exelon 2020, details an enterprise-wide approach and a host of initiatives being pursued by Exelon to reduce Exelon’s GHG emissions and that of its customers, communities, suppliers and markets. Exelon 2020 sets a goal for Exelon to reduce, offset, or displace more than 15 million metric tons of greenhouse gas emissions per year by 2020 (from 2001 levels).

Through Exelon 2020, Exelon is pursuing three broad strategies: reducing or offsetting its own carbon footprint, helping customers and communities reduce their GHG emissions, and offering more low-carbon electricity in the marketplace. Initiatives to reduce Exelon’s own carbon footprint include reducing building energy consumption by 25%, reducing the vehicle fleet emissions, improving the efficiency of the generation and delivery system for electricity and natural gas, and developing an industry-leading green supply chain. Plans to help customers reduce their GHG emissions include ComEd’s new portfolio of energy efficiency programs, a similar portfolio of energy efficiency programs at PECO to meet the requirements of the recently enacted PA Act 129, the implementation of smart-meters and real-time pricing programs and a broad array of communication initiatives to increase customer awareness of approaches to manage their energy consumption. ComEd and PECO have filed applications with the U.S. Department of Energy seeking matching funds for smart grid investments under the Federal stimulus grant program. See Note 3 — Regulatory Issues for further information regarding the smart grid filings and stimulus grant applications. Finally, Exelon will offer more low-carbon electricity in the marketplace by increasing its investment in renewable power, adding capacity to existing nuclear plants through uprates, and through the potential addition of new low-carbon natural gas and nuclear generation.

Exelon has incorporated Exelon 2020 into its overall business plans and has an organized implementation effort underway. This implementation effort includes a periodic review and refinement of Exelon 2020 initiatives in light of changing market conditions. Exelon has recently completed a periodic review of the original analysis of the costs and abatement potential of various emissions-reducing opportunities and remains committed to achieving the goal put forward in 2008. Specific initiatives and the amount of expenditures to implement the plan will depend on economic and policy developments, and will be made on a project-by-project basis in accordance with Exelon’s normal project evaluation standards.

One of the key policy developments that could affect the Exelon 2020 roadmap is enactment of Federal climate change legislation. Federal 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 6% 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 expected that the Senate committees will review S.1733 in the fall of 2009, and climate change legislation will not be enacted until 2010 at the earliest.

Regulation of GHG emissions under the Clean Air Act. On April 2, 2007, the U.S. Supreme Court issued a decision in the case of Massachusetts v. U. S. Environmental Protection Agency holding that CO2 and other GHG emissions are pollutants subject to regulation under the new motor vehicle provisions of the Clean Air Act. The case was remanded to the EPA for additional rulemaking to determine whether GHG emissions may reasonably be anticipated to endanger public health or welfare, or in the alternative, provide a reasonable explanation why GHG emissions should not be regulated. Possible outcomes from this decision include regulation of GHG emissions from manufacturing plants, including electric generation, transmission and distribution facilities, under a new EPA rule and Federal or state legislation. In response to the Supreme Court decision, on July 11, 2008, the EPA issued an Advance Notice of Proposed Rulemaking (ANPR) to solicit public comments on legal and regulatory analyses and policy alternatives regarding GHG effects and regulation under the Clean Air Act.

On September 22, 2009, the EPA issued final regulations for the reporting of GHG emissions from all industrial sectors of the economy, including electric generating stations. This rulemaking requires that large stationary sources of GHG emissions (greater than 25,000 metric tons per year) begin reporting their 2010 emissions in 2011. The EPA has determined that the reporting rule will cover over 85% of total national U.S. GHG emissions and that emissions data collected will be used to inform future policy decisions.

On April 17, 2008, the EPA issued a proposed endangerment finding under Section 202 of the Clean Air Act regarding GHGs from new motor vehicles. The EPA expects to issue a final endangerment finding and promulgate final regulations for new motor vehicles, in conjunction with the U.S Department of Transportation, by March 2010. While the regulations do not specifically address stationary sources, such as a generating plant, it is the 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 EPA issued proposed regulations for permitting for large stationary sources (greater than 25,000 tons per year of GHG emissions, on a carbon dioxide 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 will likely be addressed either under the Clean Air Act or by new and comprehensive Federal legislation. The Obama administration and the EPA have stated a preference for addressing the issue through Federal legislation. Due to the uncertainty as to the final outcome of Federal climate change legislation or regulations, Exelon cannot definitively estimate the effect of GHG regulation on its operations and its future competitive position, results of operations, cash flows and financial position.

Litigation and Regulatory Matters

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.

At September 30, 2009 and December 31, 2008, Generation had reserved approximately $49 million and $52 million, respectively, in total for asbestos-related bodily injury claims. As of September 30, 2009, approximately $11 million of this amount related to 135 open claims presented to Generation, while the remaining $38 million of the reserve is for estimated future asbestos-related bodily injury claims anticipated to arise through 2050 based on actuarial assumptions and analyses, 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 and 2008, the updates to this reserve did not result in material adjustments.

Exelon

Pension Claim. 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 Employee Retirement Income Security Act (ERISA). The plaintiff seeks compensatory relief from the Plan on behalf of participants who received lump sum distributions since 2001 and injunctive relief with respect to future lump sum distributions. On August 31, 2007, the District Court dismissed the lawsuit in its entirety. On December 21, 2007, the District Court amended its order, in part, to allow 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 dismissal of the plaintiff’s claims and, on July 30, 2009, the plaintiff’s motion requesting rehearing of the case before the entire Seventh Circuit Court of Appeals was denied. In addition, on January 6, 2009, the plaintiff filed a complaint in the District Court challenging the Plan’s denial of his administrative claim. The ultimate outcome of the remaining claim before the District Court is 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 alleges 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 seek declaratory, equitable and monetary relief on behalf of the Savings Plan and participants, including alleged investment losses. On February 21, 2007, the district court granted the defendants’ motion to strike the plaintiffs’ claim for investment losses. On June 27, 2007, the district court granted the plaintiffs’ motion for class certification. On June 28, 2007, the district court granted the defendants’ motion to stay proceedings in this action pending the outcome of the appeal to the U.S. Seventh Circuit Court of Appeals in another case not involving Exelon. In that case, the U.S. District Court for the Western District of Wisconsin dismissed with prejudice substantially similar claims. On February 12, 2009, a panel of the Seventh Circuit Court of Appeals affirmed the district court’s dismissal of that case and, on March 9, 2009, the plaintiffs’ motion requesting a rehearing of that case before the entire Seventh Circuit Court of Appeals was denied. On August 19, 2009, the plaintiffs in the Exelon case filed an amended complaint in the district court, which again alleges that defendants breached fiduciary duties under ERISA by, among other things, permitting the Savings Plan to pay excessive fees and expenses for administrative services. On September 11, 2009, the defendants filed a motion to dismiss the amended complaint and enter judgment in the defendants’ favor. 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, Local 15 of the International Brotherhood of Electrical Workers (IBEW Local 15) filed a demand for arbitration of a grievance challenging certain changes implemented in 2004 to the health care 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 as disputes regarding benefits provided to current retirees are not within the scope of the collective bargaining agreement. On December 3, 2007, the U.S. 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, Generation, ComEd and PECO

General. The Registrants are involved in various other litigation matters that are being defended and handled in the ordinary course of business. The Registrants maintain accruals for such costs that are probable of being incurred and subject to reasonable estimation. The Registrants will record a receivable if they expect to recover costs for these contingencies. The ultimate outcomes of such matters, as well as the matters discussed above, are uncertain and may have a material adverse impact on the Registrants’ results of operations, cash flows or financial positions.

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 North American Electric Reliability Corporation (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. The settlement agreement has been approved by NERC and has been submitted to FERC for final approval. ComEd is awaiting final approval from FERC but does not believe it would result in a material unfavorable impact to ComEd’s consolidated financial statements.

Agreement Related to Sale of Accounts Receivable

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, which PECO accounted for as a sale under the current authoritative guidance related to accounting for transfers and servicing of financial assets. 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 September 30, 2009, PECO was 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 6 — Fair Value of Assets and Liabilities for additional information regarding the servicing liability.

Income Taxes

See Note 11 — Income Taxes for information regarding the Registrants’ income tax refund claims and certain tax positions, including the 1999 sale of fossil generating assets.

15. Supplemental Financial Information (Exelon, Generation, ComEd and PECO)

9 Months Ended

Sep. 30, 2009

Notes to Financial Statements [Abstract]

15. Supplemental Financial Information (Exelon, Generation, ComEd and PECO)

15. Supplemental Financial Information (Exelon, Generation, ComEd and PECO)

Supplemental Statement of Operations Information

The following tables provide additional information regarding the components of depreciation, amortization and accretion, and other, net within the Consolidated Statements of Operations and Comprehensive Income of Exelon, Generation, ComEd and PECO for the three and nine months ended September 30, 2009 and 2008:


Three Months Ended September 30, 2009	Exelon		Generation		ComEd		PECO
Depreciation, amortization and accretion
Property, plant and equipment	$	242	$	74	$	112	$	42
Regulatory assets(a)		243		—		13		230
Nuclear fuel(b)		143		143		—		—
Asset retirement obligation accretion(c)		54		54		—		—

Total depreciation, amortization and accretion	$	682	$	271	$	125	$	272

(a)	For PECO, primarily 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.


Nine Months Ended September 30, 2009	Exelon		Generation		ComEd		PECO
Depreciation, amortization and accretion
Property, plant and equipment	$	716	$	223	$	332	$	121
Regulatory assets(a)		644		—		39		605
Nuclear fuel(b)		415		415		—		—
Asset retirement obligation accretion(c)		160		159		1		—

Total depreciation, amortization and accretion	$	1,935	$	797	$	372	$	726

(a)	For PECO, primarily 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.


Three Months Ended September 30, 2008	Exelon		Generation		ComEd		PECO
Depreciation, amortization and accretion
Property, plant and equipment	$	220	$	58	$	110	$	41
Regulatory assets(a)		211		—		9		202
Nuclear fuel(b)		142		142		—		—
Asset retirement obligation accretion(c)		56		56		—		—

Total depreciation, amortization and accretion	$	629	$	256	$	119	$	243

(a)	For PECO, primarily 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.


Nine Months Ended September 30, 2008	Exelon		Generation		ComEd		PECO
Depreciation, amortization and accretion
Property, plant and equipment	$	669	$	202	$	317	$	118
Regulatory assets(a)		561		—		26		535
Nuclear fuel(b)		320		320		—		—
Asset retirement obligation accretion(c)		175		175		—		—

Total depreciation, amortization and accretion	$	1,725	$	697	$	343	$	653

(a)	For PECO, primarily 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.

The following tables set forth costs for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through a reconcilable automatic adjustment clause for Exelon and ComEd for the three and nine months ended September 30, 2009 and 2008. An equal and offsetting amount has been reflected in operating revenues during the period.


	Exelon and ComEd
(In Millions)	Three Months Ended September 30, 2009		Nine Months Ended September 30, 2009
Operating and maintenance for regulatory required programs
Energy efficiency and demand response programs(a)	$	18	$	41
Purchased power administrative costs		1		3

Total operating and maintenance for regulatory required programs	$	19	$	44


	Exelon and ComEd
(In Millions)	Three Months Ended September 30, 2008		Nine Months Ended September 30, 2008
Operating and maintenance for regulatory required programs
Energy efficiency and demand response programs(a)	$	11	$	16
Purchased power administrative costs		—		1

Total operating and maintenance for regulatory required programs	$	11	$	17

(a)	As a result of the 2007 Illinois Settlement, utilities are required to provide energy efficiency and demand response programs beginning June 1, 2008. See Note 3 — Regulatory Issues for additional information.

The following tables provide additional information regarding the components of other, net within the Consolidated Statements of Operations and Comprehensive Income of Exelon, Generation, ComEd and PECO for the three and nine months ended September 30, 2009 and 2008:


Three Months Ended September 30, 2009	Exelon			Generation			ComEd			PECO
Other, Net
Decommissioning-related activities:
Net realized income on decommissioning trust funds — Regulated Units(a)	$	53		$	53		$	—		$	—
Net realized losses on decommissioning trust funds — Unregulated Units(a)		(3	)		(3	)		—			—
Net unrealized gains on decommissioning trust funds — Regulated Units		454			454			—			—
Net unrealized gains on decommissioning trust funds — Unregulated Units		153			153			—			—
Regulatory offset to decommissioning trust fund-related activities(b)		(406	)		(406	)		—			—

Total decommissioning-related activities		251			251			—			—

Net direct financing lease income		6			—			—			—
Interest income related to uncertain income tax positions(c)		(24	)		(4	)		(23	)		1
Losses on early retirement of debt		(93	)		(57	)		—			—
Other		8			2			4			1

Other, net	$	148		$	192		$	(19	)	$	2

(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 Regulated Units, which are subject to regulatory accounting, including the elimination of net realized income, net unrealized gains and related income taxes. See Notes 6 — Fair Value of Assets and Liabilities and 12 — Asset Retirement Obligations and Spent Nuclear Fuel Storage for additional information regarding the accounting for nuclear decommissioning.

(c)	Primarily includes the reversal of interest income originally recorded in the first quarter at ComEd related to the ITC Illinois Supreme Court Decision. See Note 11 — Income Taxes for information regarding the Registrants’ tax positions.


Nine Months Ended September 30, 2009	Exelon			Generation			ComEd			PECO
Other, Net
Decommissioning-related activities:
Net realized income on decommissioning trust funds — Regulated Units(a)	$	81		$	81		$	—		$	—
Net realized income on decommissioning trust funds — Unregulated Units(a)		16			16			—			—
Net unrealized gains on decommissioning trust funds — Regulated Units		712			712			—			—
Net unrealized gains on decommissioning trust funds — Unregulated Units		204			204			—			—
Regulatory offset to decommissioning trust fund-related activities(b)		(639	)		(639	)		—			—

Total decommissioning-related activities		374			374			—			—

Investment income		1			—			—			1
Net direct financing lease income		19			—			—			—
Interest income related to uncertain income tax positions(c)		51			—			64			4
Other-than-temporary impairment to Rabbi trust investments(d)		(7	)		—			(7	)		—
Losses on early retirement of debt		(93	)		(57	)		—			—
Other		22			8			10			3

Other, net	$	367		$	325		$	67		$	8

(a)	Includes investment income and realized gains and losses on sales of investments of the trust funds.

(b)

(c)	Primarily includes interest income at ComEd from the 2009 re-measurement of income tax uncertainties. See Note 11 — 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 6 — Fair Value of Assets and Liabilities for additional information regarding the impairment.


Three Months Ended September 30, 2008	Exelon			Generation			ComEd		PECO
Other, Net
Decommissioning-related activities:
Net realized losses on decommissioning trust funds — Regulated Units(a)	$	(3	)	$	(3	)	$	—	$	—
Net realized income on decommissioning trust funds — Unregulated Units(a)		5			5			—		—
Net unrealized losses on decommissioning trust funds — Regulated Units		(337	)		(337	)		—		—
Net unrealized losses on decommissioning trust funds — Unregulated Units		(105	)		(105	)		—		—
Regulatory offset to decommissioning trust fund-related activities(b)		273			273			—		—

Total decommissioning-related activities		(167	)		(167	)		—		—

Investment income		2			—			1		1
Net direct financing lease income		6			—			—		—
Interest income related to uncertain income tax positions		(3	)		—			—		2
Other		4			3			2		(1	)

Other, net	$	(158	)	$	(164	)	$	3	$	2

(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 Regulated Units, which are subject to regulatory accounting, including the elimination of net realized losses, net unrealized losses and related income taxes. See Notes 6 — Fair Value of Assets and Liabilities and 12 — Asset Retirement Obligations and Spent Nuclear Fuel Storage for additional information regarding the accounting for nuclear decommissioning.


Nine Months Ended September 30, 2008	Exelon			Generation			ComEd		PECO
Other, Net
Decommissioning-related activities:
Net realized income on decommissioning trust funds — Regulated Units(a)	$	56		$	56		$	—	$	—
Net realized income on decommissioning trust funds — Unregulated Units(a)		9			9			—		—
Net unrealized losses on decommissioning trust funds — Regulated Units		(672	)		(672	)		—		—
Net unrealized losses on decommissioning trust funds — Unregulated Units		(204	)		(204	)		—		—
Regulatory offset to decommissioning trust fund-related activities(b)		488			488			—		—

Total decommissioning-related activities		(323	)		(323	)		—		—

Investment income		9			—			6		3
Net direct financing lease income		18			—			—		—
Interest income related to uncertain income tax positions		13			9			1		9
Income related to the termination of a gas supply guarantee(c)		13			13			—		—
Other		14			9			5		1

Other, net	$	(256	)	$	(292	)	$	12	$	13

(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 Regulated Units, which are subject to regulatory accounting, including the elimination of net realized income, net unrealized losses and related income taxes. See Notes 6 — Fair Value of Assets and Liabilities and 12 — Asset Retirement Obligations and Spent Nuclear Fuel Storage for additional information regarding the accounting for nuclear decommissioning.

(c)	Income related to the termination of a gas supply guarantee to Mystic Development LLC.

Supplemental Cash Flow Information

The following tables provide additional information regarding the components of net fair value changes related to derivatives and nuclear decommissioning trust funds, other non-cash operating activities and changes in other assets and liabilities within the Registrants’ Consolidated Statements of Cash Flows for the nine months ended September 30, 2009 and 2008:


Nine Months Ended September 30, 2009	Exelon			Generation			ComEd			PECO
Net fair value changes related to derivatives and nuclear decommissioning trust funds:
Net mark-to-market gains on derivative transactions	$	(74	)	$	(74	)	$	—		$	—
Net unrealized gains and realized losses on nuclear decommissioning trust fund investments(a)		(183	)		(183	)		—			—

Total net fair value changes related to derivatives and nuclear decommissioning trust funds	$	(257	)	$	(257	)	$	—		$	—

Other non-cash operating activities:
Pension and non-pension postretirement benefits costs	$	404		$	180		$	146		$	36
Equity in losses of unconsolidated affiliates and investments		21			2			—			19
Provision for uncollectible accounts		121			4			63			54
Stock-based compensation costs		54			—			—			—
Other decommissioning-related activity(b)		(143	)		(143	)		—			—
Amortization of energy-related options		37			37			—			—
Asset retirement obligation reduction(c)		(47	)		(47	)		—			—
Amortization of regulatory asset related to debt costs		19			—			16			3
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			—
Other		(7	)		(4	)		3			(3	)

Total other non-cash operating activities	$	464		$	29		$	235		$	107

Changes in other assets and liabilities:
Under/over-recovered energy and transmission costs		38			—			35			3
Other current assets		(127	)		(75	)(f)		1			(45	)(i)
Other noncurrent assets and liabilities		(174	)		(86	)(g)		(58	)(h)		(35	)

Total changes in other assets and liabilities	$	(263	)	$	(161	)	$	(22	)	$	(77	)

(a)	Represents net unrealized gains and realized losses on sales of investments of the trust funds of the Unregulated Units. Net unrealized gains and realized losses on sales of investments of the trust funds of the Regulated Units are eliminated as a result of regulatory accounting.

(b)

Includes the elimination of decommissioning-related activity for the Regulated Units, which are subject to regulatory accounting, including the elimination of operating revenues, ARO accretion, asset retirement cost amortization, investment income and income taxes related to all trust fund activity. See Note 12 of the Combined Notes to Consolidated Financial Statements within Exelon’s 2008 Annual Report on Form 10-K for additional information regarding the accounting for nuclear decommissioning.

(c)	Represents the reduction in the ARO in excess of the existing asset retirement cost 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 6 — Fair Value of Assets and Liabilities for additional information regarding the impairment.

(f)	Relates primarily to the purchase of energy-related options and prepaid assets.

(g)	Relates primarily to the purchase of long-term fuel options.

(h)	Relates primarily to a decrease in interest payable associated with the re-measurement of uncertain income tax positions. See Note 11 — Income Taxes for additional information.

(i)	Relates primarily to prepaid utility taxes.


Nine Months Ended September 30, 2008	Exelon			Generation			ComEd			PECO
Net fair value changes related to derivatives and nuclear decommissioning trust funds:
Net mark-to-market gains on derivative transactions	$	(352	)	$	(350	)	$	—		$	—
Net unrealized and realized losses on nuclear decommissioning trust fund investments(a)		237			237			—			—

Total net fair value changes related to derivatives and nuclear decommissioning trust funds	$	(115	)	$	(113	)	$	—		$	—

Other non-cash operating activities:
Pension and non-pension postretirement benefits costs	$	237		$	104		$	76		$	24
Equity in losses of unconsolidated affiliates and investments		19			1			7			11
Provision for uncollectible accounts		200			16			59			136
Stock-based compensation costs		54			—			—			—
Other decommissioning-related activity(b)		122			122			—			—
Amortization of energy-related options		(6	)		(6	)		—			—
Amortization of regulatory asset related to debt costs		20			—			17			3
Amortization of the regulatory liability related to the PURTA tax settlement(c)		(27	)		—			—			(27	)
Net impact of the 2007 distribution rate case order(d)		22			—			22			—
Other		17			(3	)		16			5

Total other non-cash operating activities	$	658		$	234		$	197		$	152

Changes in other assets and liabilities:
Under/over-recovered energy and transmission costs		(20	)		—			(2	)		(18	)
Other current assets		(50	)		(71	)(e)		14			8	(g)
Other noncurrent assets and liabilities		(378	)		(292	)(f)		(5	)		(6	)

Total changes in other assets and liabilities	$	(448	)	$	(363	)	$	7		$	(16	)

(a)	Represents net unrealized losses and realized losses on sales of investments of the trust funds of the Unregulated Units. Net unrealized losses and realized losses on sales of investments of the trust funds of the Regulated Units are eliminated as a result of regulatory accounting.

(b)

(c)

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.

(d)

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 3 — Regulatory Issues for more information.

(e)	Relates primarily to the purchase of energy-related options and prepaid assets.

(f)	Relates primarily to the purchase of long-term fuel options.

(g)	Relates primarily to prepaid utility taxes.

Supplemental Balance Sheet Information

The following tables provide information about the regulatory assets and liabilities of Exelon, ComEd and PECO as of September 30, 2009 and December 31, 2008:


September 30, 2009	Exelon		ComEd		PECO
Regulatory assets
Competitive transition charge	$	1,066	$	—	$	1,066
Pension and other postretirement benefits		2,731		—		21
Deferred income taxes		839		18		821
Debt costs		151		131		20
Severance		100		100		—
Conditional asset retirement obligations		66		50		16
MGP remediation costs		121		80		41
Rate case costs		10		9		1
RTO start-up costs		13		13		—
Financial swap with Generation — noncurrent		—		779		—
Under-recovered universal service fund costs(a)		2		—		2
DSP Program electric procurement contracts(b)		1		—		3
Other		37		11		25

Noncurrent regulatory assets		5,137		1,191		2,016
Financial swap with Generation — current		—		305		—
Under-recovered energy and transmission costs current asset		27		27		—

Total regulatory assets	$	5,164	$	1,523	$	2,016

Regulatory liabilities
Nuclear decommissioning	$	2,152	$	1,860	$	292
Removal costs		1,201		1,201		—
Deferred taxes		22		—		—
Over-recovered universal service fund costs(a)		2		—		2
Energy efficiency and demand response programs		18		17		1

Noncurrent regulatory liabilities		3,395		3,078		295
Over-recovered energy and transmission costs current liability(c)		20		5		15

Total regulatory liabilities	$	3,415	$	3,083	$	310

(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 September 30, 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 September 30, 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)

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. These 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 3 — 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		—
Conditional 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)

The following tables provide information regarding accumulated depreciation and the allowance for uncollectible accounts as of September 30, 2009 and December 31, 2008:


September 30, 2009	Exelon			Generation			ComEd		PECO
Property, plant and equipment:
Accumulated depreciation	$	8,836	(a)	$	4,155	(a)	$	2,029	$	2,420

Accounts receivable:
Allowance for uncollectible accounts		240			34			77		129

(a)	Includes accumulated amortization of nuclear fuel in the reactor core of $1,431 million.


December 31, 2008	Exelon			Generation			ComEd		PECO
Property, plant and equipment:
Accumulated depreciation	$	8,242	(a)	$	3,812	(a)	$	1,866	$	2,345

Accounts receivable:
Allowance for uncollectible accounts		238			30			57		151

(a)	Includes accumulated amortization of nuclear fuel in the reactor core of $1,214 million.

The following tables provide information regarding Exelon’s and Generation’s option premiums as of September 30, 2009 and December 31, 2008:


Exelon and Generation	September 30, 2009		December 31, 2008
Other current assets:
Option premiums	$	144	$	308

Other current liabilities:
Option premiums		192		267

The following tables provide information about accumulated other comprehensive income (loss) recorded (after tax) within Exelon’s Consolidated Balance Sheets as of September 30, 2009 and December 31, 2008:


September 30, 2009	Exelon			Generation		ComEd		PECO
Accumulated other comprehensive income(loss)
Minimum pension liability	$	(224	)	$	—	$	—	$	—
Adjustment to adopt defined benefit pension and other postretirement plans accounting guidance		(1,268	)		—		—		—
Net unrealized gain on cash-flow hedges		740			1,414		—		1
Pension and non-pension postretirement benefit plans		(1,223	)		—		—		—
Unrealized gain on marketable securities		2			—		2		—

Total accumulated other comprehensive income (loss)	$	(1,973	)	$	1,414	$	2	$	1


December 31, 2008	Exelon			Generation			ComEd			PECO
Accumulated other comprehensive income (loss)
Minimum pension liability	$	(224	)	$	—		$	—		$	—
Adjustment to adopt defined benefit pension and other postretirement plans accounting guidance		(1,268	)		2			—			—
Net unrealized gain on cash-flow hedges		564			855			—			2
Pension and non-pension postretirement benefit plans		(1,317	)		(22	)		—			—
Unrealized loss on marketable securities		(6	)		—			(5	)		—

Total accumulated other comprehensive income (loss)	$	(2,251	)	$	835		$	(5	)	$	2

17. Related-Party Transactions (Exelon, Generation, ComEd and PECO)

9 Months Ended

Sep. 30, 2009

Notes to Financial Statements [Abstract]

17. Related-Party Transactions (Exelon, Generation, ComEd and PECO)

Exelon

The financial statements of Exelon include related-party transactions as presented in the tables below:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
Operating revenues from affiliates
ComEd Transitional Funding Trust(a)	$	—		$	1		$	—		$	2
PETT		1			1			2			3
ComEd(b)		(4	)		—			—			—
PECO(b)		7			—			9			—
Other		—			—			—			1

Total operating revenues from affiliates	$	4		$	2		$	11		$	6

Fuel purchases from related parties
Keystone Fuels, LLC	$	16		$	20		$	46		$	52
Conemaugh Fuels, LLC		16			16			52			42

Total fuel purchases from related parties	$	32		$	36		$	98		$	94

Interest expense to affiliates, net
ComEd Transitional Funding Trust(a)	$	—		$	1		$	—		$	6
ComEd Financing II(c)		—			—			—			2
ComEd Financing III		3			3			10			10
PETT		11			24			43			80
PECO Trust III		2			2			5			5
PECO Trust IV		1			1			4			4
Other		1			—			—			(1	)

Total interest expense to affiliates, net	$	18		$	31		$	62		$	106

Equity in losses of unconsolidated affiliates and investments
ComEd Funding LLC(a)	$	—		$	(2	)	$	—		$	(7	)
PETT		(6	)		(4	)		(19	)		(11	)
NuStart Energy Development, LLC		(1	)		—			(2	)		(1	)
Other		(1	)		—			—			—

Total equity in losses of unconsolidated affiliates and investments	$	(8	)	$	(6	)	$	(21	)	$	(19	)

(a)

In the fourth quarter of 2008, ComEd fully paid its long-term debt obligations to the ComEd Transitional Funding Trust and received its current receivable from the ComEd Transitional Funding Trust. ComEd Funding LLC liquidated its investment in the ComEd Transitional Funding Trust and ComEd liquidated its investment in ComEd Funding LLC.

(b)	The intersegment profit associated with Generation’s sale of RECs to ComEd and AECs to PECO is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. See Note 3 — Regulatory Issues for additional information on RECs and AECs.

(c)	ComEd Financing II was liquidated and dissolved upon repayment of the debt in 2008.


	As of September 30, 2009		As of December 31, 2008
Investments in affiliates
ComEd Financing III	$	6	$	6
PETT		10		30
PECO Energy Capital Corporation		4		4
PECO Trust IV		5		5

Total investments in affiliates	$	25	$	45

Payables to affiliates (current)
ComEd Financing III	$	1	$	4
PECO Trust III		2		1
PECO Trust IV		2		—

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		591		1,124
PECO Trust III		81		81
PECO Trust IV		103		103

Total long-term debt due to financing trusts	$	981	$	1,514

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:


	Three Months Ended September 30,					Nine Months Ended September 30,
	2009			2008		2009			2008
Operating revenues from affiliates
ComEd(a)	$	349		$	413	$	1,138		$	1,124
PECO(b)		562			601		1,549			1,603

Total operating revenues from affiliates	$	911		$	1,014	$	2,687		$	2,727

Fuel expense from related parties
PECO	$	—		$	—	$	1		$	1
Keystone Fuels, LLC		16			20		46			52
Conemaugh Fuels, LLC		16			16		52			42

Total fuel purchases from related parties	$	32		$	36	$	99		$	95

Operating and maintenance from affiliates
ComEd(c)	$	1		$	—	$	2		$	1
PECO(c)		1			2		5			6
BSC(d)		68			66		228			205

Total operating and maintenance from affiliates	$	70		$	68	$	235		$	212

Equity in losses of investments
NuStart Energy Development, LLC	$	(1	)	$	—	$	(2	)	$	(1	)

Total equity in losses of investments	$	(1	)	$	—	$	(2	)	$	(1	)

Cash distribution paid to member	$	1,126		$	253	$	1,800		$	1,244
Contribution from member	$	58		$	86	$	58		$	86


	As of September 30, 2009		As of December 31, 2008
Market-to-market derivative assets with affiliate (current)
ComEd(e)	$	305	$	111
Receivables from affiliates (current)
ComEd(a)(f)(g)		111		151
PECO(b)		157		126

Total receivables from affiliates (current)	$	268	$	277

Receivable from affiliate (noncurrent)
Exelon(h)	$	1	$	1
Market-to-market derivative assets with affiliate (noncurrent)
ComEd(e)	$	779	$	345
PECO(k)		1		—
Prepaid voluntary employee beneficiary association trust
Generation(i)	$	—	$	2
Payables to affiliates (current)
Exelon(h)	$	8	$	44
BSC(d)		32		34

Total payables to affiliates (current)	$	40	$	78

Payables to affiliates (noncurrent)
ComEd decommissioning(j)	$	1,861	$	1,289
PECO decommissioning(j)		292		47

Total payables to affiliates (noncurrent)	$	2,153	$	1,336

(a)

Generation has a supplier forward contract 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 3 — 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 of the Combined Notes to Consolidated Financial Statements within Exelon’s 2008 Annual Report on Form 10-K for more information regarding the PPA. Generation has a five-year agreement with PECO to sell AECs. See Note 3 — 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)	Represents the fair value of Generation’s five-year financial swap contract with ComEd.

(f)

Under the Illinois Settlement Legislation, Generation is responsible to contribute to rate relief programs for ComEd customers, which are issued through ComEd. As of September 30, 2009 and December 31, 2008, Generation had a $1 million and $10 million payable, respectively, to ComEd. See Note 3 — Regulatory Issues for additional information.

(g)	As of September 30, 2009, Generation had a $36 million receivable from ComEd associated with the completed portion of the financial swap contract entered into as part of the Illinois Settlement. See Note 3 — Regulatory Issues and Note 8 — Derivative Financial Instruments for additional information.

(h)	In order to facilitate payment processing, Exelon processes certain invoice payments on behalf of Generation.

(i)

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.

(j)

Generation has long-term payables to ComEd and PECO as a result of the nuclear decommissioning contractual construct whereby, to the extent nuclear decommissioning trust 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 12 of the Combined Notes to Consolidated Financial Statements within Exelon’s 2008 Annual report on Form 10-K for additional information.

(k)	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:


	Three Months Ended September 30,					Nine Months Ended September 30,
	2009		2008			2009		2008
Operating revenues from affiliates
Generation	$	1	$	—		$	2	$	1
ComEd Transitional Funding Trust(a)		—		1			—		2

Total operating revenues from affiliates	$	1	$	1		$	2	$	3

Purchased power from affiliate
Generation(b)	$	353	$	413		$	1,138	$	1,124
Operating and maintenance from affiliate
BSC(c)	$	39	$	41		$	128	$	127
Interest expense to affiliates, net
ComEd Transitional Funding Trust(a)	$	—	$	1		$	—	$	6
ComEd Financing II(a)		—		—			—		2
ComEd Financing III		3		3			10		10

Total interest expense to affiliates, net	$	3	$	4		$	10	$	18

Equity in losses of unconsolidated affiliate
ComEd Funding LLC(a)	$	—	$	(2	)	$	—	$	(7	)
Capitalized costs
BSC(c)	$	18	$	14		$	49	$	41
Cash dividends paid to parent	$	60	$	—		$	180	$	—
Contribution from parent	$	8	$	13		$	8	$	13


	As of September 30, 2009		As of December 31, 2008
Prepaid voluntary employee beneficiary association trust(d)	$	6	$	9
Investment in affiliate(e)
ComEd Financing III		6		6
Receivable from affiliates (noncurrent)
Generation(g)	$	1,861	$	1,289
Other		2		2

Total receivable from affiliates (noncurrent)	$	1,863	$	1,291

Payables to affiliates (current)
Generation(b)(h)(i)	$	111	$	151
BSC(c)		22		22
ComEd Financing III		1		4
Other		1		2

Total payables to affiliates (current)	$	135	$	179

Mark-to-market derivative liability with affiliate (current)
Generation(f)	$	305	$	111
Mark-to-market derivative liability with affiliate (noncurrent)
Generation(f)	$	779	$	345
Long-term debt to ComEd financing trust
ComEd Financing III	$	206	$	206

(a)	In the fourth quarter of 2008, ComEd fully paid its long-term debt obligations to the ComEd Transitional Funding Trust. 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 supplier forward contract 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 3 — 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 September 30, 2009, ComEd had a $36 million payable to Generation associated with the completed portion of the financial swap contract entered into as part of the Illinois Settlement. See Note 3 — Regulatory Issues and Note 8 — 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 September 30, 2009 and December 31, 2008, ComEd had a $1 million and $10 million receivable, respectively, from Generation. See Note 3 — Regulatory Issues for additional information.

PECO

The financial statements of PECO include related-party transactions as presented in the tables below:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
Operating revenues from affiliates
Generation(a)	$	1		$	2		$	5		$	7
PETT(b)		1			1			2			3

Total operating revenues from affiliates	$	2		$	3		$	7		$	10

Purchased power from affiliate
Generation(c)	$	555		$	600		$	1,539		$	1,602
Operating and maintenance from affiliates
BSC(d)	$	22		$	22		$	71		$	69
Generation		—			1			1			1

Total operating and maintenance from affiliates	$	22		$	23		$	72		$	70

Interest expense to affiliates, net
PETT	$	11		$	24		$	43		$	80
PECO Trust III		2			2			5			5
PECO Trust IV		1			1			4			4
Other		—			1			—			1

Total interest expense to affiliates, net	$	14		$	28		$	52		$	90

Equity in losses of unconsolidated affiliates
PETT	$	(6	)	$	(4	)	$	(19	)	$	(11	)
Capitalized costs
BSC(d)	$	6		$	(1	)	$	17		$	8
Cash dividends paid to parent	$	94		$	146		$	247		$	382
Repayment of receivable from parent	$	80		$	71		$	240		$	213
Contribution from parent	$	27		$	36		$	27		$	36


	As of September 30, 2009		As of December 31, 2008
Prepaid voluntary employee beneficiary association trust(e)	$	1	$	2
Investments in affiliates
PETT	$	10	$	30
PECO Energy Capital Corporation		4		4
PECO Trust IV		5		5

Total investments in affiliates	$	19	$	39

Receivable from affiliate (noncurrent)
Generation decommissioning(f)	$	292	$	47
Mark-to-market derivative liability with affiliate (noncurrent)
Generation(h)		1		—
Payables to affiliates (current)
Generation(i)	$	157	$	126
BSC(d)		14		16
Exelon		1		1
PECO Trust III		2		1
PECO Trust IV		2		—

Total payables to affiliates (current)	$	176	$	144

Long-term debt to PETT and other financing trusts (including due within one year)
PETT	$	591	$	1,124
PECO Trust III		81		81
PECO Trust IV		103		103

Total long-term debt to financing trusts	$	775	$	1,308

Shareholders’ equity — receivable from parent(g)	$	260	$	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. The mark-to-market derivative liability related to PECO’s block contracts is included in other deferred credits and other liabilities on PECO’s Consolidated Balance Sheets.

(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 3 — Regulatory Issues for additional information on AECs.

Consolidated Statement of Changes in Equity - USD ($) shares in Thousands, $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2009	Sep. 30, 2009
EXELON CORP
Accumulated Other Comprehensive Income (Loss)
Beginning Balance		$ 11,047
Net income	$ 757	2,126
Long-term incentive plan activity		80
Common stock dividends		(1,041)
Other comprehensive income, net of income taxes	(102)	278
Ending Balance	12,490	12,490
EXELON GENERATION CO LLC
Accumulated Other Comprehensive Income (Loss)
Beginning Balance		6,566
Net income	657	1,697
Distribution to member		(1,800)
Allocation of tax benefit from member		58
Transfer of AmerGen pension and non-pension postretirement benefit plans to Exelon, net of income taxes of $17		20
Other comprehensive income, net of income taxes	(98)	559
Ending Balance	7,100	7,100
COMMONWEALTH EDISON CO
Accumulated Other Comprehensive Income (Loss)
Beginning Balance		6,735
Net income	46	275
Appropriation of retained earnings for future dividends		0
Common stock dividends		(180)
Allocation of tax benefit from parent		8
Other comprehensive income, net of income taxes	2	7
Ending Balance	6,845	6,845
PECO ENERGY CO
Accumulated Other Comprehensive Income (Loss)
Beginning Balance		2,182
Net income	92	275
Common stock dividends		(247)
Preferred security dividends		(3)
Repayment of receivable from parent		240
Allocation of tax benefit from parent		27
Other comprehensive income, net of income taxes	(1)	(1)
Ending Balance	$ 2,473	$ 2,473
Common Stock \| EXELON CORP
Accumulated Other Comprehensive Income (Loss)
Beginning Balance		692,953
Long-term incentive plan activity		1,191
Ending Balance	694,144	694,144
Beginning Balance		$ 8,816
Long-term incentive plan activity		80
Ending Balance	$ 8,896	8,896
Common Stock \| COMMONWEALTH EDISON CO
Accumulated Other Comprehensive Income (Loss)
Beginning Balance		1,588
Ending Balance	1,588	1,588
Common Stock \| PECO ENERGY CO
Accumulated Other Comprehensive Income (Loss)
Beginning Balance		2,291
Allocation of tax benefit from parent		27
Ending Balance	2,318	2,318
Membership Interest \| EXELON GENERATION CO LLC
Accumulated Other Comprehensive Income (Loss)
Beginning Balance		3,407
Allocation of tax benefit from member		58
Ending Balance	3,465	3,465
Treasury Stock \| EXELON CORP
Accumulated Other Comprehensive Income (Loss)
Beginning Balance		(2,338)
Ending Balance	(2,338)	(2,338)
Receivable from Parent \| PECO ENERGY CO
Accumulated Other Comprehensive Income (Loss)
Beginning Balance		(500)
Repayment of receivable from parent		240
Ending Balance	(260)	(260)
Retained Earnings \| EXELON CORP
Accumulated Other Comprehensive Income (Loss)
Beginning Balance		6,820
Net income		2,126
Common stock dividends		(1,041)
Ending Balance	7,905	7,905
Retained Earnings \| EXELON GENERATION CO LLC
Accumulated Other Comprehensive Income (Loss)
Beginning Balance		2,323
Net income		1,697
Distribution to member		(1,800)
Ending Balance	2,220	2,220
Retained Earnings \| PECO ENERGY CO
Accumulated Other Comprehensive Income (Loss)
Beginning Balance		389
Net income		275
Common stock dividends		(247)
Preferred security dividends		(3)
Ending Balance	414	414
Other Paid-In Capital \| COMMONWEALTH EDISON CO
Accumulated Other Comprehensive Income (Loss)
Beginning Balance		4,982
Allocation of tax benefit from parent		8
Ending Balance	4,990	4,990
Retained (Deficit) Earnings Unappropriated \| COMMONWEALTH EDISON CO
Accumulated Other Comprehensive Income (Loss)
Beginning Balance		(1,639)
Net income		275
Appropriation of retained earnings for future dividends		(275)
Ending Balance	(1,639)	(1,639)
Retained Earnings Appropriated \| COMMONWEALTH EDISON CO
Accumulated Other Comprehensive Income (Loss)
Beginning Balance		1,809
Appropriation of retained earnings for future dividends		275
Common stock dividends		(180)
Ending Balance	1,904	1,904
Accumulated Other Comprehensive (Loss) Income \| EXELON CORP
Accumulated Other Comprehensive Income (Loss)
Beginning Balance		(2,251)
Other comprehensive income, net of income taxes		278
Ending Balance	(1,973)	(1,973)
Accumulated Other Comprehensive (Loss) Income \| EXELON GENERATION CO LLC
Accumulated Other Comprehensive Income (Loss)
Beginning Balance		835
Transfer of AmerGen pension and non-pension postretirement benefit plans to Exelon, net of income taxes of $17		20
Other comprehensive income, net of income taxes		559
Ending Balance	1,414	1,414
Accumulated Other Comprehensive (Loss) Income \| COMMONWEALTH EDISON CO
Accumulated Other Comprehensive Income (Loss)
Beginning Balance		(5)
Other comprehensive income, net of income taxes		7
Ending Balance	2	2
Accumulated Other Comprehensive (Loss) Income \| PECO ENERGY CO
Accumulated Other Comprehensive Income (Loss)
Beginning Balance		2
Other comprehensive income, net of income taxes		(1)
Ending Balance	1	1
Noncontrolling Interest \| EXELON GENERATION CO LLC
Accumulated Other Comprehensive Income (Loss)
Beginning Balance		1
Ending Balance	$ 1	$ 1

Consolidated Statement of Changes in Equity (Parenthetical) $ in Millions	9 Months Ended
	Sep. 30, 2009 USD ($)
EXELON CORP
Statement [Line Items]
Other comprehensive income, income taxes	$ 199
EXELON GENERATION CO LLC
Statement [Line Items]
Transfer of AmerGen pension and non-pension postretirement benefit plans to Exelon, income taxes	17
Other comprehensive income, income taxes	368
COMMONWEALTH EDISON CO
Statement [Line Items]
Other comprehensive income, income taxes	(5)
PECO ENERGY CO
Statement [Line Items]
Other comprehensive income, income taxes	$ 0

Document Information	9 Months Ended
Document Information	Sep. 30, 2009
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2009

Entity Information	9 Months Ended
Entity Information	Sep. 30, 2009 shares
Trading Symbol	EXC
Entity Registrant Name	EXELON CORP
Entity Central Index Key	0001109357
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding	659,377,386
COMMONWEALTH EDISON CO
Entity Registrant Name	COMMONWEALTH EDISON CO
Entity Central Index Key	0000022606
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding	127,016,519
PECO ENERGY CO
Entity Registrant Name	PECO ENERGY CO
Entity Central Index Key	0000078100
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding	170,478,507
EXELON GENERATION CO LLC
Entity Registrant Name	EXELON GENERATION CO LLC
Entity Central Index Key	0001168165
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding	0

Consolidated Balance Sheets (Parenthetical) - EXELON CORP - $ / shares shares in Millions	Sep. 30, 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	659	658
Treasury stock, shares held	35	35

1. Basis of Presentation (Exelon, Generation, ComEd and PECO)	9 Months Ended
	Sep. 30, 2009
Notes to Financial Statements [Abstract]
1. Basis of Presentation (Exelon, Generation, ComEd and PECO)	1. Basis of Presentation (Exelon, Generation, ComEd and PECO) Exelon Corporation (Exelon) is a utility services holding company engaged, through its subsidiaries, in the generation and energy delivery businesses. The generation business consists of the electric generating facilities, the wholesale energy marketing operations and competitive retail supply operations of Exelon Generation Company, LLC (Generation). The energy delivery businesses include the purchase and regulated retail sale of electricity and the provision of distribution and transmission services by Commonwealth Edison Company (ComEd) in northern Illinois, including the City of Chicago, and by PECO Energy Company (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. Exelon’s corporate operations, some of which are performed through its business services subsidiary, Exelon Business Services Company, LLC (BSC), provide Exelon’s 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 September 30, 2009, as equity, and PECO’s preferred securities as preferred securities of subsidiary in its consolidated financial statements. Generation owns 100% of all of its significant consolidated subsidiaries, either directly or indirectly, except for Exelon SHC, LLC, of which Generation owns 99% and the remaining 1% is indirectly owned by Exelon, which is eliminated in Exelon’s consolidated financial statements. AmerGen Energy Company, LLC (AmerGen), formerly a wholly owned subsidiary of Generation through January 8, 2009, owned and operated the Clinton Nuclear Power Station (Clinton), Three Mile Island (TMI) Unit No. 1 and the Oyster Creek Generating Station (Oyster Creek). Effective January 8, 2009, AmerGen was dissolved and the operating licenses for Clinton, TMI and Oyster Creek were transferred to Generation, which continues to operate 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. The accompanying consolidated financial statements as of September 30, 2009 and 2008 and for the three and nine months then ended are unaudited but, in the opinion of the management of each of Exelon, Generation, ComEd and PECO (collectively, Registrants), include all adjustments that are considered necessary for a fair presentation of its respective financial statements in accordance with accounting principles generally accepted in the United States of America (GAAP). All adjustments are of a normal, recurring nature, except as otherwise disclosed. Certain prior year amounts in Operating Activities in Exelon’s, Generation’s, ComEd’s, and PECO’s Consolidated Statements of Cash Flows, in Financing Activities in PECO’s Consolidated Statement of Cash Flows and in Exelon’s and ComEd’s Consolidated Statements of Operations 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. The December 31, 2008 Consolidated Balance Sheets were taken from audited financial statements. The Registrants performed an evaluation of subsequent events for the accompanying financial statements and notes included in Part 1, ITEM I of this report through October 23, 2009, 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 September 30, 2009. These Combined Notes to Consolidated Financial Statements have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC) for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations. These notes should be read in conjunction with the Notes to Consolidated Financial Statements of Exelon, Generation, ComEd and PECO included in ITEM 8 of their 2008 Annual Report on Form 10-K. *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 variable interest entity (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 method of accounting. Generation enters into power purchase agreements (PPAs) with the objective of obtaining low-cost energy supply sources to meet its physical delivery obligations to customers, including ComEd and PECO. Several of Generation’s long-term PPAs have been determined to be operating leases, which are not considered variable interests. Generation’s PPAs that are not deemed to be operating leases are typically either non-derivatives or derivatives that qualify for the normal purchases and normal sales scope exception and are not marked-to-market. Generation has evaluated these PPAs and determined that it either has no variable interest in the PPA counterparties or, where Generation does have variable interests in PPA counterparties, it is not the primary beneficiary of those counterparties and, therefore, consolidation is not required. These conclusions are based on the following factors: the PPAs do not have residual value guarantees and purchase options, Generation has no equity investments in the counterparties and does not incur expected losses related to the loss of plant value, the PPAs were based on market terms at their inception and Generation does not bear any operational risk related to the plants. Generation’s financial exposure to its PPAs relates to its fixed capacity payments, which are disclosed in Note 14 — Commitments and Contingencies. The financing trusts of ComEd, namely ComEd Financing II, ComEd Financing III, ComEd Funding LLC (ComEd Funding) and ComEd Transitional Funding Trust (CTFT), and the financing trusts of PECO, namely PECO Trust III, PECO Energy Capital Trust IV (PECO Trust IV) and PECO Energy Transition Trust (PETT), are not consolidated in Exelon’s, ComEd’s and PECO’s financial statements. ComEd Funding, CTFT and PETT were created for the sole purpose of issuing debt obligations to securitize intangible transition property of ComEd and PECO; and the other entities were created to issue mandatorily redeemable trust preferred securities. As of September 30, 2009, the only remaining VIE for ComEd is ComEd Financing III, as the other entities were dissolved during 2008. ComEd and PECO have concluded that they are not the primary beneficiaries of their respective trusts because investors in the trusts’ securities, not ComEd and PECO, bear the risk of loss related to those securities. 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. The maximum exposure to loss as a result of ComEd’s and PECO’s involvement with the financing trusts was $6 million and $19 million, respectively, at September 30, 2009 and $6 million and $39 million, respectively, at December 31, 2008. ComEd’s and PECO’s maximum exposure to loss is determined based on the current carrying value of investments made in VIEs. ComEd’s and PECO’s estimated range of exposure to loss related to the financing trusts is any amount up to the current carrying value of investments made in the VIEs. ComEd and PECO have not provided any non-contractually required financial support to the trusts during the nine months ended September 30, 2009 and 2008.

4. Property Plant and Equipment (Exelon and Generation)	9 Months Ended
4. Property Plant and Equipment (Exelon and Generation)	Sep. 30, 2009
EXELON GENERATION CO LLC
Notes to Financial Statements [Abstract]
4. Property Plant and Equipment (Exelon and Generation)	4. Property Plant and Equipment (Exelon and Generation) Long-Lived Asset Impairments (Exelon and Generation) Generation evaluated its Texas plants, comprised of the Handley, Mountain Creek and LaPorte generating stations, for potential impairment as of December 31, 2008, and concluded that there was no impairment, as the plants’ estimated undiscounted future cash flows exceeded the carrying values of the plants. Due to the continued decline in forward energy prices in the first quarter of 2009, Generation again evaluated its Texas plants for recoverability as of March 31, 2009. As the estimated undiscounted future cash flows and fair value of the Handley and Mountain Creek stations were less than the stations’ carrying values, the stations were determined to be impaired at March 31, 2009. LaPorte station was determined not to be impaired. Accordingly, the Handley and Mountain Creek stations were written down to fair value, and an impairment charge of $223 million was recorded in operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations in the first quarter of 2009. The fair value of the stations was determined using the income (discounted cash flow), market (available comparables) and cost (replacement cost) valuation approaches in determining fair value. During the second and third quarter of 2009, Generation assessed whether there had been any triggering events requiring an impairment assessment for any of its generating stations. Based on this analysis, it was determined that Generation did not have any triggering events requiring impairment assessments for any of its generating stations during the three months ended June 30, 2009 and September 30, 2009. See Note 6 — Fair Value of Assets and Liabilities for additional disclosures.
EXELON CORP
Notes to Financial Statements [Abstract]
4. Property Plant and Equipment (Exelon and Generation)	4. Property Plant and Equipment (Exelon and Generation) Long-Lived Asset Impairments (Exelon and Generation) Generation evaluated its Texas plants, comprised of the Handley, Mountain Creek and LaPorte generating stations, for potential impairment as of December 31, 2008, and concluded that there was no impairment, as the plants’ estimated undiscounted future cash flows exceeded the carrying values of the plants. Due to the continued decline in forward energy prices in the first quarter of 2009, Generation again evaluated its Texas plants for recoverability as of March 31, 2009. As the estimated undiscounted future cash flows and fair value of the Handley and Mountain Creek stations were less than the stations’ carrying values, the stations were determined to be impaired at March 31, 2009. LaPorte station was determined not to be impaired. Accordingly, the Handley and Mountain Creek stations were written down to fair value, and an impairment charge of $223 million was recorded in operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations in the first quarter of 2009. The fair value of the stations was determined using the income (discounted cash flow), market (available comparables) and cost (replacement cost) valuation approaches in determining fair value. During the second and third quarter of 2009, Generation assessed whether there had been any triggering events requiring an impairment assessment for any of its generating stations. Based on this analysis, it was determined that Generation did not have any triggering events requiring impairment assessments for any of its generating stations during the three months ended June 30, 2009 and September 30, 2009. See Note 6 — Fair Value of Assets and Liabilities for additional disclosures.