For information regarding commitments and contingencies at December 31, 2011, see Note 18 of the Exelon 2011 Form 10-K's and Note 12 of Constellation's and BGE's 2011 Form 10-K.

As of March 31, 2012, Generation's short- and long-term commitments relating to the sale and purchases from unaffiliated utilities and others of energy, capacity and transmission rights, are as indicated in the following table:

	Net Capacity			Power			Transmission Rights			Purchased Energy
	Purchases (a)			Purchases (b)			Purchases (c)			from CENG			Total

2012		$	391		$	61		$	26		$	677		$	1,155
2013			360			67			32			583			1,042
2014			354			34			26			351			765
2015			351			9			13			—			373
2016			265			4			2			—			271
Thereafter			668			6			36			—			710

Total		$	2,389		$	181		$	135		$	1,611		$	4,316

(a) Net capacity purchases include PPAs and other capacity contracts including those that are accounted for as operating leases. Amounts presented in the commitments represent Generation's expected payments under these arrangements at March 31, 2012, net of fixed capacity payments expected to be received by Generation under contracts to resell such acquired capacity to third parties under long-term capacity sale contracts. Expected payments include certain capacity charges which are contingent on plant availability.

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

As part of reaching a comprehensive agreement with EDF in October 2010, the existing power purchase agreement with CENG was modified to be unit-contingent through the end of its original term in 2014. Additionally, beginning in 2015 and continuing to the end of the life of the respective plants, Generation agreed to purchase 50.01% of the available output of CENG's nuclear plants at market prices. Generation discloses in the table commitments to purchase from CENG at fixed prices. All commitments to purchase at market prices, which include all purchases subsequent to December 31, 2014, are excluded from the table. Further, while CENG purchases from the balance sheet date through December 31, 2014 will eventually be purchased at a fixed price, only those portions of purchases that have been locked in with a fixed price have been disclosed in the table. Generation continues to own a 50.01% membership interest in CENG that is accounted for as an equity method investment. See Note 5 for more details on this arrangement.

ComEd's, PECO's and BGE's electric supply procurement, curtailment services and REC and AEC purchase commitments as of March 31, 2012 are as follows:

			Expiration within
													2017
	Total		2012		2013		2014		2015		2016		and beyond

ComEd
Electric supply procurement (a)	$	1,182	$	95	$	367	$	309	$	134	$	137	$	140
Renewable energy and RECs (b)		1,697		36		71		74		74		81		1,361
PECO
Electric supply procurement (c)		1,208		675		416		93		24		-		-
AECs		39		7		11		9		2		2		8
Curtailment services		12		12		-		-		-		-		-
BGE
Electric supply procurement (d)		1,299		646		544		109		-		-		-
Curtailment services		144		31		49		46		18		-		-

(a) ComEd entered into various contracts for the procurement of electricity that expire between 2012 and 2017. ComEd is permitted to recover its electric supply procurement costs from retail customers with no mark-up. See Note 4 - Regulatory Matters for additional information.

(b) ComEd entered into various contracts for the procurement of renewable energy and RECs that expire between 2012 and 2032. ComEd is permitted to recover its renewable energy and REC costs from retail customers with no mark-up. See Note 4 - Regulatory Matters for additional information.

(c) PECO entered into various contracts for the procurement of electric supply to serve its default service customers that expire between 2012 and 2015. PECO is permitted to recover its electric supply procurement costs from default service customers with no mark-up in accordance with its PAPUC-approved DSP Program. See Note 4 - Regulatory Matters for additional information.

(d) BGE entered into various contracts for the procurement of electricity that expire between 2012 and 2014. The cost of power under these contracts is recoverable under MDPSC approved fuel clauses. See Note 4 - Regulatory Matters for additional information.

In addition to the energy commitments described above, Generation has commitments to purchase fuel supplies for nuclear and fossil generation (and with respect to coal, commitments to sell coal) and PECO and BGE have commitments to purchase natural gas, related to transportation, storage capacity and services to serve customers in their gas distribution service territory. As of March 31, 2012, these net commitments were as follows:

			Expiration within
													2017
	Total		2012		2013		2014		2015		2016		and beyond

Generation	$	8,343	$	975	$	1,076	$	1,097	$	1,129	$	732	$	3,334
PECO		494		137		97		78		55		34		93
BGE		656		85		84		70		52		51		314

Exelon's, Generation's, ComEd's, PECO's and BGE's other purchase obligations as of March 31, 2012, which primarily represent commitments for services, materials and information, are as follows:

			Expiration within
													2017
	Total		2012		2013		2014		2015		2016		and beyond

Exelon	$	1,043	$	525	$	167	$	127	$	87	$	25	$	112
Generation		597		308		99		90		67		5		28
ComEd		90		85		5		—		—		—		—
PECO		105		60		18		17		1		1		8
BGE		18		7		11		—		—		—		—

Generation has committed to the construction of a solar PV facility in Los Angeles County, California. Generation's estimated commitments are $443 million and $445 million for the years 2012 and 2013, respectively. See Note 3 of the Exelon 2011 Form 10-K for additional information.

Generation has committed to the construction of approximately 404 MW of new wind facilities during 2012. Generation's estimated commitments are approximately $460 million primarily related to the procurement of the turbines.

Refer to Note 4 - Regulatory Matters for information on investment programs associated with regulatory mandates such as ComEd's Infrastructure Investment Plan under EIMA, PECO's Smart Meter Procurement and Installation Plan and BGE's comprehensive smart grid initiative.

The proceeding tables do not include the merger commitments made to the State of Maryland in conjunction with the Constellation merger. See Note 3 - Merger and Acquisitions for additional information on the merger commitments.

The Registrant's commercial commitments as of March 31, 2012, representing commitments potentially triggered by future events were as follows:

		Exelon			Generation			ComEd			PECO			BGE

Letters of credit (non-debt) (a)	$	2,623		$	1,381		$	23		$	21		$	1
Guarantees		10,696	(b)		1,448	(c)		209	(d)		181	(e)		253	(f)
Nuclear insurance premiums		2,098			2,098			0			0			0

Total commercial commitments	$	15,417		$	4,927		$	232		$	202		$	254

(a) Non-debt letters of credit maintained to provide credit support for certain transactions as requested by third parties. As of March 31, 2012, guarantees of $1 million have been issued by Exelon to provide support for certain letters of credit as required by third parties.

(b) Primarily reflects parental guarantees issued on behalf of Generation to allow the flexibility needed to conduct business with counterparties without having to post other forms of collateral. Also reflects guarantees issued to ensure performance under specific contracts, preferred securities of financing trusts, property leases, indemnifications, NRC minimum funding assurance requirements and $211 million on behalf of CENG nuclear generating facilities for nuclear insurance and credit support. The estimated net exposure for obligations under commercial transactions covered by these guarantees was $1.6 billion at March 31, 2012, which represents the total amount Exelon could be required to fund based on March 31, 2012 market prices.

(c) Primarily reflects guarantees issued to ensure performance under energy marketing and other specific contracts and $205 million on behalf of CENG nuclear generating facilities for credit support. The estimated net exposure for obligations under commercial transactions covered by these guarantees was $0.3 billion at March 31, 2012, which represents the total amount Generation could be required to fund based on March 31, 2012 market prices.

(d) Primarily reflects guarantees of $200 million Trust Preferred Securities of ComEd Financing III.

(e) Primarily reflects guarantees of $178 million Trust Preferred Securities of PECO Trust III and IV.

(f) Primarily reflects guarantees of $250 million Trust Preferred Securities of BGE Capital Trust II.

The Price-Anderson Act requires mandatory participation in a retrospective rating plan for power reactors (currently 104 reactors) resulting in $12.2 billion in funds available for public liability claims for any single incident at any power reactor site that exceeds the primary level of financial protection currently required ($375 million). Additionally, Generation is also required each year to report to the NRC the current levels and sources of property insurance that demonstrates Generation possesses sufficient financial resources to stabilize and decontaminate a reactor and reactor station site in the event of an accident. The property insurance maintained for each facility is currently provided through insurance policies purchased from NEIL, an industry mutual insurance company of which Generation is a member. Premiums paid to NEIL by its members are subject to assessment for adverse loss experience (the retrospective premium obligation). The maximum combined retrospective premium amount that Generation could be required to pay due to participation in the Price-Anderson Act retrospective rating plan for power reactors and the NEIL retrospective premium obligation was $2.1 billion at March 31, 2012, which is included above in the Commercial Commitments table and which does not include the potential maximum combined retrospective premium obligations of CENG. See the Nuclear Insurance section within Note 18 of the Exelon 2011 Form 10-K and Note 12 of Constellation's and BGE's 2011 Form 10-K for additional details on Generation's nuclear insurance premiums.

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

In connection with the sale, Generation recorded liabilities related to certain indemnifications provided to Dynegy and other guarantees directly resulting from the transaction. 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 March 31, 2012 and is set to expire in 2014. The guarantee is included above in the Commercial Commitments table under Guarantees.

On February 9, 2007, Tamuin International Inc. (TII), a wholly owned subsidiary of Generation, sold its 49.5% ownership interests in TEG and TEP to a subsidiary of AES Corporation for $95 million in cash plus certain purchase price adjustments. In connection with the transaction, Generation entered into a guarantee agreement under which Generation guarantees the timely payment of TII's obligations to the subsidiary of AES Corporation pursuant to the terms of the purchase and sale agreement relating to the sale of TII's ownership interests. Generation would be required to perform in the event that TII does not pay any obligation covered by the guarantee that is not otherwise subject to a dispute resolution process. Generation's maximum obligation under the guarantee is $95 million as of March 31, 2012. Generation has not recorded a liability associated with this guarantee. The exposures covered by this guarantee expired in part during 2008. Generation expects that the remaining exposure will expire by 2014. The guarantee of $95 million is included above in the Commercial Commitments table under Guarantees.

General. The Registrants' operations have in the past, and may in the future, require substantial expenditures in order to comply with environmental laws. Additionally, under Federal and state environmental laws, the Registrants are generally liable for the costs of remediating environmental contamination of property now or formerly owned by them and of property contaminated by hazardous substances generated by them. The Registrants own or lease a number of real estate parcels, including parcels on which their operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. 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, PECO and BGE have identified sites where former MGP activities have or may have resulted in actual site contamination. For almost all of these sites, ComEd, PECO or BGE is one of several PRPs that may be responsible for ultimate remediation of each location.

Pursuant to orders from the ICC, PAPUC and MDPSC, respectively, ComEd, PECO and BGE are authorized to and are currently recovering environmental costs for the remediation of former MGP facility sites from customers, for which they have recorded regulatory assets. See Note 4 - Regulatory Matters for additional information regarding the associated regulatory assets.

As of March 31, 2012 and December 31, 2011, the Registrants had accrued the following undiscounted amounts for environmental liabilities in other deferred credits and other liabilities within their respective Consolidated Balance Sheets:

March 31, 2012	Total Environmental Investigation and Remediation Reserve		Portion of Total Related to MGP Investigation and Remediation
Exelon	$	223	$	163
Generation		51		0
ComEd		123		116
PECO		49		46
December 31, 2011	Total Environmental Investigation and Remediation Reserve		Portion of Total Related to MGP Investigation and Remediation
Exelon	$	224	$	168
Generation		47		0
ComEd		127		121
PECO		50		47

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

Section 316(b) of the Clean Water Act. Section 316(b) requires that the cooling water intake structures at electric power plants reflect the best technology available to minimize adverse environmental impacts, and is implemented through state-level NPDES permit programs. All of Generation's and CENG'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. For Generation those facilities are C.P. Crane, Clinton, Dresden, Eddystone, Fairless Hills, Gould Street, H.A. Wagner, Handley, Mountain Creek, Mystic 7, Oyster Creek, Peach Bottom, Quad Cities, Riverside, Salem and Schuylkill. For CENG, those facilities are Calvert Cliffs, Nine Milke Point Unit 1 and R.E. Ginna. See Item 2. properties of the Exelon's 2011 Form 10-K for a description of these facilities.

On March 28, 2011, the EPA issued the proposed regulation under Section 316(b). The proposal does not require closed-cycle cooling (e.g., cooling towers) as the best technology available to address impingement and entrainment. The proposal provides the state permitting agency with discretion to determine the best technology available to limit entrainment (drawing aquatic life into the plants cooling system) mortality, including application of a cost-benefit test and the consideration of a number of site-specific factors. After consideration of these factors, the state permitting agency may require closed cycle cooling, an alternate technology, or determine that the current technology is the best available. The rule also imposes limits on impingement (trapping aquatic life on screens) mortality, which likely will be accomplished by the installation of screens or another technology at the intake. Exelon filed comments on the proposed regulation on August 18, 2011, stating its support for a number of its provisions (e.g., cooling towers not required as best technology available, and the use of site-specific and cost benefit analysis) while also noting a number of technical provisions that require revision to take into account existing unit operations and practices within the industry. The EPA has announced that it will publish a Notice of Data Availability to obtain public comments on the national benefits of the proposed rule and alternative compliant impingement technologies. Pursuant to a court approved Settlement Agreement, the EPA is required to approve the final rule by July 27, 2012. Until the rule is finalized, the state permitting agencies will continue to apply their best professional judgment to address impingement and entrainment.

Oyster Creek. On January 78, 2010, the NJDEP issued a draft NPDES permit for Oyster Creek that would have required, in the exercise of its best professional judgment, the installation of cooling towers as the best technology available within seven years after the effective date of the permit. On December 8, 2010, Exelon announced that Generation will permanently cease generation operations at Oyster Creek by no later than December 31, 2019. The current NRC license for Oyster Creek expires in 2029. In reliance upon Exelon's determination to cease generation operations no later than December 31, 2019, the NJDEP determined that closed cycle cooling is not the best technology available for Oyster Creek given the length of time that would be required to retrofit from the existing once-through cooling system to a closed-cycle cooling system and the limited life span of the plant after installation of a closed-cycle cooling system. Based on its consideration of these and other factors, NJDEP determined that the existing measures at the plant represent the best technology available for the facility's cooling water intake through cessation of generation operations.

On December 9, 2010, Generation executed an Administrative Consent Order (ACO) with the NJDEP regarding Oyster Creek. The ACO sets forth, among other things, the agreement by Generation to permanently cease generation operations at Oyster Creek if the conditions of the ACO are satisfied. In accordance with the ACO, on December 21, 2011, the NJDEP agreed to issue a final NPDES permit that became effective on April 12, 2012 that does not require the construction of cooling towers or other closed-cycle cooling facilities. The ACO and the final permit apply only to Oyster Creek based on its unique circumstances and does not set any precedent for the ultimate compliance requirements for Section 316(b) at Exelon's other plants.

As a result of the decision and the ACO, the expected economic useful life of Oyster Creek was reduced by 10 years to correspond top Exelon's current best estimate as to the timing of ceasing generation operations at the Oyster Creek unit in 2019. The financial impacts relate primarily to accelerated depreciation and accretion expense associated with the changes in decommissioning assumptions related to Generation's asset retirement obligation over the remaining expected economic useful life of Oyster Creek.. During the three months ended March 31, 2012, Generation made employee retention payments of approximately $14 million that will result in approximately $3 million of expense in each of years 2011 through 2015. During the three months ended March 31, 2012, Generation recorded approximately $2 2 million of employee retention expense.

Salem and Other Power Generation Facilities. In June 2001, the NJDEP issued a renewed NPDES permit for Salem, allowing for the continued operation of Salem with its existing cooling water system. NJDEP advised PSEG in July 2004 that it strongly recommended reducing cooling water intake flow commensurate with closed-cycle cooling as a compliance option for Salem. PSEG submitted an application for a renewal of the permit on February 1, 2006. In the permit renewal application, PSEG analyzed closed-cycle cooling and other options and demonstrated that the continuation of the Estuary Enhancement Program, an extensive environmental restoration program at Salem, is the best technology to meet the Section 316(b) requirements. PSEG continues to operate Salem under the approved June 2001 NPDES permit while the NPDES permit renewal application is being reviewed. If the final permit or Section 316(b) regulations ultimately requires the retrofitting of Salem's cooling water intake structure to reduce cooling water intake flow commensurate with closed-cycle cooling, Exelon's and Generation's share of the total cost of the retrofit and any resulting interim replacement power would be approximately $430 430 million, based on a 2006 estimate, and would result in increased depreciation expense related to the retrofit investment.

It is unknown at this time whether the NJDEP permit programs will require closed-cycle cooling at Salem. In addition, the economic viability of Generation's other power generation facilities, as well as CENG's, without closed-cycle cooling water systems will be called into question by any requirement to construct cooling towers. Should the final rule not require the installation of cooling towers, and retain the flexibility afforded the state permitting agencies in applying a cost benefit test and to consider site-specific factors, the impact of the rule would be minimized even though the costs of compliance could be material to Generation and CENG.

Given the uncertainties associated with the requirements that will be contained in the final rule, Generation cannot predict the eventual outcome or estimate the effect that compliance with any resulting Section 316(b) or interim state requirements will have on the operation of its and CENG's generating facilities and its future results of operations, cash flows and financial position.

Groundwater Contamination. In October 2007, a subsidiary of Constellation Energy entered into a consent decree with the MDE relating to groundwater contamination at a third party facility that was licensed to accept fly ash, a byproduct generated by coal-fired plants. The consent decree required the payment of a $1 1 million penalty, remediation of groundwater contamination resulting from the ash placement operations at the site, replacement of drinking water supplies in the vicinity of the site, and monitoring of groundwater conditions. Constellation recorded a liability in its Consolidated Balance Sheets of approximately $23 23 million to comply with the consent decree. As of March 31, 2012, approximately $6 5 million of these costs were paid, resulting in a remaining liability at March 31, 2012 of $17 18 million.

Alleged Conemaugh Clean Streams Violation by PA DEP. The PA DEP has alleged that GenOn Northeast Management Company (GenOn), the operator of Conemaugh Generating Station (CGS), violated the Clean Streams Law. GenOn is engaged in discussions with PA DEP and anticipates that the parties will reach a settlement pursuant to which GenOn will be obligated to pay a civil penalty of $500,000500,000, of which Generation's responsibility would be approximately $100,000200,000.

Cross State Air Pollution Rule. On July 11, 2008, the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court) vacated the CAIR, which had been promulgated by the U.S. EPA to reduce power plant emissions of SO2 and NOx. The D.C. Circuit Court later remanded the CAIR to the U.S. EPA, without invalidating the entire rulemaking, so that the U.S. EPA could correct CAIR in accordance with the D.C. Circuit Court's July 11, 2008 opinion. On July 6, 2010, the U.S. EPA published the proposed Transport Rule as the replacement to the CAIR. On July 7, 2011, the U.S. EPA published the final rule, now known as the CSAPR. The CSAPR requires 27 28 states in the eastern half of the United States to significantly improve air quality by reducing power plant emissions that cross state lines and contribute to ground-level ozone and fine particle pollution in other states. The final rule maintains the January 1, 2012 and January 1, 2014 phase-in dates that were in the proposed Transport Rule. However, the CSAPR imposes tighter emissions caps than the proposed Transport Rule and includes six additional states under the summertime NOx reduction requirements. These emissions limits may be further reduced as the U.S. EPA finalizes more restrictive ozone and particulate matter NAAQS in the 2012 - 2013 timeframe.

Under the CSAPR, Generation units will receive allowances based on historic heat input. Intrastate, and limited interstate, trading of allowances is permitted, subject to certain limitations. The CSAPR restricts entirely the use of pre-2012 allowances. Existing SO2 allowances under the ARP would remain available for use under ARP. During the third quarter of 2010, Generation recognized a lower of cost or market impairment charge of $57 57 million on its ARP SO2 allowances that are not expected to be used by Generation's fossil-fuel power plants and that have not been sold forward. The impairment was recorded due to the significant decline of allowance market prices because CSAPR regulations would restrict entirely the use of ARP SO2 allowances beginning in 2012. As of March 31, 2012, Generation had $4 36 million of emission allowances carried at the lower of weighted average cost or market., which are included in inventory, net within Exelon's Consolidated Balance Sheets .

On October 6, 2011 and February 7, 2012, the EPA proposed for public comment certain technical corrections to CSAPR, including correction of data errors in determining generation unit allowances and state allowance budgets. These corrections will increase the number of emission allowances available under the CSAPR. In addition, the proposal defers until 2014 penalties that will involve surrender of additional allowances should states not meet certain levels of emission reductions. This deferral is intended to increase the liquidity of allowances during the initial years of transition from CAIR to the CSAPR.

Numerous entities challenged the CSAPR in the D.C. Circuit Court, and some requested a stay of the rule pending the Court's consideration of the matter on the merits. The D.C. Circuit Court granted permission for Exelon, as well as a number of other parties, to intervene in the litigation in support of the rule. On December 30, 2011, the Court granted a stay of the CSAPR, and directed the U.S. EPA to continue the administration of CAIR in the interim. Subsequently the Court ordered an expedited case management schedule that resulted in oral argument on April 13, 2012. It is unknown when the Court will issue its decision on the merits. Exelon believes that the CSAPR is a valid exercise of the U.S. EPA's authority and discretion under the Clean Air Act.

EPA Mercury and Air Toxics Standards (MATS). On April16, 2012, the MATS rule to reduce emissions of toxic air pollutants from electric generating units (EGUs) became final. The MATS rule also finalized the new source performance standards for EGUs. The MATS rule resulted from a finding by the D.C. Circuit of Appeals that the prior rule, known as the Clean Air Mercury Rule (CAMR), was invalid because it did not regulate mercury as a HAP. The MATS rule requires coal-fired EGUs to achieve high removal rates of mercury, acid gases and other metals from air emissions. To achieve these standards, coal units with no pollution control equipment installed (uncontrolled coal units) will have to make capital investments and incur higher operating expenses. It is expected that smaller, older, uncontrolled coal units will retire rather than make these investments. Coal units with existing controls that do not meet the required standards may need to upgrade existing controls or add new controls to comply. In addition, the new standards will cause oil units to achieve high removal rates of metals. Owners of oil units not currently meeting the proposed emission standards may choose to convert the units to light oils or natural gas, install control technologies or retire the units. The MATS rule requires generating stations to meet the new standards three years after the rule takes effect, April 16, 2015, with specific guidelines for an additional one or two years in limited cases. Numerous entities have challenged MATS in the D.C. Circuit Court, and Exelon has petitioned the Court to intervene in support of the rule.

Exelon, along with the other co-owners of Conemaugh Generating Station are moving forward with plans to improve the existing scrubbers and install Selective Catalytic Reduction (SCR) controls to meet the mercury removal requirements of MATS. In addition, Generation owns three base-load, coal-fired generation units in Maryland that were acquired in the merger with Constellation – Brandon Shores, H.A. Wagner and C.P. Crane. However, in connection with certain of the regulatory approvals required for the merger Exelon agreed to divest these generating stations. It is anticipated that these plants are well positioned to comply with CSAPR and MATS since Maryland has adopted SO2, NOx, and mercury emission limits under its Healthy Air Act and Clean Power Rule that are generally consistent with the requirements of CSAPR and MATS.

In addition, as of March 31, 2012, Exelon had a $663 million net investment in coal-fired plants in Georgia and Texas subject to long-term leases extending through 2028-2032. While Exelon currently estimates the value of these plants at the end of the lease term will be in excess of the recorded residual lease values, final applications of the CSAPR and MATS regulations could negatively impact the end-of-lease term values of these assets, which could result in a future impairment loss that could be material.

NAAQS. The U.S. EPA previously announced that it would complete a review of NAAQS in the 2011 - 2012 timeframe for particulate matter, nitrogen dioxide, sulfur dioxide, and lead. This review could result in more stringent emissions limits on fossil-fired electric generating stations. In September 2011, the U.S. EPA withdrew its reconsideration of the NAAQS standard for ozone, which is next scheduled for reconsideration in 2013.

Notices and Finding of Violations Related to Electric Generation Stations. On August 6, 2007, ComEd received a NOV, addressed to it and Midwest Generation, LLC (Midwest Generation) from the U.S. EPA, alleging that ComEd and Midwest Generation have violated and are continuing to violate several provisions of the 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 generating stations 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 August 2009, the DOJ and the Illinois Attorney General filed a complaint against Midwest Generation with the U.S. District Court for the Northern District of Illinois initiating enforcement proceedings with respect to the alleged Clean Air Act violations set forth in the NOV. Neither ComEd nor Exelon were named as a defendant in this original complaint. In March 2010, the District Court granted Midwest Generation's partial motion to dismiss all but one of the claims against Midwest Generation. The Court held that Midwest Generation cannot be liable for any alleged violations relating to construction that occurred prior to Midwest Generation's ownership of the stations. In May 2010, the government plaintiffs filed an amended complaint substantially similar to the original complaint, and added ComEd and EME as defendants. The amended complaint seeks injunctive relief and civil penalties against all defendants, although not all of the claims specifically pertain to ComEd. On March 16, 2011, the U.S. District Court granted ComEd's motion to dismiss the May 2010 complaint. On January 3, 2012, upon leave of the U.S. District Court, the government parties appealed the dismissal of ComEd to the U.S. Circuit Court of Appeals.

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 amended complaint, 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 in light of the District Court decision the likelihood of loss is remote. Therefore, no reserve has been established. Further, Generation believes that it would be reimbursed by Midwest Generation and EME for any losses under the terms of the indemnification agreement, subject to the credit worthiness of Midwest Generation and EME.

Cotter Corporation. The U.S. EPA has advised Cotter Corporation (Cotter), a former ComEd subsidiary, that it is potentially liable in connection with radiological contamination at a site known as the West Lake Landfill in Missouri. On February 18, 2000, ComEd sold Cotter to an unaffiliated third party. As part of the sale, ComEd agreed to indemnify Cotter for any liability 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. On May 29, 2008, the U.S. EPA issued a Record of Decision approving the remediation option submitted by Cotter and the two other PRPs that required additional landfill cover. The current estimated cost of the anticipated landfill cover remediation for the site is approximately $42 million, which will be allocated among all PRPs. Generation has accrued what it believes to be an adequate amount to cover its anticipated share of such liability. By letter dated January 11, 2010, the U.S. EPA requested that the PRPs perform a supplemental feasibility study for a remediation alternative that would involve excavation of the radiological contamination. On September 30, 2011, the PRPs submitted the final supplemental feasibility study to the EPA for review. It is anticipated that the EPA will propose a remedy in the second quarter of 2012, which will be subject to public comment. Thereafter the EPA will select a final remedy and enter into a Consent Decree with the PRPs to effectuate the remedy. An excavation remedy would be significantly more expensive than the previously selected additional cover remedy; however, Generation believes the likelihood that the U.S. EPA would require the use of an excavation remedy is remote.

On August 8, 2011, Cotter was notified by the DOJ that Cotter is considered a PRP with respect to the government's clean-up costs for contamination attributable to low level radioactive residues at a former storage and reprocessing facility named Latty Avenue near St. Louis, Missouri. The Latty Avenue site is included in ComEd's indemnification responsibilities discussed above as part of the sale of Cotter. The radioactive residues had been generated initially in connection with the processing of uranium ores as part of the U.S. government's Manhattan Project. Cotter purchased the residues in 1969 for initial processing at the Latty Avenue facility for the subsequent extraction of uranium and metals. In 1976, the NRC found that the Latty Avenue site had radiation levels exceeding NRC criteria for decontamination of land areas. Latty Avenue was investigated and remediated by the United States Army Corps of Engineers pursuant to funding under the Formerly Utilized Sites Remedial Action Program. The DOJ has not yet formally advised the PRPs of the amount that it is seeking, but it is believed to be approximately $100 million. The DOJ and the PRPs have agreed to toll the statute of limitations until August 2012 so that settlement discussions can proceed. Based on Exelon's preliminary review, it appears probable that Exelon has liability to Cotter under the indemnification agreement and has established an appropriate accrual for this liability.

On February 28, 2012, and April 12, 2012, two lawsuits were filed in the U.S. District Court for the Eastern District of Missouri against 15 and 14 defendants respectively, including Exelon, Generation and ComEd (the “Exelon defendants”). The suits allege that individuals living in the North St. Louis area developed some form of cancer due to the defendants' negligent or reckless conduct in processing, transporting, storing, handling and/or disposing of radioactive materials. Plaintiffs have asserted claims for negligence, strict liability, emotional distress, medical monitoring, and violations of the Price-Anderson Act. The complaints do not contain specific damage claims. The Exelon defendants are parties to the actions based on their prior ownership of Cotter Corporation as described above. Due to the early stage of the litigation, Exelon is unable to determine the extent of its potential liability, if any.

68th Street Dump. In 1999, the EPA proposed to add the 68th Street Dump in Baltimore, Maryland to the Superfund National Priorities List, and notified BGE and 19 others that they are PRPs at the site. In March 2004, BGE and other PRPs formed the 68th Street Coalition and entered into consent order negotiations with the EPA to investigate clean-up options for the site under the Superfund Alternative Sites Program. In May 2006, a settlement among the EPA and 19 of the PRPs, including BGE, with respect to investigation of the site became effective. The settlement requires the PRPs, over the course of several years, to identify contamination at the site and recommend clean-up options. The potentially responsible parties submitted their investigation of the range of clean-up options in the first quarter of 2011. Although the investigation and options provided to the EPA are still subject to EPA review and selection of a remedy, the range of estimated clean-up costs to be allocated among all of the PRPs is in the range of $50 million and $64 million. The EPA is expected to make a final selection of one of the alternatives in 2012. Since the EPA has not selected the remedy and the allocation of the clean-up costs among the PRPs has not been determined, an estimate of the range of BGE's possible loss cannot be determined. BGE is indemnified by a wholly owned subsidiary of Generation for most of the costs related to this settlement and clean-up of the site.

Climate Change Regulation. Exelon is subject to climate change regulation or legislation at the international, Federal, regional and state levels. In 2007, the U.S. Supreme Court ruled that GHG emissions are pollutants subject to regulation under the new motor vehicle provisions of the Clean Air Act. Consequently, on December 7, 2009, the U.S. EPA issued an endangerment finding under Section 202 of the Clean Air Act regarding GHGs from new motor vehicles and on April 1, 2010 issued final regulations limiting GHG emissions from cars and light trucks effective on January 2, 2011. While such regulations do not specifically address stationary sources, such as a generating plant, it is the U.S. EPA's position that the regulation of GHGs under the mobile source provisions of the Clean Air Act has triggered the permitting requirements under the Prevention of Significant Deterioration (PSD) and Title V operating permit sections of the Clean Air Act for new and modified stationary sources effective January 2, 2011. Therefore, on May 13, 2010, the U.S. EPA issued final regulations relating to these provisions of the Clean Air Act for major stationary sources of GHG emissions that apply to new sources that emit greater than 100,000 tons per year, on a CO2 equivalent basis, and to modifications to existing sources that result in emissions increases greater than 75,000 tons per year on a CO2 equivalent basis. These thresholds became effective January 2, 2011, apply for six years and will be reviewed by the U.S. EPA for future applicability thereafter. On April 13, 2012, the U.S. EPA published proposed regulations for new source performance standards (NSPS) for GHG emissions from new fossil-fueled power plants, greater than 25 MW, that would require the plants to limit CO2 emissions to a thirty-year average of less than 1000 pounds per MWh (less than 1800 pounds per MWh for the first ten years and less than 600 pounds per MWh thereafter). Under the regulations, new and modified major stationary sources could be required to install best available control technology, to be determined on a case-by-case basis. Generation could be significantly affected by the regulations if it were to build new plants or modify existing plants.

Except to the extent noted below, the circumstances set forth in Note 18 of the Exelon's 2011 Form 10-K and Note 12 of Constellation's and BGE's 2011 Form 10-K describe, in all material respects, the current status of litigation matters. The following is an update to that discussion.

Exelon and Generation. 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 March 31, 2012 and December 31, 2011, Generation had reserved approximately $47 million and $49 million, respectively, in total for asbestos-related bodily injury claims. As of March 31, 2012, approximately $13 million of this amount related to 172 open claims presented to Generation, while the remaining $34 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.

BGE. Since 1993, BGE and certain Constellation subsidiaries have been involved in several actions concerning asbestos. The actions are based upon the theory of "premises liability," alleging that BGE and Constellation knew of and exposed individuals to an asbestos hazard. In addition to BGE and Constellation, numerous other parties are defendants in these cases.

Approximately 480 individuals who were never employees of BGE or Constellation have pending claims each seeking several million dollars in compensatory and punitive damages. Cross-claims and third party claims brought by other defendants may also be filed against BGE and Generation in these actions. To date, most asbestos claims which have been resolved have been dismissed or resolved without any payment by BGE or Constellation and a small minority of these cases has been resolved for amounts that were not material to its financial results.

Discovery begins in these cases once they are placed on the trial docket. At present, only none a small number of the pending cases have reached theare set for trial docket. Given the limited discovery, BGE and Generation do not know the specific facts that are necessary to provide an estimate of the possible loss relating to these claims. The specific facts not known include:

Insurance and hold harmless agreements from contractors who employed the plaintiffs may cover a portion of any awards in the actions.

CENG is currently in negotiations with the DOE to recover damages caused by the DOE's failure to comply with legal and contractual obligations to dispose of spent nuclear fuel related to the Nine Mile Point nuclear power plant. Any funds received from the DOE related to costs incurred prior to November 6, 2009 will belong to Generation. We have recorded a pre-acquisition contingent asset of approximately $25 million related to Generation's share of the potential settlement. See Note-3 Mergers and Acquisitions for additional information on the merger.

On January 30, 2012, FERC published a notice on its website regarding a non-public investigation of certain of Constellation's power trading activities in and around the New York ISO from September 2007 through December 2008. Prior to the merger, Constellation announced on March 9, 2012, that it had resolved the FERC investigation. Under the settlement, Constellation agreed to pay a $135 million civil penalty and $110 million in disgorgement. The disgorgement amount will be disbursed in two ways. First, Constellation will provide $1 million each to six U.S. regional grid operators for the purpose of improving their surveillance and analytic capabilities. The remainder of the disgorgement amount was deposited in a fund that will be administered by a FERC ALJ. State agencies in New York, New England and PJM (the regional grid operator for 13 states and the District of Columbia) will be eligible to make claims against the fund on behalf of electric energy consumers in those states.

During the three months ended March 31, 2012, Generation recorded expense of $195 million in operating and maintenance expense, with the remaining $50 million recorded as a Constellation pre-acquisition contingency. As of March 31, 2012, the full amount of the civil penalty and disgorgement was paid. See Note 3 - Merger and Acquisitions for additional information on the merger.

The Illinois Public Utilities Act provides that in the event an electric utility, such as ComEd, experiences a continuous power interruption of four hours or more that affects (in ComEd's case) 30,000 or more customers, the utility may be liable for actual damages suffered by customers as a result of the interruption and may be responsible for reimbursement of local governmental emergency and contingency expenses incurred in connection with the interruption. Recovery of consequential damages is barred. The affected utility may seek from the ICC a waiver of these liabilities when the utility can show that the cause of the interruption was unpreventable damage due to weather events or conditions, customer tampering, or certain other causes enumerated in the law.

On August 18, 2011, ComEd sought from the ICC a determination that ComEd is not liable for damage compensation to customers in connection with the July 11, 2011 storm system that produced multiple power interruptions that in the aggregate affected more than 900,000 customers in ComEd's service territory, as well as for five other storm systems that affected ComEd's customers during June and July 2011. The ICC is currently conducting a proceeding to assess ComEd's request. In the absence of a favorable determination from the ICC, some ComEd customers affected by the outages could seek recovery of their actual, non-consequential damages, and the local governments in the areas in which those customers are located could seek recovery of emergency and contingency expenses. On January 27, 2012, the ICC Staff and the Illinois Attorney General (AG) filed testimony in the ICC proceeding. They both disagree with ComEd's interpretation that the statute does not apply to any of the individual continuous power interruptions caused by the 2011 storms. Additionally, the ICC witness supports granting a waiver for the three of the six storms, while the AG asserts that ComEd should be held responsible for the damages from all the storms. On March 30, 2012, ComEd filed responsive testimony in the ICC proceeding to further support its position that no compensation is required.

In addition, on September 29, 2011, ComEd sought from the ICC a determination that it was not liable for damage compensation related to the February 1, 2011 blizzard. On February 14, 2012, the ICC Staff and the AG filed testimony in the proceeding. ICC staff has recommended that the ICC issue ComEd a waiver based on the extreme weather conditions. The AG has taken the same position as that filed in the summer storm system waiver noted above. Additional active proceedings related to storms of lesser collective impact are also pending. Both of the above proceedings have been set for hearing in July 2012. The ultimate outcomes of these proceedings are uncertain, and the amount of damages, if any, which might be asserted, cannot be reasonably estimated at this time, but may be material to ComEd's results of operations and cash flows.

Three federal securities class action lawsuits were filed in the United States District Courts for the Southern District of New York and the District of Maryland between September 2008 and November 2008 against Constellation. The cases were filed on behalf of a proposed class of persons who acquired publicly traded securities, including the Series A Junior Subordinated Debentures (Debentures), of Constellation between January 30, 2008 and September 16, 2008, and who acquired Debentures in an offering completed in June 2008. The securities class actions generally allege that Constellation, a number of its present or former officers or directors, and the underwriters violated the securities laws by issuing a false and misleading registration statement and prospectus in connection with Constellation's June 27, 2008 offering of Debentures. The securities class actions also allege that Constellation issued false or misleading statements or was aware of material undisclosed information which contradicted public statements including in connection with its announcements of financial results for 2007, the fourth quarter of 2007, the first quarter of 2008 and the second quarter of 2008 and the filing of its first quarter 2008 Form 10-Q. The securities class actions seek, among other things, certification of the cases as class actions, compensatory damages, reasonable costs and expenses, including counsel fees, and rescission damages.

The Southern District of New York granted the defendants' motion to transfer the two securities class actions filed in Maryland to the District of Maryland, and the actions have since been transferred for coordination with the securities class action filed there. On June 18, 2009, the court appointed a lead plaintiff, who filed a consolidated amended complaint on September 17, 2009. On November 17, 2009, the defendants moved to dismiss the consolidated amended complaint in its entirety. On August 13, 2010, the District Court of Maryland issued a ruling on the motion to dismiss, holding that the plaintiffs failed to state a claim with respect to the claims of the common shareholders under the Securities Exchange Act of 1934 and limiting the suit to those persons who purchased Debentures in the June 2008 offering. In August 2011, plaintiffs requested permission from the court to file a third amended complaint in an effort to attempt to revive the claims of the common shareholders. Constellation has filed an objection to the plaintiffs' request for permission to file a third amended complaint and on March 28, 2012, the District Court of Maryland denied the plaintiffs' request for permission to revive the claims of the common shareholders. Given that limited discovery has occurred, that the court has not certified any class and the plaintiffs have not quantified their potential damage claims, Exelon is unable at this time to provide an estimate of the range of possible loss relating to these proceedings or to determine the ultimate outcome of the securities class actions or their possible effect on its financial results.

The Registrants are involved in various other litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. The Registrants maintain accruals for losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of reasonably possible loss, particularly where (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.

See Note 9 - Income Taxes for information regarding the Registrants' income tax refund claims and certain tax positions, including the 1999 sale of fossil generating assets.