Regulatory and Legislative Proceedings (Exelon, Generation, ComEd, PECO and BGE)

Except for the matters noted below, the disclosures set forth in Note 2 of the Exelon 2011 Form 10-K and Note 6 of Constellation's and BGE's 2011 Form 10-K appropriately represent, in all material respects, the current status of regulatory and legislative proceedings of the Registrants. The following is an update to that discussion.

Energy Infrastructure Modernization Act (Exelon and ComEd). During the fourth quarter of 2011, EIMA was passed into law and became effective for Illinois utility companies on an opt-in basis. The legislation provides for substantial capital investment over a ten-year period to modernize Illinois' electric utility infrastructure and for greater certainty related to the recovery of costs by a utility through a pre-established formula rate tariff. On January 6, 2012, ComEd filed its Infrastructure Investment Plan with the ICC. Under the plan, ComEd will invest approximately $2.6 billion over ten years to modernize and storm-harden its distribution system and to implement smart grid technology. These investments will be incremental to ComEd's historical level of capital expenditures. The January 6, 2012 filing with the ICC specifically included ComEd's $233 million investment plan for 2012. On April 23, 2012, ComEd filed its initial AMI Deployment Plan with the ICC. Implementation of the investment plan began in early 2012 while smart meter installation in homes and businesses is expected to begin later in 2012, subject to a final order from the ICC regarding ComEd's AMI Deployment Plan, which is expected during the second quarter of 2012. Additionally, ComEd will contribute $10 million per year for five years, as long as ComEd is subject to EIMA, to fund customer assistance programs for low-income customers, which amounts will not be recoverable through rates. ComEd recorded an immaterial amount of costs associated with customer assistance programs for the three months ended March 31, 2012. ComEd expects to make an initial contribution of $15 million (recognized as expense in 2011) to a new Science and Technology Innovation Trust fund later in 2012. ComEd will pay to the trust approximately $4 million annually, beginning later in 2012, which will be used for customer education for as long as the AMI Deployment Plan remains in effect.

EIMA provides for a performance-based distribution formula rate tariff. On November 8, 2011, ComEd filed its initial formula rate tariff and associated testimony based on 2010 costs and 2011 plant additions. The primary purpose of this initial proceeding is to establish the formula under which rates will be calculated going-forward, and the initial rate, which is expected to be lower than current rates, which will take effect within 30 days after the ICC order, which must be issued by May 31, 2012. Through an annual reconciliation process as described below, customer rates will be further adjusted effective January 2013 to provide recovery of the actual costs incurred during 2011, including recovery of and return on increases in rate base associated with capital spending under EIMA.

During the first quarter of 2012, ComEd and several intervenors filed testimony in the proceeding. The intervenors proposed various reductions to ComEd's proposed revenues, which included changes to return on pension asset, rate base and operating expenses. On May 1, 2012, the ALJs issued a proposed order in ComEd's formula rate tariff proceeding providing for a $146 million reduction in the revenue requirement being recovered in current rates, as opposed to ComEd's final position supporting a $59 million reduction. The primary differences between the ALJ's proposed order and ComEd's final position relate to different approaches to allocating certain costs and differences in timing or rate recovery mechanisms for various costs. The ALJs propose the use of average annual rate base and capital structure amounts (as opposed to year-end amounts as proposed by ComEd) and lower carrying costs on future reconciliation amounts. If approved by the ICC, the revenue requirement reduction as proposed by the ALJs would primarily delay the timing of cash flows, with a less significant impact on earnings given the annual reconciliation mechanism as described below. Use of average annual rate base and capital structure amounts (vs. year-end amounts), though, would unfavorably impact future earnings given increased regulatory lag.

ComEd is currently assessing the potential impacts of the proposed order and cannot predict the reduction in the revenue requirement the ICC may approve and which provisions of the ALJs' proposed order will ultimately be included in the final order. As a proposed order, it has no independent legal effect as the ICC must vote on a final order which may materially vary from the findings and conclusions in the proposed order. If the ICC provides significant changes to ComEd's filed revenue requirement request, it could have a material impact on ComEd's future results of operations and cash flows.

As noted, the legislation provides for an annual reconciliation of the revenue requirement in effect in a given year to reflect the actual costs that the ICC determines are prudently and reasonably incurred for such year. The first year for which the reconciliation will be performed is 2011. ComEd made its initial 2011 reconciliation filing on April 30, 2012, and the rate adjustments necessary to reconcile the 2011 revenue requirement in effect to ComEd's actual 2011 costs incurred will take effect in January 2013, after the ICC's review. A similar 2012 annual reconciliation will be filed in early 2013 with any adjustments to rates taking effect in January 2014. As of March 31, 2012 and December 31, 2011, ComEd recorded an estimated regulatory asset of $118 million and $84 million, respectively, which represents ComEd's best estimate of the probable increase in distribution rates expected to be approved by the ICC to provide for recovery of prudent and reasonable costs incurred as of those dates. Of the amount recorded at March 31, 2012, $61 million relates to 2011 and $57 million relates to the first quarter of 2012. During the first quarter of 2012, ComEd reduced the 2011 portion of the regulatory asset by $19 million to reflect management's interpretation of how the ongoing formula rate tariff proceedings discussed above may impact the formula rate mechanism ultimately approved by the ICC. Based on its preliminary review, if the ALJ's proposed order dated May 1, 2012, were to be implemented, ComEd does not believe it would have a material impact to the cumulative regulatory asset amount recorded as of March 31, 2012.

Appeal of 2007 Illinois Electric Distribution Rate Case (Exelon and ComEd). The ICC issued an order in ComEd's 2007 electric distribution rate case (2007 Rate Case) approving a $274 million increase in ComEd's annual delivery services revenue requirement, which became effective in September 2008. In the order, the ICC authorized a 10.3% rate of return on common equity. ComEd and several other parties filed appeals of the rate order with the Illinois Appellate Court (Court). The Court issued a decision on September 30, 2010, ruling against ComEd on the treatment of post-test year accumulated depreciation and the recovery of system modernization costs via a rider (Rider SMP). The ICC subsequently initiated a proceeding on remand. On February 23, 2012, the ICC issued an order in the remand proceeding requiring ComEd to provide a refund of approximately $37 million to customers related to the treatment of post-test year accumulated depreciation issue. On March 26, 2012, ComEd filed a notice of appeal. ComEd has recognized for accounting purposes its best estimate of any refund obligation.

Advanced Metering Program Proceeding (Exelon and ComEd). In October 2009, the ICC approved a modified version of ComEd's system modernization rider proposed in the 2007 Rate Case, Rider AMP (Advanced Metering Program). ComEd collected approximately $24 million under Rider AMP through December 31, 2011. Several other parties, including the Illinois Attorney General, appealed the ICC's order on Rider AMP. In ComEd's 2010 electric distribution rate case, the ICC approved ComEd's transfer of other costs from recovery under Rider AMP to recovery through base electric distribution rates. On March 19, 2012, the Court reversed Rider AMP, concluding that the ICC's October 2009 approval of the rider constituted single-issue ratemaking. ComEd filed a Petition for Leave to Appeal to the Illinois Supreme Court on April 23, 2012. ComEd believes any refund obligation associated with Rider AMP should be prospective from no earlier than the date of the Court's order on March 19, 2012, which would have an immaterial impact at ComEd and Exelon.

Illinois Procurement Proceedings (Exelon, Generation and ComEd). ComEd is permitted to recover its electricity procurement costs from its retail customers without mark-up. Since June 2009, the IPA designs, and the ICC approves, an electricity supply portfolio for ComEd and the IPA administers a competitive process under which ComEd procures its electricity supply from various suppliers, including Generation. In order to fulfill a requirement of the Illinois Settlement Legislation, ComEd hedged the price of a significant portion of energy purchased in the spot market with a five-year variable-to-fixed financial swap contract with Generation that expires on May 31, 2013. EIMA contains a provision for the IPA to conduct procurement events for energy and REC requirements for the June 2013 through December 2017 period. The procurement events mandated under EIMA were completed during February 2012. See Note 15 – Commitments and Contingencies for additional information on ComEd's energy commitments.

Pennsylvania Procurement Proceedings (Exelon and PECO). PECO's PAPUC-approved DSP Program, under which PECO is providing default electric service, has a 29-month term that began January 1, 2011 and ends May 31, 2013. Under the DSP Program, PECO is permitted to recover its electric procurement costs from retail default service customers without mark-up through the GSA. The GSA provides for the recovery of energy, capacity, ancillary costs and administrative costs and is subject to adjustments at least quarterly for any over or under collections. The filing and implementation costs of the DSP Program were recorded as a regulatory asset and are being recovered through the GSA over its 29-month term. In January and April 2012, PECO entered into contracts with PAPUC-approved bidders, including Generation, for electric supply for default electric service which included full requirements fixed price contracts for its residential and small commercial, medium commercial procurement classes that commence in June 2012, hourly spot market price full requirements contracts for its small and medium commercial and large commercial and industrial procurement classes that commence in June 2012 and block contracts for its residential class beginning December 2012. Charges incurred for electric supply procured through contracts with Generation are included in purchased power from affiliates on PECO's Statement of Operations. PECO has one competitive procurement remaining over the term of this DSP Program.

On January 13, 2012, PECO filed its second DSP Plan for approval with the PAPUC. The plan outlined how PECO will purchase electricity for default customers from June 1, 2013 through May 31, 2015. To continue to ensure a competitive procurement process for residential customers, PECO proposed to procure electricity through a combination of one-year and two-year fixed full requirements contracts, reduce the amount of time between when the energy is purchased and when it is provided to customers and complete an annual, rather than quarterly, reconciliation of costs for actual versus forecasted energy use. The DSP Plan also proposed to eliminate the AEPS rider and recover AEPS costs through the GSA. Hearings on the filing are scheduled for May 2012, with a PAPUC ruling expected in mid-October 2012.

Smart Meter and Smart Grid Investments (Exelon and PECO). In April 2010, the PAPUC approved PECO's $550 million Smart Meter Procurement and Installation Plan under which PECO will install more than 1.6 million smart meters and deploy advanced communication networks by 2020. In 2010, PECO entered into a Financial Assistance Agreement with the DOE for SGIG funds under the ARRA of 2009. Under the SGIG, PECO has been awarded $200 million, the maximum grant allowable under the program, for its SGIG project – Smart Future Greater Philadelphia. In total, through 2020, PECO plans to spend up to a total of $650 million on its smart grid and smart meter infrastructure. The $200 million SGIG is being used to reduce the impact of these investments on PECO ratepayers.

As of March 31, 2012, PECO received $87 million in reimbursements from the DOE. As of March 31, 2012, PECO's outstanding receivable from the DOE for reimbursable costs was $28 million, which has been recorded in other accounts receivable, net on Exelon's and PECO's Consolidated Balance Sheets.

Natural Gas Choice Supplier Tariff (Exelon and PECO). During 2011, the PAPUC approved PECO's tariff supplements to its Gas Choice Supplier Coordination Tariff and its Retail Gas Service Tariff to address the new licensing requirements for natural gas suppliers (NGS) set forth in the PAPUC's final rulemaking order, which became effective January 1, 2011. The new licensing requirements broaden the types of collateral that PECO can require to mitigate its risk related to a NGS default, as well as PECO's ability to adjust collateral when material changes in supplier creditworthiness occur. PECO has completed its creditworthiness determinations and notified affected NGSs of their new collateral levels. As a result PECO will obtain $14 million of assurance in May 2012.

Investigation of PA Retail Electricity Market (Exelon and PECO). On July 28, 2011, the PAPUC issued an order outlining the next steps in its investigation into the status of competition in Pennsylvania's retail electric market. The PAPUC found that the existing default service model presents substantial impediments to the development of a vibrant retail market in Pennsylvania and directed its Office of Competitive Markets Oversight to evaluate potential intermediate and long-term structural changes to the default service model. On January 13, 2012, PECO filed its second Default Service Plan for approval with the PAPUC, which proposed several new programs to continue PECO's support of retail market competition in Pennsylvania in accordance with the order issued by the PAPUC on December 15, 2011. On March 1, 2012, the PAPUC approved the final order describing more detailed recommendations to be implemented prior to the expiration of the electric distribution company's current default service plan beginning in 2012 and providing guidelines for EDCs for the development of their next Default Service Plan.

Pennsylvania Act 11 of 2012 (Exelon and PECO). On February 13, 2012, Act 11 was signed into law by the Governor. Act 11 seeks to clarify the PAPUC's authority to approve alternative ratemaking mechanisms, which would allow for the implementation of a distribution system improvement charge (DSIC) in rates designed to recover capital project costs incurred to repair, improve or replace utilities' aging electric and natural gas distribution systems in Pennsylvania.

Act 11 also includes a provision that allows utilities to use a fully projected future test year under which the PAPUC may permit the inclusion of projected capital costs in rate base for assets that will be placed in service in future test years.

2011 Maryland Electric and Natural Gas Distribution Rate Cases (Exelon and BGE). In March 2011, the MDPSC issued a comprehensive rate order setting forth the details of the decision contained in its abbreviated electric and gas distribution rate order issued in December 2010. As part of the March 2011 comprehensive rate order, BGE was authorized to defer $19 million of costs as regulatory assets. These costs will be recovered over a 5-year period beginning December 2010 and include the deferral of $16 million of storm costs incurred in February 2010. The regulatory asset for the storm costs earns a regulated rate of return.

Smart Meter and Smart Grid Investments (Exelon and BGE). In August 2010, the MDPSC approved a comprehensive smart grid initiative for BGE which includes the planned installation of 2 million residential and commercial electric and gas smart meters at an expected total cost of $480 million. The MDPSC's approval ordered BGE to defer the associated incremental costs, depreciation and amortization, and an appropriate return, in a regulatory asset until such time as a cost-effective advanced metering system is delivered to customers. Under a grant from the DOE, BGE is a recipient of $200 million in federal funding for its smart grid and other related initiatives. This grant allows BGE to be reimbursed for smart grid and other expenditures up to $200 million, substantially reducing the total cost of these initiatives.

During the three months ended March 31, 2012, BGE received $14 million in reimbursements from the DOE. As of March 31, 2012, BGE's outstanding receivable from the DOE for reimbursable costs was $1 million, which has been recorded in other accounts receivable, net on Exelon's and BGE's Consolidated Balance Sheets.

New Electric Generation (Exelon and BGE). On April 12, 2012, the MDPSC issued an order directing BGE and two other Maryland utilities to enter a contract for difference (CfD) with CPV Maryland, LLC (CPV), under which CPV will construct a 661 MW natural gas-fired combined-cycle generation plant in Waldorf, MD, with a projected commercial operation date of June 1, 2015. The initial term of the proposed contract is 20 years. The CfD will provide that the utilities will pay (or receive) the difference between CPV's contract prices and the revenues CPV receives for capacity and energy from bidding the unit into the PJM market. The utilities are required to enter into a CfD in amounts proportionate to their relative SOS load as of the date of execution. The utilities are directed to meet with CPV and the consultant for the MDPSC to negotiate changes to the CfD for submission to the MDPSC for approval. Depending on the precise terms of the CfD, the eventual market conditions and the manner of cost recovery, the CfD could have a material impact on Exelon's and BGE's financial results. On April 27, 2012, a civil complaint was filed in the United States District Court for the District of Maryland by certain unaffiliated parties that challenges the actions taken by the MDPSC on federal law grounds. Among other requests for relief, the plaintiffs seek to enjoin the MDPSC from executing or otherwise putting into effect any part of its order. On May 4, 2012, BGE filed a petition in the Circuit Court for Anne Arundel County, Maryland, seeking judicial review of the MDPSC order. Similar petitions have been filed by two other Maryland utilities in other Maryland State Courts.

PJM Minimum Offer Price Rule (Exelon and Generation). PJM's capacity market rules include a Minimum Offer Price Rule (MOPR) intended to ensure that a competitive capacity offer is based on the costs and competitive market revenues of a new entry unit. On February 1, 2011, in response to the enactment of New Jersey Senate Bill 2381, Exelon Generation joined the PJM Power Providers Group (P3) complaint at FERC seeking a revision to PJM's MOPR to preclude the exercise of buyer market power. In response to P3's complaint, PJM filed revisions to the MOPR which were largely approved by FERC in its April 12, 2011 Order. The revised MOPR, among other things, sets a minimum price level for sell offers for capacity from certain types of new generation resources submitted in PJM's capacity market auctions. While a number of state regulators and consumer groups opposed the MOPR revision, the changes were in line with recent FERC orders regarding capacity markets in the New York and New England ISOs. A number of parties filed for rehearing of the FERC order.

Exelon, ComEd, PECO and BGE prepare their consolidated financial statements in accordance with the authoritative guidance for accounting for certain types of regulation. Under this guidance, regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent the excess recovery of costs or accrued credits that have been deferred because it is probable such amounts will be returned to customers through future regulated rates or represent billings in advance of expenditures for approved regulatory programs.

The following tables provide information about the regulatory assets and liabilities of Exelon, ComEd, PECO and BGE as of March 31, 2012 and December 31, 2011. The Registrants have reclassified certain regulatory asset and liability balances as of December 31, 2011 in order to align the reporting of regulatory activities subsequent to the closing of the merger with Constellation. For additional information on the specific regulatory assets and liabilities, refer to Note 2 of the Exelon 2011 Form 10-K for Exelon, ComEd and PECO and Note 6 of BGE's 2011 Form 10-K.

March 31, 2012		Exelon				ComEd				PECO					BGE

Regulatory assets		Current		Noncurrent		Current		Noncurrent		Current			Noncurrent		Current		Noncurrent
Pension and other postretirement
	benefits(a)	$	265	$	3,512	$	0	$	0	$	5		$	0	$	2	$	0
Deferred income taxes			12		1,243		5		64		0			1,115		7		64
AMI and smart meter programs			2		46		2		6		0			22		0		18
Under-recovered distribution service
	costs		19		99		19		99		0			0		0		0
Debt costs			15		78		12		70		3			8		2		10
Fair value of BGE long-term debt (b)			41		253		0		0		0			0		0		0
Fair value of BGE supply contract (c)			117		89		0		0		0			0		0		0
Severance			28		44		25		31		0			0		3		13
Asset retirement obligations			0		76		0		52		0			24		0		0
MGP remediation costs			31		124		24		85		6			37		1		2
RTO start-up costs			3		3		3		3		0			0		0		0
Under-recovered electric universal
	service fund costs		5		0		0		0		5			0		0		0
Financial swap with Generation			0		0		590		92		0			0		0		0
Renewable energy and associated
	RECs		16		125		16		125		0			0		0		0
Under-recovered energy and
	transmission costs		139		0		85		0		9	(d)		0		45		0
DSP Program costs			3		2		0		0		3			2		0		0
Deferred storm costs			3		8		0		0		0			0		3		8
Electric generation-related
	regulatory asset		16		52		0		0		0			0		16		52
Rate stabilization deferral			63		282		0		0		0			0		63		282
Energy efficiency and demand
	response programs		29		100		0		0		0			0		29		100
Other			39		32		12		17		17			9		3		4

Total regulatory assets		$	846		6,168	$	793	$	644	$	48		$	1,217	$	174	$	553

Regulatory liabilities
Nuclear decommissioning		$	0	$	2,430	$	0	$	2,017	$	0		$	413	$	0	$	0
Removal costs			86		1,396		64		1,191		0			0		22		205
Energy efficiency and demand
	response programs		42		79		42		0		0			79		0		0
Electric distribution tax repairs			20		145		0		0		20			145		0		0
Over-recovered uncollectible
	accounts		10		0		10		0		0			0		0		0
Over-recovered energy and
	transmission costs		55		0		11		0		44	(e)		0		0		0
Over-recovered gas universal
	service fund costs		3		0		0		0		3			0		0		0
Over-recovered AEPS costs			6		0		0		0		6			0		0		0
Customer rate credit			113		0		0		0		0			0		113		0

Total regulatory liabilities		$	335	$	4,050	$	127	$	3,208	$	73		$	637	$	135	$	205

December 31, 2011		Exelon				ComEd				PECO					BGE

Regulatory assets		Current		Noncurrent		Current		Noncurrent		Current			Noncurrent		Current		Noncurrent
Pension and other postretirement
	benefits	$	204	$	2,794	$	0	$	0	$	7		$	0	$	3	$	0
Deferred income taxes			5		1,176		5		66		0			1,110		7		64
AMI and smart meter programs			2		28		2		6		0			22		0		15
Under-recovered distribution service
	costs		14		70		14		70		0			0		0		0
Debt costs			18		81		15		73		3			8		2		10
Severance			25		38		25		38		0			0		0		1
Asset retirement obligations			0		74		0		50		0			24		0		0
MGP remediation costs			30		129		24		91		6			38		1		2
RTO start-up costs			3		4		3		4		0			0		0		0
Under-recovered uncollectible
Under-recovered electric universal
	service fund costs		3		0		0		0		3			0		0		0
Financial swap with Generation			0		0		503		191		0			0		0		0
Renewable energy and associated
	RECs		9		97		9		97		0			0		0		0
Under-recovered energy and
	transmission costs		57		0		48		0		9	(b)		0		50		0
DSP Program costs			3		2		0		0		3			2		0		0
Deferred storm costs			0		0		0		0		0			0		3		9
Electric generation-related
	regulatory asset		0		0		0		0		0			0		16		56
Rate stabilization deferral			0		0		0		0		0			0		63		295
Energy efficiency and demand
	response programs		0		0		0		0		0			0		29		95
Other			17		25		9		13		8			12		0		3

Total regulatory assets		$	390	$	4,518	$	657	$	699	$	39		$	1,216	$	174	$	550

Regulatory liabilities
Nuclear decommissioning		$	0	$	2,222	$	0	$	1,857	$	0		$	365	$	0	$	0
Removal costs			61		1,185		61		1,185		0			0		18		200
Energy efficiency and demand
	response programs		49		69		49		0		0			69		0		0
Electric distribution tax repairs			19		151		0		0		19			151		0		0
Over-recovered uncollectible
	accounts		15		0		15		0		0			0		0		0
Over-recovered energy and
	transmission costs		42		0		12		0		30	(c)		0		0		0
Over-recovered gas universal
	service fund costs		3		0		0		0		3			0		0		0
Over-recovered AEPS costs			8		0		0		0		8			0		0		0

Total regulatory liabilities		$	197	$	3,627	$	137	$	3,042	$	60		$	585	$	18	$	200

ComEd, PECO and BGE are required, under separate legislation and regulations in Illinois, Pennsylvania and Maryland, respectively, to purchase certain receivables from retail electric and natural gas suppliers. For retail suppliers participating in the utilities' consolidated billing, ComEd, PECO and BGE must purchase their customer accounts receivables. ComEd and BGE purchase receivables at a discount to primarily recover uncollectible accounts expense from the suppliers. PECO is required to purchase receivables at face value and permitted to recover uncollectible accounts expense from customers through distribution rates. Purchased receivables are classified in other accounts receivable, net on Exelon's, ComEd's, PECO's and BGE's Consolidated Balance Sheets. The following tables provide information about the purchased receivables of the Registrants as of March 31, 2012 and December 31, 2011.

As of March 31, 2012	Exelon		ComEd		PECO		BGE
Purchased receivables (a)	$	146	$	20	$	57	$	69
Allowance for uncollectible accounts (b)		(13)		(3)		(6)		(4)
Purchased receivables, net	$	133	$	17	$	51	$	65

As of December 31, 2011	Exelon (c)		ComEd		PECO		BGE
Purchased receivables (a)	$	68	$	16	$	52	$	61
Allowance for uncollectible accounts (b)		(5)		-		(5)		(3)
Purchased receivables, net	$	63	$	16	$	47	$	58

(a) PECO's gas POR program became effective on January 1, 2012 and includes a 1% discount on purchased receivables in order to recover the implementation costs of the program. If the costs are not fully recovered when PECO files its next gas distribution rate case, PECO will propose a mechanism to recover the remaining implementation costs as a distribution charge to low volume transportation customers or apply future discounts on purchased receivables from natural gas suppliers serving those customers.

(b) For ComEd and BGE, reflects the incremental allowance for uncollectible accounts recorded, which is in addition to the purchase discount. For ComEd, the incremental uncollectible accounts expense is recovered through its Purchase of Receivables with Consolidated Billing (PORCB) tariff.