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.

EIMA provides a structure for substantial capital investment over a ten-year period to modernize Illinois' electric utility infrastructure. EIMA allows the recovery of costs by a utility through a pre-established performance-based formula rate tariff, approved by the ICC and will provide greater certainty as to the recovery of those costs. ComEd made an initial contribution of $15 million (recognized as expense in 2011) to a new Science and Technology Innovation Trust fund on July 31, 2012, and will make recurring annual contributions of $4 million beginning in 2012, which will be used for customer education for as long as the AMI Deployment Plan remains in effect. In addition, 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.

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 that proceeding was to establish the formula rate under which rates will be calculated going-forward, and the initial rates, which went into effect in late June. On May 29, 2012, the ICC issued its final Order (May Order) in that proceeding. The May Order reduced the annual revenue requirement by $168 million, or approximately $110 million more than proposed by ComEd. Of this incremental revenue requirement reduction, approximately $50 million reflected the ICC's determination that certain costs should be recovered through alternative rate recovery tariffs available to ComEd or will be reflected in a subsequent annual reconciliation, thereby primarily delaying the timing of cash flows. The incremental revenue reduction also reflected a $35 million reduction for the disallowance of return on ComEd's pension asset, a $10 million reduction for incentive compensation related adjustments, and $15 million of reductions for various adjustments for cash working capital, operating reserves, and other technical items. In the second quarter of 2012, ComEd recorded a reduction of revenue of approximately $100 million pre-tax to decrease the regulatory asset for the 2011 periods and for the first three months of 2012 consistent with the terms of the May Order.

On June 22, 2012, the ICC granted an expedited rehearing on the issues of ComEd's pension asset recovery, the use of average or year-end rate base in determining ComEd's reconciliation revenue requirement and the interest rate charged on over/under recovered costs. On October 3, 2012, the ICC issued its final order (Rehearing Order) in ComEd's expedited rehearing. The Rehearing Order adopted ComEd's position on the return on its pension asset, resulting in an increase in ComEd's annual revenue requirement. In two other areas, the ICC ruled against ComEd by reaffirming use of an average rather than year-end rate base in ComEd's reconciliation revenue requirement; and amending its prior order to provide a short-term debt rate as the appropriate interest rate to apply to under/over recoveries of incurred costs. ComEd filed an appeal of the May Order and the Rehearing Order in court on October 4, 2012. ComEd expects to record in the fourth quarter of 2012 an increase in revenue of approximately $135 million pre-tax consistent with the terms of the Rehearing Order.

On January 6, 2012, ComEd filed its Infrastructure Investment Plan with the ICC. Under that 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 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. On June 22, 2012, the ICC approved the AMI Deployment Plan with certain modifications. However, as a result of the Rehearing Order above, ComEd is delaying certain elements of the AMI Deployment Plan, including the delay of installation of additional smart meters. ComEd has outlined the new deployment schedule within testimony provided in the AMI Plan Rehearing on October 3, 2012. As a result of the Rehearing Order ComEd has deferred approximately $50 million of the 2012 AMI Deployment Plan and $15 million of planned capital investment to future years. An Order from the ICC on ComEd's revised deployment plan is due by December 5, 2012.

ComEd will file an annual reconciliation of the revenue requirement in effect in a given year to reflect actual costs that the ICC determines are prudently and reasonably incurred for such year. ComEd made its initial 2011 reconciliation filing on April 30, 2012, which reconciled the 2011 revenue requirement in effect to ComEd's actual 2011 costs incurred (the rates will take effect in January 2013). ComEd updated its 2011 reconciliation filing on June 12, 2012 to reflect the impacts of the May Order discussed above. A similar reconciliation with respect to 2012 will be filed in second quarter 2013 with any adjustments to rates taking effect in January 2014. As of September 30, 2012 and December 31, 2011, ComEd recorded an estimated net regulatory asset of $74 million and $84 million, respectively, which represents the ICC's approved distribution formula and associated rulings as of September 30, 2012 and 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 for the twelve months ended December 31, 2011 and for the nine months ended September 30, 2012. The evidentiary hearing in ComEd's 2011 reconciliation rate case was held on September 25, 2012, and a final order is due by December 26, 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, as discussed above.

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 the ICC's approval of 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. The Illinois Supreme Court denied the Petition on September 26, 2012, and returned the matter to the ICC to calculate a refund amount. 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 16 – 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, small commercial and medium commercial procurement classes that commenced in June 2012, hourly spot market price full requirements contracts for its small and medium commercial and large commercial and industrial procurement classes that commenced in June 2012 and block contracts for its residential class beginning in December 2012. In September 2012, PECO completed its last competitive procurement under the DSP Program for electric supply for default electric service. PECO entered into block contracts with PAPUC-approved bidders, including Generation, for its residential class beginning in 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 and Comprehensive Income.

On October 12, 2012, the PAPUC issued its Opinion and Order approving PECO's second DSP Plan, which was filed with the PAPUC in January 2012. The plan, which has a 24-month term from June 1, 2013 through May 31, 2015, complies with electric generation procurement guidelines set forth in Act 129. Under the second 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, administrative costs and AEPS 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 24-month term.

In the second DSP plan, the load for the residential and small and medium commercial classes will be served through competitively procured contracts for fixed price, full requirements contracts of two years or less. Similar to the current DSP plan, for the large commercial and industrial class load, PECO will competitively procure contracts for 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. The first competitive procurement is expected to take place for the residential class in December 2012 for default electric service commencing June 1, 2013.

In addition, the second DSP plan includes a number of retail market enhancements recommended by the PAPUC in its previously issued Retail Markets Intermediate Work Plan Order. In the PAPUC's Opinion and Order, PECO was also directed to develop a plan by January 1, 2014 that will allow its low-income Customer Assistance Program (CAP) customers to purchase their generation supply from EGSs. PECO expects to file its plan by March 2013.

Smart Meter and Smart Grid Investments (Exelon and PECO). Pursuant to Act 129 and the follow-on Implementation Order of 2009 by the PAPUC, PECO began the first phase of its smart meter deployment in March 2012. The first phase calls for the installation of an AMI communications network and the deployment of 600,000 smart meters to communicate with that network. The first phase of smart meter deployment was estimated to cost $415 million.

Pursuant to the ARRA of 2009, PECO and the DOE entered into a Financial Assistance Agreement to extend PECO $200 million in SGIG funds. Of the $200 million in grant money, $140 million is being applied to the AMI technology deployment, including 600,000 smart meters in the first phase deployment. Therefore, the SGIG funds are being used to offset the impact to ratepayers of the smart meter deployment required by Act 129. As of September 30, 2012, PECO has received $130 million in reimbursements from the DOE for its smart meter deployment and other grid improvements. PECO's outstanding receivable from the DOE for reimbursable costs was $16 million as of September 30, 2012, which has been recorded in other accounts receivable, net on Exelon's and PECO's Consolidated Balance Sheets.

On August 15, 2012, PECO suspended its installation of smart meters for new customers based on a limited number of incidents involving overheating meters. Following its own internal investigation and additional scientific analysis and testing by independent experts completed after September 30, 2012, PECO announced its decision to resume meter deployment work on October 9, 2012. PECO will replace 186,000 previously installed meters with Landis+Gyr (L+G) meters by the end of November 2012 and will use L+G meters for the remainder of the first phase deployment.

As of September 30, 2012, the carrying value of the original meters, including installation and removal costs, owned by PECO was approximately $18 million, net of approximately $16 million of reimbursements from the DOE. PECO does not expect the change in vendor to impact its eligibility for the $200 million in SGIG funds. PECO is seeking and anticipates full recovery of these meter and other incremental costs incurred in response to the overheating incidents, and, therefore, expects this matter will not have a material impact on PECO's results of operations, cash flows or financial position.

Energy Efficiency Program (Exelon and PECO). PECO's PAPUC-approved EE&C Plan has a four-year term that began on June 1, 2009 and sets forth how PECO will meet the various reduction targets established by Act 129's EE&C provisions. In addition to energy consumption reductions, Act 129 requires Pennsylvania electric distribution companies to reduce peak demand by a minimum of 4.5% of their annual system peak demand in the 100 hours of highest demand. The peak demand period ended on September 30, 2012 and PECO will report its compliance with the reduction targets in a filing with the PAPUC by December 2012.

On August 2, 2012, the PAPUC issued its Phase II EE&C implementation order. The order provides energy consumption reduction requirements for the second phase of Act 129 EE&C programs, which will go into effect on June 1, 2013, but defers a decision on peak demand reduction requirements until the first quarter of 2013. The order tentatively establishes PECO's three year cumulative consumption reduction target at 2.9%. The order also provides the opportunity for any electric utility to challenge its proposed target in an evidentiary hearing, which PECO requested on August 20, 2012. In addition, on September 4, 2012, PECO filed a Petition for Reconsideration of the terms of the PAPUC's implementation order for Phase II, which was subsequently denied.

Pursuant to the Phase II implementation order, PECO filed its three year EE&C Phase II plan with the PAPUC on November 2, 2012. The plan sets forth how PECO will reduce electric consumption by at least 2.9% in its service territory for the period June 1, 2013 through May 31, 2016, adjusted for weather and extraordinary loads. The implementation order permits PECO to apply any excess savings achieved during Phase I against its Phase II consumption reduction targets, with no reduction to its Phase II budget. In accordance with the Act 129 Phase II implementation order, at least 10% and 4.5% of the total consumption reductions must be through programs directed toward PECO's public and low income sectors, respectively. If PECO fails to achieve the required reductions in consumption, it will be subject to civil penalties of up to $20 million, which would not be recoverable from ratepayers. Act 129 mandates that that the total cost of the plan may not exceed 2% of the electric company's total annual revenue as of December 31, 2006.

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 has obtained $14 million of collateral as of September 30, 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 October 12, 2012, the PAPUC approved PECO's second DSP plan, which includes 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 issued the final order describing more detailed recommendations to be implemented prior to an expiration of the electric distribution company's current default service plan and providing guidelines for electric distribution companies for the development of their next default service plan. Further, the PAPUC issued a Secretarial Letter on September 27, 2012, outlining its proposed end-state for default service, which included short-term contracts for all default service providers of approximately 3 months and the inclusion of CAP customers in the customer choice programs. A Tentative Order on these proposals is expected to be issued in November 2012.

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' 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. On August 2, 2012, the PAPUC issued a final order establishing rules and procedures to implement the ratemaking provisions of Act 11.

2010 Natural Gas Distribution Rate Case (Exelon and PECO). PECO's 2010 natural gas distribution rate case settlement approved by the PAPUC stipulates that the expected cash benefit resulting from the application of new tax repairs deduction methodologies for 2010 and prior tax years must be refunded to customers over a seven-year period. In September 2012, PECO filed an application with the IRS to change its method of accounting for gas distribution repairs for the 2011 tax year. The expected total refund to customers for the tax cash benefit from the application of the new method to costs incurred prior to 2011 is $54 million, for which PECO has recorded a regulatory liability that is reflected on Exelon's and PECO's Consolidated Balance Sheets as of September 30, 2012. This amount is subject to adjustment based on the outcome of IRS examinations. Credits will be reflected in customer bills beginning January 1, 2013. The prospective tax benefits claimed as a result of the new methodology will be reflected in tax expense in the year in which they are claimed on the tax return and will be reflected in the determination of revenue requirements in the next natural gas distribution base rate case. See Note 10 – Income Taxes for additional information.

2011 Maryland Electric and Gas Distribution Rate Case (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 are being recovered over a 5-year period which began in 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 implemented. Under a grant from the DOE, BGE is a recipient of $200 million in federal funding for its smart grid and other related initiatives, which substantially reduces the total cost of these initiatives. The project to install the smart meters began in late April 2012.

As of September 30, 2012, BGE had received $126 million in reimbursements from the DOE. As of September 30, 2012, BGE's outstanding receivable from the DOE for reimbursable costs was $13 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 into a contract for differences (CfD) with CPV Maryland, LLC (CPV), under which CPV will construct a 700 MW natural gas-fired combined-cycle generation plant in Waldorf, Maryland, with an assumed 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 markets. The three Maryland utilities are required to enter into a CfD in amounts proportionate to their relative SOS load as of the date of execution. Depending on the precise terms of the CfD, the eventual market conditions, and the manner of cost recovery, the CfD could have a material adverse impact on Exelon's and BGE's results of operations, cash flows and financial positions. 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. The MDPSC and CPV filed motions to dismiss the federal lawsuit, which were both denied by the U.S. District Court on August 3, 2012. On May 4, 2012, BGE filed a petition in the Circuit Court for Anne Arundel County, Maryland, seeking judicial review of the MDPSC order. That petition was subsequently transferred to the Circuit Court for Baltimore City, where similar appeals have been filed by other interested parties. All cases have now been consolidated and will be heard together by the Circuit Court for Baltimore City in the first quarter of 2013.

2012 Maryland Electric and Gas Distribution Rate Case (Exelon and BGE). On July 27, 2012, BGE filed an application for increases to its electric and gas base rates with the MDPSC. The requested rate of return on equity in the application is 10.5%. On October 22, 2012, BGE filed an updated application to request an increase of $131 million and $45 million to its electric and gas base rates, respectively. The new electric and gas distribution base rates are expected to take effect in late February 2013. BGE cannot predict how much of the requested increases, if any, the MDPSC will approve.

Annual Transmission Formula Rate Update (Exelon, ComEd and BGE). ComEd's most recent annual formula rate update filed in May 2012 reflects actual 2011 expenses and investments plus forecasted 2012 capital additions. The update resulted in a revenue requirement of $450 million offset by a $5 million reduction related to the reconciliation of 2011 actual costs for a net revenue requirement of $445 million. This compares to the May 2011 updated revenue requirement of $438 million offset by a $16 million reduction related to the reconciliation of 2010 actual costs for a net revenue requirement of $422 million. The increase in the revenue requirement was primarily driven by higher depreciation, pension and operating and maintenance costs, and the absence of a one-time credit that had been included in 2010 costs. The 2012 net revenue requirement became effective June 1, 2012 and is recovered over the period extending through May 31, 2013. The regulatory liability associated with the true-up is being amortized as the associated amounts are refunded.

ComEd's updated formula transmission rate currently provides for a weighted average debt and equity return on transmission rate base of 8.91%, a decrease from the 9.10% return for the prior year, primarily due to lower debt costs. As part of the FERC-approved settlement of ComEd's 2007 rate case, the return on common equity is 11.5% and the common equity component of the ratio used to calculate the weighted average debt and equity return for the formula transmission rate is currently capped at 55%.

PJM Transmission Rate Design and Operating Agreements (Exelon, ComEd, PECO and BGE). PJM Transmission Rate Design specifies the rates for transmission service charged to customers within PJM. Currently, ComEd, PECO and BGE 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.

ComEd, PECO and BGE are committed to the construction of transmission facilities under their operating agreements with PJM to maintain system reliability. ComEd, PECO and BGE will work with PJM to continue to evaluate the scope and timing of any required construction projects. ComEd, PECO and BGE's RTEP baseline project commitments changed as of September 30, 2012 from December 31, 2011 as follows:

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. FERC generally denied rehearing, and the FERC orders have been appealed to the Third Circuit Court of Appeals. A resolution of that appeal is not expected until sometime in 2013.

In May 2012, PJM announced the results of its capacity auction covering 2015/2016. Several new units with state-sanctioned subsidy contracts cleared in the auction at prices below the MOPR. There is potential that states will expand such state-sanctioned subsidy programs or that other states may seek to establish similar programs. Exelon believes that further revisions to the MOPR may be necessary to ensure that the potential to artificially reduce capacity auction prices is appropriately limited in PJM. In late September, PJM announced to all of its stakeholders that a group of its stakeholders had developed a proposal addressing the shortcomings of the current MOPR. PJM plans to have its stakeholders review and consider these proposed MOPR changes in October and November with a potential vote on these proposed MOPR changes in late November 2012. PJM would need to obtain approval from the FERC prior to implementing any changes. Exelon was actively involved in the process through which the MOPR changes were developed, supports the changes and intends to continue to work with PJM and its stakeholders to obtain necessary approvals.

License Renewals (Exelon and Generation). On August 29, 2012 and August 30, 2012, Generation submitted hydroelectric license applications to the FERC for 46-year licenses for the Muddy Run Pumped Storage Project and the Conowingo Hydroelectric Project. The FERC review process is scheduled to be completed by August 31, 2014 and September 1, 2014, when the current Conowingo and Muddy Run licenses expire.

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 September 30, 2012 and December 31, 2011. Upon consummation of the merger, the Registrants reclassified certain regulatory asset and liability balances as of December 31, 2011 in order to align the reporting of the regulated utilities. 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.

September 30, 2012		Exelon				ComEd				PECO					BGE

Regulatory assets		Current		Noncurrent		Current		Noncurrent		Current			Noncurrent		Current		Noncurrent
Pension and other postretirement
	benefits(a)	$	264	$	3,499	$	0	$	0	$	2		$	0	$	1	$	0
Deferred income taxes			13		1,346		5		62		0			1,220		8		64
AMI and smart meter programs			2		54		2		5		0			24		0		25
Under-recovered distribution service
	costs		0		119		0		119		0			0		0		0
Debt costs			14		71		11		65		3			6		2		9
Fair value of BGE long-term debt (b)			43		226		0		0		0			0		0		0
Fair value of BGE supply contract (c)			94		31		0		0		0			0		0		0
Severance			30		36		25		19		0			0		5		17
Asset retirement obligations			0		84		0		59		0			25		0		0
MGP remediation costs			65		227		58		190		6			35		1		2
RTO start-up costs			3		3		3		3		0			0		0		0
Under-recovered electric universal
	service fund costs		8		0		0		0		8			0		0		0
Financial swap with Generation			0		0		352		0		0			0		0		0
Renewable energy and associated
	RECs		17		53		17		53		0			0		0		0
Under-recovered energy and
	transmission costs		62		0		22		0		7	(d)		0		33		0
DSP Program costs			2		2		0		0		2			2		0		0
DSP II Program costs			0		2		0		0		0			2		0		0
Deferred storm costs			3		7		0		0		0			0		3		7
Electric generation-related
	regulatory asset		16		44		0		0		0			0		16		44
Rate stabilization deferral			65		244		0		0		0			0		65		244
Energy efficiency and demand
	response programs		55		117		0		0		0			0		55		117
Other			30		27		16		14		14			9		0		5

Total regulatory assets		$	786		6,192	$	511	$	589	$	42		$	1,323	$	189	$	534

September 30, 2012		Exelon				ComEd				PECO					BGE

Regulatory liabilities		Current		Noncurrent		Current		Noncurrent		Current			Noncurrent		Current		Noncurrent
Nuclear decommissioning		$	0	$	2,383	$	0	$	2,021	$	0		$	362	$	0	$	0
Removal costs			94		1,397		73		1,185		0			0		21		212
Energy efficiency and demand
	response programs		82		33		37		0		45			33		0		0
Electric distribution tax repairs			18		138		0		0		18			138		0		0
Gas distribution tax repairs			5		49						5			49
Over-recovered distribution service
	costs		45		0		45		0		0			0		0		0
Over-recovered uncollectible
	accounts		10		0		10		0		0			0		0		0
Over-recovered energy and
	transmission costs		39		0		7		0		32	(e)		0		0		0
Over-recovered gas universal
	service fund costs		3		0		0		0		3			0		0		0
Over-recovered AEPS costs			1		0		0		0		1			0		0		0
Customer rate credit			1		0		0		0		0			0		1		0
Other			1		0		0		0		1			0		0		0

Total regulatory liabilities		$	299	$	4,000	$	172	$	3,206	$	105		$	582	$	22	$	212

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 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	(d)		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

December 31, 2011		Exelon				ComEd				PECO					BGE

Regulatory liabilities		Current		Noncurrent		Current		Noncurrent		Current			Noncurrent		Current		Noncurrent
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	(e)		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 September 30, 2012 and December 31, 2011.

As of September 30, 2012	Exelon		ComEd		PECO		BGE
Purchased receivables (a)	$	203	$	56	$	72	$	75
Allowance for uncollectible accounts (b)		(18)		(6)		(7)		(5)
Purchased receivables, net	$	185	$	50	$	65	$	70

As of December 31, 2011	Exelon		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.