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

Except for the matters noted below, the disclosures set forth in Note 3 of the Exelon 2012 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). EIMA provides a structure for substantial capital investment by utilities over a ten-year period to modernize Illinois' electric utility infrastructure. EIMA allows for the recovery of costs by a utility through a pre-established performance-based formula rate tariff, approved by the ICC.

On April 1, 2013, ComEd filed annual progress reports on both its Infrastructure Investment Plan and AMI Implementation Plan as required by statute. On April 9, 2013, the ICC initiated an investigation proceeding pursuant to the provisions of EIMA to review ComEd's progress in implementing the AMI Plan. The ICC's Order in this proceeding is expected by June 30, 2013.

On April 29, 2013, ComEd filed its 2013 distribution formula rate update, which establishes the net revenue requirement used to set the rates that will take effect in January 2014 after the ICC's review. The revenue requirement requested in the filing is based on 2012 actual costs and forecasted 2013 capital additions as well as an annual reconciliation of the revenue requirement in effect in 2012 to the actual costs incurred for that year. ComEd requested a total increase to the net revenue requirement of $311 million, reflecting an increase of $169 million for the initial revenue requirement for 2013 and an increase of $142 million for the annual reconciliation for 2012. The initial revenue requirement for 2013 provided for a weighted average debt and equity return on distribution rate base of 6.99% inclusive of an allowed return on common equity of 8.72%, reflecting the average rate on 30-year treasury notes plus 580 basis points. The annual reconciliation for 2012 provided for a weighted average debt and equity return on distribution rate base of 7.01% inclusive of an allowed return on common equity of 8.72%, reflecting the average rate on 30-year treasury notes plus 580 basis points.

Rates effective in 2013 as a result of the 2012 distribution formula rate update are subject to a reconciliation to actual 2013 costs, which will be filed with the ICC in 2014. The approved annual reconciliation amount will be reflected in customer rates beginning in January 2015. Throughout each year, ComEd records regulatory assets or regulatory liabilities and corresponding increases or decreases to operating revenues for any differences between the revenue requirement in effect and its best estimate of the probable increase or decrease in the revenue requirement expected to ultimately be approved by the ICC in that year's reconciliation proceedings based on the year's actual costs incurred.

As of March 31, 2013, and December 31, 2012, ComEd recorded a net regulatory asset associated with the distribution formula rate of $255 million and $209 million, respectively.

Senate Bill 9 and House Bill 2529 (Exelon and ComEd). During March 2013, the Illinois House and Senate each passed Senate Bill 9 with supermajority votes to clarify the intent of EIMA on three major issues: the use of year-end rather than average rate base and capital structure in the annual reconciliation, the use of ComEd's weighted average cost of capital interest rate to apply to the annual reconciliation and an allowed return on ComEd's pension asset. These major issues were also addressed in ComEd's appeal of the ICC's May 2012 Order and October 2012 Rehearing Order filed in the Illinois Appellate Court in October 2012. See Note 3 of the Exelon 2012 Form 10-K for further details regarding the appeal. In addition, Senate Bill 9 provides for accelerated AMI deployment that would commence earlier than 2015 as currently approved by the ICC.

On March 21, 2013, Senate Bill 9 was sent to the Illinois Governor for his consideration. The Illinois Governor vetoed the legislation on May 5, 2013. ComEd intends to seek legislative override of the Illinois Governor's veto, which requires approval by supermajority votes in each of the Illinois House and Senate. If the legislation becomes law by June 15, 2013, ComEd would also update certain elements of its AMI deployment schedule to provide for an accelerated deployment as called for by Senate Bill 9.

If the legislation is enacted, ComEd projects that Senate Bill 9 would result in increased operating revenues of approximately $25 million and $65 million in 2013 and 2014, respectively. Also, if the legislation is enacted, ComEd projects that Senate Bill 9 would accelerate capital expenditures by approximately $35 million and $40 million in 2013 and 2014, respectively. The April 29, 2013 annual distribution formula rate filing discussed above does not reflect the enactment of Senate Bill 9. If enacted, the distribution formula rate update filing will be revised to reflect the passage of such legislation shortly thereafter.

Illinois Procurement Proceedings (Exelon and ComEd). ComEd is permitted to recover its electricity procurement costs from retail customers without mark-up. The IPA's 2013 procurement plan, approved by the ICC, provides for curtailment of the existing long-term contracts for renewable energy and RECs in response to the increased number of ComEd's customers purchasing their energy from alternative energy suppliers on their own or through municipal aggregation. In March 2013, ICC staff and the IPA approved ComEd's updated load forecast. Purchases under the existing long-term contracts for energy and the associated RECs were reduced under the terms of the contracts for the June 2013 – May 2014 period on a pro-rata basis to keep the purchases under the statutory impact cap. The curtailment was applied proportionately to each of the long-term renewable energy suppliers consistent with the terms of the contracts on an equal, pro-rata basis. The curtailment did not have a significant impact on ComEd's financial position or cash flows.

On December 19, 2012, the ICC issued an order directing ComEd and Ameren (the Utilities) to enter into sourcing agreements with FutureGen Industrial Alliance, Inc (FutureGen), under which FutureGen will retrofit and repower an existing plant in Morgan County, Illinois to a 166 MW near zero emissions coal-fueled generation plant, with an assumed commercial operation date in 2017. The proposed term of the agreement is 20 years. The project was approved by the DOE on February 4, 2013. The sourcing agreement is currently being drafted and approved under a separate proceeding, with a final order expected in the second quarter of 2013. The sourcing agreement is expected to stipulate that the Utilities will pay (or receive) the difference between FutureGen's contract prices and the revenues FutureGen receives for capacity and energy from bidding the unit into the MISO markets. The order also directs the Utilities to recover (or pass along) the difference from the Utilities' distribution system customers, regardless of whether they purchase electricity from the Utility or from an alternative electric generation supplier. On January 22, 2013, ComEd filed an application for rehearing, requesting the ICC reconsider its December order by expanding the parties to the sourcing agreement to also include RES suppliers. On January 29, 2013, the ICC denied ComEd's rehearing request. ComEd filed an appeal on February 22, 2013, questioning the legality of requiring ComEd to procure power for its non-Eligible Retail Customers. Depending on the precise terms of the sourcing agreement, the eventual market conditions, and the manner of cost recovery, the sourcing agreement could have a material adverse impact on Exelon's and ComEd's cash flows and financial positions.

See Note 17 – Commitments and Contingencies for additional information on ComEd's energy commitments.

Pennsylvania Procurement Proceedings (Exelon and PECO). PECO's current PAPUC approved DSP Program, under which PECO is providing default electric service, has a 29-month term that ends May 31, 2013. On October 12, 2012, the PAPUC issued its Opinion and Order approving PECO's second DSP Program, which was filed with the PAPUC in January 2012. The program, 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.

In the second DSP Program, PECO will procure electric supply for its default electric customers through five competitive procurements. The load for the residential and small and medium commercial classes will be served through competitively procured fixed price, full requirements contracts of two years or less. Similar to the current DSP Program, 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. In December 2012 and February 2013, PECO entered into contracts with PAPUC-approved bidders, including Generation, for its residential and small and medium commercial classes beginning in June 2013. 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.

In addition, the second DSP Program includes a number of retail market enhancements recommended by the PAPUC in its previously issued Retail Markets Intermediate Work Plan Order. PECO was also directed to allow its low-income Customer Assistance Program (CAP) customers to purchase their generation supply from EGSs beginning April 2014. On May 1, 2013, PECO filed its CAP Shopping Plan with the PAPUC.

Smart Meter and Smart Grid Investments (Exelon and PECO). Pursuant to Act 129 and the follow-on Implementation Order of 2009, in April 2010, the PAPUC approved PECO's Smart Meter Procurement and Installation Plan (SMPIP), under which PECO will install more than 1.6 million smart meters and an AMI communication network by 2020. The first phase of PECO's SMPIP included the installation of an AMI communications network and the deployment of 600,000 smart meters to communicate with that network. On January 18, 2013, PECO filed with the PAPUC its universal deployment plan for approval of its proposal to deploy the remainder of the 1.6 million smart meters on an accelerated basis by the end of 2014. In total, PECO currently expects to spend up to $595 million, excluding the cost of the original meters (as further described below), on its smart meter infrastructure and approximately $120 million on smart grid investments through 2014 before considering the DOE reimbursements discussed below. As of March 31, 2013, PECO has spent $262 million and $103 million on smart meter and smart grid infrastructure, respectively, not including the DOE reimbursements received to date.

Pursuant to the ARRA of 2009, PECO and the DOE entered into a Financial Assistance Agreement to extend PECO $200 million in non-taxable SGIG funds of which $140 million relates to smart meter deployment and $60 million relates to smart grid infrastructure. As part of the agreement, the DOE has a conditional ownership interest in qualifying Federally-funded project property and equipment, which is subordinate to PECO's existing mortgage. The SGIG funds are being used to offset the total impact to ratepayers of the smart meter deployment required by Act 129. As of March 31, 2013, PECO has received $161 million of the $200 million in reimbursements. PECO's outstanding receivable from the DOE for reimbursable costs was $8 million as of March 31, 2013, which has been recorded in other accounts receivable, net on Exelon's and PECO's Consolidated Balance Sheets.

On August 15, 2012, PECO suspended 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 has replaced the previously installed meters with an alternative vendor's meters. PECO intends to move forward with the alternative meters during universal deployment and continues to evaluate meters from several vendors and may use more than one meter vendor during universal deployment.

Following PECO's decision, as of October 9, 2012 PECO will no longer use the original smart meters. For the meters that will no longer be used the accounting guidance requires that any difference between the carrying value and net realizable value be recognized in the current period's earnings, before considering potential regulatory recovery. The cost of the original meters, including installation and removal costs, owned by PECO was approximately $19 million, net of approximately $16 million of reimbursements from the DOE. PECO is seeking full recovery of all incurred costs related to the original deployment of meters. For amounts not recovered from the vendor, PECO will seek regulatory rate recovery in a future filing with the PAPUC. PECO did not seek recovery of original meter costs in the January 2013 universal deployment filing, as resolution with the vendor is still pending. In November 2012, PECO requested and received approval from the DOE that the original meters continue to be allowable costs. In addition, PECO remains eligible for the full $200 million in SGIG funds.

As of March 31, 2013, PECO believes the amounts incurred for the original meters and related installation and removal costs are probable of recovery based on applicable case law and past precedent on reasonably and prudently incurred costs. As a result, a regulatory asset of $17 million, representing the cost of the original meters, net of accumulated depreciation and DOE reimbursements, was recorded on Exelon's and PECO's Consolidated Balance Sheets. If PECO later determines that the regulatory asset is no longer probable of recovery, PECO would be required to recognize a charge in earnings in the period in which that determination was made.

Energy Efficiency Programs (Exelon and PECO). PECO's PAPUC-approved Phase I EE&C Plan has a four-year term that began on June 1, 2009 and will conclude on May 31, 2013. The Phase I Plan sets forth how PECO will meet the required reduction targets established by Act 129's EE&C provisions, which include a 3% reduction in electric consumption in PECO's service territory and a 4.5% reduction in PECO's annual system peak demand in the 100 hours of highest demand by May 31, 2013. The peak demand period ended on September 30, 2012 and PECO communicated its compliance with the reduction targets in a preliminary report with the PAPUC on March 1, 2013. The final compliance report is due to the PAPUC by November 15, 2013.

On March 29, 2013, PECO filed a Petition with the PAPUC to change the recovery period of certain Direct Load Control (DLC) Program costs necessary to implement the Phase I Plan. The Petition seeks approval to allow PECO to recover $12 million in equipment, installation and information technology costs for its Residential DLC program with the amounts collected for the Phase I Plan. As the Phase I Plan was implemented at a cost less than originally budgeted, PECO proposes to recover these expenses from its Phase I Energy Efficiency Program Charge over-collection consistent with PAPUC guidance to recover all Phase I costs through Phase I funding. The PAPUC approved PECO's Petition on May 9, 2013.

The PAPUC issued its Phase II EE&C implementation order on August 2, 2012, that provides energy consumption reduction requirements for the second phase of Act 129's EE&C programs, which will go into effect on June 1, 2013. The PAPUC deferred a decision on peak demand reduction requirements until mid-2013. On February 28, 2013, the PAPUC approved PECO's three-year EE&C Phase II plan that was filed on November 1, 2012, and 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.

On March 15, 2013, PECO filed a Petition for Approval to Amend its EE&C Phase II Plan to continue its DLC demand reduction program for mass market customers from June 1, 2013 to May 31, 2014. PECO proposed to fund the estimated $10 million cost of the one-year program by modifying incentive levels for other Phase II programs. On May 9, 2013, the PAPUC approved PECO's amended EE&C Phase II plan. The costs of DLC program will be recovered through PECO's Energy Efficiency Program Charge along with all other Phase II Plan costs.

Investigation of Pennsylvania 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 March 1, 2012, the PAPUC issued the final order describing more detailed recommendations to be implemented prior to the expiration of the electric distribution company's current default service plan and providing guidelines for electric distribution companies for development of their next default service plan. On October 12, 2012, the PAPUC approved PECO's second DSP Program, 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. Further, the PAPUC issued a final order on February 14, 2013, outlining its proposed end-state for default service, which included default service pricing for residential and small commercial customers based on three month full requirements contracts, full requirement contracts using hourly spot market pricing for large commercial and industrial default service customers, and the inclusion of CAP customers in the customer choice programs.

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 during the first year rates are in effect. The PAPUC's implementation order requires a utility to have a Long Term Infrastructure Improvement Plan (LTIIP) which outlines how the utility is planning to increase its investment for repairing, improving, or replacing aging infrastructure, approved by the Commission prior to implementing a DSIC. On May 9, 2013, the PAPUC approved PECO's LTIIP for its Gas Operations which was filed on February 8, 2013.

Smart Meter and Smart Grid Investments (Exelon and BGE). In August 2010, the MDPSC approved a comprehensive smart grid initiative for BGE that 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. As of March 31, 2013 and December 31, 2012, BGE recorded a regulatory asset of $37 million and $31 million, respectively, representing incremental costs, depreciation and amortization, and a debt return on fixed assets related to its AMI program given that it believes such costs are probable of recovery in future rates. Additionally, the MDPSC has determined that the cost recovery for the non-AMI meters that BGE retires will be considered in a future depreciation proceeding. The MDPSC continues to evaluate the impacts of a customer opt-out feature in BGE's Smart Grid program. The ultimate resolution related to this feature could affect BGE's ability to demonstrate cost-effectiveness of the advanced metering system. Pursuant to the ARRA of 2009, BGE is a recipient of $200 million in federal funding from the DOE for its smart grid and other related initiatives, which substantially reduces the total cost of these initiatives to BGE's ratepayers. The project to install the smart meters began in late April 2012.

As of March 31, 2013, BGE had received $162 million in reimbursements from the DOE. As of March 31, 2013, 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.

Reliability and Quality of Service Standards (Exelon and BGE). During its 2011 legislative session, the Maryland General Assembly passed legislation:

In May 2011, the Governor of Maryland signed this legislation into law. The related new service quality and reliability regulations became effective on May 28, 2012. These regulations are still being implemented and could have a material impact on BGE's financial results of operations, cash flows and financial position.

New Electric Generation (Exelon, Generation 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 an approximately 700 MW natural gas-fired combined-cycle generation plant in Waldorf, Maryland, that it projected will be in commercial operation by June 1, 2015. The initial term of the proposed contract is 20 years. The CfD mandates that the utilities pay (or receive) the difference between CPV's contract prices and the revenues CPV receives for capacity and energy from clearing the unit in the PJM capacity market. 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. 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. Trial of this matter occurred in March 2013, and a decision from the trial judge is now pending. 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 pending the outcome of the underlying MDPSC proceeding.

On April 16, 2013, the MDPSC issued an order that required BGE to execute a contract with CPV within 20 days of the date of the order, and BGE executed the contract on May 6, 2013. As of March 31, 2013, there is no impact on Exelon's and BGE's results of operations, cash flows and financial positions. Furthermore, the agreement does not become effective until the resolution of certain items, including all current litigation.

Depending on the ultimate outcome of the pending litigation, on the eventual market conditions and on the manner of cost recovery as of the effective date of the agreement, the CfD could have a material impact on Exelon's and BGE's results of operations, cash flows and financial positions.

Exelon believes that this and other states' projects may have artificially suppressed capacity prices in PJM and may continue to do so in future auctions to the detriment of Exelon's market driven position. In addition to this litigation, Exelon is working with other market participants to implement market rules that will appropriately limit the market suppressing effect of such state activities.

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. On February 22, 2013, the MDPSC issued an order in BGE's 2012 electric and natural gas distribution rate case for increases in annual distribution service revenue of $81 million and $32 million, respectively. The electric distribution rate increase was set using an allowed return on equity of 9.75% and the gas distribution rate increase was set using an allowed return on equity of 9.60%. The approved electric and natural gas distribution rates became effective for services rendered on or after February 23, 2013. As part of the rate order, the MDPSC approved both recovery of and return on merger integration costs, including severance. As a result, the order affirmed the treatment of $20 million of severance-related costs that BGE had recorded as a regulatory asset in 2012, consistent with prior MDPSC decisions. Additionally, BGE established a new regulatory asset of $8 million related to non-severance-related merger integration costs as of March 31, 2013, which includes $6 million of costs incurred during 2012. These merger integration regulatory assets are recovered over a five year period.

MDPSC Derecho Storm Order (Exelon and BGE). Following the June 2012 Derecho storm which hit the mid-Atlantic region interrupting electrical service to a significant portion of the State of Maryland, the MDPSC issued an order on February 27, 2013 that requires BGE and other Maryland utilities to file several comprehensive reports on improving reliability and grid resiliency that are due at various times before August 30, 2013. BGE cannot predict the outcome of this review, which may result in increased capital expenditures and operating costs. BGE currently expects that any increased capital expenditures and operating costs would be recoverable in distribution rates.

The Maryland Strategic Infrastructure Development and Enhancement Program (Exelon and BGE). In February 2013, the Maryland General Assembly passed legislation intended to accelerate gas infrastructure replacements in Maryland by establishing a mechanism for gas companies to promptly recover reasonable and prudent costs of eligible infrastructure replacement projects separate from base rate proceedings. On May 2, 2013, the Governor of Maryland signed the legislation into law; the law takes effect June 1, 2013. Under the new law, following a proceeding before the MDPSC and with the MDPSC's approval of the eligible infrastructure replacement projects along with a corresponding surcharge, BGE could begin charging gas customers a monthly surcharge for infrastructure costs incurred after June 1, 2013. The legislation includes a cap on the monthly surcharge to residential customers, which effectively caps the surcharge for other customers, and would require an annual true-up of the surcharge revenues against actual expenditures. Investment levels in excess of the cap would be recoverable in a subsequent gas base rate proceeding at which time all costs for the infrastructure replacement projects would be rolled into gas distribution rates. Irrespective of the cap, BGE is required to file a gas rate case every five years under this legislation.

Transmission Formula Rate (Exelon, ComEd and BGE). ComEd's and BGE's transmission rates are each established based on a FERC-approved formula.

ComEd's most recent annual formula rate update filed in April 2013 reflects 2012 actual costs plus forecasted 2013 capital additions. The update resulted in a revenue requirement of $488 million plus a $25 million adjustment related to the reconciliation of 2012 actual costs for a net revenue requirement of $513 million. This compares to the May 2012 updated 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. The increase in the revenue requirement was primarily driven by increased plant investment, higher pension and post-retirement healthcare costs, and higher operating and maintenance costs. The 2013 net revenue requirement will become effective June 1, 2013, and is recovered over the period extending through May 31, 2014. The regulatory asset associated with the true-up is being amortized as the associated amounts are recovered through rates.

ComEd's updated formula transmission rate currently provides for a weighted average debt and equity return on transmission rate base of 8.70%, a decrease from the 8.91% return previously authorized. The decrease in return was primarily due to lower interest rates on ComEd's long-term debt outstanding. As part of the FERC-approved settlement of ComEd's 2007 transmission rate case, the rate of return on common equity is 11.5% and the common equity component of the ratio used to calculate the weighted average debt and equity return for the formula transmission rate is currently capped at 55%.

BGE's most recent annual formula rate update filed in April 2013 reflects actual 2012 expenses and investments plus forecasted 2013 capital additions. The update resulted in a revenue requirement of $158 million offset by a $1 million reduction related to the reconciliation of 2012 actual costs for a net revenue requirement of $157 million. This compares to the April 2012 updated revenue requirement of $156 million increased by $2 million related to the reconciliation of 2011 actual costs for a net revenue requirement of $158 million. The decrease in the revenue requirement was primarily driven by a lower authorized rate of return and reduced rate base, offset partially by higher depreciation and operating and maintenance costs. The 2013 net revenue requirement will become effective June 1, 2013, and is recovered over the period extending through May 31, 2014. The regulatory asset associated with the true-up is being amortized as the associated amounts are recovered through rates.

BGE's updated formula transmission rate currently provides for a weighted average debt and equity return on transmission rate base of 8.35%, a decrease from the 8.43% return previously authorized. The decrease in return was primarily due to a debt issuance in 2012 and lower interest rates on BGE's debt outstanding. As part of the FERC-approved settlement in 2006 of BGE's 2005 transmission rate case and updated by FERC's November 2007 order in BGE's 2007 incentive rate filing, the base rate of return on common equity for BGE's electric transmission business is 11.3%.

FERC Transmission Complaint (Exelon and BGE). On February 27, 2013, consumer advocates and regulators from the District of Columbia, New Jersey, Delaware and Maryland, and the Delaware Electric Municipal Cooperatives (the parties), filed a complaint at FERC against BGE and the Pepco Holdings, Inc. companies relating to their respective transmission formula rates. BGE's formula rate includes a 10.8% base rate of return on common equity for most investments included in its rate base. The parties seek a reduction in the base return on equity to 8.7% and changes to the formula rate process. FERC docketed the matter and set April 3, 2013 as the deadline for interventions, protests and answers. Under FERC rules, the earliest date from which the base return on equity could be adjusted and refunds required is the date of the complaint. On March 19, 2013, BGE filed a motion to dismiss or sever the complaint. As of March 31, 2013, BGE cannot predict the likelihood or a reasonable estimate of the amount of a change, if any, in the allowed base ROE, or a reasonable estimate of the refund period start date. While BGE cannot predict the outcome of this matter, if FERC orders a reduction of BGE's base ROE to 8.7%, the annual impact would be a reduction in revenues of approximately $10 million.

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. In April 2007, FERC issued an order concluding that PJM's current rate design for existing facilities is just and reasonable and should not be changed. In the same order, FERC held that the costs of new facilities 500 kV and above should be socialized across the entire PJM footprint and that the costs of new facilities less than 500 kV should be allocated to the customers of the new facilities who caused the need for those facilities. After FERC ultimately denied all requests for rehearing on all issues, several parties filed petitions in the U.S. Court of Appeals for the Seventh Circuit for review of the decision. On August 6, 2009, that court issued its decision affirming FERC's order with regard to the costs of existing facilities but reversing and remanding to FERC for further consideration its decision with regard to the costs of new facilities 500 kV and above. On January 21, 2010, FERC issued an order establishing paper hearing procedures to supplement the record. On March 30, 2012, FERC issued an order on remand affirming the cost allocation in its April 2007 order. On March 22, 2013, FERC issued an order denying rehearing and made it clear that the cost allocation at issue concerns only projects approved prior to February 1, 2013. A number of entities have filed appeals of the FERC orders. ComEd anticipates that all impacts of any rate design changes effective after December 31, 2006, should be recoverable through retail rates and, thus, the rate design changes are not expected to have a material impact on ComEd's results of operations, cash flows or financial position. PECO anticipates that all impacts of any rate design changes should be recoverable through the transmission service charge rider approved in PECO's 2010 electric distribution rate case settlement and, thus, the rate design changes are not expected to have a material impact on PECO's results of operations, cash flows or financial position. To the extent any rate design changes are retroactive to periods prior to January 1, 2011, there may be an impact on PECO's results of operations. BGE anticipates that all impacts of any rate design changes effective after the implementation of its standard offer service programs in Maryland should be recoverable through retail rates and, thus, the rate design changes are not expected to have a material impact on BGE's results of operations, cash flows or financial position.

On October 11, 2012, the PJM Transmission Owners filed with FERC a cost allocation for new transmission facilities asking that the new cost allocation methodology apply to all transmission approved by the PJM Board on or after February 1, 2013. The proposed methodology is a hybrid methodology that would socialize 50% of the costs of new facilities at 500kV and above and double-circuit 345kV lines, and allocate the remaining 50% to direct beneficiaries. For all other facilities, the costs would be allocated to the direct beneficiaries. On March 22, 2013, FERC issued an order accepting the cost allocation with minor exceptions and requiring a compliance filing on those few issues within 120 days of the order.

PJM Minimum Offer Price Rule (Exelon and Generation). PJM's capacity market rules include a Minimum Offer Price Rule (MOPR) that is intended to preclude sellers from artificially suppressing the competitive price signals for generation capacity. The proceedings leading to the FERC's approval of the existing MOPR were extensive. The parties disputed numerous elements of the MOPR including: (i) the default price that should apply to bids found subject to the MOPR, (ii) the duration of the MOPR and (iii) the application of the MOPR to self-supplying capacity and state-sponsored capacity. The FERC orders approving the existing MOPR have been appealed to the Third Circuit Court of Appeals. A resolution of that appeal is not expected until sometime in late 2013.

In May 2012, PJM announced the results of its capacity auction covering 2015 and 2016. Several new units with state-sanctioned subsidy contracts cleared in the auction at prices below the MOPR. Potentially, states will expand such state-sanctioned subsidy programs or other states may seek to establish similar programs. Generation believes that further revisions to the MOPR are necessary to ensure that the potential to artificially reduce capacity auction prices is appropriately limited in PJM. In late December 2012, PJM filed a new MOPR for approval at the FERC, which Exelon believed would be more effective in preventing state-sanctioned subsidy contracts from artificially reducing capacity prices. Generation was actively involved in the process through which the MOPR changes were developed and supported the changes. On February 5, 2013, the FERC issued a letter finding that PJM's new MOPR filing is deficient and requested that PJM provide additional information on several aspects of PJM's MOPR proposal. In early March 2013, PJM filed the additional information requested by the FERC. On May 3, 2013, the FERC issued its order. While the FERC order accepted certain aspects of the proposal that Exelon supported (such as applying the MOPR to all of PJM and not just certain zones within PJM), the FERC required PJM to retain a key element of its previous MOPR structure, the unit-specific exemption, an element that Exelon had supported removing. Exelon is currently considering its options with respect to this proceeding.

Market Based Rates (Exelon, Generation, ComEd, PECO and BGE). Generation, ComEd, PECO and BGE are public utilities for purposes of the Federal Power Act and are required to obtain FERC's acceptance of rate schedules for wholesale electricity sales. Currently, Generation, ComEd, PECO and BGE have authority to execute wholesale electricity sales at market-based rates. As is customary with market-based rate schedules, FERC has reserved the right to suspend market-based rate authority on a retroactive basis if it subsequently determines that Generation, ComEd, PECO or BGE has violated the terms and conditions of its tariff or the Federal Power Act. FERC is also authorized to order refunds in certain instances if it finds that the market-based rates are not just and reasonable under the Federal Power Act.

As required by FERC's regulations, as promulgated in the Order No. 697 series, Generation, ComEd, PECO and BGE have filed market power analyses using the prescribed market share screens to demonstrate that Generation, ComEd, PECO and BGE qualify for market-based rates in the regions where they are selling energy and capacity under market-based rate tariffs. These analyses must examine historic test period data and must be updated every three years on a prescribed schedule. The most recent updated analysis for the PJM and Northeast Regions was filed in late 2010, based on 2009 historic test period data. On June 22, 2011, FERC issued an order confirming Generation's continued authority to charge market based rates, based on Generation's most recent updated analysis filed in 2010, stating that any market power concerns are adequately addressed by PJM's monitoring and mitigation programs. Similarly, on June 29, 2012, Generation, ComEd, BGE and PECO filed their updated market power analysis for the Central Region which the FERC accepted on November 13, 2012, and on December 23, 2011, Generation filed its updated market power analysis for the Southeast Region which the FERC accepted on October 10, 2012. On December 21, 2012, Generation, ComEd, BGE and PECO filed their updated market power analysis for the SPP region, and the FERC has not yet acted on this filing.

Reliability Pricing Model (Exelon, Generation and BGE). PJM's RPM auctions take place 36 months ahead of the scheduled delivery year. The most recent auction for the delivery year ending May 31, 2016 occurred in May 2012.

License Renewals (Exelon and Generation). On June 22, 2011, Generation submitted applications to the NRC to extend the operating licenses of Limerick Units 1 and 2 by 20 years. The current operating licenses for Limerick Units 1 and 2 expire in 2024 and 2029, respectively. In June 2012, the United States District Court of Appeals for the DC Circuit vacated the NRC's temporary storage rule on the grounds that the NRC should have conducted a more comprehensive environmental review to support the rule. The temporary storage rule (also referred to as the “waste confidence decision”) recognizes that licensees can safely store spent nuclear fuel at nuclear plants for up to 60 years beyond the original and renewed licensed operating life of the plants and that licensing renewal decisions do not require discussion of the environmental impact of spent fuel stored on site. In August 2012, the NRC placed a hold on issuing new or renewed operating licenses that depend on the temporary storage rule until the court's decision is addressed. In September 2012, the NRC directed NRC Staff to revise the temporary storage rule through rulemaking no later than September 6, 2014. Generation does not expect the NRC to issue license renewals until the end of 2014, at the earliest.

On August 29, 2012 and August 30, 2012, Generation submitted hydroelectric license applications to the FERC for 46-year licenses for the Conowingo Hydroelectric Project (Conowingo) and the Muddy Run Pumped Storage Facility Project (Muddy Run), respectively. Generation is working with stakeholders to resolve licensing issues, including: (1) water quality, (2) fish passage and habitat, and (3) sediment. In the third quarter 2013, Exelon expects to file a water quality certification application pursuant to Section 401 of the Clean Water Act with the MDE for Conowingo, and a water quality certification application pursuant to Section 401 of the Clean Water Act with the PA DEP for Muddy Run, addressing these and other issues. The stations are being depreciated over their useful lives, which includes the license renewal period. Although Generation expects that these licenses will be renewed, it cannot predict the conditions that may be imposed. Resolution of these issues may require a substantial increase in capital expenditures or may result in increased operating costs and significantly affect Generation's results of operations or financial position. Based on the latest FERC procedural schedule, the FERC licensing process is not expected to be completed prior to the expiration of Muddy Run's current license on August 31, 2014, and the expiration of Conowingo's license on September 1, 2014. However, the stations would continue to operate under annual licenses until FERC takes action on the 46-year license applications.

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, 2013 and December 31, 2012. For additional information on the specific regulatory assets and liabilities, refer to Note 3 of the Exelon 2012 Form 10-K.

March 31, 2013		Exelon				ComEd				PECO				BGE

Regulatory assets		Current		Noncurrent		Current		Noncurrent		Current		Noncurrent		Current		Noncurrent
Pension and other postretirement
	benefits (a)	$	308	$	3,685	$	0	$	0	$	0	$	0	$	0	$	0
Deferred income taxes			14		1,397		5		63		0		1,269		9		65
AMI programs			3		81		3		16		0		28		0		37
AMI meter events			0		17		0		0		0		17		0		0
Under-recovered distribution service
	costs		52		203		52		203		0		0		0		0
Debt costs			13		65		10		60		3		5		1		9
Fair value of BGE long-term debt (b)			0		245		0		0		0		0		0		0
Fair value of BGE supply contract (c)			61		9		0		0		0		0		0		0
Severance			29		23		25		6		0		0		4		17
Asset retirement obligations			0		92		0		67		0		25		0		0
MGP remediation costs			56		223		49		189		6		32		1		2
RTO start-up costs			3		2		3		2		0		0		0		0
Under-recovered uncollectible
	accounts		6		0		6		0		0		0		0		0
Under-recovered electric universal
	service fund costs		4		0		0		0		4		0		0		0
Financial swap with Generation			0		0		85		0		0		0		0		0
Renewable energy and associated
	RECs		15		60		15		60		0		0		0		0
Under-recovered energy and
	transmission costs		32		0		32		0		0		0		0		0
DSP Program costs			1		3		0		0		1		3		0		0
DSP II Program costs			2		2		0		0		2		2		0		0
Deferred storm costs			3		5		0		0		0		0		3		5
Electric generation-related
	regulatory asset		13		40		0		0		0		0		13		40
Rate stabilization deferral			67		209		0		0		0		0		67		209
Energy efficiency and demand
	response programs		49		129		0		0		0		0		49		129
Merger integration costs (d)			1		7		0		0		0		0		1		7
Other			33		24		16		15		17		8		0		2

Total regulatory assets		$	765		6,521	$	301	$	681	$	33	$	1,389	$	148	$	522

March 31, 2013		Exelon				ComEd				PECO					BGE

Regulatory liabilities		Current		Noncurrent		Current		Noncurrent		Current			Noncurrent		Current			Noncurrent
Nuclear decommissioning		$	0	$	2,530	$	0	$	2,138	$	0		$	392	$	0		$	0
Removal costs			98		1,417		77		1,199		0			0		21			218
Energy efficiency and demand
	response programs		145		0		43		0		102			0		0			0
Electric distribution tax repairs			20		125		0		0		20			125		0			0
Gas distribution tax repairs			8		43						8			43
Over-recovered uncollectible
	accounts		0		0		0		0		0			0		0			0
Over-recovered energy and
	transmission costs		85		0		6		0		71	(e)		0		8	(i)		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
Revenue subject to refund (f)			40		0		40		0		0			0		0			0
Over-recovered electric and gas
	revenue decoupling (g)		15		0		0		0		0			0		15			0
Other			3		0		0		0		0			0		3			0

Total regulatory liabilities		$	418	$	4,115	$	166	$	3,337	$	205		$	560	$	47		$	218

December 31, 2012		Exelon				ComEd				PECO					BGE

Regulatory assets		Current		Noncurrent		Current		Noncurrent		Current			Noncurrent		Current			Noncurrent
Pension and other postretirement
	benefits (a)	$	304	$	3,673	$	0	$	0	$	0		$	0	$	0		$	0
Deferred income taxes			14		1,382		5		62		0			1,255		9			65
AMI programs			3		70		3		10		0			29		0			31
AMI meter events			0		17		0		0		0			17		0			0
Under-recovered distribution service
	costs		18		191		18		191		0			0		0			0
Debt costs			14		68		11		62		3			6		1			9
Fair value of BGE long-term debt (b)			0		256		0		0		0			0		0			0
Fair value of BGE supply contract (c)			77		12		0		0		0			0		0			0
Severance			29		28		25		12		0			0		4			16
Asset retirement obligations			0		90		0		65		0			25		0			0
MGP remediation costs			58		232		51		197		6			33		1			2
RTO start-up costs			3		2		3		2		0			0		0			0
Under-recovered electric universal
	service fund costs		11		0		0		0		11			0		0			0
Financial swap with Generation			0		0		226		0		0			0		0			0
Renewable energy and associated
	RECs		18		49		18		49		0			0		0			0
Under-recovered energy and
	transmission costs		43		0		14		0		1	(h)		0		28	(i)		0
DSP Program costs			1		3		0		0		1			3		0			0
DSP II Program costs			1		2		0		0		1			2		0			0
Deferred storm costs			3		6		0		0		0			0		3			6
Electric generation-related
	regulatory asset		16		40		0		0		0			0		16			40
Rate stabilization deferral			67		225		0		0		0			0		67			225
Energy efficiency and demand
	response programs		56		126		0		0		0			0		56			126
Under-recovered electric
	revenue decoupling (g)		5		0		0		0		0			0		5			0
Other			23		25		14		16		9			8		0			2

Total regulatory assets		$	764	$	6,497	$	388	$	666	$	32		$	1,378	$	190		$	522

December 31, 2012		Exelon				ComEd				PECO					BGE

Regulatory liabilities		Current		Noncurrent		Current		Noncurrent		Current			Noncurrent		Current		Noncurrent
Nuclear decommissioning		$	0	$	2,397	$	0	$	2,037	$	0		$	360	$	0	$	0
Removal costs			97		1,406		75		1,192		0			0		22		214
Energy efficiency and demand
	response programs		131		0		43		0		88			0		0		0
Electric distribution tax repairs			20		132		0		0		20			132		0		0
Gas distribution tax repairs			8		46		0		0		8			46
Over-recovered uncollectible
	accounts		6		0		6		0		0			0		0		0
Over-recovered energy and
	transmission costs		54		0		6		0		48	(e)		0		0		0
Over-recovered gas universal
	service fund costs		3		0		0		0		3			0		0		0
Over-recovered AEPS costs			2		0		0		0		2			0		0		0
Revenue subject to refund (f)			40		0		40		0		0			0		0		0
Over-recovered gas revenue
	decoupling (g)		7		0		0		0		0			0		7		0

Total regulatory liabilities		$	368	$	3,981	$	170	$	3,229	$	169		$	538	$	29	$	214

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. Exelon, ComEd, PECO and BGE do not record unbilled commodity receivables under the POR programs. Purchased billed 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, 2013 and December 31, 2012.

As of March 31, 2013	Exelon		ComEd		PECO		BGE
Purchased receivables (a)	$	244	$	86	$	69	$	89
Allowance for uncollectible accounts (b)		(25)		(13)		(7)		(5)
Purchased receivables, net	$	219	$	73	$	62	$	84

As of December 31, 2012	Exelon		ComEd		PECO		BGE
Purchased receivables (a)	$	191	$	55	$	65	$	71
Allowance for uncollectible accounts (b)		(21)		(9)		(6)		(6)
Purchased receivables, net	$	170	$	46	$	59	$	65

(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.