Regulatory Matters (Exelon, Generation, ComEd, PECO and BGE)

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

Except for the matters noted below, the disclosures set forth in Note 3 - Regulatory Matters of the Exelon 2013 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.

Illinois Regulatory Matters

Energy Infrastructure Modernization Act (Exelon and ComEd). Since 2011, ComEd’s distribution rates are established through a performance-based rate formula, pursuant to EIMA. Participating utilities are required to file an annual update to the performance-based formula rate tariff on or before May 1, with resulting rates effective in January of the following year. This annual formula rate update is based on prior year actual costs and current year projected capital additions. The update also reconciles any differences between the revenue requirement(s) in effect for the prior year and actual costs incurred for that year. ComEd's earned rate of return on common equity is required to be within plus or minus 50 basis points ("the collar") of the target rate of return determined as the annual average rate on 30-year treasury notes plus 580 basis points. Therefore, the collar limits favorable and unfavorable impacts of weather and load on distribution revenue. In addition, ComEd's target rate of return on common equity is subject to reduction if ComEd does not deliver the reliability and customer service benefits, as defined, it has committed to over the ten-year life of the investment program. ComEd records regulatory assets or regulatory liabilities and corresponding increases or decreases to operating revenues for any differences between the revenue requirement(s) in effect and ComEd’s best estimate of the revenue requirement expected to be approved by the ICC for that year’s reconciliation. As of September 30, 2014, and December 31, 2013, ComEd had recorded a net regulatory asset associated with the distribution formula rate of $466 million and $463 million, respectively. The regulatory asset associated with the distribution true-up will be amortized as the associated amounts are recovered through rates.

On April 16, 2014, ComEd filed its annual distribution formula rate update with the ICC. The filing establishes the revenue requirement used to set the rates that will take effect in January 2015 after the ICC’s review and approval, which is due by December 2014. The revenue requirement requested is based on 2013 actual costs plus projected 2014 capital additions as well as an annual reconciliation of the revenue requirement in effect in 2013 to the actual costs incurred that year. ComEd's 2014 filing request includes a total increase to the net revenue requirement of $269 million, reflecting an increase of $174 million for the initial revenue requirement for 2014 and an increase of $95 million related to the annual reconciliation for 2013. The revenue requirement for 2014 provides for a weighted average debt and equity return on distribution rate base of 7.06% inclusive of an allowed return on common equity of 9.25%, reflecting the average rate on 30-year treasury notes plus 580 basis points. The annual reconciliation for 2013 provided for a weighted average debt and equity return on distribution rate base of 7.04% inclusive of an allowed return on common equity of 9.20%, reflecting the average rate on 30-year treasury notes plus 580 basis points less a performance metrics penalty of 5 basis points.

On October 15, 2014, the ALJ issued its proposed order in ComEd’s current distribution formula rate proceeding, recommending an increase to the net revenue requirement of $239 million as compared to ComEd’s request of $269 million discussed above. The $30 million reduction, a portion of which may be recoverable through other recovery mechanisms, consisted of a decrease of $20 million for the initial revenue requirement for 2014 and a decrease of $10 million related to the annual reconciliation for 2013. The ALJs proposed order has no independent legal effect as the ICC must vote on a final order by mid December 2014, which may materially vary from the findings and conclusions in the proposed order. If the ICC provides significant changes to ComEd’s filed revenue requirement request, it could have a material impact on ComEd’s current and future results of operations and cash flows.

EIMA also provides a structure for substantial capital investment by utilities over a ten-year period to modernize Illinois' electric utility infrastructure. Participating utilities are required to file an annual update on their AMI implementation progress. On April 1, 2014, ComEd filed an annual progress report on its AMI Implementation Plan with the ICC. The ICC ruled that no investigation would be opened in regards to that April filing. In March 2014, ComEd filed a petition with the ICC for approval to accelerate the deployment of AMI meters. On June 11, 2014, the ICC approved ComEd's accelerated deployment plan which allows for the installation of more than four million smart meters throughout ComEd's service territory by 2018, three years in advance of the originally scheduled 2021 completion date. To date, nearly 500,000 smart meters have been installed in the Chicago area.

Appeal of the 2012 Formula Rate Tariff (Exelon and ComEd). On April 30, 2012, ComEd filed its annual distribution formula rate update. The filing established the revenue requirement used to set the rates that were effective in January 2013. On December 20, 2012, the ICC issued its final order, which increased the revenue requirement by $73 million. The $73 million reflected an increase of $80 million for the initial revenue requirement for 2012 and a decrease of $7 million for the annual reconciliation for 2011. The rate increase was set using an allowed return on capital of 7.54% (inclusive of an allowed return on common equity of 9.81%). The rates took effect in January 2013. ComEd and intervenors requested a rehearing on specific issues, which was denied by the ICC. ComEd and intervenors also filed appeals with the Illinois Appellate Court.

On June 30, 2014, the Illinois Appellate Court issued its opinion, finding against ComEd on two issues and for ComEd on a third issue. The two issues (billing determinants and the use of certain allocators) were the same issues previously rejected by the Court in the Appeal of Initial Formula Rate Tariff (see Appeal of Initial Formula Rate Tariff discussed below). The Court re-affirmed the ICC’s order and rejected ComEd’s arguments. However, on the third issue (rate case expenses), the Court allowed for the possibility of future recovery. The Court’s opinion has no accounting impact as ComEd recorded the distribution formula regulatory asset consistent with the ICC’s final Order.

Appeal of Initial Formula Rate Tariff (Exelon and ComEd). On March 26, 2014, the Illinois Appellate Court issued an opinion with respect to ComEd’s appeal of the ICC’s order relating to ComEd’s initial formula rate tariff. The most significant financial issues under appeal related to ICC findings that were counter to the formula rate legislation and were clarified by subsequent legislation (Senate Bill 9). Therefore, only a subset of the issues originally appealed remained. The Court found against ComEd on each of the remaining issues: compensation related adjustments, billing determinants and the use of certain allocators. The Court’s opinion has no accounting impact as ComEd recorded the distribution formula regulatory asset consistent with the ICC’s final Order.

ComEd has asked the Illinois Supreme Court to hear the issue of allocation between State and Federal regulatory jurisdictions. On June 4, 2014, ComEd filed a Petition for Leave to Appeal with the Illinois Supreme Court solely on the issue of allocation between FERC and ICC jurisdictional costs. On July 2, 2014, the ICC filed its Answer to the Petition, arguing that Supreme Court review is not necessary or appropriate. Under the procedural rules of the Illinois Supreme Court, ComEd is not allowed to reply to the ICC filing. There is no set time by which the Court must rule on the Petition. ComEd cannot predict whether the Court will grant the appeal, or if it does, the ultimate outcome.

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 court held the ICC abused its discretion in not reducing ComEd’s rate base to account for an additional 18 months of accumulated depreciation while including post-test year pro forma plant additions through that period. ComEd continued to bill rates as established under the ICC’s order in the 2007 Rate Case until June 1, 2011 when the rates set in the 2010 electric distribution rate case became effective. In subsequent ICC proceedings, the ICC issued an order 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 with the Court.

However, on September 27, 2013, the Court ruled against ComEd on the accumulated depreciation issue and affirmed that ComEd owes a refund to customers of approximately $37 million, including interest. On September 18, 2014, the ICC issued an order which modified the timing of the refund, now to occur in November 2014, rather than the eight month period previously approved. The refund will be included with the Rider AMP refund discussed below. Former ComEd customers also are eligible for a refund. As of September 30, 2014, and December 31, 2013, ComEd had fully reserved for this liability.

Advanced Metering Program Proceeding (Exelon and ComEd). As part of ComEd’s 2007 Rate Case, the ICC approved recovery of costs associated with ComEd’s Rider SMP for the limited purpose of implementing a pilot program for AMI. In October 2009, the ICC approved ComEd’s AMI pilot program and associated rider (Rider AMP). ComEd collected approximately $24 million under Rider AMP and had no collections under Rider SMP through September 30, 2014. In ComEd’s 2010 electric distribution rate case, the ICC approved ComEd’s transfer of certain other costs from recovery under Rider AMP to recovery through electric distribution rates.

Several parties, including the Illinois Attorney General, appealed the ICC’s orders on Rider SMP and Rider AMP. The Illinois Appellate Court reversed the ICC’s approval of the cost recovery provisions of Rider SMP and Rider AMP on September 30, 2010 and March 19, 2012, respectively. In both cases, the Court ruled that the ICC’s approval of the rider constituted single-issue ratemaking. ComEd filed Petitions for Leave to Appeal to the Illinois Supreme Court, which were denied.

In October 2013, the ICC opened an investigation on Rider AMP to determine if a refund is required and if so, to determine the appropriate refund amount. The ALJ presiding over the investigation requested each party provide a pre-trial memorandum describing their positions, which were submitted on April 10, 2014. The ICC Staff and the Illinois Attorney General proposed a refund of $14.6 million, representing the amount they claim was collected under Rider AMP since September 30, 2010, the date the Illinois Appellate Court reversed the ICC’s approval of the cost recovery provisions of Rider SMP. ComEd believes no refund is appropriate and that any refund obligation associated with Rider AMP should be prospective from no earlier than the date of the Illinois Appellate Court’s order on Rider AMP, or March 19, 2012, which would represent a refund of approximately $0.4 million. During the second quarter of 2014, ComEd reached a tentative agreement to jointly resolve the disputed refund claim. On September 18, 2014, the ICC approved a refund of $9.5 million plus interest to be issued to current customers in November 2014. Former ComEd customers also are eligible for a refund. As of September 30, 2014, ComEd had fully reserved for this liability.

Grand Prairie Gateway Transmission Line (ComEd). On December 2, 2013, ComEd filed a request to obtain the ICC’s approval to construct a 60-mile, overhead 345kV transmission line that traverses Ogle, DeKalb, Kane and DuPage Counties in Northern Illinois. On May 28, 2014, in a separate proceeding, FERC issued an order granting ComEd’s request to include 100% of the capital costs recorded to construction work in progress during construction of the line in ComEd’s transmission rate base. If the project is cancelled or abandoned for reasons beyond ComEd’s control, FERC approved the ability for ComEd to recover 100% of its prudent costs incurred after May 21, 2014 and 50% of its costs incurred prior to May 21, 2014 in ComEd’s transmission rate base. On October 22, 2014, the ICC issued an order approving ComEd’s Grand Prairie Gateway Project over the objection of numerous landowners and the City of Elgin. Those parties now have 30 days to request that the ICC reconsider its decision and subsequently file an appeal with the Illinois Appellate Court. ComEd expects to begin construction of the line in the second quarter of 2015 with an in service date expected in the second quarter of 2017.

Illinois Procurement Proceedings (Exelon, Generation and ComEd). ComEd is permitted to recover its electricity procurement costs from retail customers without mark-up. Since June 2009, as a result of the Illinois Settlement Legislation, 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. On December 18, 2013, the ICC approved the IPA’s procurement plan covering the period June 2014 through May 2019.

The Illinois Settlement Legislation requires ComEd to purchase an increasing percentage of the electricity for customer deliveries from renewable energy resources. Purchases by customers of electricity from competitive generation suppliers, whether as a result of the customers’ own actions or as a result of municipal aggregation, are not included in this calculation and have the effect of reducing ComEd’s purchase obligation. ComEd entered into several 20-year contracts with unaffiliated suppliers in December 2010 regarding the procurement of long-term renewable energy and associated RECs in order to meet its obligations under the state’s RPS. Under the Illinois Settlement Legislation, all associated costs are recoverable from customers. The ICC did not require the acquisition of additional renewable resources for the period June 2014 through May 2015 due to ComEd expecting to exceed the renewable cost cap established by the Illinois Settlement Legislation.

The IPA’s 2014-2019 plan provides for two separate energy procurements during 2014 to address potential fluctuations in energy demand due to customer switching between ComEd and competitive electric generation suppliers. The ICC also approved the IPA’s expansion of energy efficiency programs for both ComEd and Ameren. As of September 30, 2014, ComEd has completed both of the scheduled 2014 energy procurements, which cover a portion of its energy requirements through the periods ending May 31, 2015, 2016 and 2017. See Note 18 - Commitments and Contingencies for additional information on ComEd’s energy commitments.

FutureGen Industrial Alliance, Inc (Exelon and ComEd). During 2013, the ICC approved and directed ComEd and Ameren to enter into a 20-year sourcing agreement 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 sourcing agreement provides that ComEd and Ameren will pay FutureGen’s contract prices, which are set annually pursuant to a formula rate. The contract prices are based on the difference between the costs of the facility and the revenues FutureGen receives from selling capacity and energy from the unit into the MISO or other markets, as well as any other revenue FutureGen receives from the operation of the facility. The order also directs ComEd and Ameren to recover these costs from their electric distribution customers through the use of a tariff, regardless of whether they purchase electricity from ComEd or Ameren, or from competitive electric generation suppliers.

In February 2013, ComEd filed an appeal with the Illinois Appellate Court questioning the legality of requiring ComEd to procure power for retail customers purchasing electricity from competitive electric generation suppliers. On July 22, 2014, the Illinois Appellate Court issued its ruling re-affirming the ICC’s order requiring ComEd to enter into the sourcing agreement with FutureGen and allowing the use of a tariff to recover its costs. ComEd decided not to appeal the Illinois Appellate Court’s decision to the Illinois Supreme Court. However, the competitive electric generation suppliers have reserved their right to appeal the Illinois Appellate Court’s decision.

ComEd executed the sourcing agreement with FutureGen in accordance with the ICC’s order. In addition, ComEd filed a petition with the ICC seeking approval of the tariff allowing for the recovery of its costs associated with the FutureGen contract from all of its electric distribution customers, which was approved by the ICC on September 30, 2014. Depending on eventual market conditions and the cost of the facility, the sourcing agreement could have a material adverse impact on Exelon’s and ComEd’s cash flows and financial positions.

Pennsylvania Regulatory Matters

Pennsylvania Procurement Proceedings (Exelon and PECO). 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 is procuring electric supply for its default electric customers through five competitive procurements. The load for the residential and small and medium commercial classes is served through competitively procured fixed price, full requirements contracts of two years or less. For the large commercial and industrial class load, PECO has competitively procured 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 class and its small and medium commercial classes that began in June 2013. In September 2013, PECO entered into contracts with PAPUC-approved bidders, including Generation, for its residential class and its small and medium commercial classes that began in December 2013. In January 2014, PECO entered into contracts with PAPUC-approved bidders, including Generation, for its residential class and its and small, medium, and large commercial classes that began in June 2014. In September 2014, PECO entered into contracts with PAPUC-approved bidders, including Generation, for its final competitive procurements of electric supply for its residential class and its small and medium commercial classes commencing December 2014. 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 submit a plan 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. By Order entered on January 24, 2014, the PAPUC approved PECO’s plan, with modifications, to make CAP shopping available beginning April 15, 2014. On March 20, 2014, low-income advocacy groups filed an appeal and emergency request for a stay with the Pennsylvania Commonwealth Court, claiming that the PAPUC-ordered CAP Shopping plan does not contain sufficient protections for low-income customers. On March 28, 2014, the Commonwealth Court issued the requested stay, pending a full review of the appeal. Pending the Commonwealth Court’s review, PECO will not implement CAP Shopping. The Commonwealth Court’s decision is expected in early 2015.

On March 10, 2014, PECO filed its third DSP Program with the PAPUC. The program has a 24-month term from June 1, 2015 through May 31, 2017, and complies with electric generation procurement guidelines set forth in Act 129. On August 28, 2014, PECO filed a Joint Petition for Partial Settlement, which affirmed PECO’s procurement plan for Residential and Small Commercial customers and reserved two issues for litigation: certain non-bypassable transmission charges and the default service product for Medium Commercial customers (including hourly pricing). On September 30, 2014, the ALJ issued a Recommended Decision to the PAPUC that PECO’s third DSP Program be approved, as modified by the Joint Petition for Partial Settlement, but also recommending that the Large C&I class should be excluded from the recommended non-bypassable charge for non-market-based charges. A final ruling from the PAPUC is expected by December 2014.

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, which was completed on June 19, 2013, included the installation of an AMI communications network and the deployment of 600,000 smart meters to communicate with that network. On May 31, 2013, PECO and interested parties filed a Joint Petition for Settlement of the universal deployment plan with the PAPUC which was approved without modification on August 15, 2013. The Joint Petition for Settlement supports all material aspects of PECO’s universal deployment plan, including cost recovery, excluding certain amounts discussed below. Universal deployment is the second phase of PECO’s SMPIP, under which PECO will deploy substantially all 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 of which $200 million will be funded by SGIG as discussed below. As of September 30, 2014, PECO has spent $516 million and $119 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 September 30, 2014, PECO has received substantially all of the $200 million, including $4 million for sub-recipients, in reimbursements. On October 15, 2014, the DOE issued a Close Out of Post-Award Project Cost Verification Audit, in which it was determined that PECO fully met its required cost share, and the audit was closed with no further action required.

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 is moving 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 $17 million, net of approximately $16 million of reimbursements from the DOE and approximately $2 million of depreciation. PECO requested and received approval from the DOE that the original meters continued to be allowable costs and that any settlement with the vendor would not be considered project income. In addition, PECO remains eligible for the full $200 million in SGIG funds. On August 15, 2013, PECO entered into an agreement with the original vendor, which was part of the final agreement discussed below, under which PECO transferred the original uninstalled meters to the vendor and received $12 million in return. On January 23, 2014, PECO entered a final agreement with the vendor pursuant to which PECO will be reimbursed for amounts incurred for the original meters and related installation and removal costs, via cash payments and rebates on future purchases of licenses, goods and services primarily through 2017. PECO previously had intended to seek regulatory rate recovery in a future filing with the PAPUC of amounts not recovered from the vendor. As PECO believed such costs were probable of rate recovery based on applicable case law and past precedent on reasonably and prudently incurred costs, a regulatory asset was established at the time of the removals. As of December 31, 2013, $5 million was recorded on Exelon’s and PECO’s Consolidated Balance Sheets. Pursuant to the January 23, 2014, vendor agreement, PECO reclassified the regulatory asset balance as a receivable, which was fully collected as of September 30, 2014, with no gain or loss impacts on future results of operations. On March 14, 2014, PECO filed its quarterly smart meter recovery surcharge with the PAPUC, which included PECO’s proposed treatment of the final agreement with the vendor. On March 27, 2014, the PAPUC approved the surcharge as proposed by PECO.

Energy Efficiency Programs (Exelon and PECO). PECO’s PAPUC-approved Phase I EE&C Plan had a four-year term that began on June 1, 2009 and concluded on May 31, 2013. The Phase I Plan set forth how PECO would meet the required reduction targets established by Act 129’s EE&C provisions, which included 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.

PECO filed its final compliance report on Phase 1 targets with the PAPUC on November 15, 2013. On March 20, 2014, the PAPUC issued its final report stating that PECO was in full compliance with all Phase I targets.

On November 14, 2013, the PAPUC issued a Tentative Order on Act 129 demand reduction programs which seeks comments on a proposed demand response program methodology for future Act 129 demand reduction programs as well as demand response potential and wholesale prices suppression studies. In its February 20, 2014 Final Order, the PAPUC stated that it does not expect to make a decision as to whether it will prescribe additional demand response obligations until 2015. Any decision reached would affect PECO’s EE&C Plan subsequent to its Phase II Plan.

On February 28, 2014, 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, 2014 to May 31, 2016. PECO proposed to fund the estimated $10 million annual costs of the program by modifying incentive levels for other Phase II programs. The costs of the DLC program will be recovered through PECO’s Energy Efficiency Program Charge along with other Phase II Plan costs. In an April 23, 2014 Tentative Order, the PAPUC granted PECO’s Petition. The Order became final on May 5, 2014.

Pennsylvania Retail Electricity Market (Exelon and PECO). The extreme weather experienced in early 2014 resulted in increased commodity costs causing certain shopping customers to receive unexpectedly high utility bills. In response to a significant number of customer complaints throughout Pennsylvania, on April 3, 2014, the PAPUC unanimously voted to adopt two rulemaking orders to address the issue. The first rulemaking order requires electric generation suppliers to provide more consumer education regarding their contract. The second rulemaking order requires electric distribution companies to enable customers to switch suppliers within three business days (known as accelerated switching). The improved customer education and accelerated switching are to be in place within 30 days and six months of approval of the orders, respectively. The Independent Regulatory Review Commission granted approval of the orders on May 22, 2014. The orders became final on June 14, 2014. PECO is in process of implementing compliance with the order.

Maryland Regulatory Matters

2014 Maryland Electric and Gas Distribution Rate Case (Exelon and BGE). On July 2, 2014, BGE filed an application for increases of $118 million and $68 million to its electric and gas base rates, respectively, with the MDPSC. The requested rates of return on equity in the application were 10.65% and 10.55% for electric and gas distribution, respectively. On September 15, 2014, BGE filed an update to its rate request which altered the requested increase to electric base rates from $118 million to $99 million. The requested increase to gas base rates did not change.

On October 17, 2014, BGE filed with the MDPSC a unanimous settlement agreement (the Settlement Agreement) reached with all parties to the case under which it would receive an increase of $22 million in electric base rates and an increase of $38 million in gas base rates. The Settlement Agreement establishes new depreciation rates which have the effect of decreasing annual depreciation expense by approximately $20 million, primarily for electric. The Settlement Agreement remains subject to MDPSC approval. If approved by the MDPSC, rates would go into effect no sooner than December 15, 2014, and no later than late January 2015. BGE is uncertain if the MDPSC will unconditionally approve the Settlement Agreement or if further proceedings will be required.

2013 Maryland Electric and Gas Distribution Rate Case (Exelon and BGE). On May 17, 2013, BGE filed an application for increases of $101 million and $30 million to its electric and gas base rates, respectively, with the MDPSC. The requested rates of return on equity in the application were 10.50% and 10.35% for electric and gas distribution, respectively. In addition to these requested rate increases, BGE’s application also included a request for recovery of incremental capital expenditures and operating costs associated with BGE’s proposed short-term reliability improvement plan (the “ERI initiative”) in response to a MDPSC order through a surcharge separate from base rates. On August 23, 2013, BGE filed an update to its rate request which altered the requested increase to electric base rates from $101 million to $83 million and the requested increase to gas base rates from $30 million to $24 million. On December 13, 2013, the MDPSC issued an order in BGE’s 2013 electric and natural gas distribution rate case for increases in annual distribution service revenue of $34 million and $12 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 December 13, 2013. As part of its December 13, 2013 decision granting BGE increases for its gas and electric distribution rates, the MDPSC also authorized BGE to recover through a surcharge mechanism costs associated with five ERI initiative programs designed to accelerate electric reliability improvements. Such a decision, however, was premised upon the condition that the MDPSC approve specific projects scheduled for each year of the five-year program in advance of cost recovery through the surcharge mechanism. On March 31, 2014, after reviewing comments filed by the parties and conducting a hearing on the matter, the MDPSC approved all but one project proposed for completion in 2014 as part of the ERI initiative. As a result of the MDPSC’s decision, BGE estimates 2014 capital and operating and maintenance costs associated with the ERI initiative of $14.8 million and a revenue requirement of $1.4 million. The ERI initiative surcharge became effective June 1, 2014. BGE is required to file an update on the 2014 work plan and reliability performance information for the specific projects, along with its work plan and cost estimates for 2015, on or before November 1, 2014.

In January 2014, the residential consumer advocate in Maryland filed an appeal to the order issued by the MDPSC on December 13, 2013 in BGE's 2013 electric and gas distribution rate cases. The residential consumer advocate filed its related legal memorandum on August 22, 2014, challenging the MDPSC's approval of the ERI initiative surcharge. BGE submitted a response to the appeal on October 15, 2014, and a hearing has been scheduled for November 17, 2014. BGE cannot predict the outcome of this appeal.

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 of which $200 million has been recovered through a grant from the DOE. 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 September 30, 2014 and December 31, 2013, BGE recorded a regulatory asset of $111 million and $66 million, respectively, representing incremental costs, depreciation and amortization, and a debt return on fixed assets related to its AMI program. As part of the settlement in BGE’s 2014 electric and gas distribution rate case discussed above, the cost of the retired non-AMI meters will be amortized over 10 years. However, as discussed above, the settlement is still subject to MDPSC approval.

On February 26, 2014, the MDPSC issued an Order authorizing BGE to impose a $75 upfront fee and an $11 recurring fee to customers electing to opt-out of smart meter replacement, effective the later of the first full billing cycle following July 1, 2014, or the AMI installation date in a customer's community. The fees authorized by the order will be reviewed after an initial 12 to 18 month period. As of September 30, 2014, BGE is awaiting the MDPSC's decision regarding BGE's proposal to automatically enroll unresponsive customers into the opt-out program. The proposal, if approved, would allow BGE to begin charging these customers opt-out fees. The ultimate impact of opt-out could affect BGE’s ability to demonstrate cost-effectiveness of the advanced metering system.

Overall, BGE continues to believe the recovery of smart grid initiative costs in future rates is probable as BGE expects to be able to demonstrate that the program benefits exceed costs.

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 recover promptly 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, which took 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 caps on the monthly surcharges to residential and non-residential 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 included in gas distribution rates. Irrespective of the cap, BGE is required to file a gas rate case every five years under this legislation. On August 2, 2013, BGE filed its infrastructure replacement plan and associated surcharge. On January 29, 2014, the MDPSC issued a decision conditionally approving the first five years of BGE’s plan and surcharge. On March 26, 2014, the Maryland PSC approved as filed BGE’s proposed 2014 project list, tariff and associated surcharge amounts, with a surcharge that became effective April 1, 2014. BGE will defer the difference between the surcharge revenues and program costs as a regulated asset or liability, which was immaterial to BGE and Exelon as of September 30, 2014.

In February 2014, the residential consumer advocate in Maryland filed an appeal with the Baltimore City Circuit Court to the decision issued by the MDPSC on BGE’s infrastructure replacement plan. The residential consumer advocate filed its related legal memorandum on July 7, 2014, claiming that the MDPSC did not apply the appropriate consideration in approving BGE’s infrastructure replacement plan and associated surcharge. BGE submitted a response to the appeal on August 6, 2014. On September 5, 2014, the Baltimore City Circuit Court affirmed the MDPSC decision on BGE's infrastructure replacement plan and associated surcharge. On October 10, 2014, the residential consumer advocate noticed its appeal to the Maryland Court of Special Appeals from the judgment entered by the Baltimore City Circuit Court.

Federal Regulatory Matters

Transmission Formula Rate (Exelon, ComEd and BGE). ComEd’s and BGE’s transmission rates are each established based on a FERC-approved formula. ComEd and BGE record regulatory assets or regulatory liabilities and corresponding increases or decreases to operating revenues for any differences between the revenue requirement in effect and ComEd’s and BGE’s best estimate of the revenue requirement expected to be approved by the FERC for that year’s reconciliation. As of September 30, 2014 and December 31, 2013, ComEd had recorded a net regulatory asset associated with the transmission formula rate of $19 million and $17 million, respectively. BGE recorded a net regulatory asset associated with the transmission formula rate of $3 million at September 30, 2014, and a net regulatory liability which was not material as of December 31, 2013. The regulatory asset associated with the transmission true-up will be amortized as the associated amounts are recovered through rates.

On April 16, 2014, ComEd filed its annual formula rate update with the FERC. The filing establishes the revenue requirement used to set rates that took effect in June 2014, subject to review by the FERC and other parties, which is due by November 2014. The revenue requirement is based on 2013 actual costs plus forecasted 2014 capital additions as well as an annual reconciliation of the revenue requirement in effect starting in June 2013 to the actual cost incurred in 2013. The update resulted in a revenue requirement of $524 million plus an $11 million adjustment related to the reconciliation of 2013 actual costs for a total revenue requirement of $535 million. This compares to the 2013 revenue requirement of $488 million plus a $25 million adjustment related to the reconciliation of 2012 actual costs for a total revenue requirement of $513 million. The increase in the revenue requirement was primarily driven by increased capital investment and higher operating and maintenance costs.

ComEd’s updated formula transmission rate currently provides for a weighted average debt and equity return on transmission rate base of 8.62%, which is inclusive of an allowed return on common equity of 11.50%, a decrease from the 8.70% average debt and equity return previously authorized. As part of the FERC-approved settlement of ComEd’s 2007 transmission rate case, the rate of return on common equity is 11.50% and the common equity component of the ratio used to calculate the weighted average debt and equity return for the transmission formula rate is currently capped at 55%.

On April 28, 2014, BGE filed its annual formula rate update with the FERC. The filing established the revenue requirement used to set rates that took effect in June 2014, subject to review by the FERC and other parties, which is due by October 2014. The revenue requirement is based on 2013 actual costs plus forecasted 2014 capital additions as well as an annual reconciliation of the revenue requirement in effect starting in June 2013 to the actual cost incurred in 2013. The update resulted in a revenue requirement of $167 million plus a $4 million adjustment related to the reconciliation of 2013 actual costs for a total revenue requirement of $171 million. This compares to the 2013 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. The increase in the revenue requirement is primarily driven by higher depreciation expense and an increased level of return on investment associated with a higher equity ratio and increased rate base.

BGE’s updated formula transmission rate currently provides for a weighted average debt and equity return on transmission rate base of 8.53%, an increase from the 8.35% average debt and equity return previously authorized. As part of the FERC-approved settlement of BGE’s 2005 transmission rate case in 2006, the rate of return on common equity for BGE’s electric transmission business for new transmission projects placed in service on and after January 1, 2006 is 11.3%, which is inclusive of a 50 basis point incentive for participating in PJM.

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 PHI companies relating to their respective transmission formula rates. BGE’s formula rate includes a 10.8% base rate of return on common equity (ROE) for most investments included in its rate base and 11.3% for the remaining transmission investment (the latter of which is conditioned upon crediting the first 50 basis points of any incentive ROE adders). 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 revenues subject to refund are limited to a fifteen month period, and 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. On June 19, 2014, FERC issued an order in another case involving New England Transmission Owners (NETOs), changing its methodology to determine ROE rates for public utilities. The result was a reduction in the NETO’s ROE from 11.14% to 10.57%, with a possible further adjustment in either direction based on additional paper hearing submissions. On July 21, 2014, the NETOs filed a Request for Rehearing and Clarification with FERC of the June 19, 2014 order. Among other things, the NETOs assert that the 11.14% is reasonable based on the new methodology. Following the paper submissions, FERC again approved a base ROE of 10.57% on October 16, 2014.

On August 21, 2014, FERC issued an order in the BGE and PHI companies' proceeding, which established hearing and settlement judge procedures for the complaint, and set a refund effective date of February 27, 2013. BGE, the PHI companies and the parties began settlement discussions under the guidance of a FERC administrative law judge on September 23, 2014 and the discussions are expected to continue at least through November. While it is too early in the process to predict the outcome of the settlement discussions, if the parties cannot resolve their differences, the matter will proceed to hearing.

Based on the current status of the settlement discussions, BGE believes it is probable that BGE’s base ROE rate will be adjusted, and that a refund to customers of transmission revenue for the maximum fifteen month period will be required. However, BGE is unable to estimate the most likely refund amount at this time, and has therefore established a reserve, which is not material, representing the low end of a reasonably possible estimated range of loss. If FERC were to order a reduction of BGE’s base return on equity to 8.7% as sought in the original complaint (while retaining the 50 basis points of any incentives that were credited to the base return on equity for certain new transmission investment), the result would be a refund to customers of approximately $13 million, as well as an estimated ongoing annual 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 from those facilities. 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 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. On June 25, 2014, the U.S. Court of Appeals for the Seventh Circuit issued a decision once again remanding to FERC the cost allocation of new facilities 500 kV and above. 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.

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 FERC orders approving the MOPR were upheld by the United States Court of Appeals for the Third Circuit in February 2014.

Exelon continues to work with PJM stakeholders and through the FERC process to implement several proposed changes to the PJM tariff aimed at ensuring that capacity resources (including those with state-sanctioned subsidy contracts and capacity market speculators) cannot inappropriately affect capacity auction prices in PJM.

Demand Response Resource Order (Exelon, Generation, ComEd, PECO, BGE). On May 23, 2014, the D.C. Circuit Court issued an opinion vacating the FERC Order No. 745 (“D.C. Circuit Decision”). Order No. 745 established uniform compensation levels for demand response resources that participate in the day ahead and real-time wholesale energy markets. Under Order No. 745, buyers in ISO and RTO markets were required to pay demand response resources the full Locational Marginal Price when the demand response replaced a generation resource and was cost-effective.

In addition to invalidating the compensation structure established by Order No. 745, the D.C. Circuit Court, in broad language, explained that demand response is part of the retail market and FERC is restricted from regulating retail markets. The full implication of the D.C. Circuit Decision for both energy and capacity markets regulated by FERC is not yet known and will depend on how FERC and the RTOs and ISOs implement the decision. FERC and several other parties sought rehearing of the D.C. Circuit Decision, which was denied in September 2014. In addition, on September 22, 2014, FERC and another party sought to stay the issuance of the D.C. Circuit Court's mandate so that FERC may determine whether to appeal the decision to the U.S. Supreme Court. Therefore, FERC will not be required to implement the D.C. Circuit Decision until a determination is made on the stay request. FERC and other parties will have until December 2014 to appeal the decision to the U.S. Supreme Court. FERC or other parties may also petition the U.S. Supreme Court to review the decision of the D.C. Circuit Court. In addition, contemporaneously with the D.C. Circuit Court's decision on May 23, 2014, First Energy filed a complaint at FERC asking FERC to direct PJM to remove all PJM Tariff provisions that allow or require PJM to compensate demand response providers as a form of supply in the PJM capacity market effective May 23, 2014. FirstEnergy also asked FERC to declare the results of PJM's May 2014 Base Residual Auction for the 2017/2018 Delivery Year, void and illegal to the extent that demand response resources cleared that auction. FERC's response to the FirstEnergy complaint and its response to address the D.C. Circuit Court's decision in all markets could preclude demand response resources from receiving any future capacity market revenues and also subject such resources to refund obligations. In addition, there is uncertainty as to how FERC might treat already settled capacity market auctions as well as future auctions, both for demand response resources and generation resources. FERC could grant all or a portion of the relief requested by FirstEnergy and may grant relief retroactively or only prospectively. Due to these uncertainties, the Registrants are unable to predict the outcome of these proceedings, and the final outcome is not expected for several months. Nonetheless, the final decision and its implementation by FERC and the RTOs and ISOs, could be material to Exelon, Generation, ComEd, PECO and BGE’s results of operations and cash flows.

Reliability Pricing Model (Exelon, Generation and BGE). PJM’s RPM Base Residual Auctions take place approximately 36 months ahead of the scheduled delivery year. The most recent auction for the delivery year ending May 31, 2018 occurred in May 2014.

New England Capacity Market Results (Exelon and Generation). Each year, ISO New England, Inc. (ISO-NE) files the results of its annual capacity auction at the FERC which is required to include documentation regarding the competitiveness of the auction. Consistent with this requirement, on February 28, 2014, ISO-NE filed the results of its eighth capacity auction (covering the June 1, 2017 through May 30, 2018 delivery period). On June 27, 2014, the FERC issued a letter to ISO-NE noting that ISO-NE’s February 28, 2014 filing was deficient and that ISO-NE must file additional information before the FERC can process the filing. ISO-NE filed the information on July 17, 2014, and the ISO-NE's filings became effective by operation of law pursuant to a notice issued by the FERC's secretary on September 16, 2014. It is not clear whether any party will seek rehearing or appeal of that notice or whether any such rehearing or appeal would be effective as there is no action by the Commission to be considered. Nonetheless, while we think any change in the auction results to be unlikely, Exelon and Generation cannot predict with certainty what further action, if any, FERC or a court may take concerning the results of that auction, but any FERC or court action could be material to Exelon’s and Generation's expected revenues from the capacity auction.

License Renewals (Exelon and Generation). In June 2012, the United States 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. On August 26, 2014, the NRC Commissioners removed the hold on final licensing decisions and approved the issuance of a revised rule codifying the NRC's generic determinations regarding the environmental impacts of continued storage of spent nuclear fuel beyond a reactor's licensed operating life. The rule was issued September 19, 2014.

On October 20, 2014, the NRC approved Generation's request to extend the operating licenses of Limerick Units 1 and 2 by 20 years. The extended operating licenses for Limerick Units 1 and 2 will expire in 2044 and 2049, respectively.

On May 29, 2013, Generation submitted applications to the NRC to extend the operating licenses of Byron Units 1 and 2 and Braidwood Units 1 and 2 by 20 years. The current operating licenses for Byron Units 1 and 2 expire in 2024 and 2026, respectively. The current operating licenses for Braidwood Units 1 and 2 expire in 2026 and 2027, respectively. Generation does not expect the NRC to issue license renewals for Byron and Braidwood until 2015 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 water quality licensing issues with the MDE for Conowingo, including: (1) water quality, (2) fish passage and habitat, and (3) sediment. On January 30, 2014, Exelon filed a water quality certification application pursuant to Section 401 of the CWA with MDE for Conowingo, addressing these and other issues, although Generation cannot currently predict the conditions that ultimately may be imposed. Resolution of these issues relating to Conowingo may have a material effect on Generation’s results of operations and financial position through an increase in capital expenditures and operating costs.

On June 3, 2014, PA DEP issued its water quality certificate for Muddy Run, which is a necessary step in the FERC licensing process and included certain commitments made by Generation. The financial impact associated with these commitments is estimated to be in the range of $25 million to $35 million, and will include both capital expenditures and operating expenses, primarily relating to fish passage and habitat improvement projects. On July 3, 2014, PPL Holtwood, LLC, the owner of the next upstream dam from Muddy Run, filed an appeal of PA DEP's issuance of its water quality certificate. Exelon is working with PA DEP and PPL to resolve PPL's concerns.

Based on the FERC procedural schedule, the FERC licensing process was not scheduled 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. FERC is required to issue annual licenses for the facilities until the new licenses are issued. On September 10, 2014, FERC issued annual licenses for Conowingo and Muddy Run, effective as of the expiration of the current licenses. If FERC does not issue new licenses prior to the expiration of annual licenses, the annual licenses will renew automatically. The stations are currently being depreciated over their estimated useful lives, which includes the license renewal period. As of September 30, 2014, $38 million of direct costs associated with licensing efforts have been capitalized.

Regulatory Assets and Liabilities (Exelon, ComEd, PECO and BGE)

Exelon, ComEd, PECO and BGE each 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, 2014 and December 31, 2013. For additional information on the specific regulatory assets and liabilities, refer to Note 3 — Regulatory Matters of the Exelon 2013 Form 10-K.



September 30, 2014	Exelon				ComEd				PECO				BGE
	Current		Noncurrent		Current		Noncurrent		Current		Noncurrent		Current			Noncurrent
Regulatory assets
Pension and other postretirement benefits	$	208	$	2,455	$	—	$	—	$	—	$	—	$	—		$	—
Deferred income taxes	7		1,517		1		67		—		1,377		6			73
AMI programs	9		254		9		69		—		74		—			111
Under-recovered distribution service costs	243		223		243		223		—		—		—			—
Debt costs	9		50		7		48		2		2		1			8
Fair value of BGE long-term debt^(a)	6		192		—		—		—		—		—			—
Fair value of BGE supply contract^(b)	3		—		—		—		—		—		—			—
Severance	4		9		—		—		—		—		4			9
Asset retirement obligations	1		111		1		73		—		26		—			12
MGP remediation costs	39		220		32		186		6		33		1			1
RTO start-up costs	1		—		1		—		—		—		—			—
Under-recovered uncollectible accounts	—		70		—		70		—		—		—			—
Renewable energy	14		164		14		164		—		—		—			—
Energy and transmission programs	22		5		19		—		—		—		3		(f)	5
Deferred storm costs	3		—		—		—		—		—		3			—
Electric generation-related regulatory asset	12		21		—		—		—		—		12			21
Rate stabilization deferral	75		101		—		—		—		—		75			101
Energy efficiency and demand response programs	84		151		—		—		—		—		84			151
Merger integration costs	2		7		—		—		—		—		2			7
Conservation voltage reduction	1		1		—		—		—		—		1			1
Under-recovered revenue decoupling^(e)	14		—		—		—		—		—		14			—
Other	17		38		3		28		13		8		—			—
Total regulatory assets	$	774	$	5,589	$	330	$	928	$	21	$	1,520	$	206		$	500



September 30, 2014	Exelon				ComEd				PECO					BGE
	Current		Noncurrent		Current		Noncurrent		Current			Noncurrent		Current			Noncurrent
Regulatory liabilities
Other postretirement benefits	$	53	$	96	$	—	$	—	$	—		$	—	$	—		$	—
Nuclear decommissioning	—		2,850		—		2,371		—			479		—			—
Removal costs	110		1,455		86		1,257		—			—		24			198
Energy efficiency and demand response programs	28		2		28		—		—			2		—			—
DLC Program Costs	—		10		—		—		—			10		—			—
Energy efficiency Phase 2	—		32		—		—		—			32		—			—
Electric distribution tax repairs	20		100		—		—		20			100		—			—
Gas distribution tax repairs	8		32		—		—		8			32		—			—
Energy and transmission programs	73		13		26		13		44		(c)	—		3		(f)	—
Over-recovered gas and electric universal service fund costs	4		—		—		—		4			—		—			—
Revenue subject to refund^(d)	47		—		47		—		—			—		—			—
Over-recovered revenue decoupling^(e)	16		—		—		—		—			—		16			—
Other	5		3		—		2		3			—		2			1
Total regulatory liabilities	$	364	$	4,593	$	187	$	3,643	$	79		$	655	$	45		$	199



December 31, 2013	Exelon				ComEd				PECO				BGE
	Current		Noncurrent		Current		Noncurrent		Current		Noncurrent		Current			Noncurrent
Regulatory assets
Pension and other postretirement benefits	$	221	$	2,794	$	—	$	—	$	—	$	—	$	—		$	—
Deferred income taxes	10		1,459		2		65		—		1,317		8			77
AMI programs	5		159		5		35		—		58		—			66
AMI meter events	—		5		—		—		—		5		—			—
Under-recovered distribution service costs	178		285		178		285		—		—		—			—
Debt costs	12		56		9		53		3		3		1			8
Fair value of BGE long-term debt^(a)	—		219		—		—		—		—		—			—
Fair value of BGE supply contract^(b)	12		—		—		—		—		—		—			—
Severance	16		12		12		—		—		—		4			12
Asset retirement obligations	1		102		1		67		—		25		—			10
MGP remediation costs	40		212		33		178		6		33		1			1
RTO start-up costs	2		—		2		—		—		—		—			—
Under-recovered uncollectible accounts	—		48		—		48		—		—		—			—
Renewable energy	17		176		17		176		—		—		—			—
Energy and transmission programs	53		—		52		—		—		—		1		(f)	—
Deferred storm costs	3		3		—		—		—		—		3			3
Electric generation-related regulatory asset	13		30		—		—		—		—		13			30
Rate stabilization deferral	71		154		—		—		—		—		71			154
Energy efficiency and demand response programs	73		148		—		—		—		—		73			148
Merger integration costs	2		9		—		—		—		—		2			9
Other	31		39		18		26		8		7		4			6
Total regulatory assets	$	760	$	5,910	$	329	$	933	$	17	$	1,448	$	181		$	524



December 31, 2013	Exelon				ComEd				PECO					BGE
	Current		Noncurrent		Current		Noncurrent		Current			Noncurrent		Current			Noncurrent
Regulatory liabilities
Other postretirement benefits	$	2	$	43	$	—	$	—	$	—		$	—	$	—		$	—
Nuclear decommissioning	—		2,740		—		2,293		—			447		—			—
Removal costs	99		1,423		78		1,219		—			—		21			204
Energy efficiency and demand response programs	53		—		45		—		8			—		—			—
DLC Program Costs	1		10		—		—		1			10		—			—
Energy efficiency phase II	—		21		—		—		—			21		—			—
Electric distribution tax repairs	20		114		—		—		20			114		—			—
Gas distribution tax repairs	8		37		—		—		8			37
Energy and transmission programs	78		—		9		—		58		(c)	—		11		(f)	—
Over-recovered gas and electric universal service fund costs	8		—		—		—		8			—		—			—
Revenue subject to refund^(d)	38		—		38		—		—			—		—			—
Over-recovered revenue decoupling^(e)	16		—		—		—		—			—		16			—
Other	4		—		—		—		3			—		—			—
Total regulatory liabilities	$	327	$	4,388	$	170	$	3,512	$	106		$	629	$	48		$	204

________________


(a)	Represents the regulatory asset recorded at Exelon Corporate for the difference in the fair value of the long-term debt of BGE as of the merger date. The asset is amortized over the life of the underlying debt.


(b)	Represents the regulatory asset recorded at Exelon Corporate representing the fair value of BGE’s supply contracts as of the close of the merger date. BGE is allowed full recovery of the costs of its electric and gas supply contracts through approved, regulated rates. The asset is amortized over a period of approximately 3 years.

(c)

Includes $28 million related to the DSP program, $11 million related to the over-recovered natural gas costs under the PGC and $5 million related to over-recovered electric transmission costs as of September 30, 2014. As of December 31, 2013, includes $34 million related to the DSP program, $8 million related to the over-recovered electric transmission costs and $16 million related to the over-recovered natural gas costs under the PGC.


(d)	Primarily represents the regulatory liability for revenue subject to refund recorded pursuant to the ICC’s order in the 2007 Rate Case. See Note 3 — Regulatory Matters of the Exelon 2013 Form 10-K. for further information.

(e)

Represents the electric and gas distribution costs recoverable from customers under BGE’s decoupling mechanism. As of September 30, 2014, BGE had a regulatory asset of $14 million related to under-recovered electric revenue decoupling and a regulatory liability of $16 million related to over-recovered natural gas revenue decoupling. As of December 31, 2013, BGE had a regulatory liability of $7 million related to over-recovered electric revenue decoupling and $9 million related to over-recovered natural gas revenue decoupling.


(f)	Relates to $3 million associated with the transmission formula rate and $3 million of over-recovered natural gas supply costs as of September 30, 2014. As of December 31, 2013, includes $1 million of under-recovered electric supply costs and $11 million of over-recovered natural gas supply costs.

Purchase of Receivables Programs (Exelon, ComEd, PECO, and BGE)

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 September 30, 2014 and December 31, 2013.



As of September 30, 2014	Exelon			ComEd			PECO			BGE
Purchased receivables^(a)	$	306		$	152		$	78		$	76
Allowance for uncollectible accounts^(b)	(36		)	(21		)	(8		)	(7		)
Purchased receivables, net	$	270		$	131		$	70		$	69



As of December 31, 2013	Exelon			ComEd			PECO			BGE
Purchased receivables^(a)	$	263		$	105		$	72		$	86
Allowance for uncollectible accounts^(b)	(30		)	(16		)	(7		)	(7		)
Purchased receivables, net	$	233		$	89		$	65		$	79

_________

(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.