5. Regulatory Matters (All Registrants)

Except for the matters noted below, the disclosures set forth in Note 3 - Regulatory Matters of the Exelon 2015 Form 10-K and Note 7 - Regulatory Matters of the PHI 2015 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

Distribution Formula Rate (Exelon and ComEd). On April 13, 2016, ComEd filed its annual distribution formula rate with the ICC pursuant to EIMA. The filing establishes the revenue requirement used to set the rates that will take effect in January 2017 after the ICC’s review and approval, which is due by December 2016. The revenue requirement requested is based on 2015 actual costs plus projected 2016 capital additions as well as an annual reconciliation of the revenue requirement in effect in 2015 to the actual costs incurred that year. ComEd's 2016 filing request includes a total increase to the revenue requirement of $138 million, reflecting an increase of $139 million for the initial revenue requirement for 2017 and a decrease of $1 million related to the annual reconciliation for 2015. The revenue requirement for 2017 provides for a weighted average debt and equity return on distribution rate base of 6.71% inclusive of an allowed ROE of 8.64%, reflecting the average rate on 30-year treasury notes plus 580 basis points. The annual reconciliation for 2015 provided for a weighted average debt and equity return on distribution rate base of 6.69% inclusive of an allowed ROE of 8.59%, reflecting the average rate on 30-year treasury notes plus 580 basis points less a performance metrics penalty of 5 basis points. See table below for ComEd's regulatory assets associated with its distribution formula rate. For additional information on ComEd's distribution formula rate filings see Note 3 — Regulatory Matters of the Exelon 2015 Form 10-K.

Grand Prairie Gateway Transmission Line (Exelon and 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 October 22, 2014, the ICC issued an Order approving ComEd’s request. The City of Elgin and certain other parties each filed an appeal of the ICC Order in the Illinois Appellate Court for the Second District. ComEd then reached a settlement of the appeal filed by all parties except Elgin. On March 31, 2016, the Illinois Appellate Court issued its opinion affirming the ICC’s grant of a certificate to ComEd to construct and operate the line. Elgin did not seek further review of the Illinois Appellate Court decision. 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. The costs incurred for the project prior to May 21, 2014 were immaterial. ComEd has acquired the necessary land rights across the project route through voluntary transactions. ComEd began construction of the line during 2015 with an expected in-service date of 2017.

FutureGen Industrial Alliance, Inc (Exelon and ComEd). During 2013, the ICC approved, and directed ComEd and Ameren (the Utilities) to enter into 20-year 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 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 and several large consumers petitioned for leave to appeal the Illinois Appellate Court’s decision. On November 26, 2014, the Illinois Supreme Court granted the petition. 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.

In February 2015, the DOE suspended funding for the cost development of FutureGen. On January 13, 2016, FutureGen informed the Illinois Supreme Court that it had ceased all development efforts on the FutureGen project. Accordingly, FutureGen requested that the court dismiss the proceeding as moot. In February 2016, FutureGen terminated its sourcing agreement with ComEd. On May 19, 2016, the Illinois Supreme Court dismissed the matter as moot. As a result, ComEd is under no further obligation under this agreement.

Pennsylvania Regulatory Matters

Pennsylvania Procurement Proceedings (Exelon and PECO). Through PECO’s first two PAPUC approved DSP Programs, PECO procured electric supply for its default electric customers through PAPUC approved competitive procurements. DSP I and DSP II expired on May 31, 2013 and May 31, 2015, respectively.

The second DSP Program included 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 CAP customers to purchase their generation supply from EGSs beginning in April 2014. In May 2013, PECO filed its CAP Shopping Plan with the PAPUC. By an 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, the Office of Consumer Advocate (OCA) and low-income advocacy groups filed an appeal and emergency request for a stay with the Pennsylvania Commonwealth Court (Court), claiming that the PAPUC-ordered CAP Shopping plan does not contain sufficient protections for low-income customers. On July 14, 2015, the Court issued opinions on the OCA and low-income advocacy group appeal. Specifically, the Court remanded the issue to the PAPUC with instructions that it approve a rule revision to the PECO CAP Shopping Plan that would prohibit CAP customers from entering into contracts with an EGS that would impose early cancellation/termination fees. The PAPUC, as well as the low-income advocates and the Office of Consumer Advocate, appealed the Court's decision. On April 5, 2016, the Pennsylvania Supreme Court declined to accept the appeals. On May 11, 2016, the PAPUC issued a Secretarial Letter requiring PECO to propose a rule revision to the PECO CAP Shopping Plan consistent with the Court’s decision. On July 19, 2016, PECO filed a letter stating its intent to revise its Plan by September 1, 2016 to incorporate the rule revision. On September 1, 2016, PECO filed its proposed rule revision that is consistent with the Court’s opinion with a proposed effective date of April 14, 2017.

On December 4, 2014, the PAPUC approved PECO's third DSP Program. 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. Under the program, PECO procured electric supply through four competitive procurements for fixed price full requirements contracts of two years or less for the residential classes and small and medium commercial classes and spot market price full requirement contracts for the large commercial and industrial class load. Beginning in June 2016, the medium commercial class (101-500 kW) moved to spot market pricing. In September 2016, PECO entered into contracts with PAPUC-approved bidders, including Generation, resulting from the final of its four scheduled procurements. Charges incurred for electric supply procured through contracts with Generation are included in purchased power from affiliates on PECO's Consolidated Statement of Operations and Comprehensive Income.

On March 17, 2016, PECO filed its fourth DSP Program with the PAPUC proposing a 24-month term from June 1, 2017 through May 31, 2019, in compliance with electric generation procurement guidelines set forth in Act 129. On October 4, 2016, the Administrative Law Judge recommended that PECO’s previously filed partial settlement be approved without modification. The settlement would extend the program period through May 2021 and consolidate the Medium Commercial and Large Commercial classes of default service customers into a Consolidated Large Commercial Class proposed by the Company. The issue of PECO’s implementation of CAP Shopping was reserved for briefing, and the Administrative Law Judge determined that issue was not a part of the DSP IV case. A decision by the PAPUC is expected in December 2016.

For further information on the Pennsylvania procurement proceedings, see Note 3 - Regulatory Matters of the Exelon 2015 Form 10-K.

Energy Efficiency Programs (Exelon and PECO). On June 19, 2015, the PAPUC issued its Phase III EE&C implementation order that provides energy consumption reduction requirements for the third phase of Act 129’s EE&C program with a five-year term from June 1, 2016 through May 31, 2021.

Pursuant to the Phase III implementation order, PECO filed its five-year EE&C Phase III Plan with the PAPUC on November 30, 2015. The Plan sets forth how PECO will reduce electric consumption by at least 1,962,659 MWh, with a goal of 2,100,875 MWh in its service territory for the period June 1, 2016 through May 31, 2021. The PAPUC approved PECO’s EE&C Phase III Plan, with requested clarifications, on May 19, 2016.

For further information on energy efficiency programs, see Note 3 - Regulatory Matters of the Exelon 2015 Form 10-K.

Maryland Regulatory Matters

2016 Maryland Electric Distribution Rate Case (Exelon, PHI and Pepco). On April 19, 2016, Pepco filed an application with the MDPSC requesting an increase of $127 million to its electric distribution base rates, which was later updated to $103 million, based on a requested ROE of 10.6%. The application is inclusive of a request seeking recovery of Pepco’s regulatory assets associated with its AMI program over a five-year period supported by evidence demonstrating that the benefits of the AMI program exceed the costs on a present value basis. Any adjustments to rates approved by the MDPSC are expected to take effect in November 2016. In addition to the proposed rate increase, Pepco is proposing to continue its Grid Resiliency Program initially approved in July 2013 in connection with Pepco’s electric distribution rate case filed in November 2012. Under the Grid Resiliency Program, Pepco is authorized to receive recovery of specific investments as the assets are placed in service through the Grid Resiliency Charge. In connection with the Grid Resiliency Program, Pepco proposes to accelerate improvement to priority feeders and install single-phase reclosing fuse technology by investing $16 million a year for two years for a total of $32 million. Pepco cannot predict how much of the requested rate increase the MDPSC will approve or if it will approve a continuation of Pepco’s Grid Resiliency Program proposal.

2016 Maryland Electric Distribution Base Rates (Exelon, PHI and DPL). On July 20, 2016, DPL filed an application with the MDPSC requesting an increase of $66 million to its electric distribution base rates, which was later updated to $57 million, based on a requested ROE of 10.6%. The application is inclusive of a request seeking recovery of DPL’s regulatory assets associated with its AMI program over a five-year period supported by evidence demonstrating that the benefits of the AMI program exceed the costs on a present value basis. Any adjustments to rates approved by the MDPSC are expected to take effect in February 2017. DPL cannot predict how much of the requested increase the MDPSC will approve. In addition to the proposed rate increase, DPL is proposing to continue its Grid Resiliency Program initially approved in September 2013 in connection with DPL’s electric distribution rate case filed in February 2013. Under the Grid Resiliency Program, DPL is authorized to receive recovery of specific investments as the assets are placed in service through the Grid Resiliency Charge. In connection with the Grid Resiliency Program, DPL proposes to accelerate improvement to priority feeders and install single-phase reclosing fuse technology by investing $4.6 million a year for two years for a total of $9.2 million. DPL cannot predict whether the MDPSC will approve a continuation of DPL’s Grid Resiliency Program proposal.

2015 Maryland Electric and Natural Gas Distribution Rate Case (Exelon and BGE). On November 6, 2015, and as amended through the course of the proceeding, BGE filed for electric and natural gas base rate increases with the MDPSC, ultimately requesting annual increases of $116 million and $78 million respectively, of which $104 million and $37 million, were related to recovery of electric and natural gas smart grid initiative costs, respectively. BGE also proposed to recover an annual increase of approximately $30 million for Baltimore City underground conduit fees through a surcharge.

On June 3, 2016, the MDPSC issued an order in which the MDPSC found compelling evidence to conclude that BGE’s smart grid initiative overall was cost beneficial to customers. However, the June 3 order contained several cost disallowances and adjustments, including not allowing BGE to defer or recover through a surcharge the $30 million increase in annual Baltimore City underground conduit fees. On June 30, 2016, BGE filed a petition for rehearing of the June 3 order requesting that the MDPSC modify its order to reverse certain decisions including the decision associated with the Baltimore City underground conduit fees. OPC also subsequently filed for a petition for rehearing of the June 3 order.

On July 29, 2016, the MDPSC issued an order on the petitions for rehearing that reversed certain of its prior cost disallowances and adjustments related to the smart grid initiative. Through the combination of the orders, the MDPSC authorized electric and natural gas rate increases of $44 million and $48 million, respectively, and an allowed ROE for the electric and natural gas distribution businesses of 9.75% and 9.65%, respectively. The new electric and natural gas base rates took effect for service rendered on or after June 4, 2016. However, MDPSC’s July 29 order on the petition on rehearing still did not allow BGE to defer or recover through a surcharge the increase in Baltimore City underground conduit fees.

On August 26, 2016, BGE filed an appeal of the MDPSC's orders with the Circuit Court for Baltimore County. On August 29, 2016, the residential consumer advocate also filed an appeal of the MDPSC's order but with the Circuit Court for Baltimore City. BGE cannot predict the outcomes of these appeals. Refer to the Smart Meter and Smart Grid Investment disclosure below for further details on the impact of the ultimate disallowances contained in the orders to BGE.

Smart Meter and Smart Grid Investments (Exelon and BGE). In August 2010, the MDPSC approved a comprehensive smart grid initiative for BGE that included the planned installation of 2 million residential and commercial electric and natural gas smart meters at an expected total cost of $480 million of which $200 million was funded by SGIG. 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, 2016 and December 31, 2015, the balance of BGE's regulatory asset was $235 million and $196 million, respectively, representing incremental program deployment costs. The current quarter balance of $235 million consists of three major components, including $148 million of unamortized incremental deployment costs of the AMI program, $55 million of unamortized costs of the non-AMI meters replaced under the program, and $32 million related to post-test year incremental program deployment costs incurred prior to approval became effective June 2016. The balance as of September 30, 2016 reflects the impact of the cost disallowances and adjustments discussed below. The incremental deployment costs for the AMI program and the non-AMI meter components of the regulatory asset are being recovered through rates and amortized to expense over a 10 year period, while the post-test year incremental program deployment costs have not yet been approved for recovery by the MDPSC. A return on the regulatory asset is currently included in rates, except for the $55 million portion representing the unamortized cost of the retired non-AMI meters and a $32 million portion related to post-test year incremental program deployment costs.

As part of the 2015 electric and natural gas distribution rate case filed on November 6, 2015, BGE sought recovery of its smart grid initiative costs, supported by evidence demonstrating that BGE had, in fact, implemented a cost-beneficial advanced metering system. On June 3, 2016, the MDPSC issued an order concluding that the smart grid initiative overall is cost beneficial to its customers. However, the June 3 order contained several cost disallowances and adjustments including disallowances of certain program and meter installation costs and denial of recovery of any return on unrecovered costs for non-AMI meters replaced under the program. On June 30, 2016, BGE filed a petition for rehearing of the June 3 order requesting that the MDPSC modify its order to reverse certain decisions and change certain of the cost disallowances and adjustments to enable BGE to defer those costs for recovery through future electric and natural gas rates. OPC also subsequently filed for a petition for rehearing of the June 3 order. On July 29, 2016, the MDPSC issued an order on the petitions for rehearing that reversed certain of its prior cost disallowances and adjustments related to the smart grid initiative. On August 26, 2016, BGE filed an appeal of the MDPSC's orders with the Circuit Court for Baltimore County. On August 29, 2016, the residential consumer advocate also filed an appeal of the MDPSC's order but with the Circuit Court for Baltimore City. BGE cannot predict the outcomes of these appeals.

As a combined result of the MDPSC orders, BGE recorded a $52 million charge to Operating and maintenance expense in Exelon’s and BGE’s Consolidated Statements of Operations and Comprehensive Income reducing certain regulatory assets and other long-lived assets. Pursuant to the combined MDPSC orders, BGE also reclassified $55 million of non-AMI plant costs from Property, plant and equipment, net to Regulatory assets on Exelon's and BGE's Consolidated Balance Sheets as of September 30, 2016. For further information, see Note 3 - Regulatory Matters of the Exelon 2015 Form 10-K.

2013 Maryland Electric and Natural Gas Distribution Rate Case (Exelon and BGE). On May 17, 2013, and as amended on August 23, 2013, BGE filed for electric and natural gas base increases with the MDPSC. 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 December 13, 2013, the MDPSC issued an order authorizing BGE to recover through a surcharge mechanism costs associated with five ERI initiative programs designed to accelerate electric reliability improvements premised upon the condition that the MDPSC approve specific projects in advance of cost recovery. As of September 30, 2016, BGE has received approval of its updated surcharge filings three times for rates to be effective in 2014, 2015 and 2016.

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 natural 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 was held on November 17, 2014. On October 26, 2015, the Circuit Court for Baltimore City issued an order affirming the MDPSC decision. However, on November 23, 2015, the residential consumer advocate filed an appeal of the Circuit Court's decision with the Maryland Court of Special Appeals. On March 7, 2016, the consumer advocate withdrew its appeal and no further action is expected.

MDPSC New Generation Contract Requirement (Exelon, Generation, BGE, PHI, Pepco and DPL). On April 12, 2012, the MDPSC issued an order that requires BGE, Pepco and DPL (collectively, the Contract EDCs) to negotiate and enter into a contract with the winning bidder of a competitive bidding process to build one new power plant in the range of 650 to 700 MWs beginning in 2015, in amounts proportional to their relative SOS loads. Under the terms of the order, the winning bidder was to construct a 661 MW natural gas-fired combined cycle generation plant in Waldorf, Maryland, with an expected commercial operation date of June 1, 2015, and each of the Contract EDCs was to recover its costs associated with the contract through surcharges on its respective SOS customers.

In response to a complaint filed by a group of generating companies in the PJM region, on September 30, 2013, the U.S. District Court for the District of Maryland issued a ruling that the MDPSC’s April 2012 order violated the Supremacy Clause of the U.S. Constitution by attempting to regulate wholesale prices. In contrast, on October 1, 2013, in response to appeals filed by the Contract EDCs and other parties, the Maryland Circuit Court for Baltimore City upheld the MDPSC’s orders requiring the Contract EDCs to enter into the contracts.

On October 24, 2013, the Federal district court issued an order ruling that the contracts are illegal and unenforceable. In November 2013 both the winning bidder and the MDPSC appealed the Federal district court decision to the U.S. Court of Appeals for the Fourth Circuit, which affirmed the lower Federal court ruling. On November 26, 2014, both the winning bidder and the MDPSC petitioned the U.S. Supreme Court to consider hearing an appeal of the Fourth Circuit decision. On October 19, 2015, the U.S. Supreme Court agreed to review the decision. On April 19, 2016, the U.S. Supreme Court unanimously affirmed the Fourth Circuit's ruling upholding the Federal district court's decision.

The decision of the Maryland Circuit Court was appealed to the Maryland Court of Special Appeals and was stayed pending decision by the U.S. Supreme Court. On August 1, 2016, the Contract EDCs submitted a filing requesting that the MDPSC take notice of the U.S. Supreme Court’s decision, and notifying the MDPSC that the Contract EDCs will dismiss their appeal pending at the Maryland Court of Special Appeals. On September 14, 2016, the Maryland Court of Special Appeals dismissed the pending appeal and the matter is considered closed.

Delaware Regulatory Matters

2016 Electric and Natural Gas Distribution Base Rates (Exelon, PHI and DPL). On May 17, 2016, DPL filed an application with the DPSC to increase its annual electric and natural gas distribution base rates by $63 million and $22 million, respectively, based on a requested ROE of 10.6%. While the DPSC is not required to issue a decision on the application within a specified period of time, Delaware law allowed DPL to put into effect $2.5 million of the rate increase two months after filing the applications which were effective July 16, 2016. It also allows the entire requested rate increase seven months after filing, subject to a cap and a refund obligation based on the final DPSC order. DPL cannot predict how much of the requested increase the DPSC will approve.

District of Columbia Regulatory Matters

2016 Electric Distribution Base Rates (Exelon, PHI and Pepco). On June 30, 2016, Pepco filed an application with the DCPSC to increase its annual electric distribution base rates by $86 million, which was updated to $82 million on October 14, 2016, based on a requested ROE of 10.6%. The DCPSC has issued a procedural schedule indicating a final decision will be issued by July 25, 2017. Any adjustments to its rates approved by the DCPSC are expected to take effect soon thereafter. Pepco cannot predict how much of the requested increase the DCPSC will approve.

On April 18, 2016, a party to a separate DCPSC proceeding filed a motion to suspend Pepco’s bill stabilization adjustment (BSA), which decouples distribution revenues from utility customers from the amount of electricity delivered. On September 9, 2016, the DCPSC denied the party’s motion and determined that the appropriate forum in which to determine whether the BSA continues to be just and reasonable is in Pepco’s rate case proceeding. In addition, the DCPSC stated that it was putting Pepco on notice that all funds collected for the BSA from January 2015 to the issuance of a decision in the rate case proceeding are subject to refund should the DCPSC determine that such funds were not justly or reasonably collected. On October 7, 2016, Pepco filed for reconsideration of this order and requested clarification that the order was not final and that the BSA matter would be decided in the base rate case. Pepco also argued that, if the order were considered final, the DCPSC reconsider its ruling that funds collected from the BSA can be retroactively refunded. Pepco cannot predict the outcome of this matter or the impact of a refund if ordered by the DCPSC.

District of Columbia Power Line Undergrounding Initiative (Exelon, PHI and Pepco). In May 2014, the Council of the District of Columbia enacted the Electric Company Infrastructure Improvement Financing Act of 2014 (the Improvement Financing Act), which provided enabling legislation for the District of Columbia Power Line Undergrounding (DC PLUG) initiative which would selectively place underground some of the District of Columbia’s most outage-prone power lines.

The Improvement Financing Act provides that: (i) Pepco is to fund approximately $500 million of the estimated cost to complete the DC PLUG initiative, recovering those costs through a volumetric surcharge on the electric bills of Pepco District of Columbia customers; (ii) $375 million of the DC PLUG initiative cost is to be financed by the District of Columbia’s issuance of securitized bonds, which bonds will be repaid through a volumetric surcharge (the DDOT surcharge) on the electric bills of Pepco District of Columbia customers that Pepco will remit to the District of Columbia; and (iii) the remaining costs up to $125 million are to be covered by the existing capital projects program of the District of Columbia Department of Transportation (DDOT). Pepco will not earn a return on or a return of the cost of the assets funded with the proceeds of the securitized bonds or assets that are constructed by DDOT under its capital projects program, but ownership and responsibility for the operation and maintenance of such assets will be transferred to Pepco for a nominal amount.

In June 2014, Pepco and DDOT filed a Triennial Plan related to the construction of selected underground feeders in the District of Columbia. In August 2014, Pepco filed an application for the issuance of a financing order to provide for the issuance of the District's bonds. In March 2016, the DCPSC's orders approving the Triennial Plan and the application for financing were upheld upon the resolution of appeals that had been filed with the District of Columbia Court of Appeals. In compliance with the Improvement Financing Act, on September 30, 2016, Pepco and DDOT filed a Second Triennial Plan. Recognizing the delays to the First Triennial Plan, Pepco and DDOT requested that the DCPSC hold the Second Triennial Plan in abeyance.

In June 2015, an agency of the federal government served by Pepco asserted that the DDOT surcharge constitutes a tax on end users from which the federal government is immune. PHI is currently evaluating the assertion and the resolution of this matter will likely further delay implementation of the DC PLUG initiative.

New Jersey Regulatory Matters

2016 Electric Distribution Base Rates (Exelon, PHI and ACE). On August 24, 2016, the NJBPU issued an order approving a stipulation of settlement among ACE, the New Jersey Division of Rate Counsel, NJBPU Staff and Unimin Corporation, and an increase of $45 million (before New Jersey sales and use tax) to its electric distribution base rates, with the new rates effective immediately. The stipulation of settlement provided that a determination on PowerAhead would be separated into a phase II of the rate proceeding and decided at a later date and the parties would seek to resolve the matter by the end of 2016, although resolution will most likely occur in the first quarter of 2017. PowerAhead includes capital investments to advance modernization of the electric grid through energy efficiency, increased distributed generation, and resiliency, focused on improving the distribution system's ability to withstand major storm events. ACE cannot predict if the NJBPU will approve the PowerAhead initiative.

Update and Reconciliation of Certain Under-Recovered Balances (Exelon, PHI and ACE). On February 1, 2016, ACE submitted its 2016 annual petition with the NJBPU seeking to reconcile and update (i) charges related to the recovery of above-market costs associated with ACE’s long-term power purchase contracts with the NUGs and (ii) costs related to surcharges for the New Jersey Societal Benefit Program (a statewide public interest program that is intended to benefit low income customers and address other public policy goals) and ACE’s uncollectible accounts.

The net impact of adjusting the charges as proposed is an overall annual rate increase of $9 million (revised to $19 million in April 2016, based upon an update for actuals through March 2016), including New Jersey sales and use tax. The matter is pending at the NJBPU.

New York Regulatory Matters

New York Clean Energy Standard (Exelon, Generation). On August 1, 2016, the New York Public Service Commission (NYPSC) issued an order establishing the Clean Energy Standard (CES), a component of which includes creation of a Tier 3 Zero Emission Credit (ZEC) program targeted at preserving the environmental attributes of zero-emissions nuclear-powered generating facilities that meet the criteria demonstrating public necessity as determined by the NYPSC. The New York State Energy Research and Development Authority (NYSERDA) will centrally procure the ZECs from eligible plants through a 12-year contract, to be administered in six two-year tranches, extending from April 1, 2017 through March 31, 2029. ZEC payments will be made to the eligible resources based upon the number of MWh produced, subject to specified caps and minimum performance requirements. The price to be paid for the ZECs under each tranche will be administratively determined using a formula based on the social cost of carbon as determined by the federal government. The ZEC price for the first tranche has been set at $17.48 per MWh of production. Following the first tranche, the price will be updated bi-annually. Each Load Serving Entity (LSE) shall be required to purchase an amount of ZECs equivalent to its load ratio share of the total electric energy in the New York Control Area. Cost recovery from ratepayers shall be incorporated into the commodity charges on customer bills. The CES initially identifies the three plants eligible for the ZEC program to include, for now, the FitzPatrick, Ginna, and Nine Mile Point nuclear facilities. The program specifically provides that Nine Mile Point Units 1 & 2 qualify jointly as a single facility and if either unit permanently ceases operations then both units will no longer qualify for ZEC payments for the remainder of the program. As issued, the order provides that the duration of the program beyond the first tranche is conditional upon a buyer purchasing the FitzPatrick facility and taking title prior to September 1, 2018; however, Generation and CENG requested clarification, or in the alternative limited rehearing, that this condition is applicable to the FitzPatrick facility only and has no bearing on the 12-year duration of the program for Ginna or Nine Mile Point. To date, several parties have filed with the NYPSC requests for rehearing or reconsideration of the CES and on October 19, 2016 a coalition of fossil generation companies filed a complaint in federal district court against the NYPSC alleging that the ZEC program violates certain provisions of the U.S. Constitution; specifically that the ZEC program interferes with FERC’s jurisdiction over wholesale rates and that it discriminates against out of state competitors. Generation and CENG will seek to intervene in the case and to dismiss the lawsuit. Other legal challenges remain possible and the outcomes of each of these challenges are currently uncertain. Negotiations with NYSERDA regarding contracts for the sale of ZECs from Ginna, Nine Mile Point and FitzPatrick are ongoing, and Generation expects that NYSERDA will enter into final agreements during the fourth quarter of 2016. See Note 7 - Early Nuclear Plant Retirements for additional information relative to Ginna and Nine Mile Point. See Note 4 - Mergers, Acquisitions and Dispositions for additional information on Generation's proposed acquisition of FitzPatrick.

Ginna Nuclear Power Plant Reliability Support Services Agreement (Exelon and Generation). In November 2014, in response to a petition filed by Ginna Nuclear Power Plant (Ginna) regarding the possible retirement of Ginna, the NYPSC directed Ginna and Rochester Gas & Electric Company (RG&E) to negotiate a Reliability Support Services Agreement (RSSA) to support the continued operation of Ginna to maintain the reliability of the RG&E transmission grid for a specified period of time. During 2015 and 2016, Ginna and RG&E made filings with the NYPSC and FERC for their approval of the proposed RSSA. Although the RSSA was still subject to regulatory approvals, on April 1, 2015, Ginna began delivering the power and capacity from the Ginna plant into the ISO-NY consistent with the technical provisions of the RSSA.

On March 22, 2016, Ginna submitted a compliance filing with FERC with revisions to the RSSA requested by FERC. On April 8, 2016, FERC accepted the compliance filing and on April 20, 2016, the NYPSC accepted the revised RSSA. Because all regulatory approvals for the RSSA have now been received, Generation began recognizing revenue based on the final approved pricing contained in the RSSA. Generation also recognized a one-time revenue adjustment in April 2016 of approximately $101 million representing the net cumulative previously unrecognized amount of revenue retroactive from the April 1, 2015 effective date through March 31, 2016. A 49.99% portion of the one-time adjustment will be removed from Generation’s results as a result of the noncontrolling interests in CENG.

The RSSA approved by the regulatory authorities has a term expiring on March 31, 2017, subject to possible extension in the event that RG&E needs additional time to complete transmission upgrades to address reliability concerns. In March 2016, RG&E notified Ginna that RG&E expects to complete the transmission upgrades prior to the RSSA expiration in March 2017 and will not need Ginna as an ongoing reliability solution after that date.

The approved RSSA requires Ginna to continue operating through the RSSA term. If Ginna does not plan to retire shortly after the expiration of the RSSA, Ginna is required to file a notice to that effect with the NYPSC no later than September 30, 2016. Under the terms of the RSSA, if Ginna continues to operate after June 14, 2017, Ginna would be required to make certain refund payments up to a maximum of $20 million to RG&E related to capital expenditures. On September 30, 2016, Ginna filed the required notice with the NYPSC of its intent to continue operating beyond the March 31, 2017 expiry of the RSSA, conditioned upon successful execution of an agreement between Ginna and NYSERDA for the sale of ZECs under the CES. As a result, Ginna has reserved the right to withdraw this notification and cease commercial operations if the ZEC program is terminated, suspended, or stayed prior to commencement of the program on April 1, 2017 or if for any reason a contract with NYSERDA in a form and substance satisfactory to Generation and CENG is not executed for Ginna, Nine Mile Point, or FitzPatrick. Negotiations with NYSERDA are ongoing and contract execution is currently targeted for completion in the fourth quarter of 2016.

There remains an increased risk that, for economic reasons, Ginna could be retired before the end of its operating license period in 2029. In the event the plant were to be retired before the current license term ends in 2029, Exelon's and Generation's results of operations could be adversely affected by the accelerated future decommissioning costs, severance costs, increased depreciation rates, and impairment charges, among other items. See Note 7-Early Nuclear Plant Retirements for further information regarding the impacts of a decision to early retire one or more nuclear plants.

Federal Regulatory Matters

Transmission Formula Rate (Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE). ComEd’s, BGE’s, Pepco's, DPL's and ACE's transmission rates are each established based on a FERC-approved formula. ComEd, BGE, Pepco, DPL, and ACE are required to file an annual update to the FERC-approved formula on or before May 15, with the resulting rates effective on June 1 of the same year. The 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 in effect beginning June 1 of the prior year and actual costs incurred for that year. ComEd, BGE, Pepco, DPL, and ACE 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, BGE’s, Pepco's, DPL's and ACE's best estimate of the revenue requirement expected to be filed with the FERC for that year’s reconciliation. The regulatory asset associated with transmission true-up is amortized to Operating revenues within their Consolidated Statements of Operations of Comprehensive Income as the associated amounts are recovered through rates.

The following total increases/(decreases) were included in ComEd’s, BGE’s, Pepco's, DPL's and ACE's electric transmission formula rate filings:



	2016
Annual Transmission Filings^(a)	ComEd			BGE			Pepco			DPL			ACE
Initial revenue requirement increase	$	90		$	12		$	2		$	8		$	8
Annual reconciliation (decrease) increase	4			3			(10		)	(10		)	(14		)
Dedicated facilities (decrease) increase ^(b)	—			13			—			—			—
MAPP abandonment recovery decrease ^(c)	—			—			(15		)	(12		)	—
Total revenue requirement increase (decrease)	$	94		$	28		$	(23	)	$	(14	)	$	(6	)

Allowed return on rate base ^(d)	8.47		%	8.09		%	7.88		%	7.21		%	7.83		%
Previously authorized allowed return on rate base ^(d)	8.61		%	8.46		%	8.36		%	7.80		%	8.51		%
Allowed ROE ^(e)	11.50		%	10.50		%	10.50		%	10.50		%	10.50		%

_____________

(a) All rates are effective June 2016.

(b) BGE's transmission revenues include a FERC approved dedicated facilities charge to recover the costs of providing transmission service to specifically designated load by BGE.

(c) In 2012, PJM terminated the MAPP transmission line construction project planned for the Pepco and DPL service territories. Pursuant to a FERC approved settlement agreement, the abandonment costs associated with MAPP were being recovered in transmission rates over a three-year period that ended in May 2016.


(d)	Refers to the weighted average debt and equity return on transmission rate bases.

(e) 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%. As part of the FERC-approved settlement of the ROE complaint against BGE, Pepco, DPL and ACE, the rate of return on common equity is 10.50%, inclusive of a 50 basis point incentive adder for being a member of a regional transmission organization.

For additional information regarding ComEd and BGE's transmission formula rate filings see Note 3 — Regulatory Matters of the Exelon 2015 Form 10-K. For additional information regarding Pepco, DPL and ACE's transmission formula rate filings see Note 7 - Regulatory Matters of the PHI 2015 Form 10-K.

PJM Transmission Rate Design and Operating Agreements (Exelon, Generation, ComEd, PECO, BGE, Pepco, DPL and ACE). PJM Transmission Rate Design specifies the rates for transmission service charged to customers within PJM. Currently, ComEd, PECO, BGE, Pepco, DPL and ACE 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. A number of parties appealed to the U.S. Court of Appeals for the Seventh Circuit for review of the decision.

In August 2009, the court issued its decision affirming the FERC’s order with regard to the existing facilities, but remanded to FERC the issue of the cost allocation associated with the new facilities 500 kV and above (Cost Allocation Issue) for further consideration by the FERC. On remand, FERC reaffirmed its earlier decision to socialize the costs of new facilities 500 kV and above. A number of parties filed appeals of these orders. In June 2014, the court again remanded the Cost Allocation Issue to FERC. On December 18, 2014, FERC issued an order setting an evidentiary hearing and settlement proceeding regarding the Cost Allocation Issue. On June 15, 2016, a number of parties, including Exelon and the Utility Registrants filed an Offer of Settlement with FERC. Each state that is a party in this proceeding either signed, or will not oppose, the settlement. On July 5, 2016, a number of merchant transmission owners and load servicing entities opposed the Settlement in whole or in part. As of September 30, 2016, the Settlement is awaiting FERC's action. If the Settlement is approved, effective January 1, 2016, for the costs of the 500 kV facilities approved by the PJM Board on or after February 1, 2013, 50% will be socialized across PJM and 50% will be allocated according to an engineering formula that calculates the flows on the transmission facilities. The Settlement includes provisions for monthly credits or charges that are expected to be mostly refunded or recovered through customer rates over a 10-year period based on negotiated numbers for charges prior to January 1, 2016.

Exelon expects that the Settlement will not have a material impact on the results of operations, cash flows and financial position of Generation, ComEd, PECO, BGE, Pepco, DPL or ACE. The Settlement is subject to approval by FERC.

Operating License Renewals (Exelon and Generation). Generation has 40-year operating licenses from the NRC for each of its nuclear units. The operating license renewal process takes approximately four to five years from the commencement of the renewal process until completion of the NRC’s review.

On December 9, 2014, Generation submitted an application to the NRC to extend the current operating licenses of LaSalle Units 1 and 2 by 20 years. On October 19, 2016, the NRC approved Generation's request to extend the operating licenses of LaSalle Unit 1 and 2 by 20 years to 2042 and 2043, respectively.

On August 29, 2012, Generation submitted a hydroelectric license application to FERC for a 46-year license for the Conowingo Hydroelectric Project (Conowingo). In connection with Generation's efforts to obtain a water quality certification pursuant to Section 401 of the Clean Water Act with Maryland Department of the Environment (MDE) for Conowingo, Generation continues to work with MDE and other stakeholders to resolve water quality licensing issues, including: (1) water quality, (2) fish habitat, and (3) sediment. In addition, Generation continues to work with MDE and other Federal and Maryland state agencies to conduct and fund an additional sediment and nutrient monitoring study.

On August 7, 2015, US Fish and Wildlife Service of the US Department of the Interior (Interior) submitted its modified fishway prescription to FERC in the Conowingo licensing proceedings. On September 11, 2015, Exelon filed a request for an administrative hearing and proposed an alternative prescription to challenge Interior's preliminary prescription. On April 21, 2016, Exelon and Interior executed a Settlement Agreement resolving all fish passage issues between the parties. Accordingly, on April 22, 2016, Exelon withdrew its Request for a Trial-Type Hearing and Alternative Prescription. The financial impact of the Settlement Agreement is estimated to be $3 million to $7 million per year, on average, over the 46-year life of the new license, including both capital and operating costs. The actual timing and amount of these costs are not currently fixed and may vary significantly from year to year throughout the life of the new license. Resolution of the remaining issues relating to Conowingo involving various stakeholders may have a material effect on Exelon's and Generation’s results of operations and financial position through an increase in capital expenditures and operating costs. As of September 30, 2016, $27 million of direct costs associated with the Conowingo licensing effort have been capitalized. See Note 3 - Regulatory Matters of the Exelon 2015 Form 10-K for additional information on Generation's operating license renewal efforts.

Regulatory Assets and Liabilities (Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE)

Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE 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.

As a result of applying the acquisition method of accounting and pushing it down to the consolidated financial statements of PHI, certain regulatory assets and liabilities were established at Exelon and PHI to offset the impacts of fair valuing the acquired assets and liabilities assumed which are subject to regulatory recovery. In total, Exelon and PHI recorded a net $2.4 billion regulatory asset reflecting adjustments recorded as a result of the acquisition method of accounting. See Note 4 — Mergers, Acquisitions and Dispositions for additional information.

The following tables provide information about the regulatory assets and liabilities of Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE as of September 30, 2016 and December 31, 2015. For additional information on the specific regulatory assets and liabilities, refer to Note 3 — Regulatory Matters of the Exelon 2015 Form 10-K and Note 7 - Regulatory Matters of the PHI 2015 Form 10-K.



									Successor
September 30, 2016	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Regulatory assets
Pension and other postretirement benefits ^(a)	$	4,096	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Deferred income taxes ^(b)	1,973		73		1,555		94		251		162		38		51
AMI programs ^(c)	704		160		53		235		256		171		85		—
Under-recovered distribution service costs ^(d)	232		232		—		—		—		—		—		—
Debt costs ^(e)	126		43		1		7		82		18		9		6
Fair value of long-term debt ^(f)	828		—		—		—		684		—		—		—
Fair value of PHI's unamortized energy contracts ^(g)	1,206		—		—		—		1,206		—		—		—
Severance	6		—		—		6		—		—		—		—
Asset retirement obligations	108		74		22		11		1		1		—		—
MGP remediation costs	295		267		27		1		—		—		—		—
Under-recovered uncollectible accounts	58		58		—		—		—		—		—		—
Renewable energy	246		244		—		—		2		—		—		2
Energy and transmission programs ^{(h)(i)(j)(k)(l)}	74		31		—		25		18		1		8		9
Deferred storm costs	39		—		—		1		38		14		5		19
Electric generation-related regulatory asset	13		—		—		13		—		—		—		—
Rate stabilization deferral	25		—		—		25		—		—		—		—
Energy efficiency and demand response programs	642		—		1		289		352		254		98		—
Merger integration costs ^(m)(n)	23		—		—		10		13		10		3		—
Under-recovered revenue decoupling ^(o)(p)	9		—		—		—		9		7		2		—
COPCO acquisition adjustment	9		—		—		—		9		—		9		—
Recoverable Workers compensation and long-term disability cost	30		—		—		—		30		30		—		—
Vacation accrual	37		—		13		—		24		—		14		10
Securitized stranded costs	153		—		—		—		153		—		—		153
CAP arrearage	7		—		7		—		—		—		—		—
Removal costs	448		—		—		—		448		119		84		246
Other	45		10		9		5		19		11		4		5
Total regulatory assets	11,432		1,192		1,688		722		3,595		798		359		501
Less: current portion	1,410		205		37		214		650		122		62		89
Total non-current regulatory assets	$	10,022	$	987	$	1,651	$	508	$	2,945	$	676	$	297	$	412



									Successor
September 30, 2016	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE

Regulatory liabilities
Other postretirement benefits	$	85	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Nuclear decommissioning	2,704		2,238		466		—		—		—		—		—
Removal costs	1,627		1,333		—		151		143		20		123		—
Deferred rent ^(q)	40		—		—		—		40		—		—		—
Energy efficiency and demand response programs	175		135		40		—		—		—		—		—
DLC program costs	8		—		8		—		—		—		—		—
Electric distribution tax repairs	79		—		79		—		—		—		—		—
Gas distribution tax repairs	21		—		21		—		—		—		—		—
Energy and transmission programs ^{(h)(i)(r)(j)(k)(l)}	171		72		59		—		40		17		11		12
Over-recovered revenue decoupling ^(o)	5		—		—		5		—		—		—		—
Other	70		3		6		16		45		7		12		24
Total regulatory liabilities	4,985		3,781		679		172		268		44		146		36
Less: current portion	548		204		128		54		101		20		46		35
Total non-current regulatory liabilities	$	4,437	$	3,577	$	551	$	118	$	167	$	24	$	100	$	1



									Predecessor
December 31, 2015	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE

Regulatory assets
Pension and other postretirement benefits	$	3,156	$	—	$	—	$	—	$	910	$	—	$	—	$	—
Deferred income taxes ^(b)	1,616		64		1,473		79		214		137		36		41
AMI programs	399		140		63		196		267		180		87		—
Under-recovered distribution service costs ^(d)	189		189		—		—		—		—		—		—
Debt costs	47		46		1		8		36		19		10		7
Fair value of long-term debt ^(f)	162		—		—		—		—		—		—		—
Severance	9		—		—		9		—		—		—		—
Asset retirement obligations	108		67		22		19		1		1		—		—
MGP remediation costs	286		255		30		1		—		—		—		—
Under-recovered uncollectible accounts	52		52		—		—		—		—		—		—
Renewable energy	247		247		—		—		6		—		1		5
Energy and transmission programs ^{(h)(i)(r)(j)(k)(l)}	84		43		1		40		33		9		11		13
Deferred storm costs	2		—		—		2		43		19		6		18
Electric generation-related regulatory asset	20		—		—		20		—		—		—		—
Rate stabilization deferral	87		—		—		87		—		—		—		—
Energy efficiency and demand response programs	279		—		1		278		401		289		111		1
Merger integration costs	6		—		—		6		—		—		—		—
Conservation voltage reduction	3		—		—		3		—		—		—		—
Under-recovered revenue decoupling ^(o)(p)	30		—		—		30		14		10		4		—
COPCO acquisition adjustment	—		—		—		—		—		—		13		—
Workers compensation and long-term disability costs	—		—		—		—		31		31		—		—
Vacation accrual	6		—		6		—		23		—		14		9
Securitized stranded costs	—		—		—		—		202		—		—		202
CAP arrearage	7		—		7		—		—		—		—		—
Removal costs	—		—		—		—		369		92		69		208
Other	29		10		13		3		32		14		9		8
Total regulatory assets	6,824		1,113		1,617		781		2,582		801		371		512
Less: current portion	759		218		34		267		305		140		72		98
Total non-current regulatory assets	$	6,065	$	895	$	1,583	$	514	$	2,277	$	661	$	299	$	414



									Predecessor
December 31, 2015	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Regulatory liabilities
Other postretirement benefits	$	94	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Nuclear decommissioning	2,577		2,172		405		—		—		—		—		—
Removal costs	1,527		1,332		—		195		150		21		129		—
Energy efficiency and demand response programs	92		52		40		—		1		—		—		1
DLC program costs	9		—		9		—		—		—		—		—
Electric distribution tax repairs	95		—		95		—		—		—		—		—
Gas distribution tax repairs	28		—		28		—		—		—		—		—
Energy and transmission programs ^{(h)(i)(r)(j)(k)(l)}	131		53		60		18		27		16		19		8
Over-recovered revenue decoupling ^(o)	1		—		—		1		—		—		—		—
Other	16		5		2		8		35		7		12		16
Total regulatory liabilities	4,570		3,614		639		222		213		44		160		25
Less: current portion	369		155		112		38		66		15		49		18
Total non-current regulatory liabilities	$	4,201	$	3,459	$	527	$	184	$	147	$	29	$	111	$	7

______

(a)

As of September 30, 2016, the pension and other postretirement benefits regulatory asset at Exelon includes regulatory assets of $1,087 million established at the date of the PHI Merger related to unrecognized costs that are probable of regulatory recovery. The regulatory assets are amortized over periods from 3 to 15 years, depending on the underlying component. Pepco, DPL and ACE are currently recovering these costs through base rates. Pepco, DPL and ACE are not earning a return on the recovery of these costs in base rates.

(b)

As of September 30, 2016, includes transmission-related regulatory assets that require FERC approval separate from the transmission formula rate of $19 million, $32 million, $29 million, $20 million and $18 million for ComEd, BGE, Pepco, DPL and ACE, respectively. As of December 31, 2015, includes transmission-related regulatory assets that require FERC approval separate from the transmission formula rate of $15 million, $16 million, $36 million, $18 million and $15 million for ComEd, BGE, Pepco, DPL and ACE, respectively.

(c)

Represents AMI costs associated with the installation of smart meters and the early retirement of legacy meters throughout the service territories for ComEd, PECO, BGE, Pepco and DPL. An AMI program has not been approved by the NJBPU for ACE in New Jersey. DPL and Pepco have received approval for recovery of deferred AMI program costs from the DCPSC and DPSC in the Delaware and DC service territories, and have requested recovery in pending distribution rate cases with the MDPSC for the Maryland service territories. As of September 30, 2016, the portion of deferred AMI program costs pending approval from the MDPSC is $32 million for BGE, $134 million for Pepco and $40 million for DPL, of which $75 million for Pepco and $14 million for DPL relates to retired legacy meters which are not earning a return and $3 million of post-test year costs for Pepco which are not earning a return.

(d)

As of September 30, 2016, ComEd’s regulatory asset of $232 million was comprised of $178 million for the 2014 - 2016 annual reconciliations and $54 million related to significant one-time events including $24 million of deferred storm costs, $11 million of Constellation and PHI merger and integration related costs and $19 million of smart meter related costs. As of December 31, 2015, ComEd’s regulatory asset of $189 million was comprised of $142 million for the 2014 and 2015 annual reconciliations and $47 million related to significant one-time events, including $36 million of deferred storm costs and $11 million of Constellation merger and integration related costs. See Note 4— Merger, Acquisitions, and Dispositions of the Exelon 2015 Form 10-K for further information.


(e)	Includes at Exelon and PHI the regulatory asset recorded at PHI for debt costs that are recoverable through the ratemaking process at Pepco, DPL, and ACE which were eliminated at Exelon and PHI as part of acquisition accounting.


(f)	Includes the unamortized regulatory assets recorded for the difference between carrying value and fair value of long-term debt of BGE as of the Constellation merger date and at Exelon and PHI for the difference between carrying value and fair value of long-term debt of Pepco, DPL and ACE as of the PHI Merger date.


(g)	Represents the regulatory asset recorded at Exelon and PHI offsetting the fair value adjustments related to Pepco's, DPL's and ACE's electricity and natural gas energy supply contracts recorded at PHI as of the PHI Merger date. Pepco, DPL and ACE are allowed full recovery of the costs of these contracts through their respective rate making processes.

(h)

As of September 30, 2016, ComEd’s regulatory asset of $31 million included $24 million associated with transmission costs recoverable through its FERC approved formula rate and $7 million of Constellation merger and integration costs to be recovered upon FERC approval. As of September 30, 2016, ComEd’s regulatory liability of $72 million included $43 million related to over-recovered energy costs and $29 million associated with revenues received for renewable energy requirements. As of December 31, 2015, ComEd’s regulatory asset of $43 million included $5 million related to under-recovered energy costs, $31 million associated with transmission costs recoverable through its FERC approved formula rate, and $7 million of Constellation merger and integration costs to be recovered upon FERC approval. As of December 31, 2015, ComEd’s regulatory liability of $53 million included $29 million related to over-recovered energy costs and $24 million associated with revenues received for renewable energy requirements.

(i)

As of September 30, 2016, BGE's regulatory asset of $25 million included $3 million of costs associated with transmission costs recoverable through its FERC approved formula rate, $19 million related to under-recovered electric energy costs, $3 million of abandonment costs to be recovered upon FERC approval, and $1 million related to under-recovered natural gas costs. As of December 31, 2015, BGE’s regulatory asset of $40 million included $12 million of costs associated with transmission costs recoverable through its FERC approved formula rate and $28 million related to under-recovered electric energy costs. As of December 31, 2015, BGE’s regulatory liability of $18 million related to $14 million of over-recovered transmission costs and $5 million of over-recovered natural gas costs, offset by $1 million of abandonment costs to be recovered upon FERC approval.

(j)

As of September 30, 2016, Pepco's regulatory asset of $1 million related to under-recovered electric energy costs. As of September 30, 2016, Pepco's regulatory liability of $17 million included $9 million of over-recovered transmission costs and $8 million of over-recovered electric energy costs. As of December 31, 2015, Pepco's regulatory asset of $9 million included $5 million of transmission costs recoverable through its FERC approved formula rate and $4 million of recoverable abandonment costs. As of December 31, 2015, Pepco's regulatory liability of $16 million included $14 million of over-recovered transmission costs and $2 million of over-recovered electric energy costs.

(k)

As of September 30, 2016, DPL's regulatory asset of $8 million included $1 million of transmission costs recoverable through its FERC approved formula rate and $7 million of under-recovered electric energy costs. As of September 30, 2016, DPL's regulatory liability of $11 million included $6 million of over-recovered electric energy costs and $5 million of over-recovered transmission costs. As of December 31, 2015, DPL's regulatory asset of $11 million included $7 million of transmission costs recoverable through its FERC approved formula rate, $3 million of recoverable abandonment costs, and $1 million of under-recovered electric energy costs. As of December 31, 2015, DPL's regulatory liability of $19 million included $4 million related to the over-recovered natural gas costs under the GCR mechanism, $4 million of over-recovered electric energy costs, and $11 million of over-recovered transmission costs.

(l)

As of September 30, 2016, ACE's regulatory asset of $9 million included $4 million of transmission costs recoverable through its FERC approved formula rate and $5 million of under-recovered electric energy costs. As of September 30, 2016, ACE's regulatory liability of $12 million included $7 million of over-recovered transmission costs and $5 million of over-recovered electric energy costs. As of December 31, 2015, ACE's regulatory asset of $13 million included $2 million of transmission costs recoverable through its FERC approved formula rate and $11 million of under-recovered electric energy costs. As of December 31, 2015, ACE's regulatory liability of $8 million related to over-recovered transmission costs.


(m)	As of September 30, 2016, BGE's regulatory asset of $10 million included $6 million of previously incurred PHI acquisition costs as authorized by the June 2016 rate case order.


(n)	Represents previously incurred PHI acquisition costs expected to be recovered in distribution rates in the Maryland service territories of Pepco and DPL.

(o)

Represents the electric and natural gas distribution costs recoverable from customers under BGE’s decoupling mechanism. As of September 30, 2016, BGE had a regulatory liability of $5 million related to over-recovered natural gas revenue decoupling and $0 million related to over-recovered electric revenue decoupling. As of December 31, 2015, BGE had a regulatory asset of $30 million related to under-recovered electric revenue decoupling and a regulatory liability of $1 million related to over-recovered natural gas revenue decoupling.


(p)	Represents the electric distribution costs recoverable from customers under Pepco's Maryland and District of Columbia decoupling mechanisms and DPL's Maryland decoupling mechanism.


(q)	Represents the regulatory liability recorded at Exelon and PHI for deferred rent related to a lease that is recoverable through the ratemaking process at Pepco, DPL and ACE.

(r)

As of September 30, 2016, PECO's regulatory liability of $59 million included $30 million related to over-recovered costs under the DSP program, $13 million related to the over-recovered natural gas costs under the PGC, $10 million related to over-recovered non-bypassable transmission service charges and $6 million related to over-recovered electric transmission costs. As of December 31, 2015, PECO's regulatory asset of $1 million related to under-recovered non-bypassable transmission service charges. As of December 31, 2015, PECO's regulatory liability of $60 million included $35 million related to over-recovered costs under the DSP program, $22 million related to the over-recovered natural gas costs under the PGC and $3 million related to the over-recovered electric transmission costs.

Purchase of Receivables Programs (Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE)

ComEd, PECO, BGE, Pepco, DPL and ACE are required, under separate legislation and regulations in Illinois, Pennsylvania, Maryland, District of Columbia and New Jersey, to purchase certain receivables from retail electric and natural gas suppliers that participate in the utilities' consolidated billing. ComEd, BGE, Pepco and DPL purchase receivables at a discount to recover primarily uncollectible accounts expense from the suppliers. PECO is required to purchase receivables at face value and is permitted to recover uncollectible accounts expense, including those from Third Party Suppliers, from customers through distribution rates. ACE purchases receivables at face value. ACE recovers all uncollectible accounts expense, including those from Third Party Suppliers, through the Societal Benefits Charge (SBC) rider, which includes uncollectible accounts expense as a component. The SBC is filed annually with the NJBPU. Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE 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, BGE’s, PHI's, Pepco's, DPL's and ACE's Consolidated Balance Sheets. The following tables provide information about the purchased receivables of those companies as of September 30, 2016 and December 31, 2015.



													Successor
As of September 30, 2016	Exelon			ComEd			PECO			BGE			PHI			Pepco			DPL		ACE
Purchased receivables^(c)	$	396		$	123		$	90		$	66		$	117		$	79		$	12	$	26
Allowance for uncollectible accounts^(a)	(36		)	(17		)	(7		)	(6		)	(6		)	(4		)	—		(2		)
Purchased receivables, net	$	360		$	106		$	83		$	60		$	111		$	75		$	12	$	24



													Predecessor
As of December 31, 2015	Exelon			ComEd			PECO			BGE			PHI			Pepco			DPL		ACE
Purchased receivables^(b)(c)	$	229		$	103		$	67		$	59		$	100		$	70		$	11	$	19
Allowance for uncollectible accounts^(a)	(31		)	(16		)	(7		)	(8		)	(6		)	(4		)	—		(2		)
Purchased receivables, net	$	198		$	87		$	60		$	51		$	94		$	66		$	11	$	17

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(a)	For ComEd, BGE, Pepco and DPL, 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 tariff.


(b)	PECO’s natural gas POR program became effective on January 1, 2012 and included a 1% discount on purchased receivables in order to recover the implementation costs of the program. The implementation costs were fully recovered and the 1% discount was reset to 0%, effective July 2015.

(c)

Pepco's electric POR program in Maryland included a discount on purchased receivables ranging from 0% to 2% depending on customer class, and Pepco's electric POR program in the District of Columbia included a discount on purchased receivables ranging from 0% to 6% depending on customer class. DPL's electric POR program in Maryland included a discount on purchased receivables ranging from 0% to 1% depending on customer class.