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. 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 numerous easements across the project route through voluntary transactions. ComEd is seeking to acquire the remaining rights either through settlement or condemnation proceedings that are currently pending in the relevant circuit courts. ComEd began construction of the line during the second quarter of 2015 with an expected in-service date of the second quarter of 2017.

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, 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 appealed the Court's decision. On April 5, 2016, the PAPUC’s request for appeal was denied. PECO does not have information at this time as to what action it may be required to take following remand to the PAPUC.

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 is procuring 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) will move to spot market pricing. As of March 31, 2016, PECO entered into contracts with PAPUC-approved bidders, including Generation, resulting from the first three 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. The program has a 24-month term from June 1, 2017 through May 31, 2019, and complies with electric generation procurement guidelines set forth in Act 129. A PAPUC ruling is expected in late 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. The order tentatively established PECO’s five-year cumulative consumption reduction target at 2,080,553 MWh.

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 on March 17, 2016, subject to clarification of a few minor issues. PECO refiled its Phase III Plan, with all requested clarifications, on March 31, 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 annual service revenues for electric delivery, based on a requested ROE of 10.6%. Any adjustments to rates approved by the MDPSC are expected to take effect in November 2016. In addition to the proposed $127 million rate increase, Pepco is proposing to continue its Grid Resiliency Charge initially approved in July 2013 in connection with Pepco’s electric distribution rate case filed in November 2012. In connection with the Grid Resiliency Charge, 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 increase the MDPSC will approve or if it will approve Pepco’s Grid Resiliency Charge proposal.

2013 Maryland Electric and Gas Distribution Rate Case (Exelon and BGE). On May 17, 2013, and as amended on August 23, 2013, BGE filed for electric and 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 March 31, 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 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.

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 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 March 31, 2016 and December 31, 2015, BGE recorded a regulatory asset of $212 million and $196 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, the cost of the retired non-AMI meters will be amortized over 10 years.

As part of the 2015 electric and gas distribution rate case filed on November 6, 2015, BGE is seeking recovery of its smart grid initiative costs. Of BGE's requested $197 million, $141 million relates to the smart grid initiative. In support of its recovery of smart grid initiative costs, BGE provided evidence demonstrating that the benefits exceed the costs on a present value basis by a ratio of 2.3 to 1.0, on a nominal basis. For further information, see Note 3 - Regulatory Matters of the Exelon 2015 Form 10-K.

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 MW beginning in 2015, in amounts proportional to their relative SOS loads. Under the terms of the order, the winning bidder will 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 will 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. The U.S. Supreme Court decision will likely moot the state court action pending in the Court of Special Appeals of Maryland.

Delaware Regulatory Matters

Gas Cost Rates. (Exelon, PHI and DPL) DPL makes an annual GCR filing with the DPSC for the purpose of allowing DPL to recover natural gas procurement costs through customer rates. In August 2015, DPL made its 2015 GCR filing. The rates proposed in the 2015 GCR filing would result in a GCR decrease of approximately 26%, primarily reflecting lower natural gas prices. On September 22, 2015, the DPSC issued an order allowing DPL to place the new rates into effect on November 1, 2015, subject to refund and pending final DPSC approval. On March 22, 2016, the DPSC approved the Gas Cost Rate as filed.

2013 Electric Distribution Base Rates (Exelon, PHI and DPL). In March 2013, and as amended on September 20, 2013, DPL filed for an electric distribution base rate increase with the DPSC, ultimately requesting an annual increase of $42 million.

In August 2014, the DPSC issued a final order in DPL's 2013 electric distribution rate case for an annual increase of $15 million and an ROE of 9.70%. Rates became effective on May 1, 2014.

In September 2014, DPL filed an appeal with the Delaware Superior Court of the DPSC’s August 2014 order in this proceeding, seeking the court’s review of the DPSC’s decision relating to the recovery of costs associated with one component of employee compensation, certain retirement benefits and credit facility expenses. The Division of the Public Advocate filed a cross-appeal in September 2014, pertaining to the treatment of a prepaid pension expense and other postretirement benefit obligations in base rates. Under the Settlement Agreement related to the Merger, the parties agreed to suspend the appeal and, upon consummation of the Merger, to the withdrawal of the appeal and the cross-appeal with prejudice. In accordance with the settlement, on April 13, 2016, the parties filed a Stipulation of Dismissal with the court to dismiss the appeal and the cross-appeal. The court has not yet acted on this filing.

District of Columbia Regulatory Matters

District of Columbia Power Line Undergrounding Initiative (Exelon, PHI and Pepco). On May 3, 2014, the Council of the District of Columbia enacted the Electric Company Infrastructure Improvement Financing Act of 2014 (the Improvement Financing Act), which provides enabling legislation for the DC PLUG initiative. This $1 billion initiative seeks to selectively place underground some of the District of Columbia’s most outage-prone power lines, which lines and surrounding conduit would be owned and maintained by Pepco.

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 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 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.

On June 17, 2014, Pepco and DDOT filed a Triennial Plan related to the construction of selected underground feeders in the District of Columbia and recovery of Pepco’s investment through a volumetric surcharge (the Triennial Plan), all in accordance with the Improvement Financing Act. On August 1, 2014, Pepco filed an application for the issuance of a financing order to provide for the issuance of the District’s bonds and a volumetric surcharge for the District to recover the costs associated with the bond issuance (the DDOT surcharge).

On November 12, 2014, the DCPSC issued an order approving the Triennial Plan and Pepco’s volumetric surcharge, and issued the financing order, including approval of the DDOT surcharge. Together these orders permit (i) Pepco and DDOT to commence proposed construction under the Triennial Plan; (ii) the District of Columbia to issue the necessary bonds to fund the District of Columbia’s portion of the DC PLUG initiative; and (iii) the establishment of the customer surcharges contemplated by the Improvement Financing Act.

In March 2015, a party to the DCPSC proceedings filed with the District of Columbia Court of Appeals a petition for review of the order approving the Triennial Plan and the issuance of the financing order. On January 14, 2016, the District of Columbia Court of Appeals affirmed the orders of the DCPSC. On January 27, 2016, the original petitioning party sought rehearing of the District of Columbia Court of Appeals decision. On March 17, 2016, the District of Columbia Court of Appeals denied the original petitioning party's motion for rehearing.

Separately, 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 delay implementation of the DC PLUG initiative.

New Jersey Regulatory Matters

2016 Electric Distribution Base Rates (Exelon, PHI and ACE). On March 22, 2016, ACE filed an application with the NJBPU requesting an increase of $84 million to its annual service revenues for electric delivery, based on a requested ROE of 10.6%. In addition to the request for base rate relief, ACE has also included a request that the NJBPU approve ACE’s five-year grid resiliency initiative known as “PowerAhead.” As proposed, PowerAhead includes $176 million of 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. A decision is expected in the first half of 2017. ACE cannot predict how much of the requested increase the NJBPU will approve or if it will approve ACE's 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 uncollected 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. ACE has requested that the NJBPU place the new rates into effect by June 1, 2016.

Standard Offer Capacity Agreements (Exelon, PHI and ACE). On April 28, 2011, ACE entered into three SOCAs by order of the NJBPU, each with a different generation company. ACE and the other New Jersey EDCs entered into the SOCAs under protest, arguing that the EDCs were denied due process and that the SOCAs violated certain of the requirements of the New Jersey law under which the SOCAs were established (the NJ SOCA Law). On October 22, 2013, in light of the decision of the U.S. District Court for the District of New Jersey described below, the state appeals of the NJBPU implementation orders filed by the EDCs and generators were dismissed without prejudice, subject to the parties exercising their appellate rights in the Federal courts.

In February 2011, ACE joined other plaintiffs in an action filed in the U.S. District Court for the District of New Jersey challenging the NJ SOCA Law on the grounds that it violates the Commerce Clause and the Supremacy Clause of the U.S. Constitution. In October 2013, the Federal district court issued a ruling that the NJ SOCA Law is preempted by the Federal Power Act (FPA) and violates the Supremacy Clause, and is therefore null and void. On October 11, 2013, the Federal district court issued an order ruling that the SOCAs are void, invalid and unenforceable, which order was affirmed by the U.S. Court of Appeals for the Third Circuit on September 11, 2014.

On November 26, 2014 and December 10, 2014, respectively, one of the generation companies and the NJBPU petitioned the U.S. Supreme Court to consider hearing an appeal of the Third Circuit decision. On April 19, 2016, the U.S. Supreme Court unanimously affirmed the Fourth Circuit decision, discussed above under “MDPSC New Generation Contract Requirement,” holding that the MDPSC’s required contracts are illegal and unenforceable. On April 25, 2016, the U.S. Supreme Court ruled not to review the Third Circuit decision. This denial leaves the Third Circuit decision in place, with the same outcome as the Fourth Circuit decision.

ACE terminated one of the three SOCAs effective July 1, 2013 due to the occurrence of an event of default on the part of the generation company counterparty. ACE terminated the remaining two SOCAs effective November 19, 2013, in response to the October 2013 Federal district court decision.

New York Regulatory Matters

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 New York Public Service Commission (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 will begin recognizing revenue based on the final approved pricing contained in the RSSA. Generation will also recognize 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 non-controlling interest 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.

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.

The approved RSSA requires Ginna to continue operating through the RSSA term. There remains an increased risk that, for economic reasons, Ginna could be retired before the end of its operating license period in 2029 if an adequate regulatory or legislative solution is not adopted in New York. 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-Implications of Potential Early 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). The following tables provide information about the net regulatory asset or liabilities associated with the transmission formula rate of the indicated registrants as of March 31, 2016 and December 31, 2015. The regulatory asset associated with the transmission true-up is amortized to Operating revenues as the associated amounts are recovered through rates.



							Successor
As of March 31, 2016	Exelon		ComEd		BGE		PHI		Pepco		DPL		ACE
Regulatory Assets^(a)	$	60	$	31	$	17	$	12	$	4	$	7	$	1



							Predecessor
As of December 31, 2015	Exelon		ComEd		BGE		PHI		Pepco		DPL		ACE
Regulatory Assets^(a)(b)	$	43	$	31	$	12	$	14	$	5	$	7	$	2

_____


(a)	The regulatory assets represent a component of the costs included within the energy and transmission regulatory programs. Refer to Regulatory Assets and Liabilities table for additional information.


(b)	The Exelon consolidated amounts do not include the regulatory assets of PHI, Pepco, DPL, and ACE at December 31, 2015.

On April 13, 2016, ComEd filed its annual transmission formula rate update based upon the FERC approved formula with the FERC. The filing establishes the revenue requirement used to set rates that will take effect in June 2016, subject to review by the FERC and other parties, which is due by fourth quarter 2016. ComEd's 2016 annual update includes a total increase to the revenue requirement of $94 million, reflecting an increase of $90 million for the initial revenue requirement and an increase of $4 million related to the annual reconciliation. The revenue requirement provides for a weighted average debt and equity return on transmission rate base of 8.47%, inclusive of an allowed ROE of 11.50%, a decrease from the 8.61% average debt and equity return previously authorized.

On April 27, 2016, BGE filed its annual transmission formula rate update based upon the FERC approved formula with the FERC. The filing establishes the revenue requirement used to set rates that will take effect in June 2016, subject to review by the FERC and other parties, which is due by third quarter 2016. BGE's 2016 annual update includes a total increase to the revenue requirement of $15 million, reflecting an increase of $12 million for the initial revenue requirement and a decrease of $3 million related to the annual reconciliation. This increase excludes the $13 million increase in revenue requirement associated with dedicated facilities charges. The revenue requirement provides for a weighted average debt and equity return on transmission rate base of 8.09%, inclusive of an allowed ROE of 10.50% a decrease from the 8.46% average debt and equity return previously authorized.

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.

FERC Transmission Complaint (Exelon, BGE, PHI, Pepco, DPL and ACE). In February 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, Pepco, DPL and ACE relating to their respective transmission formula rates. BGE’s formula rate included a 10.8% base ROE and a 50 basis point incentive for participating in PJM (and certain additional incentive base points on certain projects). Pepco's, DPL's and ACE's formula rates included, for facilities placed into service after January 1, 2006, a base ROE of 11.3%, and for facilities placed into service prior to January 1, 2006, a base ROE of 10.8% and a 50 basis point incentive for participating in PJM. The parties sought a reduction in the base return on equity to 8.7% and changes to the formula rate process. Under FERC rules, any revenues subject to refund are limited to a fifteen month period and the earliest date from which the base ROE could be adjusted and refunds required is the date of the complaint.

On August 21, 2014, FERC issued an order in the proceeding, which established hearing and settlement judge procedures for the complaint, and set a refund effective date of February 27, 2013.

On February 23, 2016, FERC approved the settlement filed by the parties on November 6, 2015, covering the ROE issues raised in the complaints. The settlement provides for a 10% base ROE, effective March 8, 2016, which will be augmented by the PJM incentive adder of 50 basis points, and refunds to customers of BGE, Pepco, DPL and ACE of $13.7 million, $14.2 million, $11.9 million and $9.5 million, respectively. The settlement also prohibits any settling party from filing to change the base ROE or any incentives prior to June 1, 2018. The date for filing a request for rehearing has expired without any such requests having been filed. Accordingly, the order is not eligible for appeal and the matter is considered closed.

Operating License Renewals (Exelon and Generation). On August 29, 2012, Generation submitted a hydroelectric license application to FERC for a 46-year license for the Conowingo Hydroelectric Project (Conowingo).

Generation is working with stakeholders to resolve water quality licensing issues with the MDE for Conowingo, including: (1) water quality, (2) fish habitat, and (3) sediment. On January 30, 2014, Generation filed a water quality certification application pursuant to Section 401 of the CWA with MDE for Conowingo, addressing these and other issues. MDE indicated that it believed it did not have sufficient information to process Generation's application. As a result, Generation entered into an agreement with MDE to work with state agencies in Maryland, the U.S. Army Corps of Engineers, the U.S. Geological Survey, the University of Maryland Center for Environmental Science and the U.S. Environmental Protection Agency Chesapeake Bay Program to design, conduct and fund an additional multi-year sediment study. Generation has agreed to contribute up to $3.5 million to fund the additional study. In addition, because of the ongoing sediment and nutrient monitoring study, and because states must act upon water quality certification applications within a year of submission, Exelon agreed with Maryland to coordinate the withdrawal and refiling of the application in accordance with FERC policy that requires an applicant to resubmit its request for a water quality certification within 90 days of the date of withdrawal

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 DOI's preliminary prescription. On April 21, 2016, Exelon and Interior executed a Settlement Agreement resolving all issues between Exelon and Interior relating to fish passage at Conowingo. 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 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 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.

The FERC license for Conowingo expired on September 1, 2014. Under the Federal Power Act, FERC is required to issue an annual license for a facility until the new license is issued. On September 10, 2014, FERC issued an annual license for Conowingo, effective as of the expiration of the previous license. If FERC does not issue a new license prior to the expiration of an annual license, the annual license will renew automatically. On March 11, 2015, FERC issued the final Environmental Impact Statement for Conowingo. The stations are currently being depreciated over their estimated useful lives, which includes the license renewal period. As of March 31, 2016, $25 million of direct costs associated with the Conowingo licensing effort have been capitalized.

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 $2.5 billion regulatory asset reflecting adjustments recorded as a result of the acquisition method of accounting.

The following tables provide information about the regulatory assets and liabilities of Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE as of March 31, 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
March 31, 2016	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Regulatory assets
Pension and other postretirement benefits ^(a)	$	4,261	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Deferred income taxes	1,861		65		1,499		80		217		139		35		43
AMI programs ^(r)	687		149		60		212		266		181		85		—
Under-recovered distribution service costs ^(b)	198		198		—		—		—		—		—		—
Debt costs ^(c)	132		45		1		8		86		19		9		7
Fair value of long-term debt ^(d)	896		—		—		—		741		—		—		—
Fair value of PHI's unamortized energy contracts ^(e)	1,535		—		—		—		1,535		—		—		—
Severance	8		—		—		8		—		—		—		—
Asset retirement obligations	113		71		22		19		1		1		—		—
MGP remediation costs	276		246		29		1		—		—		—		—
Under-recovered uncollectible accounts	60		60		—		—		—		—		—		—
Renewable energy	265		265		—		—		—		—		—		—
Energy and transmission programs ^{(f)(g)(m)(n)(o)}	118		56		—		38		24		5		6		13
Deferred storm costs	47		—		—		2		45		19		6		20
Electric generation-related regulatory asset	18		—		—		18		—		—		—		—
Rate stabilization deferral	77		—		—		67		10		9		1		—
Energy efficiency and demand response programs	651		—		1		264		386		277		108		1
Merger integration costs	5		—		—		5		—		—		—		—
Conservation voltage reduction	3		—		—		3		—		—		—		—
Under-recovered revenue decoupling ^(h)	36		—		—		36		—		—		—		—
COPCO acquisition adjustment	12		—		—		—		12		—		12		—
Recoverable workers compensation and long-term disability	31		—		—		—		31		31		—		—
Vacation accrual	43		—		17		—		26		—		15		11
Securitized stranded costs	185		—		—		—		185		—		—		185
CAP arrearage	8		—		8		—		—		—		—		—
Removal costs	397		—		—		—		397		103		73		222
AEC ⁽ⁱ⁾	7		—		—		—		7		—		—		—
Other	61		9		10		4		34		12		12		12
Total regulatory assets	11,991		1,164		1,647		765		4,003		796		362		514
Less: current portion	1,584		239		42		266		801		133		67		95
Total non-current regulatory assets	$	10,407	$	925	$	1,605	$	499	$	3,202	$	663	$	295	$	419



									Successor
March 31, 2016	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE

Regulatory liabilities
Other postretirement benefits	$	93	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Nuclear decommissioning	2,599		2,182		417		—		—		—		—		—
Removal costs	1,669		1,334		—		187		148		21		127		—
Deferred rent ^(j)	42								42		—		—		—
Energy efficiency and demand response programs	122		78		43		—		1		—		—		1
DLC program costs	9		—		9		—		—		—		—		—
Electric distribution tax repairs	89		—		89		—		—		—		—		—
Gas distribution tax repairs	25		—		25		—		—		—		—		—
Energy and transmission programs ^{(f)(g)(k)(l)(p)(q)}	187		43		69		15		60		25		25		10
Other	55		2		3		10		41		9		14		16
Total regulatory liabilities	4,890		3,639		655		212		292		55		166		27
Less: current portion	512		150		134		61		106		26		57		22
Total non-current regulatory liabilities	$	4,378	$	3,489	$	521	$	151	$	186	$	29	$	109	$	5



									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	1,616		64		1,473		79		214		137		36		41
AMI programs ^(r)	399		140		63		196		267		180		87		—
Under-recovered distribution service costs ^(b)	189		189		—		—		—
Debt costs	47		46		1		8		36		19		10		7
Fair value of long-term debt ^(d)	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		—		—		—		—		—		—
Energy and transmission programs ^{(f)(g)(k)(m)(n)(o)}	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		14		10		4		—
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 ^(h)	30		—		—		30		—		—		—		—
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		38		14		10		13
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 ^{(f)(g)(k)(l)(p)(q)}	131		53		60		18		27		16		19		8
Over-recovered revenue decoupling^(h)	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 March 31, 2016, the pension and other postretirement benefits regulatory asset at Exelon includes regulatory assets of $1,125 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 March 31, 2016, ComEd’s regulatory asset of $198 million was comprised of $156 million for the 2014 - 2016 annual reconciliations and $42 million related to significant one-time events including $31 million of deferred storm costs, $9 million of Constellation merger and integration related costs and $2 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.


(c)	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.


(d)	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.


(e)	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 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.

(f)

As of March 31, 2016, ComEd’s regulatory asset of $56 million included $18 million related to under-recovered energy costs, $31 million associated with transmission costs recoverable through its FERC approved formulate rate, and $7 million of Constellation merger and integration costs to be recovered upon FERC approval. As of March 31, 2016, ComEd’s regulatory liability of $43 million included $17 million related to over-recovered energy costs and $26 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 formulate 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.

(g)

As of March 31, 2016, BGE's regulatory asset of $38 million included $5 million of costs associated with transmission costs recoverable through its FERC approved formula rate and $33 million related to under-recovered electric energy costs. As of March 31, 2016, BGE's regulatory liability of $15 million related to $2 million of over-recovered transmission costs and $14 million of over-recovered natural gas costs, offset by $1 million of abandonment costs to be recovered upon FERC approval. 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.

(h)

Represents the electric and gas distribution costs recoverable from customers under BGE’s decoupling mechanism. As of March 31, 2016, BGE had a regulatory asset of $31 million related to under-recovered electric revenue decoupling and a regulatory asset of $5 million related to under-recovered natural gas 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.


(i)	Represents the regulatory asset recorded at Exelon and PHI for the difference between the carrying value and fair value of alternative energy credits at Pepco, DPL and ACE recorded at Exelon and PHI that are recoverable through the rate making process.


(j)	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 which was eliminated at PHI as part of acquisition accounting.

(k)

As of March 31, 2016, PECO's regulatory liability of $69 million included $36 million related to the DSP program, $26 million related to the over-recovered natural gas costs under the PGC, $3 million related to over-recovered electric transmission costs and $4 million related to over-recovered non-bypassable transmission service charges. 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 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.

(l)

As of March 31, 2016, DPL's regulatory liability of $25 million included $6 million related to over-recovered natural gas costs under the GCR mechanism, $7 million of over-recovered electric energy costs, and $12 million of over-recovered transmission 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.

(m)

As of March 31, 2016, Pepco's regulatory asset of $5 million included $4 million of transmission costs recoverable through its FERC approved formula rate and $1 million of under-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.


(n)	As of March 31, 2016, DPL's regulatory asset of $6 million related to transmission costs recoverable through its FERC approved formula rate. 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.

(o)

As of March 31, 2016, ACE's regulatory asset of $13 million included $1 million of transmission costs recoverable through its FERC approved formula rate and $12 million of under-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.


(p)	As of March 31, 2016, Pepco's regulatory liability of $25 million included $15 million of over-recovered transmission costs and $10 million of over-recovered electric energy 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.


(q)	As of March 31, 2016, ACE's regulatory liability of $10 million related to over-recovered transmission costs. As of December 31, 2015, ACE's regulatory liability of $8 million related to over-recovered transmission costs.


(r)	Represents AMI costs associated with the installation of smart meters and the early retirement of legacy meters throughout Pepco’s and DPL’s service territories that are recoverable from customers. AMI has not been approved by the NJBPU for ACE in New Jersey. PHI generally is deferring carrying charges on these regulatory assets.

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 and ACE are required to purchase receivables at face value and are permitted to recover uncollectible accounts expense from customers through distribution rates. 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 March 31, 2016 and December 31, 2015.



													Successor
As of March 31, 2016	Exelon			ComEd			PECO			BGE			PHI			Pepco			DPL		ACE
Purchased receivables^(c)	$	343		$	96		$	75		$	66		$	106		$	77		$	11	$	18
Allowance for uncollectible accounts^(a)	(38		)	(16		)	(8		)	(8		)	(6		)	(4		)	—		(2		)
Purchased receivables, net	$	305		$	80		$	67		$	58		$	100		$	73		$	11	$	16



													Predecessor
As of December 31, 2015	Exelon			ComEd			PECO			BGE			PHI			Pepco			DPL		ACE
Purchased receivables^(b)	$	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

_______


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