Regulatory Matters

12 Months Ended

Dec. 31, 2015

Regulatory Matters

(7) REGULATORY MATTERS

Regulatory Assets and Regulatory Liabilities

The components of Pepco Holdings’ regulatory asset and liability balances at December 31, 2015 and 2014 are as follows:

	2015		2014
	(millions of dollars)
Regulatory Assets
Pension and other postretirement benefit costs	$	910	$	946
Demand-side management costs		403		329
Smart Grid costs		266		261
Recoverable income taxes		224		274
Securitized stranded costs		202		278
Incremental storm restoration costs		43		51
Deferred debt extinguishment costs		36		42
Deferred energy supply costs		32		73
Recoverable workers’ compensation and long-term disability costs		31		30
MAPP abandonment costs		7		33
Deferred losses on gas derivatives		2		4
Other		90		88
Total Regulatory Assets	$	2,246	$	2,409
Regulatory Liabilities
Asset removal costs	$	211	$	250
Reserves for FERC ROE transmission challenges		32		4
Federal and state tax benefits, related to securitized stranded costs		13		8
Deferred income taxes due to customers		12		44
Deferred energy supply costs		11		3
Other		29		34
Total Regulatory Liabilities	$	308	$	343

A description for each category of regulatory assets and regulatory liabilities follows:

Pension and OPEB Costs: Represents unrecognized net actuarial losses and prior service cost (credit) for Pepco Holdings’ defined benefit pension and other postretirement benefit (OPEB) plans that are expected to be recovered by Pepco, DPL and ACE in rates. The utilities have historically included these items as a part of its cost of service in its customer rates. This regulatory asset is adjusted at least annually when the funded status of Pepco Holdings’ defined benefit pension and OPEB plans are re-measured. See Note (9), “Pension and Other Postretirement Benefits,” for more information about the components of the unrecognized pension and OPEB costs. PHI does not earn a return on these regulatory assets.

Demand-Side Management Costs: Represents recoverable costs associated with customer direct load control and energy efficiency and conservation programs in all jurisdictions that are being recovered from customers. These programs are designed to reduce customers’ energy consumption. PHI earns a return on these regulatory assets.

Smart Grid Costs: 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.

Recoverable Income Taxes: Represents amounts recoverable from Power Delivery’s customers for tax benefits applicable to utility operations of Pepco, DPL and ACE previously recognized in income tax expense before the companies were ordered to record the tax benefits as deferred income taxes. As the temporary differences between the financial statement basis and tax basis of assets reverse, the deferred recoverable balances are reversed.

Securitized Stranded Costs: Certain contract termination payments under a contract between ACE and an unaffiliated non-utility generator (NUG) and costs associated with the regulated operations of ACE’s electricity generation business are no longer recoverable through customer rates (collectively referred to as “stranded costs”). The stranded costs are amortized over the life of Transition Bonds issued by Atlantic City Electric Transition Funding LLC (ACE Funding) (Transition Bonds) to securitize the recoverability of these stranded costs. These bonds mature between 2016 and 2023. A customer surcharge is collected by ACE to fund principal and interest payments on the Transition Bonds. PHI earns a return on these regulatory assets.

Incremental Storm Restoration Costs: Represents total incremental storm restoration costs incurred for repair work due to major storm events in 2015, 2012 and 2011, including the June 2015 storm (for DPL and ACE), Hurricane Sandy, the June 2012 derecho, Hurricane Irene and the 2011 severe winter storm (for Pepco), that are recoverable from customers in the Maryland and New Jersey jurisdictions. Pepco’s and DPL’s costs related to Hurricane Sandy, the June 2012 derecho, Hurricane Irene and Pepco’s costs related to the 2011 severe winter storm are being amortized and recovered from customers, each over a five-year period. ACE’s costs related to Hurricane Sandy, the June 2012 derecho and Hurricane Irene are being amortized and recovered from customers, each over a three-year period. PHI does not earn a return on these regulatory assets.

Deferred Debt Extinguishment Costs: Represents deferred costs of debt extinguishment of Pepco, DPL and ACE that are amortized to interest expense and recovered from customers. PHI generally earns a return on these regulatory assets.

Deferred Energy Supply Costs: The regulatory asset represents primarily deferred costs associated with a net under-recovery of Default Electricity Supply costs incurred by Pepco, DPL and ACE that are being or are expected to be recovered from customers. PHI generally earns a return on these regulatory assets. The regulatory liability represents primarily deferred costs associated with a net over-recovery of Default Electricity Supply costs incurred that will be refunded by Pepco, DPL and ACE to customers.

Recoverable Workers’ Compensation and Long-Term Disability Costs: Represents accrued workers’ compensation and long-term disability costs for Pepco, which are recoverable from customers when actual claims are paid to employees. PHI does not earn a return on these regulatory assets.

MAPP Abandonment Costs: Represents abandonment costs incurred in connection with the Mid-Atlantic Power Pathway (MAPP) transmission line construction project which was terminated by PJM Interconnection, LLC (PJM) on August 24, 2012. These regulatory assets are being amortized and recovered in transmission rates through May 2016. PHI generally does not earn a return on these regulatory assets.

Deferred Losses on Gas Derivatives: Represents losses associated with hedges of natural gas purchases that are recoverable from customers through the Gas Cost Rate (GCR) approved by the DPSC. PHI does not earn a return on these regulatory assets.

Other: Represents miscellaneous regulatory assets that generally are being amortized over 1 to 20 years.

Asset Removal Costs: The depreciation rates for Pepco and DPL include a component for removal costs, as approved by the relevant federal and state regulatory commissions. Accordingly, Pepco and DPL have recorded regulatory liabilities for their estimate of the difference between incurred removal costs and the amount of removal costs recovered through depreciation rates.

Reserves for FERC ROE Transmission Challenges: Represents reserves established under a settlement agreement filed with FERC for the resolution of certain challenges filed by a group of complainants of the base return on equity (ROE) currently authorized by FERC for the transmission service that PHI’s utilities provide.

Federal and State Tax Benefits, Related to Securitized Stranded Costs: Securitized stranded costs include a portion attributable to the future tax benefit expected to be realized when the higher tax basis of the generating facilities divested by ACE is deducted for New Jersey state income tax purposes, as well as the future benefit to be realized through the reversal of federal excess deferred taxes. To account for the possibility that these tax benefits may be given to ACE’s customers through lower rates in the future, ACE established a regulatory liability. The regulatory liability related to federal excess deferred taxes will remain until such time as the Internal Revenue Service (IRS) issues its final regulations with respect to normalization of these federal excess deferred taxes.

Deferred Income Taxes Due to Customers: Represents the portions of deferred income tax assets applicable to utility operations of Pepco and DPL that have not been reflected in current customer rates for which future payment to customers is probable. As the temporary differences between the financial statement basis and tax basis of assets reverse, deferred recoverable income taxes are amortized.

Other: Represents miscellaneous regulatory liabilities.

Rate Proceedings

As further described in Note (1), “Organization,” on April 29, 2014, PHI entered into the Merger Agreement with Exelon and Merger Sub. Subject to certain exceptions, prior to the Merger or the termination of the Merger Agreement, PHI and its subsidiaries may not, without the consent of Exelon, initiate, file or pursue any rate cases, other than pursuing the conclusion of certain proceedings, as described below. To date, PHI has not requested such consent from Exelon and has not filed any new distribution base rate cases since entering into the Merger Agreement.

Bill Stabilization Adjustment

Each of PHI’s utility subsidiaries proposed in each of its respective jurisdictions the adoption of a mechanism to decouple retail distribution revenue from the amount of power delivered to retail customers. A decoupling mechanism, the BSA, was approved and implemented for Pepco and DPL electric service in Maryland and for Pepco electric service in the District of Columbia. None of the other jurisdictions have to date adopted decoupling proposals.

Delaware

Electric Distribution Base Rates

In March 2013, DPL submitted an application with the DPSC to increase its electric distribution base rates. The application sought approval of an annual rate increase of approximately $42 million (adjusted by DPL to approximately $39 million on September 20, 2013), based on a requested ROE of 10.25%. The requested rate increase sought to recover expenses associated with DPL’s ongoing investments in reliability enhancement improvements and efforts to maintain safe and reliable service. In August 2014, the DPSC issued a final order in this proceeding providing for an annual increase in DPL’s electric distribution base rates of approximately $15.1 million, based on an ROE of 9.70%. The new 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 described below in “Merger Approval Proceedings – Delaware,” the parties agreed to suspend the appeal and, if the Merger is completed, to the withdrawal of the appeal and the cross-appeal with prejudice.

Forward Looking Rate Plan

In October 2013, DPL filed a multi-year rate plan, referred to as the Forward Looking Rate Plan (FLRP). As proposed, the FLRP would provide for annual electric distribution base rate increases over a four-year period in the aggregate amount of approximately $56 million. The FLRP as proposed provides the opportunity to achieve estimated earned ROEs of 7.41% and 8.80% in years one and two, respectively, and 9.75% in both years three and four of the plan.

In addition, DPL proposed that as part of the FLRP, in order to provide a higher minimum required standard of reliability for DPL’s customers than that to which DPL is currently subject, the standards by which DPL’s reliability is measured would be made more stringent in each year of the FLRP. DPL has also offered to refund an aggregate of $500,000 to customers in each year of the FLRP that it fails to meet the proposed stricter minimum reliability standards.

In October 2013, the DPSC opened a docket for the purpose of reviewing the details of the FLRP, but stated that it would not address the FLRP until the electric distribution base rate case discussed above was concluded. Although the rate case has been concluded, a schedule for the FLRP docket has not yet been established.

Under the Merger Agreement, DPL is permitted to pursue this matter; however, under the settlement agreement related to the Merger described below in “Merger Approval Proceedings – Delaware,” DPL agreed to withdraw the FLRP if the Merger is completed, without prejudice to the right to make future filings with the DPSC proposing alternative regulatory methodologies that could include, but are not limited to, a multi-year rate plan.

Gas Cost Rates

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.

Under the Merger Agreement, DPL is permitted to continue to file its required annual GCR cases in Delaware.

Maryland

Pepco Electric Distribution Base Rates

2011 Base Rate Proceeding

In December 2011, Pepco submitted an application with the MPSC to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $68.4 million (subsequently adjusted by Pepco to approximately $66.2 million), based on a requested ROE of 10.75%. In July 2012, the MPSC issued an order approving an annual rate increase of approximately $18.1 million, based on an ROE of 9.31%. Among other things, the order also authorized Pepco to recover the actual cost of AMI meters installed during the 2011 test year, stating that cost recovery for AMI deployment will be allowed in future rate cases in which Pepco demonstrates that the system is cost effective. The new rates became effective on July 20, 2012. The Maryland Office of People’s Counsel has sought rehearing on the portion of the order allowing Pepco to recover the costs of AMI meters installed during the test year; that motion remains pending.

2012 Base Rate Proceeding – Phase I

In November 2012, Pepco submitted an application with the MPSC to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $60.8 million, based on a requested ROE of 10.25%. In July 2013, the MPSC issued an order in this proceeding approving an annual rate increase of approximately $27.9 million, based on an ROE of 9.36%. The order excludes the cost of AMI meters from Pepco’s rate base until such time as Pepco demonstrates the cost effectiveness of the AMI system; as a result, costs for AMI meters incurred with respect to the 2012 test year and beyond will be treated as other incremental AMI costs incurred in conjunction with the deployment of the AMI system that are deferred and on which a carrying charge is deferred, but only until such cost effectiveness has been demonstrated and such costs are included in rates. However, MPSC’s July 2012 order issued in connection with Pepco’s 2011 base rate proceeding, which allowed Pepco to recover the costs of meters installed during the 2011 test year for that case, remains in effect.

The July 2013 order also approved a Grid Resiliency Charge, which went into effect on January 1, 2014, for recovery of costs totaling approximately $24.0 million associated with Pepco’s proposed plan to accelerate investments related to certain priority feeders, provided that, before implementing the surcharge, Pepco (i) provides additional information to the MPSC related to performance objectives, milestones and costs, and (ii) makes annual filings with the MPSC thereafter concerning this project, which will permit the MPSC to establish the applicable Grid Resiliency Charge rider for each following year. These conditions have been met. The MPSC rejected certain other cost recovery mechanisms, including Pepco’s proposed reliability performance-based mechanism. The new rates were effective on July 12, 2013.

In July 2013, Pepco filed a notice of appeal of the July 2013 order in the Circuit Court for Baltimore City. Other parties also filed notices of appeal, which were consolidated with Pepco’s appeal. In its appeal, Pepco asserted that the MPSC erred in failing to grant Pepco an adequate ROE, denying a number of other cost recovery mechanisms and limiting Pepco’s test year data to no more than four months of forecasted data in future rate cases. The other parties primarily asserted that the MPSC erred or acted arbitrarily and capriciously in allowing the recovery of certain costs by Pepco, in approving the Grid Resiliency Charge, and in refusing to reduce Pepco’s rate base by known and measurable accumulated depreciation. In November 2014, the Circuit Court issued an order reversing the MPSC’s decision on Pepco’s ROE and directing the MPSC to make more specific findings regarding the impact of improved service reliability and the BSA in calculating Pepco’s ROE. On all other issues that were the subject of an appeal, the Circuit Court affirmed the MPSC’s July 2013 order.

Other parties to this proceeding filed notices of appeal of the Circuit Court’s decision to the Maryland Court of Special Appeals. On December 15, 2015, the Court of Special Appeals issued its decision in this matter (i) affirming the Circuit Court’s decision upholding the MPSC’s decision to approve the use of the Grid Resiliency Charge for Pepco, and (ii) reversing the Circuit Court on the ROE issue, finding that the MPSC’s original ROE of 9.36% was within the zone of reasonableness. Because none of the parties to the proceeding, including Pepco, appealed this Court of Special Appeals decision, the MPSC decision is now final.

2013 Base Rate Proceeding – Phase I

In December 2013, Pepco submitted an application with the MPSC to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $43.3 million (adjusted by Pepco to approximately $37.4 million on April 15, 2014), based on a requested ROE of 10.25%. The requested rate increase sought to recover expenses associated with Pepco’s ongoing investments in reliability enhancement improvements and efforts to maintain safe and reliable service. In July 2014, the MPSC issued an order approving an annual rate increase of approximately $8.75 million, based on an ROE of 9.62%. The new rates became effective on July 4, 2014. In July 2014, Pepco filed a petition for rehearing seeking reconsideration of the recovery of certain expenses, which the MPSC denied by its order issued in November 2014 (described below). In December 2014, Pepco filed a petition for judicial review of this MPSC order with the Circuit Court for Baltimore City. On August 7, 2015, the Circuit Court for Baltimore City affirmed the MPSC’s decision and denied Pepco’s appeal. Pepco has elected not to appeal the decision of the Circuit Court.

2012 and 2013 Base Rate Proceedings – Phase II

In August 2014, the MPSC issued an order establishing a Phase II proceeding in the 2012 base rate case described above (the 2012 Phase II proceeding) to address the tax implications of Pepco’s net operating loss carryforward (NOLC), which had impacted certain of Pepco’s rate adjustments in the 2012 base rate proceeding. Pepco filed a motion to dismiss the 2012 Phase II proceeding, asserting that the MPSC no longer has jurisdiction over the 2012 base rate case due to appeals having been filed by numerous parties. In September 2014, the MPSC issued an order staying the 2012 Phase II proceeding until further notice. In a similar Phase II proceeding in the 2013 base rate case described above, the MPSC issued an order in November 2014 upholding Pepco’s treatment of the NOLC. Although Pepco believes the November 2014 MPSC order should be dispositive of the issues raised in the 2012 Phase II proceeding, the 2012 Phase II proceeding has remained open pending the resolution of all appeals of the 2012 base rate proceeding. Now that the MPSC decision in that proceeding is final, the MPSC will have authority to act on Phase II.

New Jersey

Update and Reconciliation of Certain Under-Recovered Balances

In March 2015, ACE submitted its 2015 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 for ACE’s uncollected accounts. As filed, the net impact of the proposed changes would have been an annual rate increase of approximately $52.0 million (revised to an increase of approximately $33.9 million on April 17, 2015, based upon updates for actual data through March 31, 2015). On May 19, 2015, the NJBPU approved a stipulation of settlement entered into by the parties providing for a provisional overall annual rate increase of $33.9 million effective June 1, 2015. On September 11, 2015, the NJBPU approved a stipulation of settlement in this proceeding, which made final the provisional rates that were placed into effect as of June 1, 2015, with an adjustment that decreased the rate applicable to the residential class by $1.3 million. This rate increase of approximately $32.6 million will have no effect on ACE’s operating income, since these revenues provide for recovery of deferred costs under an approved deferral mechanism.

On February 1, 2016, ACE submitted its 2016 annual petition with the NJBPU seeking to reconcile and update the same categories of charges and costs described in (i) and (ii) in the above paragraph. The net impact of adjusting the charges as proposed is an overall annual rate increase of approximately $8.8 million, including New Jersey Sales and Use Tax. The matter is pending at the NJBPU and will be updated for January through March 2016 actual data. ACE has requested that the NJBPU place the new rates into effect by June 1, 2016.

Service Extension Contributions Refund Order

In July 2013, in compliance with a 2012 Superior Court of New Jersey Appellate Division (Appellate Division) court decision, the NJBPU released an order requiring utilities to issue refunds to persons or entities that paid non-refundable contributions for utility service extensions to certain areas described as “Areas Not Designated for Growth.” The order is limited to eligible contributions paid between March 20, 2005 and December 20, 2009. ACE is processing the refund requests that meet the eligibility criteria established in the order as they are received. Although ACE estimates that it received approximately $11 million of contributions between March 20, 2005 and December 20, 2009, it is currently unable to reasonably estimate the amount that it may be required to refund using the eligibility criteria established by the order. Since the July 2013 order was released, ACE has paid less than $1 million in refund claims, the validity of each of which is investigated by ACE prior to making any such refunds. In September 2014, the NJBPU commenced a rulemaking proceeding to further implement the directives of the Appellate Division decision. In November 2015, the NJBPU adopted new regulations that remove provisions distinguishing between growth areas and not-for-growth areas and provide formulae for allocating extension costs. At this time, ACE does not expect the amount it is ultimately required to refund will have a material effect on its consolidated financial condition, results of operations or cash flows, as the amount refunded will generally increase the value of ACE’s property, plant and equipment and may ultimately be recovered through depreciation expense and cost of service in future electric distribution base rate cases.

Generic Consolidated Tax Adjustment Proceeding

In January 2013, the NJBPU initiated a generic proceeding to examine whether a consolidated tax adjustment (CTA) should continue to be used, and if so, how it should be calculated in determining a utility’s cost of service. Under the NJBPU’s current policy, when a New Jersey utility is included in a consolidated group income tax return, an allocated amount of any reduction in the consolidated group’s taxes as a result of losses by affiliates is used to reduce the utility’s rate base, upon which the utility earns a return. This policy has negatively impacted ACE’s electric distribution base rate case outcomes and ACE’s position is that the CTA should be eliminated. In an order issued in October 2014, the NJBPU determined that it is appropriate for affected consolidated groups to continue to include a CTA in New Jersey base rate filings, but that the CTA calculation will be modified to limit the look-back period for the calculation to five years, exclude transmission assets from the calculation, and allocate 25 percent of the final CTA amount as a reduction to the distribution revenue requirement. ACE anticipates that this revised methodology will significantly reduce the negative effects of the CTA in future base rate cases. In November 2014, the New Jersey Division of Rate Counsel filed an appeal of the NJBPU’s CTA order in the Appellate Division. No stay of the October 2014 CTA order was requested in connection with the appeal. As such, barring an adverse finding by the Appellate Division, the order is in effect. The appeal remains pending.

FERC Transmission ROE Challenges

In February 2013, the public service commissions and public advocates of the District of Columbia, Maryland, Delaware and New Jersey, as well as the Delaware Municipal Electric Corporation, Inc., filed a joint complaint at FERC against Pepco, DPL and ACE, as well as Baltimore Gas and Electric Company (BGE). The complainants challenged the base ROE and certain protocols regarding the formula rate process associated with the transmission service that the utilities provide. The complainants support an ROE within a zone of reasonableness of 6.78% and 10.33%, and have argued for a base ROE of 8.7%. The base ROE currently authorized by FERC for PHI’s utilities is (i) 11.3% for facilities placed into service after January 1, 2006, and (ii) 10.8% for facilities placed into service prior to 2006. The 10.8% base ROE for facilities placed into service prior to 2006 receives a 50-basis-point incentive adder for being a member of a regional transmission organization. In August 2014, FERC issued an order setting the matters in this proceeding for hearing, but holding the hearing in abeyance pending settlement discussions. The order also (i) directed that the evidence and analysis presented concerning ROE be guided by the new ROE methodology adopted by FERC in another proceeding (discussed below), and (ii) set a 15-month refund period that commenced on February 27, 2013, should a refund result from this proceeding. After settlement discussions among the parties in this matter reached an impasse, the settlement judge, in November 2014, issued an order terminating the settlement discussions and referring the matter to a presiding administrative law judge.

In June 2014, FERC issued an order in a proceeding in which the PHI utilities were not involved, in which it adopted a new ROE methodology for electric utilities. This new methodology replaces the existing one-step discounted cash flow analysis (which incorporates only short-term growth rates) traditionally used to derive ROE for electric utilities with the two-step discounted cash flow analysis (which incorporates both short-term and long-term measures of growth) used for natural gas and oil pipelines. As a result of the August 2014 FERC order discussed in the preceding paragraph, Pepco, DPL and ACE applied an estimated ROE based on the two-step methodology announced by FERC for the 15-month period over which each of their transmission revenues would be subject to refund as a result of the challenge, and recorded estimated reserves for the entire 15-month refund period in the second quarter of 2014.

On December 8, 2014, the parties that filed the February 2013 complaint filed a second complaint against Pepco, DPL, ACE, as well as BGE, regarding the base transmission ROE, seeking a reduction from 10.8% to 8.8%. By order issued on February 9, 2015, FERC established a hearing on the second complaint and established a second 15-month refund period that commenced on December 8, 2014. Consistent with the prior challenge, Pepco, DPL and ACE applied an estimated ROE based on the two-step methodology described above, and in the fourth quarter of 2014 and in the first, second and third quarters of 2015 established reserves for the estimated refund based on the effective date of the second refund period of December 8, 2014. On February 20, 2015, the chief judge issued an order consolidating the two complaint proceedings and established an initial decision issuance deadline of February 29, 2016. On March 2, 2015, the presiding administrative law judge issued an order establishing a procedural schedule for the consolidated proceedings that provided for the hearing to commence on October 20, 2015.

Also during the third quarter of 2015, PHI further evaluated the reserves established for each of the two refund periods and, based on an updated assessment of market conditions, developments in other cases before FERC, litigation risk and other factors, increased its reserves to reflect management’s best estimate of the refund that is expected to result from these consolidated proceedings. A settlement entered into by the parties regarding the protocols (but not the ROE) raised in the February 2013 complaint was submitted to FERC on July 31, 2015 and was approved by FERC in November 2015.

On November 6, 2015, the parties filed a settlement agreement with FERC regarding the ROE. This settlement agreement provides for (i) a base ROE of 10.0%, effective March 8, 2016, to which a 50-basis-point incentive adder will be applied for being a member of a regional transmission organization, and (ii) customer refunds in the amount of approximately $9.5 million, $11.9 million, and $14.2 million for ACE, DPL and Pepco, respectively, covering the two 15-month refund periods described above. In addition, under this settlement agreement, no party may file to change the base ROE or any incentives prior to June 1, 2018. The parties have requested that FERC approve this settlement agreement by March 16, 2016, in order to incorporate the new ROE and applicable refunds into each utility’s 2016 transmission formula rate update. As of December 31, 2015, PHI’s reserves for both of the refund periods totaled $32 million as required under the settlement agreement.

MPSC New Generation Contract Requirement

In April 2012, the MPSC issued an order that requires Maryland electric distribution companies (EDCs) Pepco, DPL and BGE (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 megawatts (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 originally expected commercial operation date of June 1, 2015 (which is now deferred pending the outcome of the proceedings discussed below), 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, in September 2013, the U.S. District Court for the District of Maryland (the Federal District Court) issued a ruling that the MPSC’s April 2012 order violated the Supremacy Clause of the U.S. Constitution by attempting to regulate wholesale prices. In contrast, in October 2013, in response to appeals filed by the Contract EDCs and other parties, the Maryland Circuit Court for Baltimore City (the Maryland Circuit Court) upheld the MPSC’s orders requiring the Contract EDCs to enter into the contracts.

In October 2013, the Federal District Court issued an order ruling that the contracts are illegal and unenforceable. The Contract EDCs, the Maryland Office of People’s Counsel and one generating company have appealed the Maryland Circuit Court’s decision to the Maryland Court of Special Appeals. In addition, in November 2013 both the winning bidder and the MPSC appealed the Federal District Court decision to the U.S. Court of Appeals for the Fourth Circuit, which affirmed the decision. In November 2014, the winning bidder and the MPSC each petitioned the U.S. Supreme Court to consider hearing an appeal of the Fourth Circuit decision and, on October 19, 2015, the U.S. Supreme Court agreed to review that decision.

Assuming the contracts, as currently written, become effective following the satisfaction of all relevant conditions, including the completion of the proceedings discussed above, PHI continues to believe that Pepco and DPL may be required to record their proportional share of the contracts as derivative instruments at fair value and record related regulatory assets of approximately the same amount because Pepco and DPL would be entitled to recover any payments under the contracts from SOS customers. PHI, Pepco and DPL have concluded that any accounting for these contracts would not be required until all legal proceedings related to these contracts and the actions of the MPSC in the related proceeding have been resolved.

ACE Standard Offer Capacity Agreements

In April 2011, ACE entered into three Standard Offer Capacity Agreements (SOCAs) by order of the NJBPU, each with a different generation company. ACE entered into the SOCAs under protest, as did the other EDCs in New Jersey, 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). In October 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 ruled that the NJ SOCA Law is preempted by the Federal Power Act (FPA) and violates the Supremacy Clause, and is therefore null and void. In October 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 in September 2014. In November 2014 and December 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. Although the U.S. Supreme Court agreed to review the Fourth Circuit decision discussed above under “MPSC New Generation Contract Requirement,” it has not yet agreed to review the Third Circuit decision and the petitions for such review remain pending.

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.

In response to the October 2013 Federal district court order, ACE, in the fourth quarter of 2013, derecognized both the derivative assets (liabilities) for the estimated fair value of the SOCAs and the related regulatory liabilities (assets) that it had established with respect to the SOCAs.

District of Columbia Power Line Undergrounding Initiative

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 provides enabling legislation for the District of Columbia Power Line Undergrounding (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 collect on behalf of and 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 and recovery of Pepco’s investment through a volumetric surcharge (the Triennial Plan), all in accordance with the Improvement Financing Act. In August 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 of Columbia to recover the costs associated with the bond issuance (the DDOT surcharge).

In November 2014, the DCPSC issued an order approving the Triennial Plan, including 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 December 2014, a party to the proceeding sought reconsideration from the DCPSC of both decisions. Final decisions denying both requests for reconsideration were issued by the DCPSC on January 22, 2015 and February 2, 2015, respectively.

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. A determination whether the Court of Appeals will rehear the case is still pending.

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.

Merger Approval Proceedings

Delaware

On June 18, 2014, Exelon, PHI and DPL, and certain of their respective affiliates, filed an application with the DPSC seeking approval of the Merger. Delaware law requires the DPSC to approve the Merger when it determines that the transaction is in accordance with law, for a proper purpose, and is consistent with the public interest. The DPSC must further find that the successor will continue to provide safe and reliable service, will not terminate or impair existing collective bargaining agreements and will engage in good faith bargaining with organized labor. On February 13, 2015, Exelon, DPL, the DPSC staff, the Division of the Public Advocate and certain other parties filed a settlement agreement with the DPSC, which was amended in April 2015. The DPSC approved the amended settlement agreement at its meeting held on May 19, 2015, memorializing this decision by written order issued on June 2, 2015. The specific grounds for the DPSC’s approval of the Merger, as well as the specific conditions, will be included in an order to be issued by the DPSC after the Merger closes.

District of Columbia

On June 18, 2014, Exelon, PHI and Pepco, and certain of their respective affiliates, filed an application with the DCPSC seeking approval of the Merger. To approve the Merger, the DCPSC must find that the Merger is in the public interest. In an order issued August 22, 2014, the DCPSC stated that to make the determination of whether the transaction is in the public interest, it will analyze the transaction in the context of seven factors to determine whether the transaction balances the interests of shareholders and investors with ratepayers and the community, whether the benefits to shareholders do or do not come at the expense of the ratepayers, and whether the transaction produces a direct and tangible benefit to ratepayers. The seven factors identified by the DCPSC are the effects of the transaction on: (i) ratepayers, shareholders, the financial health of the utility standing alone and as merged, and the local economy; (ii) utility management and administrative operations; (iii) the public safety and the safety and reliability of services; (iv) risks associated with all of the affiliated non-jurisdictional business operations, including nuclear operations, of the applicants; (v) the DCPSC’s ability to regulate the utility effectively following the Merger; (vi) competition in the local retail and wholesale markets that impacts the District and District ratepayers; and (vii) conservation of natural resources and preservation of environmental quality. District of Columbia law does not impose any time limit on the DCPSC’s review of the Merger. The DCPSC held evidentiary hearings in March and April of 2015 and the record was closed on May 27, 2015.

On August 27, 2015, the DCPSC issued a written order denying the application seeking approval of the Merger. On September 28, 2015, Exelon, PHI and Pepco, and certain of their respective affiliates, filed an application for reconsideration before the DCPSC. Following the DCPSC’s decision on reconsideration, Exelon and Pepco Holdings have the option of filing further appeals with the DC Court of Appeals.

On October 6, 2015, Exelon, PHI and Pepco, and certain of their respective affiliates, entered into the DC Settlement Agreement with the District of Columbia Government, the Office of the People’s Counsel and other parties. Also on October 6, 2015, Exelon, PHI and Pepco, and certain of their respective affiliates filed with the DCPSC the Motion to Reopen requesting consideration of the DC Settlement Agreement and approval of the Merger on such terms and conditions set forth in the DC Settlement Agreement, without condition or modification, and to stay further proceedings on the application for reconsideration filed by the parties on September 28, 2015, and suspend the time period for reconsideration pending the DCPSC’s consideration of the DC Settlement Agreement.

On October 28, 2015, the DCPSC approved the Motion to Reopen and set a procedural schedule for its review of this matter. Upon completion of the public input and evidentiary hearings, the record was closed as of December 23, 2015. Although District of Columbia law does not impose any time limit on the DCPSC’s review of the Merger, the parties requested a decision by March 4, 2016.

Maryland

On August 19, 2014, Exelon, PHI, Pepco, DPL and certain of their respective affiliates, filed an application with the MPSC seeking approval of the Merger. Maryland law requires the MPSC to approve a merger subject to its review if it finds that the merger is consistent with the public interest, convenience and necessity, including its benefits to and impact on consumers. Evidentiary hearings were held beginning on January 26, 2015. On March 10, 2015, Exelon, PHI, Pepco, DPL and certain of their respective affiliates, filed with the MPSC a settlement agreement entered into with one of the stakeholder groups participating in the MPSC approval proceeding. On March 16, 2015, Exelon, PHI, Pepco, DPL and certain of their respective affiliates, filed with the MPSC a settlement agreement entered into with Montgomery and Prince George’s Counties in Maryland, and a number of other parties. On May 15, 2015, the MPSC approved the Merger, with conditions, including conditions that modify and supplement those originally proposed. On May 18, 2015, Pepco Holdings and Exelon announced that they had completed their review of the MPSC’s order approving the Merger and have committed to fulfill the modified, more stringent conditions and package of customer benefits imposed by the MPSC.

Multiple parties have filed petitions for judicial review of the MPSC order by the Circuit Court of Queen Anne’s County, Maryland, seeking to appeal the MPSC order. In connection with these proceedings, the Maryland Office of People’s Counsel and several other parties to the Merger proceedings filed motions in the Circuit Court for Queen Anne’s County, Maryland, requesting a stay of the MPSC order. On August 7, 2015, the Circuit Court for Queen Anne’s County denied the motions for stay. On January 8, 2016, the Circuit Court affirmed the MPSC’s order in all respects. On January 20 and 22, 2016, respectively, the Maryland Office of People’s Counsel and environmental groups filed notices of appeal of the Circuit Court’s order to the Maryland Court of Special Appeals. Unless a motion to stay is filed and then granted by the court, the MPSC order will remain in effect during the appeals process.

New Jersey

On June 18, 2014, Exelon, PHI and ACE, and certain of their respective affiliates, filed a petition with the NJBPU seeking approval of the Merger. To approve the Merger, the NJBPU must find the Merger is in the public interest, and consider the impact of the Merger on (i) competition, (ii) rates of ratepayers affected by the Merger, (iii) ACE’s employees, and (iv) the provision of safe and reliable service at just and reasonable rates. On January 14, 2015, PHI, ACE, Exelon, certain of Exelon’s affiliates, the Staff of the NJBPU, and the Independent Energy Producers of New Jersey filed a stipulation of settlement (the Stipulation) with the NJBPU in this proceeding. On February 11, 2015, the NJBPU approved the Stipulation and the Merger and on March 6, 2015, the NJBPU issued a written order approving the Stipulation.

The NJBPU order states that the Merger must be closed by November 1, 2015 unless extended by the NJBPU. On October 15, 2015, the NJBPU voted to extend the effectiveness of its Merger approval until June 30, 2016.

Virginia

On June 3, 2014, Exelon, PHI, Pepco and DPL, and certain of their respective affiliates, filed an application with the VSCC seeking approval of the Merger. Virginia law provides that, if the VSCC determines, with or without hearing, that adequate service to the public at just and reasonable rates will not be impaired or jeopardized by granting the application for approval, then the VSCC shall approve a merger with such conditions that the VSCC deems to be appropriate in order to satisfy this standard. On October 7, 2014,

the VSCC issued an order approving the Merger.

Federal Energy Regulatory Commission

On May 30, 2014, Exelon, PHI, Pepco, DPL and ACE, and certain of their respective affiliates, submitted to FERC a Joint Application for Authorization of Disposition of Jurisdictional Assets and Merger under Section 203 of the FPA. Under that section, FERC shall approve a merger if it finds that the proposed transaction will be consistent with the public interest. On November 20, 2014, FERC issued an order approving the Merger.

Hart-Scott-Rodino Act

The HSR Act, which is the U.S. federal pre-merger notification statute, and its related rules and regulations provide that acquisition transactions that meet the HSR Act’s coverage thresholds may not be completed until a Notification and Report Form has been furnished to the Department of Justice (DOJ) and the Federal Trade Commission (FTC), and that the waiting period required by the HSR Act has been terminated or has expired. Pursuant to the HSR Act requirements, Pepco Holdings and Exelon filed the required Notification and Report Forms with the DOJ and the FTC, and the waiting period under the HSR Act expired on December 2, 2015, which allows for the closing of the Merger at any time on or before December 1, 2016.

Potomac Electric Power Co [Member]

Regulatory Matters

(6) REGULATORY MATTERS

Regulatory Assets and Regulatory Liabilities

The components of Pepco’s regulatory asset and liability balances at December 31, 2015 and 2014 are as follows:

	2015		2014
	(millions of dollars)
Regulatory Assets
Demand-side management costs	$	292	$	238
Smart Grid costs		181		175
Recoverable income taxes		142		148
Recoverable workers’ compensation and long-term disability costs		31		30
Incremental storm restoration costs		19		29
Deferred debt extinguishment costs		19		22
MAPP abandonment costs		4		19
Deferred energy supply costs		3		3
Other		29		33
Total Regulatory Assets	$	720	$	697
Regulatory Liabilities
Asset removal costs	$	58	$	84
Reserves for FERC ROE transmission challenges		13		2
Deferred income taxes due to customers		6		4
Deferred energy supply costs		5		3
Other		10		11
Total Regulatory Liabilities	$	92	$	104

A description for each category of regulatory assets and regulatory liabilities follows:

Demand-Side Management Costs: Represents recoverable costs associated with customer direct load control and energy efficiency and conservation programs in all jurisdictions that are being recovered from customers. These programs are designed to reduce customer’s energy consumption. Pepco earns a return on these regulatory assets.

Smart Grid Costs: Represents advanced metering infrastructure (AMI) costs associated with the installation of smart meters and the early retirement of legacy meters throughout Pepco’s service territory that are recoverable from customers. Pepco generally is deferring carrying charges on these regulatory assets.

Recoverable Income Taxes: Represents amounts recoverable from Pepco’s customers for tax benefits applicable to utility operations that were previously recognized in income tax expense before the company was ordered to record the tax benefits as deferred income taxes. As the temporary differences between the financial statement basis and tax basis of assets reverse, the deferred recoverable balances are reversed.

Recoverable Workers’ Compensation and Long-Term Disability Costs: Represents accrued workers’ compensation and long-term disability costs for Pepco, which are recoverable from customers when actual claims are paid to employees. Pepco does not earn a return on these regulatory assets.

Incremental Storm Restoration Costs: Represents total incremental storm restoration costs incurred for repair work due to major storm events in 2012 and 2011, including Hurricane Sandy, the June 2012 derecho, Hurricane Irene, and the 2011 severe winter storm, that are recoverable from customers in the Maryland jurisdiction. Pepco’s costs related to Hurricane Sandy, the June 2012 derecho, Hurricane Irene and the 2011 severe winter storm are being amortized and recovered from customers, each over a five-year period. Pepco does not earn a return on these regulatory assets.

Deferred Debt Extinguishment Costs: Represents deferred costs of debt extinguishment that are amortized to interest expense and recovered from customers. Pepco generally earns a return on these regulatory assets.

MAPP Abandonment Costs: Represents abandonment costs incurred in connection with the Mid-Atlantic Power Pathway (MAPP) transmission line construction project which was terminated by PJM Interconnection, LLC (PJM) on August 24, 2012. These regulatory assets are being amortized and recovered in transmission rates through May 2016. Pepco generally does not earn a return on these regulatory assets.

Deferred Energy Supply Costs: The regulatory asset represents primarily deferred costs associated with a net under-recovery of Default Electricity Supply costs incurred by Pepco and are being or are expected to be recovered from customers. Pepco does not earn a return on these regulatory assets. The regulatory liability represents primarily deferred costs associated with a net over-recovery of Default Electricity Supply costs incurred that will be refunded by Pepco to customers.

Other: Represents miscellaneous regulatory assets that generally are being amortized over 1 to 20 years.

Asset Removal Costs: The depreciation rates for Pepco include a component for removal costs, as approved by the relevant federal and state regulatory commissions. Accordingly, Pepco has recorded regulatory liabilities for its estimate of the difference between incurred removal costs and the amount of removal costs recovered through depreciation rates.

Reserves for FERC ROE Transmission Challenges: Represents reserves established under a settlement agreement filed with FERC for the resolution of certain challenges filed by a group of complainants of the base return on equity (ROE) currently authorized by FERC for the transmission service that Pepco provides.

Deferred Income Taxes Due to Customers: Represents the portions of deferred income tax assets applicable to utility operations of Pepco that have not been reflected in current customer rates for which future payment to customers is probable. As the temporary differences between the financial statement basis and tax basis of assets reverse, deferred recoverable income taxes are amortized.

Other: Represents miscellaneous regulatory liabilities.

Rate Proceedings

As further described in Note (1), “Organization,” on April 29, 2014, PHI entered into the Merger Agreement with Exelon and Merger Sub. Subject to certain exceptions, prior to the Merger or the termination of the Merger Agreement, PHI and its subsidiaries may not, without the consent of Exelon, initiate, file or pursue any rate cases, other than pursuing the conclusion of certain proceedings, as described below. To date, Pepco has not requested such consent from Exelon and has not filed any new distribution base rate cases since entering into the Merger Agreement.

Bill Stabilization Adjustment

A decoupling mechanism, the BSA, was approved and implemented for Pepco electric service in Maryland and in the District of Columbia.

Maryland

Pepco Electric Distribution Base Rates

2011 Base Rate Proceeding

In December 2011, Pepco submitted an application with the MPSC to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $68.4 million (subsequently adjusted by Pepco to approximately $66.2 million), based on a requested ROE of 10.75%. In July 2012, the MPSC issued an order approving an annual rate increase of approximately $18.1 million, based on an ROE of 9.31%. Among other things, the order also authorized Pepco to recover the actual cost of AMI meters installed during the 2011 test year, stating that cost recovery for AMI deployment will be allowed in future rate cases in which Pepco demonstrates that the system is cost effective. The new rates became effective on July 20, 2012. The Maryland Office of People’s Counsel has sought rehearing on the portion of the order allowing Pepco to recover the costs of AMI meters installed during the test year; that motion remains pending.

2012 Base Rate Proceeding – Phase I

In November 2012, Pepco submitted an application with the MPSC to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $60.8 million, based on a requested ROE of 10.25%. In July 2013, the MPSC issued an order in this proceeding approving an annual rate increase of approximately $27.9 million, based on an ROE of 9.36%. The order excludes the cost of AMI meters from Pepco’s rate base until such time as Pepco demonstrates the cost effectiveness of the AMI system; as a result, costs for AMI meters incurred with respect to the 2012 test year and beyond will be treated as other incremental AMI costs incurred in conjunction with the deployment of the AMI system that are deferred and on which a carrying charge is deferred, but only until such cost effectiveness has been demonstrated and such costs are included in rates. However, MPSC’s July 2012 order issued in connection with Pepco’s 2011 base rate proceeding, which allowed Pepco to recover the costs of meters installed during the 2011 test year for that case, remains in effect.

The July 2013 order also approved a Grid Resiliency Charge, which went into effect on January 1, 2014, for recovery of costs totaling approximately $24.0 million associated with Pepco’s proposed plan to accelerate investments related to certain priority feeders, provided that, before implementing the surcharge, Pepco (i) provides additional information to the MPSC related to performance objectives, milestones and costs, and (ii) makes annual filings with the MPSC thereafter concerning this project, which will permit the MPSC to establish the applicable Grid Resiliency Charge rider for each following year. These conditions have been met. The MPSC rejected certain other cost recovery mechanisms, including Pepco’s proposed reliability performance-based mechanism. The new rates were effective on July 12, 2013.

In July 2013, Pepco filed a notice of appeal of the July 2013 order in the Circuit Court for Baltimore City. Other parties also filed notices of appeal, which were consolidated with Pepco’s appeal. In its appeal, Pepco asserted that the MPSC erred in failing to grant Pepco an adequate ROE, denying a number of other cost recovery mechanisms and limiting Pepco’s test year data to no more than four months of forecasted data in future rate cases. The other parties primarily asserted that the MPSC erred or acted arbitrarily and capriciously in allowing the recovery of certain costs by Pepco, in approving the Grid Resiliency Charge, and in refusing to reduce Pepco’s rate base by known and measurable accumulated depreciation. In November 2014, the Circuit Court issued an order reversing the MPSC’s decision on Pepco’s ROE and directing the MPSC to make more specific findings regarding the impact of improved service reliability and the BSA in calculating Pepco’s ROE. On all other issues that were the subject of an appeal, the Circuit Court affirmed the MPSC’s July 2013 order.

Other parties to this proceeding filed notices of appeal of the Circuit Court’s decision to the Maryland Court of Special Appeals. On December 15, 2015, the Court of Special Appeals issued its decision in this matter (i) affirming the Circuit Court’s decision upholding the MPSC’s decision to approve the use of the Grid Resiliency Charge for Pepco, and (ii) reversing the Circuit Court on the ROE issue, finding that the MPSC’s original ROE of 9.36% was within the zone of reasonableness. Because none of the parties to the proceeding, including Pepco, appealed this Court of Special Appeals decision, the MPSC decision is now final.

2013 Base Rate Proceeding – Phase I

In December 2013, Pepco submitted an application with the MPSC to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $43.3 million (adjusted by Pepco to approximately $37.4 million on April 15, 2014), based on a requested ROE of 10.25%. The requested rate increase sought to recover expenses associated with Pepco’s ongoing investments in reliability enhancement improvements and efforts to maintain safe and reliable service. In July 2014, the MPSC issued an order approving an annual rate increase of approximately $8.75 million, based on an ROE of 9.62%. The new rates became effective on July 4, 2014. In July 2014, Pepco filed a petition for rehearing seeking reconsideration of the recovery of certain expenses, which the MPSC denied by its order issued in November 2014 (described below). In December 2014, Pepco filed a petition for judicial review of this MPSC order with the Circuit Court for Baltimore City. On August 7, 2015, the Circuit Court for Baltimore City affirmed the MPSC’s decision and denied Pepco’s appeal. Pepco has elected not to appeal the decision of the Circuit Court.

2012 and 2013 Base Rate Proceedings – Phase II

In August 2014, the MPSC issued an order establishing a Phase II proceeding in the 2012 base rate case described above (the 2012 Phase II proceeding) to address the tax implications of Pepco’s net operating loss carryforward (NOLC), which had impacted certain of Pepco’s rate adjustments in the 2012 base rate proceeding. Pepco filed a motion to dismiss the 2012 Phase II proceeding, asserting that the MPSC no longer has jurisdiction over the 2012 base rate case due to appeals having been filed by numerous parties. In September 2014, the MPSC issued an order staying the 2012 Phase II proceeding until further notice. In a similar Phase II proceeding in the 2013 base rate case described above, the MPSC issued an order in November 2014 upholding Pepco’s treatment of the NOLC. Although Pepco believes the November 2014 MPSC order should be dispositive of the issues raised in the 2012 Phase II proceeding, the 2012 Phase II proceeding has remained open pending the resolution of all appeals of the 2012 base rate proceeding. Now that the MPSC decision in that proceeding is final, the MPSC will have authority to act on Phase II.

FERC Transmission ROE Challenges

In February 2013, the public service commissions and public advocates of the District of Columbia, Maryland, Delaware and New Jersey, as well as the Delaware Municipal Electric Corporation, Inc., filed a joint complaint at FERC against Pepco and its affiliates, Delmarva Power & Light Company (DPL) and Atlantic City Electric Company (ACE), as well as Baltimore Gas and Electric Company (BGE). The complainants challenged the base ROE and certain protocols regarding the formula rate process associated with the transmission service that the utilities provide. The complainants support an ROE within a zone of reasonableness of 6.78% and 10.33%, and have argued for a base ROE of 8.7%. The base ROE currently authorized by FERC for PHI’s utilities is (i) 11.3% for facilities placed into service after January 1, 2006, and (ii) 10.8% for facilities placed into service prior to 2006. The 10.8% base ROE for facilities placed into service prior to 2006 receives a 50-basis-point incentive adder for being a member of a regional transmission organization. In August 2014, FERC issued an order setting the matters in this proceeding for hearing, but holding the hearing in abeyance pending settlement discussions. The order also (i) directed that the evidence and analysis presented concerning ROE be guided by the new ROE methodology adopted by FERC in another proceeding (discussed below), and (ii) set a 15-month refund period that commenced on February 27, 2013, should a refund result from this proceeding. After settlement discussions among the parties in this matter reached an impasse, the settlement judge, in November 2014, issued an order terminating the settlement discussions and referring the matter to a presiding administrative law judge.

In June 2014, FERC issued an order in a proceeding in which Pepco was not involved, in which it adopted a new ROE methodology for electric utilities. This new methodology replaces the existing one-step discounted cash flow analysis (which incorporates only short-term growth rates) traditionally used to derive ROE for electric utilities with the two-step discounted cash flow analysis (which incorporates both short-term and long-term measures of growth) used for natural gas and oil pipelines. As a result of the August 2014 FERC order discussed in the preceding paragraph, Pepco applied an estimated ROE based on the two-step methodology announced by FERC for the 15-month period over which its transmission revenues would be subject to refund as a result of the challenge, and recorded estimated reserves for the entire 15-month refund period in the second quarter of 2014.

On December 8, 2014, the parties that filed the February 2013 complaint filed a second complaint against Pepco, DPL, ACE, as well as BGE, regarding the base transmission ROE, seeking a reduction from 10.8% to 8.8%. By order issued on February 9, 2015, FERC established a hearing on the second complaint and established a second 15-month refund period that commenced on December 8, 2014. Consistent with the prior challenge, Pepco applied an estimated ROE based on the two-step methodology described above, and in the fourth quarter of 2014 and in the first, second and third quarters of 2015 established reserves for the estimated refund based on the effective date of the second refund period of December 8, 2014. On February 20, 2015, the chief judge issued an order consolidating the two complaint proceedings and established an initial decision issuance deadline of February 29, 2016. On March 2, 2015, the presiding administrative law judge issued an order establishing a procedural schedule for the consolidated proceedings that provided for the hearing to commence on October 20, 2015.

Also during the third quarter of 2015, Pepco further evaluated the reserves established for each of the two refund periods and, based on an updated assessment of market conditions, developments in other cases before FERC, litigation risk and other factors, increased its reserves to reflect management’s best estimate of the refund that is expected to result from these consolidated proceedings. A settlement entered into by the parties regarding the protocols (but not the ROE) raised in the February 2013 complaint was submitted to FERC on July 31, 2015 and was approved by FERC in November 2015.

On November 6, 2015, the parties filed a settlement agreement with FERC regarding the ROE. This settlement agreement provides for (i) a base ROE of 10.0%, effective March 8, 2016, to which a 50-basis-point incentive adder will be applied for being a member of a regional transmission organization, and (ii) customer refunds in the amount of approximately $14.2 million for Pepco covering the two 15-month refund periods described above. In addition, under this settlement agreement, no party may file to change the base ROE or any incentives prior to June 1, 2018. The parties have requested that FERC approve this settlement agreement by March 16, 2016, in order to incorporate the new ROE and applicable refunds into each utility’s 2016 transmission formula rate update. As of December 31, 2015, Pepco’s reserves for both of the refund periods totaled $13 million as required under the settlement agreement.

MPSC New Generation Contract Requirement

In April 2012, the MPSC issued an order that requires Maryland electric distribution companies (EDCs) Pepco, DPL and BGE (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 megawatts (MWs) beginning in 2015, in amounts proportional to their relative standard offer service (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 originally expected commercial operation date of June 1, 2015 (which is now deferred pending the outcome of the proceedings discussed below), 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, in September 2013, the U.S. District Court for the District of Maryland (the Federal District Court) issued a ruling that the MPSC’s April 2012 order violated the Supremacy Clause of the U.S. Constitution by attempting to regulate wholesale prices. In contrast, in October 2013, in response to appeals filed by the Contract EDCs and other parties, the Maryland Circuit Court for Baltimore City (the Maryland Circuit Court) upheld the MPSC’s orders requiring the Contract EDCs to enter into the contracts.

In October 2013, the Federal District Court issued an order ruling that the contracts are illegal and unenforceable. The Contract EDCs, the Maryland Office of People’s Counsel and one generating company have appealed the Maryland Circuit Court’s decision to the Maryland Court of Special Appeals. In addition, in November 2013 both the winning bidder and the MPSC appealed the Federal District Court decision to the U.S. Court of Appeals for the Fourth Circuit, which affirmed the decision. In November 2014, the winning bidder and the MPSC each petitioned the U.S. Supreme Court to consider hearing an appeal of the Fourth Circuit decision and, on October 19, 2015, the U.S. Supreme Court agreed to review that decision.

Assuming the contracts, as currently written, become effective following the satisfaction of all relevant conditions, including the completion of the proceedings discussed above, Pepco continues to believe that it may be required to record its proportional share of the contracts as derivative instruments at fair value and record related regulatory assets of approximately the same amount because it would be entitled to recover any payments under the contracts from SOS customers. Pepco has concluded that any accounting for these contracts would not be required until all legal proceedings related to these contracts and the actions of the MPSC in the related proceeding have been resolved.

District of Columbia Power Line Undergrounding Initiative

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 provides enabling legislation for the District of Columbia Power Line Undergrounding (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 collect on behalf of and 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 and recovery of Pepco’s investment through a volumetric surcharge (the Triennial Plan), all in accordance with the Improvement Financing Act. In August 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 of Columbia to recover the costs associated with the bond issuance (the DDOT surcharge).

In November 2014, the DCPSC issued an order approving the Triennial Plan, including 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 December 2014, a party to the proceeding sought reconsideration from the DCPSC of both decisions. Final decisions denying both requests for reconsideration were issued by the DCPSC on January 22, 2015 and February 2, 2015, respectively.

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. A determination whether the Court of Appeals will rehear the case is pending.

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.

Merger Approval Proceedings

District of Columbia

On June 18, 2014, Exelon, PHI and Pepco, and certain of their respective affiliates, filed an application with the DCPSC seeking approval of the Merger. To approve the Merger, the DCPSC must find that the Merger is in the public interest. In an order issued August 22, 2014, the DCPSC stated that to make the determination of whether the transaction is in the public interest, it will analyze the transaction in the context of seven factors to determine whether the transaction balances the interests of shareholders and investors with ratepayers and the community, whether the benefits to shareholders do or do not come at the expense of the ratepayers, and whether the transaction produces a direct and tangible benefit to ratepayers. The seven factors identified by the DCPSC are the effects of the transaction on: (i) ratepayers, shareholders, the financial health of the utility standing alone and as merged, and the local economy; (ii) utility management and administrative operations; (iii) the public safety and the safety and reliability of services; (iv) risks associated with all of the affiliated non-jurisdictional business operations, including nuclear operations, of the applicants; (v) the DCPSC’s ability to regulate the utility effectively following the Merger; (vi) competition in the local retail and wholesale markets that impacts the District and District ratepayers; and (vii) conservation of natural resources and preservation of environmental quality. District of Columbia law does not impose any time limit on the DCPSC’s review of the Merger. The DCPSC held evidentiary hearings in March and April of 2015 and the record was closed on May 27, 2015.

On August 27, 2015, the DCPSC issued a written order denying the application seeking approval of the Merger. On September 28, 2015, Exelon, PHI and Pepco, and certain of their respective affiliates, filed an application for reconsideration before the DCPSC. Following the DCPSC’s decision on reconsideration, Exelon and Pepco Holdings have the option of filing further appeals with the DC Court of Appeals.

On October 6, 2015, Exelon, PHI and Pepco, and certain of their respective affiliates, entered into the DC Settlement Agreement with the District of Columbia Government, the Office of the People’s Counsel and other parties. Also on October 6, 2015, Exelon, PHI and Pepco, and certain of their respective affiliates filed with the DCPSC the Motion to Reopen requesting consideration of the DC Settlement Agreement and approval of the Merger on such terms and conditions set forth in the DC Settlement Agreement, without condition or modification, and to stay further proceedings on the application for reconsideration filed by the parties on September 28, 2015, and suspend the time period for reconsideration pending the DCPSC’s consideration of the DC Settlement Agreement.

On October 28, 2015, the DCPSC approved the Motion to Reopen and set a procedural schedule for its review of this matter. Upon completion of the public input and evidentiary hearings, the record was closed as of December 23, 2015. Although District of Columbia law does not impose any time limit on the DCPSC’s review of the Merger, the parties requested a decision by March 4, 2016.

Maryland

On August 19, 2014, Exelon, PHI, Pepco, DPL and certain of their respective affiliates, filed an application with the MPSC seeking approval of the Merger. Maryland law requires the MPSC to approve a merger subject to its review if it finds that the merger is consistent with the public interest, convenience and necessity, including its benefits to and impact on consumers. Evidentiary hearings were held beginning on January 26, 2015. On March 10, 2015, Exelon, PHI, Pepco, DPL and certain of their respective affiliates, filed with the MPSC a settlement agreement entered into with one of the stakeholder groups participating in the MPSC approval proceeding. On March 16, 2015, Exelon, PHI, Pepco, DPL and certain of their respective affiliates, filed with the MPSC a settlement agreement entered into with Montgomery and Prince George’s Counties in Maryland, and a number of other parties. On May 15, 2015, the MPSC approved the Merger, with conditions, including conditions that modify and supplement those originally proposed. On May 18, 2015, Pepco Holdings and Exelon announced that they had completed their review of the MPSC’s order approving the Merger and have committed to fulfill the modified, more stringent conditions and package of customer benefits imposed by the MPSC.

Multiple parties have filed petitions for judicial review of the MPSC order by the Circuit Court of Queen Anne’s County, Maryland, seeking to appeal the MPSC order. In connection with these proceedings, the Maryland Office of People’s Counsel and several other parties to the Merger proceedings filed motions in the Circuit Court for Queen Anne’s County, Maryland, requesting a stay of the MPSC order. On August 7, 2015, the Circuit Court for Queen Anne’s County denied the motions for stay. On January 8, 2016, the Circuit Court affirmed the MPSC’s order in all respects. On January 20 and 22, 2016, respectively, the Maryland Office of People’s Counsel and environmental groups filed notices of appeal of the Circuit Court’s order to the Maryland Court of Special Appeals. Unless a motion to stay is filed and then granted by the court, the MPSC order will remain in effect during the appeals process.

Virginia

On June 3, 2014, Exelon, PHI, Pepco and DPL, and certain of their respective affiliates, filed an application with the VSCC seeking approval of the Merger. Virginia law provides that, if the VSCC determines, with or without hearing, that adequate service to the public at just and reasonable rates will not be impaired or jeopardized by granting the application for approval, then the VSCC shall approve a merger with such conditions that the VSCC deems to be appropriate in order to satisfy this standard. On October 7, 2014, the VSCC issued an order approving the Merger.

Federal Energy Regulatory Commission

On May 30, 2014, Exelon, PHI, Pepco, DPL and ACE, and certain of their respective affiliates, submitted to FERC a Joint Application for Authorization of Disposition of Jurisdictional Assets and Merger under Section 203 of the Federal Power Act. Under that section, FERC shall approve a merger if it finds that the proposed transaction will be consistent with the public interest. On November 20, 2014, FERC issued an order approving the Merger.

Delmarva Power & Light Co/De [Member]

Regulatory Matters

(7) REGULATORY MATTERS

Regulatory Assets and Regulatory Liabilities

The components of DPL’s regulatory asset and liability balances at December 31, 2015 and 2014 are as follows:

	2015		2014
	(millions of dollars)
Regulatory Assets
Demand-side management costs	$	111	$	91
Smart Grid costs		85		86
Recoverable income taxes		38		84
COPCO acquisition adjustment		13		18
Deferred debt extinguishment costs		10		12
Incremental storm restoration costs		6		7
MAPP abandonment costs		3		14
Deferred energy supply costs		2		12
Deferred losses on gas derivatives		2		4
Other		38		28
Total Regulatory Assets	$	308	$	356
Regulatory Liabilities
Asset removal costs	$	153	$	166
Reserves for FERC ROE transmission challenges		11		1
Deferred energy supply costs		6		—
Deferred income taxes due to customers		3		37
Other		16		21
Total Regulatory Liabilities	$	189	$	225

A description for each category of regulatory assets and regulatory liabilities follows:

Demand-Side Management Costs: Represents recoverable costs associated with customer direct load control and energy efficiency and conservation programs in all jurisdictions that are being recovered from customers. These programs are designed to reduce customers’ energy consumption. DPL earns a return on these regulatory assets.

Smart Grid Costs: Represents advanced metering infrastructure costs associated with the installation of smart meters and the early retirement of legacy meters throughout DPL’s service territory that are recoverable from customers. DPL generally is deferring carrying charges on these regulatory assets.

Recoverable Income Taxes: Represents amounts recoverable from DPL’s customers for tax benefits applicable to utility operations that were previously recognized in income tax expense before the company was ordered to record the tax benefits as deferred income taxes. As the temporary differences between the financial statement basis and tax basis of assets reverse, the deferred recoverable balances are reversed.

COPCO Acquisition Adjustment: On July 19, 2007, the MPSC issued an order which provided for the recovery of a portion of DPL’s goodwill. As a result of this order, $41 million in DPL goodwill was transferred to a regulatory asset. This item is being amortized from August 2007 through August 2018. DPL earns a return of 12.95% on these regulatory assets.

Deferred Debt Extinguishment Costs: Represents deferred costs of debt extinguishment that are amortized to interest expense and recovered from customers. DPL generally earns a return on these regulatory assets.

Incremental Storm Restoration Costs: Represents total incremental storm restoration costs incurred for repair work due to major storm events in 2015, 2012 and 2011, including the June 2015 storm, Hurricane Sandy, the June 2012 derecho, and Hurricane Irene, that are recoverable from customers in the Maryland jurisdiction. DPL’s costs related to Hurricane Sandy, the June 2012 derecho and Hurricane Irene are being amortized and recovered from customers, each over a five-year period. DPL generally earns a return on these regulatory assets.

MAPP Abandonment Costs: Represents abandonment costs incurred in connection with the Mid-Atlantic Power Pathway (MAPP) transmission line construction project which was terminated by PJM Interconnection, LLC (PJM) on August 24, 2012. These regulatory assets are being amortized and recovered in transmission rates through May 2016. DPL generally does not earn a return on these regulatory assets.

Deferred Energy Supply Costs: The regulatory asset represents primarily deferred costs associated with a net under-recovery of Default Electricity Supply costs incurred by DPL that are being or expected to be recovered from customers. DPL earns a return on these regulatory assets in Delaware. The regulatory liability represents primarily deferred costs associated with a net over-recovery of Default Electricity Supply costs incurred that will be refunded by DPL to customers.

Deferred Losses on Gas Derivatives: Represents losses associated with hedges of natural gas purchases that are recoverable from customers through the Gas Cost Rate (GCR) approved by the DPSC. DPL does not earn a return on these regulatory assets.

Other: Represents miscellaneous regulatory assets that generally are being amortized over 1 to 20 years.

Asset Removal Costs: The depreciation rates for DPL include a component for removal costs, as approved by the relevant federal and state regulatory commissions. Accordingly, DPL has recorded regulatory liabilities for its estimate of the difference between incurred removal costs and the amount of removal costs recovered through depreciation rates.

Reserves for FERC ROE Transmission Challenges: Represents reserves established under a settlement agreement filed with FERC for the resolution of certain challenges filed by a group of complainants of the base return on equity (ROE) currently authorized by FERC for the transmission service that DPL provides.

Deferred Income Taxes Due to Customers: Represents the portions of deferred income tax assets applicable to utility operations of DPL that have not been reflected in current customer rates for which future payment to customers is probable. As the temporary differences between the financial statement basis and tax basis of assets reverse, deferred recoverable income taxes are amortized.

Other: Represents miscellaneous regulatory liabilities.

Rate Proceedings

As further described in Note (1), “Organization,” on April 29, 2014, PHI entered into the Merger Agreement with Exelon and Merger Sub. Subject to certain exceptions, prior to the Merger or the termination of the Merger Agreement, PHI and its subsidiaries may not, without the consent of Exelon, initiate, file or pursue any rate cases, other than pursuing the conclusion of certain proceedings, as described below. To date, DPL has not requested such consent from Exelon and has not filed any new distribution base rate cases since entering into the Merger Agreement.

Bill Stabilization Adjustment

A decoupling mechanism, the BSA, was approved and implemented for DPL electric service in Maryland. DPL’s decoupling proposal in Delaware has not to date been adopted.

Delaware

Electric Distribution Base Rates

In March 2013, DPL submitted an application with the DPSC to increase its electric distribution base rates. The application sought approval of an annual rate increase of approximately $42 million (adjusted by DPL to approximately $39 million on September 20, 2013), based on a requested ROE of 10.25%. The requested rate increase sought to recover expenses associated with DPL’s ongoing investments in reliability enhancement improvements and efforts to maintain safe and reliable service. In August 2014, the DPSC issued a final order in this proceeding providing for an annual increase in DPL’s electric distribution base rates of approximately $15.1 million, based on an ROE of 9.70%. The new 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 described below in “Merger Approval Proceedings – Delaware,” the parties agreed to suspend the appeal and, if the Merger is completed, to the withdrawal of the appeal and the cross-appeal with prejudice.

Forward Looking Rate Plan

In October 2013, DPL filed a multi-year rate plan, referred to as the Forward Looking Rate Plan (FLRP). As proposed, the FLRP would provide for annual electric distribution base rate increases over a four-year period in the aggregate amount of approximately $56 million. The FLRP as proposed provides the opportunity to achieve estimated earned ROEs of 7.41% and 8.80% in years one and two, respectively, and 9.75% in both years three and four of the plan.

In addition, DPL proposed that as part of the FLRP, in order to provide a higher minimum required standard of reliability for DPL’s customers than that to which DPL is currently subject, the standards by which DPL’s reliability is measured would be made more stringent in each year of the FLRP. DPL has also offered to refund an aggregate of $500,000 to customers in each year of the FLRP that it fails to meet the proposed stricter minimum reliability standards.

In October 2013, the DPSC opened a docket for the purpose of reviewing the details of the FLRP, but stated that it would not address the FLRP until the electric distribution base rate case discussed above was concluded. Although the rate case has been concluded, a schedule for the FLRP docket has not yet been established.

Under the Merger Agreement, DPL is permitted to pursue this matter; however, under the settlement agreement related to the Merger described below in “Merger Approval Proceedings – Delaware,” DPL agreed to withdraw the FLRP if the Merger is completed, without prejudice to the right to make future filings with the DPSC proposing alternative regulatory methodologies that could include, but are not limited to, a multi-year rate plan.

Gas Cost Rates

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.

Under the Merger Agreement, DPL is permitted to continue to file its required annual GCR cases in Delaware.

FERC Transmission ROE Challenges

In February 2013, the public service commissions and public advocates of the District of Columbia, Maryland, Delaware and New Jersey, as well as the Delaware Municipal Electric Corporation, Inc., filed a joint complaint at FERC against DPL and its affiliates, Pepco and Atlantic City Electric Company (ACE), as well as Baltimore Gas and Electric Company (BGE). The complainants challenged the base ROE and certain protocols regarding the formula rate process associated with the transmission service that the utilities provide. The complainants support an ROE within a zone of reasonableness of 6.78% and 10.33%, and have argued for a base ROE of 8.7%. The base ROE currently authorized by FERC for PHI’s utilities is (i) 11.3% for facilities placed into service after January 1, 2006, and (ii) 10.8% for facilities placed into service prior to 2006. The 10.8% base ROE for facilities placed into service prior to 2006 receives a 50-basis-point incentive adder for being a member of a regional transmission organization. In August 2014, FERC issued an order setting the matters in this proceeding for hearing, but holding the hearing in abeyance pending settlement discussions. The order also (i) directed that the evidence and analysis presented concerning ROE be guided by the new ROE methodology adopted by FERC in another proceeding (discussed below), and (ii) set a 15-month refund period that commenced on February 27, 2013, should a refund result from this proceeding. After settlement discussions among the parties in this matter reached an impasse, the settlement judge, in November 2014, issued an order terminating the settlement discussions and referring the matter to a presiding administrative law judge.

In June 2014, FERC issued an order in a proceeding in which DPL was not involved, in which it adopted a new ROE methodology for electric utilities. This new methodology replaces the existing one-step discounted cash flow analysis (which incorporates only short-term growth rates) traditionally used to derive ROE for electric utilities with the two-step discounted cash flow analysis (which incorporates both short-term and long-term measures of growth) used for natural gas and oil pipelines. As a result of the August 2014 FERC order discussed in the preceding paragraph, DPL applied an estimated ROE based on the two-step methodology announced by FERC for the 15-month period over which its transmission revenues would be subject to refund as a result of the challenge, and recorded estimated reserves for the entire 15-month refund period in the second quarter of 2014.

On December 8, 2014, the parties that filed the February 2013 complaint filed a second complaint against Pepco, DPL, ACE, as well as BGE, regarding the base transmission ROE, seeking a reduction from 10.8% to 8.8%. By order issued on February 9, 2015, FERC established a hearing on the second complaint and established a second 15-month refund period that commenced on December 8, 2014. Consistent with the prior challenge, DPL applied an estimated ROE based on the two-step methodology described above, and in the fourth quarter of 2014 and in the first, second and third quarters of 2015 established reserves for the estimated refund based on the effective date of the second refund period of December 8, 2014. On February 20, 2015, the chief judge issued an order consolidating the two complaint proceedings and established an initial decision issuance deadline of February 29, 2016. On March 2, 2015, the presiding administrative law judge issued an order establishing a procedural schedule for the consolidated proceedings that provided for the hearing to commence on October 20, 2015.

Also during the third quarter of 2015, DPL further evaluated the reserves established for each of the two refund periods and, based on an updated assessment of market conditions, developments in other cases before FERC, litigation risk and other factors, increased its reserves to reflect management’s best estimate of the refund that is expected to result from these consolidated proceedings. A settlement entered into by the parties regarding the protocols (but not the ROE) raised in the February 2013 complaint was submitted to FERC on July 31, 2015 and was approved by FERC in November 2015.

On November 6, 2015, the parties filed a settlement agreement with FERC regarding the ROE. This settlement agreement provides for (i) a base ROE of 10.0%, effective March 8, 2016, to which a 50-basis-point incentive adder will be applied for being a member of a regional transmission organization, and (ii) customer refunds in the amount of approximately $11.9 million for DPL covering the two 15-month refund periods described above. In addition, under this settlement agreement, no party may file to change the base ROE or any incentives prior to June 1, 2018. The parties have requested that FERC approve this settlement agreement by March 16, 2016, in order to incorporate the new ROE and applicable refunds into each utility’s 2016 transmission formula rate update. As of December 31, 2015, DPL’s reserves for both of the refund periods totaled $11 million as required under the settlement agreement.

MPSC New Generation Contract Requirement

In April 2012, the MPSC issued an order that requires Maryland electric distribution companies (EDCs) Pepco, DPL and BGE (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 megawatts (MWs) beginning in 2015, in amounts proportional to their relative standard offer service (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 originally expected commercial operation date of June 1, 2015 (which is now deferred pending the outcome of the proceedings discussed below), 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, in September 2013, the U.S. District Court for the District of Maryland (the Federal District Court) issued a ruling that the MPSC’s April 2012 order violated the Supremacy Clause of the U.S. Constitution by attempting to regulate wholesale prices. In contrast, in October 2013, in response to appeals filed by the Contract EDCs and other parties, the Maryland Circuit Court for Baltimore City (the Maryland Circuit Court) upheld the MPSC’s orders requiring the Contract EDCs to enter into the contracts.

In October 2013, the Federal District Court issued an order ruling that the contracts are illegal and unenforceable. The Contract EDCs, the Maryland Office of People’s Counsel and one generating company have appealed the Maryland Circuit Court’s decision to the Maryland Court of Special Appeals. In addition, in November 2013 both the winning bidder and the MPSC appealed the Federal District Court decision to the U.S. Court of Appeals for the Fourth Circuit, which affirmed the decision. In November 2014, the winning bidder and the MPSC each petitioned the U.S. Supreme Court to consider hearing an appeal of the Fourth Circuit decision and, on October 19, 2015, the U.S. Supreme Court agreed to review that decision.

Assuming the contracts, as currently written, become effective following the satisfaction of all relevant conditions, including the completion of the proceedings discussed above, DPL continues to believe that it may be required to record its proportional share of the contracts as derivative instruments at fair value and record related regulatory assets of approximately the same amount because it would be entitled to recover any payments under the contracts from SOS customers. DPL has concluded that any accounting for these contracts would not be required until all legal proceedings related to these contracts and the actions of the MPSC in the related proceeding have been resolved.

Merger Approval Proceedings

Delaware

On June 18, 2014, Exelon, PHI and DPL, and certain of their respective affiliates, filed an application with the DPSC seeking approval of the Merger. Delaware law requires the DPSC to approve the Merger when it determines that the transaction is in accordance with law, for a proper purpose, and is consistent with the public interest. The DPSC must further find that the successor will continue to provide safe and reliable service, will not terminate or impair existing collective bargaining agreements and will engage in good faith bargaining with organized labor. On February 13, 2015, Exelon, DPL, the DPSC staff, the Division of the Public Advocate and certain other parties filed a settlement agreement with the DPSC, which was amended in April 2015. The DPSC approved the amended settlement agreement at its meeting held on May 19, 2015, memorializing this decision by written order issued on June 2, 2015. The specific grounds for the DPSC’s approval of the Merger, as well as the specific conditions, will be included in an order to be issued by the DPSC after the Merger closes.

Maryland

On August 19, 2014, Exelon, PHI, Pepco, DPL and certain of their respective affiliates, filed an application with the MPSC seeking approval of the Merger. Maryland law requires the MPSC to approve a merger subject to its review if it finds that the merger is consistent with the public interest, convenience and necessity, including its benefits to and impact on consumers. Evidentiary hearings were held beginning on January 26, 2015. On March 10, 2015, Exelon, PHI, Pepco, DPL and certain of their respective affiliates, filed with the MPSC a settlement agreement entered into with one of the stakeholder groups participating in the MPSC approval proceeding. On March 16, 2015, Exelon, PHI, Pepco, DPL and certain of their respective affiliates, filed with the MPSC a settlement agreement entered into with Montgomery and Prince George’s Counties in Maryland, and a number of other parties. On May 15, 2015, the MPSC approved the Merger, with conditions, including conditions that modify and supplement those originally proposed. On May 18, 2015, Pepco Holdings and Exelon announced that they had completed their review of the MPSC’s order approving the Merger and have committed to fulfill the modified, more stringent conditions and package of customer benefits imposed by the MPSC.

Multiple parties have filed petitions for judicial review of the MPSC order by the Circuit Court of Queen Anne’s County, Maryland, seeking to appeal the MPSC order. In connection with these proceedings, the Maryland Office of People’s Counsel and several other parties to the Merger proceedings filed motions in the Circuit Court for Queen Anne’s County, Maryland, requesting a stay of the MPSC order. On August 7, 2015, the Circuit Court for Queen Anne’s County denied the motions for stay. On January 8, 2016, the Circuit Court affirmed the MPSC’s order in all respects. On January 20 and 22, 2016, respectively, the Maryland Office of People’s Counsel and environmental groups filed notices of appeal of the Circuit Court’s order to the Maryland Court of Special Appeals. Unless a motion to stay is filed and then granted by the court, the MPSC order will remain in effect during the appeals process.

Virginia

On June 3, 2014, Exelon, PHI, Pepco and DPL, and certain of their respective affiliates, filed an application with the VSCC seeking approval of the Merger. Virginia law provides that, if the VSCC determines, with or without hearing, that adequate service to the public at just and reasonable rates will not be impaired or jeopardized by granting the application for approval, then the VSCC shall approve a merger with such conditions that the VSCC deems to be appropriate in order to satisfy this standard. On October 7, 2014, the VSCC issued an order approving the Merger.

Federal Energy Regulatory Commission

On May 30, 2014, Exelon, PHI, Pepco, DPL and ACE, and certain of their respective affiliates, submitted to FERC a Joint Application for Authorization of Disposition of Jurisdictional Assets and Merger under Section 203 of the Federal Power Act. Under that section, FERC shall approve a merger if it finds that the proposed transaction will be consistent with the public interest. On November 20, 2014, FERC issued an order approving the Merger.

Atlantic City Electric Co [Member]

Regulatory Matters

(6) REGULATORY MATTERS

Regulatory Assets and Regulatory Liabilities

The components of ACE’s regulatory asset and liability balances at December 31, 2015 and 2014 are as follows:

	2015		2014
	(millions of dollars)
Regulatory Assets
Securitized stranded costs	$	202	$	278
Recoverable income taxes		44		42
Deferred energy supply costs		27		58
Incremental storm restoration costs		18		15
Deferred debt extinguishment costs		7		8
Other		24		26
Total Regulatory Assets	$	322	$	427
Regulatory Liabilities
Federal and state tax benefits, related to securitized stranded costs	$	13	$	8
Reserves for FERC ROE transmission challenges		8		1
Deferred income taxes due to customers		3		3
Other		3		2
Total Regulatory Liabilities	$	27	$	14

A description for each category of regulatory assets and regulatory liabilities follows:

Securitized Stranded Costs: Certain contract termination payments under a contract between ACE and an unaffiliated non-utility generator (NUG) and costs associated with the regulated operations of ACE’s electricity generation business are no longer recoverable through customer rates (collectively referred to as “stranded costs”). The stranded costs are amortized over the life of Transition Bonds issued by ACE Funding to securitize the recoverability of these stranded costs (the Transition Bonds). These Transition Bonds mature between 2016 and 2023. A customer surcharge is collected by ACE to fund principal and interest payments on the Transition Bonds. ACE earns a return on these regulatory assets.

Recoverable Income Taxes: Represents amounts recoverable from ACE’s customers for tax benefits applicable to utility operations previously recognized in income tax expense before the company was ordered to record the tax benefits as deferred income taxes. As the temporary differences between the financial statement basis and tax basis of assets reverse, the deferred recoverable balances are reversed.

Deferred Energy Supply Costs: The regulatory asset represents primarily deferred costs associated with a net under-recovery of energy supply costs incurred by ACE that are being or are expected to be recovered from customers. ACE earns a return on these regulatory assets.

Incremental Storm Restoration Costs: Represents total incremental storm restoration costs incurred for repair work due to major storm events in 2015, 2012 and 2011, including the June 2015 storm, Hurricane Sandy, the June 2012 derecho, and Hurricane Irene, that are recoverable from customers. ACE’s costs related to Hurricane Sandy, the June 2012 derecho and Hurricane Irene are being amortized and recovered from customers, each over a three-year period. ACE does not earn a return on these regulatory assets.

Deferred Debt Extinguishment Costs: Represents deferred costs of debt extinguishment that are amortized to interest expense and recovered from customers. ACE generally earns a return on these regulatory assets.

Other: Represents miscellaneous regulatory assets that generally are being amortized over 1 to 20 years.

Federal and State Tax Benefits, Related to Securitized Stranded Costs: Securitized stranded costs include a portion attributable to the future tax benefit expected to be realized when the higher tax basis of the generating facilities divested by ACE is deducted for New Jersey state income tax purposes, as well as the future benefit to be realized through the reversal of federal excess deferred taxes. To account for the possibility that these tax benefits may be given to ACE’s customers through lower rates in the future, ACE established a regulatory liability. The regulatory liability related to federal excess deferred taxes will remain until such time as the Internal Revenue Service (IRS) issues its final regulations with respect to normalization of these federal excess deferred taxes.

Reserves for FERC ROE Transmission Challenges: Represents reserves established under a settlement agreement filed with FERC for the resolution of certain challenges filed by a group of complainants of the base return on equity (ROE) currently authorized by FERC for the transmission service that ACE provides.

Deferred Income Taxes Due to Customers: Represents the portions of deferred income tax assets applicable to utility operations of ACE that have not been reflected in current customer rates for which future payment to customers is probable. As the temporary differences between the financial statement basis and tax basis of assets reverse, deferred recoverable income taxes are amortized.

Other: Represents miscellaneous regulatory liabilities.

Rate Proceedings

As further described in Note (1), “Organization,” on April 29, 2014, PHI entered into the Merger Agreement with Exelon and Merger Sub. Subject to certain exceptions, prior to the Merger or the termination of the Merger Agreement, PHI and its subsidiaries may not, without the consent of Exelon, initiate, file or pursue any rate cases, other than pursuing the conclusion of certain proceedings, as described below. To date, ACE has not requested such consent from Exelon and has not filed any new distribution base rate cases since entering into the Merger Agreement.

Bill Stabilization Adjustment

Although ACE proposed the adoption of a mechanism to decouple retail distribution revenue from the amount of power delivered to retail customers, this decoupling proposal has not to date been adopted.

New Jersey

Update and Reconciliation of Certain Under-Recovered Balances

In March 2015, ACE submitted its 2015 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 for ACE’s uncollected accounts. As filed, the net impact of the proposed changes would have been an annual rate increase of approximately $52.0 million (revised to an increase of approximately $33.9 million on April 17, 2015, based upon updates for actual data through March 31, 2015). On May 19, 2015, the NJBPU approved a stipulation of settlement entered into by the parties providing for a provisional overall annual rate increase of $33.9 million effective June 1, 2015. On September 11, 2015, the NJBPU approved a stipulation of settlement in this proceeding, which made final the provisional rates that were placed into effect as of June 1, 2015, with an adjustment that decreased the rate applicable to the residential class by $1.3 million. This rate increase of approximately $32.6 million will have no effect on ACE’s operating income, since these revenues provide for recovery of deferred costs under an approved deferral mechanism.

On February 1, 2016, ACE submitted its 2016 annual petition with the NJBPU seeking to reconcile and update the same categories of charges and costs described in (i) and (ii) in the above paragraph. The net impact of adjusting the charges as proposed is an overall annual rate increase of approximately $8.8 million, including New Jersey Sales and Use Tax. The matter is pending at the NJBPU and will be updated for January through March 2016 actual data. ACE has requested that the NJBPU place the new rates into effect by June 1, 2016.

Service Extension Contributions Refund Order

In July 2013, in compliance with a 2012 Superior Court of New Jersey Appellate Division (Appellate Division) court decision, the NJBPU released an order requiring utilities to issue refunds to persons or entities that paid non-refundable contributions for utility service extensions to certain areas described as “Areas Not Designated for Growth.” The order is limited to eligible contributions paid between March 20, 2005 and December 20, 2009. ACE is processing the refund requests that meet the eligibility criteria established in the order as they are received. Although ACE estimates that it received approximately $11 million of contributions between March 20, 2005 and December 20, 2009, it is currently unable to reasonably estimate the amount that it may be required to refund using the eligibility criteria established by the order. Since the July 2013 order was released, ACE has paid less than $1 million in refund claims, the validity of each of which is investigated by ACE prior to making any such refunds. In September 2014, the NJBPU commenced a rulemaking proceeding to further implement the directives of the Appellate Division decision. In November 2015, the NJBPU adopted new regulations that remove provisions distinguishing between growth areas and not-for-growth areas and provide formulae for allocating extension costs. At this time, ACE does not expect the amount it is ultimately required to refund will have a material effect on its consolidated financial condition, results of operations or cash flows, as the amount refunded will generally increase the value of ACE’s property, plant and equipment and may ultimately be recovered through depreciation expense and cost of service in future electric distribution base rate cases.

Generic Consolidated Tax Adjustment Proceeding

In January 2013, the NJBPU initiated a generic proceeding to examine whether a consolidated tax adjustment (CTA) should continue to be used, and if so, how it should be calculated in determining a utility’s cost of service. Under the NJBPU’s current policy, when a New Jersey utility is included in a consolidated group income tax return, an allocated amount of any reduction in the consolidated group’s taxes as a result of losses by affiliates is used to reduce the utility’s rate base, upon which the utility earns a return. This policy has negatively impacted ACE’s electric distribution base rate case outcomes and ACE’s position is that the CTA should be eliminated. In an order issued in October 2014, the NJBPU determined that it is appropriate for affected consolidated groups to continue to include a CTA in New Jersey base rate filings, but that the CTA calculation will be modified to limit the look-back period for the calculation to five years, exclude transmission assets from the calculation, and allocate 25 percent of the final CTA amount as a reduction to the distribution revenue requirement. ACE anticipates that this revised methodology will significantly reduce the negative effects of the CTA in future base rate cases. In November 2014, the New Jersey Division of Rate Counsel filed an appeal of the NJBPU’s CTA order in the Appellate Division. No stay of the October 2014 CTA order was requested in connection with the appeal. As such, barring an adverse finding by the Appellate Division, the order is in effect. The appeal remains pending.

FERC Transmission ROE Challenges

In February 2013, the public service commissions and public advocates of the District of Columbia, Maryland, Delaware and New Jersey, as well as the Delaware Municipal Electric Corporation, Inc., filed a joint complaint at FERC against ACE and its affiliates, Pepco and Delmarva Power & Light Company (DPL), as well as Baltimore Gas and Electric Company (BGE). The complainants challenged the base ROE and certain protocols regarding the formula rate process associated with the transmission service that the utilities provide. The complainants support an ROE within a zone of reasonableness of 6.78% and 10.33%, and have argued for a base ROE of 8.7%. The base ROE currently authorized by FERC for PHI’s utilities is (i) 11.3% for facilities placed into service after January 1, 2006, and (ii) 10.8% for facilities placed into service prior to 2006. The 10.8% base ROE for facilities placed into service prior to 2006 receives a 50-basis-point incentive adder for being a member of a regional transmission organization. In August 2014, FERC issued an order setting the matters in this proceeding for hearing, but holding the hearing in abeyance pending settlement discussions. The order also (i) directed that the evidence and analysis presented concerning ROE be guided by the new ROE methodology adopted by FERC in another proceeding (discussed below), and (ii) set a 15-month refund period that commenced on February 27, 2013, should a refund result from this proceeding. After settlement discussions among the parties in this matter reached an impasse, the settlement judge, in November 2014, issued an order terminating the settlement discussions and referring the matter to a presiding administrative law judge.

In June 2014, FERC issued an order in a proceeding in which ACE was not involved, in which it adopted a new ROE methodology for electric utilities. This new methodology replaces the existing one-step discounted cash flow analysis (which incorporates only short-term growth rates) traditionally used to derive ROE for electric utilities with the two-step discounted cash flow analysis (which incorporates both short-term and long-term measures of growth) used for natural gas and oil pipelines. As a result of the August 2014 FERC order discussed in the preceding paragraph, ACE applied an estimated ROE based on the two-step methodology announced by FERC for the 15-month period over which its transmission revenues would be subject to refund as a result of the challenge, and recorded estimated reserves for the entire 15-month refund period in the second quarter of 2014.

On December 8, 2014, the parties that filed the February 2013 complaint filed a second complaint against Pepco, DPL, ACE, as well as BGE, regarding the base transmission ROE, seeking a reduction from 10.8% to 8.8%. By order issued on February 9, 2015, FERC established a hearing on the second complaint and established a second 15-month refund period that commenced on December 8, 2014. Consistent with the prior challenge, ACE applied an estimated ROE based on the two-step methodology described above, and in the fourth quarter of 2014 and in the first, second and third quarters of 2015 established reserves for the estimated refund based on the effective date of the second refund period of December 8, 2014. On February 20, 2015, the chief judge issued an order consolidating the two complaint proceedings and established an initial decision issuance deadline of February 29, 2016. On March 2, 2015, the presiding administrative law judge issued an order establishing a procedural schedule for the consolidated proceedings that provided for the hearing to commence on October 20, 2015.

Also during the third quarter of 2015, ACE further evaluated the reserves established for each of the two refund periods and, based on an updated assessment of market conditions, developments in other cases before FERC, litigation risk and other factors, increased its reserves to reflect management’s best estimate of the refund that is expected to result from these consolidated proceedings. A settlement entered into by the parties regarding the protocols (but not the ROE) raised in the February 2013 complaint was submitted to FERC on July 31, 2015 and was approved by FERC in November 2015.

On November 6, 2015, the parties filed a settlement agreement with FERC regarding the ROE. This settlement agreement provides for (i) a base ROE of 10.0%, effective March 8, 2016, to which a 50-basis-point incentive adder will be applied for being a member of a regional transmission organization, and (ii) customer refunds in the amount of approximately $9.5 million for ACE covering the two 15-month refund periods described above. In addition, under this settlement agreement, no party may file to change the base ROE or any incentives prior to June 1, 2018. The parties have requested that FERC approve this settlement agreement by March 16, 2016, in order to incorporate the new ROE and applicable refunds into each utility’s 2016 transmission formula rate update. As of December 31, 2015, ACE’s reserves for both of the refund periods totaled $8 million as required under the settlement agreement.

ACE Standard Offer Capacity Agreements

In April 2011, ACE entered into three Standard Offer Capacity Agreements (SOCAs) by order of the NJBPU, each with a different generation company. ACE entered into the SOCAs under protest, as did the other electric distribution companies (EDCs) in New Jersey, 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). In October 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 ruled that the NJ SOCA Law is preempted by the Federal Power Act (FPA) and violates the Supremacy Clause, and is therefore null and void. In October 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 in September 2014. In November 2014 and December 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. The U.S. Supreme Court has not yet agreed to review the Third Circuit decision and the petitions for such review remain pending.

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.

In response to the October 2013 Federal district court order, ACE, in the fourth quarter of 2013, derecognized both the derivative assets (liabilities) for the estimated fair value of the SOCAs and the related regulatory liabilities (assets) that it had established with respect to the SOCAs.

Merger Approval Proceedings

New Jersey

On June 18, 2014, Exelon, PHI and ACE, and certain of their respective affiliates, filed a petition with the NJBPU seeking approval of the Merger. To approve the Merger, the NJBPU must find the Merger is in the public interest, and consider the impact of the Merger on (i) competition, (ii) rates of ratepayers affected by the Merger, (iii) ACE’s employees, and (iv) the provision of safe and reliable service at just and reasonable rates. On January 14, 2015, PHI, ACE, Exelon, certain of Exelon’s affiliates, the Staff of the NJBPU, and the Independent Energy Producers of New Jersey filed a stipulation of settlement (the Stipulation) with the NJBPU in this proceeding. On February 11, 2015, the NJBPU approved the Stipulation and the Merger and on March 6, 2015, the NJBPU issued a written order approving the Stipulation.

The NJBPU order states that the Merger must be closed by November 1, 2015 unless extended by the NJBPU. On October 15, 2015, the NJBPU voted to extend the effectiveness of its Merger approval until June 30, 2016.

Federal Energy Regulatory Commission

On May 30, 2014, Exelon, PHI, Pepco, DPL and ACE, and certain of their respective affiliates, submitted to FERC a Joint Application for Authorization of Disposition of Jurisdictional Assets and Merger under Section 203 of the FPA. Under that section, FERC shall approve a merger if it finds that the proposed transaction will be consistent with the public interest. On November 20, 2014, FERC issued an order approving the Merger.