Regulatory Matters

12 Months Ended

Dec. 31, 2014

Regulatory Matters

(7) REGULATORY MATTERS

Regulatory Assets and Regulatory Liabilities

The components of Pepco Holdings’ regulatory asset and liability balances at December 31, 2014 and 2013 are as follows:

	2014		2013
	(millions of dollars)
Regulatory Assets
Pension and other postretirement benefit costs	$	946	$	667
Securitized stranded costs		278		350
Recoverable income taxes		274		225
Demand-side management costs		264		125
Smart Grid costs		261		251
Deferred energy supply costs		73		136
Incremental storm restoration costs		51		72
Deferred debt extinguishment costs		42		47
MAPP abandonment costs		33		68
Recoverable workers’ compensation and long-term disability costs		30		26
Deferred losses on gas derivatives		4		—
Other		153		120
Total Regulatory Assets	$	2,409	$	2,087
Regulatory Liabilities
Asset removal costs	$	250	$	275
Deferred income taxes due to customers		44		45
Deferred energy supply costs		3		46
Deferred gains on gas derivatives		—		1
Other		46		32
Total Regulatory Liabilities	$	343	$	399

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.

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 2015 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.

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.

Demand-Side Management Costs: Represents costs associated with customer energy efficiency and conservation programs in all jurisdictions that are being recovered from customers. 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.

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.

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 (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.

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. For additional information, see “MAPP Settlement Agreement” discussion below. 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.

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.

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.

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.

Deferred Gains on Gas Derivatives: Represents gains associated with hedges of natural gas purchases that will be refunded to customers through the GCR approved by the DPSC.

Other: Represents miscellaneous regulatory liabilities.

Rate Proceedings

The following table shows, for each of PHI’s utility subsidiaries, the distribution base rate cases completed in 2014. Additional information concerning each of these cases is provided in the discussion below.

Jurisdiction/Company	Approved Revenue Requirement Increase		Approved Return on Equity			Completion Date	Rate Effective Date
	(millions of dollars)
DC – Pepco	$	23.4		9.40	%	March 26, 2014	April 16, 2014
DE – DPL (Electric)	$	15.1		9.70	%	August 5, 2014	May 1, 2014
MD – Pepco	$	8.8		9.62	%	July 2, 2014	July 4, 2014
NJ – ACE	$	19.0		9.75	%	August 20, 2014	September 1, 2014

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.

Bill Stabilization Adjustment

PHI’s utility subsidiaries have proposed in each of their respective jurisdictions the adoption of a mechanism to decouple retail distribution revenue from the amount of power delivered to retail customers. To date:

• A BSA has been approved and implemented for Pepco and DPL electric service in Maryland and for Pepco electric service in the District of Columbia.

• A proposed modified fixed variable rate design (MFVRD) for DPL electric and natural gas service in Delaware was filed in 2009 for consideration by the DPSC and while there was little to no activity associated with this filing in 2014 or to date in 2015, the proceeding remains open.

• In New Jersey, a BSA proposed by ACE in 2009 was not approved and there is no BSA proposal currently pending.

Under the BSA, customer distribution rates are subject to adjustment (through a credit or surcharge mechanism), depending on whether actual distribution revenue per customer exceeds or falls short of the revenue-per-customer amount approved by the applicable public service commission. The MFVRD proposed in Delaware contemplates a fixed customer charge (i.e., not tied to the customer’s volumetric consumption of electricity or natural gas) to recover the utility’s fixed costs, plus a reasonable rate of return.

Delaware

Electric Distribution Base Rates

On March 22, 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 return on equity (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. On August 5, 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.

On September 4, 2014, DPL filed an appeal with the Delaware Superior Court of the DPSC’s August 5, 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 recovery of credit facility expenses. The Division of the Public Advocate filed a cross-appeal on September 8, 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 have agreed to suspend the appeal and to withdraw the appeal with prejudice upon the closing of the Merger.

Under the Merger Agreement, DPL is not permitted to initiate or file any new electric distribution base rate cases in Delaware without Exelon’s consent.

Forward Looking Rate Plan

On October 2, 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.

On October 22, 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. 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 has agreed to withdraw the FLRP without prejudice to refile it in a subsequent base rate case.

Gas Distribution Base Rates

A settlement approved in October 2013 by the DPSC in a proceeding filed by DPL in December 2012 to increase its natural gas distribution base rates provides in part for a phase-in of the recovery of the deferred costs associated with DPL’s deployment of the interface management unit (IMU). The IMU is part of DPL’s AMI and allows for the remote reading of gas meters. Filing for recovery of such costs will occur in two phases, subject to compliance with specific metrics, with recovery over a 15-year period. For the first phase, 50% of the IMU-related portion of DPL’s AMI costs were put into rates on July 11, 2014. The remainder of these costs will be put into rates in the second phase when the specific metrics allowing for recovery are met.

Under the Merger Agreement, DPL is not permitted to initiate or file any new gas distribution base rate cases without Exelon’s consent.

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. On August 29, 2014, DPL made its 2014 GCR filing in which it proposed a GCR decrease of approximately 7.4%. On September 30, 2014, the DPSC issued an order authorizing DPL to place the new rates into effect on November 1, 2014, subject to refund and pending final DPSC approval.

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

District of Columbia

On March 8, 2013, Pepco filed an application with the DCPSC to increase its annual electric distribution base rates by approximately $52.1 million (adjusted by Pepco to approximately $44.8 million on December 3, 2013), 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. On March 26, 2014, the DCPSC issued an order approving an increase in base rates of approximately $23.4 million, based on an ROE of 9.40%. The new rates became effective on April 16, 2014.

Under the Merger Agreement, Pepco is not permitted to initiate or file any new electric distribution base rate cases in the District of Columbia without Exelon’s consent.

Maryland

Pepco Electric Distribution Base Rates

Under the Merger Agreement, Pepco is permitted, and intends to continue, to pursue the conclusion of the following matters. However, Pepco is not permitted to initiate or file any new electric distribution base rate cases in Maryland without Exelon’s consent.

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 (OPC) 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

On November 30, 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%.

On July 12, 2013, the MPSC issued an order related to Pepco’s November 30, 2012 application 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, the MPSC’s July 2012 order in Pepco’s previous electric distribution base rate case, which allowed Pepco to recover the costs of meters installed during the 2011 test year for that case, remains in effect, and the Maryland OPC’s motion for rehearing in that case remains pending.

The July 12, 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. 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.

On July 26, 2013, Pepco filed a notice of appeal of the July 12, 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. On November 14, 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 appealed, the Circuit Court affirmed the MPSC’s July 12, 2013 order. Pepco will not appeal this decision, but other parties have filed notices of appeal of the Circuit Court’s decision to the Court of Special Appeals.

Phase II Proceeding to 2012 Base Rate Proceeding

On August 26, 2014, the MPSC issued an order establishing a Phase II proceeding pertaining to the base rate case filed in November 2012 to address an issue regarding Pepco’s net operating loss carryforward (NOLC). The issue in this Phase II proceeding is the same as for the Phase II proceeding described below. Pepco filed a motion to dismiss this 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. On September 11, 2014, the MPSC issued an order staying this Phase II proceeding until further notice.

2013 Base Rate Proceeding

On December 4, 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. On July 2, 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. On July 31, 2014, Pepco filed a petition for rehearing seeking reconsideration of the recovery of certain expenses, which the MPSC denied by its order dated November 13, 2014. On December 11, 2014, Pepco filed a petition for judicial review of this MPSC order with the Circuit Court for Baltimore City. This petition remains pending.

Phase II Proceeding to 2013 Base Rate Proceeding

On August 26, 2014, the MPSC issued an order establishing a Phase II proceeding pertaining to the base rate case filed in December 2013 to address an issue regarding Pepco’s NOLC. Specifically, the MPSC considered the tax implications of Pepco’s NOLC, which had impacted certain of Pepco’s rate adjustments in the 2013 base rate proceeding. On November 13, 2014, the MPSC issued its order in this Phase II proceeding upholding Pepco’s treatment of the NOLC.

New Jersey

Electric Distribution Base Rates

On March 14, 2014, ACE submitted an application with the NJBPU to increase its electric distribution base rates by approximately $61.7 million (excluding sales and use taxes), based on a requested ROE of 10.25%. The requested rate increase sought to recover expenses associated with ACE’s ongoing investments in reliability enhancement improvements and efforts to maintain safe and reliable service. On August 20, 2014, the NJBPU approved a Stipulation of Settlement entered into by ACE, NJBPU staff and the Division of Rate Counsel (DRC). The approved stipulation of settlement provides for an annual increase in ACE’s electric distribution base rates by the net amount of approximately $19.0 million (excluding sales and use taxes), based on a specified ROE of 9.75%. The new electric distribution base rates became effective for service rendered by ACE on and after September 1, 2014. The annual pre-tax earnings impact of the rate increase is approximately $19.0 million.

Under the Merger Agreement, ACE is not permitted to initiate or file any new electric distribution base rate cases in New Jersey without Exelon’s consent.

Update and Reconciliation of Certain Under-Recovered Balances

On March 3, 2014, ACE submitted a 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, (ii) costs related to surcharges for the New Jersey Societal Benefit Program (a statewide public interest program that is intended to benefit low income customers and address other public policy goals) and ACE’s uncollected accounts and (iii) operating costs associated with ACE’s residential appliance cycling program. The net impact of adjusting the charges as proposed would have been an overall annual rate decrease of approximately $24.5 million (revised to a decrease of approximately $41.1 million on April 16, 2014, based upon an update for actual data through March 2014). In May 2014, the NJBPU approved a stipulation of settlement entered into by the parties in this proceeding providing for an overall annual rate decrease of $41.1 million. The rate decrease was placed into effect provisionally on June 1, 2014, subject to a review by the NJBPU of the final underlying costs for reasonableness and prudence. On January 21, 2015, the NJBPU approved a stipulation of settlement in this proceeding, which made final the provisional rates that were placed into effect on June 1, 2014. The rate decrease will have no effect on ACE’s operating income.

This proceeding is not expected to be affected by the Merger Agreement.

Service Extension Contributions Refund Order

On July 19, 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 received less than $1 million in refund claims, the validity of which is being investigated by ACE prior to making any such refunds. At this time, ACE does not expect that any such amount refunded will have a material effect on its consolidated financial condition, results of operations or cash flows, as any amounts that may be refunded will generally increase the value of ACE’s property, plant and equipment and may ultimately be recovered through depreciation and cost of service. On September 30, 2014, the NJBPU commenced a rulemaking proceeding to further implement the directives of the Appellate Division decision and, on December 1, 2014, published a rule proposal for comment. The changes proposed by the NJBPU remove provisions distinguishing between growth areas and not-for-growth areas and provide formulae for allocating extension costs.

Under the Merger Agreement, ACE is permitted to pursue the conclusion of this matter and intends to continue to do so.

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 dated October 22, 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. With this revised methodology, ACE anticipates that the negative effects of the CTA in future base rate cases will be significantly reduced.

On November 5, 2014, the DRC filed an appeal of the NJBPU’s CTA order in the Appellate Division. This appeal remains pending.

Under the Merger Agreement, ACE is permitted to pursue the conclusion of this matter and intends to continue to do so.

Federal Energy Regulatory Commission

Transmission Annual Formula Rate Update Challenges

In October 2013, FERC issued a ruling on challenges filed by the Delaware Municipal Electric Corporation, Inc. (DEMEC) to DPL’s 2011 and 2012 annual formula rate updates for transmission service. In 2006, FERC approved a formula rate for DPL that is incorporated into the PJM tariff. The formula rate establishes the treatment of costs and revenues and the resulting rates for DPL. Pursuant to the protocols approved by FERC and after a period of discovery, interested parties have an opportunity to file challenges regarding the application of the formula rate. The October 2013 FERC order set various issues in this proceeding for hearing, including challenges regarding formula rate inputs, deferred income items, prepayments of estimated income taxes, rate base reductions, various administrative and general expenses and the inclusion in rate base of construction work in progress related to the MAPP project abandoned by PJM. Settlement discussions began in this matter in November 2013 before an administrative law judge at FERC.

In December 2013, DEMEC filed a formal challenge to the DPL 2013 annual formula rate update for transmission service, including a request to consolidate the 2013 challenge with the two prior challenges. The issues in the challenges for 2011, 2012 and 2013 are similar. On April 8, 2014, FERC issued an order setting the 2013 challenge issues for hearing and on April 15, 2014, those issues were consolidated with the 2011 and 2012 challenges. A settlement agreement was filed with FERC on August 25, 2014. On January 9, 2015, FERC issued an order approving the settlement, thereby resolving all of the issues set for hearing in the proceeding. Pursuant to the settlement, DPL will provide a one-time reduction of $225,000 to DPL’s 2015 annual formula rate update and will provide a one-time payment of $258,500 to DEMEC. In addition, the settlement resolves certain ratemaking and accounting treatments prospectively and provides that certain items will not be challenged in the future.

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 DEMEC, 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 the application of the formula rate process, each associated with the transmission service that PHI’s 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. PHI, Pepco, DPL and ACE believe the allegations in this complaint are without merit and are vigorously contesting it. 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 February 27, 2013 as the refund effective date, should a refund result from this proceeding. After settlement discussions among the parties in this matter reached an impasse, on November 24, 2014, the settlement judge issued an order terminating the settlement discussions. The matter is now before a hearing judge and a procedural schedule will be established for both the February 2013 complaint and a second complaint (discussed below) that has been consolidated with the February 2013 complaint.

On June 19, 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 period over which each of their transmission revenues would be subject to refund as a result of the challenge, and recorded estimated reserves in the second quarter of 2014 related to this matter. To the extent that the final ROE determined by FERC is lower than the ROE used to record the estimated reserves, each ten basis point reduction in the ROE would result in a reduction of PHI’s operating income of $1.5 million.

A second complaint against Pepco, DPL and ACE challenging the base ROE was filed at FERC on December 8, 2014 by the same parties. Employing the new ROE methodology referenced above, the complainants contend that the resulting base ROE should be 8.8%, and request consolidation of this complaint with the February 2013 complaint. Consistent with the prior challenge, Pepco, DPL and ACE applied an estimated ROE based on the two-step methodology described above, and recorded estimated reserves in the fourth quarter of 2014 using a refund effective date of December 8, 2014.

Under the Merger Agreement, PHI is permitted to pursue the conclusion of these FERC matters and intends to continue to do so.

MPSC New Generation Contract Requirement

In April 2012, the MPSC issued an order that requires 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 will construct a 661 MW natural gas-fired combined cycle generation plant in Waldorf, Maryland, with an expected commercial operation date of June 1, 2015, and each of the Contract EDCs will recover its costs associated with the contract through surcharges on its respective SOS customers.

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

On October 24, 2013, the Federal district court issued an order ruling that the contracts are illegal and unenforceable. The Federal district court order and its associated ruling could impact the state circuit court appeal, to which the Contract EDCs are parties, although such impact, if any, cannot be determined at this time. 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 lower Federal court ruling. On November 26, 2014, both the winning bidder and the MPSC petitioned the U.S. Supreme Court to consider hearing an appeal of the Fourth Circuit decision.

The Maryland Court of Special Appeals has stayed the appeal of the Baltimore City Circuit Court decision until July 23, 2015.

On June 2, 2014, the winning bidder filed the contracts at FERC requesting that they be accepted pursuant to Section 205 of the Federal Power Act (FPA). On August 5, 2014, FERC issued an order rejecting the filings made by the winning bidder, finding that the contracts cannot be accepted as valid contracts, given the decisions reached in the Federal court proceedings discussed above.

Assuming the contracts, as currently written, were to become effective by the expected commercial operation date of June 1, 2015, 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 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.

Under the Merger Agreement, PHI is permitted to pursue the conclusion of this matter and intends to continue to do so.

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 and the other New Jersey EDCs entered into the SOCAs under protest, arguing that the EDCs were denied due process and that the SOCAs violate certain of the requirements under the New Jersey law under which the SOCAs were established (the NJ SOCA Law). On October 22, 2013, in light of the decision of the U.S. District Court for the District of New Jersey described below, the state appeals of the NJBPU implementation orders filed by the EDCs and generators were dismissed without prejudice subject to the parties exercising their appellate rights in the Federal courts.

In February 2011, ACE joined other plaintiffs in an action filed in the U.S. District Court for the District of New Jersey challenging the NJ SOCA Law on the grounds that it violates the Commerce Clause and the Supremacy Clause of the U.S. Constitution. On October 11, 2013, the Federal district court issued a ruling that the NJ SOCA Law is preempted by the FPA and violates the Supremacy Clause, and is therefore null and void. On October 25, 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. On November 26, 2014 and December 10, 2014, respectively, one of the generation companies and the NJBPU petitioned the U.S. Supreme Court to consider hearing an appeal of the Third Circuit decision.

One of the three SOCAs was terminated effective July 1, 2013 because of an event of default of the generation company that was a party to the SOCA. The remaining two SOCAs were terminated effective November 19, 2013, as a result of a termination notice delivered by ACE after the Federal district court’s October 25, 2013 decision.

Despite the terminated status of the SOCAs, on June 2, 2014, one of the generation companies that was a party to a SOCA filed the SOCA at FERC seeking to have the SOCA accepted under Section 205 of the FPA. The EDCs intervened in the proceeding and requested that the generation company’s filing be rejected on the grounds that the SOCA never came into effect. On August 5, 2014, FERC issued an order rejecting the filings made by the generation company, finding that the contracts cannot be accepted as valid contracts, given the decisions reached in the Federal court proceedings discussed above.

In light of the October 25, 2013 Federal district court order, ACE derecognized both the derivative assets (liabilities) for the estimated fair value of the SOCAs and the related regulatory liabilities (assets) in the fourth quarter of 2013.

District of Columbia Power Line Undergrounding Initiative

On May 3, 2014, the Council of the District of Columbia enacted the Electric Company Infrastructure Improvement Financing Act of 2014 (the Improvement Financing Act), which provides enabling legislation for the 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 remit to the District of Columbia; and (iii) the remaining amount is to be covered by the existing capital projects program of the District of Columbia Department of Transportation (DDOT). Pepco will not earn a return on or a return of the cost of the assets funded with the proceeds of the securitized bonds or assets that are constructed by DDOT under its capital projects program, but ownership and responsibility for the operation and maintenance of such assets will be transferred to Pepco for a nominal amount.

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

On November 12, 2014, the DCPSC issued an order approving the Triennial Plan and Pepco’s volumetric surcharge, and on November 24, 2014, the DCPSC issued the financing order. 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 on January 22, 2015 and February 2, 2015, respectively.

On December 4, 2014, a party filed a petition for review with the District of Columbia Court of Appeals disputing the DCPSC’s denial of its motion to intervene. The procedural schedule for the petition has not yet been set.

Under the Merger Agreement, Pepco is permitted to pursue the DC PLUG initiative and intends to continue to do so.

MAPP Settlement Agreement

In February 2014, FERC issued an order approving the settlement agreement submitted by Pepco and DPL in connection with Pepco’s and DPL’s proceeding seeking recovery of approximately $88 million in abandonment costs related to the MAPP project. PHI had been directed by PJM to construct the MAPP project, a 152-mile high-voltage interstate transmission line, and in August 2012 was directed by PJM to cancel it. The abandonment costs sought for recovery were subsequently reduced to $82 million as a result of write-offs of certain disallowed costs in 2013 and transfers of materials to inventories for use on other projects. Under the terms of the FERC-approved settlement agreement, Pepco and DPL will receive $80.5 million of transmission revenues over a three-year period, which began on June 1, 2013, and will retain title to all real property and property rights acquired in connection with the MAPP project, which had an estimated fair value of $8 million. The FERC-approved settlement agreement resolves all issues concerning the recovery of abandonment costs associated with the cancellation of the MAPP project, and the terms of the settlement agreement are not subject to modification through any other FERC proceeding. As of December 31, 2014, PHI had recorded a regulatory asset related to the MAPP abandonment costs of approximately $33 million, net of amortization, and land of $8 million. PHI expects to recognize pre-tax income related to the MAPP abandonment costs of $1 million in 2015.

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. The settling parties also requested that the scheduled hearings be suspended. The settlement requests that hearings regarding DPSC approval of the settlement be held in April 2015 and that the decision of the DPSC be issued thereafter in April 2015.

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 has scheduled evidentiary hearings for March 30, 2015 to April 8, 2015.

Maryland

On August 19, 2014, Exelon, PHI, Pepco and 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. In making this determination, the MPSC is required to consider the following 12 criteria: (i) the potential impact of the merger on rates and charges paid by customers and on the services and conditions of operation of the utility; (ii) the potential impact of the merger on continuing investment needs for the maintenance of utility services, plant and related infrastructure; (iii) the proposed capital structure that will result from the merger, including allocation of earnings from the utility; (iv) the potential effects on employment by the utility; (v) the projected allocation between the utility’s shareholders and ratepayers of any savings that are expected; (vi) issues of reliability, quality of service and quality of customer service; (vii) the potential impact of the merger on community investment; (viii) affiliate and cross-subsidization issues; (ix) the use or pledge of utility assets for the benefit of an affiliate; (x) jurisdictional and choice-of-law issues; (xi) whether it is necessary to revise the MPSC’s ring-fencing and affiliate code of conduct regulations in light of the merger; and (xii) any other issues the MPSC considers relevant to the assessment of the merger. The MPSC is required to issue an order within 180 days of the August 19, 2014 filing date. However, the MPSC can grant a 45-day extension for good cause. If no order is issued by the statutory deadline, then the Merger would be deemed to be approved. On September 22, 2014, the MPSC issued an order setting the procedural schedule for this matter. Pursuant to that schedule, evidentiary hearings were held beginning on January 26, 2015, and all briefs are scheduled to be filed in March 2015. The deadline for the MPSC’s decision is April 8, 2015.

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 July 23, 2014, the NJBPU voted to retain this matter, rather than assigning it to an administrative law judge. 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.

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 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 on August 6, 2014. Following informal discussions with the DOJ, effective as of September 5, 2014, Exelon withdrew its Notification and Report Form and refiled it on September 9, 2014, which restarted the waiting period required by the HSR Act. On October 9, 2014, each of Pepco Holdings and Exelon received a request for additional information and documentary material from the DOJ, which had the effect of extending the DOJ review period until 30 days after each of Pepco Holdings and Exelon certified that it has substantially complied with the request. On November 21, 2014, each of Pepco Holdings and Exelon certified that it had substantially complied with the request. Accordingly, the HSR Act waiting period expired on December 22, 2014, and the HSR Act no longer precludes completion of the Merger. Although the DOJ allowed the waiting period under the HSR Act to expire without taking any action with respect to the Merger, the DOJ has not advised Pepco Holdings or Exelon that it has concluded its investigation.

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, 2014 and 2013 are as follows:

	2014		2013
	(millions of dollars)
Regulatory Assets
Smart Grid costs	$	86	$	83
Recoverable income taxes		84		76
Demand-side management costs		67		27
COPCO acquisition adjustment		18		22
MAPP abandonment costs		14		31
Deferred debt extinguishment costs		12		13
Deferred energy supply costs		12		13
Incremental storm restoration costs		7		9
Deferred losses on gas derivatives		4		—
Other		52		37
Total Regulatory Assets	$	356	$	311
Regulatory Liabilities
Asset removal costs	$	166	$	173
Deferred income taxes due to customers		37		37
Deferred energy supply costs		—		3
Deferred gains on gas derivatives		—		1
Other		22		15
Total Regulatory Liabilities	$	225	$	229

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

Smart Grid Costs: Represents advanced metering infrastructure (AMI) 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.

Demand-Side Management Costs: Represents recoverable costs associated with customer energy efficiency and conservation programs in all jurisdictions that are being recovered from customers. DPL earns a return on these regulatory assets.

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.

MAPP Abandonment Costs: Represents abandonment costs incurred in connection with the Mid-Atlantic Power Pathway (MAPP) transmission line construction project which was terminated on August 24, 2012. For additional information, see “MAPP Settlement Agreement” discussion below. 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 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.

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 are 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.

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, 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.

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.

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.

Deferred Gains on Gas Derivatives: Represents gains associated with hedges of natural gas purchases that will be refunded to customers through the GCR approved by the DPSC.

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 the pending filings indicated below.

Bill Stabilization Adjustment

DPL has 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. To date:

• A BSA has been approved and implemented for DPL electric service in Maryland.

• A proposed modified fixed variable rate design (MFVRD) for DPL electric and natural gas service in Delaware was filed in 2009 for consideration by the DPSC and while there was little to no activity associated with this filing in 2014, or to date in 2015, the proceeding remains open.

Under a BSA, customer distribution rates are subject to adjustment (through a credit or surcharge mechanism), depending on whether actual distribution revenue per customer exceeds or falls short of the revenue-per-customer amount approved by the applicable public service commission. The MFVRD proposed in Delaware contemplates a fixed customer charge (i.e., not tied to the customer’s volumetric consumption of electricity or natural gas) to recover the utility’s fixed costs, plus a reasonable rate of return.

Delaware

Electric Distribution Base Rates

On March 22, 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 return on equity (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. On August 5, 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.

On September 4, 2014, DPL filed an appeal with the Delaware Superior Court of the DPSC’s August 5, 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 recovery of credit facility expenses. The Division of the Public Advocate filed a cross-appeal on September 8, 2014, pertaining to the treatment of 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 have agreed to suspend the appeal and to withdraw the appeal with prejudice upon the closing of the Merger.

Forward Looking Rate Plan

On October 2, 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.

On October 22, 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. 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 has agreed to withdraw the FLRP without prejudice to refile it in a subsequent base rate case.

Gas Distribution Base Rates

A settlement approved in October 2013 by the DPSC in a proceeding filed by DPL in December 2012 to increase its natural gas distribution base rates provides in part for a phase-in of the recovery of the deferred costs associated with DPL’s deployment of the interface management unit (IMU). The IMU is part of DPL’s AMI and allows for the remote reading of gas meters. Filing for recovery of such costs will occur in two phases, subject to compliance with specific metrics, with recovery over a 15-year period. For the first phase, 50% of the IMU-related portion of DPL’s AMI costs were put into rates on July 11, 2014. The remainder of these costs will be put into rates in the second phase when the specific metrics allowing for recovery are met.

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. On August 29, 2014, DPL made its 2014 GCR filing in which it proposed a GCR decrease of approximately 7.4%. On September 30, 2014, the DPSC issued an order authorizing DPL to place the new rates into effect on November 1, 2014, subject to refund and pending final DPSC approval.

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

Federal Energy Regulatory Commission

Transmission Annual Formula Rate Update Challenges

In October 2013, FERC issued a ruling on challenges filed by the Delaware Municipal Electric Corporation, Inc. (DEMEC) to DPL’s 2011 and 2012 annual formula rate updates for transmission service. In 2006, FERC approved a formula rate for DPL that is incorporated into the PJM Interconnection, LLC (PJM) tariff. The formula rate establishes the treatment of costs and revenues and the resulting rates for DPL. Pursuant to the protocols approved by FERC and after a period of discovery, interested parties have an opportunity to file challenges regarding the application of the formula rate. The October 2013 FERC order set various issues in this proceeding for hearing, including challenges regarding formula rate inputs, deferred income items, prepayments of estimated income taxes, rate base reductions, various administrative and general expenses and the inclusion in rate base of construction work in progress related to the MAPP project abandoned by PJM. Settlement discussions began in this matter in November 2013 before an administrative law judge at FERC.

In December 2013, DEMEC filed a formal challenge to the DPL 2013 annual formula rate update for transmission service, including a request to consolidate the 2013 challenge with the two prior challenges. The issues in the challenges for 2011, 2012 and 2013 are similar. On April 8, 2014, FERC issued an order setting the 2013 challenge issues for hearing and on April 15, 2014, those issues were consolidated with the 2011 and 2012 challenges. A settlement agreement was filed with FERC on August 25, 2014. On January 9, 2015, FERC issued an order approving the settlement, thereby resolving all of the issues set for hearing in the proceeding. Pursuant to the settlement, DPL will provide a one-time reduction of $225,000 to DPL’s 2015 annual formula rate update and will provide a one-time payment of $258,500 to DEMEC. In addition, the settlement resolves certain ratemaking and accounting treatments prospectively and provides that certain items will not be challenged in the future.

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 DEMEC, filed a joint complaint at FERC against DPL and its affiliates Potomac Electric Power Company (Pepco) and Atlantic City Electric Company (ACE), as well as Baltimore Gas and Electric Company (BGE). The complainants challenged the base ROE and the application of the formula rate process, each associated with the transmission service that PHI’s 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 DPL and its utility affiliates 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 is eligible for a 50-basis-point incentive adder for being a member of a regional transmission organization. DPL believes the allegations in this complaint are without merit and is vigorously contesting it. 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 February 27, 2013 as the refund effective date, should a refund result from this proceeding. After settlement discussions among the parties in this matter reached an impasse, on November 24, 2014, the settlement judge issued an order terminating the settlement discussions. The matter is now before a hearing judge and a procedural schedule will be established for both the February 2013 complaint and a second complaint (discussed below) that has been consolidated with the February 2013 complaint.

On June 19, 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 period over which its transmission revenues would be subject to refund as a result of the challenge, and recorded estimated reserves in the second quarter of 2014 related to this matter. To the extent that the final ROE determined by FERC is lower than the ROE used to record the estimated reserves, each ten basis point reduction in the ROE would result in a reduction of DPL’s operating income of $0.5 million.

A second complaint against Pepco, DPL and ACE challenging the base ROE was filed at FERC on December 8, 2014 by the same parties. Employing the new ROE methodology referenced above, the complainants contend that the resulting base ROE should be 8.8%, and request consolidation of this complaint with the February 2013 complaint. Consistent with the prior challenge, DPL applied an estimated ROE based on the two-step methodology described above, and recorded estimated reserves in the fourth quarter of 2014 using a refund effective date of December 8, 2014.

Under the Merger Agreement, DPL is permitted to pursue the conclusion of these FERC matters and intends to continue to do so.

MPSC New Generation Contract Requirement

In April 2012, the MPSC issued an order that requires 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 will construct a 661 MW natural gas-fired combined cycle generation plant in Waldorf, Maryland, with an expected commercial operation date of June 1, 2015, and each of the Contract EDCs will recover its costs associated with the contract through surcharges on its respective SOS customers.

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

On October 24, 2013, the Federal district court issued an order ruling that the contracts are illegal and unenforceable. The Federal district court order and its associated ruling could impact the state circuit court appeal, to which the Contract EDCs are parties, although such impact, if any, cannot be determined at this time. 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 lower Federal court ruling. On November 26, 2014, both the winning bidder and the MPSC petitioned the U.S. Supreme Court to consider hearing an appeal of the Fourth Circuit decision.

The Maryland Court of Special Appeals has stayed the appeal of the Baltimore City Circuit Court decision until July 23, 2015.

On June 2, 2014, the winning bidder filed the contracts at FERC requesting that they be accepted pursuant to Section 205 of the Federal Power Act (FPA). On August 5, 2014, FERC issued an order rejecting the filings made by the winning bidder, finding that the contracts cannot be accepted as valid contracts, given the decisions reached in the Federal court proceedings discussed above.

Assuming the contracts, as currently written, were to become effective by the expected commercial operation date of June 1, 2015, 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 DPL would 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.

Under the Merger Agreement, DPL is permitted to pursue the conclusion of this matter and intends to continue to do so.

MAPP Settlement Agreement

In February 2014, FERC issued an order approving the settlement agreement submitted by DPL in connection with DPL’s proceeding seeking recovery of approximately $38 million in abandonment costs related to the MAPP project. DPL had been directed by PJM to construct the MAPP project, a 152-mile high-voltage interstate transmission line, and in August 2012 was directed by PJM to cancel it. The abandonment costs sought for recovery were subsequently reduced to $37 million as a result of write-offs of certain disallowed costs in 2013. Under the terms of the FERC-approved settlement agreement, DPL will receive $36.6 million of transmission revenues over a three-year period, which began on June 1, 2013, and will retain title to all real property and property rights acquired in connection with the MAPP project, which had an estimated fair value of $6 million. The FERC-approved settlement agreement resolves all issues concerning the recovery of abandonment costs associated with the cancellation of the MAPP project, and the terms of the settlement agreement are not subject to modification through any other FERC proceeding. As of December 31, 2014, DPL had a regulatory asset related to the MAPP abandonment costs of approximately $14 million, net of amortization, and land of $6 million. DPL expects to recognize pre-tax income related to the MAPP abandonment costs of $1 million in 2015.

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. The settling parties also requested that the scheduled hearings be suspended. The settlement requests that hearings regarding DPSC approval of the settlement be held in April 2015 and that the decision of the DPSC be issued thereafter in April 2015.

Maryland

On August 19, 2014, Exelon, PHI, Pepco and 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. In making this determination, the MPSC is required to consider the following 12 criteria: (i) the potential impact of the merger on rates and charges paid by customers and on the services and conditions of operation of the utility; (ii) the potential impact of the merger on continuing investment needs for the maintenance of utility services, plant and related infrastructure; (iii) the proposed capital structure that will result from the merger, including allocation of earnings from the utility; (iv) the potential effects on employment by the utility; (v) the projected allocation between the utility’s shareholders and ratepayers of any savings that are expected; (vi) issues of reliability, quality of service and quality of customer service; (vii) the potential impact of the merger on community investment; (viii) affiliate and cross-subsidization issues; (ix) the use or pledge of utility assets for the benefit of an affiliate; (x) jurisdictional and choice-of-law issues; (xi) whether it is necessary to revise the MPSC’s ring-fencing and affiliate code of conduct regulations in light of the merger; and (xii) any other issues the MPSC considers relevant to the assessment of the merger. The MPSC is required to issue an order within 180 days of the August 19, 2014 filing date. However, the MPSC can grant a 45-day extension for good cause. If no order is issued by the statutory deadline, then the Merger would be deemed to be approved. On September 22, 2014, the MPSC issued an order setting the procedural schedule for this matter. Pursuant to that schedule, evidentiary hearings were held beginning on January 26, 2015, and all briefs are scheduled to be filed in March 2015. The deadline for the MPSC’s decision is April 8, 2015.

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, 2015, 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.

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, 2014 and 2013 are as follows:

	2014		2013
	(millions of dollars)
Regulatory Assets
Demand-side management costs	$	197	$	98
Smart Grid costs		175		168
Recoverable income taxes		148		107
Recoverable workers’ compensation and long-term disability costs		30		26
Incremental storm restoration costs		29		37
Deferred debt extinguishment costs		22		25
MAPP abandonment costs		19		37
Deferred energy supply costs		3		6
Other		74		59
Total Regulatory Assets	$	697	$	563
Regulatory Liabilities
Asset removal costs	$	84	$	102
Other		20		11
Total Regulatory Liabilities	$	104	$	113

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

Demand-Side Management Costs: Represents costs associated with customer energy efficiency and conservation programs in all jurisdictions that are being recovered from customers. 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 on August 24, 2012. For additional information, see “MAPP Settlement Agreement” discussion below. 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.

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.

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 the pending filings indicated below.

Bill Stabilization Adjustment

Pepco proposed in each of its respective jurisdictions the adoption of a BSA mechanism to decouple retail distribution revenue from the amount of power delivered to retail customers. The BSA proposal has been approved and implemented for Pepco electric service in Maryland and in the District of Columbia.

Under the BSA, customer distribution rates are subject to adjustment (through a credit or surcharge mechanism), depending on whether actual distribution revenue per customer exceeds or falls short of the revenue-per-customer amount approved by the applicable public service commission.

District of Columbia

On March 8, 2013, Pepco filed an application with the DCPSC to increase its annual electric distribution base rates by approximately $52.1 million (adjusted by Pepco to approximately $44.8 million on December 3, 2013), 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. On March 26, 2014, the DCPSC issued an order approving an increase in base rates of approximately $23.4 million, based on an ROE of 9.40%. The new rates became effective on April 16, 2014.

Maryland

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 (OPC) 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

On November 30, 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%.

On July 12, 2013, the MPSC issued an order related to Pepco’s November 30, 2012 application 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, the MPSC’s July 2012 order in Pepco’s previous electric distribution base rate case, which allowed Pepco to recover the costs of meters installed during the 2011 test year for that case, remains in effect, and the Maryland OPC’s motion for rehearing in that case remains pending.

The July 12, 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. 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.

On July 26, 2013, Pepco filed a notice of appeal of the July 12, 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. On November 14, 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 appealed, the Circuit Court affirmed the MPSC’s July 12, 2013 order. Pepco will not appeal this decision, but other parties have filed notices of appeal of the Circuit Court’s decision to the Court of Special Appeals.

Phase II Proceeding to 2012 Base Rate Proceeding

On August 26, 2014, the MPSC issued an order establishing a Phase II proceeding pertaining to the base rate case filed in November 2012 to address an issue regarding Pepco’s net operating loss carryforward (NOLC). The issue in this Phase II proceeding is the same as for the Phase II proceeding described below. Pepco filed a motion to dismiss this 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. On September 11, 2014, the MPSC issued an order staying this Phase II proceeding until further notice.

2013 Base Rate Proceeding

On December 4, 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. On July 2, 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. On July 31, 2014, Pepco filed a petition for rehearing seeking reconsideration of the recovery of certain expenses, which the MPSC denied by its order dated November 13, 2014. On December 11, 2014, Pepco filed a petition for judicial review of this MPSC order with the Circuit Court for Baltimore City. This petition remains pending.

Phase II Proceeding to 2013 Base Rate Proceeding

On August 26, 2014, the MPSC issued an order establishing a Phase II proceeding pertaining to the base rate case filed in December 2013 to address an issue regarding Pepco’s NOLC. Specifically, the MPSC considered the tax implications of Pepco’s NOLC, which had impacted certain of Pepco’s rate adjustments in the 2013 base rate proceeding. On November 13, 2014, the MPSC issued its order in this Phase II proceeding upholding Pepco’s treatment of the NOLC.

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 Delaware Municipal Electric Corporation, Inc., filed a joint complaint at FERC against Pepco, and its affiliates Delmarva Power & Light Company (DPL) and ACE, as well as Baltimore Gas and Electric Company (BGE). The complainants challenged the base ROE and the application of the formula rate process, each associated with the transmission service that PHI’s 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. Pepco believes the allegations in this complaint are without merit and is vigorously contesting it. 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 February 27, 2013 as the refund effective date, should a refund result from this proceeding. After settlement discussions among the parties in this matter reached an impasse, on November 24, 2014, the settlement judge issued an order terminating the settlement discussions. The matter is now before a hearing judge and a procedural schedule will be established for both the February 2013 complaint and a second complaint (discussed below) that has been consolidated with the February 2013 complaint.

On June 19, 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 period over which its transmission revenues would be subject to refund as a result of the challenge, and recorded estimated reserves in the second quarter of 2014 related to this matter. To the extent that the final ROE determined by FERC is lower than the ROE used to record the estimated reserves, each ten basis point reduction in the ROE would result in a reduction of Pepco’s operating income of $0.6 million.

A second complaint against Pepco, DPL and ACE challenging the base ROE was filed at FERC on December 8, 2014 by the same parties. Employing the new ROE methodology referenced above, the complainants contend that the resulting base ROE should be 8.8%, and request consolidation of this complaint with the February 2013 complaint. Consistent with the prior challenge, Pepco applied an estimated ROE based on the two-step methodology described above, and recorded estimated reserves in the fourth quarter of 2014 using a refund effective date of December 8, 2014.

Under the Merger Agreement, ACE is permitted to pursue the conclusion of these FERC matters and intends to continue to do so.

MPSC New Generation Contract Requirement

In April 2012, the MPSC issued an order that requires 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 will construct a 661 MW natural gas-fired combined cycle generation plant in Waldorf, Maryland, with an expected commercial operation date of June 1, 2015, and each of the Contract EDCs will recover its costs associated with the contract through surcharges on its respective SOS customers.

In response to a complaint filed by a group of generating companies in the PJM Interconnection, LLC (PJM) region, on September 30, 2013, the U.S. District Court for the District of Maryland 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, on October 1, 2013, in response to appeals filed by the Contract EDCs and other parties, the Maryland Circuit Court for Baltimore City upheld the MPSC’s orders requiring the Contract EDCs to enter into the contracts.

On October 24, 2013, the Federal district court issued an order ruling that the contracts are illegal and unenforceable. The Federal district court order and its associated ruling could impact the state circuit court appeal, to which the Contract EDCs are parties, although such impact, if any, cannot be determined at this time. 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 lower Federal court ruling. On November 26, 2014, both the winning bidder and the MPSC petitioned the U.S. Supreme Court to consider hearing an appeal of the Fourth Circuit decision.

The Maryland Court of Special Appeals has stayed the appeal of the Baltimore City Circuit Court decision until July 23, 2015.

On June 2, 2014, the winning bidder filed the contracts at FERC requesting that they be accepted pursuant to Section 205 of the Federal Power Act (FPA). On August 5, 2014, FERC issued an order rejecting the filings made by the winning bidder, finding that the contracts cannot be accepted as valid contracts, given the decisions reached in the Federal court proceedings discussed above.

Assuming the contracts, as currently written, were to become effective by the expected commercial operation date of June 1, 2015, 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 Pepco would 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.

Under the Merger Agreement, Pepco is permitted to pursue the conclusion of this matter and intends to continue to do so.

District of Columbia Power Line Undergrounding Initiative

On May 3, 2014, the Council of the District of Columbia enacted the Electric Company Infrastructure Improvement Financing Act of 2014 (the Improvement Financing Act), which provides enabling legislation for the 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 remit to the District of Columbia; and (iii) the remaining amount is to be covered by the existing capital projects program of the District of Columbia Department of Transportation (DDOT). Pepco will not earn a return on or a return of the cost of the assets funded with the proceeds of the securitized bonds or assets that are constructed by DDOT under its capital projects program, but ownership and responsibility for the operation and maintenance of such assets will be transferred to Pepco for a nominal amount.

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

On November 12, 2014, the DCPSC issued an order approving the Triennial Plan and Pepco’s volumetric surcharge, and on November 24, 2014, the DCPSC issued the financing order. 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 on January 22, 2015 and February 2, 2015, respectively.

On December 4, 2014, a party filed a petition for review with the District of Columbia Court of Appeals disputing the DCPSC’s denial of its motion to intervene. The procedural schedule for the petition has not yet been set.

Under the Merger Agreement, Pepco is permitted to pursue the DC PLUG initiative and intends to continue to do so.

MAPP Settlement Agreement

In February 2014, FERC issued an order approving the settlement agreement submitted by Pepco connection with Pepco’s proceeding seeking recovery of approximately $88 million in abandonment costs related to the MAPP project. Pepco had been directed by PJM to construct the MAPP project, a 152-mile high-voltage interstate transmission line, and in August 2012 was directed by PJM to cancel it. The abandonment costs sought for recovery were subsequently reduced to $45 million as a result of write-offs of certain disallowed costs in 2013 and transfers of materials to inventories for use on other projects. Under the terms of the FERC-approved settlement agreement, Pepco will receive approximately $43.9 million of transmission revenues over a three-year period, which began on June 1, 2013, and will retain title to all real property and property rights acquired in connection with the MAPP project, which had an estimated fair value of $2 million. The FERC-approved settlement agreement resolves all issues concerning the recovery of abandonment costs associated with the cancellation of the MAPP project, and the terms of the settlement agreement are not subject to modification through any other FERC proceeding. As of December 31, 2014, Pepco had a regulatory asset related to the MAPP abandonment costs of approximately $19 million, net of amortization, and land of $2 million. Pepco does not expect to recognize any further pre-tax income related to the MAPP abandonment costs.

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 has scheduled evidentiary hearings for March 30, 2015 to April 8, 2015.

Maryland

On August 19, 2014, Exelon, PHI, Pepco and 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. In making this determination, the MPSC is required to consider the following 12 criteria: (i) the potential impact of the merger on rates and charges paid by customers and on the services and conditions of operation of the utility; (ii) the potential impact of the merger on continuing investment needs for the maintenance of utility services, plant and related infrastructure; (iii) the proposed capital structure that will result from the merger, including allocation of earnings from the utility; (iv) the potential effects on employment by the utility; (v) the projected allocation between the utility’s shareholders and ratepayers of any savings that are expected; (vi) issues of reliability, quality of service and quality of customer service; (vii) the potential impact of the merger on community investment; (viii) affiliate and cross-subsidization issues; (ix) the use or pledge of utility assets for the benefit of an affiliate; (x) jurisdictional and choice-of-law issues; (xi) whether it is necessary to revise the MPSC’s ring-fencing and affiliate code of conduct regulations in light of the merger; and (xii) any other issues the MPSC considers relevant to the assessment of the merger. The MPSC is required to issue an order within 180 days of the August 19, 2014 filing date. However, the MPSC can grant a 45-day extension for good cause. If no order is issued by the statutory deadline, then the Merger would be deemed to be approved. On September 22, 2014, the MPSC issued an order setting the procedural schedule for this matter. Pursuant to that schedule, evidentiary hearings were held beginning on January 26, 2015, and all briefs are scheduled to be filed in March 2015. The deadline for the MPSC’s decision is April 8, 2015.

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.

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, 2014 and 2013 are as follows:

	2014		2013
	(millions of dollars)
Regulatory Assets
Securitized stranded costs	$	278	$	350
Deferred energy supply costs		58		117
Recoverable income taxes		42		42
Incremental storm restoration costs		15		26
Other		34		34
Total Regulatory Assets	$	427	$	569
Regulatory Liabilities
Federal and state tax benefits, related to securitized stranded costs	$	8	$	13
Deferred energy supply costs		—		38
Other		6		6
Total Regulatory Liabilities	$	14	$	57

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 2015 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.

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. The regulatory liability represents primarily deferred costs associated with a net over-recovery of energy supply costs incurred that will be refunded by ACE to customers.

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.

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, 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.

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.

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 the pending filings indicated below.

Bill Stabilization Adjustment

In 2009, ACE proposed in New Jersey the adoption of a bill stabilization adjustment (BSA) mechanism to decouple retail distribution revenue from the amount of power delivered to retail customers. The BSA proposal was not approved and there is no BSA proposal currently pending. Under a BSA, customer distribution rates would be subject to adjustment (through a credit or surcharge mechanism), depending on whether actual distribution revenue per customer exceeds or falls short of the revenue-per-customer amount approved by the applicable public service commission.

Electric Distribution Base Rates

On March 14, 2014, ACE submitted an application with the NJBPU to increase its electric distribution base rates by approximately $61.7 million (excluding sales and use taxes), based on a requested return on equity (ROE) of 10.25%. The requested rate increase sought to recover expenses associated with ACE’s ongoing investments in reliability enhancement improvements and efforts to maintain safe and reliable service. On August 20, 2014, the NJBPU approved a Stipulation of Settlement entered into by ACE, NJBPU staff and the Division of Rate Counsel (DRC). The approved stipulation of settlement provides for an annual increase in ACE’s electric distribution base rates by the net amount of approximately $19.0 million (excluding sales and use taxes), based on a specified ROE of 9.75%. The new electric distribution base rates became effective for service rendered by ACE on and after September 1, 2014. The annual pre-tax earnings impact of the rate increase is approximately $19.0 million.

Update and Reconciliation of Certain Under-Recovered Balances

On March 3, 2014, ACE submitted a 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, (ii) costs related to surcharges for the New Jersey Societal Benefit Program (a statewide public interest program that is intended to benefit low income customers and address other public policy goals) and ACE’s uncollected accounts and (iii) operating costs associated with ACE’s residential appliance cycling program. The net impact of adjusting the charges as proposed would have been an overall annual rate decrease of approximately $24.5 million (revised to a decrease of approximately $41.1 million on April 16, 2014, based upon an update for actual data through March 2014). In May 2014, the NJBPU approved a stipulation of settlement entered into by the parties in this proceeding providing for an overall annual rate decrease of $41.1 million. The rate decrease was placed into effect provisionally on June 1, 2014, subject to a review by the NJBPU of the final underlying costs for reasonableness and prudence. On January 21, 2015, the NJBPU approved a stipulation of settlement in this proceeding, which made final the provisional rates that were placed into effect on June 1, 2014. The rate decrease will have no effect on ACE’s operating income.

This proceeding is not expected to be affected by the Merger Agreement.

Service Extension Contributions Refund Order

On July 19, 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 received less than $1 million in refund claims, the validity of which is being investigated by ACE prior to making any such refunds. At this time, ACE does not expect that any such amount refunded will have a material effect on its consolidated financial condition, results of operations or cash flows, as any amounts that may be refunded will generally increase the value of ACE’s property, plant and equipment and may ultimately be recovered through depreciation and cost of service. On September 30, 2014, the NJBPU commenced a rulemaking proceeding to further implement the directives of the Appellate Division decision and on December 1, 2014, published a rule proposal for comment. The changes proposed by the NJBPU remove provisions distinguishing between growth areas and not-for-growth areas and provide formulae for allocating extension costs.

Under the Merger Agreement, ACE is permitted to pursue the conclusion of this matter and intends to continue to do so.

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 dated October 22, 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. With this revised methodology, ACE anticipates that the negative effects of the CTA in future base rate cases will be significantly reduced.

On November 5, 2014, the DRC filed an appeal of the NJBPU’s CTA order in the Appellate Division. This appeal remains pending.

Under the Merger Agreement, ACE is permitted to pursue the conclusion of this matter and intends to continue to do so.

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 DEMEC, filed a joint complaint at FERC against ACE and its affiliates Potomac Electric Power Company (Pepco) and Delmarva Power & Light Company (DPL), as well as Baltimore Gas and Electric Company (BGE). The complainants challenged the base ROE and the application of the formula rate process, each associated with the transmission service that PHI’s 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. PHI, Pepco, DPL and ACE believe the allegations in this complaint are without merit and are vigorously contesting it. 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 February 27, 2013 as the refund effective date, should a refund result from this proceeding. After settlement discussions among the parties in this matter reached an impasse, on November 24, 2014, the settlement judge issued an order terminating the settlement discussions. The matter is now before a hearing judge and a procedural schedule will be established for both the February 2013 complaint and a second complaint (discussed below) that has been consolidated with the February 2013 complaint.

On June 19, 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 period over which its transmission revenues would be subject to refund as a result of the challenge, and recorded estimated reserves in the second quarter of 2014 related to this matter. To the extent that the final ROE determined by FERC is lower than the ROE used to record the estimated reserves, each ten basis point reduction in the ROE would result in a reduction of ACE’s operating income of $0.4 million.

A second complaint against Pepco, DPL and ACE challenging the base ROE was filed at FERC on December 8, 2014 by the same parties. Employing the new ROE methodology referenced above, the complainants contend that the resulting base ROE should be 8.8%, and request consolidation of this complaint with the February 2013 complaint. Consistent with the prior challenge, ACE applied an estimated ROE based on the two-step methodology described above, and recorded estimated reserves in the fourth quarter of 2014 using a refund effective date of December 8, 2014.

Under the Merger Agreement, ACE is permitted to pursue the conclusion of these FERC matters and intends to continue to do so.

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 and the other New Jersey EDCs entered into the SOCAs under protest, arguing that the EDCs were denied due process and that the SOCAs violate certain of the requirements under the New Jersey law under which the SOCAs were established (the NJ SOCA Law). On October 22, 2013, in light of the decision of the U.S. District Court for the District of New Jersey described below, the state appeals of the NJBPU implementation orders filed by the EDCs and generators were dismissed without prejudice subject to the parties exercising their appellate rights in the Federal courts.

In February 2011, ACE joined other plaintiffs in an action filed in the U.S. District Court for the District of New Jersey challenging the NJ SOCA Law on the grounds that it violates the Commerce Clause and the Supremacy Clause of the U.S. Constitution. On October 11, 2013, the Federal district court issued a ruling that the NJ SOCA Law is preempted by the Federal Power Act (FPA) and violates the Supremacy Clause, and is therefore null and void. On October 25, 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. On November 26, 2014 and December 10, 2014, respectively, one of the generation companies and the NJBPU petitioned the U.S. Supreme Court to consider hearing an appeal of the Third Circuit decision.

One of the three SOCAs was terminated effective July 1, 2013 because of an event of default of the generation company that was a party to the SOCA. The remaining two SOCAs were terminated effective November 19, 2013, as a result of a termination notice delivered by ACE after the Federal district court’s October 25, 2013 decision.

Despite the terminated status of the SOCAs, on June 2, 2014, one of the generation companies that was a party to a SOCA filed the SOCA at FERC seeking to have the SOCA accepted under Section 205 of the FPA. The EDCs intervened in the proceeding and requested that the generation company’s filing be rejected on the grounds that the SOCA never came into effect. On August 5, 2014, FERC issued an order rejecting the filings made by the generation company, finding that the contracts cannot be accepted as valid contracts, given the decisions reached in the Federal court proceedings discussed above.

In light of the October 25, 2013 Federal district court order, ACE derecognized both the derivative assets (liabilities) for the estimated fair value of the SOCAs and the related regulatory liabilities (assets) in the fourth quarter of 2013.

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 July 23, 2014, the NJBPU voted to retain this matter, rather than assigning it to an administrative law judge. 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.

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.