(7) REGULATORY MATTERS

Rate Proceedings

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

Jurisdiction/Company

Requested Revenue
Requirement Increase

Requested Return
on Equity

Filing
Date

Expected Timing
of Decision

(millions of dollars)

MD – Pepco

$

37.4

(a)

10.25

%

December 4, 2013

Q3, 2014

NJ – ACE

$

61.7

10.25

%

March 14, 2014

Q1, 2015

(a)	Reflects Pepco’s updated revenue requirement as filed on April 15, 2014.

The following table shows, for each of PHI’s utility subsidiaries, the distribution base rate cases completed to date 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	%	April 2, 2014	May 1, 2014

As further described in Note (18), “Subsequent Events,” 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 as indicated below. In addition, the regulatory commissions may seek to suspend or delay one or more of the ongoing proceedings as a result of the Merger Agreement.

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 bill stabilization adjustment (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 Delaware Public Service Commission (DPSC) and while there was little activity associated with this filing in 2013, or to date in 2014, 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 seeks 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 seeks to recover expenses associated with DPL’s ongoing investments in reliability enhancement improvements and efforts to maintain safe and reliable service. The DPSC suspended the full proposed increase and, as permitted by state law, DPL implemented an interim increase of $2.5 million on June 1, 2013, subject to refund and pending final DPSC approval. On October 8, 2013, the DPSC approved DPL’s request to implement an additional interim increase of $25.1 million, effective on October 22, 2013, bringing the total interim rates in effect subject to refund to $27.6 million. At the conclusion of a meeting held on April 1 and 2, 2014, the DPSC issued an order 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 amounts contained in the DPSC order are subject to verification by all parties to the base rate proceeding and may be changed by further order of the DPSC upon such verification. A final order in this proceeding will be issued by the DPSC at a later date. The new rates became effective May 1, 2014. DPL will submit a rate refund plan to provide credit or refund to any customer whose rates were increased in October 2013 in an amount that exceeded the increase approved by the DPSC. The final order in this proceeding is not expected to be affected by the Merger Agreement.

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. In addition, DPL has 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.

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 advanced metering infrastructure (AMI) and allows for the remote reading of gas meters. Recovery of such costs will occur through base rates over a two-year period, assuming specific milestones are met and pursuant to the following schedule: 50% of the IMU portion of DPL’s AMI will be put into rates on July 1, 2014, and the remainder will be put into rates on April 1, 2015. DPL also agreed in the settlement that its next natural gas distribution base rate application may be filed with the DPSC no earlier than January 1, 2015. Under the Merger Agreement, DPL is not permitted to file further gas distribution base rate cases without Exelon’s consent.

Gas Cost Rates

DPL makes an annual Gas Cost Rate (GCR) filing with the DPSC for the purpose of allowing DPL to recover natural gas procurement costs through customer rates. On August 28, 2013, DPL made its 2013 GCR filing. The rates proposed in the 2013 GCR filing would result in a GCR decrease of approximately 5.5%. On September 26, 2013, the DPSC issued an order authorizing DPL to place the new rates into effect on November 1, 2013, subject to refund and pending final DPSC approval. On April 23, 2014, DPL, the DPSC staff and the Delaware Division of the Public Advocate entered into a settlement agreement providing that the proposed GCR rates as filed by DPL should be approved. The settlement agreement is subject to DPSC approval. A DPSC decision on the settlement agreement is expected in the third quarter of 2014. Under the Merger Agreement, DPL is permitted, and will continue, to pursue this matter.

District of Columbia

On March 8, 2013, Pepco filed an application with the District of Columbia Public Service Commission (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. On April 28, 2014, Pepco filed an application for reconsideration or clarification of the DCPSC’s March 26, 2014 order, contesting several of the reporting obligations and other directives imposed by the order. On April 29, 2014, the other parties to the proceeding filed applications for reconsideration of the March 26, 2014 order, which generally challenge Pepco’s post-test year reliability projects, the adequacy of Pepco’s environmental and efficiency measures, and the structure of Pepco’s residential aid discount rate. All of these applications remain pending. Under the Merger Agreement, Pepco is permitted, and will continue, to pursue the application for reconsideration, but under the Merger Agreement, Pepco is not permitted to initiate or file further electric distribution base rate cases in the District of Columbia without Exelon’s consent.

Maryland

Pepco Electric Distribution Base Rates

In December 2011, Pepco submitted an application with the Maryland Public Service Commission (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.

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%. 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. Pepco also proposed a three-year Grid Resiliency Charge rider for recovery of costs totaling approximately $192 million associated with its plan to accelerate investments in infrastructure in a condensed timeframe. Acceleration of resiliency improvements was one of several recommendations included in a September 2012 report from Maryland’s Grid Resiliency Task Force (as discussed below under “Resiliency Task Forces”). Specific projects under Pepco’s Grid Resiliency Charge plan included acceleration of its tree-trimming cycle, upgrade of 12 additional feeders per year for two years and undergrounding of six distribution feeders. In addition, Pepco proposed a reliability performance-based mechanism that would allow Pepco to earn up to $1 million as an incentive for meeting enhanced reliability goals in 2015, but provided for a credit to customers of up to $1 million in total if Pepco does not meet at least the minimum reliability performance targets. Pepco requested that any credits/charges would flow through the proposed Grid Resiliency Charge rider.

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 provides for the full recovery of storm restoration costs incurred as a result of recent major storm events, including the derecho storm in June 2012 and Hurricane Sandy in October 2012, by including the related capital costs in the rate base and amortizing the related deferred operation and maintenance expenses of $23.6 million over a five-year period. 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 return is earned, 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 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 did not approve the proposed acceleration of the tree-trimming cycle or the undergrounding of six distribution feeders. The MPSC also rejected 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 the City of Baltimore. Other parties also have filed notices of appeal, which have been consolidated with Pepco’s appeal. In its memorandum filed with the appeals court, Pepco asserts 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 memoranda filed with the appeals court by the other parties primarily assert that the MPSC erred or acted arbitrarily and capriciously in allowing the recovery of certain costs by Pepco and refusing to reduce Pepco’s rate base by known and measurable accumulated depreciation. The appeal remains pending.

On December 4, 2013, Pepco submitted an application with the MPSC to increase its electric distribution base rates. The filing seeks 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 seeks to recover expenses associated with Pepco’s ongoing investments in reliability enhancement improvements and efforts to maintain safe and reliable service. A decision is expected in the third quarter of 2014.

Under the Merger Agreement, Pepco is permitted, and will continue, to pursue the conclusion of the aforementioned matters, but under the Merger Agreement, Pepco is not permitted to initiate or file further electric distribution base rate cases in Maryland without Exelon’s consent.

New Jersey

Electric Distribution Base Rates

On March 14, 2014, ACE submitted an application with the New Jersey Board of Public Utilities (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 seeks to recover expenses associated with ACE’s ongoing investments in reliability enhancement improvements and efforts to maintain safe and reliable service. The application requests that the NJBPU put rates into effect by mid-December 2014. The matter has been transmitted by NJBPU to the Office of Administrative Law. A decision is expected in the first quarter of 2015. Under the Merger Agreement, ACE is permitted, and will continue, to pursue the conclusion of the aforementioned matter, but under the Merger Agreement, ACE is not permitted to initiate or file further electric distribution base rate cases in New Jersey without Exelon’s consent.

Update and Reconciliation of Certain Under-Recovered Balances

In February 2012 and March 2013, ACE submitted petitions 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 non-utility generators (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. In June 2012, the NJBPU approved a stipulation of settlement related to ACE’s February 2012 filing, which provided for an overall annual rate increase of $55.3 million that went into effect on July 1, 2012. In May 2013, the NJBPU approved a stipulation of settlement related to ACE’s March 2013 filing, which provided for an overall annual rate increase of $52.2 million (in addition to the $55.3 million approved by the NJBPU in June 2012) that went into effect on June 1, 2013. These rate increases, which primarily provide for the recovery of above-market costs associated with the NUG contracts and will have no effect on ACE’s operating income, were placed into effect provisionally and were subject to a review by the NJBPU of the final underlying costs for reasonableness and prudence. On February 19, 2014, the NJBPU approved a stipulation of settlement for both proceedings, which made final the provisional rates that went into effect on July 1, 2012 and June 1, 2013, respectively.

On March 3, 2014, ACE submitted a petition with the NJBPU seeking to reconcile and update the same types of charges and costs covered in the February 2012 and March 2013 filings described in the preceding paragraph. The net impact of adjusting the charges as proposed is an overall annual rate decrease of approximately $24.5 million (revised to approximately $41.1 million on April 16, 2014, based upon an update for actuals through March 2014). The matter is pending at the NJBPU. The NJBPU is expected to rule upon the petition by June 1, 2014; in the past, the NJBPU has approved rates on a provisional basis and deferred certain issues to a phase two proceeding. The final order in 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 believes 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. 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. It is anticipated that the NJBPU will commence a rulemaking proceeding to further implement the directives of the Appellate Division decision. Under the Merger Agreement, ACE is permitted, and will continue, to pursue this matter.

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 base rate case outcomes and ACE’s position is that the CTA should be eliminated. A stakeholder process has been initiated by the NJBPU to aid in this examination. No formal schedule has been set by the NJBPU for the remainder of the proceeding or for the issuance of a decision. Under the Merger Agreement, ACE is permitted, and will continue, to pursue this matter.

Federal Energy Regulatory Commission

On October 17, 2013, the Federal Energy Regulatory Commission (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. 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 sets 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 Mid-Atlantic Power Pathway (MAPP) project (which has been abandoned). Settlement discussions began in this matter in November 2013 before an administrative law judge at FERC.

On December 12, 2013, DEMEC filed a formal challenge to the DPL 2013 annual formula rate update, including a request to consolidate the 2013 challenge with the two prior challenges. On April 8, 2014, FERC issued an order setting the 2013 challenge issues for hearing. On April 15, 2014, those issues were consolidated with the 2011 and 2012 challenges. Settlement procedures will continue with the three challenges in one proceeding. PHI cannot predict when a final FERC decision in this proceeding will be issued.

On February 27, 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 with 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. As currently authorized, 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. PHI, Pepco, DPL and ACE believe the allegations in this complaint are without merit and are vigorously contesting it. On April 3, 2013, Pepco, DPL and ACE filed their answer to this complaint, requesting that FERC dismiss the complaint against them on the grounds that the complaint failed to meet the required burden to demonstrate that the existing rates and protocols are unjust and unreasonable. PHI cannot predict when a final FERC decision in this proceeding will be issued.

Under the Merger Agreement, PHI is permitted, and will continue, to pursue the conclusion of the aforementioned matters.

MPSC New Generation Contract Requirement

In September 2009, the MPSC initiated an investigation into whether Maryland electric distribution companies (EDCs) should be required to enter into long-term contracts with entities that construct, acquire or lease, and operate, new electric generation facilities in Maryland. In April 2012, the MPSC issued an order determining that there is a need for one new power plant in the range of 650 to 700 megawatts (MWs) beginning in 2015. The order 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 in amounts proportional to their relative SOS loads. Under the contract, 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. The order acknowledged the Contract EDCs’ concerns about the requirements of the contract and directed them to negotiate with the winning bidder and submit any proposed changes in the contract to the MPSC for approval. The order further specified that each of the Contract EDCs will recover its costs associated with the contract through surcharges on its respective SOS customers.

In April 2012, a group of generating companies operating in the PJM region filed a complaint in the U.S. District Court for the District of Maryland challenging the MPSC’s order on the grounds that it violates the Commerce Clause and the Supremacy Clause of the U.S. Constitution. In May 2012, the Contract EDCs and other parties filed notices of appeal in circuit courts in Maryland requesting judicial review of the MPSC’s order. The Maryland circuit court appeals were consolidated in the Circuit Court for Baltimore City.

On April 16, 2013, the MPSC issued an order approving a final form of the contract and directing the Contract EDCs to enter into the contract with the winning bidder in amounts proportional to their relative SOS loads. On June 4, 2013, Pepco and DPL each entered into identical contracts in accordance with the terms of the MPSC’s order; however, under each contract’s terms, it will not become effective, if at all, until all legal proceedings related to these contracts and the actions of the MPSC in the related proceeding have been resolved.

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, 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. These appeals remain pending.

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 account for their proportional share of the contracts as a derivative instrument at fair value with an offsetting regulatory asset because they 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.

PHI, Pepco and DPL continue to evaluate these proceedings to determine, should the contracts be found to be valid and enforceable, (i) the extent of the negative effect that the contracts may have on PHI’s, Pepco’s and DPL’s respective credit metrics, as calculated by independent rating agencies that evaluate and rate PHI, Pepco and DPL and their debt issuances, (ii) the effect on Pepco’s and DPL’s ability to recover their associated costs of the contracts if a significant number of SOS customers elect to buy their energy from alternative energy suppliers, and (iii) the effect of the contracts on the financial condition, results of operations and cash flows of each of PHI, Pepco and DPL.

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 Federal Power Act and violates the Supremacy Clause, and is therefore null and void. On October 21, 2013 a joint motion to stay the Federal district court’s decision pending appeal was filed by the NJBPU and one of the SOCA generation companies. In that motion, the NJBPU notified the Federal district court that it would take no action to force implementation of the SOCAs pending the appeal or such other action—such as FERC approval of the SOCAs—that would cure the constitutional issues to the Federal district court’s satisfaction. On October 25, 2013, the Federal district court’s issued an order denying the joint motion to stay and ruling that the SOCAs are void, invalid and unenforceable. The SOCA generation companies and the NJBPU have appealed the Federal district court’s decision. The Federal district court consolidated the appeals and the matter has been placed on an expedited schedule and appeal proceedings remain pending. The U.S. Court of Appeals for the Third Circuit heard the appeal on March 27, 2014, but has not rendered a 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.

In light of the Federal district court order (which has not been stayed pending appeal), ACE derecognized both the derivative assets (liabilities) for the estimated fair value of the SOCAs and the offsetting regulatory liabilities (assets) in the fourth quarter of 2013.

Resiliency Task Forces

In July 2012, the Maryland governor signed an Executive Order directing his energy advisor, in collaboration with certain state agencies, to solicit input and recommendations from experts on how to improve the resiliency and reliability of the electric distribution system in Maryland. The resulting Grid Resiliency Task Force issued its report in September 2012, in which it made 11 recommendations. The governor forwarded the report to the MPSC in October 2012, urging the MPSC to quickly implement the first four recommendations: (i) strengthen existing reliability and storm restoration regulations; (ii) accelerate the investment necessary to meet the enhanced metrics; (iii) allow surcharge recovery for the accelerated investment; and (iv) implement clearly defined performance metrics into the traditional ratemaking scheme. Pepco’s electric distribution base rate case filed with the MPSC on November 30, 2012 and DPL’s electric distribution base rate case filed with the MPSC on March 29, 2013, each attempted to address the Grid Resiliency Task Force recommendations. In July and August 2013, the MPSC issued orders in the Pepco and DPL Maryland electric distribution base rate cases, respectively, that only partially approved the proposed Grid Resiliency Charge. See “Rate Proceedings – Maryland” above for more information about these base rate cases.

In August 2012, the District of Columbia mayor issued an Executive Order establishing the Mayor’s Power Line Undergrounding Task Force (the DC Undergrounding Task Force). The stated purpose of the DC Undergrounding Task Force was to pool the collective resources available in the District of Columbia to produce an analysis of the technical feasibility, infrastructure options and reliability implications of undergrounding new or existing overhead distribution facilities in the District of Columbia. These resources included legislative bodies, regulators, utility personnel, experts and other parties who could contribute in a meaningful way to the DC Undergrounding Task Force. On May 13, 2013, the DC Undergrounding Task Force issued a written recommendation endorsing a $1 billion plan of the DC Undergrounding Task Force to underground 60 of the District of Columbia’s most outage-prone power lines, which lines would be owned and maintained by Pepco. The legislation providing for implementation of the report’s recommendations contemplates that: (i) Pepco would fund approximately $500 million of the $1 billion estimated cost to complete this project, recovering those costs through surcharges on the electric bills of Pepco District of Columbia customers; (ii) $375 million of the undergrounding project cost would be financed by the District of Columbia’s issuance of securitized bonds, which bonds would be repaid through surcharges on the electric bills of Pepco District of Columbia customers (Pepco would not earn a return on or of the cost of the assets funded with the proceeds received from the issuance of the securitized bonds, but ownership and responsibility for the operation and maintenance of such assets would be transferred to Pepco for a nominal amount); and (iii) the remaining amount would be funded through the District of Columbia Department of Transportation’s existing capital projects program. This legislation was approved in the Council of the District of Columbia on February 4, 2014 and signed by the Mayor of the District of Columbia on March 3, 2014. The legislation became law on May 3, 2014 following the 30-day Congressional review period. The final steps in the approval process will be DCPSC authorization of the underground project plan and issuance of financing orders required by the legislation to establish the customer surcharges contemplated by the legislation, a decision on which is expected during the fourth quarter of 2014. Under the Merger Agreement, Pepco is permitted, and will continue, to pursue the DC undergrounding project.

MAPP Settlement Agreement

On February 28, 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 was subsequently directed by PJM to cancel it. The abandonment costs sought for recovery were subsequently reduced to $82 million from 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 March 31, 2014, PHI had a regulatory asset related to the MAPP abandonment costs of approximately $52 million, net of amortization, and land of $8 million. PHI expects to recognize pre-tax income related to the MAPP abandonment costs of $3 million in 2014 and $1 million in 2015.

Regulatory Matters

(6) REGULATORY MATTERS

Rate Proceedings

As further described in Note (13), “Subsequent Events,” 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 as indicated below. In addition, the DCPSC and the MPSC may seek to suspend or delay one or more of the ongoing proceedings as a result of the Merger Agreement.

Bill Stabilization Adjustment

Pepco proposed in each of its respective jurisdictions 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 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 District of Columbia Public Service Commission (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 return on equity (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. On April 28, 2014, Pepco filed an application for reconsideration or clarification of the DCPSC’s March 26, 2014 order, contesting several of the reporting obligations and other directives imposed by the order. On April 29, 2014, the other parties to the proceeding filed applications for reconsideration of the March 26, 2014 order, which generally challenge Pepco’s post-test year reliability projects, the adequacy of Pepco’s environmental and efficiency measures, and the structure of Pepco’s residential aid discount rate. All of these applications remain pending. Under the Merger Agreement, Pepco is permitted, and will continue, to pursue the application for reconsideration, but under the Merger Agreement, Pepco is not permitted to initiate or file further electric distribution base rate cases in the District of Columbia without Exelon’s consent.

Maryland

Pepco Electric Distribution Base Rates

In December 2011, Pepco submitted an application with the Maryland Public Service Commission (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 advanced metering infrastructure (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.

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%. 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. Pepco also proposed a three-year Grid Resiliency Charge rider for recovery of costs totaling approximately $192 million associated with its plan to accelerate investments in infrastructure in a condensed timeframe. Acceleration of resiliency improvements was one of several recommendations included in a September 2012 report from Maryland’s Grid Resiliency Task Force (as discussed below under “Resiliency Task Forces”). Specific projects under Pepco’s Grid Resiliency Charge plan included acceleration of its tree-trimming cycle, upgrade of 12 additional feeders per year for two years and undergrounding of six distribution feeders. In addition, Pepco proposed a reliability performance-based mechanism that would allow Pepco to earn up to $1 million as an incentive for meeting enhanced reliability goals in 2015, but provided for a credit to customers of up to $1 million in total if Pepco does not meet at least the minimum reliability performance targets. Pepco requested that any credits/charges would flow through the proposed Grid Resiliency Charge rider.

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 provides for the full recovery of storm restoration costs incurred as a result of recent major storm events, including the derecho storm in June 2012 and Hurricane Sandy in October 2012, by including the related capital costs in the rate base and amortizing the related deferred operation and maintenance expenses of $23.6 million over a five-year period. 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 return is earned, 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 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 did not approve the proposed acceleration of the tree-trimming cycle or the undergrounding of six distribution feeders. The MPSC also rejected 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 the City of Baltimore. Other parties also have filed notices of appeal, which have been consolidated with Pepco’s appeal. In its memorandum filed with the appeals court, Pepco asserts 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 memoranda filed with the appeals court by the other parties primarily assert that the MPSC erred or acted arbitrarily and capriciously in allowing the recovery of certain costs by Pepco and refusing to reduce Pepco’s rate base by known and measurable accumulated depreciation. The appeal remains pending.

On December 4, 2013, Pepco submitted an application with the MPSC to increase its electric distribution base rates. The filing seeks 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 seeks to recover expenses associated with Pepco’s ongoing investments in reliability enhancement improvements and efforts to maintain safe and reliable service. A decision is expected in the third quarter of 2014.

Under the Merger Agreement, Pepco is permitted, and will continue, to pursue the conclusion of the aforementioned matters, but under the Merger Agreement, Pepco is not permitted to initiate or file further electric distribution base rate cases in Maryland without Exelon’s consent.

Federal Energy Regulatory Commission

On February 27, 2013, the public service commissions and public advocates of the District of Columbia, Maryland, Delaware and New Jersey, as well as the Delaware Municipal Electric Corporation, Inc., filed a joint complaint with the Federal Energy Regulatory Commission (FERC) against Pepco and its affiliates Delmarva Power & Light Company (DPL) and Atlantic City Electric Company (ACE), as well as Baltimore Gas and Electric Company (BGE). The complainants challenged the base ROE and 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 Pepco 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. As currently authorized, 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. Pepco believes the allegations in this complaint are without merit and is vigorously contesting it. On April 3, 2013, Pepco filed its answer to this complaint, requesting that FERC dismiss the complaint against it on the grounds that the complaint failed to meet the required burden to demonstrate that the existing rates and protocols are unjust and unreasonable. Pepco cannot predict when a final FERC decision in this proceeding will be issued.

Under the Merger Agreement, Pepco is permitted, and will continue to pursue the conclusion of the aforementioned matter.

MPSC New Generation Contract Requirement

In September 2009, the MPSC initiated an investigation into whether Maryland electric distribution companies (EDCs) should be required to enter into long-term contracts with entities that construct, acquire or lease, and operate, new electric generation facilities in Maryland. In April 2012, the MPSC issued an order determining that there is a need for one new power plant in the range of 650 to 700 megawatts (MWs) beginning in 2015. The order requires Pepco, its affiliate DPL and BGE (collectively, the Contract EDCs) to negotiate and enter into a contract with the winning bidder of a competitive bidding process in amounts proportional to their relative standard offer service (SOS) loads. Under the contract, 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. The order acknowledged the Contract EDCs’ concerns about the requirements of the contract and directed them to negotiate with the winning bidder and submit any proposed changes in the contract to the MPSC for approval. The order further specified that each of the Contract EDCs will recover its costs associated with the contract through surcharges on its respective SOS customers.

In April 2012, a group of generating companies operating in the PJM Interconnection, LLC (PJM) region filed a complaint in the U.S. District Court for the District of Maryland challenging the MPSC’s order on the grounds that it violates the Commerce Clause and the Supremacy Clause of the U.S. Constitution. In May 2012, the Contract EDCs and other parties filed notices of appeal in circuit courts in Maryland requesting judicial review of the MPSC’s order. The Maryland circuit court appeals were consolidated in the Circuit Court for Baltimore City.

On April 16, 2013, the MPSC issued an order approving a final form of the contract and directing the Contract EDCs to enter into the contract with the winning bidder in amounts proportional to their relative SOS loads. On June 4, 2013, Pepco entered into a contract in accordance with the terms of the MPSC’s order; however, under the contract’s terms, it will not become effective, if at all, until all legal proceedings related to these contracts and the actions of the MPSC in the related proceeding have been resolved.

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, 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. These appeals remain pending.

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 account for its proportional share of the contracts as a derivative instrument at fair value with an offsetting regulatory asset because they 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.

Pepco continues to evaluate these proceedings to determine, should the contracts be found to be valid and enforceable, (i) the extent of the negative effect that the contracts may have on Pepco’s credit metrics, as calculated by independent rating agencies that evaluate and rate Pepco and its debt issuances, (ii) the effect on Pepco’s ability to recover its associated costs of the contracts if a significant number of SOS customers elect to buy their energy from alternative energy suppliers, and (iii) the effect of the contracts on the financial condition, results of operations and cash flows of Pepco.

Resiliency Task Forces

In July 2012, the Maryland governor signed an Executive Order directing his energy advisor, in collaboration with certain state agencies, to solicit input and recommendations from experts on how to improve the resiliency and reliability of the electric distribution system in Maryland. The resulting Grid Resiliency Task Force issued its report in September 2012, in which it made 11 recommendations. The governor forwarded the report to the MPSC in October 2012, urging the MPSC to quickly implement the first four recommendations: (i) strengthen existing reliability and storm restoration regulations; (ii) accelerate the investment necessary to meet the enhanced metrics; (iii) allow surcharge recovery for the accelerated investment; and (iv) implement clearly defined performance metrics into the traditional ratemaking scheme. Pepco’s electric distribution base rate case filed with the MPSC on November 30, 2012 attempted to address the Grid Resiliency Task Force recommendations. In July 2013, the MPSC issued an order in the Pepco Maryland electric distribution base rate case that only partially approved the proposed Grid Resiliency Charge. See “Rate Proceedings – Maryland” above for more information about the base rate case.

In August 2012, the District of Columbia mayor issued an Executive Order establishing the Mayor’s Power Line Undergrounding Task Force (the DC Undergrounding Task Force). The stated purpose of the DC Undergrounding Task Force was to pool the collective resources available in the District of Columbia to produce an analysis of the technical feasibility, infrastructure options and reliability implications of undergrounding new or existing overhead distribution facilities in the District of Columbia. These resources included legislative bodies, regulators, utility personnel, experts and other parties who could contribute in a meaningful way to the DC Undergrounding Task Force. On May 13, 2013, the DC Undergrounding Task Force issued a written recommendation endorsing a $1 billion plan of the DC Undergrounding Task Force to underground 60 of the District of Columbia’s most outage-prone power lines, which lines would be owned and maintained by Pepco. The legislation providing for implementation of the report’s recommendations contemplates that: (i) Pepco would fund approximately $500 million of the $1 billion estimated cost to complete this project, recovering those costs through surcharges on the electric bills of Pepco District of Columbia customers; (ii) $375 million of the undergrounding project cost would be financed by the District of Columbia’s issuance of securitized bonds, which bonds would be repaid through surcharges on the electric bills of Pepco District of Columbia customers (Pepco would not earn a return on or of the cost of the assets funded with the proceeds received from the issuance of the securitized bonds, but ownership and responsibility for the operation and maintenance of such assets would be transferred to Pepco for a nominal amount); and (iii) the remaining amount would be funded through the District of Columbia Department of Transportation’s existing capital projects program. This legislation was approved in the Council of the District of Columbia on February 4, 2014 and signed by the Mayor of the District of Columbia on March 3, 2014. The legislation became law on May 3, 2014 following the 30-day Congressional review period. The final steps in the approval process will be DCPSC authorization of the underground project plan and issuance of financing orders required by the legislation to establish the customer surcharges contemplated by the legislation, a decision on which is expected during the fourth quarter of 2014. Under the Merger Agreement, Pepco is permitted, and will continue to pursue the DC undergrounding project.

MAPP Settlement Agreement

On February 28, 2014, FERC issued an order approving the settlement agreement submitted by Pepco in connection with Pepco’s proceeding seeking recovery of approximately $50 million in abandonment costs related to the Mid-Atlantic Power Pathway (MAPP) project. Pepco had been directed by PJM to construct the MAPP project, a 152-mile high-voltage interstate transmission line, and was subsequently directed by PJM to cancel it. The abandonment costs sought for recovery were subsequently reduced to $45 million from 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 March 31, 2014, Pepco had a regulatory asset related to the MAPP abandonment costs of approximately $30 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.

Regulatory Matters

(7) REGULATORY MATTERS

Rate Proceedings

As further described in Note (16), “Subsequent Events,” 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 as indicated below. In addition, the DPSC may seek to suspend or delay one or more of the ongoing proceedings as a result of the Merger Agreement.

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 bill stabilization adjustment (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 Delaware Public Service Commission (DPSC) and while there was little activity associated with this filing in 2013, or to date in 2014, the proceeding remains open.

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 seeks 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 seeks to recover expenses associated with DPL’s ongoing investments in reliability enhancement improvements and efforts to maintain safe and reliable service. The DPSC suspended the full proposed increase and, as permitted by state law, DPL implemented an interim increase of $2.5 million on June 1, 2013, subject to refund and pending final DPSC approval. On October 8, 2013, the DPSC approved DPL’s request to implement an additional interim increase of $25.1 million, effective on October 22, 2013, bringing the total interim rates in effect subject to refund to $27.6 million. At the conclusion of a meeting held on April 1 and 2, 2014, the DPSC issued an order 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 amounts contained in the DPSC order are subject to verification by all parties to the base rate proceeding and may be changed by further order of the DPSC upon such verification. A final order in this proceeding will be issued by the DPSC at a later date. The new rates became effective May 1, 2014. DPL will submit a rate refund plan to provide credit or refund to any customer whose rates were increased in October 2013 in an amount that exceeded the increase approved by the DPSC. The final order in this proceeding is not expected to be affected by the Merger Agreement.

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. In addition, DPL has 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.

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 advanced metering infrastructure (AMI) and allows for the remote reading of gas meters. Recovery of such costs will occur through base rates over a two-year period, assuming specific milestones are met and pursuant to the following schedule: 50% of the IMU portion of DPL’s AMI will be put into rates on July 1, 2014, and the remainder will be put into rates on April 1, 2015. DPL also agreed in the settlement that its next natural gas distribution base rate application may be filed with the DPSC no earlier than January 1, 2015. Under the Merger Agreement, DPL is not permitted to file further gas distribution base rate cases without Exelon’s consent.

Gas Cost Rates

DPL makes an annual Gas Cost Rate (GCR) filing with the DPSC for the purpose of allowing DPL to recover natural gas procurement costs through customer rates. On August 28, 2013, DPL made its 2013 GCR filing. The rates proposed in the 2013 GCR filing would result in a GCR decrease of approximately 5.5%. On September 26, 2013, the DPSC issued an order authorizing DPL to place the new rates into effect on November 1, 2013, subject to refund and pending final DPSC approval. On April 23, 2014, DPL, the DPSC staff and the Delaware Division of the Public Advocate entered into a settlement agreement providing that the proposed GCR rates as filed by DPL should be approved. The settlement agreement is subject to DPSC approval. A DPSC decision on the settlement agreement is expected in the third quarter of 2014. Under the Merger Agreement, DPL is permitted, and will continue, to pursue this matter.

Federal Energy Regulatory Commission

On October 17, 2013, the Federal Energy Regulatory Commission (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. 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 sets 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 Mid-Atlantic Power Pathway (MAPP) project (which has been abandoned). Settlement discussions began in this matter on November 5, 2013 before an administrative law judge at FERC.

On December 12, 2013, DEMEC filed a formal challenge to the DPL 2013 annual formula rate update, including a request to consolidate the 2013 challenge with the two prior challenges. On April 8, 2014, FERC issued an order setting the 2013 challenge issues for hearing. On April 15, 2014, those issues were consolidated with the 2011 and 2012 challenges. Settlement procedures will continue with the three challenges in one proceeding. PHI cannot predict when a final FERC decision in this proceeding will be issued.

On February 27, 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 with 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. As currently authorized, 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. On April 3, 2013, DPL filed its answer to this complaint, requesting that FERC dismiss the complaint against it on the grounds that the complaint failed to meet the required burden to demonstrate that the existing rates and protocols are unjust and unreasonable. DPL cannot predict when a final FERC decision in this proceeding will be issued.

Under the Merger Agreement, DPL is permitted, and will continue, to pursue the conclusion of the aforementioned matters.

MPSC New Generation Contract Requirement

In September 2009, the Maryland Public Service Commission (MPSC) initiated an investigation into whether Maryland electric distribution companies (EDCs) should be required to enter into long-term contracts with entities that construct, acquire or lease, and operate, new electric generation facilities in Maryland. In April 2012, the MPSC issued an order determining that there is a need for one new power plant in the range of 650 to 700 megawatts (MWs) beginning in 2015. The order requires DPL, its affiliate Pepco and BGE (collectively, the Contract EDCs) to negotiate and enter into a contract with the winning bidder of a competitive bidding process in amounts proportional to their relative standard offer service (SOS) loads. Under the contract, 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. The order acknowledged the Contract EDCs’ concerns about the requirements of the contract and directed them to negotiate with the winning bidder and submit any proposed changes in the contract to the MPSC for approval. The order further specified that each of the Contract EDCs will recover its costs associated with the contract through surcharges on its respective SOS customers.

In April 2012, a group of generating companies operating in the PJM region filed a complaint in the U.S. District Court for the District of Maryland challenging the MPSC’s order on the grounds that it violates the Commerce Clause and the Supremacy Clause of the U.S. Constitution. In May 2012, the Contract EDCs and other parties filed notices of appeal in circuit courts in Maryland requesting judicial review of the MPSC’s order. The Maryland circuit court appeals were consolidated in the Circuit Court for Baltimore City.

On April 16, 2013, the MPSC issued an order approving a final form of the contract and directing the Contract EDCs to enter into the contract with the winning bidder in amounts proportional to their relative SOS loads. On June 4, 2013, DPL entered into a contract in accordance with the terms of the MPSC’s order; however, under the contract’s terms, it will not become effective, if at all, until all legal proceedings related to these contracts and the actions of the MPSC in the related proceeding have been resolved.

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, 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. These appeals remain pending.

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 account for its proportional share of the contracts as a derivative instrument at fair value with an offsetting regulatory asset because they 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.

DPL continues to evaluate these proceedings to determine, should the contracts be found to be valid and enforceable, (i) the extent of the negative effect that the contracts may have on DPL’s credit metrics, as calculated by independent rating agencies that evaluate and rate DPL and its debt issuances, (ii) the effect on DPL’s ability to recover its associated costs of the contracts if a significant number of SOS customers elect to buy their energy from alternative energy suppliers, and (iii) the effect of the contracts on the financial condition, results of operations and cash flows of DPL.

Resiliency Task Force

In July 2012, the Maryland governor signed an Executive Order directing his energy advisor, in collaboration with certain state agencies, to solicit input and recommendations from experts on how to improve the resiliency and reliability of the electric distribution system in Maryland. The resulting Grid Resiliency Task Force issued its report in September 2012, in which it made 11 recommendations. The governor forwarded the report to the MPSC in October 2012, urging the MPSC to quickly implement the first four recommendations: (i) strengthen existing reliability and storm restoration regulations; (ii) accelerate the investment necessary to meet the enhanced metrics; (iii) allow surcharge recovery for the accelerated investment; and (iv) implement clearly defined performance metrics into the traditional ratemaking scheme. DPL’s electric distribution base rate case filed with the MPSC on March 29, 2013 attempted to address the Grid Resiliency Task Force recommendations. In August 2013, the MPSC issued an order in the DPL Maryland electric distribution base rate case that only partially approved the proposed Grid Resiliency Charge. See “Rate Proceedings – Maryland” above for more information about these base rate cases.

MAPP Settlement Agreement

On February 28, 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 was subsequently directed by PJM to cancel it. The abandonment costs sought for recovery were subsequently reduced to $37 million from 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 March 31, 2014, DPL had a regulatory asset related to the MAPP abandonment costs of approximately $22 million, net of amortization, and land of $6 million. DPL expects to recognize pre-tax income related to the MAPP abandonment costs of $3 million in 2014 and $1 million in 2015.

Regulatory Matters

(6) REGULATORY MATTERS

Rate Proceedings

As further described in Note (14), “Subsequent Events,” 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 as indicated below. In addition, the NJBPU may seek to suspend or delay one or more of the ongoing proceedings as a result of the Merger Agreement.

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 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.

Electric Distribution Base Rates

On March 14, 2014, ACE submitted an application with the New Jersey Board of Public Utilities (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 seeks to recover expenses associated with ACE’s ongoing investments in reliability enhancement improvements and efforts to maintain safe and reliable service. The application requests that the NJBPU put rates into effect by mid-December 2014. The matter has been transmitted by NJBPU to the Office of Administrative Law. A decision is expected in the first quarter of 2015. Under the Merger Agreement, ACE is permitted, and will continue, to pursue the conclusion of the aforementioned matter, but under the Merger Agreement, ACE is not permitted to initiate or file further electric distribution base rate cases in New Jersey without Exelon’s consent.

Update and Reconciliation of Certain Under-Recovered Balances

In February 2012 and March 2013, ACE submitted petitions 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 non-utility generators (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. In June 2012, the NJBPU approved a stipulation of settlement related to ACE’s February 2012 filing, which provided for an overall annual rate increase of $55.3 million that went into effect on July 1, 2012. In May 2013, the NJBPU approved a stipulation of settlement related to ACE’s March 2013 filing, which provided for an overall annual rate increase of $52.2 million (in addition to the $55.3 million approved by the NJBPU in June 2012) that went into effect on June 1, 2013. These rate increases, which primarily provide for the recovery of above-market costs associated with the NUG contracts and will have no effect on ACE’s operating income, were placed into effect provisionally and were subject to a review by the NJBPU of the final underlying costs for reasonableness and prudence. On February 19, 2014, the NJBPU approved a stipulation of settlement for both proceedings, which made final the provisional rates that went into effect on July 1, 2012 and June 1, 2013, respectively.

On March 3, 2014, ACE submitted a petition with the NJBPU seeking to reconcile and update the same types of charges and costs covered in the February 2012 and March 2013 filings described in the preceding paragraph. The net impact of adjusting the charges as proposed is an overall annual rate decrease of approximately $24.5 million (revised to approximately $41.1 million on April 16, 2014, based upon an update for actuals through March 2014). The matter is pending at the NJBPU. The NJBPU is expected to rule upon the petition by June 1, 2014; in the past, the NJBPU has approved rates on a provisional basis and deferred certain issues to a phase two proceeding. The final order in 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 believes 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. 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. It is anticipated that the NJBPU will commence a rulemaking proceeding to further implement the directives of the Appellate Division decision. Under the Merger Agreement, ACE is permitted, and will continue, to pursue this matter.

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 base rate case outcomes and ACE’s position is that the CTA should be eliminated. A stakeholder process has been initiated by the NJBPU to aid in this examination. No formal schedule has been set by the NJBPU for the remainder of the proceeding or for the issuance of a decision. Under the Merger Agreement, ACE is permitted, and will continue, to pursue this matter.

Federal Energy Regulatory Commission

On February 27, 2013, the public service commissions and public advocates of the District of Columbia, Maryland, Delaware and New Jersey, as well as the Delaware Municipal Electric Corporation, Inc., filed a joint complaint with the Federal Energy Regulatory Commission (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. 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 ACE 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. As currently authorized, 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. ACE believes the allegations in this complaint are without merit and is vigorously contesting it. On April 3, 2013, ACE filed its answer to this complaint, requesting that FERC dismiss the complaint against it on the grounds that the complaint failed to meet the required burden to demonstrate that the existing rates and protocols are unjust and unreasonable. ACE cannot predict when a final FERC decision in this proceeding will be issued. Under the Merger Agreement, ACE is permitted, and will continue, to pursue the conclusion of the aforementioned matters.

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 electric distribution companies (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 and violates the Supremacy Clause, and is therefore null and void. On October 21, 2013 a joint motion to stay the Federal district court’s decision pending appeal was filed by the NJBPU and one of the SOCA generation companies. In that motion, the NJBPU notified the Federal district court that it would take no action to force implementation of the SOCAs pending the appeal or such other action—such as FERC approval of the SOCAs—that would cure the constitutional issues to the Federal district court’s satisfaction. On October 25, 2013, the Federal district court issued an order denying the joint motion to stay and ruling that the SOCAs are void, invalid and unenforceable. The SOCA generation companies and the NJBPU have appealed the Federal district court’s decision. The Federal district court consolidated the appeals and the matter has been placed on an expedited schedule and appeal proceedings remain pending. The U.S. Court of Appeals for the Third Circuit heard the appeal on March 27, 2014, but has not rendered a 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.

In light of the Federal district court order (which has not been stayed pending appeal), ACE derecognized both the derivative assets (liabilities) for the estimated fair value of the SOCAs and the offsetting regulatory liabilities (assets) in the fourth quarter of 2013.