(7) REGULATORY MATTERS

Rate Proceedings

Over the last several years, 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) was approved and implemented for Pepco and DPL electric service in Maryland and for Pepco electric service in the District of Columbia.

•

A modified fixed variable rate design (MFVRD) for DPL electric and natural gas service in Delaware is under consideration by the DPSC.

•

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 under consideration by the DPSC in Delaware provides for 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. Although different from the BSA, PHI views the MFVRD as an appropriate distribution revenue decoupling mechanism.

The following table shows, for each of the PHI utility subsidiaries, the base rate cases currently pending. More 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)

DE – DPL Gas

$

12.0

(a)

10.25

%

December 7, 2012

Q4-2013

DC – Pepco Electric

52.1

10.25

%

March 8, 2013

Q1-2014

DE – DPL Electric

42.0

10.25

%

March 22, 2013

Q1-2014

MD – DPL Electric

22.8

10.25

%

March 29, 2013

Q3-2013

(b)

(a)	Reflects DPL’s updated revenue requirement as filed on July 15, 2013.

(b)	On July 17, 2013, a joint motion was filed by the parties requesting MPSC approval of a settlement providing for an annual rate increase of $15 million (an imputed ROE of 9.81%) (see below under “Maryland – DPL Electric Distribution Base Rates”).

The following table shows, for each of the PHI utility subsidiaries, the base rate cases completed in 2013. More 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)

NJ – ACE Electric

$

25.5

9.75

%

June 21, 2013

July 1, 2013

MD – Pepco Electric

27.8

9.36

%

July 12, 2013

Delaware

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. In August 2012, DPL made its 2012 GCR filing. The rates proposed in the 2012 GCR would result in a GCR decrease of approximately 22.3%. On September 18, 2012, the DPSC issued an order allowing DPL to place the new rates into effect on November 1, 2012, subject to refund and pending final DPSC approval. On June 18, 2013, the DPSC issued an order approving a settlement agreement entered into on April 24, 2013 by DPL and the DPSC staff. This order provided that the proposed GCR rates as filed by DPL be approved.

Electric Distribution Base Rates

On March 22, 2013, DPL submitted an application with the DPSC to increase its electric distribution base rates. The filing seeks approval of an annual rate increase of approximately $42 million, based on a requested ROE of 10.25%. The requested rate increase seeks to recover expenses associated with DPL’s ongoing 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. A final DPSC decision is expected by the first quarter of 2014.

Gas Distribution Base Rates

On December 7, 2012, DPL submitted an application with the DPSC to increase its natural gas distribution base rates. The filing seeks approval of an annual rate increase of approximately $12.0 million (as adjusted on July 15, 2013), based on a requested ROE of 10.25%. The requested rate increase is for the purposes of recovering expenses associated with DPL’s ongoing efforts to maintain safe and reliable service and to provide enhanced customer service technology. The DPSC suspended the full proposed increase and, as permitted by state law, DPL implemented an interim increase of $2.5 million on February 5, 2013, subject to refund and pending final DPSC approval. On July 2, 2013, the DPSC approved DPL’s request to implement an additional interim increase of $8 million on July 7, 2013, as permitted by state law. A final DPSC decision is expected by the fourth quarter of 2013.

District of Columbia

On March 8, 2013, Pepco filed an application with the District of Columbia Public Service Commission (DCPSC) to increase its electric distribution base rates by approximately $52.1 million annually, based on a requested ROE of 10.25%. The requested rate increase is for the purpose of recovering (i) Pepco’s expenses associated with ongoing efforts to maintain safe and reliable service for its customers, (ii) Pepco’s investment in infrastructure to maintain and harden the electric distribution system, and (iii) Pepco’s investment in major reliability enhancement improvements. Evidentiary hearings are expected to begin on November 4, 2013 and a final DCPSC decision is expected in the first quarter of 2014.

Maryland

DPL Electric Distribution Base Rates

On March 29, 2013, DPL submitted an application with the Maryland Public Service Commission (MPSC) to increase its electric distribution base rates by approximately $22.8 million, based on a requested ROE of 10.25%. The requested rate increase was for the purpose of recovering reliability enhancements to serve Maryland customers. DPL also proposed a three-year Grid Resiliency Charge rider for recovery of costs totaling approximately $10.2 million associated with its plan to accelerate investments in electric distribution 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 “Reliability Task Forces”). Specific projects under DPL’s Grid Resiliency Charge plan included accelerating its tree-trimming cycle and upgrading five additional feeders per year for two years. In addition, DPL proposed a reliability performance-based mechanism that would allow DPL to earn up to $500,000 as an incentive for meeting enhanced reliability goals in 2015, but provided for a credit to customers of up to $500,000 in total if DPL does not meet at least the minimum reliability performance targets. DPL requested that any credits or charges would flow through the proposed Grid Resiliency Charge rider.

On July 17, 2013, DPL, the MPSC staff and the Maryland Office of People’s Counsel (OPC) filed a joint motion with the MPSC, requesting that the MPSC approve a settlement entered into by the parties. The settlement provides for an annual rate increase of $15 million (an imputed ROE of 9.81%). The settlement provides for 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 amortizing the related deferred operation and maintenance expenses of approximately $6 million over a five-year period with the unamortized balance included in rate base. The settlement also provides for a Grid Resiliency Charge for recovery of costs totaling approximately $4.2 million associated with DPL’s proposed plan to accelerate investments related to certain priority feeders, provided that DPL provides additional information to the MPSC before implementing the surcharge related to performance objectives, milestones and costs, and makes annual filings with the MPSC thereafter concerning this project, which will permit the MPSC to establish the applicable Grid Resiliency Charge rider for the following year. The settlement does not provide for approval of a portion of the Grid Resiliency Charge related to the proposed acceleration of the tree-trimming cycle, or DPL’s proposed reliability performance-based mechanism. Under the settlement, the new rates would become effective on September 15, 2013 or as soon as reasonably practicable thereafter following effectiveness of the proposed MPSC order, which will occur on August 30, 2013 unless challenged by a party to the proceeding or the MPSC modifies or reverses the proposed order or initiates further proceedings in the matter.

Pepco Electric Distribution Base Rates

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 reduced by Pepco to $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%. The order also reduced Pepco’s depreciation rates, which lowered annual depreciation and amortization expenses by an estimated $27.3 million. The lower depreciation rates resulted from, among other things, the rebalancing of excess reserves for estimated future removal costs identified in a depreciation study conducted as part of the rate case filing. The identified excess reserves for estimated future removal costs, reported as Regulatory Liabilities, were reclassified to Accumulated Depreciation among various plant accounts. Among other things, the order also authorizes Pepco to recover the actual cost of advanced metering infrastructure (AMI) meters installed during the 2011 test year and states that cost recovery for AMI deployment will only be allowed in future rate cases in which Pepco demonstrates that the system is cost effective. The new revenue rates and lower depreciation rates were effective on July 20, 2012. The Maryland 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 was for the purpose of recovering reliability enhancements to serve Maryland customers. 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 “Reliability 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 $27.8 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 requires that the cost of AMI meters be excluded from Pepco’s rate base until such time as Pepco demonstrates the cost effectiveness of the AMI system; however, the July 2012 MPSC ruling in Pepco’s previous electric distribution base rate case, which stated that Pepco may recover the costs of meters installed during the 2011 test year for that case, is not affected by the July 2013 order and the Maryland OPC’s motion for rehearing in that case remains pending. As a result, costs for AMI meters will be treated as other incremental AMI costs incurred in conjunction with the deployment of the AMI system which are deferred and on which a return is earned. The order also approved a Grid Resiliency Charge 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 Pepco provides additional information to the MPSC before implementing the surcharge related to performance objectives, milestones and costs, and makes annual filings with the MPSC thereafter concerning this project, which will permit the MPSC to establish the applicable Grid Resiliency Charge rider for the following year. The MPSC did not approve the proposed acceleration of the tree-trimming cycle or the undergrounding of six distribution feeders. The MPSC 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 this July 12, 2013 order in the Circuit Court for the City of Baltimore. Pepco intends to file another electric distribution base rate case with the MPSC in the fourth quarter of 2013. Pepco is continuing to review the impact of the order and may also consider other actions to more closely align its spending in Maryland to the revenue received while maintaining compliance with the MPSC’s established standards applicable to the utility.

New Jersey

Electric Distribution Base Rates

On December 11, 2012, ACE submitted an application with the NJBPU, updated on January 4, 2013, to increase its electric distribution base rates by approximately $70.4 million (excluding sales-and-use taxes), based on a requested ROE of 10.25%. This proposed net increase was comprised of (i) a proposed increase to ACE’s distribution rates of approximately $72.1 million and (ii) a net decrease to ACE’s Regulatory Asset Recovery Charge (RARC) (costs associated with deferred, NJBPU-approved expenses incurred as part of ACE’s public service obligation) in the amount of approximately $1.7 million. The requested rate increase was primarily for the purposes of continuing to implement reliability-related investments and recovering system restoration costs associated with the derecho storm in June 2012 and Hurricane Sandy in October 2012. On June 21, 2013, the NJBPU approved a settlement of the parties (the “NJ Rate Settlement”) providing for an increase in ACE’s distribution base rates in the amount of $25.5 million, based on an ROE of 9.75%. The base distribution revenue increase includes full recovery of the approximately $70.0 million in incremental storm restoration costs incurred as a result of recent major storm events, including the derecho storm and Hurricane Sandy, by including the related capital costs of approximately $44.2 million in rate base and amortizing the related deferred operation and maintenance expenses of approximately $25.8 million over a three-year period. In addition, depreciation expense will be reduced approximately $8.3 million per year. The NJ Rate Settlement also includes approximately $4.9 million of current RARC, but eliminates the RARC going forward. Rates were effective on July 1, 2013.

In a March 20, 2013 order, the NJBPU established a generic proceeding to evaluate the prudency of major storm event restoration costs and expenses. Each New Jersey EDC was directed to file a separate proceeding for the evaluation of these costs. Those portions of ACE’s electric base rate filing pertaining to the recovery of major storm event expenditures were to be evaluated in the context of the generic proceeding. On April 9, 2013, ACE filed a petition with the NJBPU to comply with the NJBPU’s generic storm cost order. All other issues in ACE’s base rate filing remained unchanged in the electric base rate proceeding discussed above. In its order approving the NJ Rate Settlement, the NJBPU found that (i) ACE’s April 9, 2013 petition met all the requirements of the NJBPU’s March 20, 2013 order, and (ii) the major storm event costs for the June 2012 derecho storm and Hurricane Sandy may be recovered in ACE’s electric distribution base rate case, discussed above.

Update and Reconciliation of Certain Under-Recovered Balances

In February 2012, 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 for low income customers) and ACE’s uncollected accounts and (iii) operating costs associated with ACE’s residential appliance cycling program. The filing proposed to recover the projected deferred under-recovered balance related to the NUGs of $113.8 million as of May 31, 2012 through a four-year amortization schedule. In June 2012, the NJBPU approved a stipulation of settlement signed by the parties, which provided for provisional rates that went into effect on July 1, 2012. The net impact of adjusting the charges (consisting of both the annual impact of the proposed four-year amortization of the historical under-recovered NUG balances of $127.0 million as of June 30, 2012 and the going-forward cost recovery of all the other charges for the period July 1, 2012 through May 31, 2013, and including associated changes in sales-and-use taxes) is an overall annual rate increase of approximately $55.3 million. The rates were deemed “provisional” because ACE’s filing was not updated for actual revenues and expenses for May and June 2012 until the March 5, 2013 petition described below was filed, after which a review by the NJBPU of the final underlying costs for reasonableness and prudence will be completed. On June 11, 2013, this matter was transmitted to the New Jersey Office of Administrative Law (OAL) for possible hearing.

On March 5, 2013, ACE submitted a new 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 and ACE’s uncollected accounts and (iii) operating costs associated with ACE’s residential appliance cycling program. The filing proposed to recover the forecasted above-market NUG costs of approximately $67.9 million for the period June 1, 2013 through May 31, 2014, the projected deferred under-recovered balance related to the NUGs of approximately $40.8 million as of May 31, 2013, and an additional approximately $32.9 million associated with the deferred under-recovered balance that is being amortized over a four-year amortization period. In May 2013, NJBPU approved a stipulation of settlement signed by the parties, which provided for provisional rates that went into effect on June 1, 2013.The net impact of adjusting the charges updated for actual data through March 31, 2013 (consisting of both the second year impact of the stipulated four-year amortization of the historical under-recovered NUG balances and the going-forward cost recovery of all the other charges for the period June 1, 2013 through May 31, 2014, and including associated changes in sales-and-use taxes) is an overall annual rate increase of approximately $52.2 million (this rate increase is in addition to the approximately $55.3 million approved by the NJBPU in June 2012, as discussed in the above paragraph). The rates were deemed “provisional” because ACE’s filing was not updated for actual revenues and expenses for April and May 2013. A review by NJBPU of the final underlying costs for reasonableness and prudence will be completed. On June 11, 2013, this matter was transmitted to the OAL for possible hearing.

MPSC New Generation Contract Requirement

In September 2009, the MPSC initiated an investigation into whether Maryland 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 MW beginning in 2015. The order requires Pepco, DPL and Baltimore Gas and Electric Company (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 the Contract EDCs will recover the associated costs through surcharges on their 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. These circuit court appeals were consolidated in the Circuit Court for Baltimore City and stayed pending the issuance of a final order from the MPSC approving the form of contract.

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, in amounts proportional to their relative SOS loads, with the winning bidder. The MPSC stated that the order, which approves timely and complete recovery by the Contract EDCs of the costs associated with the contract, constitutes a binding commitment that shall not be subject to future modification or rescission by the MPSC. Despite this commitment from the MPSC, Pepco and DPL believe that the attempt by the MPSC to bind a future commission in this manner may be subject to legal challenge, which challenge, if successful, could impair the right of Pepco and DPL to recover their costs in the future. In addition, the MPSC excluded from the contract a provision that Pepco and DPL believe is important to mitigate their financial risk because the provision, had it been included, would have required Pepco and DPL to make payments to the winning bidder under the contract only to the extent they were able to recover those costs (for example, Pepco and DPL believe the excluded provision would have protected them in the event a significant number of their SOS customers elect to buy their energy from alternative energy suppliers). In light of the issuance of the MPSC’s final order, the previously filed appeals of the MPSC’s actions in this case before the circuit court are now proceeding. On June 4, 2013, Pepco and DPL entered into the contract in accordance with the terms of the MPSC’s order; however, under the contract’s own terms, it will not become effective, if at all, until all legal proceedings related to this contract and the actions of the MPSC in the related proceeding have been resolved.

PHI believes that Pepco and DPL may be required to account for their proportional share of the contract as a derivative instrument at fair value with an offsetting regulatory asset because they would recover any payments under the contract from SOS customers. Assuming the contracts, as currently written, were to become effective by the expected commercial operation date of June 1, 2015, PHI estimates that Pepco and DPL would be required to record an aggregate derivative liability ranging from $55 million to $70 million with an offsetting regulatory asset in a like amount. These estimates and other assumptions made may change prior to the time that the contract becomes effective, if at all. PHI, Pepco and DPL have concluded that any accounting for this contract would not be required until all legal proceedings related to this contract and the actions of the MPSC in the related proceeding have been resolved.

PHI, Pepco and DPL are in the process of determining (i) the extent of the negative effect that the contract for new generation 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 each of their debt issuances, (ii) the effect on Pepco’s and DPL’s ability to recover their associated costs of the contract for new generation if a significant number of SOS customers elect to buy their energy from alternative energy suppliers, and (iii) the effect of the contract on the financial condition, results of operations and cash flows of each of PHI, Pepco and DPL.

Reliability 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 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. The options that are available for financing these efforts were also to be evaluated to identify required legislative or regulatory actions to implement these recommendations. 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 bury five dozen of the District of Columbia’s most outage-prone power lines. Under this recommendation, (i) Pepco would bear 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 municipal 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 the underground lines paid for with the proceeds received from the issuance of the bonds, but those lines would be transferred to Pepco to operate and maintain); and (iii) the remaining amount would be funded through the District of Columbia Department of Transportation’s existing capital projects program. Legislation providing for implementation of the report recommendations was introduced in the Council of the District of Columbia on July 10, 2013. This legislation is expected to be voted upon by the City Council by the fourth quarter of 2013. The final step in the process would be DCPSC approval of the recommendations, a decision on which is expected by the first quarter of 2014.

ACE Standard Offer Capacity Agreements

In April 2011, ACE entered into three SOCAs by order of the NJBPU, each with a different generation company, as more fully described in Note (2), “Significant Accounting Policies – Consolidation of Variable Interest Entities – ACE Standard Offer Capacity Agreements” and Note (13), “Derivative Instruments and Hedging Activities.” 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 dispute is pending before the NJBPU and has been referred to an Administrative Law Judge for further consideration. On April 11, 2013, the Superior Court of New Jersey Appellate Division issued an order consolidating the EDCs’ state court appeal of the NJBPU order (filed by the EDCs with the Appellate Division of the New Jersey Superior Court in June 2011) with a similar challenge filed by several generators and instructing the Administrative Law Judge to complete proceedings by June 15, 2013. The NJBPU filed a motion for clarification of the Appellate Division order, seeking an extension of time to complete the proceedings at the OAL. On June 28, 2013, the Appellate Division issued an order staying the consolidated appeals until September 30, 2013, and requiring the proceedings before the OAL and the NJBPU to be completed by that time.

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 New Jersey law under which the SOCAs were established on the grounds that it violates the Commerce Clause and the Supremacy Clause of the U.S. Constitution. In September 2012, the District Court denied motions for summary judgment filed by ACE and the other plaintiffs, as well as cross-motions filed by defendants. A bench trial was completed in May 2013 and final arguments were heard by the District Court Judge on June 17, 2013. It has not been determined when the District Court will issue 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.

MAPP Project

On August 24, 2012, the board of PJM terminated the Mid-Atlantic Power Pathway (MAPP) project and removed it from PJM’s regional transmission expansion plan. PHI had been directed to construct the MAPP project, a 152-mile high-voltage interstate transmission line, to address the reliability needs of the region’s transmission system. As of December 31, 2012, PHI’s total costs related to the MAPP project were $102 million. In a 2008 FERC order approving incentives for the MAPP project, FERC authorized the recovery of prudently incurred abandoned costs in connection with the MAPP project. Consistent with this order, in December 2012, PHI submitted a filing to FERC seeking recovery of $88 million of abandoned MAPP costs. The FERC filing addressed, among other things, the prudence of the recoverable costs incurred, the proposed period over which the abandoned costs are to be amortized and the rate of return on these costs during the recovery period.

Various protests were submitted in response to PHI’s December 2012 filing, arguing, among other things, that FERC should disallow a portion of the rate of return involving an incentive adder that would be applied to the abandoned costs, and requesting a hearing on various issues such as the amount of the ROE and the prudence of the costs. On February 28, 2013, FERC issued an order concluding that the MAPP project was cancelled for reasons beyond the control of Pepco and DPL, finding that the prudently incurred costs associated with the abandonment of the MAPP project are eligible to be recovered, and setting for hearing and settlement procedures the prudence of the abandoned costs and the amortization period for those costs. FERC reduced the ROE applicable to the abandoned costs from the previously approved 12.8% incentive ROE to 10.8% by disallowing 200 basis points of ROE adders. FERC also denied recovery of 50% (calculated by PHI to be $2 million), of the prudently incurred abandoned costs prior to November 1, 2008, the date of FERC’s MAPP incentive order. PHI believes that the February 2013 FERC order is not consistent with prior precedent and is vigorously pursuing its rights to recover all prudently incurred abandoned costs associated with the MAPP project, as well as the full ROE previously approved by FERC. On April 1, 2013, PHI filed a rehearing request of the February 28, 2013 FERC order challenging the reduction of the ROE applicable to the abandoned costs, as well as the denial of 50% of the costs incurred prior to November 1, 2008. On that same date, a group of public advocates from Maryland, Delaware, New Jersey, Virginia, West Virginia and Pennsylvania also filed a rehearing request challenging the 10.8% ROE authorized in FERC’s order, arguing that PHI is not entitled to any rate of return on the abandoned costs and that FERC improperly failed to set the ROE for hearing. PHI cannot predict when a final FERC decision in this proceeding will be issued.

As of December 31, 2012, PHI had placed in service $11 million of its total capital expenditures with respect to the MAPP project, which represented upgrades of existing substation assets that were expected to support the MAPP transmission line, transferred approximately $3 million of materials to inventories, for use on other projects, and reclassified the remaining $88 million of capital expenditures to a regulatory asset. During the first quarter of 2013, PHI further transferred an additional $2 million of materials to inventories, for use on other projects, and expensed $2 million of abandoned costs as a result of FERC’s disallowance noted above. During the second quarter of 2013, PHI further transferred an additional $3 million of materials to inventories, for use on other projects, resulting in a regulatory asset of $81 million as of June 30, 2013. The regulatory asset includes the costs of land, land rights, supplies and materials, engineering and design, environmental services, and project management and administration. PHI intends to reduce further the amount of the regulatory asset by any amounts recovered from the sale or alternative use of the land, land rights, supplies and materials.

Transmission ROE Challenge

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 Electric Municipal Corporation, Inc., filed a joint complaint with FERC against Pepco, DPL and ACE, as well as 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 claim to 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 it failed to meet the required burden to demonstrate that the existing rates and protocols are unjust and unreasonable.

Regulatory Matters

(6) REGULATORY MATTERS

Rate Proceedings

Over the last several years, Pepco has proposed in each of its 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) was approved and implemented for electric service in Maryland and 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 electric distribution base rates by approximately $52.1 million annually, based on a requested return on equity (ROE) of 10.25%. The requested rate increase is for the purpose of recovering (i) Pepco’s expenses associated with ongoing efforts to maintain safe and reliable service for its customers, (ii) Pepco’s investment in infrastructure to maintain and harden the electric distribution system, and (iii) Pepco’s investment in major reliability enhancement improvements. Evidentiary hearings are expected to begin on November 4, 2013 and a final DCPSC decision is expected in the first quarter of 2014.

Maryland

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 reduced by Pepco to $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%. The order also reduced Pepco’s depreciation rates, which lowered annual depreciation and amortization expenses by an estimated $27.3 million. The lower depreciation rates resulted from, among other things, the rebalancing of excess reserves for estimated future removal costs identified in a depreciation study conducted as part of the rate case filing. The identified excess reserves for estimated future removal costs, reported as Regulatory Liabilities, were reclassified to Accumulated Depreciation among various plant accounts. Among other things, the order also authorizes Pepco to recover the actual cost of advanced metering infrastructure (AMI) meters installed during the 2011 test year and states that cost recovery for AMI deployment will only be allowed in future rate cases in which Pepco demonstrates that the system is cost effective. The new revenue rates and lower depreciation rates were 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 was for the purpose of recovering reliability enhancements to serve Maryland customers. 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 “Reliability 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 $27.8 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 requires that the cost of AMI meters be excluded from Pepco’s rate base until such time as Pepco demonstrates the cost effectiveness of the AMI system; however, the July 2012 MPSC ruling in Pepco’s previous electric distribution base rate case, which stated that Pepco may recover the costs of meters installed during the 2011 test year for that case, is not affected by the July 2013 order and the Maryland OPC’s motion for rehearing in that case remains pending. As a result, costs for AMI meters will be treated as other incremental AMI costs incurred in conjunction with the deployment of the AMI system which are deferred and on which a return is earned. The order also approved a Grid Resiliency Charge 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 Pepco provides additional information to the MPSC before implementing the surcharge related to performance objectives, milestones and costs, and makes annual filings with the MPSC thereafter concerning this project, which will permit the MPSC to establish the applicable Grid Resiliency Charge rider for the following year. The MPSC did not approve the proposed acceleration of the tree-trimming cycle or the undergrounding of six distribution feeders. The MPSC 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 this July 12, 2013 order in the Circuit Court for the City of Baltimore. Pepco intends to file another electric distribution base rate case with the MPSC in the fourth quarter of 2013. Pepco is continuing to review the impact of the order and may also consider other actions to more closely align its spending in Maryland to the revenue received while maintaining compliance with the MPSC’s established standards applicable to the utility.

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 (MW) beginning in 2015. The order requires Pepco, Delmarva Power & Light Company (DPL) and Baltimore Gas and Electric Company (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 the Contract EDCs will recover the associated costs through surcharges on their 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. These circuit court appeals were consolidated in the Circuit Court for Baltimore City and stayed pending the issuance of a final order from the MPSC approving the form of contract.

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, in amounts proportional to their relative SOS loads, with the winning bidder. The MPSC stated that the order, which approves timely and complete recovery by the Contract EDCs of the costs associated with the contract, constitutes a binding commitment that shall not be subject to future modification or rescission by the MPSC. Despite this commitment from the MPSC, Pepco believes that the attempt by the MPSC to bind a future commission in this manner may be subject to legal challenge, which challenge, if successful, could impair the right of Pepco to recover its costs in the future. In addition, the MPSC excluded from the contract a provision that Pepco believes is important to mitigate its financial risk because the provision, had it been included, would have required Pepco to make payments to the winning bidder under the contract only to the extent it were able to recover those costs (for example, Pepco believes the excluded provision would have protected it in the event a significant number of its SOS customers elect to buy their energy from alternative energy suppliers). In light of the issuance of the MPSC’s final order, the previously filed appeals of the MPSC’s actions in this case before the circuit court are now proceeding. On June 4, 2013, Pepco entered into the contract in accordance with the terms of the MPSC’s order; however, under the contract’s own terms, it will not become effective, if at all, until all legal proceedings related to this contract and the actions of the MPSC in the related proceeding have been resolved.

Pepco believes it may be required to account for its proportional share of the contract as a derivative instrument at fair value with an offsetting regulatory asset because it would recover any payments under the contract from SOS customers. Assuming the contract, as currently written, were to become effective by the expected commercial operation date of June 1, 2015, Pepco estimates that it would be required to record an aggregate derivative liability ranging from $40 million to $50 million with an offsetting regulatory asset in a like amount. These estimates and other assumptions made may change prior to the time that the contract becomes effective, if at all. Pepco has concluded that any accounting for this contract would not be required all legal proceedings related to this contract and the actions of the MPSC in the related proceeding have been resolved.

Pepco is in the process of determining (i) the extent of the negative effect that the contract for new generation 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 contract for new generation if a significant number of SOS customers elect to buy their energy from alternative energy suppliers, and (iii) the effect of the contract on the financial condition, results of operations and cash flows of Pepco.

Reliability 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 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. The options that are available for financing these efforts were also to be evaluated to identify required legislative or regulatory actions to implement these recommendations. 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 bury five dozen of the District of Columbia’s most outage-prone power lines. Under this recommendation, (i) Pepco would bear 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 municipal 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 the underground lines paid for with the proceeds received from the issuance of the bonds, but those lines would be transferred to Pepco to operate and maintain); and (iii) the remaining amount would be funded through the District of Columbia Department of Transportation’s existing capital projects program. Legislation providing for implementation of the report recommendations was introduced in the Council of the District of Columbia on July 10, 2013. This legislation is expected to be voted upon by the City Council by the fourth quarter of 2013. The final step in the process would be DCPSC approval of the recommendations, a decision on which is expected by the first quarter of 2014.

MAPP Project

On August 24, 2012, the board of PJM terminated the Mid-Atlantic Power Pathway (MAPP) project and removed it from PJM’s regional transmission expansion plan. PHI had been directed to construct the MAPP project, a 152-mile high-voltage interstate transmission line, to address the reliability needs of the region’s transmission system. As of December 31, 2012, Pepco’s total costs related to the MAPP project were $64 million. In a 2008 Federal Energy Regulatory Commission (FERC) order approving incentives for the MAPP project, FERC authorized the recovery of prudently incurred abandoned costs in connection with the MAPP project. Consistent with this order, in December 2012, Pepco submitted a filing to FERC seeking recovery of $50 million of abandoned MAPP costs. The FERC filing addressed, among other things, the prudence of the recoverable costs incurred, the proposed period over which the abandoned costs are to be amortized and the rate of return on these costs during the recovery period.

Various protests were submitted in response to Pepco’s December 2012 filing, arguing, among other things, that FERC should disallow a portion of the rate of return involving an incentive adder that would be applied to the abandoned costs, and requesting a hearing on various issues such as the amount of the ROE and the prudence of the costs. On February 28, 2013, FERC issued an order concluding that the MAPP project was cancelled for reasons beyond the control of Pepco, finding that the prudently incurred costs associated with the abandonment of the MAPP project are eligible to be recovered, and setting for hearing and settlement procedures the prudence of the abandoned costs and the amortization period for those costs. FERC reduced the ROE applicable to the abandoned costs from the previously approved 12.8% incentive ROE to 10.8% by disallowing 200 basis points of ROE adders. FERC also denied recovery of 50% (calculated by Pepco to be $1 million) of the prudently incurred abandoned costs prior to November 1, 2008, the date of FERC’s MAPP incentive order. Pepco believes that the February 2013 FERC order is not consistent with prior precedent and is vigorously pursuing its rights to recover all prudently incurred abandoned costs associated with the MAPP project, as well as the full ROE previously approved by FERC. On April 1, 2013, PHI filed a rehearing request on behalf of Pepco of the February 28, 2013 FERC order challenging the reduction of the ROE applicable to the abandoned costs, as well as the denial of 50% of the costs incurred prior to November 1, 2008. On that same date, a group of public advocates from Maryland, Delaware, New Jersey, Virginia, West Virginia and Pennsylvania also filed a rehearing request challenging the 10.8% ROE authorized in FERC’s order, arguing that Pepco is not entitled to any rate of return on the abandoned costs and that FERC improperly failed to set the ROE for hearing. Pepco cannot predict when a final FERC decision in this proceeding will be issued.

As of December 31, 2012, Pepco had placed in service $11 million of its total capital expenditures with respect to the MAPP project, which represented upgrades of existing substation assets that were expected to support the MAPP transmission line, transferred approximately $3 million of materials to inventories, for use on other projects, and reclassified the remaining $50 million of capital expenditures to a regulatory asset. During the first quarter of 2013, Pepco further transferred an additional $2 million of materials to inventories, for use on other projects, and expensed $1 million of abandoned costs as a result of FERC’s disallowance noted above. During the second quarter of 2013, Pepco further transferred an additional $3 million of materials to inventories, for use on other projects, resulting in a regulatory asset of $44 million as of June 30, 2013. The regulatory asset includes the costs of land, land rights, supplies and materials, engineering and design, environmental services, and project management and administration. Pepco intends to reduce further the amount of the regulatory asset by any amounts recovered from the sale or alternative use of the land, land rights, supplies and materials.

Transmission ROE Challenge

On February 27, 2013, the public service commissions and public advocates of the District of Columbia, Maryland, Delaware and New Jersey filed a joint complaint with FERC against Pepco, DPL, an affiliate of Pepco, and Atlantic City Electric Company (ACE), an affiliate of Pepco, as well as BGE. The complainants challenged the base ROE and the application of the formula rate process, each associated with the transmission service that Pepco provides. The complainants claim to 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 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 it failed to meet the required burden to demonstrate that the existing rates and protocols are unjust and unreasonable.

Regulatory Matters

(7) REGULATORY MATTERS

Rate Proceedings

Over the last several years, DPL has proposed in each its 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) was approved and implemented for electric service in Maryland.

•

A modified fixed variable rate design (MFVRD) is under consideration by the DPSC.

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 approved in concept in Delaware provides for 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. Although different from the BSA, DPL views the MFVRD as an appropriate distribution revenue decoupling mechanism.

Delaware

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. In August 2012, DPL made its 2012 GCR filing. The rates proposed in the 2012 GCR would result in a GCR decrease of approximately 22.3%. On September 18, 2012, the DPSC issued an order allowing DPL to place the new rates into effect on November 1, 2012, subject to refund and pending final DPSC approval. On June 18, 2013, the DPSC issued an order approving a settlement agreement entered into on April 24, 2013 by DPL and the DPSC staff. This order provided that the proposed GCR rates as filed by DPL be approved.

Electric Distribution Base Rates

On March 22, 2013, DPL submitted an application with the DPSC to increase its electric distribution base rates. The filing seeks approval of an annual rate increase of approximately $42 million, based on a requested return on equity (ROE) of 10.25%. The requested rate increase seeks to recover expenses associated with DPL’s ongoing 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. A final DPSC decision is expected by the first quarter of 2014.

Gas Distribution Base Rates

On December 7, 2012, DPL submitted an application with the DPSC to increase its natural gas distribution base rates. The filing seeks approval of an annual rate increase of approximately $12.0 million (as adjusted on July 15, 2013), based on a requested ROE of 10.25%. The requested rate increase is for the purposes of recovering expenses associated with DPL’s ongoing efforts to maintain safe and reliable service and to provide enhanced customer service technology. The DPSC suspended the full proposed increase and, as permitted by state law, DPL implemented an interim increase of $2.5 million on February 5, 2013, subject to refund and pending final DPSC approval. On July 2, 2013, the DPSC approved DPL’s request to implement an additional interim increase of $8 million on July 7, 2013, as permitted by state law. A final DPSC decision is expected by the fourth quarter of 2013.

Maryland

Electric Distribution Base Rates

On March 29, 2013, DPL submitted an application with the Maryland Public Service Commission (MPSC) to increase its electric distribution base rates by approximately $22.8 million, based on a requested ROE of 10.25%. The requested rate increase was for the purpose of recovering reliability enhancements to serve Maryland customers. DPL also proposed a three-year Grid Resiliency Charge rider for recovery of costs totaling approximately $10.2 million associated with its plan to accelerate investments in electric distribution 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 “Reliability Task Forces”). Specific projects under DPL’s Grid Resiliency Charge plan included accelerating its tree-trimming cycle and upgrading five additional feeders per year for two years. In addition, DPL proposed a reliability performance-based mechanism that would allow DPL to earn up to $500,000 as an incentive for meeting enhanced reliability goals in 2015, but provided for a credit to customers of up to $500,000 in total if DPL does not meet at least the minimum reliability performance targets. DPL requested that any credits or charges would flow through the proposed Grid Resiliency Charge rider.

On July 17, 2013, DPL, the MPSC staff and the Maryland Office of People’s Counsel filed a joint motion with the MPSC, requesting that the MPSC approve a settlement entered into by the parties. The settlement provides for an annual rate increase of $15 million (an imputed ROE of 9.81%). The settlement provides for 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 amortizing the related deferred operation and maintenance expenses of approximately $6 million over a five-year period with the unamortized balance included in rate base. The settlement also provides for a Grid Resiliency Charge for recovery of costs totaling approximately $4.2 million associated with DPL’s proposed plan to accelerate investments related to certain priority feeders, provided that DPL provides additional information to the MPSC before implementing the surcharge related to performance objectives, milestones and costs, and makes annual filings with the MPSC thereafter concerning this project, which will permit the MPSC to establish the applicable Grid Resiliency Charge rider for the following year. The settlement does not provide for approval of a portion of the Grid Resiliency Charge related to the proposed acceleration of the tree-trimming cycle, or DPL’s proposed reliability performance-based mechanism. Under the settlement, the new rates would become effective on September 15, 2013 or as soon as reasonably practicable thereafter following effectiveness of the proposed MPSC order, which will occur on August 30, 2013 unless challenged by a party to the proceeding, or the MPSC modifies or reverses the proposed order or initiates further proceedings in the 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 MW beginning in 2015. The order requires DPL, Potomac Electric Power Company (Pepco) and Baltimore Gas and Electric Company (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 the Contract EDCs will recover the associated costs through surcharges on their 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. These circuit court appeals were consolidated in the Circuit Court for Baltimore City and stayed pending the issuance of a final order from the MPSC approving the form of contract.

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, in amounts proportional to their relative SOS loads, with the winning bidder. The MPSC stated that the order, which approves timely and complete recovery by the Contract EDCs of the costs associated with the contract, constitutes a binding commitment that shall not be subject to future modification or rescission by the MPSC. Despite this commitment from the MPSC, DPL believes that the attempt by the MPSC to bind a future commission in this manner may be subject to legal challenge, which challenge, if successful, could impair the right of DPL to recover its costs in the future. In addition, the MPSC excluded from the contract a provision that DPL believe is important to mitigate its financial risk because the provision, had it been included, would have required DPL to make payments to the winning bidder under the contract only to the extent it were able to recover those costs (for example, DPL believes the excluded provision would have protected it in the event a significant number of its SOS customers elect to buy their energy from alternative energy suppliers). In light of the issuance of the MPSC’s final order, the previously filed appeals of the MPSC’s actions in this case before the circuit court are now proceeding. On June 4, 2013, DPL entered into the contract in accordance with the terms of the MPSC’s order; however, under the contract’s own terms, it will not become effective, if at all, until all legal proceedings related to this contract and the actions of the MPSC in the related proceeding have been resolved.

DPL believes that it may be required to account for their proportional share of the contract as a derivative instrument at fair value with an offsetting regulatory asset because it would recover any payments under the contract from SOS customers. Assuming the contracts, as currently written, were to become effective by the expected commercial operation date of June 1, 2015, DPL estimates that it would be required to record an aggregate derivative liability ranging from $15 million to $20 million with an offsetting regulatory asset in a like amount. These estimates and other assumptions made may change prior to the time that the contract becomes effective, if at all. DPL has concluded that any accounting for this contract would not be required until all legal proceedings related to this contract and the actions of the MPSC in the related proceeding have been resolved.

DPL is in the process of determining (i) the extent of the negative effect that the contract for new generation may have on DPL’s credit metrics, as calculated by independent rating agencies that evaluate and rate DPL and each of its debt issuances, (ii) the effect on DPL’s ability to recover its associated costs of the contract for new generation if a significant number of SOS customers elect to buy their energy from alternative energy suppliers, and (iii) the effect of the contract on the financial condition, results of operations and cash flows of DPL.

Reliability 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.

MAPP Project

On August 24, 2012, the board of PJM terminated the Mid-Atlantic Power Pathway (MAPP) project and removed it from PJM’s regional transmission expansion plan. PHI had been directed to construct the MAPP project, a 152-mile high-voltage interstate transmission line, to address the reliability needs of the region’s transmission system. As of December 31, 2012, DPL’s total costs related to the MAPP project were $38 million. In a 2008 Federal Energy Regulatory Commission (FERC) order approving incentives for the MAPP project, FERC authorized the recovery of prudently incurred abandoned costs in connection with the MAPP project. Consistent with this order, in December 2012, DPL submitted a filing to FERC seeking recovery of $38 million of abandoned MAPP costs. The FERC filing addressed, among other things, the prudence of the recoverable costs incurred, the proposed period over which the abandoned costs are to be amortized and the rate of return on these costs during the recovery period.

Various protests were submitted in response to DPL’s December 2012 filing, arguing, among other things, that FERC should disallow a portion of the rate of return involving an incentive adder that would be applied to the abandoned costs, and requesting a hearing on various issues such as the amount of the ROE and the prudence of the costs. On February 28, 2013, FERC issued an order concluding that the MAPP project was cancelled for reasons beyond the control of DPL, finding that the prudently incurred costs associated with the abandonment of the MAPP project are eligible to be recovered, and setting for hearing and settlement procedures the prudence of the abandoned costs and the amortization period for those costs. FERC reduced the ROE applicable to the abandoned costs from the previously approved 12.8% incentive ROE to 10.8% by disallowing 200 basis points of ROE adders. FERC also denied recovery of 50% (calculated by DPL to be $1 million) of the prudently incurred abandoned costs prior to November 1, 2008, the date of FERC’s MAPP incentive order. DPL believes that the February 2013 FERC order is not consistent with prior precedent and is vigorously pursuing its rights to recover all prudently incurred abandoned costs associated with the MAPP project, as well as the full ROE previously approved by FERC. On April 1, 2013, PHI filed a rehearing request on behalf of DPL of the February 28, 2013 FERC order challenging the reduction of the ROE applicable to the abandoned costs, as well as the denial of 50% of the costs incurred prior to November 1, 2008. On that same date, a group of public advocates from Maryland, Delaware, New Jersey, Virginia, West Virginia and Pennsylvania also filed a rehearing request challenging the 10.8% ROE authorized in FERC’s order, arguing that DPL is not entitled to any rate of return on the abandoned costs and that FERC improperly failed to set the ROE for hearing. DPL cannot predict when a final FERC decision in this proceeding will be issued.

As of December 31, 2012, DPL had reclassified all $38 million of capital expenditures with respect to the MAPP project to a regulatory asset. During the first quarter of 2013, DPL expensed $1 million of prudently incurred abandoned costs as a result of FERC’s disallowance noted above, resulting in a regulatory asset of $37 million as of June 30, 2013. The regulatory asset includes the costs of land, land rights, engineering and design, environmental services, and project management and administration. DPL intends to reduce further the amount of the regulatory asset by any amounts recovered from the sale or alternative use of the land and land rights.

Transmission ROE Challenge

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 Electric Municipal Corporation, Inc., filed a joint complaint with FERC against DPL, Pepco, an affiliate of DPL, and Atlantic City Electric Company (ACE), an affiliate of DPL, as well as BGE. The complainants challenged the base ROE and the application of the formula rate process, each associated with the transmission service that DPL provides. The complainants claim to 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 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 it failed to meet the required burden to demonstrate that the existing rates and protocols are unjust and unreasonable.

Regulatory Matters

(6) REGULATORY MATTERS

Rate Proceedings

Electric Distribution Base Rates

On December 11, 2012, ACE submitted an application with the NJBPU, updated on January 4, 2013, to increase its electric distribution base rates by approximately $70.4 million (excluding sales-and-use taxes), based on a requested ROE of 10.25%. This proposed net increase was comprised of (i) a proposed increase to ACE’s distribution rates of approximately $72.1 million and (ii) a net decrease to ACE’s Regulatory Asset Recovery Charge (RARC) (costs associated with deferred, NJBPU-approved expenses incurred as part of ACE’s public service obligation) in the amount of approximately $1.7 million. The requested rate increase was primarily for the purposes of continuing to implement reliability-related investments and recovering system restoration costs associated with the derecho storm in June 2012 and Hurricane Sandy in October 2012. On June 21, 2013, the NJBPU approved a settlement of the parties (the NJ Rate Settlement) providing for an increase in ACE’s distribution base rates in the amount of $25.5 million, based on an ROE of 9.75%. The base distribution revenue increase includes full recovery of the approximately $70.0 million in incremental storm restoration costs incurred as a result of recent major storm events, including the derecho storm and Hurricane Sandy, by including the related capital costs of approximately $44.2 million in rate base and amortizing the related deferred operation and maintenance expenses of approximately $25.8 million over a three-year period. In addition, depreciation expense will be reduced approximately $8.3 million per year. The NJ Rate Settlement also includes approximately $4.9 million of current RARC, but eliminates the RARC going forward. Rates were effective on July 1, 2013.

In a March 20, 2013 order, the NJBPU established a generic proceeding to evaluate the prudency of major storm event restoration costs and expenses. Each New Jersey EDC was directed to file a separate proceeding for the evaluation of these costs. Those portions of ACE’s electric base rate filing pertaining to the recovery of major storm event expenditures were to be evaluated in the context of the generic proceeding. On April 9, 2013, ACE filed a petition with the NJBPU to comply with the NJBPU’s generic storm cost order. All other issues in ACE’s base rate filing remained unchanged in the electric base rate proceeding discussed above. In its order approving the NJ Rate Settlement, the NJBPU found that (i) ACE’s April 9, 2013 petition met all the requirements of the NJBPU’s March 20, 2013 order, and (ii) the major storm event costs for the June 2012 derecho storm and Hurricane Sandy may be recovered in ACE’s electric distribution base rate case, discussed above.

Update and Reconciliation of Certain Under-Recovered Balances

In February 2012, 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 for low income customers) and ACE’s uncollected accounts and (iii) operating costs associated with ACE’s residential appliance cycling program. The filing proposed to recover the projected deferred under-recovered balance related to the NUGs of $113.8 million as of May 31, 2012 through a four-year amortization schedule. In June 2012, the NJBPU approved a stipulation of settlement signed by the parties, which provided for provisional rates that went into effect on July 1, 2012. The net impact of adjusting the charges (consisting of both the annual impact of the proposed four-year amortization of the historical under-recovered NUG balances of $127.0 million as of June 30, 2012 and the going-forward cost recovery of all the other charges for the period July 1, 2012 through May 31, 2013, and including associated changes in sales-and-use taxes) is an overall annual rate increase of approximately $55.3 million. The rates were deemed “provisional” because ACE’s filing was not updated for actual revenues and expenses for May and June 2012 until the March 5, 2013 petition described below was filed, after which a review by the NJBPU of the final underlying costs for reasonableness and prudence will be completed. On June 11, 2013, this matter was transmitted to the New Jersey Office of Administrative Law (OAL) for possible hearing.

On March 5, 2013, ACE submitted a new 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 and ACE’s uncollected accounts and (iii) operating costs associated with ACE’s residential appliance cycling program. The filing proposed to recover the forecasted above-market NUG costs of approximately $67.9 million for the period June 1, 2013 through May 31, 2014, the projected deferred under-recovered balance related to the NUGs of approximately $40.8 million as of May 31, 2013, and an additional approximately $32.9 million associated with the deferred under-recovered balance that is being amortized over a four-year amortization period. In May 2013, NJBPU approved a stipulation of settlement signed by the parties, which provided for provisional rates that went into effect on June 1, 2013. The net impact of adjusting the charges updated for actual data through March 31, 2013 (consisting of both the second year impact of the stipulated four-year amortization of the historical under-recovered NUG balances and the going-forward cost recovery of all the other charges for the period June 1, 2013 through May 31, 2014, and including associated changes in sales-and-use taxes) is an overall annual rate increase of approximately $52.2 million (this rate increase is in addition to the approximately $55.3 million approved by the NJBPU in June 2012, as discussed in the above paragraph). The rates were deemed “provisional” because ACE’s filing was not updated for actual revenues and expenses for April and May 2013. A review by NJBPU of the final underlying costs for reasonableness and prudence will be completed. On June 11, 2013, this matter was transmitted to the OAL for possible hearing.

Standard Offer Capacity Agreements

In April 2011, ACE entered into three SOCAs by order of the NJBPU, each with a different generation company, as more fully described in Note (2), “Significant Accounting Policies – Consolidation of Variable Interest Entities – ACE Standard Offer Capacity Agreements” and Note (10), “Derivative Instruments and Hedging Activities.” 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 dispute is pending before the NJBPU and has been referred to an Administrative Law Judge for further consideration. On April 11, 2013, the Superior Court of New Jersey Appellate Division issued an order consolidating the EDCs’ state court appeal of the NJBPU order (filed by the EDCs with the Appellate Division of the New Jersey Superior Court in June 2011) with a similar challenge filed by several generators and instructing the Administrative Law Judge to complete proceedings by June 15, 2013. The NJBPU filed a motion for clarification of the Appellate Division order, seeking an extension of time to complete the proceedings at the OAL. On June 28, 2013, the Appellate Division issued an order staying the consolidated appeals until September 30, 2013, and requiring the proceedings before the OAL and the NJBPU to be completed by that time.

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 New Jersey law under which the SOCAs were established on the grounds that it violates the Commerce Clause and the Supremacy Clause of the U.S. Constitution. In September 2012, the District Court denied motions for summary judgment filed by ACE and the other plaintiffs, as well as cross-motions filed by defendants. A bench trial was completed in May 2013 and final arguments were heard by the District Court Judge on June 17, 2013. It has not been determined when the District Court will issue 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.

Transmission ROE Challenge

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 Electric Municipal Corporation, Inc., filed a joint complaint with the Federal Energy Regulatory Commission (FERC) against ACE, Potomac Electric Power Company (Pepco), an affiliate of ACE, and Delmarva Power & Light Company (DPL), an affiliate of ACE, 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 ACE provides. The complainants claim to 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 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 it failed to meet the required burden to demonstrate that the existing rates and protocols are unjust and unreasonable.