Item 1. BUSINESS
Overview
Pepco Holdings, Inc. (Pepco Holdings or PHI) is a holding company that was incorporated in Delaware in 2001. Through its regulated public utility subsidiaries, PHI is engaged primarily in the transmission, distribution and default supply of electricity, and, to a lesser extent, the distribution and supply of natural gas. The principal executive offices of PHI are located at 701 Ninth Street, N.W., Washington, D.C. 20068.
PHI’s public utility subsidiaries are:
The service territories of each of Pepco Holdings’ utilities are depicted in the map below:
PHI’s three utility subsidiaries comprise a single operating segment for accounting purposes, which is referred to herein as “Power Delivery.”
In addition to its regulated utility operations, Pepco Holdings, through Pepco Energy Services, Inc. and its subsidiaries (collectively, Pepco Energy Services), is engaged in the following activities:
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providing energy savings performance contracting services principally to federal, state and local government customers;
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designing, constructing and operating combined heat and power, and thermal energy plants; and
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providing high voltage underground transmission construction and maintenance services and low voltage electric construction and maintenance services and streetlight construction services.
The operations of Pepco Energy Services collectively comprise a separate, second operating segment for accounting purposes. During 2013, Pepco Energy Services completed the wind-down of its retail electricity and natural gas supply businesses, and, as a result, these businesses are being accounted for as discontinued operations, as described below under “Discontinued Operations.”
Through its wholly owned subsidiary, Potomac Capital Investment Corporation (PCI), PHI previously held a portfolio of cross-border energy lease investments. During 2013, Pepco Holdings completed the termination of its interests in its cross-border energy lease investments, and as a result, these investments are being accounted for as discontinued operations, as described below under “Discontinued Operations.”
The following table shows PHI’s consolidated operating revenue and net income from continuing operations derived from the Power Delivery and Pepco Energy Services segments over the three preceding fiscal years.
For additional financial information with respect to PHI’s segments, see Note (5), “Segment Information,” to the consolidated financial statements of PHI.
PHI Service Company, a wholly owned subsidiary of PHI, provides a variety of support services, including legal, accounting, treasury, tax, purchasing and information technology services, to PHI and its operating subsidiaries. These services are provided pursuant to service agreements among PHI, PHI Service Company and the participating operating subsidiaries. The expenses of PHI Service Company are charged to PHI and the participating operating subsidiaries in accordance with cost allocation methodologies set forth in the service agreements.
Business Strategy
PHI’s business objective is to be a top-performing, regulated power delivery company that delivers safe and reliable electric and natural gas service to its customers and through its regulatory proceedings, earns a just and reasonable rate of return on, and receives timely recovery of, its utility investments.
In seeking to achieve this objective, Pepco Holdings’ business strategy is guided by its core values of safety, integrity and diversity and its mission of environmental stewardship, and is focused on the following initiatives:
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investing in its utilities’ transmission and distribution infrastructure;
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building a smarter grid and implementing other technological enhancements designed to:
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automate power delivery system functions and improve the reliability of the power distribution system;
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enable its utilities to restore power more quickly and efficiently;
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offer customers detailed information about, and options to help customers better manage, their energy usage; and
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enhance the customer experience and PHI’s communications with customers; and
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through Pepco Energy Services, providing comprehensive energy management solutions and developing, installing and operating renewable energy solutions.
In furtherance of its business strategy, PHI may from time to time enter into various transactions involving its businesses. These transactions may include joint ventures, the disposition of existing businesses or the acquisitions of new businesses. PHI also may from time to time refine components of its business strategy as it deems necessary or appropriate in response to business factors and other conditions, including regulatory requirements.
Overview of the Power Delivery Business
Distribution and Default Supply of Electricity
Each of PHI’s utility subsidiaries owns and operates a network of wires, substations and other equipment that are classified as transmission facilities, distribution facilities or common facilities (which are used for both transmission and distribution). Transmission facilities carry wholesale electricity into, out of and across the utilities’ service territories. Distribution facilities carry electricity from the transmission facilities to the customers located in the utilities’ service territories.
Each utility subsidiary is responsible for the distribution of electricity to customers within its service territory or territories and for which it is paid tariff rates established by the applicable public service commissions. While the transmission and distribution of electricity is regulated, the law of each of these service territories allows for competition in the supply of electricity, which enables distribution customers to contract to purchase their electricity from a supplier approved by the applicable public service commission. PHI’s utility subsidiaries supply electricity at regulated rates to customers who do not elect to purchase their electricity from a competitive supplier. These “default” supply services are referred to generally in this Form 10-K as Default Electricity Supply. The regulatory term for Default Electricity Supply is Standard Offer Service (SOS) in Delaware, the District of Columbia and Maryland, and Basic Generation Service (BGS) in New Jersey. The results of operations of PHI’s utility subsidiaries are only minimally impacted when customers choose to obtain their electricity through competitive suppliers because the utilities earn their approved rates of return by providing distribution service, and not by supplying the electricity.
Transmission of Electricity and Relationship With PJM
Each of PHI’s utility subsidiaries provides transmission services within the jurisdictions that encompass its electricity distribution service territory. In the aggregate, PHI owns approximately 4,600 miles of interconnected transmission lines with voltages ranging from 115 kilovolts (kV) to 500 kV. Under the Open Access Transmission Tariff adopted by the FERC, each owner of transmission services is required to provide transmission customers with non-discriminatory access to its transmission facilities at tariff rates approved by FERC.
The transmission facilities owned by Pepco, DPL and ACE are interconnected with the transmission facilities of contiguous utilities and are part of an interstate power transmission grid over which electricity is transmitted throughout a region encompassing the mid-Atlantic portion of the United States and parts of the Midwest. PJM is the FERC-approved independent operator of this transmission grid and manages the wholesale electricity market within its region. Pepco, DPL and ACE each are members of the PJM Regional Transmission Organization (PJM RTO), the regional transmission organization designated by FERC to coordinate the movement of wholesale electricity in PJM’s region.
In accordance with FERC-approved rules, Pepco, DPL, ACE and the other transmission-owning utilities in the PJM region make their transmission facilities available to PJM, and PJM directs and controls the operation of these transmission facilities. Each transmission owner is compensated at transmission rates approved by FERC for the use of its transmission facilities. PJM provides billing and settlement services, collects transmission service revenue from transmission service customers and distributes the revenue to the transmission owners.
PJM also directs the regional transmission planning process within its region. The Board of Managers of PJM reviews and approves all transmission expansion plans within the PJM region, including the construction of new transmission facilities by PJM members. Changes in the current policies for building new transmission lines ordered by FERC and implemented by PJM could result in additional competition to build transmission lines in the PJM region, including in the service territories of PHI’s utility subsidiaries, and could allow PHI’s utility subsidiaries the opportunity to construct transmission facilities in other service territories.
For a discussion of the regulation of transmission rates, see Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Regulatory and Other Matters - Rate Proceedings - Transmission” and for a discussion of recently completed and pending FERC transmission rate proceedings, see Note (7), “Regulatory Matters - Rate Proceedings - Federal Energy Regulatory Commission,” to the consolidated financial statements of PHI.
Distribution and Supply of Natural Gas
DPL owns pipelines and other equipment for the distribution and supply of natural gas. DPL uses its natural gas distribution facilities to deliver natural gas to retail customers in its service territory and provides transportation-only services to customers that purchase natural gas from another supplier. Intrastate transportation customers pay DPL distribution service rates approved by the Delaware Public Service Commission (DPSC). Rates for the interstate transportation and sale of wholesale natural gas are regulated by FERC. DPL purchases natural gas supplies for resale to its retail service customers from marketers and producers through a combination of long-term agreements and next-day distribution arrangements.
PHI’s Utility Subsidiaries
Potomac Electric Power Company
Pepco’s electric distribution service territory consists of the District of Columbia and major portions of Prince George’s County and Montgomery County in Maryland. The service territory covers approximately 640 square miles and, as of December 31, 2013, had a population of approximately 2.2 million. This region is economically diverse and includes key industries that contribute to the regional economic base:
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Commercial activities in the region include professional and medical services, government and education, shopping malls, tourism and transportation.
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Industrial activities in the region include chemical, glass, pharmaceutical, steel manufacturing, food processing and oil refining.
The following table shows the number of Pepco distribution customers in each of its service territories as of the end of each of the preceding three years.
Pepco distributed a total of 25,801,000, 26,006,000 and 26,895,000 megawatt (MW) hours (MWh) of electricity in 2013, 2012 and 2011, respectively. The following table shows the allocation by percentage among customer types of the total MWh of electricity delivered by Pepco in each of its service territories during each of the preceding three fiscal years:
Pepco has been designated as the default electricity supplier in its District of Columbia and Maryland service territories by the District of Columbia Public Service Commission (DCPSC) and the Maryland Public Service Commission (MPSC), respectively. Pepco purchases the electricity required to satisfy its SOS obligations from wholesale suppliers primarily under contracts entered into in accordance with competitive bid procedures approved and supervised by each of the DCPSC and the MPSC. For commercial customers in the District of Columbia and large commercial customers in Maryland that do not purchase their electricity from a competitive supplier, Pepco is obligated to provide Hourly Priced Service (HPS), a form of SOS service for which Pepco purchases the electricity in the next-day and other short-term PJM RTO markets.
Under orders issued by the DCPSC, Pepco is obligated to provide SOS to residential and small, medium-sized and large commercial customers in the District of Columbia indefinitely. Under orders issued by the MPSC, Pepco is obligated to provide SOS to residential and small commercial customers and to medium-sized commercial customers in Maryland through November 2014. As contracts expire, they are rebid annually by Pepco through the MPSC-approved request for proposal process. Pepco is paid tariff rates for the transmission and distribution of electricity over its transmission and distribution facilities to all electricity customers in its service territory, whether the customer receives SOS or HPS, or purchases electricity from a competitive supplier, and is entitled to recover from its SOS and HPS customers the costs of acquiring the electricity, plus an administrative charge that is intended to allow it to recover its administrative costs, plus a modest margin, which varies depending on the customer class.
The following table shows for Pepco customers in the District of Columbia and Maryland the percentage of distribution sales (measured by MWh) over the past three fiscal years to SOS customers.
In the District of Columbia, under various acts of Congress, pursuant to Pepco’s corporate charter, and subject to the supervision of the DCPSC, Pepco has the non-exclusive authority to install and maintain overhead and underground transmission and distribution lines and other related facilities for the furnishing of electricity. Pepco’s right to occupy public space for utility purposes is by permit from the District of Columbia and the federal government. Pepco is the only public utility that distributes electricity for sale to the public in the District of Columbia.
In Maryland, Pepco operates pursuant to state-wide franchises granted by Maryland’s General Assembly that are unlimited in duration. These franchises were granted to Pepco or to predecessor companies acquired by Pepco, and confer, among other things, the ability to construct electric transmission and distribution lines. Pursuant to statute, public service companies in Maryland may exercise a franchise to the extent authorized by the MPSC. The service territories for Pepco, as well as for other electric utilities in the state, were precisely delineated in 1966 by the MPSC and have been modified in minor ways over the years.
Delmarva Power & Light Company
DPL is engaged in the transmission, distribution and default supply of electricity in portions of Delaware and Maryland. In northern Delaware, DPL also supplies and delivers natural gas to retail customers and provides transportation-only services to retail customers that purchase natural gas from another supplier.
In Maryland, DPL operates pursuant to state-wide franchises that are substantially similar in nature to those described above with respect to Pepco’s Maryland operations. DPL’s exclusive and continuing authority to distribute electricity and natural gas in its non-municipal service territories in Delaware is derived from legislation, through which the DPSC has established exclusive service territories. With respect to municipalities that it serves, DPL provides service under various franchises granted to DPL and predecessor companies, which franchises are generally either unlimited as to time or renew automatically.
Distribution and Supply of Electricity
DPL’s electric distribution service territory consists of the state of Delaware, and Caroline, Cecil, Dorchester, Harford, Kent, Queen Anne’s, Somerset, Talbot, Wicomico and Worcester counties in Maryland. This territory covers approximately 5,000 square miles and, as of December 31, 2013, had a population of approximately 1.4 million. This region is economically diverse and includes the following key industries that contribute to the regional economic base:
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Commercial activities in the region include banking, government, insurance, shopping malls, casinos and tourism.
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Industrial activities in the region include chemical, pharmaceutical, steel manufacturing and oil refining.
The following table shows the number of DPL electricity distribution customers in each of its service territories as of the end of each of the preceding three fiscal years.
DPL distributed a total of 12,465,000, 12,641,000 and 12,688,000 MWh of electricity in 2013, 2012 and 2011, respectively. The following table shows the allocation by percentage among customer types of the total MWh of electricity delivered by DPL in each of its service territories during each of the preceding three fiscal years:
DPL has been designated as the default electricity supplier in its Delaware and Maryland service territories by the DPSC and the MPSC, respectively. DPL purchases the electricity required to satisfy its SOS obligations from wholesale suppliers primarily under contracts entered into in accordance with competitive bid procedures approved and supervised by each of the DPSC and the MPSC. DPL also has an obligation to provide HPS for its largest customers in Delaware and its large customers in Maryland. DPL acquires power to supply its HPS customers in the next-day and other short-term PJM RTO markets.
Under orders issued by the DPSC, DPL is obligated to provide SOS to residential, small commercial and industrial customers in Delaware through May 2017, and to medium, large and general service commercial customers in Delaware through May 2015. Under orders issued by the MPSC, DPL is obligated to provide SOS to residential and small commercial customers in Maryland until further action of the Maryland General Assembly, and to medium-sized commercial customers in Maryland through November 2014. As contracts expire, they are rebid annually by DPL through the MPSC approved request for proposal process. In Delaware and Maryland, DPL is paid tariff rates for the transmission and
distribution of electricity over its transmission and distribution facilities to all electricity customers in its service territories, whether the customer receives SOS or HPS, or purchases electricity from a competitive supplier. In Delaware, DPL is also entitled to recover from its SOS and HPS customers the associated costs of acquiring the electricity (including transmission, capacity and ancillary services costs and costs to satisfy renewable energy requirements), plus an amount referred to as a Reasonable Allowance for Retail Margin. In Maryland, DPL is entitled to recover from its SOS and HPS customers the costs of acquiring the electricity, plus an administrative charge that is intended to allow it to recover its administrative costs, plus a modest margin, which varies depending on the customer class.
The following table shows for DPL customers in Delaware and Maryland the percentage of distribution sales (measured in MWh) over the past three fiscal years to SOS customers.
Distribution and Supply of Natural Gas
DPL provides regulated natural gas supply and distribution service to customers in a service territory consisting of a major portion of New Castle County in Delaware. This service territory covers approximately 275 square miles and, as of December 31, 2013, had a population of approximately 500,000.
Large volume commercial, institutional, and industrial natural gas customers may purchase natural gas from DPL. Alternatively, a customer receiving a “transportation-only” service from DPL will purchase natural gas from a competitive supplier and have the natural gas delivered through DPL’s distribution facilities. The following table provides certain information regarding DPL’s natural gas distribution business for each of the last three fiscal years.
The following table shows on a percentage basis the allocation among customer types of the Mcf of natural gas delivered by DPL in Delaware in each of the preceding three fiscal years.
Atlantic City Electric Company
Electricity Distribution and Supply
ACE’s electric distribution service territory consists of Gloucester, Camden, Burlington, Ocean, Atlantic, Cape May, Cumberland and Salem counties in southern New Jersey. The service territory covers approximately 2,700 square miles and had, as of December 31, 2013, a population of approximately 1.1 million. This region is economically diverse and includes key industries that contribute to the regional economic base:
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Commercial activities in the region include professional services, government, shopping malls, casinos, and tourism.
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Industrial activities in the region include chemical, glass, food processing and oil refining.
The following table provides certain information regarding ACE’s electric distribution business for each of the last three fiscal years.
The following table shows the allocation by percentage among customer types of the total MWh of electricity delivered by ACE during each of the preceding three fiscal years.
ACE has been designated as the default electricity supplier in its service territory by the New Jersey Board of Public Utilities (NJBPU). In New Jersey, each of the state’s electric distribution companies, including ACE, jointly obtains the electricity to meet such companies’ collective BGS obligations from competitive suppliers selected through auctions authorized by the NJBPU for the supply of New Jersey’s total BGS requirements. Each winning bidder is required to supply its committed portion of the BGS customer load with full requirements service, consisting of power supply and transmission service. ACE provides two types of BGS:
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fixed price BGS, which is provided to smaller commercial and residential customers at seasonally-adjusted fixed prices (which as of December 31, 2013, had a peak load of approximately 1,429 MW and represented approximately 97% of ACE’s total BGS load); and
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commercial and industrial energy price BGS, which is provided to large customers at hourly PJM RTO real-time market prices for a term of 12 months (which as of December 31, 2013, had a peak load of approximately 42 MW and represented approximately 3% of ACE’s total BGS load).
ACE is paid tariff supply rates established by the NJBPU that compensate it for the cost of obtaining the BGS supply. These rates are set such that ACE does not make any profit or incur any loss with respect to the supply component of its BGS obligations. ACE is also paid tariff rates for the transmission and distribution of electricity over its transmission and distribution facilities to all electricity customers in its service territory, whether the customer receives BGS or purchases electricity from a competitive supplier.
For the year ended December 31, 2013, 48% of ACE’s total distribution sales (measured in MWh) were to BGS customers, as compared to 51% and 56% in 2012 and 2011, respectively.
ACE operates under non-exclusive franchises that have been granted by the NJBPU and under certain non-exclusive consents from municipalities in which ACE provides service. While most of the municipal consents were granted in perpetuity, two of the municipal consents require renewal on a periodic basis in accordance with their terms, and are subject to the ultimate review and approval of the NJBPU. All of the franchises and consents are currently in full force and effect.
Atlantic City Electric Transition Funding LLC
In 2001, ACE established Atlantic City Electric Transition Funding LLC (ACE Funding) solely for the purpose of securitizing authorized portions of ACE’s recoverable stranded costs through the issuance and sale of bonds (Transition Bonds). The proceeds of the sale of each series of Transition Bonds were transferred to ACE in exchange for the transfer by ACE to ACE Funding of the right to collect a non-bypassable transition bond charge (Transition Bond Charge) from ACE customers pursuant to bondable stranded costs rate orders issued by the NJBPU in an amount sufficient to fund the principal and interest payments on the Transition Bonds and related taxes, expenses and fees (Bondable Transition Property). The assets of ACE Funding, including the Bondable Transition Property, and the Transition Bond Charges (representing revenue ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds and related taxes, expenses and fees) collected from ACE’s customers, are not available to creditors of ACE. The holders of Transition Bonds have recourse only to the assets of ACE Funding.
Smart Grid Initiatives
PHI’s utility subsidiaries are engaged in transforming the power grid that they own and operate into a “smart grid,” a network of automated digital devices capable of collecting and communicating large amounts of real-time data. PHI believes that the smart grid benefits its customers by:
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improving service reliability of the energy distribution system;
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automating specific distribution system functions;
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enabling its utilities to restore energy to customers more quickly and efficiently;
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facilitating more efficient use of energy to meet the challenges of rising energy costs and governmental energy reduction goals;
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permitting its utilities to obtain and communicate to their customers timely and accurate information regarding energy usage and outages; and
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enhancing communications with its customers and the overall customer experience.
A central component of the smart grid is advanced metering infrastructure (AMI), a system that collects, measures and analyzes energy usage data from advanced digital meters, known as “smart meters.” Also critical to the operation of the smart grid is distribution automation technology, which is comprised of automated devices that have internal intelligence and can be controlled remotely to better manage power flow and restore service quickly and more safely. Both the AMI system and distribution automation are enabled by advanced technology that communicates with devices installed on the energy delivery system and transmits energy usage data to the host utility. The implementation of the AMI system and distribution automation involves an integration of technologies provided by multiple vendors.
The installation of smart meters in the service territories of each of PHI’s utility subsidiaries is subject to approval by the applicable public service commissions. The regulatory and implementation status of Pepco Holdings’ AMI smart meter activities as of December 31, 2013 was as follows:
Utility
Jurisdiction
Regulatory Status
Installation and Activation Status
Pepco
Maryland
Approved
Complete
District of Columbia
Approved
Complete
DPL (Electric)
Delaware
Approved
Complete
Maryland
Approved
Estimated Completion 3Q 2014
DPL (Natural Gas)
Delaware
Approved
Substantially Complete
ACE
New Jersey
Not approved
N/A
The DCPSC, the MPSC and the DPSC have approved the creation by PHI’s utility subsidiaries of regulatory assets to defer AMI costs between rate cases and to accrue returns on the deferred costs. Thus, these costs will be recovered in the future through base rates; however, for AMI costs incurred by Pepco in Maryland with respect to test years after 2011, pursuant to an MPSC order, the recovery of such costs will be allowed when Pepco demonstrates that the AMI system is cost-effective. The MPSC’s July 2013 order in Pepco’s November 2012 electric distribution base rate application excluded 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.
In 2010, two of PHI’s utility subsidiaries were granted cash awards in the aggregate amount of $168 million by the U.S. Department of Energy to support their smart grid initiatives.
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Pepco was awarded $149 million for AMI, direct load control, distribution automation and communications infrastructure, of which $145 million has been received through December 31, 2013.
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ACE was awarded $19 million for direct load control, distribution automation and communications infrastructure, of which $17 million has been received through December 31, 2013.
For a discussion of the projected capital expenditures of each utility subsidiary associated with PHI’s smart grid initiatives over the period 2014 through 2018, see Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity - Capital Requirements.”
Utility Capital Expenditures
PHI’s utility subsidiaries devote a substantial portion of their total capital expenditures to improving the reliability of their electrical transmission and distribution systems and replacing aging infrastructure throughout their service territories. These activities include:
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identifying and upgrading under-performing feeder lines;
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adding new facilities to support load;
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installing distribution automation systems on both the overhead and underground network systems; and
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rejuvenating and replacing underground residential cables.
In addition, PHI’s utility subsidiaries devote capital expenditures to increasing transmission and distribution system capacity, providing resiliency against major storm events, providing operating and system flexibility and installing and upgrading facilities for new and existing customers. For a discussion of PHI’s consolidated capital expenditure plan for 2014 through 2018, see Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity - Capital Requirements - Capital Expenditures.”
Maryland Grid Resiliency Task Force
In September 2012, a Grid Resiliency Task Force established through an executive order issued by the Governor of Maryland issued a report containing 11 recommendations on improving the resiliency and reliability of the electric distribution system in Maryland. In October 2012, the Governor of Maryland forwarded the report to the MPSC and urged the MPSC to implement quickly four of the Grid Resiliency Task Force’s recommendations:
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strengthen existing reliability and storm restoration regulations;
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accelerate the investment necessary to meet the enhanced metrics;
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allow surcharge recovery for the accelerated investment; and
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implement clearly defined performance metrics into the traditional ratemaking scheme.
Components of Pepco’s electric distribution base rate case filed with the MPSC in November 2012 and DPL’s electric distribution base rate case filed with the MPSC in March 2013 were intended to address the Grid Resiliency Task Force recommendations. In July and August 2013, the MPSC issued orders in these base rate cases that only partially approved these components. See Note (7), “Regulatory Matters - Rate Proceedings - Maryland” to the consolidated financial statements of PHI for more information about these base rate cases.
District of Columbia Proposed Undergrounding Legislation
In August 2012, the Mayor of the District of Columbia issued an Executive Order establishing the Mayor’s Power Line Undergrounding Task Force (the DC Undergrounding Task Force). In May 2013, the DC Undergrounding Task Force issued a written recommendation endorsing a $1 billion plan 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 DC Undergrounding Task Force recommendations contemplates that:
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$500 million of the estimated cost would be funded by Pepco, with recovery of its investment to be made through surcharges to be billed to Pepco District of Columbia customers;
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$375 million of the estimated cost would be financed by the District of Columbia’s issuance of securitized bonds, which bonds would be repaid through surcharges to be billed to Pepco District of Columbia customers (Pepco would not earn a return on or of the cost of the assets funded with the proceeds of these securitized bonds); and
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the remaining $125 million would be funded through the District of Columbia Department of Transportation’s existing capital projects program.
This legislation was approved by the Council of the District of Columbia on February 4, 2014 and is awaiting the signature of the Mayor of the District of Columbia. Once signed by the Mayor and transmitted to Congress, the legislation will undergo a 30-day Congressional review period before becoming law, which is expected to be completed in the second quarter of 2014. The final step would be for the DCPSC to approve the underground project plan and issue financing orders to establish the customer surcharges contemplated by the undergrounding law. A decision by the DCPSC on such actions would likely occur during the fourth quarter of 2014.
NERC Reliability Standards
NERC has established, and FERC has approved, reliability standards with regard to the bulk power system that impose certain operating, planning and cyber security requirements on Pepco, DPL and ACE. There are eight NERC regional oversight entities, including ReliabilityFirst Corporation (RFC), of which Pepco, DPL, ACE and Pepco Energy Services are members. These oversight entities are charged with the day-to-day implementation and enforcement of NERC’s reliability standards, which impose certain operating, planning and cybersecurity requirements on the bulk power systems of each utility. RFC performs compliance audits on entities registered with NERC based on reliability standards and criteria established by NERC. NERC and RFC also conduct compliance investigations in response to a system disturbance, complaint, or possible violation of a reliability standard identified by other means. Each of PHI’s utility subsidiaries are subject to routine audits and monitoring for compliance with applicable NERC reliability standards, including standards requested by FERC to increase the number of assets designated as “critical assets” (including cybersecurity assets) subject to NERC’s cybersecurity standards. NERC is empowered to impose financial penalties, fines and other sanctions for non-compliance with certain rules and regulations.
Energy Efficiency Initiatives
Dynamic Pricing
Dynamic pricing provides customers with incentives to reward them for decreasing their energy use during peak energy demand periods, when energy demand and consequently, the cost of supplying electricity, are higher. PHI’s dynamic pricing rate structures, implemented in tandem with PHI’s smart grid, provide customers with billing credits when they reduce their power usage in response to their utility’s request.
Dynamic pricing has been approved by the respective public service commissions and is in place for Pepco customers in Maryland and DPL customers in Delaware. As of December 31, 2013, approximately 625,000 Pepco customers in Maryland and 293,000 DPL customers in Delaware have received dynamic pricing program credits. Dynamic pricing has been approved in concept pending AMI deployment for DPL’s Maryland SOS customers. Pepco’s dynamic pricing proposal in the District of Columbia was rejected by the DCPSC on February 7, 2014. Pepco is considering its options in that jurisdiction with respect to dynamic pricing. Dynamic pricing has not been approved at this time by the NJBPU for ACE’s customers in New Jersey.
Utility Energy Efficiency Programs
Each of Pepco, DPL and ACE has implemented the Energy Wise Rewards™ program, which allows participating customers to reduce energy usage and costs by authorizing the utility to cycle their air conditioner compressors off and on during high energy demand periods. Customers participating in this program are eligible to receive a credit on their bill. Pepco and DPL have also implemented a portfolio of energy efficiency programs designed to reduce energy consumption in Maryland, including appliance rebate and recycling, home energy check-ups, rebates on the purchase of energy efficiency equipment and services and discounts on energy efficient light bulbs and lighting fixtures. The MPSC has approved a customer surcharge through 2014 to recover Pepco’s and DPL’s costs associated with these energy efficiency programs.
Pepco Energy Services
Pepco Energy Services is engaged in the following:
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Energy savings performance contracting business: designing, constructing and operating energy efficiency projects and distributed generation equipment, including combined heat and power plants, principally for federal, state and local government customers;
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Underground transmission and distribution business: providing underground transmission and distribution construction and maintenance services for electric utilities in North America; and
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Thermal business: providing steam and chilled water under long-term contracts through systems owned and operated by Pepco Energy Services, primarily to hotels and casinos in Atlantic City, New Jersey.
The energy savings performance contracting business is highly competitive, and Pepco Energy Services competes with other energy services companies primarily with respect to contracts with federal, state and local governments and independent agencies. Many of these energy services companies are subsidiaries of larger building controls and equipment providers or utility holding companies. Competitive offerings include a wide range of electrical and thermal system upgrades, improved controls, and generation equipment such as combined heat and power units. Among the factors as to which companies in this business compete are the amount and duration of the guarantees provided in energy savings performance contracts and the quality and value of service provided to customers. In connection with many of Pepco Energy Services’ energy savings performance contracts, Pepco Energy Services provides performance guarantees, including guarantees of a certain level of energy savings. This business is affected by new entrants into the market, the financial strength of customers, governmental directives regarding energy efficiency, energy prices, and general economic conditions. Pepco Energy Services’ backlog of construction contracts in this business increased to $91 million at year-end 2013 from $82 million at year-end 2012. Pepco Energy Services estimates that it will complete $88 million of the construction contracts in its backlog in 2014 and $3 million in 2015.
Most of Pepco Energy Services’ energy savings performance contracts with federal, state and local governments, as well as those with independent agencies, such as housing and water authorities, contain provisions authorizing the governmental authority or independent agency to terminate the contract at any time. Those provisions include explicit mechanisms which, if exercised, would require the other party to pay Pepco Energy Services for work performed through the date of termination and for additional costs incurred as a result of the termination.
Through its wholly owned subsidiary, W.A. Chester, L.L.C., Pepco Energy Services constructs and maintains underground transmission and distribution projects for electric utilities in North America. W.A. Chester is one of the two largest North American contractors that specializes in the installation and maintenance of pipe-type cable systems, a technology that W.A. Chester believes currently accounts for the majority of existing underground transmission circuit miles in North America. W.A. Chester’s primary competitor in the pipe-type cable system market is UTEC Constructors Corporation, and there are several other contractors that do not specialize in this cable system but rather undertake installation projects on a more limited basis. W.A. Chester also competes in the market for the installation and maintenance of solid dielectric cable, which is a relatively newer technology compared to pipe-type cable systems. The solid dielectric cable installation and maintenance market is highly competitive and composed of numerous different competitors, and the barriers to entry in this market are relatively low. The principal factors for competition in both of these markets are price, experience, customer service and ability to handle a wide range of utility applications. W.A. Chester believes its competitive strengths in both of these markets are the breadth of its experience in working with both technologies in various utility applications (including new installations, modifications, upgrades and maintenance of existing systems), its in-depth knowledge of the U.S. and Canadian utility industries and utility customers’ needs, and its ability to manage successfully all phases of these projects for the customer. W.A. Chester’s backlog of construction contracts increased to $84 million at year-end 2013 from $38 million at year-end 2012. W.A. Chester estimates that it will complete $73 million of the construction contracts in its backlog in 2014 and $11 million in 2015.
Revenues associated with Pepco Energy Services’ combined heat and power thermal generating plant and operations are concentrated with a few major customers in the Atlantic City hotel and casino industry. Pepco Energy Services has long-term contracts with these customers, and for the largest customer, the contracts expire in 2017. The Atlantic City hotel and casino industry has been experiencing a decrease in gaming revenues and overcapacity, as well as potential future competition from casinos that are being constructed in nearby markets. As a result, Pepco Energy Services is exposed to the risk that it may not be able to renew these contracts or that the contract counterparties may fail to perform their obligations thereunder.
PHI guarantees the obligations of Pepco Energy Services under certain contracts in its energy savings performance contracting business and underground transmission and distribution construction business. At December 31, 2013, PHI’s guarantees of Pepco Energy Services’ obligations under these contracts totaled $190 million. PHI also guarantees the obligations of Pepco Energy Services under surety bonds obtained by Pepco Energy Services for construction projects in these businesses. These guarantees totaled $229 million at December 31, 2013.
During 2012, Pepco Energy Services deactivated its Buzzard Point oil-fired generation facility and its Benning Road oil-fired generation facility, and in 2013 began work to demolish the Benning Road facility. This demolition is expected to be completed by the end of 2014. At December 31, 2013, Pepco Energy Services owned five renewable energy generating facilities, with an aggregate generating capacity of 17,400 KW. See Part I, Item 2. “Properties - Generating Facilities” for more information about these facilities.
Discontinued Operations
Through its subsidiary Potomac Capital Investment Corporation, PHI maintained a portfolio of cross-border energy lease investments. During the third quarter of 2013, PHI completed the termination of its interests in its cross-border energy lease investments. These activities, which previously comprised substantially all of the operations of the Other Non-Regulated segment, are being accounted for as discontinued operations. The remaining operations of the Other Non-Regulated segment, which no longer meet the definition of a separate segment for financial reporting purposes, are being included in Corporate and Other. Substantially all of the information in the notes to the consolidated financial statements of PHI with respect to the cross-border energy lease investments has been consolidated in Note (19), “Discontinued Operations - Cross-Border Energy Lease Investments.”
In 2013, Pepco Energy Services completed a previously announced wind-down of its retail electric and retail natural gas supply businesses. These operations are being accounted for as discontinued operations and are no longer a part of the Pepco Energy Services segment for financial reporting purposes. Substantially all of the information in the notes to the consolidated financial statements of PHI with respect to Pepco Energy Services’ retail electric and retail natural gas supply businesses has been consolidated in Note (19), “Discontinued Operations - Retail Electric and Natural Gas Supply Businesses of Pepco Energy Services.”
Seasonality
Power Delivery
The operating results of Power Delivery historically have been directly related to the volume of electricity delivered to its customers, producing higher revenues and net income during periods when customers consumed higher amounts of electricity (usually during periods of extreme temperatures) and lower revenues and net income during periods when customers consumed lower amounts of electricity (usually during periods of mild temperatures). This has been due in part to the longstanding practice of tying the distribution charges paid by customers to kilowatt-hours of electricity used. Because most of the costs associated with the distribution of electricity do not vary with the volume of electricity delivered, this pricing mechanism also contributed to seasonal variations in net income.
As a result of the implementation of a bill stabilization adjustment (BSA) for retail customers of Pepco and DPL in Maryland and for customers of Pepco in the District of Columbia, distribution revenues from utility customers in these jurisdictions have been decoupled from the amount of electricity delivered. Under the BSA, utility customers pay an approved distribution charge for their electric service which does not vary by electricity usage. This change has had the effect of aligning annual distribution revenues more closely with annual distribution costs. In addition, the change has had the effect of eliminating changes in customer electricity usage, whether due to weather conditions or for any other reason, as a factor having an impact on annual distribution revenue and net income in those jurisdictions. The BSA also eliminates what otherwise might be a disincentive for the utility to aggressively develop and promote efficiency
programs. A comparable revenue decoupling mechanism proposed for DPL electricity and natural gas customers in Delaware is under consideration by the DPSC although there was little activity in this matter in 2013. Distribution revenues are not decoupled for the distribution of electricity by ACE in New Jersey, and thus are subject to variability due to changes in customer consumption.
In contrast to electricity distribution costs, the cost of the electricity supplied, which is the largest component of a customer’s bill, does vary directly in relation to the volume of electricity used by a customer. Accordingly, whether or not a BSA is in effect for the jurisdiction, the revenues of Pepco, DPL and ACE from the supply of electricity and natural gas vary based on consumption and on this basis are seasonal. Because the revenues received by each of the utility subsidiaries for the default supply of electricity and natural gas closely approximate the supply costs, the impact on net income is immaterial, and therefore is not seasonal.
Pepco Energy Services
The energy services business of Pepco Energy Services is not seasonal, except with respect to its thermal operations. The thermal operations of Pepco Energy Services provide steam and chilled water to customers year-round. Steam usage peaks during months with colder temperatures and chilled water usage peaks during months with warmer temperatures. The rates charged customers adjust quarterly for the cost of natural gas used to produce steam and electricity used to produce chilled water. Pepco Energy Services’ revenues and gross profit from its thermal operations will fluctuate based on the volumes of steam and chilled water delivered to customers.
Regulation
The operations of PHI’s utility subsidiaries, including the rates and tariffs they are permitted to charge customers for the transmission and distribution of electricity, and, in the case of DPL, the distribution and transportation of natural gas, are subject to regulation by governmental agencies in the jurisdictions in which the subsidiaries provide utility service as described above in “ - PHI’s Utility Subsidiaries.” Rates and tariffs are established by these regulatory commissions. PHI’s utility subsidiaries have filed or plan to file rate cases in each of its jurisdictions as further described in Note (7), “Regulatory Matters - Rate Proceedings,” to the consolidated financial statements of PHI.
In addition to the other regulatory matters described elsewhere in this section and in Note (7), “Regulatory Matters,” to the consolidated financial statements of PHI, provided below are summary descriptions of certain regulatory matters involving PHI’s utility subsidiaries.
Mitigation of Regulatory Lag
An important factor in the ability of PHI’s utility subsidiaries to earn their authorized ROE is the willingness of applicable public service commissions to adequately address the shortfall in revenues in a utility’s rate structure due to the delay in time or “lag” between when costs are incurred and when they are reflected in rates. This delay is commonly known as “regulatory lag.” Pepco, DPL and ACE are currently experiencing significant regulatory lag because investments in rate base and operating expenses are increasing more rapidly than their revenue growth.
In an effort to minimize the effects of regulatory lag, PHI’s utility subsidiaries are:
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filing electric distribution base rate cases every nine to twelve months in each of their jurisdictions,
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pursuing alternative ratemaking mechanisms,
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evaluating potential reductions in planned capital expenditures, and
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continuing outreach to the regulatory community and other stakeholders, to discuss the changing regulatory model economics that are causing regulatory lag.
Alternative mechanisms that may reduce regulatory lag include adjusting historic test periods in distribution base rate cases to recognize plant additions which are already being used to provide service to customers when new rates go into effect, grid resiliency charges to allow contemporaneous cost recovery of costs for infrastructure related to system reliability, and multi-year rate plans.
Each of PHI’s utility subsidiaries will continue to seek cost recovery from applicable public service commissions to reduce the effects of regulatory lag and have an opportunity to earn its authorized ROE. There can be no assurance that any attempts by PHI’s utility subsidiaries to mitigate regulatory lag will be approved or, that even if approved, the cost recovery mechanisms will fully mitigate the effects of regulatory lag.
FERC MAPP Abandonment Cost Filing
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 MAPP, a 152-mile high-voltage interstate transmission line, to address the reliability needs of the region’s transmission system. In December 2012, PHI submitted a filing to FERC seeking recovery of $88 million of abandoned MAPP costs over a five-year period. 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.
In February 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.
In December 2013, PHI submitted a settlement agreement to FERC with respect to this matter. Under the terms of the proposed settlement agreement, Pepco and DPL would recover their abandoned MAPP costs over a three-year recovery period beginning June 1, 2013. The settlement agreement, which is subject to FERC approval, would resolve all issues concerning the recovery of abandonment costs associated with the cancellation of the MAPP project. The terms of this settlement, if approved, would not be subject to the pending formula rate or transmission ROE challenges at FERC or modification through any other FERC proceeding. PHI cannot predict the timing or results of a final FERC decision in this proceeding.
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 requiring Pepco, DPL and Baltimore Gas and Electric Company (BGE) (collectively, the Contract EDCs) to negotiate and enter into a contract with the winning bidder for the construction of a 661 MW natural gas-fired combined cycle generation plant in Waldorf, Maryland, with an expected commercial operation date of June 1, 2015. The April 2012 order specified that each of the Contract EDCs will recover its costs associated with the contract through surcharges on its 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 order. In May 2012, the Contract EDCs and other parties also filed notices of appeal in circuit courts in Maryland requesting judicial review of the MPSC order, and these notices of appeal were consolidated in a single appeal in the Circuit Court for Baltimore City.
In September and October 2013, the U.S. District Court issued a final decision and order, respectively, holding that the MPSC order violated the Supremacy Clause of the U.S. Constitution and finding that the contracts that had been entered into in June 2013 between each of the Contract EDCs and the winning bidder (as mandated by an April 2013 order of the MPSC) were illegal and unenforceable. In November 2013, the MPSC and the winning bidder appealed the U.S. District Court’s decision and order to the U.S. Circuit Court of Appeals for the Fourth Circuit. This appeal presently remains pending.
In October 2013, the Maryland Circuit Court for Baltimore County issued a ruling upholding the MPSC’s orders requiring the Contract EDCs to enter into the contracts. The Contract EDCs, the Maryland Office of People’s Counsel and one generating company have appealed the Maryland Circuit Court’s ruling to the Maryland Court of Special Appeals. This appeal presently remains pending.
PHI, Pepco and DPL continue to evaluate these proceedings to determine, if the contracts are found to be valid and enforceable: (i) the extent of the negative effect that the contracts may have on the credit metrics of PHI, Pepco and DPL, as calculated by independent rating agencies that evaluate and rate PHI, Pepco and DPL, and their debt issuances, (ii) the effect on the ability of Pepco and DPL to recover their associated costs of the contracts if a significant number of SOS customers elect to buy their energy from competitive energy suppliers, and (iii) the effect of the contracts on the financial condition, results of operations and cash flows 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, as more fully described in Note (13), “Derivative Instruments and Hedging Activities,” to the consolidated financial statements of PHI. 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.
ACE and the other EDCs in New Jersey 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). This dispute was pending before the NJBPU; however, in April 2013, it was consolidated with an appeal filed in June 2011 by the EDCs in the Superior Court of New Jersey Appellate Division.
In February 2011, ACE joined other plaintiffs in an action filed in the U.S. District Court for the District of New Jersey challenging the NJ SOCA Law on the grounds that it violates the Commerce Clause and the Supremacy Clause of the U.S. Constitution. In October 2013, the U.S. 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, and an order deciding that the remaining SOCAs are void, invalid and unenforceable. The U.S. District Court decision’s has been appealed to the U.S. Third Circuit Court of Appeals, and this appeal presently remains pending. In light of the U.S. District Court’s decision, the New Jersey Appellate Division dismissed the EDCs’ appeal without prejudice, subject to the EDCs’ rights to revive their appeal if the U.S. District Court’s decision is reversed.
Delaware Renewable Energy Portfolio Standards
DPL is subject to Renewable Energy Portfolio Standards (RPS) in the state of Delaware that require it to obtain renewable energy credits (RECs) for energy delivered to its customers. In July 2011, the Governor of the State of Delaware signed legislation that expanded DPL’s RPS obligations beginning in 2012. Before this legislation, DPL was required to obtain RECs for energy delivered only to SOS customers in Delaware; the legislation expands that requirement to energy delivered to all of DPL’s distribution customers in Delaware. DPL’s costs associated with obtaining RECs to fulfill its RPS obligations are recoverable from its distribution customers by law.
The legislation also establishes that the energy output from fuel cells manufactured in Delaware capable of running on renewable fuels is an eligible resource for RECs under the Renewable Portfolio Standards Act. The legislation requires that the DPSC adopt a tariff under which DPL would be an agent that collects payments from its customers and disburses the amounts collected to a qualified fuel cell provider that deploys Delaware-manufactured fuel cells as part of a 30-megawatt generation facility. The
legislation also provides for a reduction in DPL’s REC and solar REC requirements based upon the actual energy output of the 30-megawatt generation facility. In October 2011, the DPSC approved the tariff submitted by DPL in response to the legislation. For more information on the tariff, see Note (16), “Variable Interest Entities - DPL Renewable Energy Transactions,” to the consolidated financial statements of PHI.
Environmental Matters
PHI, through its subsidiaries, is subject to regulation by various federal, regional, state, and local authorities with respect to the environmental effects of its operations, including air and water quality control, solid and hazardous waste disposal, greenhouse gas emissions, and limitations on land use. In addition, federal and state statutes authorize governmental agencies to compel responsible parties to clean up certain abandoned or unremediated hazardous waste sites. PHI’s subsidiaries may incur costs to clean up currently or formerly owned facilities or sites found to be contaminated, as well as other facilities or sites that may have been contaminated due to past disposal practices. PHI’s subsidiaries may also be responsible for ongoing environmental remediation costs associated with facilities or operations that have been sold to third parties as further described in Note (15), “Commitments and Contingencies - Environmental Matters - Conectiv Energy Wholesale Power Generation Sites,” to the consolidated financial statements of PHI.
PHI’s subsidiaries’ currently projected capital expenditures for the replacement of existing or installation of new environmental control facilities that are necessary for compliance with environmental laws, rules or agency orders are approximately $7.5 million in 2014, $7.8 million in 2015, and $2.4 million in each of 2016, 2017 and 2018. The projections for these capital expenditures could change depending on the outcome of the matters addressed below or as a result of the imposition of additional environmental requirements or new or different interpretations of existing environmental laws, rules and agency orders. In view of the sale of the Conectiv Energy wholesale power generation business in 2010 and the deactivation in 2012 of two generating facilities located in the District of Columbia owned by Pepco Energy Services, PHI is no longer significantly affected by air quality and other environmental regulations applicable to electricity generating facilities.
Air Quality Regulation
The generating facilities owned by Pepco Energy Services were subject to federal, state and local laws and regulations, including the Federal Clean Air Act (CAA), which limit emissions of air pollutants, require permits for operation of facilities and impose recordkeeping and reporting requirements. Following the June 2012 deactivation of Pepco Energy Services’ Buzzard Point and Benning Road oil-fired generating facilities, both of which were considered major sources under the CAA, Pepco Energy Services received authorization in 2013 from the District Department of the Environment (DDOE) to exclude these major sources from the CAA Title V operating permits. DDOE also agreed to transfer the CAA Title V operating permit covering the remaining minor sources (e.g., Pepco-operated emergency generators) to Pepco. Pepco has filed minor source permit applications with DDOE for these minor sources.
Greenhouse Gas Emissions Reporting
In October 2009, the U.S. Environmental Protection Agency (EPA) adopted regulations requiring sources that emit designated greenhouse gases - specifically, carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons, and other fluorinated gases (e.g., nitrogen trifluoride and hydrofluorinated ethers) - in excess of specified thresholds to file annual reports with EPA disclosing the amount of such emissions. Under these regulations:
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For the operating period ending with the two oil-fired generating units’ deactivation in June 2012, Pepco Energy Services reported CO2, methane and nitrous oxide for its Benning Road units.
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By April 1 of each year, DPL is required to report with respect to its gas distribution operations CO2 emissions that would result assuming the complete combustion or oxidation of the annual volume of natural gas it distributed to its customers during the previous calendar year. In addition, DPL is required to report fugitive CO2 and methane emissions for its gas distribution operations for the previous calendar year. DPL’s liquefied natural gas storage facility does not meet the reporting threshold (25,000 metric tons) for fugitive emissions.
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By April 1 of each year, Pepco, DPL and ACE are required to report sulfur hexafluoride emissions from electrical equipment for the previous calendar year.
Water Quality Regulation
Clean Water Act
Provisions of the federal Water Pollution Control Act, also known as the Clean Water Act, establish the basic legal structure for regulating the discharge of pollutants from point sources to surface waters of the United States. Among other things, the Clean Water Act requires that any person wishing to discharge pollutants from a point source (generally a confined, discrete conveyance such as a pipe) obtain a National Pollutant Discharge Elimination System (NPDES) permit issued by EPA or by a state agency under a federally authorized state program.
Pepco holds a NPDES permit issued by EPA with a July 19, 2009 effective date, which authorizes discharges from the Benning Road facility, including the now deactivated Pepco Energy Services generating facility located at that site. The permit imposes compliance monitoring and storm water best management practices to satisfy the District of Columbia’s Total Maximum Daily Load (TMDL) standards for polychlorinated biphenyls, oil and grease, metals and other substances. As required by the permit, Pepco has initiated a study to identify the source of the regulated substances to determine appropriate best management practices for minimizing the presence of the substances in storm water discharges from the facility. The initial study report was completed in May 2012. Pepco has completed the implementation of the first two phases of the best management practices recommended in the study report (consisting principally of installing metal absorbing filters to capture contaminants from storm water flows, removing stored equipment from areas exposed to the weather, covering and painting exposed metal pipes, and covering and cleaning dumpsters). Pepco will be evaluating the effectiveness of these initial best management practices and will consult with EPA regarding the need for additional measures. The capital expenditures, if any, that may be needed to implement additional best management practices to satisfy TMDL requirements will not be known until Pepco and EPA have completed the assessment of the effectiveness of these initial best management practices. In December 2013, Pepco filed an application with EPA to renew this permit, which is scheduled to expire on June 19, 2014.
EPA Oil Pollution Prevention Regulations
Facilities that, because of their location, store or use oil and could reasonably be expected to discharge oil into water bodies or adjacent shorelines in quantities that may be harmful to the environment are subject to EPA’s oil pollution prevention regulations. These regulations require entities to prepare and implement Spill Prevention, Control, and Countermeasure (SPCC) plans and specify site-specific measures to prevent and respond to an oil discharge. The SPCC regulations generally require the use of containment and/or diversionary structures to prevent the discharge of oil in the event of a leak or release of oil at the facility. As an alternative to the containment/diversionary structure requirement, owners of certain oil-filled operational equipment, such as electric system transformers, may comply with EPA’s regulations by implementing an inspection and monitoring program, developing an oil spill contingency plan, and providing a written commitment of resources to control and remove any discharge of oil. Pepco, DPL and ACE are complying with the SPCC regulations by employing containment/diversionary structures and by means of inspection and monitoring measures, in each case where such measures have been determined to be appropriate. Total costs of complying with these regulations in 2013 for Pepco, DPL and ACE collectively were approximately $6.6 million. PHI projects total expenditures of
approximately $22.5 million over the next five years for its subsidiaries to comply with these regulations, as shown in the capital expenditure projection set forth in “Environmental Matters” above, all of which are to install additional containment facilities and to replace certain oil-filled breakers with gas-filled breakers to eliminate the possibility of an oil release from such equipment. Compliance costs for Pepco Energy Services have not been material, and PHI does not expect that they will become material in the foreseeable future.
Hazardous Substance Regulation
The Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA) authorizes EPA, and comparable state laws authorize state environmental authorities, to issue orders and bring enforcement actions to compel responsible parties to investigate and take remedial actions at any site that is determined to present an actual or potential threat to human health or the environment because of an actual or threatened release of one or more hazardous substances. Parties that generated or transported hazardous substances to such sites, as well as the owners and operators of such sites, may be deemed liable under CERCLA or comparable state laws. Each of Pepco, DPL and ACE has been named by EPA or a state environmental agency as a potentially responsible party in pending proceedings involving certain contaminated sites. For additional information on these matters, see Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity - Capital Requirements - Environmental Remediation Obligations,” and Note (15), “Commitments and Contingencies - Environmental Matters,” to the consolidated financial statements of PHI.
Employees
At December 31, 2013, PHI had the following employees:
PHI’s subsidiaries are parties to five collective bargaining agreements with four local unions. Collective bargaining agreements are generally renegotiated every three to five years.
Executive Officers of PHI
The names of the executive officers of PHI, their ages and the positions they held as of February 26, 2014, are set forth in the following table. The business experience of each executive officer during the past five years is set forth adjacent to his or her name under the heading “Office and Length of Service” in the following table and in the applicable footnote.
(1) Mr. Rigby was Chief Operating Officer of PHI from September 2007 until February 28, 2009 and Executive Vice President of PHI from September 2007 until March 2008, Senior Vice President of PHI from August 2002 until September 2007 and Chief Financial Officer of PHI from May 2004 until September 2007. Mr. Rigby was President and Chief Executive Officer of Pepco, DPL and ACE from September 1, 2007 to February 28, 2009. Mr. Rigby has been Chairman of Pepco, DPL and ACE since March 1, 2009. On January, 24, 2014, Mr. Rigby notified PHI that he would be stepping down from his positions as President and Chief Executive Officer of PHI by the end of 2014 and would remain employed by PHI through May 1, 2015 to facilitate the transition of these roles. Mr. Rigby intends to remain as PHI’s Chairman of the Board through the 2015 Annual Meeting of Stockholders.
(2) Mr. Velazquez served as President of Conectiv Energy Holding Company, formerly an affiliate of PHI, from June 2006 to February 28, 2009, Chief Executive Officer of Conectiv Energy Holding Company from January 2007 to February 28, 2009 and Chief Operating Officer of Conectiv Energy Holding Company from June 2006 to December 2006.
(3) Mr. Fitzgerald joined PHI in September 2012 as Executive Vice President and General Counsel. Prior to such time, he was a partner with the law firm of Troutman Sanders, LLP in Washington, D.C. since 1997. Mr. Fitzgerald was Managing Partner of that firm’s Washington, D.C. office from 1999 until 2010 and Executive Partner for Client Development Strategic Planning from 2010 to September 2012.
(4) Mr. Boyle joined PHI in April 2012 as Senior Vice President and Chief Financial Officer. Prior to such time, he served as Senior Vice President and Chief Financial Officer of DPL Inc. and its wholly owned utility subsidiary, The Dayton Power and Light Company, from December 2010 until its acquisition in 2011. He served as Senior Vice President, Chief Financial Officer and Treasurer of both companies from May 2009 to December 2010, Senior Vice President, Chief Financial Officer, Treasurer and Controller of both companies from December 2008 to May 2009, Vice President, Finance, Chief Accounting Officer and Controller of both companies from June 2008 to November 2008, Vice President, Chief Accounting Officer and Controller of both companies from July 2007 to June 2008, and Vice President and Chief Accounting Officer of both companies from June 2006 to July 2007.
(5) Mr. Parker became Senior Vice President, Government Affairs and Corporate Citizenship effective September 1, 2012. Prior to such time, he served as Vice President of Public Policy from June 2009 to September 2012 and the ACE Region President from March 2005 to June 2009.
(6) Mr. Graham became Vice President, People Strategy and Human Resources effective August 1, 2013. Prior to such time, he served as the Pepco Region President from March 2005 to August 2013.
(7) Ms. Monica joined PHI in August 2011 as Vice President, Corporate Communications. From October 2006 to October 2010, Ms. Monica was Senior Vice President, Corporate Communications at American Water Works Company (NYSE: AWK), and from September 1991 to October 2006, Ms. Monica was President of High Point Communications, a strategic communications firm. Ms. Monica rejoined High Point Communications as President from October 2010 to August 2011.
(8) Mr. Huffman has been employed by Pepco Energy Services since June 2003. He was Chief Operating Officer from April 2006 to February 28, 2009, Senior Vice President from February 2005 to March 2006 and Vice President from June 2003 to February 2005.
Each PHI executive officer is elected annually and serves until his or her respective successor has been elected and qualified or his or her earlier resignation or removal.
Investor Information
Each Reporting Company maintains an Internet web site, at the Internet address listed below:
Reporting Company
Internet Address
PHI
http://www.pepcoholdings.com
Pepco
http://www.pepco.com
DPL
http://www.delmarva.com
ACE
http://www.atlanticcityelectric.com
Each Reporting Company files reports with the SEC under the Exchange Act. Copies of the Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and all amendments to those reports, of each Reporting Company are routinely made available free of charge on PHI’s Internet Web site (http://www.pepcoholdings.com/investors) as soon as reasonably practicable after such documents are electronically filed with or furnished to the SEC. PHI recognizes its website as a key channel of distribution to reach public investors and as a means of disclosing material non-public information to comply with each Reporting Company’s disclosure obligations under SEC Regulation FD. The information contained on the web sites listed above shall not be deemed incorporated into, or to be part of, this Annual Report on Form 10-K, and any web site references included herein are not intended to be made through active hyperlinks.
INFORMATION FOR THIS ITEM IS NOT REQUIRED FOR PEPCO, DPL, AND ACE AS THEY MEET THE CONDITIONS SET FORTH IN GENERAL INSTRUCTIONS I(1)(a) AND (b) OF FORM 10-K AND THEREFORE ARE FILING THIS FORM WITH THE REDUCED FILING FORMAT.
Item 1A.
Item 1A. RISK FACTORS
The businesses of each Reporting Company are subject to numerous risks and uncertainties, including the events or conditions identified below. The occurrence of one or more of these events or conditions could have an adverse effect on the business of any one or more of the Reporting Companies, including, depending on the circumstances, its financial condition, results of operations and cash flow. Unless otherwise noted, each risk factor set forth below applies to each Reporting Company.
PHI’s utility subsidiaries are subject to comprehensive regulation which significantly affects their operations. PHI’s utility subsidiaries may be subject to fines, penalties and other sanctions for the inability to meet these requirements.
The regulated utilities that comprise Power Delivery are subject to extensive regulation by various federal, state and local regulatory agencies. Each of Pepco, DPL and ACE is regulated by the state agencies for each service territory in which it operates, with respect to, among other things, the manner in which utility service is provided to customers, as well as rates it can charge customers for the distribution and supply of electricity (and, additionally for DPL, the distribution and supply of natural gas). NERC has also established, and FERC has approved, reliability standards with regard to the bulk power system that impose certain operating, planning and cyber security requirements on Pepco, DPL, ACE and Pepco Energy Services. Further, FERC regulates the electricity transmission facilities of Pepco, DPL and ACE.
Approval of these regulators is required in connection with changes in rates and other aspects of the utilities’ operations. These regulatory authorities, and NERC with respect to electric reliability, are empowered to impose financial penalties, fines and other sanctions including setting rates at a level that may be inadequate to permit recovery of costs against the utilities for non-compliance with certain rules and regulations. In this regard, in December 2011, the MPSC sanctioned Pepco related to its reliability in connection with major storm events that occurred in July and August 2010. These sanctions included imposing a fine on Pepco and requiring Pepco to file a work plan detailing, among other things, its reliability improvement objectives and progress in meeting those objectives, while raising the possibility of additional fines or cost recovery disallowances for failing to meet those objectives.
NERC’s eight regional oversight entities, including RFC, of which Pepco, DPL, ACE and Pepco Energy Services are members, and the Northeast Power Coordinating Council (NPCC), of which Pepco Energy Services is a member, are charged with the day-to-day implementation and enforcement of NERC’s standards. RFC and NPCC perform compliance audits on entities registered with NERC based on reliability standards and criteria established by NERC. NERC, RFC and NPCC also conduct compliance investigations in response to a system disturbance, complaint, or possible violation of a reliability standard identified by other means. Pepco, DPL, ACE and Pepco Energy Services are subject to routine audits and monitoring with respect to compliance with applicable NERC reliability standards, including standards requested by FERC to increase the number of assets (including cyber security assets) subject to NERC cyber security standards that are designated as “critical assets.” From time to time, Pepco, DPL and ACE have entered into settlement agreements with RFC resolving alleged violations and resulting in fines. There can be no assurance that additional settlements resolving issues related to RFC or NPCC requirements will not occur in the future. The imposition of additional sanctions and civil fines by these enforcement entities could have a material adverse effect on a Reporting Company’s results of operations, cash flow and financial condition.
PHI’s utility subsidiaries, as well as Pepco Energy Services, are also required to have numerous permits, approvals and certificates from governmental agencies that regulate their businesses. Although PHI believes that each of its subsidiaries has, and each of Pepco, DPL and ACE believes it has, obtained or sought renewal of the material permits, approvals and certificates necessary for its existing operations and that its business is conducted in accordance with applicable laws, PHI is unable to predict the impact that future regulatory activities may have on its business. Changes in or reinterpretations of existing laws or regulations, or the imposition of new laws or regulations, may require any one or more of PHI’s subsidiaries to incur additional expenses or significant capital expenditures or to change the way it conducts its operations.
PHI’s profitability is largely dependent on its ability to recover costs of providing utility services to its customers and to earn an adequate return on its capital investments. The failure of PHI’s utility subsidiaries to obtain timely recognition of costs in rates may have a negative effect on PHI’s results of operations and financial condition.
The public service commissions which regulate PHI’s utility subsidiaries establish utility rates and tariffs intended to provide the utility the opportunity to obtain revenues sufficient to recover its prudently incurred costs, together with a reasonable return on investor supplied capital. These regulatory authorities also determine how Pepco, DPL and ACE recover from their customers purchased power and natural gas and other operating costs, including transmission and other costs. The utilities cannot change their rates without approval by the applicable regulatory authority. There can be no assurance that the regulatory authorities will consider all costs to have been prudently incurred, nor can there be any assurance that the regulatory process by which rates are determined will always result in rates that achieve full and timely recovery of costs or a just and reasonable rate of return on investments. In addition, if the costs incurred by any of the utilities in operating its business exceed the amounts on which its approved rates are based, the financial results of that utility, and correspondingly PHI, may be adversely affected.
For example, PHI’s utility subsidiaries are exposed to “regulatory lag,” which refers to a shortfall in revenues in a utility’s rate structure due to the delay in time or “lag” between when costs are incurred and when they are reflected in rates. All of PHI’s utilities are currently experiencing significant regulatory lag because their investments in rate base and operating expenses are increasing more rapidly than their revenue growth. PHI anticipates that this trend will continue for the foreseeable future. The failure to timely recognize costs in rates could have a material adverse effect on PHI’s and each utility subsidiary’s business, results of operations, cash flow and financial condition.
Each of PHI’s utility subsidiaries will continue to seek cost recovery from applicable public service commissions to reduce the effects of regulatory lag and have an opportunity to earn its authorized return on equity. See Part I, Item 1. “Business - Regulation - Mitigation of Regulatory Lag.” There can be no assurance that any attempts by Pepco, DPL and ACE to mitigate regulatory lag will be approved, or that even if approved, the cost recovery mechanisms will fully mitigate the effects of regulatory lag. The inability of PHI’s utility subsidiaries to obtain relief from the impact of regulatory lag through base rate cases or otherwise may have a material adverse effect on the business, results of operations, cash flow and financial condition of PHI and each utility subsidiary.
The operating results of Power Delivery fluctuate on a seasonal basis and can be adversely affected by changes in weather.
The Power Delivery business historically has been seasonal and, as a result, weather has had a material impact on its operating performance. Demand for electricity is generally higher in the summer months associated with cooling and demand for electricity and natural gas is generally higher in the winter months associated with heating as compared to other times of the year. Accordingly, each of PHI, Pepco, DPL and ACE historically has generated less revenue and income when temperatures are warmer in the winter and cooler in the summer. In addition, severe weather conditions can produce storms that cause extensive damage to the transmission and distribution systems, as well as related facilities, that can require the utilities to incur additional operation and maintenance expense, as well as capital expenditures. These additional costs can be significant and the rates charged to customers may not always be timely or adequately adjusted to reflect these higher costs.
In the District of Columbia and Maryland, Pepco and DPL are subject to a bill stabilization adjustment mechanism applicable to retail customers, which decouples distribution revenue for a given reporting period from the amount of power delivered during the period. The bill stabilization mechanism has the
effect in those jurisdictions of reducing the impact of changes in the use of electricity by retail customers due to weather conditions or for other reasons on reported distribution revenue and income. A comparable revenue decoupling mechanism for DPL electricity and natural gas customers in Delaware is under consideration by the DPSC. In those jurisdictions that have not adopted a bill stabilization adjustment or similar mechanism, operating results continue to be affected by weather conditions.
Facilities and related systems may not operate as planned or may require significant capital or operation and maintenance expenditures, which could decrease revenues or increase expenses.
Operation of the Pepco, DPL and ACE transmission and distribution facilities and related systems involves many risks, including: the breakdown or failure of equipment; accidents; labor disputes; theft of copper wire or pipe; failure of computer systems, software or hardware; and performance below expected levels. Older facilities, systems and equipment, even if maintained in accordance with sound engineering practices, may require significant capital expenditures for additions or upgrades to provide reliable operations or to comply with changing environmental requirements. Thefts of copper wire or pipe, which seek to capitalize on the current high market price of copper, increase the likelihood of poor system voltage control, electricity and streetlight outages, damage to equipment and property, and injury or death, as well as increasing the likelihood of damage to fuel lines, which can create an unsafe and potentially explosive condition. Natural disasters and weather, including tornadoes, hurricanes and snow and ice storms, also can disrupt transmission and distribution systems. Disruption of the operation of transmission or distribution facilities and related systems can reduce revenues and result in the incurrence of additional expenses that may not be recoverable from customers or through insurance. Upgrades and improvements to computer systems and networks may require substantial amounts of management’s time and financial resources to complete, and may also result in system or network defects or operational errors due to employees’ inexperience of using a new or upgraded system.
In connection with the replacement of certain customers’ existing electric and natural gas meters with smart meters as part of the AMI system, Pepco and DPL were required to construct a wireless network across certain of their service territories and to implement and integrate new and existing information technology systems to collect and manage data made available by the smart meters and the AMI system. The implementation of the AMI system involves a combination of technologies provided by multiple vendors. If the AMI system results in lower than projected performance, PHI’s utility subsidiaries could experience higher than anticipated maintenance expenditures.
Energy companies are subject to adverse publicity and reputational risks, which make them vulnerable to negative customer perception and could lead to increased regulatory oversight or other sanctions.
Utility companies, including PHI’s utility subsidiaries, have a large consumer customer base and as a result have been the subject of public criticism focused on the reliability of their distribution services and the speed with which they are able to respond to outages caused by storm damage or other unanticipated events. Adverse publicity of this nature may render legislatures and other governing bodies, public service commissions and other regulatory authorities, and government officials less likely to view energy companies such as PHI and its subsidiaries in a favorable light, and may cause PHI and its subsidiaries to be susceptible to less favorable legislative and regulatory outcomes, as well as increased regulatory oversight and more stringent regulatory requirements. Unfavorable regulatory outcomes can include the enactment of more stringent laws and regulations governing PHI’s operations, such as reliability and customer service quality standards or vegetation management requirements, as well as fines, penalties or other sanctions or requirements. The imposition of any of the foregoing could have a material negative impact on PHI’s and each utility subsidiary’s business, results of operations, cash flow and financial condition.
Unfavorable regulatory developments and compliance with new or more rigorous regulatory requirements will subject PHI’s utility subsidiaries to higher operating costs.
PHI’s utility subsidiaries are subject to and will continue to be subject to changing regulatory requirements, including those related to reliability and customer service, in the various jurisdictions in which they operate. For example, in 2012, the MPSC adopted rules establishing reliability and customer service requirements. In April 2014, DPL expects to file an annual report with the MPSC in which it will indicate that it was not in compliance with certain of these reliability requirements for 2013. In addition, in July 2011, the DCPSC adopted regulations that establish specific maximum outage frequency and outage duration levels beginning in 2013 and continuing through 2020 and thereafter and are intended to require Pepco to achieve a reliability level in the first quartile of all utilities in the nation by 2020. Pepco believes that the DCPSC’s standards are achievable in the short term, but believes that the standards may not be realistically achievable at an acceptable cost over the longer term. The reliability standards permit Pepco to petition the DCPSC to reevaluate these standards for the period from 2016 to 2020 to address feasibility and cost issues.
Each of Pepco and DPL expect that it will have to incur significant operating and maintenance and capital expenses to comply with these requirements. Furthermore, each of Pepco and DPL would be subject to civil penalties or other sanctions if it does not meet the required performance or reliability standards. Other jurisdictions in which PHI’s utility subsidiaries have operations have already adopted or may in the future adopt reliability and customer service quality standards, the violation of which could also result in the imposition of penalties, fines and other sanctions. Compliance, and any failure to comply, with current, proposed or future regulatory requirements may have a material adverse effect on PHI and each utility subsidiary’s business, results of operations, cash flow and financial condition.
The resolution of tax matters involving PHI’s former cross-border energy lease investments may have a material negative impact on PHI’s results of operations and financial condition. (PHI only).
Prior to July 2013, a wholly-owned subsidiary of PHI had maintained a portfolio of cross-border energy lease investments involving public utility assets located outside of the United States, which investments were terminated during the third quarter of 2013 prior to the expiration date of the leases. The aggregate financial impact to PHI of the completion of these early terminations resulted in a pre-tax loss, including transaction costs, of approximately $3 million ($2 million after-tax) for the year ended December 31, 2013.
These cross-border energy lease investments, each of which was with a tax-indifferent party, have been under examination by the IRS as part of normal PHI federal income tax audits. In connection with the audits of PHI’s federal income tax returns from 2001 to 2008, the IRS disallowed the depreciation and interest deductions in excess of rental income claimed by PHI with respect to its cross-border energy lease investments. In addition, the IRS has sought to recharacterize the leases as loan transactions. In January 2012, PHI commenced litigation in the U.S. Court of Federal Claims regarding the disallowance of certain tax benefits claimed by PHI on its federal tax returns for 2001 and 2002.
In January 2013, the U.S. Court of Appeals for the Federal Circuit issued an opinion in an unrelated case that disallowed tax benefits associated with a lease-in, lease-out transaction. After analyzing this ruling, in the first quarter of 2013, PHI determined that its tax position with respect to the tax benefits associated with its cross-border energy leases no longer met the more-likely-than-not standard of recognition for accounting purposes. Accordingly, PHI recorded non-cash charges of $383 million (after-tax) in the first half of 2013, consisting of a non-cash charge to reduce the carrying value of the cross-border energy lease investments and a non-cash charge to reflect the anticipated additional interest expense related to changes in estimated federal and state income tax obligations for the period over which the tax benefits may be disallowed.
After consideration of certain tax benefits arising from matters unrelated to these lease investments, PHI estimated that, as of March 31, 2013, it would have been obligated to pay approximately $192 million in additional federal and state taxes and approximately $50 million of interest on the additional federal and state taxes. In order to mitigate PHI’s ongoing interest costs associated with the $242 million estimate of additional taxes and interest, PHI made an advanced payment to the IRS of $242 million in the first quarter of 2013. While PHI presently believes that it is more likely than not that no penalty will be incurred, the IRS could require PHI to pay a penalty of up to 20% of the amount of additional taxes due. In order to mitigate the cost of continued litigation related to the cross-border energy lease investments, PHI and its subsidiaries have entered into discussions with the IRS with the intention of seeking a settlement of all tax issues for open tax years 2001 through 2011, including the cross-border energy lease issue. PHI currently believes that it is possible that a settlement with the IRS may be reached in 2014. If a settlement of all tax issues or a standalone settlement on the cross-border energy leases is not reached, PHI may move forward with its litigation with the IRS. Further discovery in the case is stayed until April 24, 2014, pursuant to an order issued by the court on January 30, 2014.
Given the uncertainties associated with PHI’s litigation with the IRS, as well as with other efforts by PHI to address and resolve tax matters associated with its former cross-border energy leases in tax years not subject to this litigation, the aggregate financial impact, and timing of the resolution, of all of these matters cannot be determined presently; however, PHI presently believes that any such impact on PHI’s consolidated results of operations and financial condition could be material.
Power Delivery’s transmission facilities are interconnected with the facilities of other transmission facility owners. Failures of neighboring transmission systems could have a negative impact on Power Delivery’s operations.
The electricity transmission facilities of Pepco, DPL and ACE are interconnected with the transmission facilities of neighboring utilities and are part of the interstate power transmission grid. Pepco, DPL and ACE are members of the PJM RTO, a regional transmission organization that operates the portion of the interstate transmission grid that includes the PHI transmission facilities. Although PJM’s systems and operations are designed to ensure the reliable operation of the transmission grid and prevent the operations of one utility from having an adverse impact on the operations of the other utilities, there can be no assurance that service interruptions originating at other utilities will not cause interruptions in the Pepco, DPL or ACE service territories. Thus, due to the interconnected nature of the interstate power transmission grid, an outage in a neighboring utility could trigger a system outage in either Pepco, DPL or ACE. If Pepco, DPL or ACE were to suffer such a service interruption, it could have a negative impact on its and PHI’s business, results of operations, cash flow and financial condition.
Changes in technology, distributed generation and conservation measures may adversely affect Power Delivery.
Increased conservation and end-user generation made possible through current or future advances in technology, such as through fuel and solar (photovoltaic) cells, wind power and microturbines, could reduce demand for the transmission and distribution facilities of Power Delivery and adversely affect the results of operations of PHI and one or more of its utility subsidiaries. Alternative technologies that produce electricity, the development of which has expanded due to climate change and other environmental concerns, could ultimately provide alternative sources of electricity and permit current customers to adopt distributed generation systems which would allow them to generate electricity for their
own use. As these and other technologies are created, developed and improved, the quantity and frequency of electricity usage by customers could decline, which could have a negative impact on the business, results of operations, cash flow and financial condition of PHI or its utility subsidiaries.
The cost of compliance with environmental laws is significant and implementation of new and existing environmental laws may increase operating costs.
The operations of PHI’s subsidiaries are subject to extensive federal, state and local environmental laws and regulations relating to air quality, water quality, spill prevention, waste management, natural resource protection, site remediation, greenhouse gas emissions and health and safety. These laws and regulations may require significant capital and other expenditures to, among other things, meet emissions and effluent standards, conduct site remediation, complete environmental studies and perform environmental monitoring. If a company fails to comply with applicable environmental laws and regulations, even if caused by factors beyond its control, such failure could result in the assessment of civil or criminal penalties and liabilities and the need to expend significant sums to achieve compliance.
In addition, PHI’s subsidiaries are required to obtain and comply with a variety of environmental permits, licenses, inspections and other approvals. If there is a delay in obtaining any required environmental regulatory approval, or if there is a failure to obtain, maintain or comply with any such approval, operations at affected facilities could be halted or subjected to additional costs.
Failure to retain and attract key skilled and properly motivated professional and technical employees could have an adverse effect on operations.
PHI and its subsidiaries operate in a highly regulated industry that requires the continued operation of sophisticated systems and technology. One of the challenges they face in implementing their business strategy is to attract, motivate and retain a skilled, efficient and cost-effective workforce while recruiting new talent to replace losses in knowledge and skills due to retirements. Over the course of the next three years, PHI estimates that approximately one-third of this skilled workforce will reach retirement age. Competition for skilled employees in some areas is high and the inability to attract and retain these employees, especially as existing skilled workers retire in the near future, could adversely affect the business, operations and financial condition of PHI or the affected company.
PHI’s subsidiaries are subject to collective bargaining agreements that could impact their business and operations.
As of December 31, 2013, 54% of employees of PHI and its subsidiaries, collectively, were represented by various labor unions. PHI’s subsidiaries are parties to five collective bargaining agreements with four local unions that represent these employees. Collective bargaining agreements are generally renegotiated every three to five years, and the risk exists that there could be a work stoppage after expiration of an agreement until a new collective bargaining agreement has been reached. Labor negotiations typically involve bargaining over wages, benefits and working conditions, including management rights. PHI’s last work stoppage, a two-week strike by DPL’s employees, occurred in 2010. During that strike, DPL used management and contractor employees to maintain essential operations. Though PHI believes that protracted work stoppages are unlikely, such an event could result in a disruption of the operations of the affected utility, which could, in turn, have a material adverse effect upon the business, results of operations, cash flow and financial condition of the affected utility and PHI.
The energy savings business of Pepco Energy Services is highly competitive and its thermal operation in Atlantic City is exposed to customer concentration. (PHI only)
Unlike PHI’s regulated business, Pepco Energy Services’ energy savings business is unregulated and its energy savings performance contracting business is highly competitive. This competition puts downward pressure on margins and increases costs. The energy savings business is affected by new entrants into the market, financial strength of customers, energy prices and general economic conditions. These factors may negatively affect Pepco Energy Services’ ability to market its services to new customers or renew existing contracts, as well as the prices Pepco Energy Services may charge.
Among the factors on which the energy savings business competes are the amount and duration of the guarantees provided in energy savings performance contracts. In connection with many of its energy savings performance installation projects, Pepco Energy Services guarantees a minimum level of annual energy cost savings over a period of typically up to 15 years. Currently, Pepco Energy Services does not insure against this risk, and accordingly could suffer financial losses if a project does not achieve the guaranteed level of performance.
Under the Budget Control Act of 2011, mandatory federal spending cuts, also known as “sequestration,” are effective for years 2013 through 2021 unless Congress agrees to a deficit reduction plan. In January 2013, Congress passed, and the President signed, the American Taxpayer Relief Act of 2012 that addressed rising federal income tax rates that would have taken effect on January 1, 2013. Although Congress has enacted the Consolidated Appropriations Act of 2014, which is expected to alleviate the effects of sequestration on the Department of Defense through October 2014, the continuation of other substantial federal spending cuts could make it more difficult for Pepco Energy Services to enter into new energy savings performance contracts with federal, state and local government agencies and thus could have a material adverse effect on the energy savings business of Pepco Energy Services.
In addition, revenues associated with Pepco Energy Services’ combined heat and power thermal generating plant and operation in Atlantic City, New Jersey are concentrated with a few major customers in the Atlantic City hotel and casino industry. Pepco Energy Services has long-term contracts with these customers, and for the largest customer, the contracts expire in 2017. The Atlantic City hotel and casino industry has been experiencing a decrease in gaming revenues and overcapacity, as well as potential future competition from casinos that are being constructed in nearby markets. Pepco Energy Services is exposed to the risk that it is not able to renew these contracts or that the contract counterparties may fail to perform their obligations thereunder. In either case, Pepco Energy Services may be required to conclude that the assets with an aggregate carrying value as of December 31, 2013 of approximately $85 million associated with the generating plant or operation have been impaired, which would require Pepco Energy Services to reduce the carrying value of these assets by the amount of the impairment and record a corresponding non-cash charge to earnings. Any of these events could have a material adverse effect on PHI’s and Pepco Energy Services’ financial condition, results of operations and cash flow.
Under its energy savings performance contracts, Pepco Energy Services is responsible for maintaining, repairing and replacing energy equipment, which obligations may require Pepco Energy Services to incur significant costs many years after an installation of a project is completed. (PHI only)
Pepco Energy Services owns energy equipment and is also responsible for operating and maintaining additional energy equipment that it does not own. In addition, it is generally Pepco Energy Services’ responsibility to repair or replace this energy equipment in the event of a failure. These equipment maintenance, repair and replacement obligations could be material and could adversely affect PHI’s results of operations, cash flow and financial condition.
Pepco Energy Services’ obligations in connection with its combined heat and power construction projects, energy savings construction projects and energy savings performance contracts may have a material adverse effect on PHI. (PHI only)
Pepco Energy Services has undertaken projects which include design, construction, startup and testing activities related to combined heat and power and energy savings construction projects, pursuant to guaranteed maximum price or fixed-price contracts. Pepco Energy Services will generally secure commitments from subcontractors and vendors to perform within contract pricing commitments, equipment-performance standards, jobsite safety requirements, and other key parameters. Under a number
of these projects, the customer of Pepco Energy Services has required Pepco Energy Services to obtain surety bonds securing the performance of Pepco Energy Services, or its subcontractors or vendors. PHI has been required to guarantee the performance of Pepco Energy Services under the surety bonds and certain of these construction contracts. PHI also guarantees the obligations of Pepco Energy Services under certain of its energy savings performance contracts. At December 31, 2013, PHI’s guarantees of Pepco Energy Services’ obligations under its energy savings performance, combined heat and power, and construction contracts totaled $190 million, and PHI’s guarantees of Pepco Energy Services’ obligations under surety bonds for construction projects totaled $229 million.
As a result, PHI may bear responsibility in the event of unexcused failures by Pepco Energy Services or its subcontractors or vendors to perform in accordance with the terms of these contracts, or if the customer does not realize the energy savings provided for in a performance contract. When such events occur, Pepco Energy Services and PHI may experience reputational harm and claims for money damages and other relief that may be sought in connection with such contracts, guarantees and surety bonds, which could, depending upon the nature of the claim and the amount of damages or other relief sought, have a material adverse effect upon Pepco Energy Services’ and PHI’s business, results of operations, cash flow and financial condition.
If PHI is not successful in mitigating the risks inherent in its business, its operations could be adversely affected.
PHI and its subsidiaries are faced with a number of different types of risk. PHI confronts legislative, regulatory policy, compliance and other risks, including:
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PHI’s inability to timely recover capital and operating costs, which may result in a shortfall in revenues;
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resource planning and other long-term planning risks, including resource acquisition risks, which may hinder PHI’s ability to maintain adequate resources;
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financial risks, including credit, interest rate and capital market risks, which could increase the cost of capital or make raising capital more difficult; and
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macroeconomic risks, and risks related to economic conditions and changes in demand for electricity and natural gas in the service territories of PHI’s utility subsidiaries (including changes due to or in connection with the loss of one or more commercial customers of a utility subsidiary), as well as with respect to Pepco Energy Services’ business, which could negatively impact the operations of the affected business.
PHI management seeks to mitigate the risks inherent in the implementation of PHI’s business strategy through its established risk mitigation process, which includes adherence to PHI’s business policies and other compliance policies, operation of formal risk management structures and groups, and overall business management. PHI management is responsible for identifying, assessing and managing risks, and developing risk-management strategies, while the Board of Directors and its various committees oversee the assessment, management and mitigation of risk. However, there can be no assurance these risk mitigation efforts will adequately address all such risks or that such efforts will be successful, and a failure to successfully mitigate such risks may have a material adverse effect on the business, results of operations, cash flow or financial condition of one or more of the Reporting Companies.
PHI and its subsidiaries are exposed to contractual and credit risks associated with certain of their operations.
PHI and its subsidiaries are subject to a number of contractual and credit risks associated with certain of their operations. To mitigate contractual or credit risk, PHI or a subsidiary may give to or receive from the counterparty collateral or other types of performance assurance, which may be in the form of cash, letters of credit or parent guarantees, to protect against performance and credit risk. Even where collateral is provided, capital market disruptions, the lowered rating or insolvency of the issuer or guarantor, changes in
the power supply market prices and other events may prevent a party from being able to meet its obligations or may degrade the value of collateral, letters of credit and guarantees, and the collateral, guarantee or other performance assurance provided may prove insufficient to protect against all losses that a party may ultimately suffer. In the event of a bankruptcy of a counterparty to any contract to which PHI or any of its subsidiaries is a party, bankruptcy law, in some circumstances, could require the surrender of collateral or other guarantees held or payments received.
Business operations could be adversely affected by terrorism and cyber attacks.
The threat of, or actual acts of, terrorism may affect the operations of PHI and its subsidiaries in unpredictable ways and may cause changes in the insurance markets, force an increase in security measures and cause electrical disruptions or disruptions of fuel supplies and markets, including natural gas. Utility industry operations require the continued deployment and utilization of sophisticated information technology systems and network infrastructure. While PHI has implemented protective measures designed to mitigate its vulnerability to physical and cyber threats and attacks, such protective measures, and technology systems generally, are vulnerable to disability or failure due to cyber attack, acts of war or terrorism, and other causes. As a result, there can be no assurance that such protective measures will be completely effective in protecting PHI’s infrastructure or assets from a physical or cyber attack or the effects thereof. If any of Pepco’s, DPL’s or ACE’s infrastructure facilities, including their transmission or distribution facilities, were to be a direct target, or an indirect casualty, of an act of terrorism, the operations of PHI, Pepco, DPL or ACE could be adversely affected. Furthermore, any threats or actions that negatively impact the physical security of PHI’s and its subsidiaries’ facilities, or the integrity or security of their computer networks and systems (and any programs or data stored thereon or therein), could adversely affect PHI’s and its subsidiaries’ ability to manage these facilities, networks, systems, programs and data efficiently or effectively, which in turn could have a material adverse effect on PHI’s or its subsidiaries’ results of operations and financial condition. Corresponding instability in the financial markets as a result of threats or acts of terrorism or threatened or actual cyber attacks also could adversely affect the ability of PHI or its subsidiaries to raise needed capital.
New accounting standards or changes to existing accounting standards could materially impact how a Reporting Company reports its results of operations, cash flow and financial condition.
Each Reporting Company’s financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (GAAP). The SEC, the Public Company Accounting Oversight Board, the Financial Accounting Standards Board (FASB) or other authoritative bodies or governmental entities may issue new pronouncements or new interpretations of existing accounting standards that may require the Reporting Companies to change their accounting policies. These changes are beyond the control of the Reporting Companies, can be difficult to predict and could materially impact how they report their results of operations, cash flow and financial condition. Each Reporting Company could be required to apply a new or revised standard retroactively, which could adversely affect its results of operations, cash flow and financial condition.
Undetected errors in internal controls and information reporting could result in the disallowance of cost recovery and noncompliant disclosure.
Each Reporting Company’s internal controls, accounting policies and practices and internal information systems are designed to enable the Reporting Company to capture and process transactions and information in a timely and accurate manner in compliance with GAAP, taxation requirements, federal securities laws and regulations and other laws and regulations (including pursuant to federal and state administrative grant programs) applicable to it. Such compliance permits each Reporting Company to, among other things, disclose and report financial and other information in connection with the recovery of its costs and with the reporting requirements for each Reporting Company under federal securities, tax and other laws and regulations.
Each Reporting Company has implemented corporate governance, internal control and accounting policies and procedures in connection with the Sarbanes-Oxley Act of 2002 (the Sarbanes-Oxley Act) and relevant SEC rules, as well as other applicable regulations. Such internal controls and policies have been and continue to be closely monitored by each Reporting Company’s management and PHI’s Board of Directors to ensure continued compliance with these laws, rules and regulations. Management is also responsible for establishing and maintaining internal control over financial reporting and is required to assess annually the effectiveness of these controls. While PHI believes these controls, policies, practices and systems are adequate to verify data integrity, unanticipated and unauthorized actions of employees or temporary lapses in internal controls due to shortfalls in oversight or resource constraints could lead to undetected errors that could result in the disallowance of cost recovery and noncompliant disclosure and reporting. The consequences of these events could have a negative impact on the results of operations and financial condition of the affected Reporting Company. The inability of management to certify as to the effectiveness of these controls due to the identification of one or more material weaknesses in these controls could also increase financing costs or could also adversely affect the ability of a Reporting Company to access the capital markets.
Insurance coverage may not be sufficient to cover all casualty or property losses that PHI and its subsidiaries might incur.
PHI and its subsidiaries, including Pepco, DPL and ACE, as well as Pepco Energy Services, currently have insurance coverage for their facilities and operations in amounts and with deductibles that they consider appropriate. However, there is no assurance that such insurance coverage will be available in the future on commercially reasonable terms or at all. In addition, some risks and losses, such as weather related casualties, may not be insurable, and, where a risk has been insured, a risk or loss may be deemed to be excluded from coverage or coverage may otherwise be denied in whole or in part. In the case of loss or damage to property, plant, equipment or other assets, there is no assurance that the insurance proceeds received, if any, will be sufficient to cover the entire loss, including costs of replacement or repair.
PHI and its subsidiaries are dependent on obtaining access to the capital markets and bank financing to satisfy their capital and liquidity requirements. The inability to obtain required financing when needed would have an adverse effect on their respective businesses.
PHI and its subsidiaries, including Pepco, DPL and ACE, have significant capital requirements, including the funding of construction expenditures and the refinancing of maturing debt. Each of the Reporting Companies relies primarily on cash flow from operations, access to the capital markets and medium- and long-term bank financing, to meet these long-term financing needs. The operating activities of PHI and its subsidiaries also require continued access to short-term sources of liquidity, including issuances by a Reporting Company of commercial paper and access to money markets and short-term bank financing, to provide for short-term liquidity needs that are not met by cash flows from their operations. Adverse business developments or market disruptions could increase the cost of financing or prevent PHI or any of its subsidiaries from accessing these sources of short-term and long-term capital. Events that could cause or contribute to a disruption of the financial markets include, but are not limited to:
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a recession or an economic slowdown;
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the bankruptcy of one or more energy companies or financial institutions;
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a significant change in energy prices;
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a terrorist or cyber attack or threatened attacks;
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the outbreak of a pandemic or other similar event; or
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a significant electricity or natural gas transmission disruption.
Any reductions in or other actions with respect to the credit ratings of PHI or any of its subsidiaries could increase its financing costs and the cost of maintaining certain contractual relationships.
Nationally recognized rating agencies currently rate each Reporting Company and debt securities issued by Pepco, DPL and ACE. Ratings are not recommendations to buy or sell securities. PHI or its subsidiaries may, in the future, incur new indebtedness with interest rates that may be affected by changes in or other actions associated with these credit ratings. Each of the rating agencies reviews its ratings periodically, and previous ratings may not be maintained in the future. Rating agencies may also place a Reporting Company under review for potential downgrade in certain circumstances or if any of them seek to take certain actions that it believes would otherwise be in its best interests. A downgrade of these debt ratings or other negative action, such as a review for a potential downgrade, could affect the market price of existing indebtedness and the ability to raise additional debt without incurring increases in the cost of capital. In addition, a downgrade of these ratings, or other negative action, could make it more difficult to raise capital to refinance any maturing debt obligations, to support business growth and to maintain or improve the current financial strength of PHI’s business and operations.
The agreements that govern PHI’s primary credit facility, as well as term loan agreements that have been entered into from time to time, contain a consolidated indebtedness covenant that may limit discretion of each borrower to incur indebtedness or reduce its equity.
Under the terms of PHI’s primary credit facility, of which each Reporting Company is a borrower, and of term loan agreements that have been entered into from time to time, the consolidated indebtedness of a borrower cannot exceed 65% of its consolidated capitalization. If a borrower’s equity were to decline or its debt were to increase to a level that caused its debt to exceed this limit, lenders under the credit facility would be entitled to refuse any further extension of credit and to declare all of the outstanding debt under the credit facility or the term loan immediately due and payable. To avoid such a default, a waiver or renegotiation of this covenant would be required, which would likely increase funding costs and could result in additional covenants that would restrict each Reporting Company’s operational and financing flexibility.
Each borrower’s ability to comply with this covenant is subject to various risks and uncertainties, including events beyond the borrower’s control. For example, events that could cause a reduction in PHI’s equity include, without limitation, potential IRS taxes, interest and penalties associated with PHI’s former cross-border energy lease investments or a significant write-down of PHI’s goodwill. Even if each borrower is able to comply with this covenant, the limitations on its operational and financial flexibility could harm its and PHI’s business by, among other things, limiting the borrower’s ability to incur indebtedness or reduce equity in connection with financings or other corporate opportunities that it may believe would be in its best interests or the interests of PHI’s stockholders to complete.
PHI’s cash flow, ability to pay dividends and ability to satisfy debt obligations depend on the performance of its regulated and competitive operating subsidiaries, access to the capital markets and other sources of liquidity. PHI’s unsecured obligations are effectively subordinated to the liabilities of its subsidiaries. (PHI only)
PHI is a holding company that conducts its operations entirely through its regulated and competitive subsidiaries, and all of PHI’s consolidated operating assets are held by its subsidiaries. Accordingly, PHI’s cash flow, its ability to satisfy its obligations to creditors and its ability to pay dividends on its common stock are dependent upon the earnings of its subsidiaries, each Reporting Company’s access to the capital markets and all sources of cash flow and liquidity that may be available to PHI. PHI’s subsidiaries are separate legal entities and have no obligation to pay any amounts due on any debt or equity securities issued by PHI or to make any funds available for such payment. The ability of PHI’s subsidiaries to pay dividends and make other payments to PHI may be restricted by, among other things, applicable corporate, tax and other laws and regulations and agreements made by PHI and its subsidiaries, including under the terms of indebtedness, and PHI’s financial objective of maintaining a common equity ratio at its
utility subsidiaries of between 49% and 50%. Because the claims of the creditors of PHI’s subsidiaries are superior to PHI’s entitlement to dividends, the unsecured debt and obligations of PHI are effectively subordinated to all existing and future liabilities of its subsidiaries, including trade creditors. In addition, claims of creditors, including trade creditors, of PHI’s subsidiaries will generally have priority with respect to the assets and earnings of such subsidiaries over the claims of PHI’s creditors.
PHI has a significant goodwill balance related to its Power Delivery business. A determination that goodwill is impaired could result in a significant non-cash charge to earnings.
PHI had a goodwill balance at December 31, 2013, of approximately $1.4 billion, primarily attributable to Pepco’s acquisition of Conectiv in 2002. An impairment charge must be recorded under GAAP to the extent that the implied fair value of goodwill is less than the carrying value of goodwill, as shown on the consolidated balance sheet. PHI is required to test goodwill for impairment at least annually and whenever events or changes in circumstances indicate that the carrying value may not be recoverable. Factors that may result in an interim impairment test include, but are not limited to: an adverse change in business conditions; a protracted decline in stock price causing market capitalization to fall significantly below book value; an adverse regulatory action; impairment of long-lived assets in the reporting unit; or a change in identified reporting units. If PHI were to determine that its goodwill is impaired, PHI would be required to reduce its goodwill balance by the amount of the impairment and record a corresponding non-cash charge to earnings. Depending on the amount of the impairment, an impairment determination could have a material adverse effect on PHI’s financial condition, results of operations and cash flow.
The funding of future defined benefit pension plan and post-retirement benefit plan obligations is based on assumptions regarding the valuation of future benefit obligations and the projected performance of plan assets. If market performance decreases plan assets or changes in assumptions regarding the valuation of benefit obligations increase plan liabilities, any of the Reporting Companies may be required to make significant cash contributions to fund these plans.
PHI holds assets in trust to meet its obligations under PHI’s defined benefit pension plan and its post-retirement benefit plan. The amounts that PHI is required to contribute (including the amounts for which Pepco, DPL and ACE are responsible) to fund the trusts are determined based on assumptions made as to the valuation of future benefit obligations, and the projected investment performance of the plan assets. Accordingly, the performance of the capital markets will affect the value of plan assets. A decline in the market value of plan assets as well as a decline in the rate of return on plan assets may increase the plan funding requirements to meet the future benefit obligations. In addition, changes in interest rates affect the valuation of the liabilities of the plans. As interest rates decrease, the present value of the liabilities increase, potentially requiring additional funding. Demographic changes, such as a change in the expected timing of retirements or changes in life expectancy assumptions, also may increase the funding requirements of the plans. A need for significant additional funding of the plans could have a material adverse effect on the cash flows of any of the Reporting Companies. Future increases in pension plan and other post-retirement benefit plan costs, to the extent they are not recoverable in the base rates of PHI’s utility subsidiaries, could have a material adverse effect on the results of operations, cash flow and financial condition of any of the Reporting Companies.
Provisions of the Delaware General Corporation Law and in PHI’s constituent documents may discourage an acquisition of PHI. (PHI only)
PHI is governed by the provisions of Section 203 of the Delaware General Corporation Law, which prohibit a public Delaware corporation from engaging in a business combination with an interested stockholder (as defined in Section 203) for a period commencing three years from the date in which the person became an interested stockholder, unless:
•
the board of directors approved the transaction which resulted in the stockholder becoming an interested stockholder;
•
upon consummation of the transaction which resulted in the stockholder becoming an interested stockholder, the interested stockholder owned at least 85% of the voting stock of the corporation (excluding shares owned by officers, directors, or certain employee stock purchase plans); or
•
at or subsequent to the time the transaction is approved by the board of directors, there is an affirmative vote of at least 66 2/3% of the outstanding voting stock not owned by the interested stockholder approving the transaction.
Section 203 could prohibit or delay mergers or other takeover attempts against PHI, and accordingly, may discourage or prevent attempts to acquire or control PHI through a tender offer, proxy contest or otherwise.
In addition, PHI’s restated certificate of incorporation and amended and restated bylaws contain provisions that may discourage, delay or prevent a third party from acquiring PHI, even if doing so would be beneficial to its stockholders. For example, under PHI’s restated certificate of incorporation, only its board of directors may call special meetings of stockholders. Further, stockholder actions may only be taken at a duly called annual or special meeting of stockholders and not by written consent. Moreover, directors of PHI may be removed by stockholders only for cause and only by the effective vote of at least a majority of the outstanding shares of capital stock of PHI entitled to vote generally in the election of directors (voting together as a single class) at a meeting of stockholders called for that purpose. In addition, under PHI’s amended and restated bylaws, stockholders must comply with advance notice requirements for nominating candidates for election to PHI’s board of directors or for proposing matters that can be acted upon by stockholders at stockholder meetings, and this provision may be amended or repealed by stockholders only upon the affirmative vote of the holders of two-thirds of the outstanding shares of PHI capital stock entitled to vote generally in the election of directors, voting together as a single class.
Issuances of additional series of PHI preferred stock could adversely affect holders of PHI’s common stock. (PHI only)
PHI’s board of directors is authorized to issue shares of PHI preferred stock in series without any action on the part of PHI stockholders. PHI’s board of directors also has the power, without stockholder approval, to set the terms of any such series of preferred stock, including with respect to dividend rights, redemption rights and sinking fund provisions, conversion rights, voting rights, and other preferential rights, limitations and restrictions. As of December 31, 2013, there were no shares of PHI preferred stock issued or outstanding.
If PHI issues preferred stock in the future that has a preference over PHI’s common stock with respect to the payment of dividends or upon its liquidation, dissolution or winding up, or if preferred stock is issued with voting rights that dilute the voting power of the common stock, the rights of holders of PHI’s common stock or the market price of such common stock could be adversely affected. Furthermore, issuances of preferred stock can be used to discourage, delay or prevent a third party from acquiring PHI where the acquisition might be perceived as being beneficial to stockholders.
Because Pepco, DPL and ACE are direct or indirect wholly owned subsidiaries of PHI and have directors and executive officers who are also officers of PHI, PHI can effectively exercise control over their dividend policies and significant business and financial transactions. (Pepco, DPL and ACE only)
All of the members of each of Pepco’s, DPL’s and ACE’s board of directors, as well as many of their respective executive officers, are officers of PHI, and Pepco, DPL and ACE are direct or indirect wholly owned subsidiaries of PHI. Among other decisions, each of Pepco’s, DPL’s and ACE’s board of directors is responsible for decisions regarding payment of dividends, financing and capital raising activities and acquisition and disposition of assets. Within the limitations of applicable law, and subject to the financial covenants under each company’s respective outstanding debt instruments, each of Pepco’s, DPL’s and ACE’s board of directors will base its decisions concerning the amount and timing of dividends, and other business decisions, on its capital structure, which is based in part on earnings and cash flow, and also may take into account the business plans and financial requirements of PHI and its other subsidiaries.
Item 1B.
Item 1B. UNRESOLVED STAFF COMMENTS
Pepco Holdings
None.
Pepco
None.
DPL
None.
ACE
None.
Item 2.
Item 2. PROPERTIES
Transmission and Distribution Systems
On a combined basis, the electric transmission and distribution systems owned by Pepco, DPL and ACE at December 31, 2013, consisted of approximately 4,000 transmission circuit miles of overhead lines, 600 transmission circuit miles of underground cables, 18,200 distribution circuit miles of overhead lines, and 15,900 distribution circuit miles of underground cables, primarily in their respective service territories. DPL and ACE own and operate distribution system control centers in New Castle, Delaware and Mays Landing, New Jersey, respectively. Pepco also operates a distribution system control center in Bethesda, Maryland. The computer equipment and systems contained in Pepco’s control center are financed through a sale and leaseback transaction.
DPL owns a liquefied natural gas facility located in Wilmington, Delaware, with a storage capacity of approximately 3 million gallons and an emergency sendout capability of 25,000 Mcf per day. DPL owns 10 natural gas city gate stations at various locations in New Castle County, Delaware. These stations have a total primary delivery point contractual entitlement of 202,075 Mcf per day. DPL also owns approximately 104 pipeline miles of natural gas transmission mains, 1,836 pipeline miles of natural gas distribution mains, and 1,321 pipeline miles of natural gas service lines. In addition, DPL has a 10% undivided interest in approximately 7 miles of natural gas transmission mains, which are used by DPL for its natural gas operations and by the 90% owner for distribution of natural gas to its electric generating facilities.
Substantially all of the transmission and distribution property, plant and equipment owned by each of Pepco, DPL and ACE is subject to the liens of the respective mortgages under which the companies issue First Mortgage Bonds. See Note (10), “Debt” to the consolidated financial statements of PHI.
Generating Facilities
The following table identifies the electric generating facilities owned by PHI’s subsidiaries at December 31, 2013.
The preceding table sets forth the net summer electric generating capacity of each electric generating facility owned. Although the generating capacity may be higher during the winter months, the facilities are used to meet summer peak loads that are generally higher than winter peak loads. Accordingly, the summer generating capacity more accurately reflects the operational capability of the facilities.
Item 3.
Item 3. LEGAL PROCEEDINGS
Pepco Holdings
Other than litigation incidental to PHI and its subsidiaries’ business, PHI is not a party to, and PHI and its subsidiaries’ property is not subject to, any material pending legal proceedings except as described in Note (15), “Commitments and Contingencies,” to the consolidated financial statements of PHI.
Pepco
Other than litigation incidental to its business, Pepco is not a party to, and its property is not subject to, any material pending legal proceedings except as described in Note (12), “Commitments and Contingencies,” to the financial statements of Pepco.
DPL
Other than litigation incidental to its business, DPL is not a party to, and its property is not subject to, any material pending legal proceedings except as described in Note (14), “Commitments and Contingencies,” to the financial statements of DPL.
ACE
Other than litigation incidental to its business, ACE is not a party to, and its property is not subject to, any material pending legal proceedings except as described in Note (13), “Commitments and Contingencies,” to the consolidated financial statements of ACE.
Item 4.
Item 4. MINE SAFETY DISCLOSURES
Not applicable.
Part II
Item 5.
Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
The New York Stock Exchange is the principal market on which Pepco Holdings common stock is traded. The following table presents the dividends declared per share on the Pepco Holdings common stock and the high and low sales prices for the common stock based on composite trading as reported by the New York Stock Exchange during each quarter in the last two years.
At February 14, 2014, there were 46,622 holders of record of Pepco Holdings common stock.
Dividends
On January 23, 2014, the PHI Board of Directors declared a dividend on common stock of 27 cents per share payable March 31, 2014, to shareholders of record on March 10, 2014.
See Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity - Capital Requirements - Dividends,” and Note (12), “Stock-Based Compensation, Dividend Restrictions, and Calculations of Earnings Per Share of Common Stock - Dividend Restrictions,” of the consolidated financial statements of PHI for information regarding restrictions on the ability of PHI and its subsidiaries to pay dividends.
PHI Subsidiaries
One of PHI’s financial objectives is to maintain an equity ratio of 49%-50% in each of its operating utilities. Each quarter, PHI may contribute equity into its utility subsidiaries or the utility subsidiaries may make a dividend payment to PHI in order to maintain an equity ratio of 49%-50% in each of the utility subsidiaries. During 2013, PHI made capital contributions of $175 million and $75 million to Pepco and ACE, respectively, and in 2012, PHI made capital contributions of $50 million and $60 million to Pepco and DPL, respectively.
All of Pepco’s common stock is held by Pepco Holdings, and all of DPL’s and ACE’s common stock is held by Conectiv, LLC (Conectiv), which in turn is wholly owned by Pepco Holdings. The table below presents the aggregate amount of common stock dividends paid by Pepco to PHI, and by DPL and ACE to Conectiv, during each quarter in the last two years. Dividends received by PHI in 2013 and 2012 from Pepco were used to support the payment of its common stock dividend. Dividends paid by ACE and DPL in 2013 and 2012 were used by Conectiv to pay down its short-term debt owed to PHI.
Recent Sales of Unregistered Equity Securities
Pepco Holdings
None.
Pepco
None.
DPL
None.
ACE
None.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
Pepco Holdings
None.
Pepco
None.
DPL
None.
ACE
None.
Item 6.
Item 6. SELECTED FINANCIAL DATA
The following table sets forth selected historical consolidated data for PHI as of and for each of the years ended December 31, 2013, 2012, 2011, 2010, and 2009, derived from PHI’s audited consolidated financial statements.
(a) Includes a charge of $101 million to establish valuation allowances related to certain PCI deferred tax assets and a charge of $66 million to reflect the anticipated additional interest expense on estimated federal and state income tax obligations resulting from the change in assessment of the tax benefits associated with the cross-border energy lease investments.
(b) Includes a loss on extinguishment of debt of $189 million ($113 million after-tax).
(c) Amounts for net book value per common share, common shareholders’ equity and total capitalization for 2009 to 2012 have been adjusted for a revision to prior period financial statements related to deferred income tax liabilities for PCI that reduced equity by $32 million, as shown below. Amounts for total equity as filed and as revised below exclude non-controlling interests of $6 million as of December 31, 2010 and 2009.
INFORMATION FOR THIS ITEM IS NOT REQUIRED FOR PEPCO, DPL, AND ACE AS THEY MEET THE CONDITIONS SET FORTH IN GENERAL INSTRUCTIONS I(1)(a) AND (b) OF FORM 10-K AND THEREFORE ARE FILING THIS FORM WITH THE REDUCED FILING FORMAT.
Item 7.
Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The information required by this item is contained herein, as follows:
PEPCO HOLDINGS
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Pepco Holdings, Inc.
General Overview
PHI, a Delaware corporation incorporated in 2001, is a holding company that, through its regulated public utility subsidiaries, is engaged primarily in the transmission, distribution and default supply of electricity, and, to a lesser extent, the distribution and supply of natural gas (Power Delivery). Through Pepco Energy Services, Inc. and its subsidiaries (collectively, Pepco Energy Services), PHI provides energy savings performance contracting services, underground transmission and distribution construction and maintenance services and steam and chilled water under long-term contracts. For additional discussion, see “Pepco Energy Services” below.
Each of Power Delivery and Pepco Energy Services constitutes a separate segment for financial reporting purposes. Through its subsidiary Potomac Capital Investment Corporation (PCI), PHI maintained a portfolio of cross-border energy lease investments. PHI completed the termination of its interests in its cross-border energy lease investments during 2013. As a result, the cross-border energy lease investments, which comprised substantially all of the operations of the Other Non-Regulated segment, are being accounted for as discontinued operations. The remaining operations of the Other Non-Regulated segment, which no longer meet the definition of a separate segment for financial reporting purposes, are being included in Corporate and Other.
The following table sets forth the percentage contributions to consolidated operating revenue and operating income from continuing operations attributable to PHI segments for each of the preceding three years:
Power Delivery
Power Delivery Electric consists primarily of the transmission, distribution and default supply of electricity, and Power Delivery Gas consists of the delivery and supply of natural gas.
The Pepco, DPL and ACE service territories are located within a corridor extending from the District of Columbia to southern New Jersey. These service territories are economically diverse and include key industries that contribute to the regional economic base:
•
Commercial activities in the region include banking and other professional and medical services, government and education, insurance, shopping malls, casinos, tourism and transportation.
•
Industrial activities in the region include chemical, glass, pharmaceutical, steel manufacturing, food processing and oil refining.
PEPCO HOLDINGS
Each utility comprising Power Delivery is a regulated public utility in the jurisdictions that comprise its service territory. Each utility is responsible for the distribution of electricity and, in the case of DPL, natural gas in its service territory, for which it is paid tariff rates established by the applicable local public service commission in each jurisdiction. Each utility also supplies electricity at regulated rates to retail customers in its service territory who do not elect to purchase electricity from a competitive energy supplier. The regulatory term for this supply service is SOS in Delaware, the District of Columbia and Maryland, and BGS in New Jersey. These supply service obligations are referred to generally as Default Electricity Supply.
Each of Pepco, DPL and ACE is responsible for the transmission of wholesale electricity into and across its service territory. The rates each utility is permitted to charge for the wholesale transmission of electricity are regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.
The profitability of Power Delivery depends on its ability to recover costs and earn a reasonable return on its capital investments through the rates it is permitted to charge. Operating results also can be affected by economic conditions generally, the level of commercial activity affecting a region, industry or business sector within a service territory, energy prices, the impact of energy efficiency measures on customer usage of electricity and weather.
Power Delivery’s results historically have been seasonal, generally producing higher revenue and income in the warmest and coldest periods of the year. For retail customers of Pepco and DPL in Maryland and of Pepco in the District of Columbia, revenue is not affected by unseasonably warmer or colder weather because a BSA was implemented that provides for a fixed distribution charge per customer rather than a charge based upon energy usage. The BSA has the effect of decoupling the distribution revenue recognized in a reporting period from the amount of power delivered during the period. As a result, the only factors that will cause distribution revenue from retail customers in Maryland and the District of Columbia to fluctuate from period to period are changes in the number of customers and changes in the approved distribution charge per customer. A comparable revenue decoupling mechanism for DPL electricity and natural gas customers in Delaware is under consideration by the DPSC.
In accounting for the BSA in Maryland and the District of Columbia, a Revenue Decoupling Adjustment (an adjustment equal to the amount by which revenue from distribution sales differs from the revenue that Pepco and DPL are entitled to earn based on the approved distribution charge per customer) is recorded representing either (i) a positive adjustment equal to the amount by which revenue from retail distribution sales falls short of the revenue that Pepco and DPL are entitled to earn based on the approved distribution charge per customer or (ii) a negative adjustment equal to the amount by which revenue from such distribution sales exceeds the revenue that Pepco and DPL are entitled to earn based on the approved distribution charge per customer.
PHI’s utility subsidiaries devote a substantial portion of their total capital expenditures to improving the reliability of their electrical transmission and distribution systems and replacing aging infrastructure throughout their service territories. These activities include:
•
identifying and upgrading under-performing feeder lines;
•
adding new facilities to support load;
•
installing distribution automation systems on both the overhead and underground network systems; and
•
rejuvenating and replacing underground residential cables.
PEPCO HOLDINGS
PHI’s capital expenditures for continuing reliability enhancement efforts are included in the table of projected capital expenditures within “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity - Capital Requirements - Capital Expenditures.”
Power Delivery Initiatives and Activities
Smart Grid Initiatives
PHI’s utility subsidiaries are engaged in transforming the power grid that they own and operate into a “smart grid,” a network of automated digital devices capable of collecting and communicating large amounts of real-time data.
A central component of the smart grid is AMI, a system that collects, measures and analyzes energy usage data from advanced digital meters, known as “smart meters.” Also critical to the operation of the smart grid is distribution automation technology, which is comprised of automated devices that have internal intelligence and can be controlled remotely to better manage power flow and restore service quickly and more safely. Both the AMI system and distribution automation are enabled by advanced technology that communicates with devices installed on the energy delivery system and transmits energy usage data to the host utility. The implementation of the AMI system and distribution automation involves an integration of technologies provided by multiple vendors.
The DCPSC, the MPSC and the DPSC have approved the creation by PHI’s utility subsidiaries of regulatory assets to defer AMI costs between rate cases and to accrue returns on the deferred costs. Thus, these costs will be recovered in the future through base rates; however, for AMI costs incurred by Pepco in Maryland with respect to test years after 2011, pursuant to an MPSC order, the recovery of such costs will be allowed when Pepco demonstrates that the AMI system is cost-effective. The MPSC’s July 2013 order in Pepco’s November 2012 electric distribution base rate application excluded 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.
In 2010, two of PHI’s utility subsidiaries were granted cash awards in the aggregate amount of $168 million by the U.S. Department of Energy to support their smart grid initiatives.
•
Pepco was awarded $149 million for AMI, direct load control, distribution automation and communications infrastructure, of which $145 has been received through December 31, 2013.
•
ACE was awarded $19 million for direct load control, distribution automation and communications infrastructure, of which $17 has been received through December 31, 2013.
For a discussion of the projected capital expenditures of each utility subsidiary associated with PHI’s smart grid initiatives over the period 2014 through 2018, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity - Capital Requirements.”
PEPCO HOLDINGS
Mitigation of Regulatory Lag
An important factor in the ability of PHI’s utility subsidiaries to earn their authorized ROE is the willingness of applicable public service commissions to adequately address the shortfall in revenues in a utility’s rate structure due to the delay in time or “lag” between when costs are incurred and when they are reflected in rates. This delay is commonly known as “regulatory lag.” Pepco, DPL and ACE are currently experiencing significant regulatory lag because investments in rate base and operating expenses are increasing more rapidly than their revenue growth.
In an effort to minimize the effects of regulatory lag, PHI’s utility subsidiaries are:
•
filing electric distribution base rate cases every nine to twelve months in each of their jurisdictions,
•
pursuing alternative ratemaking mechanisms,
•
evaluating potential reductions in planned capital expenditures, and
•
continuing outreach to the regulatory community and other stakeholders, to discuss the changing regulatory model economics that are causing regulatory lag.
Alternative mechanisms that may reduce regulatory lag include adjusting historic test periods in distribution base rate cases to recognize plant additions which are already being used to provide service to customers when new rates go into effect, grid resiliency charges to allow contemporaneous recovery of costs for infrastructure related to system reliability, and multi-year rate plans.
Each of PHI’s utility subsidiaries will continue to seek cost recovery from applicable public service commissions to reduce the effects of regulatory lag and have an opportunity to earn its authorized ROE. There can be no assurance that any attempts by PHI’s utility subsidiaries to mitigate regulatory lag will be approved or, that even if approved, the cost recovery mechanisms will fully mitigate the effects of regulatory lag.
MAPP Project
On August 24, 2012, the board of PJM terminated the MAPP project and removed it from PJM’s regional transmission expansion plan. PHI had been directed to construct MAPP, a 152-mile high-voltage interstate transmission line, to address the reliability needs of the region’s transmission system. In December 2012, PHI submitted a filing to FERC seeking recovery of $88 million of abandoned MAPP costs over a five-year period. 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.
In February 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.
In December 2013, PHI submitted a settlement agreement to FERC with respect to this matter. Under the terms of the proposed settlement agreement, Pepco and DPL would recover their abandoned MAPP costs over a three-year recovery period beginning June 1, 2013. The settlement agreement, which is subject to FERC approval, would resolve all issues concerning the recovery of abandonment costs associated with the cancellation of the MAPP project. The terms of this settlement, if approved, would not be subject to the pending formula rate or transmission ROE challenges at FERC or modification through any other FERC proceeding. PHI cannot predict the timing or results of a final FERC decision in this proceeding.
As of December 31, 2013, PHI had a regulatory asset related to the MAPP abandoned costs of approximately $68 million, representing the original filing amount of approximately $88 million of abandoned costs referred to above less: (i) approximately $2 million of disallowed costs written off in
PEPCO HOLDINGS
2013; (ii) $4 million of materials transferred to inventories for use on other projects; and (iii) $14 million of amortization expense recorded in 2013. The regulatory asset balance includes the costs of land, land rights, engineering and design, environmental services, and project management and administration.
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 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. PHI cannot predict when a final FERC decision in this proceeding will be issued.
Pepco Energy Services
Pepco Energy Services is focused on growing its energy savings business and its underground transmission and distribution construction business while managing its thermal assets in Atlantic City. The energy savings business focuses on developing, building and operating energy savings performance contracting solutions primarily for federal, state and local government customers. After a significant slowdown in 2012, the energy savings market improved in 2013, however the market has not returned to the level of activity prior to 2012. The market is expected to continue to improve as the long-term fundamentals of the energy savings business remain strong. Pepco Energy Services’ underground transmission and distribution construction business focuses on providing construction and maintenance services for electric power utilities in North America.
PHI guarantees the obligations of Pepco Energy Services under certain contracts in its energy savings performance contracting business and underground transmission and distribution construction business. At December 31, 2013, PHI’s guarantees of Pepco Energy Services’ obligations under these contracts totaled $190 million.
During 2012, Pepco Energy Services deactivated its Buzzard Point and Benning Road oil-fired generation facilities. Pepco Energy Services placed the facilities into an idle condition termed a “cold closure.” A cold closure requires that the utility service be disconnected so that the facilities are no longer operable and require only essential maintenance until they are completely decommissioned. During the third quarter of 2013, Pepco Energy Services determined that it would be more cost effective to pursue the demolition of the Benning Road generation facility and realization of the scrap metal salvage value of the facility instead of maintaining cold closure status. The demolition of the facility commenced in the fourth quarter of 2013 and is expected to be completed by the end of 2014. Pepco Energy Services will recognize the salvage proceeds associated with the scrap metals at the facility as realized.
PEPCO HOLDINGS
Corporate and Other
Between 1990 and 1999, PCI, through various subsidiaries, entered into certain transactions involving investments in aircraft and aircraft equipment, railcars and other assets. In connection with these transactions, PCI recorded deferred tax assets in prior years of $101 million in the aggregate. Following events that took place during the first quarter of 2013, which included (i) court decisions in favor of the IRS with respect to both Consolidated Edison’s cross-border lease transaction (discussed in “- Discontinued Operations - Cross-Border Energy Lease Investments” below) and another taxpayer’s structured transactions, (ii) the change in PHI’s tax position with respect to the tax benefits associated with its cross-border energy leases, and (iii) PHI’s decision in March 2013 to begin to pursue the early termination of its remaining cross-border energy lease investments (which represented a substantial portion of the remaining assets within PCI) without the intent to reinvest these proceeds in income-producing assets, management evaluated the likelihood that PCI would be able to realize the $101 million of deferred tax assets in the future. Based on this evaluation, PCI established valuation allowances against these deferred tax assets totaling $101 million in the first quarter of 2013. Further, during the fourth quarter of 2013, in light of additional court decisions in favor of the IRS involving other taxpayers, and after consideration of all relevant factors, management determined that it would abandon the further pursuit of these deferred tax assets, and these assets totaling $101 million were charged off against the previously established valuation allowances. This charge is included in Corporate and Other, as presented in Note (5), “Segment Information,” to the consolidated financial statements of PHI, because the remaining operations of the former Other Non-Regulated segment are now included in Corporate and Other.
Discontinued Operations
In this Management’s Discussion and Analysis of Financial Condition and Results of Operations, all references to continuing operations exclude the following discontinued operations.
Cross-Border Energy Lease Investments
Through its subsidiary PCI, PHI held a portfolio of cross-border energy lease investments. During July 2013, PHI completed the termination of its interest in its cross-border energy lease investments. With the completion of the termination of the cross-border energy leases, the cross-border energy lease investments are being accounted for as discontinued operations.
As discussed in Note (15), “Commitments and Contingencies - PHI’s Cross-Border Energy Lease Investments,” to the consolidated financial statements of PHI, PHI is involved in ongoing litigation with the IRS concerning certain benefits associated with previously held investments in cross-border energy leases. On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit issued an opinion in Consolidated Edison Company of New York, Inc. & Subsidiaries v. United States (to which PHI is not a party) that disallowed tax benefits associated with Consolidated Edison’s cross-border lease transaction. As a result of the court’s ruling in this case, PHI determined in the first quarter of 2013 that its tax position with respect to the benefits associated with its cross-border energy leases no longer met the more-likely-than-not standard of recognition for accounting purposes, and PCI recorded non-cash charges of $323 million (after-tax) in the first quarter of 2013 and $6 million (after-tax) in the second quarter of 2013, consisting of the following components:
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A non-cash pre-tax charge of $373 million ($313 million after-tax) to reduce the carrying value of these cross-border energy lease investments under FASB guidance on leases (Accounting Standards Codification (ASC) 840). This pre-tax charge was originally recorded in the consolidated statements of (loss) income as a reduction in operating revenue and is now reflected in (loss) income from discontinued operations, net of income taxes.
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A non-cash charge of $16 million after-tax to reflect the anticipated additional net interest expense under FASB guidance for income taxes (ASC 740), related to estimated federal and state income tax obligations for the period over which the tax benefits may be disallowed. This after-tax charge was originally recorded in the consolidated statements of (loss) income as an increase
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in income tax expense and is now reflected in (loss) income from discontinued operations, net of income taxes. The after-tax interest charge for PHI on a consolidated basis was $70 million and this amount was allocated to each member of PHI’s consolidated group as if each member was a separate taxpayer, resulting in the recognition of a $12 million interest benefit for the Power Delivery segment and interest expense of $16 million for PCI and $66 million for Corporate and Other, respectively.
Retail Electric and Natural Gas Supply Businesses of Pepco Energy Services
In December 2009, PHI announced the wind-down of the retail energy supply component of the Pepco Energy Services business which was comprised of the retail electric and natural gas supply businesses. Pepco Energy Services implemented the wind-down by not entering into any new retail electric or natural gas supply contracts while continuing to perform under its existing retail electric and natural gas supply contracts through their respective expiration dates. On March 21, 2013, Pepco Energy Services entered into an agreement whereby a third party assumed all the rights and obligations of the remaining retail natural gas supply customer contracts, and the associated supply obligations, inventory and derivative contracts. The transaction was completed on April 1, 2013. In addition, Pepco Energy Services completed the wind-down of its retail electric supply business in the second quarter of 2013 by terminating its remaining customer supply and wholesale purchase obligations beyond June 30, 2013.
The operations of Pepco Energy Services’ retail electric and natural gas supply businesses have been classified as discontinued operations and are no longer a part of the Pepco Energy Services segment for financial reporting purposes.
Earnings Overview
Year Ended December 31, 2013 Compared to Year Ended December 31, 2012
Net income from continuing operations for the year ended December 31, 2013 was $110 million, or $0.45 per share, compared to $218 million, or $0.95 per share, for the year ended December 31, 2012.
Net income from continuing operations for the year ended December 31, 2013 included the charges set forth below in Corporate and Other, which are presented, where applicable, net of related federal and state income taxes and are in millions of dollars:
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Excluding the items listed above for the year ended December 31, 2013, net income from continuing operations would have been $277 million, or $1.13 per share. PHI discloses net income from continuing operations and related per share data excluding these items because management believes that these items are not representative of PHI’s ongoing business operations. Management uses this information, and believes that such information is useful to investors, in evaluating PHI’s period-over-period performance. The inclusion of this disclosure is intended to complement, and should not be considered as an alternative to, PHI’s reported net income from continuing operations and related per share data in accordance with GAAP.
Net loss from discontinued operations for the year ended December 31, 2013 was $322 million, or $1.31 per share, compared to net income of $67 million, or $0.30 per share ($0.29 per share on a diluted basis), for the year ended December 31, 2012.
Discussion of Operating Segment Net Income Variances:
Power Delivery’s $54 million increase in earnings was primarily due to the following:
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An increase of $64 million from electric distribution base rate increases (Pepco in the District of Columbia and Maryland, DPL in Maryland and Delaware and ACE in New Jersey).
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An increase of $16 million due to lower operation and maintenance expense, primarily associated with higher storm restoration and system maintenance in 2012, partially offset by recovery in 2012 of 2011 storm restoration costs and regulatory expenses.
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An increase of $4 million primarily due to higher sales from colder winter weather, partially offset by lower sales from milder summer weather.
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A decrease of $12 million due to higher depreciation and amortization expense associated primarily with regulatory assets and increases in plant investment, partially offset by lower depreciation rates.
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A decrease of $7 million due to higher interest expense resulting from an increase in outstanding debt.
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A decrease of $6 million associated with Default Electricity Supply margins for DPL Delaware, primarily due to favorable adjustments in 2012 related to the under-recognition of allowed returns on net uncollectible expense and regulatory taxes.
Pepco Energy Services’ $11 million increase in earnings was primarily due to the following:
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An increase of $6 million primarily due to improved performance in the energy savings business and thermal business in Atlantic City, New Jersey, as well as lower compensation expenses.
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An increase of $5 million due to lower asset impairment charges.
Corporate and Other’s $173 million increase in net loss was primarily due to the following:
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An after-tax charge of $101 million to establish valuation allowances against certain PCI deferred tax assets.
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An after-tax charge of $66 million to reflect the anticipated additional interest expense allocated to Corporate and Other related to changes in PHI’s consolidated estimated federal and state income tax obligations resulting from the change in assessment regarding the tax benefits related to the cross-border energy lease investments.
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Discussion of Discontinued Operations Variance:
Net earnings from discontinued operations for the year ended December 31, 2013 decreased by $389 million as a result of the following:
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An aggregate after-tax charge of $313 million recorded in 2013 to reduce the carrying value of PCI’s cross-border energy lease investments ($373 million pre-tax).
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An after-tax charge of $16 million recorded in 2013 to reflect the anticipated additional interest expense on estimated federal and state income tax obligations allocated to PCI (as if it were a separate taxpayer) resulting from the change in assessment of the tax benefits associated with the cross-border energy lease investments ($25 million pre-tax).
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An after-tax gain of $9 million recorded in 2012 related to the early termination of certain cross-border energy leases ($39 million pre-tax) and an after-tax loss of $2 million recorded in 2013 ($3 million pre-tax), associated with the completion of the early termination of the remaining cross-border energy lease investments.
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A decrease of $27 million as a result of holding fewer cross-border energy leases in 2013.
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A decrease of $21 million as a result of lower sales volume in 2013 due to the wind-down of the retail electric and natural gas supply businesses.
Consolidated Results of Operations
The following results of operations discussion compares the year ended December 31, 2013 to the year ended December 31, 2012. All amounts in the tables (except sales and customers) are in millions of dollars.
Continuing Operations
Operating Revenue
A detail of the components of PHI’s consolidated operating revenue is as follows:
Power Delivery
The following table categorizes Power Delivery’s operating revenue by type of revenue.
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Regulated Transmission and Distribution (T&D) Electric Revenue includes revenue from the distribution of electricity, including the distribution of Default Electricity Supply, by PHI’s utility subsidiaries to customers within their service territories at regulated rates. Regulated T&D Electric Revenue also includes transmission service revenue that PHI’s utility subsidiaries receive as transmission owners from PJM at rates regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.
Default Electricity Supply Revenue is the revenue received from the supply of electricity by PHI’s utility subsidiaries at regulated rates to retail customers who do not elect to purchase electricity from a competitive energy supplier. The costs related to Default Electricity Supply are included in Fuel and Purchased Energy. Default Electricity Supply Revenue also includes revenue from non-bypassable Transition Bond Charges that ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds, and revenue in the form of transmission enhancement credits that PHI utility subsidiaries receive as transmission owners from PJM in consideration for approved regional transmission expansion plan expenditures.
Other Electric Revenue includes work and services performed on behalf of customers, including other utilities, which is generally not subject to price regulation. Work and services include mutual assistance to other utilities, highway relocation, rentals of pole attachments, late payment fees and collection fees.
Regulated Gas Revenue includes the revenue DPL receives from on-system natural gas delivered sales and the transportation of natural gas for customers within its service territory at regulated rates.
Other Gas Revenue consists of DPL’s off-system natural gas sales and the short-term release of interstate pipeline transportation and storage capacity not needed to serve customers. Off-system sales are made possible when low demand for natural gas by regulated customers creates excess pipeline capacity.
Regulated T&D Electric
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Regulated T&D Electric Revenue increased by $140 million primarily due to:
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An increase of $107 million due to distribution rate increases (Pepco in the District of Columbia effective October 2012, and in Maryland effective July 2013 and July 2012; DPL in Maryland effective July 2012 and September 2013, and in Delaware effective October 2013 and July 2012; ACE effective November 2012 and July 2013).
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An increase of $14 million in transmission revenue related to the recovery of MAPP abandonment costs, as approved by FERC (which is offset in Depreciation and Amortization).
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An increase of $14 million in transmission revenue rates effective June 1, 2012 and June 1, 2013 related to increases in transmission plant investment and operating expenses.
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An increase of $7 million in transmission revenue related to the resale by DPL of renewable energy in Delaware (which is substantially offset in Purchased Energy and Depreciation and Amortization).
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An increase of $6 million primarily due to a rate increase in the New Jersey Societal Benefit Charge (related to the New Jersey Societal Benefit Program, which is a New Jersey public interest program for low income customers) effective July 2012 (which is offset in Deferred Electric Service Costs).
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An increase of $6 million in transmission revenue primarily attributable to higher capacity as a result of expanding Maryland demand side management programs (which is partially offset in Depreciation and Amortization).
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An increase of $5 million primarily due to a Renewable Portfolio Surcharge in Delaware effective June 2012 (which is substantially offset in Fuel and Purchased Energy and Depreciation and Amortization).
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An increase of $3 million due to Pepco and DPL customer growth in 2013, primarily in the residential class.
The aggregate amount of these increases was partially offset by:
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A decrease of $13 million due to lower non-weather related average residential and commercial customer usage.
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A decrease of $6 million in transmission revenue associated with the change in FERC formula rate true-ups.
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A decrease of $4 million in distribution revenue due to lower pass-through revenue (which is substantially offset by a corresponding decrease in Other Taxes) primarily the result of a decrease in utility taxes collected by Pepco on behalf of Montgomery County, Maryland.
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A decrease of $1 million in transmission revenue primarily attributable to a peak-load rate decrease effective January 2013.
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Default Electricity Supply
Other Default Electricity Supply Revenue consists primarily of (i) revenue from the resale by ACE in the PJM RTO market of energy and capacity purchased under contracts with unaffiliated non-utility generators (NUGs), and (ii) revenue from transmission enhancement credits.
Default Electricity Supply Revenue decreased by $49 million primarily due to:
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A decrease of $76 million due to lower sales, primarily as a result of customer migration to competitive suppliers.
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A decrease of $22 million due to lower ACE and DPL non-weather related average customer usage.
The aggregate amount of these decreases was partially offset by:
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An increase of $36 million in wholesale energy and capacity resale revenues primarily due to higher market prices for the resale of electricity and capacity purchased from NUGs.
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An increase of $6 million due to higher Pepco and DPL revenue from transmission enhancement credits.
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An increase of $4 million due to higher sales primarily as a result of colder weather during the 2013 fall months, as compared to 2012.
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A net increase of $2 million as a result of higher Pepco Default Electricity Supply rates, partially offset by lower DPL and ACE rates.
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Regulated Gas
DPL’s natural gas service territory is located in New Castle County, Delaware. Several key industries contribute to the economic base as well as to growth as follows:
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Commercial activities in the region include banking, government, insurance, shopping malls, casinos and tourism.
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Industrial activities in the region include chemical, pharmaceutical, steel manufacturing and oil refining.
Regulated Gas Revenue increased by $14 million primarily due to:
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An increase of $22 million due to higher sales primarily as a result of colder weather during the winter months of 2013 as compared to 2012.
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An increase of $7 million due to higher non-weather related average commercial customer usage.
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An increase of $4 million due to a revenue adjustment recorded in June 2012 for a reduction in the estimate of gas sold but not yet billed to customers (which is partially offset by an increase in Purchased Energy).
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An increase of $2 million due to a distribution rate increase effective July 2013.
The aggregate amount of these increases was partially offset by a decrease of $22 million due to a Gas Cost Rate (GCR) decrease effective November 2012.
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Other Gas Revenue
Other Gas Revenue decreased by $6 million primarily due to lower average prices and lower volumes for off-system sales to electric generators and gas marketers.
Pepco Energy Services
Pepco Energy Services’ operating revenue decreased by $53 million primarily due to:
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A decrease of $36 million primarily in energy savings construction activities.
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A decrease of $18 million associated with the retirement of the two remaining oil-fired generation facilities in the second quarter of 2012.
Operating Expenses
Fuel and Purchased Energy and Other Services Cost of Sales
A detail of PHI’s consolidated Fuel and Purchased Energy and Other Services Cost of Sales is as follows:
Power Delivery
Power Delivery’s Fuel and Purchased Energy consists of the cost of electricity and natural gas purchased by its utility subsidiaries to fulfill their respective Default Electricity Supply and Regulated Gas obligations and, as such, is recoverable from customers in accordance with the terms of public service commission orders. It also includes the cost of natural gas purchased for off-system sales. Fuel and Purchased Energy expense decreased by $39 million primarily due to:
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A decrease of $85 million primarily due to customer migration to competitive suppliers.
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A decrease of $20 million in deferred electricity expense primarily due to higher DPL Default Electricity Supply cost of service rates, which resulted in a lower rate of recovery of Default Electricity Supply costs.
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A decrease of $13 million from the settlement of financial hedges entered into as part of DPL’s hedge program for the purchase of regulated natural gas.
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A decrease of $5 million in the cost of gas purchases for off-system sales as a result of lower volumes.
The aggregate amount of these decreases was partially offset by:
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A net increase of $45 million due to higher average electricity costs under Pepco and DPL Default Electricity Supply contracts, partially offset by lower ACE costs.
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An increase of $13 million in deferred electricity expense primarily due to a Renewable Portfolio Surcharge in Delaware effective June 2012 (which is substantially offset in Regulated T&D Electric Revenue and Depreciation and Amortization).
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An increase of $11 million in the cost of gas purchases for on-system sales as a result of higher average gas prices.
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An increase of $6 million due to higher electricity sales primarily as a result of colder weather during the 2013 fall months, as compared to 2012.
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An increase of $4 million in the costs associated with purchasing Renewable Energy Credits in Delaware (which is offset by a corresponding increase in Regulated T&D Electric Revenue).
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An increase of $4 million in the cost of gas purchases for on-system sales as a result of an adjustment recorded in June 2012 for a reduction in the estimate of gas sold but not yet billed to customers (which is offset by an increase in Regulated Gas Revenue).
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An increase of $2 million in the costs associated with purchases under wind power purchase agreements in Delaware (which is offset by a corresponding increase in Regulated T&D Electric Revenue).
Pepco Energy Services
Pepco Energy Services’ Fuel and Purchased Energy and Other Services Cost of Sales decreased by $38 million primarily due to:
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A decrease of $30 million primarily due to lower energy savings construction activity.
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A decrease of $7 million due to lower purchases of capacity and lower fuel usage, both attributable to the retirement of the remaining oil-fired generation facilities in the second quarter of 2012.
Other Operation and Maintenance
A detail of PHI’s Other Operation and Maintenance expense is as follows:
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Power Delivery
Other Operation and Maintenance expense for Power Delivery decreased by $30 million primarily due to:
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A decrease of $16 million in storm restoration costs.
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A decrease of $15 million associated with lower maintenance costs.
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A decrease of $9 million in customer service costs.
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A decrease of $1 million primarily due to 2012 total incremental storm restoration costs for major storm events as described in the following table:
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In January 2011, Pepco incurred incremental storm restoration costs of $10 million associated with a severe winter storm, all of which were expensed in 2011. In July 2012, the MPSC issued an order allowing for the deferral and recovery of $9 million of such costs over a five-year period.
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During 2012, Pepco, DPL and ACE incurred incremental storm restoration costs of $38 million associated with the June 2012 derecho which resulted in widespread damage to the electric distribution system in each of their service territories. PHI’s utility subsidiaries deferred $34 million of these costs as regulatory assets to reflect the probable recovery of these storm restoration costs in Maryland and New Jersey. The MPSC approved the recovery of these costs in Maryland for both Pepco and DPL in its July 2013 and August 2013 rate orders, respectively, over a five-year period. ACE’s stipulation of settlement approved by the NJBPU in June 2013 provides for recovery of these costs in New Jersey over a three-year period. The remaining costs of $4 million relate to repair work completed in Delaware and the District of Columbia which are not deferrable in those jurisdictions.
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In the fourth quarter of 2012, Pepco, DPL and ACE incurred incremental storm restoration costs of $28 million associated with Hurricane Sandy which resulted in widespread damage to the electric distribution system in each of their service territories. PHI’s utility subsidiaries deferred $22 million of these costs as regulatory assets to reflect the probable recovery of these storm restoration costs in Maryland and New Jersey. The MPSC approved the recovery of these costs in Maryland for both Pepco and DPL in its July 2013 and August 2013 rate orders, respectively, over a five-year period. ACE’s stipulation of settlement approved by the NJBPU in June 2013 provides for recovery of these costs in New Jersey over a three-year period. The remaining costs of $6 million relate to repair work completed in Delaware and the District of Columbia which are not deferrable in those jurisdictions.
The aggregate amount of these decreases was partially offset by:
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An increase of $6 million resulting from a 2012 deferred cost adjustment associated with DPL Default Electricity Supply. The deferred cost adjustments were primarily due to the under-recognition of allowed returns on net uncollectible expense and regulatory taxes.
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An increase of $3 million associated with the write-off of disallowed MAPP and associated transmission projects costs.
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An increase of $3 million in environmental remediation costs.
Pepco Energy Services
Other Operation and Maintenance expense for Pepco Energy Services decreased by $16 million primarily due to:
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A decrease of $5 million in personnel costs in its energy savings business primarily due to a reduction in the number of employees in the second half of 2012.
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A decrease of $4 million in contractual costs associated with the retirement of the two remaining oil-fired generation facilities in the second quarter of 2012.
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A decrease of $3 million in bid and proposal costs in its energy savings business.
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A decrease of $1 million associated with an accrual for an energy savings guarantee shortfall in 2012.
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A decrease of $1 million in operating, repairs and maintenance expenses at its combined heat and power thermal operations in Atlantic City.
Depreciation and Amortization
Depreciation and Amortization expense increased by $19 million to $473 million in 2013 from $454 million in 2012 primarily due to:
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An increase of $14 million in amortization of regulatory assets primarily related to recoverable AMI costs, major storm costs and rate case costs.
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An increase of $14 million in amortization of MAPP abandonment costs (which is offset in T&D Electric Revenue).
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An increase of $6 million in amortization due to the expiration in August 2013 of the excess depreciation reserve regulatory liability of ACE.
The aggregate amount of these increases was partially offset by:
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A decrease of $8 million due to the deactivation of Pepco Energy Services’ oil-fired generating facilities in the second quarter of 2012 and a reduction in the Benning Road asset retirement obligation in 2013 resulting from the decision to pursue the demolition of the Benning Road oil-fired generating facility.
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A decrease of $7 million in the Delaware Renewable Energy Portfolio Standards deferral (which is substantially offset by a corresponding increase in Fuel and Purchased Energy).
Power Delivery depreciation reflected no change from 2012 due to an increase from higher plant investment offset by lower depreciation rates in Pepco and DPL, approved by the MPSC effective July 20, 2012.
Other Taxes
Other Taxes decreased by $4 million to $428 million in 2013 from $432 million in 2012. The decrease was primarily due to lower sales that resulted in a decrease in utility taxes that are collected and passed through by Power Delivery (substantially offset by a corresponding decrease in Regulated T&D Electric Revenue).
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Deferred Electric Service Costs
Deferred Electric Service Costs, which relate only to ACE, represent (i) the over or under recovery of electricity costs incurred by ACE to fulfill its Default Electricity Supply obligation and (ii) the over or under recovery of New Jersey Societal Benefit Program costs incurred by ACE. The cost of electricity purchased is reported under Fuel and Purchased Energy and the corresponding revenue is reported under Default Electricity Supply Revenue. The cost of the New Jersey Societal Benefit Program is reported under Other Operation and Maintenance and the corresponding revenue is reported under Regulated T&D Electric Revenue.
Deferred Electric Service Costs increased by $31 million to an expense of $26 million in 2013 as compared to an expense reduction of $5 million in 2012 primarily due to an increase in deferred electricity expense as a result of higher Default Electricity Supply and New Jersey Societal Benefit Program revenue rates and lower electricity supply costs.
Impairment Losses
Impairment losses decreased by $8 million to $4 million in 2013 from $12 million in 2012. The decrease was primarily due to 2012 impairment losses of $12 million ($7 million after-tax) at Pepco Energy Services associated with the combustion turbines at Buzzard Point and certain landfill gas-fired electric generation facilities, partially offset by a 2013 impairment loss of $4 million ($3 million after-tax) associated with a landfill gas-fired electric generation facility.
Other Income (Expenses)
Other Expenses (which are net of Other Income) increased by $19 million to a net expense of $239 million in 2013 from a net expense of $220 million in 2012. The increase reflects a $16 million increase in interest expense primarily associated with higher long-term debt and $3 million associated with lower income related to the allowance for funds used during construction (AFUDC) that is applied to capital projects.
Income Tax Expense
PHI’s income tax expense increased by $216 million to $319 million in 2013 from $103 million in 2012.
PHI’s consolidated effective income tax rates for the years ended December 31, 2013 and 2012 were 74.4% and 32.1%, respectively.
The increase in the effective tax rate for the year ended December 31, 2013 occurred as a result of recording $56 million of changes in estimates and interest related to uncertain and effectively settled tax positions in the first quarter of 2013. In addition, the increase in the effective tax rate resulted from the establishment of valuation allowances of $101 million in the first quarter of 2013 against certain deferred tax assets in PCI, which is now included in Corporate and Other. Between 1990 and 1999, PCI, through various subsidiaries, entered into certain transactions involving investments in aircraft and aircraft equipment, railcars and other assets. In connection with these transactions, PCI recorded deferred tax assets in prior years of $101 million in the aggregate. Following events that took place during the first quarter of 2013, which included (i) court decisions in favor of the IRS with respect to both Consolidated Edison’s cross-border lease transaction (as discussed in Note (19), “Discontinued Operations - Cross-Border Energy Lease Investments,” to the consolidated financial statements of PHI) and another taxpayer’s structured transactions, (ii) the change in PHI’s tax position with respect to the tax benefits associated with its cross-border energy leases, and (iii) PHI’s decision in March 2013 to begin to pursue the early termination of its remaining cross-border energy lease investments (which represented a substantial portion of the remaining assets within PCI) without the intent to reinvest these proceeds in income-producing assets, management evaluated the likelihood that PCI would be able to realize the $101 million of deferred tax assets in the future. Based on this evaluation, PCI established valuation allowances against these deferred tax assets totaling $101
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million in the first quarter of 2013. Further, during the fourth quarter of 2013, in light of additional court decisions in favor of the IRS involving other taxpayers, and after consideration of the relevant factors, management determined that it would abandon the further pursuit of these deferred tax assets, and these assets totaling $101 million were charged off against the previously established valuation allowances.
The effective income tax rate for the year ended December 31, 2012 includes income tax benefits of $8 million related to uncertain and effectively settled tax positions, primarily due to the effective settlement with the IRS in the first quarter of 2012 with respect to the methodology used historically to calculate deductible mixed service costs and the expiration of the statute of limitations associated with an uncertain tax position in Pepco.
The rate for the year ended December 31, 2012 also reflects an increase in deductible asset removal costs for Pepco in 2012 related to a higher level of asset retirements.
Discontinued Operations
PHI’s (loss) income from discontinued operations, net of income taxes, is comprised of the following:
For the years ended December 31, 2013 and 2012, (loss) income from discontinued operations, net of income taxes, was a loss of $322 million and income of $67 million, respectively. The decrease of $389 million is comprised of a decrease of $368 million related to PHI’s cross-border lease investments and a decrease of $21 million related to the retail electric and natural gas supply businesses at Pepco Energy Services.
The decrease in (loss) income from discontinued operations, net of income taxes, for PHI’s cross-border energy lease investments is primarily due to after-tax non-cash charges of $323 million recorded in the first quarter of 2013 and $6 million in the second quarter of 2013, each related to a change in assessment regarding the tax benefits related to the cross-border energy lease investments and consisting of a $373 million pre-tax non-cash charge ($313 million after-tax) to reduce the carrying value of the investments and a $16 million after-tax non-cash charge to reflect the anticipated additional interest expense related to the change in PCI’s estimated federal and state income tax obligations as if it were a separate taxpayer. The (loss) income from discontinued operations, net of income taxes, was reduced further by lower cross-border energy lease investment earnings as a result of terminating the cross-border lease investments in 2013, the loss recorded on the early termination of the remaining cross-border energy lease investments during 2013, and gains recorded on the early termination of certain leases within the cross-border energy lease portfolio in the third quarter of 2012.
The decrease in (loss) income from discontinued operations, net of income taxes, at Pepco Energy Services is due to a reduction in sales volume associated with the wind-down of the retail electric and natural gas supply businesses, a reduction in mark-to-market gains, and costs incurred to accelerate the wind-down of the retail electric supply business.
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The following results of operations discussion compares the year ended December 31, 2012 to the year ended December 31, 2011. All amounts in the tables (except sales and customers) are in millions of dollars.
Continuing Operations
Operating Revenue
A detail of the components of PHI’s consolidated operating revenue is as follows:
Power Delivery
The following table categorizes Power Delivery’s operating revenue by type of revenue.
Regulated T&D Electric Revenue includes revenue from the distribution of electricity, including the distribution of Default Electricity Supply, by PHI’s utility subsidiaries to customers within their service territories at regulated rates. Regulated T&D Electric Revenue also includes transmission service revenue that PHI’s utility subsidiaries receive as transmission owners from PJM at rates regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.
Default Electricity Supply Revenue is the revenue received from the supply of electricity by PHI’s utility subsidiaries at regulated rates to retail customers who do not elect to purchase electricity from a competitive energy supplier. The costs related to Default Electricity Supply are included in Fuel and Purchased Energy. Default Electricity Supply Revenue also includes revenue from Transition Bond Charges that ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds issued by ACE Funding, and revenue in the form of transmission enhancement credits that PHI utility subsidiaries receive as transmission owners from PJM for approved regional transmission expansion plan costs.
Other Electric Revenue includes work and services performed on behalf of customers, including other utilities, which is generally not subject to price regulation. Work and services include mutual assistance to other utilities, highway relocation, rentals of pole attachments, late payment fees and collection fees.
Regulated Gas Revenue includes the revenue DPL receives from on-system natural gas delivered sales and the transportation of natural gas for customers within its service territory at regulated rates.
Other Gas Revenue consists of DPL’s off-system natural gas sales and the short-term release of interstate pipeline transportation and storage capacity not needed to serve customers. Off-system sales are made possible when low demand for natural gas by regulated customers creates excess pipeline capacity.
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Regulated T&D Electric
Regulated T&D Electric Revenue increased by $115 million primarily due to:
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An increase of $46 million due to distribution rate increases in all jurisdictions (Pepco in the District of Columbia effective October 2012, and in Maryland effective July 2012; DPL in Maryland effective July 2012 and July 2011, and in Delaware effective July 2012; ACE effective November 2012).
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An increase of $35 million in transmission revenue primarily attributable to higher Pepco and DPL rates effective June 1, 2012 and June 1, 2011 related to increases in transmission plant investment and operating expenses.
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An increase of $17 million due to EmPower Maryland (a demand-side management program) rate increases in February 2012 (which is substantially offset by a corresponding increase in Depreciation and Amortization).
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An increase of $15 million primarily due to a Renewable Portfolio Surcharge in Delaware effective June 2012 (which is substantially offset by a corresponding increase in Fuel and Purchased Energy and Depreciation and Amortization).
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An increase of $15 million primarily due to a rate increase in the New Jersey Societal Benefit Charge effective July 2012 (which is offset in Deferred Electric Service Costs).
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An increase of $7 million due to Pepco customer growth in 2012, primarily in the residential class.
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The aggregate amount of these increases was partially offset by:
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A decrease of $13 million due to lower pass-through revenue (which is substantially offset by a corresponding decrease in Other Taxes) primarily the result of a decrease in Montgomery County, Maryland utility taxes that are collected by Pepco on behalf of the jurisdiction.
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A decrease of $6 million in Transitional Energy Facility Assessment (TEFA) rate revenue in New Jersey due to a rate decrease effective January 2012 (which is primarily offset by a corresponding decrease in Other Taxes).
Default Electricity Supply
Other Default Electricity Supply Revenue consists primarily of (i) revenue from the resale by ACE in the PJM RTO market of energy and capacity purchased under contracts with unaffiliated NUGs, and (ii) revenue from transmission enhancement credits.
Default Electricity Supply Revenue decreased by $338 million primarily due to:
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A decrease of $140 million due to lower sales, primarily as a result of customer migration to competitive suppliers.
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A net decrease of $100 million as a result of lower Pepco and DPL Default Electricity Supply rates, partially offset by higher ACE rates.
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A decrease of $38 million in wholesale energy and capacity resale revenues primarily due to lower market prices for the resale of electricity and capacity purchased from NUGs.
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A decrease of $35 million due to lower sales as a result of milder weather during the 2012 winter and spring months, as compared to 2011.
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A net decrease of $26 million due to lower Pepco and ACE non-weather related average residential customer usage, partially offset by higher DPL residential customer usage.
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The aggregate amount of these decreases was partially offset by an increase of $5 million due to higher Pepco revenue from transmission enhancement credits.
Regulated Gas
Regulated Gas Revenue decreased by $32 million primarily due to:
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A decrease of $14 million due to lower sales primarily as a result of milder weather during the winter months of 2012 as compared to 2011.
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A decrease of $9 million due to GCR decreases effective November 2011 and November 2012.
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A decrease of $5 million due to lower non-weather related average customer usage.
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A decrease of $4 million due to a revenue adjustment recorded in June 2012 for a reduction in the estimate of gas sold but not yet billed to customers (which is offset by a decrease in Fuel and Purchased Energy).
The aggregate amount of these decreases was partially offset by an increase of $1 million due to a distribution rate increase effective July 2011.
Other Gas Revenue
Other Gas Revenue decreased by $15 million primarily due to lower average prices and lower volumes for off-system sales to electric generators and gas marketers.
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Pepco Energy Services
Pepco Energy Services’ operating revenue decreased by $74 million primarily due to:
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A decrease of $55 million due to lower generation and capacity revenues attributable to the retirement of the remaining generation facilities in the second quarter of 2012.
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A decrease of $19 million primarily due to decreased energy savings construction activities.
Operating Expenses
Fuel and Purchased Energy and Other Services Cost of Sales
A detail of PHI’s consolidated Fuel and Purchased Energy and Other Services Cost of Sales is as follows:
Power Delivery
Power Delivery’s Fuel and Purchased Energy consists of the cost of electricity and natural gas purchased by its utility subsidiaries to fulfill their respective Default Electricity Supply and Regulated Gas obligations and, as such, is recoverable from customers in accordance with the terms of public service commission orders. It also includes the cost of natural gas purchased for off-system sales. Fuel and Purchased Energy expense decreased by $381 million primarily due to:
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A decrease of $158 million due to lower average electricity costs under Default Electricity Supply contracts.
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A decrease of $142 million primarily due to customer migration to competitive suppliers.
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A decrease of $29 million due to lower electricity sales primarily as a result of milder weather during the winter and spring months of 2012, as compared to the corresponding periods in 2011.
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A decrease of $21 million in the cost of gas purchases for on-system sales as a result of lower average gas prices and lower volumes purchased.
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A decrease of $18 million in deferred electricity expense primarily due to lower Pepco and DPL Default Electricity Supply revenue rates, which resulted in a lower rate of recovery of Default Electricity Supply costs.
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A decrease of $12 million in the cost of gas purchases for off-system sales as a result of lower average gas prices and lower volumes purchased.
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A decrease of $11 million from the settlement of financial hedges entered into as part of DPL’s hedge program for the purchase of regulated natural gas.
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A decrease of $4 million in the cost of gas purchases for on-system sales as a result of an adjustment recorded in June 2012 for a reduction in the estimate of gas sold but not yet billed to customers (which is offset by a decrease in Regulated Gas Revenue).
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The aggregate amount of these decreases was partially offset by:
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An increase of $6 million in deferred gas expense as a result of a higher rate of recovery of natural gas supply costs due to lower average gas prices.
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An increase of $6 million in costs to purchase Renewable Energy Credits in Delaware (which is offset by a corresponding increase in Regulated T&D Electric Revenue).
Pepco Energy Services
Pepco Energy Services’ Fuel and Purchased Energy and Other Services Cost of Sales decreased by $35 million primarily due to:
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A decrease of $29 million due to lower purchases of capacity and lower fuel usage, both attributable to the retirement of the remaining generation facilities in the second quarter of 2012.
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A decrease of $7 million due to lower energy savings construction activity partially offset by higher costs associated with energy services and underground transmission construction activities.
Other Operation and Maintenance
A detail of PHI’s Other Operation and Maintenance expense is as follows:
Power Delivery
Other Operation and Maintenance expense for Power Delivery increased by $17 million primarily due to:
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An increase of $16 million in employee-related costs, primarily pension and other employee benefits.
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An increase of $10 million resulting from a decrease in deferred cost adjustments associated with DPL Default Electricity Supply. The deferred costs adjustments were primarily due to the under-recognition of allowed returns on working capital and administrative costs in 2011, partially offset by favorable adjustments in 2012 related to allowed returns on net uncollectible expense and recovery of regulatory taxes.
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An increase of $8 million in customer support service and system support costs.
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An increase of $5 million in New Jersey Societal Benefit Program costs that are deferred and recoverable.
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An increase of $4 million in expenses related to regulatory filings.
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An increase of $4 million in self-insurance reserves for general and auto liability claims.
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The aggregate amount of these increases was partially offset by:
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A decrease of $15 million primarily due to a decrease in total incremental storm restoration costs for major storm events as described in the following table:
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In January 2011, Pepco incurred incremental storm restoration costs of $10 million associated with a severe winter storm, all of which were expensed in 2011. In July 2012, the MPSC issued an order allowing for the deferral and recovery of $9 million of such costs over a five-year period.
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During 2012, Pepco, DPL and ACE incurred incremental storm restoration costs of $38 million associated with the June 2012 derecho which resulted in widespread damage to the electric distribution system in each of their service territories. PHI’s utility subsidiaries deferred $34 million of these costs as regulatory assets to reflect the probable recovery of these storm restoration costs in Maryland and New Jersey, and will be pursuing recovery of these incremental storm restoration costs in their respective jurisdictions in their electric distribution base rate cases. The remaining costs of $4 million primarily relate to repair work completed in Delaware and the District of Columbia which are not deferrable in those jurisdictions.
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In the fourth quarter of 2012, Pepco, DPL and ACE incurred incremental storm restoration costs of $28 million associated with Hurricane Sandy which resulted in widespread damage to the electric distribution system in each of their service territories. PHI’s utility subsidiaries deferred $22 million of these costs as regulatory assets to reflect the probable recovery of these storm restoration costs in Maryland and New Jersey, and will be pursuing recovery of these incremental storm restoration costs in their respective jurisdictions in their electric distribution base rate cases. The remaining costs of $6 million primarily relate to repair work completed in Delaware and the District of Columbia which are not deferrable in those jurisdictions.
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During 2011, Pepco, DPL and ACE incurred incremental storm restoration costs of $28 million associated with Hurricane Irene which resulted in widespread damage to the electric distribution system in each of their service territories. PHI’s utility subsidiaries deferred $22 million of these costs as regulatory assets to reflect the probable recovery of these storm restoration costs in Maryland and New Jersey. The MPSC approved the recovery of these costs in Maryland for both Pepco and DPL in its July 2012 rate orders over a five-year period. ACE’s stipulation of settlement approved by the NJBPU in October 2012 provides for recovery of these costs in New Jersey over a three-year period. The remaining costs of $6 million relate to repair work completed in Delaware and the District of Columbia which are not deferrable in those jurisdictions.
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A decrease of $8 million in bad debt expenses.
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A decrease of $4 million associated with lower preventative maintenance and tree trimming costs due to accelerated efforts made in 2011 to improve reliability.
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A decrease of $3 million due to the deferral of distribution rate case costs previously charged to Other Operation and Maintenance expense. These deferrals were recorded in accordance with the MPSC rate order issued in July 2012 and the DCPSC rate order issued in September 2012, each allowing for the recovery of these costs.
Pepco Energy Services
Other Operation and Maintenance expense for Pepco Energy Services decreased by $4 million primarily due to the closing of the oil-fired generation facilities in the second quarter of 2012, partially offset by higher energy services expenses.
Depreciation and Amortization
Depreciation and Amortization expense increased by $29 million to $454 million in 2012 from $425 million in 2011 primarily due to:
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An increase of $22 million in amortization of regulatory assets primarily due to EmPower Maryland surcharge rate increases effective February 2012 and expanding Demand Side Management Programs (which are substantially offset by corresponding increases in Regulated T&D Electric Revenue).
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An increase of $11 million in amortization of AMI projects.
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An increase of $5 million due to utility plant additions, partially offset by lower depreciation rates.
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An increase of $4 million in the Delaware Renewable Energy Portfolio Standards deferral associated with the over-recovery of renewable energy procurement costs (which is offset by a corresponding increase in Regulated T&D Electric Revenue).
The aggregate amount of these increases was partially offset by:
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A decrease of $12 million in amortization of stranded costs primarily as the result of lower revenue due to rate decreases effective October 2011 for the ACE Transition Bond Charge and Market Transition Charge Tax (revenue ACE receives and pays to ACE Funding to recover income taxes associated with Transition Bond Charge revenue) (partially offset in Default Electricity Supply Revenue).
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A decrease of $4 million primarily due to the deactivation of Pepco Energy Services generating facilities in May 2012.
The MPSC reduced the depreciation rates for Pepco and DPL in their most recent electric distribution base rate cases, which is expected to lower annual Depreciation and Amortization expense for PHI by approximately $31 million effective July 20, 2012.
Other Taxes
Other Taxes decreased by $19 million to $432 million in 2012 from $451 million in 2011. The decrease was primarily due to:
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A decrease of $10 million, primarily due to a decrease in utility taxes that are collected and passed through by Power Delivery (substantially offset by a corresponding decrease in Regulated T&D Electric Revenue).
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A decrease of $5 million in TEFA tax collections due to a rate decrease effective January 2012 (partially offset by a corresponding decrease in Regulated T&D Electric Revenue).
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Deferred Electric Service Costs
Deferred Electric Service Costs, which relate only to ACE, represent (i) the over or under recovery of electricity costs incurred by ACE to fulfill its Default Electricity Supply obligation and (ii) the over or under recovery of New Jersey Societal Benefit Program costs incurred by ACE. The cost of electricity purchased is reported under Fuel and Purchased Energy and the corresponding revenue is reported under Default Electricity Supply Revenue. The cost of New Jersey Societal Benefit Programs is reported under Other Operation and Maintenance and the corresponding revenue is reported under Regulated T&D Electric Revenue.
Deferred Electric Service Costs increased by $58 million, to an expense reduction of $5 million in 2012 as compared to an expense reduction of $63 million in 2011, primarily due to an increase in deferred electricity expense as a result of higher Default Electricity Supply revenue rates, partially offset by higher electricity supply costs.
Impairment Losses
PHI’s operating expenses for the year ended December 31, 2012, included impairment losses of $12 million ($7 million after-tax) at Pepco Energy Services associated with the combustion turbines at Buzzard Point and certain landfill gas-fired electric generation facilities.
Other Income (Expenses)
Other Expenses (which are net of Other Income) increased by $3 million to a net expense of $220 million in 2012 from a net expense of $217 million in 2011. The increase reflects a $14 million increase in interest expense primarily associated with higher long-term debt and lower capitalized interest. The increase was mostly offset by an increase of $10 million in other income primarily from losses and impairments on equity investments in 2011 that did not occur in 2012.
Income Tax Expense
PHI’s income tax expense decreased by $11 million to $103 million in 2012 from $114 million in 2011.
PHI’s consolidated effective income tax rates for the years ended December 31, 2012 and 2011 were 32.1% and 33.9%, respectively.
The effective income tax rate for the year ended December 31, 2012 includes income tax benefits of $10 million related to uncertain and effectively settled tax positions, primarily due to the effective settlement with the IRS in the first quarter of 2012 with respect to the methodology used historically to calculate deductible mixed service costs and the expiration of the statute of limitations associated with an uncertain tax position in Pepco. During the year ended December 31, 2011, PHI recorded tax benefits of $17 million related to uncertain and effectively settled tax positions, primarily resulting from the settlement with the IRS on interest due on its 1996 through 2002 tax years.
The rate for the year ended December 31, 2012 also reflects an increase in deductible asset removal costs for Pepco in 2012 related to a higher level of asset retirements.
Discontinued Operations
PHI’s income from discontinued operations, net of income taxes, is comprised of the following:
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Income from discontinued operations, net of income taxes, increased by $32 million to $67 million in 2012 from $35 million in 2011.
The increase of $5 million in income from discontinued operations, net of income taxes, attributable to PHI’s cross-border energy lease investments was primarily due to higher gains recorded on the early termination of certain leases within the cross-border energy lease portfolio in 2012 as compared to 2011. The pre-tax gains were $39 million for each of the years ended December 31, 2012 and 2011, and the after-tax gains were $9 million and $3 million for the years ended December 31, 2012 and 2011, respectively.
The increase of $24 million in income from discontinued operations, net of income taxes, attributable to Pepco Energy Services’ retail electric and natural gas supply businesses was primarily due to higher gross margins related to gains from mark-to-market accounting for derivatives used to manage commodity price risk and decreases in other operation and maintenance expenses. These increases were partially offset by reduced sales volumes associated with the ongoing wind-down of the retail electric and natural gas supply businesses.
The loss from discontinued operations, net of income taxes, for Conectiv Energy in 2011 resulted from the recognition of a loss related to the disposition of the remaining assets and businesses of Conectiv Energy not included in the sale of such assets and businesses to Calpine Corporation.
Capital Resources and Liquidity
This section discusses PHI’s working capital, cash flow activity, capital requirements and other uses and sources of capital.
Working Capital
At December 31, 2013, PHI’s current assets on a consolidated basis totaled $1.4 billion and its consolidated current liabilities totaled $2.3 billion, resulting in a working capital deficit of $0.9 billion. PHI expects the working capital deficit at December 31, 2013 to be funded during 2014 in part through cash flows from operations and from the issuance of long-term debt. At December 31, 2012, PHI’s current assets on a consolidated basis totaled $1.3 billion and its consolidated current liabilities totaled $2.5 billion, for a working capital deficit of $1.2 billion. The decrease of $361 million in the working capital deficit from December 31, 2012 to December 31, 2013 was primarily due to a decrease in short-term debt, the repayment of which was primarily funded with cash received from the early terminations of the cross-border energy leases, a decrease in the current portion of long-term debt, and an increase in income taxes receivable, partially offset by an increase in liabilities and accrued interest related to uncertain tax positions.
At December 31, 2013, PHI’s consolidated cash and cash equivalents totaled $23 million, which consisted of cash and uncollected funds but excluded current Restricted Cash Equivalents (cash that is available to be used only for designated purposes) that totaled $13 million. At December 31, 2012, PHI’s consolidated cash and cash equivalents totaled $25 million, which consisted of cash and uncollected funds but excluded current Restricted Cash Equivalents that totaled $10 million.
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PHI’s short-term debt balances and current portions of long-term debt and project funding balances are summarized below:
Commercial Paper
PHI, Pepco, DPL and ACE maintain commercial paper programs to address short-term liquidity needs. As of December 31, 2013, the maximum capacity available under these programs was $875 million, $500 million, $500 million and $350 million, respectively, subject to available borrowing capacity under the unsecured syndicated credit facility described below.
The weighted average interest rate for commercial paper issued by PHI, Pepco, DPL and ACE during 2013 was 0.70%, 0.34%, 0.29% and 0.31%, respectively. The weighted average maturity of all commercial paper issued by PHI, Pepco, DPL and ACE during 2013 was five, five, three and four days, respectively.
Equity Forward Transaction
During 2012, PHI entered into an equity forward transaction in connection with a public offering of PHI common stock. Pursuant to the terms of this transaction, a forward counterparty borrowed 17,922,077 shares of PHI’s common stock from third parties and sold them to a group of underwriters for $19.25 per share, less an underwriting discount equal to $0.67375 per share. Under the terms of the equity forward transaction, upon physical settlement thereof, PHI was required to issue and deliver shares of PHI common stock to the forward counterparty at the then applicable forward sale price. The forward sale price was initially determined to be $18.57625 per share at the time the equity forward transaction was entered into and was subject to reduction from time to time in accordance with the terms of the equity
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forward transaction. PHI believed that the equity forward transaction substantially eliminated future equity price risk because the forward sale price was determinable as of the date that PHI entered into the equity forward transaction and was only reduced pursuant to the contractual terms of the equity forward transaction through the settlement date, which reductions were not affected by a future change in the market price of the PHI common stock. On February 27, 2013, PHI physically settled the equity forward at the then applicable forward sale price of $17.39 per share. The proceeds of approximately $312 million were used to repay outstanding commercial paper, a portion of which had been issued in order to make capital contributions to the utilities, and for general corporate purposes.
Credit Facility
PHI, Pepco, DPL and ACE maintain an unsecured syndicated credit facility to provide for their respective liquidity needs, including obtaining letters of credit, borrowing for general corporate purposes and supporting their commercial paper programs. On August 1, 2011, PHI, Pepco, DPL and ACE entered into an amended and restated credit agreement which, on August 2, 2012, was amended to extend the term of the credit facility to August 1, 2017 and to amend the pricing schedule to decrease certain fees and interest rates payable to the lenders under the facility. On August 1, 2013, as permitted under the existing terms of the credit agreement, a request by PHI, Pepco, DPL and ACE to extend the credit facility termination date to August 1, 2018 was approved. All of the terms and conditions, as well as pricing, remained the same after such extension.
The aggregate borrowing limit under the amended and restated credit facility is $1.5 billion, all or any portion of which may be used to obtain loans and up to $500 million of which may be used to obtain letters of credit. The facility also includes a swingline loan sub-facility, pursuant to which each company may make same day borrowings in an aggregate amount not to exceed 10% of the total amount of the facility. Any swingline loan must be repaid by the borrower within fourteen days of receipt. The credit sublimit is $750 million for PHI and $250 million for each of Pepco, DPL and ACE. The sublimits may be increased or decreased by the individual borrower during the term of the facility, except that (i) the sum of all of the borrower sublimits following any such increase or decrease must equal the total amount of the facility, and (ii) the aggregate amount of credit used at any given time by (a) PHI may not exceed $1.25 billion, and (b) each of Pepco, DPL or ACE may not exceed the lesser of $500 million or the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of the sublimit reallocations may not exceed eight per year during the term of the facility.
For additional discussion of the Credit Facility, see Note (10), “Debt,” to the consolidated financial statements of PHI.
Term Loan Agreements
PHI Term Loan Agreement
On March 28, 2013, PHI entered into a $250 million term loan agreement due March 27, 2014, pursuant to which PHI had borrowed $250 million at a rate of interest equal to the prevailing Eurodollar rate, which is determined by reference to the London Interbank Offered Rate (LIBOR) with respect to the relevant interest period, all as defined in the loan agreement, plus a margin of 0.875%. PHI used the net proceeds of the loan under the loan agreement to repay its outstanding $200 million term loan obtained in 2012, and for general corporate purposes. On May 29, 2013, PHI repaid the $250 million term loan with a portion of the net proceeds from the early termination of the cross-border energy lease investments.
ACE Term Loan Agreement
On May 10, 2013, ACE entered into a $100 million term loan agreement, pursuant to which ACE has borrowed (and may not re-borrow) $100 million at a rate of interest equal to the prevailing Eurodollar rate, which is determined by reference to the LIBOR with respect to the relevant interest period, all as defined in the loan agreement, plus a margin of 0.75%. ACE’s Eurodollar borrowings under the loan
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agreement may be converted into floating rate loans under certain circumstances, and, in that event, for so long as any loan remains a floating rate loan, interest would accrue on that loan at a rate per year equal to (i) the highest of (a) the prevailing prime rate, (b) the federal funds effective rate plus 0.5%, or (c) the one-month Eurodollar rate plus 1%, plus (ii) a margin of 0.75%. As of December 31, 2013, outstanding borrowings under the loan agreement bore interest at an annual rate of 0.92%, which is subject to adjustment from time to time. All borrowings under the loan agreement are unsecured, and the aggregate principal amount of all loans, together with any accrued but unpaid interest due under the loan agreement, must be repaid in full on or before November 10, 2014.
Under the terms of the term loan agreement, ACE must maintain compliance with specified covenants, including (i) the requirement that ACE maintain a ratio of total indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the loan agreement, which calculation excludes from the definition of total indebtedness certain trust preferred securities and deferrable interest subordinated debt (not to exceed 15% of total capitalization), (ii) a restriction on sales or other dispositions of assets, other than certain permitted sales and dispositions, and (iii) a restriction on the incurrence of liens (other than liens permitted by the loan agreement) on the assets of ACE. The loan agreement does not include any rating triggers. ACE was in compliance with all covenants under this loan agreement as of December 31, 2013.
Long-Term Project Funding
On October 24, 2013, Pepco Energy Services entered into an agreement with a lender to receive up to $8 million in construction financing at an interest rate of 4.68% for an energy savings project that is expected to be completed in 2014. The agreement includes a transfer of receivables from Pepco Energy Services to the lender after construction is completed, under which the customer would make contractual payments over a 23-year period to repay the financing. If there are shortfalls in Pepco Energy Services’ energy savings guarantee or other performance obligations to the customer that reduce customer payments below the contractual payment amounts, then Pepco Energy Services would compensate the lender for the unpaid amounts. PHI has guaranteed the performance obligations of Pepco Energy Services under the financing agreement.
Cash and Credit Facility Available as of December 31, 2013
(a) Cash and cash equivalents reported on the PHI consolidated balance sheet totaled $23 million, of which $7 million was invested in money market funds, and the balance was held in cash and uncollected funds.
PHI’s Cross-Border Energy Lease Investments
PHI has an ongoing dispute with the IRS regarding the appropriateness of certain significant income tax benefits claimed by PHI related to its cross-border energy lease investments beginning with its 2001 federal income tax return. In the first quarter of 2013, PHI estimated that, in the event the IRS were to be fully successful in its challenge to PHI’s tax position on the cross-border energy leases, PHI would have been obligated to pay $192 million in additional federal taxes and $50 million of interest on the additional federal taxes, totaling $242 million as of March 31, 2013. The estimate of additional federal taxes due includes PHI’s estimate of the expected resolution of other uncertain and effectively settled tax positions unrelated to the leases, the carrying back or carrying forward of any existing net operating losses, and the application of certain amounts paid in advance to the IRS.
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In order to mitigate PHI’s ongoing interest costs associated with the $242 million estimate of additional taxes and interest, PHI made a $242 million advanced payment to the IRS for the estimated additional taxes and related interest in the first quarter of 2013. This advanced payment was funded from then currently available sources of liquidity and short-term borrowings. In March 2013, PHI began to pursue the early termination of its six remaining cross-border energy lease investments, which had a net carrying value of approximately $869 million as of March 31, 2013. During the second and third quarters of 2013, PHI terminated early all of its interests in the six remaining lease investments. PHI received aggregate net cash proceeds of $873 million (net of aggregate termination payments of $2.0 billion used to retire the non-recourse debt associated with the terminated leases) and recorded an aggregate pre-tax loss, including transaction costs, of approximately $3 million ($2 million after-tax), representing the excess of the carrying value of the terminated leases over the net cash proceeds received. A portion of the net cash proceeds from the terminated leases was used to repay borrowings utilized to fund the advanced payment discussed above.
Pension and Other Postretirement Benefit Plans
PHI sponsors a non-contributory, defined benefit pension plan (the PHI Retirement Plan) that covers substantially all employees of Pepco, DPL and ACE and certain employees of other PHI subsidiaries. PHI also provides supplemental retirement benefits to certain eligible executive and key employees through nonqualified retirement plans. PHI’s funding policy with regard to the PHI Retirement Plan is to maintain a funding level that is at least equal to the target liability as defined under the Pension Protection Act of 2006.
Under the Pension Protection Act, if a plan incurs a funding shortfall in the preceding plan year, there can be required minimum quarterly contributions in the current and following plan years. In 2014, PHI, Pepco, DPL and ACE do not expect to make discretionary tax-deductible contributions to the PHI Retirement Plan. Management expects that the current balance of the PHI Retirement Plan assets is at least equal to the funding target liability for 2014 under the Pension Protection Act. During 2013, PHI, DPL and ACE made discretionary tax-deductible contributions to the PHI Retirement Plan in the amounts of $80 million, $10 million and $30 million, respectively. During 2012, Pepco, DPL and ACE made discretionary tax-deductible contributions to the PHI Retirement Plan in the amounts of $85 million, $85 million and $30 million, respectively. PHI satisfied the minimum required contribution rules under the Pension Protection Act in 2013, 2012 and 2011. For additional discussion of PHI’s Pension and Other Postretirement Benefits, see Note (9), “Pension and Other Postretirement Benefits,” to the consolidated financial statements of PHI.
PHI provides certain postretirement health care and life insurance benefits for eligible retired employees. Most employees hired on January 1, 2005 or later will not have company subsidized retiree health care coverage; however, they will be able to purchase coverage at full cost through PHI.
In 2013 and 2012, Pepco contributed $6 million and $5 million, respectively, DPL contributed $3 million and $7 million, respectively, and ACE contributed $6 million and $7 million, respectively, to the other postretirement benefit plan. In 2013 and 2012, contributions of $7 million and $13 million, respectively, were made by other PHI subsidiaries.
Based on the results of the 2013 actuarial valuation, PHI’s net periodic pension and other postretirement benefit (OPEB) costs were approximately $94 million in 2013 versus $110 million in 2012. The current estimate of benefit cost for 2014 is $67 million. The utility subsidiaries are responsible for substantially all of the total PHI net periodic pension and OPEB costs. Approximately 37% of net periodic pension and OPEB costs were capitalized in 2013. PHI estimates that its net periodic pension and OPEB expense will be approximately $40 million in 2014, as compared to $57 million in 2013 and $67 million in 2012.
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Other Postretirement Benefit Plan Amendment
During 2013, PHI approved two amendments to its other postretirement benefits plan. These amendments impacted the retiree health care and retiree life insurance benefits, and were effective on January 1, 2014. As a result of the amendments, which were cumulatively significant, PHI remeasured its accumulated postretirement benefit obligation as of July 1, 2013. The remeasurement resulted in a $193 million reduction of the accumulated postretirement benefit obligation, which included recording a prior service credit of $124 million, which will be amortized over approximately ten years, and a $69 million reduction from a change in the discount rate from 4.10% as of December 31, 2012 to 4.95% as of July 1, 2013.
Cash Flow Activity
PHI’s cash flows during 2013, 2012 and 2011 are summarized below:
Operating Activities
Cash flows from operating activities during 2013, 2012 and 2011 are summarized below:
Net cash from operating activities decreased $95 million for the year ended December 31, 2013, compared to the same period in 2012. The decrease was primarily due to a decrease in net income of $108 million and a $242 million advanced payment to the IRS for estimated additional taxes and related interest, partially offset by an $80 million decrease in pension contributions and a $72 million reduction in net current assets held for disposition or sale associated with the early termination of all cross-border energy lease investments and the wind-down of Pepco Energy Services’ retail electric and natural gas supply businesses.
Net cash from operating activities decreased $94 million for the year ended December 31, 2012, compared to the same period in 2011. The decrease was due primarily to a $90 million increase in pension contributions compared to 2011, the disposition of substantially all of Conectiv Energy’s remaining assets in 2011 and a $46 million increase in Pepco Energy Services net assets held for disposition. This was partially offset by a $79 million decrease in cash collateral related to derivative activities.
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Investing Activities
Cash flows used by investing activities during 2013, 2012 and 2011 are summarized below:
Net cash used by investing activities decreased $558 million for the year ended December 31, 2013, compared to the same period in 2012. The decrease was primarily due to proceeds from the early termination of all cross-border energy lease investments.
Net cash used by investing activities increased $222 million for the year ended December 31, 2012, compared to the same period in 2011. The increase was due primarily to a $275 million increase in capital expenditures associated with new customer services, distribution reliability and transmission. This increase was partially offset by $41 million in increased proceeds received from the early termination of certain cross-border energy lease investments.
Financing Activities
Cash flows from financing activities during 2013, 2012 and 2011 are summarized below:
(a) Prior to October 1, 2013, the DRP was named the Shareholder Dividend Reinvestment Plan.
Net cash from financing activities decreased $381 million for the year ended December 31, 2013, compared to the same period in 2012. The decrease was primarily due to a net decrease of $400 million in term loans and an increase of $233 million in short-term debt repayments, partially offset by issuances of common stock of $324 million primarily due to the settlement of the equity forward transaction.
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Net cash from financing activities increased $144 million for the year ended December 31, 2012 compared to the same period in 2011. The increase was due primarily to a $200 million term loan issuance and a $109 million net increase in long-term debt partially offset by a $165 million net decrease in short-term debt issuances.
Common Stock Dividends
Common stock dividend payments were $270 million in 2013, $248 million in 2012, and $244 million in 2011. The increase in common stock dividends paid in 2013 and 2012 was the result of additional shares outstanding, primarily shares issued upon settlement of the equity forward transaction in February 2013 and under the DRP.
Changes in Outstanding Common Stock
PHI issued approximately 1 million shares of common stock in each of 2013, 2012 and 2011 under PHI’s long-term incentive plans.
Under the DRP, PHI issued 1.6 million shares of common stock in 2013, 1.7 million shares of common stock in 2012, and 1.6 million shares of common stock in 2011.
In February 2013, PHI issued 17.9 million shares of common stock pursuant to the settlement of the equity forward transaction discussed above.
Changes in Outstanding Long-Term Debt
Cash flows from issuances and reacquisitions of long-term debt in 2013, 2012 and 2011 are summarized in the tables below:
(a) Consists of Pollution Control Refunding Revenue Bonds (DPL Bonds) issued by the Delaware Economic Development Authority (DEDA) for the benefit of DPL that were purchased by DPL in May 2011. See footnote (b) to the Reacquisitions table below. The DPL Bonds were resold to the public in June 2011. While DPL held the DPL Bonds, they remained outstanding as a contractual matter, but were considered extinguished for accounting purposes. In connection with the resale of the DPL Bonds, the interest rate on the bonds was adjusted from 4.90% to a fixed rate of 0.75%.
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(a) These bonds were secured by an outstanding series of collateral first mortgage bonds issued by the utility, which had maturity dates, optional and mandatory redemption provisions, interest rates and interest payment dates that are identical to the terms of the tax-exempt bonds. The collateral first mortgage bonds were automatically redeemed simultaneously with the redemption of the tax-exempt bonds.
(b) Repurchased by DPL in May 2011 pursuant to a mandatory purchase provision in the indenture for the bonds that was triggered by the expiration of the original interest period for the bonds. The bonds were resold by DPL in June 2011. See footnote (a) to the Issuances table above.
(c) Repurchased by DPL in June 2012 pursuant to a mandatory purchase obligation and then retired.
Tax Exempt Auction Rate and First Mortgage Bond Issuances
During 2013, Pepco issued $250 million of 4.15% first mortgage bonds due March 15, 2043 and $150 million of 4.95% first mortgage bonds due November 15, 2043. These bonds were issued under a Mortgage and Deed of Trust and are secured thereunder by a first lien, subject to certain leases, permitted liens and other exceptions, on substantially all of Pepco’s properties, except for such property excluded from the lien of the Mortgage and Deed of Trust. Net proceeds from the issuance of the 4.15% bonds were used to repay Pepco’s outstanding commercial paper and for general corporate purposes. The net proceeds from the 4.95% bonds were used to repay outstanding commercial paper, including commercial paper issued to repay in full at maturity $200 million of Pepco 4.95% senior notes due November 15, 2013, plus accrued but unpaid interest thereon. The senior notes were secured by a like principal amount of Pepco first mortgage bonds, which under Pepco’s Mortgage and Deed of Trust were deemed to be satisfied with the repayment of the senior notes.
During 2013, DPL issued $300 million of 3.50% first mortgage bonds due November 15, 2023. These bonds were issued under a Mortgage and Deed of Trust and are secured thereunder by a first lien, subject to certain leases, permitted liens and other exceptions, on substantially all of DPL’s properties, except for such property excluded from the lien of the Mortgage and Deed of Trust. The net proceeds from the issuance of the long-term debt were used to repay at maturity $250 million of DPL’s 6.40% first mortgage bonds, plus accrued but unpaid interest thereon, to repay outstanding commercial paper and for general corporate purposes.
During 2012, Pepco issued $200 million of 3.05% first mortgage bonds due April 1, 2022. Net proceeds from the issuance of the long-term debt were used primarily (i) to repay Pepco’s outstanding commercial paper that was issued to temporarily fund capital expenditures and working capital, (ii) to fund the redemption, prior to maturity, of all of the $38.3 million outstanding of the 5.375% pollution control revenue refunding bonds due in 2024 issued by the Industrial Development Authority of the City of Alexandria, Virginia (IDA), on Pepco’s behalf and (iii) for general corporate purposes.
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During 2012, DPL issued $250 million of 4.00% first mortgage bonds due June 1, 2042. Net proceeds from the issuance of the long-term debt were used primarily (i) to repay $215 million of DPL’s outstanding commercial paper that was issued (a) to temporarily fund capital expenditures and working capital and (b) to fund the redemption in June 2012, prior to maturity, of $65.7 million in aggregate principal amount of three series of outstanding tax-exempt pollution control refunding revenue bonds issued by DEDA for DPL’s benefit; (ii) to fund the redemption, prior to maturity, of $31 million of tax-exempt bonds issued by DEDA for DPL’s benefit; and (iii) for general corporate purposes.
In 2011, DPL resold $35 million of Pollution Control Refunding Revenue Bonds (Delmarva Power & Light Company Project) Series 2001C due 2026 (the Series 2001C Bonds). The Series 2001C Bonds were issued for the benefit of DPL in 2001 and were repurchased by DPL on May 2, 2011, pursuant to a mandatory repurchase provision in the indenture for the Series 2001C Bonds triggered by the expiration of the original interest rate period specified by the Series 2001C Bonds. See footnote (b) to the Reacquisitions table above.
In connection with the issuance of the Series 2001C Bonds, DPL entered into a continuing disclosure agreement under which it is obligated to furnish certain information to the bondholders. At the time of the resale, the continuing disclosure agreement was amended and restated to designate the Municipal Securities Rulemaking Board as the sole repository for these continuing disclosure documents. The amendment and restatement of the continuing disclosure agreement did not change the operating or financial data that are required to be provided by DPL under such agreement.
In 2011, ACE issued $200 million of 4.35% first mortgage bonds due April 1, 2021. The net proceeds were used to repay short-term debt and for general corporate purposes.
Tax Exempt Auction Rate and First Mortgage Bond Redemptions
During 2013, Pepco repaid at maturity $200 million of its 4.95% senior notes, which were secured by a like principal amount of Pepco’s first mortgage bonds as previously discussed.
During 2013, DPL repaid at maturity $250 million of its 6.40% first mortgage bonds.
During 2013, ACE repaid at maturity $69 million of its 6.625% non-callable first mortgage bonds. ACE also funded the redemption, prior to maturity, of $4 million of outstanding weekly rate pollution control revenue refunding bonds due 2017, issued by the Pollution Control Financing Authority of Salem County, New Jersey for ACE’s benefit.
During 2012, all of the $38.3 million of the outstanding 5.375% pollution control revenue refunding bonds issued by IDA for Pepco’s benefit were redeemed. In connection with the redemption, Pepco redeemed all of the $38.3 million outstanding of its 5.375% first mortgage bonds due in 2024 that secured the obligations under the pollution control bonds.
During 2012, DPL funded the redemption by DEDA, prior to maturity, of $65.7 million of outstanding tax-exempt pollution control refunding revenue bonds issued by DEDA for DPL’s benefit, as described above. Of the pollution control refunding revenue bonds redeemed, $34.5 million in aggregate principal amount bore interest at 0.75% per year and matured in 2026, $15.0 million in aggregate principal amount bore interest at 1.80% per year and matured in 2025, and $16.2 million in aggregate principal amount bore interest at 2.30% per year and matured in 2028. In connection with such redemption, on June 1, 2012, DPL redeemed, prior to maturity, all of the $34.5 million in aggregate principal amount outstanding of its 0.75% first mortgage bonds due 2026 that secured the obligations under one of the series of pollution control refunding revenue bonds redeemed by DEDA.
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During 2012, DPL redeemed, prior to maturity, $31 million of 5.20% tax-exempt pollution control refunding revenue bonds due 2019, issued by DEDA for DPL’s benefit. Contemporaneously with this redemption, DPL redeemed $31 million of its outstanding 5.20% first mortgage bonds due 2019 that secured the obligations under the pollution control bonds.
During 2012, ACE redeemed, prior to maturity, $4 million of 5.60% tax-exempt pollution control revenue bonds due 2025 issued by the Industrial Pollution Control Financing Authority of Salem County, New Jersey for ACE’s benefit. Contemporaneously with this redemption, ACE redeemed, prior to maturity, $4 million of its outstanding 5.60% first mortgage bonds due 2025 that secured the obligations under the pollution control bonds.
Changes in Short-Term Debt
As of December 31, 2013, PHI had a total of $442 million of commercial paper outstanding as compared to $637 million and $586 million of commercial paper outstanding at December 31, 2012 and 2011, respectively.
On March 28, 2013, PHI entered into a $250 million term loan agreement, pursuant to which PHI had borrowed (and was not permitted to re-borrow) $250 million. PHI used the net proceeds of the loan under the loan agreement to repay its outstanding $200 million term loan made in 2012, and for general corporate purposes. On May 29, 2013, PHI repaid the $250 million term loan with a portion of the net proceeds from the early termination of the cross-border energy lease investments.
Capital Requirements
Capital Expenditures
Pepco Holdings’ capital expenditures for the year ended December 31, 2013 totaled $1,310 million, an increase of $94 million from $1,216 million in 2012. Capital expenditures in 2013 were $576 million for Pepco, $357 million for DPL, $261 million for ACE, $4 million for Pepco Energy Services and $112 million for Corporate and Other. The Power Delivery expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission. Corporate and Other capital expenditures primarily consisted of hardware and software expenditures that will be allocated to Power Delivery when the assets are placed in service.
The table below shows the projected capital expenditures for Power Delivery, Pepco Energy Services and Corporate and Other for the five-year period 2014 through 2018. PHI expects to fund these expenditures through internally generated cash and external financing.
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Transmission and Distribution
The projected capital expenditures listed in the table for distribution (other than the smart grid), transmission and gas delivery are primarily for facility replacements and upgrades to accommodate customer growth and service reliability, including capital expenditures for continuing reliability enhancement efforts. For a more detailed discussion of these efforts, see “General Overview - Power Delivery.”
DOE Capital Reimbursement Awards
In 2009, the U.S. Department of Energy (DOE) announced awards under the American Recovery and Reinvestment Act of 2009 of:
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$105 million and $44 million in Pepco’s Maryland and District of Columbia service territories, respectively, for the implementation of an AMI system, direct load control, distribution automation, and communications infrastructure.
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$19 million in ACE’s New Jersey service territory for the implementation of direct load control, distribution automation, and communications infrastructure.
Of the total $168 million in DOE awards, $130 million is being used for the smart grid and other capital expenditures of Pepco and ACE. The remaining $38 million is being used to offset incremental expenditures associated with direct load control and other Pepco and ACE programs. During 2013, Pepco and ACE received award payments of $30 million and $4 million, respectively. The cumulative award payments received by Pepco and ACE as of December 31, 2013, were $145 million and $17 million, respectively.
The IRS has announced that, to the extent these grants are expended on capital items, they will not be considered taxable income.
Dividends
Pepco Holdings’ annual dividend rate on its common stock is determined by the Board of Directors on a quarterly basis and takes into consideration, among other factors, current and possible future developments that may affect PHI’s income and cash flows. In 2013, PHI’s Board of Directors declared quarterly dividends of 27 cents per share of common stock payable on March 28, 2013, June 28, 2013, September 30, 2013 and December 31, 2013.
On January 23, 2014, the Board of Directors declared a dividend on common stock of 27 cents per share payable March 31, 2014, to shareholders of record on March 10, 2014.
PHI, on a stand-alone basis, generates no operating income of its own. Accordingly, its ability to pay dividends to its shareholders depends on dividends received from its subsidiaries. In addition to their future financial performance, the ability of each of PHI’s direct and indirect subsidiaries to pay dividends is subject to limits imposed by: (i) state corporate laws, which impose limitations on the funds that can be used to pay dividends and when such dividends can be paid, and, in the case of ACE, the regulatory requirement that it obtain the prior approval of the NJBPU before dividends can be paid if its equity as a percent of its total capitalization, excluding securitization debt, falls below 30%; (ii) the prior rights of holders of existing and future mortgage bonds and other long-term debt issued by the subsidiaries, and any preferred stock that may be issued by the subsidiaries in the future, (iii) any other restrictions imposed in connection with the incurrence of liabilities; and (iv) certain provisions of ACE’s charter that impose restrictions on payment of common stock dividends for the benefit of preferred stockholders. None of Pepco, DPL or ACE currently have shares of preferred stock outstanding. Currently, the capitalization ratio limitation to which ACE is subject and the restriction in the ACE charter do not limit ACE’s ability to pay common stock dividends. PHI had approximately $595 million and $1,077 million of retained earnings free of restrictions at December 31, 2013 and 2012, respectively. These amounts represent the total retained earnings balances at those dates.
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Contractual Obligations and Commercial Commitments
Summary information about Pepco Holdings’ consolidated contractual obligations and commercial commitments at December 31, 2013, is as follows:
(a) Includes transition bonds issued by ACE Funding.
(b) Excludes contracts for the purchase of electricity to satisfy Default Electricity Supply load service obligations which have neither a fixed commitment amount nor a minimum purchase amount. In addition, costs are recoverable from customers.
(c) Excludes $606 million of net current and non-current liabilities related to uncertain tax positions due to uncertainty in the timing of the associated cash payments.
Guarantees, Indemnifications and Off-Balance Sheet Arrangements
PHI and certain of its subsidiaries have various financial and performance guarantees and indemnification obligations that they have entered into in the normal course of business to facilitate commercial transactions with third parties.
PHI guarantees the obligations of Pepco Energy Services under certain contracts in its energy savings performance contracting business and underground transmission and distribution construction business. At December 31, 2013, PHI’s guarantees of Pepco Energy Services’ obligations under these contracts totaled $190 million. PHI also guarantees the obligations of Pepco Energy Services under surety bonds obtained by Pepco Energy Services for construction projects in these businesses. These guarantees totaled $229 million at December 31, 2013.
In addition, PHI guarantees certain obligations of Pepco, DPL and ACE under surety bonds obtained by these subsidiaries, for construction projects and self-insured workers compensation matters. These guarantees totaled $29 million at December 31, 2013.
For additional discussion of PHI’s third party guarantees, indemnifications, obligations and off-balance sheet arrangements, see Note (15), “Commitments and Contingencies - Third Party Guarantees, Indemnifications, and Off-Balance Sheet Arrangements,” to the consolidated financial statements of PHI.
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Contractual Arrangements with Credit Rating Triggers or Margining Rights
Under certain contractual arrangements entered into by PHI’s subsidiaries, the subsidiary may be required to provide cash collateral or letters of credit as security for its contractual obligations if the credit ratings of PHI or the subsidiary are downgraded. In the event of a downgrade, the amount required to be posted would depend on the amount of the underlying contractual obligation existing at the time of the downgrade. Based on contractual provisions in effect at December 31, 2013, a downgrade in the unsecured debt credit ratings of PHI and each of its rated subsidiaries to below “investment grade” would increase the collateral obligation of PHI and its subsidiaries by up to $78 million. This amount is attributable primarily to energy services contracts and accounts payable to independent system operators and distribution companies. PHI believes that it and its subsidiaries currently have sufficient liquidity to fund their operations and meet their financial obligations.
Many of the contractual arrangements entered into by PHI’s subsidiaries in connection with Default Electricity Supply activities include margining rights pursuant to which the PHI subsidiary or a counterparty may request collateral if the market value of the contractual obligations reaches levels in excess of the credit thresholds established in the applicable arrangements. Pursuant to these margining rights, the affected PHI subsidiary may receive, or be required to post, collateral due to energy price movements. PHI believes that it and its subsidiaries currently have sufficient liquidity to fund their operations and meet their financial obligations.
Environmental Remediation Obligations
PHI’s accrued liabilities for environmental remediation obligations as of December 31, 2013 totaled approximately $30 million, of which approximately $4 million is expected to be incurred in 2014, for potential environmental cleanup and related costs at sites owned or formerly owned by an operating subsidiary where an operating subsidiary is a potentially responsible party or is alleged to be a third-party contributor. For further information concerning the remediation obligations associated with these sites, see Note (15), “Commitments and Contingencies - Environmental Matters,” to the consolidated financial statements of PHI. The most significant environmental remediation obligations as of December 31, 2013, are for the following items:
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Environmental investigation and remediation costs payable by Pepco with respect to the Benning Road site.
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Amounts payable by Pepco in connection with a January 2011 mineral oil release at Pepco’s Potomac River substation in Alexandria, Virginia.
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Estimated costs for implementation of a closure plan and cap on a Pepco right-of-way that traverses the GenOn MD Ash Management, LLC fly ash disposal site in Brandywine, Prince George’s County, Maryland. PHI and Pepco believe that the costs incurred in this matter will be recoverable from GenOn under a 2000 asset purchase and sale agreement, the terms of which specify that the buyer of Pepco’s generation assets assumed environmental liability for hazardous substances, including ash, which remain on or have been removed from the land on which the acquired generating stations are situated.
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Costs associated with investigation and resolution of potential impacts from a September 2013 mineral oil release from a Pepco underground feeder to Watts Branch.
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Amounts payable by DPL in accordance with a 2001 consent agreement reached with the Delaware Department of Natural Resources and Environmental Control, for remediation, site restoration, natural resource damage compensatory projects and other costs associated with environmental contamination that resulted from an oil release at the Indian River power plant, which DPL sold in June 2001.
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Potential compliance remediation costs under New Jersey’s Industrial Site Recovery Act payable by PHI associated with the retained environmental exposure from the sale of the Conectiv Energy wholesale power generation business.
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Amounts payable by DPL in connection with the Wilmington Coal Gas South site located in Wilmington, Delaware, to remediate residual material from the historical operation of a manufactured gas plant.
Sources of Capital
PHI’s sources to meet its long-term funding needs, such as capital expenditures, dividends, and new investments, and its short-term funding needs, such as working capital and the temporary funding of long-term funding needs, include internally generated funds, issuances by PHI, Pepco, DPL and ACE under their commercial paper programs, securities issuances, medium- and short-term loans, and bank financing under new or existing facilities. PHI’s ability to generate funds from its operations and to access capital and credit markets is subject to risks and uncertainties. Volatile and deteriorating financial market conditions, diminished liquidity and tightening credit may affect access to certain of PHI’s potential funding sources.
Cash Flow from Operations
Cash flow generated by regulated utility subsidiaries in Power Delivery is the primary source of PHI’s cash flow from operations. Additional cash flows are generated by the business of Pepco Energy Services and from the occasional sale of non-core assets.
Short-Term Funding Sources
Pepco Holdings and its regulated utility subsidiaries have traditionally used a number of sources to fulfill short-term funding needs, such as commercial paper, short-term notes and bank term loans and lines of credit. Proceeds from short-term borrowings are used primarily to meet working capital needs but may also be used to temporarily fund long-term capital requirements. For additional discussion of PHI’s short-term debt, see Note (10), “Debt,” to the consolidated financial statements of PHI.
Long-Term Funding Sources
The sources of long-term funding for PHI and its subsidiaries are the issuance of debt and equity securities and borrowing under long-term credit agreements. Proceeds from long-term financings are used primarily to fund long-term capital requirements, such as capital expenditures and new investments, and to repay or refinance existing indebtedness.
Regulatory Restrictions on Financing Activities
The issuance of debt securities by PHI’s principal subsidiaries requires the approval of either FERC or one or more state public utility commissions. Neither FERC approval nor state public utility commission approval is required as a condition to the issuance of securities by PHI.
State Financing Authority
Pepco’s long-term financing activities (including the issuance of securities and the incurrence of long-term debt) are subject to authorization by the DCPSC and MPSC. DPL’s long-term financing activities are subject to authorization by the MPSC and the DPSC. ACE’s long-term and short-term (consisting of debt instruments with a maturity of one year or less) financing activities are subject to authorization by the NJBPU. Each utility, through periodic filings with the state public service commission(s) having jurisdiction over its financing activities, has maintained standing authority sufficient to cover its projected financing needs over a multi-year period.
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FERC Financing Authority
Under the Federal Power Act (FPA), FERC has jurisdiction over the issuance of long-term and short-term securities of public utilities, but only if the issuance is not regulated by the state public utility commission in which the public utility is organized and operating. Under these provisions, FERC has jurisdiction over the issuance of short-term debt by Pepco and DPL. Pepco and DPL have obtained FERC authority for the issuance of short-term debt. Because Pepco Energy Services also qualifies as a public utility under the FPA and is not regulated by a state utility commission, FERC also has jurisdiction over the issuance of securities by Pepco Energy Services. Pepco Energy Services has obtained the requisite FERC financing authority in its market-based rate orders.
Money Pool
Pepco Holdings operates a system money pool under a blanket authorization adopted by FERC. The money pool is an unsecured cash management mechanism used by Pepco Holdings to manage the short-term investment and borrowing requirements of its subsidiaries that participate in the money pool. Pepco Holdings may invest in but not borrow from the money pool. Eligible subsidiaries with surplus cash may deposit those funds in the money pool. Deposits in the money pool are guaranteed by Pepco Holdings. Eligible subsidiaries with cash requirements may borrow from the money pool. Depositors in the money pool receive, and borrowers from the money pool pay, an interest rate based primarily on Pepco Holdings’ short-term borrowing rate. Pepco Holdings deposits funds in the money pool to the extent that the pool has insufficient funds to meet the borrowing needs of its participants, which may require Pepco Holdings to borrow funds for deposit from external sources.
Regulatory and Other Matters
Rate Proceedings
Distribution
The rates that each of Pepco, DPL and ACE is permitted to charge for the retail distribution of electricity and natural gas to its various classes of customers are based on the principle that the utility is entitled to generate an amount of revenue sufficient to recover the cost of providing the service, including a reasonable rate of return on its invested capital. These “base rates” are intended to cover all of each utility’s reasonable and prudent expenses of constructing, operating and maintaining its distribution facilities (other than costs covered by specific cost-recovery surcharges).
A change in base rates in a jurisdiction requires the approval of the public service commission. In the rate application submitted to the public service commission, the utility specifies an increase in its “revenue requirement,” which is the additional revenue that the utility is seeking authorization to earn. The “revenue requirement” consists of (i) the allowable expenses incurred by the utility, including operation and maintenance expenses, taxes and depreciation, and (ii) the utility’s cost of capital. The compensation of the utility for its cost of capital takes the form of an overall “rate of return” allowed by the public service commission on the utility’s distribution “rate base” to compensate the utility’s investors for their debt and equity investments in the company. The rate base is the aggregate value of the investment in property used by the utility in providing electricity and natural gas distribution services and generally consists of plant in service net of accumulated depreciation and accumulated deferred taxes, plus cash working capital, material and operating supplies and, depending on the jurisdiction, construction work in progress. Over time, the rate base is increased by utility property additions and reduced by depreciation and property retirements and write-offs.
In addition to its base rates, some of the costs of providing distribution service are recovered through the operation of surcharges. Examples of costs recovered by PHI’s utility subsidiaries through surcharges, which vary depending on the jurisdiction, include: a surcharge to reimburse the utility for the cost of purchasing electricity from NUGs (New Jersey); surcharges to reimburse the utility for costs of public interest programs for low income customers and for demand-side management programs (New Jersey,
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Maryland, Delaware and the District of Columbia); a surcharge to pay the Transitional Bond Charge (New Jersey); surcharges to reimburse the utility for certain environmental costs (Delaware and Maryland); and surcharges related to the BSA (Maryland and the District of Columbia). Each utility subsidiary regularly reviews its distribution rates in each jurisdiction of its service territory, and files applications to adjust its rates as necessary in an effort to ensure that its revenues are sufficient to cover its operating expenses and its cost of capital. The timing of future rate filings and the change in the distribution rate requested will depend on a number of factors, including changes in revenues and expenses and the incurrence or the planned incurrence of capital expenditures. PHI’s utility subsidiaries currently plan to, among other things, file electric distribution base rate cases every 9 to 12 months and evaluate potential reductions in planned capital expenditures in an effort to mitigate the effects of regulatory lag. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations - General Overview - Power Delivery Initiatives and Activities - Mitigation of Regulatory Lag.”
In general, a request for new distribution rates is made on the basis of “test year” balances for rate base allowable operating expenses and a requested rate of return. The test year amounts used in the filing may be historical or partially projected. The public service commission may, however, select a different test period than that proposed by the applicable utility. Although the approved tariff rates are intended to be forward-looking, and therefore provide for the recovery of some future changes in rate base and operating costs, they typically do not reflect all of the changes in costs for the period in which the new rates are in effect.
The following table shows, for each of the PHI utility subsidiaries, the authorized return on equity as determined in the most recently concluded base rate proceeding and the effective date of the authorized return:
(a) ROE has not been determined by any proceeding and is specified only for the purposes of calculating the AFUDC and regulatory asset carrying costs.
(b) ROE has not been determined by any proceeding and is specified only for reporting purposes and for calculating the AFUDC, construction work in progress (CWIP), regulatory asset carrying costs and other accounting metrics.
Transmission
The rates Pepco, DPL and ACE are permitted to charge for the transmission of electricity are regulated by FERC and are based on each utility’s transmission rate base, transmission operating expenses and an overall rate of return that is approved by FERC. For each utility subsidiary, FERC has approved a formula for the calculation of the utility transmission rate, which is referred to as a “formula rate.” The formula rates include both fixed and variable elements. Certain of the fixed elements, such as the return on equity
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and depreciation rates, can be changed only in a FERC transmission rate proceeding. The variable elements of the formula, including the utility’s rate base and operating expenses, are updated annually, effective June 1 of each year, with data from the utility’s most recent annual FERC Form 1 filing. In addition to its formula rate, each utility’s return on equity is supplemented by incentive rates, sometimes referred to as “adders,” and other incentives, which are authorized by FERC to promote capital investment in transmission infrastructure. 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 PHI’s utilities 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. In addition, ROE adders are in effect for each of Pepco, DPL and ACE relating to specific transmission upgrades and improvements, as well as in consideration for each utility’s continued membership in PJM. As members of PJM, the transmission rates of Pepco, DPL and ACE are set out in PJM’s Open Access Transmission Tariff.
For a discussion of pending state public utility commission and FERC transmission rate and other regulatory proceedings, see Note (7), “Regulatory Matters,” to the consolidated financial statements of PHI.
Legal Proceedings and Regulatory Matters
For a discussion of legal proceedings, see Note (15), “Commitments and Contingencies,” to the consolidated financial statements of PHI, and for a discussion of regulatory matters, see Note (7), “Regulatory Matters,” to the consolidated financial statements of PHI.
Critical Accounting Policies
General
PHI has identified the following critical accounting policies that result in having to make certain estimates that, as a result of the judgments, uncertainties, uniqueness and complexities of the underlying accounting standards and estimates involved, could result in material changes in its financial condition or results of operations under different conditions or using different assumptions. PHI has discussed the development, selection and disclosure of each of these policies with the Audit Committee of the Board of Directors.
Goodwill Impairment Evaluation
Substantially all of PHI’s goodwill was generated by Pepco’s acquisition of Conectiv in 2002 and is allocated entirely to the Power Delivery reporting unit for purposes of assessing impairment under FASB guidance on goodwill and other intangibles (ASC 350). PHI has identified Power Delivery as a single reporting unit because its components have similar economic characteristics, similar products and services, similar distribution methods and support processes, and operate in a similar regulatory environment.
PHI tests its goodwill for impairment annually as of November 1 and whenever an event occurs or circumstances change in the interim that would more likely than not (that is, a greater than 50% chance) reduce the estimated fair value of a reporting unit below the carrying amount of its net assets.
Factors that may result in an interim impairment test include, but are not limited to: an adverse change in business conditions; a protracted decline in stock price causing market capitalization to fall significantly below book value; an adverse regulatory action; impairment of long-lived assets in the reporting unit; or a change in identified reporting units.
The first step of the goodwill impairment test compares the estimated fair value of the reporting unit with its carrying amount, including goodwill. PHI uses its best judgment to make reasonable projections of future cash flows and selection of a discount rate for the associated risk with those cash flows when
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estimating the reporting unit’s fair value. These judgments are inherently uncertain, and actual results could vary from those used in PHI’s estimates. The impact of such variations could significantly alter the results of a goodwill impairment test, which could materially impact the estimated fair value of Power Delivery and potentially the amount of any impairment recorded in the financial statements.
PHI’s November 1, 2013 annual impairment test indicated that its goodwill was not impaired. See Note (6), “Goodwill,” to the consolidated financial statements of PHI.
In order to estimate the fair value of the Power Delivery reporting unit, PHI prepares an analysis of traditional valuation techniques: an income approach and a market approach. The income approach estimates fair value based on a discounted future cash flow analysis and a terminal value that is consistent with Power Delivery’s long-term view of the business. This approach uses a discount rate based on the estimated weighted average cost of capital (WACC) for the reporting unit. PHI determines the estimated WACC by considering appropriate market-based information for the cost of equity and cost of debt as of the measurement date. The market approach estimates fair value based on a multiple of earnings before interest, taxes, depreciation, and amortization (EBITDA) that PHI believes is consistent with EBITDA multiples for comparable utilities. PHI has consistently used this valuation technique to estimate the fair value of Power Delivery.
The estimation of fair value is dependent on a number of factors including but not limited to interest rates, growth assumptions, returns on rate base, operating and capital expenditure requirements, and other factors, changes in which could materially impact the results of impairment testing. Assumptions used were consistent with historical experience, including assumptions concerning the recovery of operating costs and capital expenditures, and current market-based information. A hypothetical 10 percent decrease in estimated fair value of the Power Delivery reporting unit at November 1, 2013 would not have resulted in the Power Delivery reporting unit failing the first step of the impairment test, as defined in the guidance, as the estimated fair value of the reporting unit would have been above its carrying value. Sensitive, interrelated and uncertain variables that could decrease the estimated fair value of the Power Delivery reporting unit include utility sector market performance, sustained adverse business conditions, change in forecasted revenues, higher operating and maintenance capital expenditure requirements, a significant increase in the weighted average cost of capital, and other factors.
PHI believes that the estimates involved in its goodwill impairment evaluation process represent “Critical Accounting Estimates” because they are subjective and susceptible to change from period to period as PHI makes assumptions and judgments, and the impact of a change in such assumptions and estimates could be material to financial results.
Long-Lived Assets Impairment Evaluation
PHI believes that the estimates involved in its long-lived asset impairment evaluation process represent “Critical Accounting Estimates” because (i) they are highly susceptible to change from period to period because PHI is required to make assumptions and judgments about when events indicate the carrying value may not be recoverable and how to estimate undiscounted and discounted future cash flows and fair values, which are inherently uncertain, (ii) actual results could vary from those used in PHI’s estimates and the impact of such variations could be material, and (iii) the impact that recognizing an impairment would have on PHI’s assets as well as the net loss related to an impairment charge could be material. The primary assets subject to a long-lived asset impairment evaluation are property, plant, and equipment.
The FASB guidance on the accounting for the impairment or disposal of long-lived assets (ASC 360), requires that certain long-lived assets must be tested for recoverability whenever events or circumstances indicate that the carrying amount may not be recoverable, such as (i) a significant decrease in the market price of a long-lived asset or asset group, (ii) a significant adverse change in the extent or manner in which a long-lived asset or asset group is being used or in its physical condition, (iii) a significant adverse change in legal factors or in the business climate, including an adverse action or assessment by a regulator, (iv) an accumulation of costs significantly in excess of the amount originally expected for the
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acquisition or construction of a long-lived asset or asset group, (v) a current-period operating or cash flow loss combined with a history of operating or cash flow losses or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset or asset group, and (vi) a current expectation that, more likely than not, a long-lived asset or asset group will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.
An impairment loss may only be recognized if the carrying amount of an asset is not recoverable and the carrying amount exceeds its estimated fair value. The asset is deemed not to be recoverable when its carrying amount exceeds the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset. PHI uses reasonable estimates in making these evaluations of an asset’s future cash flows and considers various factors, including forward price curves for energy, related fuel costs, legislative initiatives, operating costs, and historical cash flows.
Accounting for Derivatives
PHI believes that the estimates involved in accounting for its derivative instruments represent “Critical Accounting Estimates” because PHI exercises judgment in the following areas, any of which could have a material impact on its financial statements: (i) the application of the definition of a derivative to contracts to identify embedded or free-standing derivatives, (ii) the election of the normal purchases and normal sales exception from derivative accounting, (iii) the application of cash flow hedge accounting, and (iv) the estimation of fair value used in the measurement of derivatives and hedged items, which are highly susceptible to changes in value over time due to market trends or, in certain circumstances, significant uncertainties in modeling techniques used to measure fair value that could result in actual results being materially different from PHI’s estimates. See Note (2), “Significant Accounting Policies - Accounting for Derivatives,” and Note (13), “Derivative Instruments and Hedging Activities,” to the consolidated financial statements of PHI.
PHI and its subsidiaries may use derivative instruments primarily to manage risk associated with commodity prices and interest rates. The definition of a derivative in the FASB guidance on derivatives (ASC 815) results in PHI having to exercise judgment, such as whether there is a notional amount or net settlement provision in contracts. PHI assesses a number of factors before determining whether it can designate derivatives for the normal purchase or normal sale exception from derivative accounting, including whether it is probable that the contracts will physically settle with delivery of the underlying commodity. The application of cash flow hedge accounting often requires judgment in the prospective and retrospective assessment and measurement of hedge effectiveness as well as whether it is probable that the forecasted transaction will occur. The fair value of derivatives is determined using quoted exchange prices where available. For instruments that are not traded on an exchange, external broker quotes may also be used to determine fair value. For some custom and complex instruments, internal models use market-based information when external broker quotes are not available. For certain long-dated instruments, broker or exchange data are extrapolated, or capacity prices are forecasted, for future periods where information is limited. Models are also used to estimate volumes for certain transactions. The same valuation methods are used for risk management purposes to determine the value of non-derivative, commodity exposure.
Pension and Other Postretirement Benefit Plans
PHI believes that the estimates involved in reporting the costs of providing pension and OPEB benefits represent Critical Accounting Estimates because (i) they are based on an actuarial calculation that includes a number of assumptions which are subjective in nature, (ii) they are dependent on numerous factors resulting from actual plan experience and assumptions of future experience, and (iii) changes in assumptions could impact PHI’s expected future cash funding requirements for the benefit plans and would have an impact on the benefit obligations, which affect the reported amount of net periodic pension and OPEB cost on the consolidated income statement.
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Assumptions about the future, including the discount rate applied to benefit obligations, the expected long-term rate of return on plan assets, the anticipated rate of increase in health care costs, average remaining service period and life expectancy, and participant compensation have a significant impact on net periodic pension and OPEB costs.
The discount rate for determining the pension benefit obligation was 5.05% and 4.15% as of December 31, 2013 and 2012, respectively. The discount rate for determining the postretirement benefit obligation was 5.00% and 4.10% as of December 31, 2013 and 2012, respectively. PHI utilizes an analytical tool developed by its actuaries to select the discount rate. The analytical tool utilizes a high-quality bond portfolio with cash flows that match the benefit payments expected to be made under the plans.
The expected long-term rate of return on pension and postretirement benefit plan assets used to determine net periodic pension and OPEB cost was 7.00% and 7.25% for 2013 and 2012, respectively. PHI uses a building block approach to estimate the expected rate of return on plan assets. Under this approach, the percentage of plan assets in each asset class according to PHI’s target asset allocation, at the measurement date of net periodic cost, is applied to the expected asset return for the related asset class. PHI incorporates long-term assumptions for real returns, inflation expectations, volatility, and correlations among asset classes to determine expected returns for the related asset class. The pension and postretirement benefit plan assets consist of equity, fixed income, real estate and private equity investments.
The average remaining service periods for participating employees of the benefit plans was approximately 11 years for both 2013 and 2012. PHI utilizes plan census data to estimate these average remaining service periods. PHI uses the IRS prescribed mortality tables to estimate the average life expectancy. The IRS prescribed tables for 2013 and 2012 were used to determine net periodic pension and OPEB cost for the same respective years. The tables for 2014 and 2013 were used for determining the benefit obligations as of December 31, 2013 and 2012, respectively.
The following table reflects the effect on the projected benefit obligation for the pension plans and the accumulated benefit obligation for the OPEB plan, as well as the net periodic cost, if there were changes in these critical actuarial assumptions while holding all other actuarial assumptions constant:
(a) The impact on benefit obligation and the projected increase in 2013 net periodic cost were determined assuming that the plan amendments that were effective July 1, 2013 were put into effect on January 1, 2014.
The impact of changes in assumptions and the difference between actual and expected or estimated results on pension and postretirement benefit obligations is generally recognized over the average remaining service period of the employees who benefit under the plans rather than immediate recognition in the statement of income.
For additional discussion, see Note (9), “Pension and Other Postretirement Benefits,” to the consolidated financial statements of PHI.
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Accounting for Regulated Activities
FASB guidance on the accounting for regulated operations (ASC 980), applies to Power Delivery and can result in the deferral of costs or revenue that would otherwise be recognized by non-regulated entities. PHI defers the recognition of costs and records regulatory assets when it is probable that those costs will be recovered in future customer rates. PHI defers the recognition of revenues and records regulatory liabilities when it is probable that it will refund payments received from customers in the future or that it will incur future costs related to the payments currently received from customers. PHI believes that the judgments involved in accounting for its regulated operations represent “Critical Accounting Estimates” because (i) PHI must interpret laws and regulatory commission orders to assess the probability of the recovery of costs in customer rates or the return of revenues to customers when determining whether those costs or revenues should be deferred, (ii) decisions made by regulatory commissions or legislative changes at a later date could vary from earlier interpretations made by PHI and the impact of such variations could be material, and (iii) the elimination of a regulatory asset because deferred costs are no longer probable of recovery in future customer rates could have a material negative impact on PHI’s assets and earnings.
PHI’s most significant judgment is whether to defer costs or revenues when there is not a current regulatory order specific to the item being considered for deferral. In those cases, PHI considers relevant historical precedents of the regulatory commissions, the results of recent rate orders, and any new information from its more current interactions with the regulatory commissions on that item. PHI regularly evaluates whether it should defer costs or revenues and reviews whether adjustments to its previous conclusions regarding its regulatory assets and liabilities are necessary based on the current regulatory and legislative environment as well as recent rate orders.
For additional discussion, see Note (7), “Regulatory Matters,” to the consolidated financial statements of PHI.
Unbilled Revenue
Unbilled revenue represents an estimate of revenue earned from services rendered by PHI’s utility operations that have not yet been billed. PHI’s utility operations calculate unbilled revenue using an output-based methodology. The calculation is based on the supply of electricity or natural gas distributed to customers but not yet billed, adjusted for estimated line losses (estimates of electricity and gas expected to be lost in the process of a utility’s transmission and distribution to customers).
PHI estimates involved in its unbilled revenue process represent “Critical Accounting Estimates” because PHI is required to make assumptions and judgments about factors to the unbilled revenue calculation. Specifically, the determination of estimated line losses is inherently uncertain. Estimated line losses is defined as the estimates of electricity and natural gas expected to be lost in the process of its transmission and distribution to customers. A change in estimated line losses can change the output available for sale which is a factor in the unbilled revenue calculation. Certain factors can influence the estimated line losses such as weather and a change in customer mix. These factors may vary between companies due to geography and density of service territory, and the impact of changes in these factors could be material. PHI seeks to reduce the risk of an inaccurate estimate of unbilled revenue through corroboration of the estimate with historical information and other output-based observable metrics.
Accounting for Income Taxes
PHI exercises significant judgment about the outcome of income tax matters in its application of the FASB guidance on accounting for income taxes (ASC 740) and believes it represents a “Critical Accounting Estimate” because: (i) it records a current tax liability for estimated current tax expense on its federal and state tax returns; (ii) it records deferred tax assets for temporary differences between the financial statement and tax return determination of pre-tax income and the carrying amount of assets and liabilities that are more likely than not going to result in tax deductions in future years; (iii) it determines
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whether a valuation allowance is needed against deferred tax assets if it is more likely than not that some portion of the future tax deductions will not be realized; (iv) it records deferred tax liabilities for temporary differences between the financial statement and tax return determination of pre-tax income and the carrying amount of assets and liabilities if it is more likely than not that they are expected to result in tax payments in future years; (v) the measurement of deferred tax assets and deferred tax liabilities requires it to estimate future effective tax rates and future taxable income on its federal and state tax returns; (vi) it must consider the effect of newly enacted tax law on its estimated effective tax rate and in measuring deferred tax balances; and (vii) it asserts that tax positions in its tax returns or expected to be taken in its tax returns are more likely than not to be sustained assuming that the tax positions will be examined by taxing authorities with full knowledge of all relevant information prior to recording the related tax benefit in the financial statements.
Assumptions, judgment and the use of estimates are required in determining if the more-likely-than-not measurement threshold (that is, the cumulative result for a greater than 50% chance of being realized) has been met when developing the provision for current and deferred income taxes and the associated current and deferred tax assets and liabilities. PHI’s assumptions, judgments and estimates take into account current tax laws and regulations, interpretation of current tax laws and regulations, the impact of newly enacted tax laws and regulations, developments in case law, settlements of tax positions, and the possible outcomes of current and future investigations conducted by tax authorities. PHI has established reserves for income taxes to address potential exposures involving tax positions that could be challenged by tax authorities. Although PHI believes that these assumptions, judgments and estimates are reasonable, changes in tax laws and regulations or its interpretation of tax laws and regulations as well as the resolutions of the current and any future investigations or legal proceedings could significantly impact the financial results from applying the accounting for income taxes in the consolidated financial statements. PHI reviews its application of the more-likely-than-not measurement threshold quarterly.
PHI also evaluates quarterly the probability of realizing deferred tax assets by reviewing a forecast of future taxable income and prudent and feasible tax planning strategies that can be implemented, if necessary, to realize deferred tax assets. Failure to achieve forecasted taxable income or successfully implement tax planning strategies may affect the realization of deferred tax assets and the amount of any associated valuation allowance. The forecast of future taxable income is dependent on a number of factors that can change over time, including growth assumptions, business conditions, returns on rate base, operating and capital expenditures, cost of capital, tax laws and regulations, the legal structure of entities and other factors, which could materially impact the realizability of deferred tax assets and the associated financial results in the consolidated financial statements.
New Accounting Standards and Pronouncements
For information concerning new accounting standards and pronouncements that have recently been adopted, or will be required to be adopted in the future, by PHI and its subsidiaries , see Note (3), “Newly Adopted Accounting Standards,” and Note (4), “Recently Issued Accounting Standards, Not Yet Adopted,” to the consolidated financial statements of PHI.
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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Potomac Electric Power Company
Pepco meets the conditions set forth in General Instruction I(1)(a) and (b) to Form 10-K, and accordingly information otherwise required under this Item has been omitted in accordance with General Instruction I(2)(a) to Form 10-K.
General Overview
Pepco is engaged in the transmission and distribution of electricity in the District of Columbia and major portions of Prince George’s County and Montgomery County in suburban Maryland. Pepco also provides Default Electricity Supply. Pepco’s service territory covers approximately 640 square miles and, as of December 31, 2013, had a population of approximately 2.2 million. As of December 31, 2013, approximately 57% of delivered electricity sales were to Maryland customers and approximately 43% were to District of Columbia customers.
Pepco’s results historically have been seasonal, generally producing higher revenue and income in the warmest and coldest periods of the year. For retail customers of Pepco in Maryland and in the District of Columbia, revenue is not affected by unseasonably warmer or colder weather because a BSA for retail customers was implemented that provides for a fixed distribution charge per customer rather than a charge based on energy usage. The BSA has the effect of decoupling the distribution revenue recognized in a reporting period from the amount of power delivered during the period. As a result, the only factors that will cause distribution revenue from customers in Maryland and the District of Columbia to fluctuate from period to period are changes in the number of customers and changes in the approved distribution charge per customer. Changes in customer usage (due to weather conditions, energy prices, energy savings programs or other reasons) from period to period have no impact on reported distribution revenue for customers to whom the BSA applies.
In accounting for the BSA in Maryland and the District of Columbia, a Revenue Decoupling Adjustment is recorded representing either (i) a positive adjustment equal to the amount by which revenue from Maryland and District of Columbia retail distribution sales falls short of the revenue that Pepco is entitled to earn based on the approved distribution charge per customer or (ii) a negative adjustment equal to the amount by which revenue from such distribution sales exceeds the revenue that Pepco is entitled to earn based on the approved distribution charge per customer.
Pepco is a wholly owned subsidiary of PHI. Because PHI is a public utility holding company subject to the Public Utility Holding Company Act of 2005 (PUHCA 2005), the relationship between each of PHI, PHI Service Company (a subsidiary service company of PHI, which provides a variety of support services, including legal, accounting, treasury, tax, purchasing and information technology services to PHI and its operating subsidiaries) and Pepco, as well as certain activities of Pepco, are subject to FERC’s regulatory oversight under PUHCA 2005.
Utility Capital Expenditures
Pepco devotes a substantial portion of its total capital expenditures to improving the reliability of its electrical transmission and distribution systems and replacing aging infrastructure throughout its service territories. These activities include one or more of the following:
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identifying and upgrading under-performing feeder lines;
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adding new facilities to support load;
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installing distribution automation systems on both the overhead and underground network systems; and
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rejuvenating and replacing underground residential cables.
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Pepco’s capital expenditures for continuing reliability enhancement efforts are included in the table of projected capital expenditures within “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Capital Requirements - Capital Expenditures.”
Smart Grid
Pepco is building a “smart grid” which is designed to meet the challenges of rising energy costs, improve service reliability of the energy distribution system, provide timely and accurate customer information and address government energy reduction goals. For a discussion of the smart grid, see PHI’s “Management’s Discussion and Analysis of Financial Condition and Results of Operations - General Overview - Power Delivery Initiatives and Activities - Smart Grid.”
Mitigation of Regulatory Lag
An important factor in the ability of Pepco to earn its authorized ROE is the willingness of the DCPSC and the MPSC to adequately address the shortfall in revenues in Pepco’s rate structure due to the delay in time or “lag” between when costs are incurred and when they are reflected in rates. This delay is commonly known as “regulatory lag.” Pepco is currently experiencing significant regulatory lag because investments in rate base and operating expenses are increasing more rapidly than revenue growth. For a more detailed discussion of regulatory lag, see PHI’s “Management’s Discussion and Analysis of Financial Condition and Results of Operations - General Overview - Power Delivery Initiatives and Activities - Mitigation of Regulatory Lag.”
MAPP Project
On August 24, 2012, the board of PJM terminated the MAPP project and removed it from PJM’s regional transmission expansion plan. Pepco had been directed to construct MAPP, a 152-mile high-voltage interstate transmission line, to address the reliability needs of the region’s transmission system. In December 2012, Pepco submitted a filing to FERC seeking recovery of approximately $50 million of abandoned MAPP costs over a five-year period. 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.
In February 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.
In December 2013, Pepco submitted a settlement agreement to FERC with respect to this matter. Under the terms of the proposed settlement agreement, Pepco would recover its abandoned MAPP costs over a three-year recovery period beginning June 1, 2013. The settlement agreement, which is subject to FERC approval, would resolve all issues concerning the recovery of abandonment costs associated with the cancellation of the MAPP project. The terms of this settlement, if approved, would not be subject to the pending formula rate or transmission ROE challenges at FERC or modification through any other FERC proceeding. Pepco cannot predict the timing or results of a final FERC decision in this proceeding.
As of December 31, 2013, Pepco had a regulatory asset related to MAPP abandoned costs of $37 million, representing the original filing amount of approximately $50 million of abandoned costs less: (i) approximately $1 million of disallowed costs written off in 2013; (ii) $4 million of materials transferred to inventories for use on other projects; and (iii) $8 million of amortization expense recorded in 2013. The regulatory asset balance includes the costs of land, land rights, engineering and design, environmental services, and project management and administration.
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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, among others. 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 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. Pepco cannot predict when a final FERC decision in this proceeding will be issued.
Earnings Overview
Net Income For the Year Ended December 31, 2013 Compared to the Year Ended December 31, 2012
Pepco’s net income for the year ended December 31, 2013 was $150 million compared to $126 million for the year ended December 31, 2012. The $24 million increase in earnings was primarily due to the following:
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An increase of $24 million from electric distribution base rate increases in the District of Columbia and Maryland.
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An increase of $7 million due to lower operation and maintenance expense, primarily associated with higher storm restoration and system maintenance in 2012, partially offset by recovery in 2012 of 2011 storm restoration costs and regulatory expenses.
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An increase of $2 million due to customer growth and other distribution revenue increases.
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An increase of $2 million due to higher transmission revenue attributable to higher rates related to increases in transmission plant investment.
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A decrease of $8 million due to lower tax benefits related to uncertain and effectively settled tax positions.
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A decrease of $5 million due to higher interest expense resulting from an increase in outstanding debt.
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Results of Operations
The following results of operations discussion compares the year ended December 31, 2013 to the year ended December 31, 2012. All amounts in the tables (except sales and customers) are in millions of dollars.
A condensed summary of Pepco’s statement of income for the year ended December 31, 2013 compared to the year ended December 31, 2012, is set forth in the table below:
Operating Revenue
The table above shows the amount of Operating Revenue earned that is subject to price regulation (Regulated T&D Electric Revenue and Default Electricity Supply Revenue) and that which is not subject to price regulation (Other Electric Revenue).
Regulated T&D Electric Revenue includes revenue from the distribution of electricity, including the distribution of Default Electricity Supply, to Pepco’s customers within its service territories at regulated rates. Regulated T&D Electric Revenue also includes transmission service revenue that Pepco receives as a transmission owner from PJM at rates regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.
The costs related to Default Electricity Supply are included in Purchased Energy. Default Electricity Supply Revenue also includes transmission enhancement credits that Pepco receives as a transmission owner from PJM in consideration for approved regional transmission expansion plan expenditures.
Other Electric Revenue includes work and services performed on behalf of customers, including other utilities, which is generally not subject to price regulation. Work and services includes mutual assistance to other utilities, highway relocation, rentals of pole attachments, late payment fees and collection fees.
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Regulated T&D Electric
Regulated T&D Electric Revenue increased by $56 million primarily due to:
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An increase of $41 million due to distribution rate increases in the District of Columbia effective October 2012 and in Maryland effective July 2012 and July 2013.
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An increase of $10 million in transmission revenue rates effective June 1, 2012 and June 1, 2013 related to increases in transmission plant investment and operating expenses.
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An increase of $8 million in transmission revenue related to the recovery of MAPP abandonment costs, as approved by FERC (which is offset in Depreciation and Amortization).
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An increase of $4 million in transmission revenue primarily attributable to higher capacity as a result of expanding Maryland demand side management programs (which is partially offset in Depreciation and Amortization).
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An increase of $2 million due to customer growth in 2013, primarily in the residential class.
The aggregate amount of these increases was partially offset by:
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A decrease of $7 million in transmission revenue associated with the change in FERC formula rate true-ups.
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A decrease of $4 million in distribution revenue due to lower pass-through revenue (which is substantially offset by a corresponding decrease in Other Taxes) primarily the result of a decrease in utility taxes collected by Pepco on behalf of Montgomery County, Maryland.
Default Electricity Supply
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Default Electricity Supply Revenue increased by $23 million primarily due to:
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An increase of $27 million as a result of higher Default Electricity Supply rates.
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An increase of $5 million primarily due to higher revenue from transmission enhancement credits.
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An increase of $2 million due to higher sales, primarily as a result of colder weather during the 2013 fall months, as compared to 2012.
The aggregate amount of these increases was partially offset by a decrease of $11 million due to lower sales, primarily as a result of customer migration to competitive suppliers.
The following table shows the percentages of Pepco’s total distribution sales by jurisdiction that are derived from customers receiving Default Electricity Supply from Pepco. Amounts are for the year ended December 31:
Operating Expenses
Purchased Energy
Purchased Energy consists of the cost of electricity purchased by Pepco to fulfill its Default Electricity Supply obligation and, as such, is recoverable from customers in accordance with the terms of public service commission orders. Purchased Energy increased by $24 million to $750 million in 2013 from $726 million in 2012 primarily due to:
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An increase of $33 million due to higher average electricity costs under Default Electricity Supply contracts.
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An increase of $2 million due to higher electricity sales primarily as a result of colder weather during the 2013 fall months, as compared to 2012.
The aggregate amount of these increases was partially offset by a decrease of $11 million primarily due to customer migration to competitive suppliers.
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Other Operation and Maintenance
Other Operation and Maintenance expense decreased by $12 million to $391 million in 2013 from $403 million in 2012 primarily due to:
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A decrease of $10 million associated with lower maintenance and tree trimming costs.
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A decrease of $7 million in other storm restoration costs.
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A decrease of $4 million in customer service costs.
The aggregate amount of these decreases was partially offset by:
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An increase of $4 million primarily due to 2012 total incremental storm restoration costs for major storm events as described in the following table:
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In January 2011, Pepco incurred incremental storm restoration costs of $10 million associated with a severe winter storm, all of which were expensed in 2011. In July 2012, the MPSC issued an order allowing for the deferral and recovery of $9 million of such costs over a five-year period.
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During 2012, Pepco incurred incremental storm restoration costs of $22 million associated with the June 2012 derecho which resulted in widespread damage to the electric distribution system in each of Pepco’s service territories. Pepco deferred $19 million of these costs as a regulatory asset to reflect the probable recovery of these storm restoration costs in Maryland. The MPSC approved the recovery of these costs for Pepco in its July 2013 rate order over a five-year period. The remaining costs of $3 million relate to repair work completed in the District of Columbia which are not deferrable.
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In the fourth quarter of 2012, Pepco incurred incremental storm restoration costs of $6 million associated with Hurricane Sandy which resulted in widespread damage to the electric distribution system in each of Pepco’s service territories. Pepco deferred $4 million of these costs as regulatory assets to reflect the probable recovery of these storm restoration costs in Maryland. The MPSC approved the recovery of these costs for Pepco in its July 2013 rate order over a five-year period. The remaining costs of $2 million relate to repair work completed in the District of Columbia which are not deferrable.
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An increase of $3 million in environmental remediation costs.
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An increase of $1 million associated with the write-off of disallowed MAPP costs.
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Depreciation and Amortization
Depreciation and Amortization expense increased by $6 million to $196 million in 2013 from $190 million in 2012 primarily due to:
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An increase of $8 million in amortization of MAPP abandonment costs (which is offset in Regulated T&D Electric Revenue).
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An increase of $4 million in amortization of regulatory assets primarily related to recoverable major storm costs and rate case costs.
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An increase of $2 million associated with expanding Maryland demand side management programs (which is offset in Regulated T&D Electric Revenue).
The aggregate amount of these increases was partially offset by:
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A decrease of $5 million primarily due to lower depreciation rates, partially offset by plant additions.
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A decrease of $3 million in amortization of software related to AMI projects.
Other Taxes
Other Taxes decreased by $4 million to $368 million in 2013 from $372 million in 2012. The decrease was primarily due to decreases in the Montgomery County, Maryland utility taxes that are collected and passed through by Pepco (substantially offset by a corresponding decrease in Regulated T&D Electric Revenue).
Other Income (Expenses)
Other Expenses (which are net of Other Income) increased by $9 million to a net expense of $92 million in 2013 from a net expense of $83 million in 2012. The increase was primarily due to an increase of $9 million in interest expense primarily associated with higher long-term debt.
Income Tax Expense
Pepco’s income tax expense increased by $31 million to $79 million in 2013 from $48 million in 2012. Pepco’s effective income tax rates for the years ended December 31, 2013 and 2012 were 34.5% and 27.6%, respectively. The increase in the effective tax rate primarily resulted from changes in estimates and interest related to uncertain and effectively settled tax positions.
On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit issued an opinion in Consolidated Edison Company of New York, Inc. & Subsidiaries v. United States (to which Pepco is not a party) that disallowed tax benefits associated with Consolidated Edison’s cross-border lease transaction. As a result of the court’s ruling in this case, PHI determined in the first quarter of 2013 that it could no longer support its current assessment with respect to the likely outcome of tax positions associated with its cross-border energy lease investments held by its wholly-owned subsidiary Potomac Capital Investment Corporation, and PHI recorded an after-tax charge of $377 million in the first quarter of 2013. Included in the $377 million charge was an after-tax interest charge of $54 million and this amount was allocated to each member of PHI’s consolidated group as if each member was a separate taxpayer, resulting in Pepco recording a $5 million interest benefit in the first quarter of 2013.
In 2012, Pepco recorded tax benefits of $11 million for changes in estimates and interest related to uncertain and effectively settled tax positions primarily due to the effective settlement with the IRS with respect to the methodology used historically to calculate deductible mixed service costs and the expiration of the statute of limitations associated with an uncertain tax position.
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Capital Requirements
Sources of Capital
Pepco has a range of capital sources available, in addition to internally generated funds, to meet its long-term and short-term funding needs. The sources of long-term funding include the issuance of mortgage bonds and other debt securities and bank financings, as well as the ability to issue preferred stock. Proceeds from long-term financings are used primarily to fund long-term capital requirements, such as capital expenditures, and to repay or refinance existing indebtedness. Pepco traditionally has used a number of sources to fulfill short-term funding needs, including commercial paper, short-term notes, bank lines of credit and borrowings under the PHI money pool. Proceeds from short-term borrowings are used primarily to meet working capital needs, but may also be used to temporarily fund long-term capital requirements. Pepco’s ability to generate funds from its operations and to access the capital and credit markets is subject to risks and uncertainties. Volatile and deteriorating financial market conditions, diminished liquidity and tightening credit may affect access to certain of Pepco’s potential funding sources.
Debt Securities
Pepco has a Mortgage and Deed of Trust (the Mortgage) under which it issues First Mortgage Bonds. First Mortgage Bonds issued under the Mortgage are secured by a lien on substantially all of Pepco’s property, plant and equipment, except for such property excluded from the lien of the Mortgage. The principal amount of First Mortgage Bonds that Pepco may issue under the Mortgage is limited by the principal amount of retired First Mortgage Bonds and 60% of the lesser of the cost or fair value of new property additions that have not been used as the basis for the issuance of additional First Mortgage Bonds. Pepco also has an indenture under which it issues senior notes secured by First Mortgage Bonds and an indenture under which it can issue unsecured debt securities, including medium-term notes. To fund the construction of pollution control facilities, Pepco also has from time to time raised capital through tax-exempt bonds issued by a municipality or public agency, the proceeds of which are loaned to Pepco by the municipality or agency.
Information concerning the principal amount and terms of Pepco’s outstanding debt securities, as of December 31, 2013, is set forth in Note (9), “Debt,” to the financial statements of Pepco.
Bank Financing
As further discussed in Note (9), “Debt,” to the financial statements of Pepco, Pepco is a borrower under a $1.5 billion unsecured syndicated credit facility, along with PHI, DPL and ACE, which expires in August 2018. This credit facility provides for Pepco’s liquidity needs, including obtaining letters of credit, borrowing for general corporate purposes and supporting its commercial paper program. Pepco’s credit limit under the facility is the lesser of $250 million and the maximum amount of short-term debt Pepco is permitted to have outstanding by its regulatory authorities. The short-term borrowing limit established by FERC for Pepco is $500 million.
Commercial Paper Program
Pepco maintains an ongoing commercial paper program to address its short-term liquidity needs. As of December 31, 2013, the maximum capacity available under the program was $500 million, subject to available borrowing capacity under the credit facility.
Pepco had $151 million of commercial paper outstanding at December 31, 2013. The weighted average interest rate for commercial paper issued by Pepco during 2013 was 0.34% and the weighted average maturity of all commercial paper issued by Pepco during 2013 was five days.
PEPCO
Money Pool
Pepco participates in the money pool operated by PHI under authorization received from FERC. The money pool is an unsecured cash management mechanism used by PHI and eligible subsidiaries to manage their short-term investment and borrowing requirements. PHI may invest in, but not borrow from, the money pool. Eligible subsidiaries with surplus cash may deposit those funds in the money pool. Deposits in the money pool are guaranteed by PHI. Eligible subsidiaries with cash requirements may borrow from the money pool. Depositors in the money pool receive, and borrowers from the money pool pay, an interest rate based primarily on PHI’s short-term borrowing rate. PHI deposits funds in the money pool to the extent that the pool has insufficient funds to meet the borrowing needs of its participants, which may require PHI to borrow funds for deposit from external sources.
Preferred Stock
Under its Articles of Incorporation, Pepco is authorized to issue and have outstanding up to 6 million shares of preferred stock in one or more series, with each series having such rights, preferences and limitations, including dividend and voting rights and redemption provisions, as the Board of Directors may establish. As of December 31, 2013 and 2012, there were no shares of Pepco preferred stock outstanding.
Regulatory Restrictions on Financing Activities
Pepco’s long-term financing activities (including the issuance of securities and the incurrence of debt) are subject to authorization by the DCPSC and MPSC. Through its periodic filings with the respective utility commissions, Pepco generally maintains standing authority sufficient to cover its projected financing needs over a multi-year period. Under the FPA, FERC has jurisdiction over the issuance of long-term and short-term securities of public utilities, but only if the issuance is not regulated by the state public utility commission in which the public utility is organized and operating. Pepco has obtained FERC authorization for the issuance of short-term debt under these provisions.
Capital Expenditures
Pepco’s capital expenditures for the year ended December 31, 2013 were $576 million. These expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission. The expenditures also include an allocation by PHI of hardware and software expenditures that primarily benefit Power Delivery and are allocated to Pepco when the assets are placed in service.
Pepco’s projected capital expenditures for the five-year period from 2014 through 2018 are summarized below. Pepco expects to fund these expenditures through internally generated cash, external financing and capital contributions from PHI.
Pepco has several construction projects within its service territory where performance has been subcontracted to Pepco Energy Services. Pepco guarantees the obligations of Pepco Energy Services under surety bonds obtained by Pepco Energy Services for these projects. These guarantees totaled $14 million at December 31, 2013.
PEPCO
Transmission and Distribution
The projected capital expenditures listed in the table above for distribution and transmission are primarily for facility replacements and upgrades to accommodate customer growth and service reliability, including capital expenditures for continuing reliability enhancement efforts.
DOE Capital Reimbursement Awards
During 2009, the DOE announced a $168 million award to PHI under the American Recovery and Reinvestment Act of 2009 for the implementation of an AMI system, direct load control, distribution automation, and communications infrastructure. Pepco was awarded $149 million, with $105 million to be used in the Maryland service territory and $44 million to be used in the District of Columbia service territory.
During 2010, Pepco and the DOE signed agreements formalizing Pepco’s $149 million share of the $168 million award. Of the $149 million, $118 million is being used for the smart grid and other capital expenditures of Pepco. The remaining $31 million is being used to offset incremental expenditures associated with direct load control and other programs. During 2013, Pepco received award payments of $30 million. The cumulative award payments received by Pepco as of December 31, 2013, were $145 million.
The IRS has announced that, to the extent these grants are expended on capital items, they will not be considered taxable income.
Pension and Other Postretirement Benefit Plans
Pepco participates in pension and OPEB plans sponsored by PHI for its employees. Pepco contributed $85 million to the PHI Retirement Plan during 2012. In 2013 and 2012, Pepco contributed $6 million and $5 million, respectively, to the other postretirement benefit plan.
DPL
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Delmarva Power & Light Company
DPL meets the conditions set forth in General Instruction I(1)(a) and (b) to Form 10-K, and accordingly information otherwise required under this Item has been omitted in accordance with General Instruction I(2)(a) to Form 10-K.
General Overview
DPL is engaged in the transmission and distribution of electricity in portions of Delaware and Maryland. DPL also provides Default Electricity Supply. DPL’s electricity distribution service territory covers approximately 5,000 square miles and, as of December 31, 2013, had a population of approximately 1.4 million. As of December 31, 2013, approximately 66% of delivered electricity sales were to Delaware customers and approximately 34% were to Maryland customers. In northern Delaware, DPL also supplies and distributes natural gas to retail customers and provides transportation-only services to retail customers who purchase natural gas from other suppliers. DPL’s natural gas distribution service territory covers approximately 275 square miles and, as of December 31, 2013, had a population of approximately 500,000.
DPL’s results historically have been seasonal, generally producing higher revenue and income in the warmest and coldest periods of the year. For retail customers of DPL in Maryland, revenues are not affected by unseasonably warmer or colder weather because a BSA for retail customers was implemented that provides for a fixed distribution charge per customer. The BSA has the effect of decoupling the distribution revenue recognized in a reporting period from the amount of power delivered during the period. As a result, the only factors that will cause distribution revenue from customers in Maryland to fluctuate from period to period are changes in the number of customers and changes in the approved distribution charge per customer. A modified fixed variable rate design, which would provide for a charge not tied to a customer’s volumetric consumption of electricity or natural gas, has been proposed for DPL electricity and natural gas customers in Delaware. Changes in customer usage (due to weather conditions, energy prices, energy efficiency programs or other reasons) from period to period have no impact on reported distribution revenue for customers to whom the BSA applies.
In accounting for the BSA in Maryland, a Revenue Decoupling Adjustment is recorded representing either (i) a positive adjustment equal to the amount by which revenue from Maryland retail distribution sales falls short of the revenue that DPL is entitled to earn based on the approved distribution charge per customer or (ii) a negative adjustment equal to the amount by which revenue from such distribution sales exceeds the revenue that DPL is entitled to earn based on the approved distribution charge per customer.
DPL is a wholly owned subsidiary of Conectiv which is wholly owned by PHI. Because each of PHI and Conectiv is a public utility holding company subject to PUHCA 2005, the relationship between each of PHI, Conectiv, PHI Service Company and DPL, as well as certain activities of DPL, are subject to FERC’s regulatory oversight under PUHCA 2005.
Utility Capital Expenditures
DPL devotes a substantial portion of its total capital expenditures to improving the reliability of its electrical transmission and distribution systems and replacing aging infrastructure throughout its service territories. These activities include one or more of the following:
•
Identifying and upgrading under-performing feeders;
•
Adding new facilities to support load;
•
Installing distribution automation systems on both the overhead and underground network systems; and
•
Rejuvenating and replacing underground residential cables.
DPL’s capital expenditures for continuing reliability enhancement efforts are included in the table of projected capital expenditures within “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Capital Requirements - Capital Expenditures.”
Smart Grid
DPL is building a smart grid which is designed to meet the challenges of rising energy costs, improve service reliability of the energy distribution system, provide timely and accurate customer information and address government energy reduction goals. For a discussion of the smart grid, see PHI’s “Management’s Discussion and Analysis of Financial Condition and Results of Operations - General Overview - Power Delivery Initiatives and Activities - Smart Grid.”
DPL
Mitigation of Regulatory Lag
An important factor in the ability of DPL to earn its authorized ROE is the willingness of the DPSC and the MPSC to adequately address the shortfall in revenues in DPL’s rate structure due to the delay in time or “lag” between when costs are incurred and when they are reflected in rates. This delay is commonly known as “regulatory lag.” DPL is currently experiencing significant regulatory lag because investments in rate base and operating expenses are increasing more rapidly than revenue growth. For a more detailed discussion of regulatory lag, see PHI’s “Management’s Discussion and Analysis of Financial Condition and Results of Operations - General Overview - Power Delivery Initiatives and Activities - Mitigation of Regulatory Lag.”
MAPP Project
On August 24, 2012, the board of PJM terminated the MAPP project and removed it from PJM’s regional transmission expansion plan. DPL had been directed to construct MAPP, a 152-mile high-voltage interstate transmission line, to address the reliability needs of the region’s transmission system. In December 2012, DPL submitted a filing to FERC seeking recovery of $38 million of abandoned MAPP costs over a five-year period. 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.
In February 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.
In December 2013, DPL submitted a settlement agreement to FERC with respect to this matter. Under the terms of the proposed settlement agreement, DPL would recover its abandoned MAPP costs over a three-year recovery period beginning June 1, 2013. The settlement agreement, which is subject to FERC approval, would resolve all issues concerning the recovery of abandonment costs associated with the cancellation of the MAPP project. The terms of this settlement, if approved, would not be subject to the pending formula rate or transmission ROE challenges at FERC or modification through any other FERC proceeding. DPL cannot predict the timing or results of a final FERC decision in this proceeding.
As of December 31, 2013, DPL had a regulatory asset related to the MAPP abandoned costs of $31 million, representing the original filing amount of approximately $38 million of abandoned costs referred to above less: (i) approximately $1 million of disallowed costs written off in 2013; and (ii) $6 million of amortization expense recorded in 2013. The regulatory asset balance includes the costs of land, land rights, engineering and design, environmental services, and project management and administration.
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, among others. 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 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. DPL cannot predict when a final FERC decision in this proceeding will be issued.
DPL
Earnings Overview
Net Income For the Year Ended December 31, 2013 Compared to the Year Ended December 31, 2012
DPL’s net income for the year ended December 31, 2013 was $89 million compared to $73 million for the year ended December 31, 2012. The $16 million increase in earnings was primarily due to the following:
•
An increase of $16 million from electric distribution base rate increases in Maryland and Delaware.
•
An increase of $8 million due to lower operation and maintenance expense, primarily associated with higher storm restoration and system maintenance in 2012.
•
An increase of $6 million primarily due to higher sales from colder winter weather, partially offset by lower sales from milder summer weather.
•
A decrease of $6 million associated with Default Electricity Supply margins for DPL Delaware, primarily due to favorable adjustments in 2012 related to the under-recognition of allowed returns on net uncollectible expense and regulatory taxes.
•
A decrease of $4 million due to higher depreciation and amortization expense associated primarily with regulatory assets and increases in plant investment, partially offset by lower depreciation rates.
•
A decrease of $2 million due to higher interest expense resulting from an increase in outstanding debt.
DPL
Results of Operations
The following results of operations discussion compares the year ended December 31, 2013 to the year ended December 31, 2012. All amounts in the tables (except sales and customers) are in millions of dollars.
A condensed summary of DPL’s statement of income for the year ended December 31, 2013 compared to the year ended December 31, 2012, is set forth in the table below:
Electric Operating Revenue
The table above shows the amount of Electric Operating Revenue earned that is subject to price regulation (Regulated T&D Electric Revenue and Default Electricity Supply Revenue) and that which is not subject to price regulation (Other Electric Revenue).
Regulated T&D Electric Revenue includes revenue from the distribution of electricity, including the distribution of Default Electricity Supply, to DPL’s customers within its service territories at regulated rates. Regulated T&D Electric Revenue also includes transmission service revenue that DPL receives as a transmission owner from PJM at rates regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.
The costs related to Default Electricity Supply are included in Purchased Energy. Default Electricity Supply Revenue also includes transmission enhancement credits that DPL receives as a transmission owner from PJM in consideration for approved regional transmission expansion plan expenditures.
Other Electric Revenue includes work and services performed on behalf of customers, including other utilities, which is generally not subject to price regulation. Work and services includes mutual assistance to other utilities, highway relocation, rentals of pole attachments, late payment fees and collection fees.
DPL
Regulated T&D Electric
Regulated T&D Electric Revenue increased by $47 million primarily due to:
•
An increase of $27 million due to distribution rate increases in Maryland effective July 2012 and September 2013, and in Delaware effective July 2012 and October 2013.
•
An increase of $7 million in transmission revenue related to the resale by DPL of renewable energy in Delaware (which is substantially offset in Purchased Energy and Depreciation and Amortization).
•
An increase of $5 million primarily due to a Renewable Portfolio Surcharge in Delaware effective June 2012 (which is substantially offset in Purchased Energy and Depreciation and Amortization).
•
An increase of $6 million in transmission revenue related to the recovery of MAPP abandonment costs, as approved by FERC (which is offset in Depreciation and Amortization).
•
An increase of $4 million in transmission revenue rates effective June 1, 2013 related to increases in transmission plant investment and operating expenses.
•
An increase of $1 million in distribution revenue related to customer growth in all Delaware and Maryland customer classes.
The aggregate amount of these increases was partially offset by:
•
A decrease of $7 million due to lower non-weather related average customer usage.
•
A decrease of $1 million in transmission revenue associated with the change in FERC formula rate true-ups.
DPL
Default Electricity Supply
Default Supply Revenue decreased by $41 million primarily due to:
•
A decrease of $27 million due to lower sales, primarily as a result of customer migration to competitive suppliers.
•
A decrease of $17 million as a result of lower Default Electricity Supply rates.
•
A decrease of $8 million due to lower non-weather related average customer usage.
The aggregate amount of these decreases was partially offset by an increase of $8 million due to higher sales primarily as a result of colder weather during the 2013 winter months, as compared to 2012.
The following table shows the percentages of DPL’s total distribution sales by jurisdiction that are derived from customers receiving Default Electricity Supply from DPL. Amounts are for the years ended December 31:
Natural Gas Operating Revenue
DPL
The table above shows the amounts of Natural Gas Operating Revenue from sources that are subject to price regulation (Regulated Gas Revenue) and those that generally are not subject to price regulation (Other Gas Revenue). Regulated Gas Revenue includes the revenue DPL receives from on-system natural gas delivered sales and the transportation of natural gas for customers within its service territory at regulated rates. Other Gas Revenue consists of off-system natural gas sales and the short-term release of interstate pipeline transportation and storage capacity not needed to serve customers. Off-system sales are made possible when low demand for natural gas by regulated customers creates excess pipeline capacity.
Regulated Gas
Regulated Gas Revenue increased by $14 million primarily due to:
•
An increase of $22 million due to higher sales primarily as a result of colder weather during the winter months of 2013 as compared to 2012.
•
An increase of $7 million due to higher non-weather related average commercial customer usage.
•
An increase of $4 million due to a revenue adjustment recorded in June 2012 for a reduction in the estimate of gas sold but not yet billed to customers (which is partially offset by an increase in Purchased Energy).
•
An increase of $2 million due to a distribution rate increase effective July 2013.
The aggregate amount of these increases was partially offset by a decrease of $22 million due to a GCR decrease effective November 2012.
Other Gas Revenue
Other Gas Revenue decreased by $6 million primarily due to lower average prices and lower volumes for off-system sales to electric generators and gas marketers.
DPL
Operating Expenses
Purchased Energy consists of the cost of electricity purchased by DPL to fulfill its Default Electricity Supply obligation and, as such, is recoverable from customers in accordance with the terms of public service commission orders. Purchased Energy decreased by $16 million to $552 million in 2013 from $568 million in 2012 primarily due to:
•
A decrease of $39 million primarily due to customer migration to competitive suppliers.
•
A decrease of $20 million in deferred electricity expense primarily due to higher Default Electricity Supply cost of service rates, which resulted in a lower rate of recovery of Default Electricity Supply costs.
The aggregate amount of these decreases was partially offset by:
•
An increase of $17 million due to higher average electricity costs under Default Electricity Supply contracts.
•
An increase of $13 million in deferred electricity expense primarily due to a Renewable Portfolio Surcharge in Delaware effective June 2012 (which is substantially offset in Regulated T&D Electric Revenue and Depreciation and Amortization).
•
An increase of $7 million due to higher electricity sales primarily as a result of colder weather during the 2013 winter months, as compared to 2012.
•
An increase of $4 million in the costs associated with purchasing Renewable Energy Credits in Delaware (which is offset by a corresponding increase in Regulated T&D Electric Revenue).
•
An increase of $2 million in the costs associated with purchases under wind power purchase agreements in Delaware (which is offset by a corresponding increase in Regulated T&D Electric Revenue).
Gas Purchased
Gas Purchased consists of the cost of gas purchased by DPL to fulfill its obligation to regulated gas customers and, as such, is recoverable from customers in accordance with the terms of public service commission orders. It also includes the cost of gas purchased for off-system sales. Total Gas Purchased decreased by $4 million to $109 million in 2013 from $113 million in 2012 primarily due to:
•
A decrease of $13 million from the settlement of financial hedges entered into as part of DPL’s hedge program for the purchase of regulated natural gas.
•
A decrease of $5 million in the cost of gas purchases for off-system sales as a result of lower volumes.
The aggregate amount of these decreases was partially offset by:
•
An increase of $11 million in the cost of gas purchases for on-system sales as a result of higher average gas prices.
•
An increase of $4 million in the cost of gas purchases for on-system sales as a result of an adjustment recorded in June 2012 for a reduction in the estimate of gas sold but not yet billed to customers (which is offset by an increase in Regulated Gas Revenue).
DPL
Other Operation and Maintenance
Other Operation and Maintenance expense decreased by $9 million to $251 million in 2013 from $260 million in 2012 primarily due to:
•
A decrease of $5 million associated with lower maintenance costs.
•
A decrease of $5 million primarily due to 2012 total incremental storm restoration costs for major storm events as described in the following table:
•
During 2012, DPL incurred incremental storm restoration costs of $2 million associated with the June 2012 derecho which resulted in widespread damage to the electric distribution system in each of DPL’s service territories. DPL deferred $1 million of these costs as a regulatory asset to reflect the probable recovery of these storm restoration costs in Maryland. The MPSC approved the recovery of these costs for DPL in its August 2013 electric distribution base rate order over a five-year period. The remaining costs of $1 million relate to repair work completed in Delaware which are not deferrable.
•
In the fourth quarter of 2012, DPL incurred incremental storm restoration costs of $9 million associated with Hurricane Sandy which resulted in widespread damage to the electric distribution system in each of DPL’s service territories. DPL deferred $5 million of these costs as a regulatory asset to reflect the probable recovery of these storm restoration costs in Maryland. The MPSC approved the recovery of these costs for DPL in its August 2013 electric distribution base rate order over a five-year period. The remaining costs of $4 million relate to repair work completed in Delaware which are not deferrable.
•
A decrease of $4 million in customer service costs.
•
A decrease of $4 million in other storm restoration costs.
The aggregate amount of these decreases was partially offset by:
•
An increase of $6 million resulting from 2012 deferred cost adjustments associated with DPL Default Electricity Supply. The deferred cost adjustments were primarily due to the under-recognition of allowed returns on net uncollectible expense and regulatory taxes.
•
An increase of $2 million associated with the write-offs of disallowed MAPP and associated transmission projects costs.
Depreciation and Amortization
Depreciation and Amortization expense increased by $5 million to $107 million in 2013 from $102 million in 2012 primarily due to:
•
An increase of $6 million in amortization of MAPP abandonment costs (which is offset by a corresponding increase in Regulated T&D Electric Revenue).
DPL
•
An increase of $4 million due to utility plant additions.
•
An increase of $2 million in amortization of regulatory assets primarily related to recoverable AMI costs, major storm costs and rate case costs.
The aggregate amount of these increases was partially offset by a decrease of $7 million in the Delaware Renewable Energy Portfolio Standards deferral (which is substantially offset by a corresponding increase in Fuel and Purchased Energy).
Other Taxes
Other Taxes increased by $4 million to $40 million in 2013 from $36 million in 2012. The increase was primarily due to higher property taxes.
Other Income (Expenses)
Other Expenses (which are net of Other Income) increased by $3 million to a net expense of $40 million in 2013 from a net expense of $37 million in 2012. The increase was primarily due to an increase in long-term debt interest expense due to the issuance of $250 million of First Mortgage Bonds in June 2012.
Income Tax Expense
DPL’s income tax expense increased by $12 million to $56 million in 2013 from $44 million in 2012. DPL’s effective income tax rates for the years ended December 31, 2013 and 2012 were 38.6% and 37.6%, respectively. The increase in the effective tax rate primarily resulted from adjustments to prior year taxes recorded during the year ended December 31, 2012.
On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit issued an opinion in Consolidated Edison Company of New York, Inc. & Subsidiaries v. United States (to which DPL is not a party) that disallowed tax benefits associated with Consolidated Edison’s cross-border lease transaction. As a result of the court’s ruling in this case, PHI determined in the first quarter of 2013 that it could no longer support its current assessment with respect to the likely outcome of tax positions associated with its cross-border energy lease investments held by its wholly-owned subsidiary Potomac Capital Investment Corporation, and PHI recorded an after-tax charge of $377 million in the first quarter of 2013. Included in the $377 million charge was an after-tax interest charge of $54 million and this amount was allocated to each member of PHI’s consolidated group as if each member was a separate taxpayer, resulting in DPL recording a $1 million interest benefit in the first quarter of 2013.
Capital Requirements
Sources of Capital
DPL has a range of capital sources available, in addition to internally generated funds, to meet its long-term and short-term funding needs. The sources of long-term funding include the issuance of mortgage bonds and other debt securities and bank financings, as well as the ability to issue preferred stock. Proceeds from long-term financings are used primarily to fund long-term capital requirements, such as capital expenditures, and to repay or refinance existing indebtedness. DPL traditionally has used a number of sources to fulfill short-term funding needs, including commercial paper, medium- and short-term notes, bank lines of credit, and borrowings under the PHI money pool. Proceeds from short-term borrowings are used primarily to meet working capital needs, but may also be used to temporarily fund long-term capital requirements. DPL’s ability to generate funds from its operations and to access the capital and credit markets is subject to risks and uncertainties. Volatile and deteriorating financial market conditions, diminished liquidity and tightening credit may affect access to certain of DPL’s potential funding sources.
DPL
Debt Securities
DPL has a Mortgage and Deed of Trust (the Mortgage) under which it issues First Mortgage Bonds. First Mortgage Bonds issued under the Mortgage are secured by a lien on substantially all of DPL’s property, plant and equipment, except for such property excluded from the lien of the Mortgage. The principal amount of First Mortgage Bonds that DPL may issue under the Mortgage is limited by the principal amount of retired First Mortgage Bonds and 60% of the lesser of the cost or fair value of new property additions that have not been used as the basis for the issuance of additional First Mortgage Bonds. DPL also has an indenture under which it issues unsecured senior notes, medium-term notes and Variable Rate Demand Bonds (VRDBs). To fund the construction of pollution control facilities, DPL also has from time to time raised capital through tax-exempt bonds, including tax-exempt VRDBs, issued by a public agency, the proceeds of which are loaned to DPL by the agency.
Information concerning the principal amount and terms of DPL’s outstanding First Mortgage Bonds, senior notes, medium-term notes and tax-exempt bonds issued for the benefit of DPL, as of December 31, 2013, is set forth in Note (10), “Debt,” to the financial statements of DPL.
Bank Financing
As further discussed in Note (10), “Debt,” to the financial statements of DPL, DPL is a borrower under a $1.5 billion unsecured syndicated credit facility, along with PHI, Pepco and ACE, which expires in August 2018. This credit facility provides for DPL’s liquidity needs, including obtaining letters of credit, borrowing for general corporate purposes and supporting its commercial paper program. DPL’s credit limit under the facility is the lesser of $250 million and the maximum amount of short-term debt DPL is permitted to have outstanding by its regulatory authorities. The short-term borrowing limit established by FERC for DPL is $500 million.
Commercial Paper Program
DPL maintains an ongoing commercial paper program to address its short-term liquidity needs. As of December 31, 2013, the maximum capacity available under the program was $500 million, subject to available borrowing capacity under the credit facility.
DPL had $147 million of commercial paper outstanding at December 31, 2013. The weighted average interest rate for commercial paper issued by DPL during 2013 was 0.29% and the weighted average maturity of all commercial paper issued by DPL during 2013 was three days.
Money Pool
DPL participates in the money pool operated by PHI under authorization received from FERC. The money pool is an unsecured cash management mechanism used by PHI and eligible subsidiaries to manage their short-term investment and borrowing requirements. PHI may invest in, but not borrow from, the money pool. Eligible subsidiaries with surplus cash may deposit those funds in the money pool. Deposits in the money pool are guaranteed by PHI. Eligible subsidiaries with cash requirements may borrow from the money pool. Depositors in the money pool receive, and borrowers from the money pool pay, an interest rate based primarily on PHI’s short-term borrowing rate. PHI deposits funds in the money pool to the extent that the pool has insufficient funds to meet the borrowing needs of its participants, which may require PHI to borrow funds for deposit from external sources.
Regulatory Restrictions on Financing Activities
DPL’s long-term financing activities (including the issuance of securities and the incurrence of debt) is subject to authorization by the DPSC and the MPSC. Through its periodic filings with the respective utility commissions, DPL generally maintains standing authority sufficient to cover its projected financing needs over a multi-year period. Under the FPA, FERC has jurisdiction over the issuance of long-term and short-term securities of public utilities, but only if the issuance is not regulated by the state public utility commission in which the public utility is organized and operating. DPL has obtained FERC authorization for the issuance of short-term debt under these provisions.
DPL
Capital Expenditures
DPL’s capital expenditures for the year ended December 31, 2013 were $357 million. These expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission. The expenditures also include an allocation by PHI of hardware and software expenditures that primarily benefit Power Delivery and are allocated to DPL when the assets are placed in service.
DPL’s projected capital expenditures for the five-year period from 2014 through 2018 are summarized below. DPL expects to fund these expenditures through internally generated cash, external financing and capital contributions from PHI.
Transmission and Distribution
The projected capital expenditures listed in the table above for distribution (other than the smart grid), transmission and gas delivery are primarily for facility replacements and upgrades to accommodate customer growth and service reliability, including capital expenditures for reliability enhancement efforts.
Pension and Other Postretirement Benefit Plans
DPL participates in pension and OPEB plans sponsored by PHI for its employees. DPL contributed $10 million and $85 million to the PHI Retirement Plan during 2013 and 2012, respectively. In 2013 and 2012, DPL contributed $3 million and $7 million, respectively, to the other postretirement benefit plan.
ACE
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Atlantic City Electric Company
ACE meets the conditions set forth in General Instruction I(1)(a) and (b) to Form 10-K, and accordingly information otherwise required under this Item has been omitted in accordance with General Instruction I(2)(a) to Form 10-K.
General Overview
ACE is engaged in the transmission and distribution of electricity in portions of southern New Jersey. ACE also provides Default Electricity Supply. Default Electricity Supply is known as BGS in New Jersey. ACE’s service territory covers approximately 2,700 square miles and, as of December 31, 2013, had a population of approximately 1.1 million.
ACE is a wholly owned subsidiary of Conectiv, which is wholly owned by PHI. Because each of PHI and Conectiv is a public utility holding company subject to PUHCA 2005, the relationship between each of PHI, Conectiv, PHI Service Company and ACE, as well as certain activities of ACE, are subject to FERC’s regulatory oversight under PUHCA 2005.
Utility Capital Expenditures
ACE devotes a substantial portion of its total capital expenditures to improving the reliability of its electrical transmission and distribution systems and replacing aging infrastructure throughout its service territory. These activities include one or more of the following:
•
Identifying and upgrading under-performing feeders;
•
Adding new facilities to support load;
•
Installing distribution automation systems on both the overhead and underground network systems; and
•
Rejuvenating and replacing underground residential cables.
ACE’s capital expenditures for continuing reliability enhancement efforts are included in the table of projected capital expenditures within “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Capital Requirements - Capital Expenditures.”
Mitigation of Regulatory Lag
An important factor in the ability of ACE to earn its authorized ROE is the willingness of the NJBPU to adequately address the shortfall in revenues in ACE’s rate structure due to the delay in time or “lag” between when costs are incurred and when they are reflected in rates. This delay is commonly known as “regulatory lag.” ACE is currently experiencing significant regulatory lag because investments in rate base and operating expenses are increasing more rapidly than revenue growth. For a more detailed discussion of regulatory lag, see PHI’s “Management’s Discussion and Analysis of Financial Condition and Results of Operations - General Overview - Power Delivery Initiatives and Activities - Mitigation of Regulatory Lag.”
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 ACE, among others. 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 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. ACE cannot predict when a final FERC decision in this proceeding will be issued.
ACE
Earnings Overview
Net Income For the Year Ended December 31, 2013 Compared to the Year Ended December 31, 2012
ACE’s consolidated net income for the year ended December 31, 2013 was $50 million compared to $35 million for the year ended December 31, 2012. The $15 million increase in earnings was primarily due to the following:
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An increase of $24 million from electric distribution base rate increases in New Jersey.
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An increase of $6 million due to higher tax benefits related to uncertain and effectively settled tax positions.
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An increase of $3 million due to lower operation and maintenance expense, primarily associated with higher storm restoration and system maintenance in 2012.
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A decrease of $8 million due to higher depreciation and amortization expense associated primarily with regulatory assets and increases in plant investment.
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A decrease of $4 million due to lower non-weather related average customer usage in New Jersey.
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A decrease of $2 million primarily due to lower sales from milder summer weather.
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A decrease of $2 million due to lower income related to AFUDC that is applied to capital projects.
ACE
Results of Operations
The following results of operations discussion compares the year ended December 31, 2013 to the year ended December 31, 2012. All amounts in the tables (except sales and customers) are in millions of dollars.
A condensed summary of ACE’s consolidated statement of income for the year ended December 31, 2013 compared to the year ended December 31, 2012, is set forth in the table below:
Operating Revenue
The table above shows the amount of Operating Revenue earned that is subject to price regulation (Regulated T&D Electric Revenue and Default Electricity Supply Revenue) and that which is not subject to price regulation (Other Electric Revenue).
Regulated T&D Electric Revenue includes revenue from the distribution of electricity, including the distribution of Default Electricity Supply, to ACE’s customers within its service territory at regulated rates. Regulated T&D Electric Revenue also includes transmission service revenue that ACE receives as a transmission owner from PJM at rates regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.
The costs related to Default Electricity Supply are included in Purchased Energy. Default Electricity Supply Revenue also includes revenue from Transition Bond Charges that ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds, and revenue in the form of transmission enhancement credits.
Other Electric Revenue includes work and services performed on behalf of customers, including other utilities, which is generally not subject to price regulation. Work and services includes mutual assistance to other utilities, highway relocation, rentals of pole attachments, late payment fees and collection fees.
ACE
Regulated T&D Electric
Regulated T&D Electric Revenue increased by $37 million primarily due to:
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An increase of $39 million due to distribution rate increases effective November 2012 and July 2013, and a customer charge rate increase effective November 2012.
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An increase of $6 million primarily due to a rate increase in the New Jersey Societal Benefit Charge effective July 2012 (which is offset in Deferred Electric Service Costs).
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An increase of $2 million in transmission revenue associated with the change in FERC formula rate true-ups.
The aggregate amount of these increases was partially offset by:
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A decrease of $6 million due to lower non-weather related average residential and commercial customer usage.
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A decrease of $3 million due to lower sales primarily as a result of milder weather during the 2013 summer months, as compared to 2012.
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A decrease of $1 million in transmission revenue primarily attributable to a peak-load rate decrease effective January 2013.
Default Electricity Supply
ACE
Other Default Electricity Supply Revenue consists primarily of (i) revenue from the resale in the PJM RTO market of energy and capacity purchased under contracts with unaffiliated NUGs and (ii) revenue from transmission enhancement credits.
Default Electricity Supply Revenue decreased by $31 million primarily due to:
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A decrease of $38 million due to lower sales, primarily as a result of customer migration to competitive suppliers.
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A decrease of $14 million due to lower non-weather related average residential and commercial customer usage.
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A decrease of $8 million as a result of lower Default Electricity Supply rates, primarily due to a Basic Generation Service rate decrease that became effective June 2013, partially offset by a Non-utility Generation Charge rate increase that became effective June 2013.
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A decrease of $6 million due to lower sales, primarily as a result of milder weather during the 2013 summer months, as compared to 2012.
The aggregate amount of these decreases was partially offset by an increase of $36 million in wholesale energy and capacity resale revenues primarily due to higher market prices for the resale of electricity and capacity purchased from NUGs.
For the years ended December 31, 2013 and 2012, the percentages of ACE’s total distribution sales that are derived from customers receiving Default Electricity Supply are 48% and 51%, respectively.
Operating Expenses
Purchased Energy
Purchased Energy consists of the cost of electricity purchased by ACE to fulfill its Default Electricity Supply obligation and, as such, is recoverable from customers in accordance with the terms of public service commission orders. Purchased Energy decreased by $43 million to $660 million in 2013 from $703 million in 2012 primarily due to:
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A decrease of $35 million primarily due to customer migration to competitive suppliers.
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A decrease of $5 million due to lower average electricity costs under Default Electricity Supply contracts.
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A decrease of $3 million due to lower electricity sales, primarily as a result of milder weather during the 2013 summer months, as compared to 2012.
ACE
Other Operation and Maintenance
Other Operation and Maintenance expense decreased by $9 million to $230 million in 2013 from $239 million in 2012 primarily due to:
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A decrease of $5 million in other storm restoration costs.
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A decrease of $2 million in bad debt expense that is deferred and recoverable.
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A decrease of $1 million associated with lower maintenance costs.
Other Operation and Maintenance expense also includes the effects of 2012 total incremental storm restoration costs for major storm events as described in the following table:
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During 2012, ACE incurred incremental storm restoration costs of $14 million associated with the June 2012 derecho which resulted in widespread damage to the electric distribution system. ACE deferred all of these costs as a regulatory asset to reflect the probable recovery of these storm restoration costs in New Jersey. ACE’s stipulation of settlement approved by the NJBPU in June 2013, provides for recovery of these costs over a three-year period.
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During the fourth quarter of 2012, ACE incurred incremental storm restoration costs of $13 million associated with Hurricane Sandy which resulted in widespread damage to the electric distribution system. ACE deferred all of these costs as a regulatory asset to reflect the probable recovery of these storm restoration costs in New Jersey. ACE’s stipulation of settlement approved by the NJBPU in June 2013 provides for recovery of these costs over a three-year period.
Depreciation and Amortization
Depreciation and Amortization expense increased by $12 million to $136 million in 2013 from $124 million in 2012 primarily due to:
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An increase of $7 million in amortization of major storm costs.
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An increase of $6 million in amortization due to the expiration of the excess depreciation reserve regulatory liability in August 2013.
Other Taxes
Other Taxes decreased by $4 million to $14 million in 2013 from $18 million in 2012. The decrease was primarily due to decreased Transitional Energy Facility Assessment taxes due to a rate decrease effective January 2013 (partially offset by a corresponding decrease in Regulated T&D Electric Revenue).
Deferred Electric Service Costs
Deferred Electric Service Costs represent (i) the over or under recovery of electricity costs incurred by ACE to fulfill its Default Electricity Supply obligation and (ii) the over or under recovery of New Jersey Societal Benefit Program costs incurred by ACE. The cost of electricity purchased is reported under Purchased Energy and the corresponding revenue is reported under Default Electricity Supply Revenue. The cost of the New Jersey Societal Benefit Program is reported under Other Operation and Maintenance expense and the corresponding revenue is reported under Regulated T&D Electric Revenue.
ACE
Deferred Electric Service Costs increased by $31 million to an expense of $26 million in 2013 as compared to an expense reduction of $5 million in 2012, primarily due to an increase in deferred electricity expense as a result of higher Default Electricity Supply and New Jersey Societal Benefit Program revenue rates and lower electricity supply costs.
Other Income (Expenses)
Other Expenses (which are net of Other Income) increased by $1 million to a net expense of $67 million in 2013 from a net expense of $66 million in 2012 primarily due to lower income related to AFUDC that is applied to capital projects.
Income Tax Expense
ACE’s consolidated income tax expense increased by $1 million to $19 million in 2013 from $18 million in 2012. ACE’s consolidated effective income tax rates for the years ended December 31, 2013 and 2012 were 27.5% and 34.0%, respectively. The change in the effective tax rate primarily resulted from changes in estimates and interest related to uncertain and effectively settled tax positions. In the first quarter of 2013, ACE recorded an interest benefit of $6 million as discussed further below. In the first quarter of 2012, ACE recorded an interest benefit as a result of the effective settlement with the IRS with respect to the methodology used historically to calculate deductible mixed service costs.
On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit issued an opinion in Consolidated Edison Company of New York, Inc. & Subsidiaries v. United States (to which ACE is not a party) that disallowed tax benefits associated with Consolidated Edison’s cross-border lease transaction. As a result of the court’s ruling in this case, PHI determined in the first quarter of 2013 that it could no longer support its current assessment with respect to the likely outcome of tax positions associated with its cross-border energy lease investments held by its wholly-owned subsidiary Potomac Capital Investment Corporation, and PHI recorded an after-tax charge of $377 million in the first quarter of 2013. Included in the $377 million charge was an after-tax interest charge of $54 million and this amount was allocated to each member of PHI’s consolidated group as if each member was a separate taxpayer, resulting in ACE recording a $6 million interest benefit in the first quarter of 2013.
Capital Requirements
Sources of Capital
ACE has a range of capital sources available, in addition to internally generated funds, to meet its long-term and short-term funding needs. The sources of long-term funding include the issuance of mortgage bonds and other debt securities and bank financings, as well as preferred stock. Proceeds from long-term financings are used primarily to fund long-term capital requirements, such as capital expenditures, and to repay or refinance existing indebtedness. ACE traditionally has used a number of sources to fulfill medium- and short-term funding needs, including commercial paper, medium- and short-term notes, bank lines of credit, and under certain circumstances, borrowings under the PHI money pool. Proceeds from short-term borrowings are used primarily to meet working capital needs, but may also be used to temporarily fund long-term capital requirements. ACE’s ability to generate funds from its operations and to access the capital and credit markets is subject to risks and uncertainties. Volatile and deteriorating financial market conditions, diminished liquidity and tightening credit may affect access to certain of ACE’s potential funding sources.
ACE
Debt Securities
ACE has a Mortgage and Deed of Trust (the Mortgage) under which it issues First Mortgage Bonds. First Mortgage Bonds issued under the Mortgage are secured by a lien on substantially all of ACE’s property, plant and equipment, except for such property excluded from the lien of the Mortgage. The principal amount of First Mortgage Bonds that ACE may issue under the Mortgage is limited by the principal amount of retired First Mortgage Bonds and 65% of the lesser of the cost or fair value of new property additions that have not been used as the basis for the issuance of additional First Mortgage Bonds. ACE also has an indenture under which it issues senior notes secured by First Mortgage Bonds and an indenture under which it can issue unsecured debt securities, including VRDBs. To fund the construction of pollution control facilities, ACE also has from time to time raised capital through tax-exempt bonds, including tax-exempt VRDBs, issued by a municipality, the proceeds of which are loaned to ACE by the municipality.
Information concerning the principal amount and terms of ACE’s outstanding First Mortgage Bonds, senior notes and tax-exempt bonds issued for the benefit of ACE, as of December 31, 2013, is set forth in Note (9), “Debt,” to the consolidated financial statements of ACE.
Bank Financing
As further discussed in Note (9), “Debt,” to the consolidated financial statements of ACE, ACE is a borrower under a $1.5 billion unsecured syndicated credit facility, along with PHI, Pepco and DPL, which expires in August 2018. This credit facility provides for ACE’s liquidity needs, including obtaining letters of credit, borrowing for general corporate purposes and supporting its commercial paper program. ACE’s credit limit under the facility is the lesser of $250 million and the maximum amount of short-term debt ACE is permitted to have outstanding by its regulatory authorities. The short-term borrowing limit established by the NJBPU for ACE is $350 million.
Commercial Paper Program
ACE maintains an ongoing commercial paper program to address its short-term liquidity needs. As of December 31, 2013, the maximum capacity available under the program was $250 million, subject to available borrowing capacity under the credit facility.
ACE had $120 million of commercial paper outstanding at December 31, 2013. The weighted average interest rate for commercial paper issued by ACE during 2013 was 0.31% and the weighted average maturity of all commercial paper issued by ACE during 2013 was four days.
Money Pool
ACE participates in the money pool operated by PHI under authorization received from the NJBPU. The money pool is an unsecured cash management mechanism used by PHI and eligible subsidiaries to manage their short-term investment and borrowing requirements. PHI may invest in, but not borrow from, the money pool. Eligible subsidiaries with surplus cash may deposit those funds in the money pool. Deposits in the money pool are guaranteed by PHI. Eligible subsidiaries with cash requirements may borrow from the money pool. Depositors in the money pool receive, and borrowers from the money pool pay, an interest rate based primarily on PHI’s short-term borrowing rate. PHI deposits funds in the money pool to the extent that the pool has insufficient funds to meet the borrowing needs of its participants, which may require PHI to borrow funds for deposit from external sources. By regulatory order, the NJBPU has restricted ACE’s participation in the PHI money pool. ACE may not invest in the money pool, but may borrow from it if the rates are lower than the rates at which ACE could borrow funds externally.
ACE
Preferred Stock
Under its Certificate of Incorporation, ACE is authorized to issue and have outstanding up to (i) 799,979 shares of Cumulative Preferred Stock, (ii) 2 million shares of No Par Preferred Stock and (iii) 3 million shares of Preference Stock, each such type of preferred stock having such terms and conditions as are set forth in or authorized by the Certificate of Incorporation. As of December 31, 2013 and 2012, ACE had no shares of preferred stock outstanding.
Regulatory Restrictions on Financing Activities
ACE’s long-term and short-term (consisting of debt instruments with a maturity of one year or less) financing activities are subject to authorization by the NJBPU. Through its periodic filings with the NJBPU, ACE generally maintains standing authority sufficient to cover its projected financing needs over a multi-year period. ACE’s long-term and short-term financing activities do not require FERC approval.
State corporate laws impose limitations on the funds that can be used to pay dividends. In addition, ACE must obtain the approval of the NJBPU before dividends can be paid if its equity as a percent of its total capitalization, excluding securitization debt, falls below 30%. As of December 31, 2013, ACE complied with this requirement without the need to seek approval of the NJBPU.
Capital Expenditures
ACE’s capital expenditures for the year ended December 31, 2013 were $261 million. These expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission. The expenditures also include an allocation by PHI of hardware and software expenditures that primarily benefit Power Delivery and are allocated to ACE when the assets are placed in service.
ACE’s projected capital expenditures for the five-year period from 2014 through 2018 are summarized below. ACE expects to fund these expenditures through internally generated cash, external financing and capital contributions from PHI.
Transmission and Distribution
The projected capital expenditures listed in the table for distribution (other than the smart grid) and transmission are primarily for facility replacements and upgrades to accommodate customer growth and service reliability, including continued capital expenditures for reliability enhancement efforts.
DOE Capital Reimbursement Awards
During 2009, the DOE announced a $168 million award to PHI under the American Recovery and Reinvestment Act of 2009 for the implementation of an AMI system, direct load control, distribution automation, and communications infrastructure, of which $19 million was for ACE’s service territory.
ACE
During 2010, ACE and the DOE signed agreements formalizing ACE’s $19 million share of the $168 million award. Of the $19 million, $12 million is being used for the smart grid and other capital expenditures of ACE. The remaining $7 million is being used to offset incremental expenditures associated with direct load control and other programs. During 2013, ACE received award payments of $4 million. The cumulative award payments received by ACE as of December 31, 2013, were $17 million.
The IRS has announced that, to the extent these grants are expended on capital items, they will not be considered taxable income.
Pension and Other Postretirement Benefit Plans
ACE participates in pension and OPEB plans sponsored by PHI for its employees. ACE contributed $30 million to the PHI Retirement Plan during each of 2013 and 2012. In 2013 and 2012, ACE contributed $6 million and $7 million, respectively, to the other postretirement benefit plan.
Item 7A.
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Risk management policies for PHI and its subsidiaries are determined by PHI’s Corporate Risk Management Committee (CRMC), the members of which are PHI’s Chief Risk Officer, Executive Vice President (Power Delivery), Chief Financial Officer, General Counsel, Chief Information Officer and other senior executives. The CRMC monitors interest rate fluctuation, commodity price fluctuation, and credit risk exposure, and sets risk management policies that establish limits on unhedged risk and determine risk reporting requirements. For information about PHI’s derivative activities, other than the information otherwise disclosed herein, refer to Note (2), “Significant Accounting Policies - Accounting For Derivatives,” and Note (13), “Derivative Instruments and Hedging Activities,” of the consolidated financial statements of PHI.
Pepco Holdings, Inc.
Interest Rate Risk
Pepco Holdings and its subsidiaries’ variable or floating rate debt is subject to the risk of fluctuating interest rates in the normal course of business. Pepco Holdings manages interest rate risk through the use of fixed and, to a lesser extent, variable rate debt. The effect of a hypothetical 10% change in interest rates on the annual interest costs for short-term and variable rate debt was less than $1 million as of December 31, 2013.
Potomac Electric Power Company
Interest Rate Risk
Pepco’s debt is subject to the risk of fluctuating interest rates in the normal course of business. Pepco manages interest rate risk through the use of fixed and, to a lesser extent, variable rate debt. The effect of a hypothetical 10% change in interest rates on the annual interest costs for short-term debt and variable rate debt was less than $1 million as of December 31, 2013.
Delmarva Power & Light Company
Commodity Price Risk
DPL uses derivative instruments (for example, forward contracts, futures, swaps, and exchange-traded and over-the-counter options) primarily to reduce natural gas commodity price volatility. DPL also manages commodity risk with capacity contracts that do not meet the definition of derivatives. The primary goal of these activities is to reduce the exposure of its regulated retail natural gas customers to natural gas price spikes. All premiums paid and other transaction costs incurred as part of DPL’s natural gas hedging activity, in addition to all gains and losses on the natural gas hedging activity, are fully recoverable through the GCR clause included in DPL’s natural gas tariff rates approved by the DPSC and are deferred until recovered. At December 31, 2013, after the effects of cash collateral and netting of derivative assets and liabilities available to be offset under master netting arrangements, DPL had no net derivative assets or liabilities. At December 31, 2012, after the effects of cash collateral and netting of derivative assets and liabilities available to be offset under master netting arrangements, DPL had a net derivative liability of $4 million, offset by a $4 million regulatory asset.
Interest Rate Risk
DPL’s debt is subject to the risk of fluctuating interest rates in the normal course of business. DPL manages interest rate risk through the use of fixed and, to a lesser extent, variable rate debt. The effect of a hypothetical 10% change in interest rates on the annual interest costs for short-term debt and variable rate debt was less than $1 million as of December 31, 2013.
Atlantic City Electric Company
Interest Rate Risk
ACE’s debt is subject to the risk of fluctuating interest rates in the normal course of business. ACE manages interest rate risk through the use of fixed and, to a lesser extent, variable rate debt. The effect of a hypothetical 10% change in interest rates on the annual interest costs for short-term debt and variable rate debt was less than $1 million as of December 31, 2013.
Item 8.
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Listed below is a table that sets forth, for each registrant, the page number where the information is contained herein.
* Pepco and DPL have no operating subsidiaries and, therefore, their financial statements are not consolidated.
PEPCO HOLDINGS
Management’s Report on Internal Control over Financial Reporting
The management of Pepco Holdings, Inc. (Pepco Holdings) is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management of Pepco Holdings assessed Pepco Holdings’ internal control over financial reporting as of December 31, 2013 based on the framework in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its assessment, the management of Pepco Holdings concluded that Pepco Holdings’ internal control over financial reporting was effective as of December 31, 2013.
PricewaterhouseCoopers LLP, the independent registered public accounting firm that audited the consolidated financial statements of Pepco Holdings included in this Annual Report on Form 10-K, has also issued its attestation report on the effectiveness of Pepco Holdings’ internal control over financial reporting, which is included herein.
PEPCO HOLDINGS
Report of Independent Registered Public Accounting Firm
To the Shareholders and Board of Directors of
Pepco Holdings, Inc.
In our opinion, the consolidated financial statements listed in the accompanying index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Pepco Holdings, Inc. and its subsidiaries at December 31, 2013 and December 31, 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedules listed in the accompanying index appearing under Item 15(a)(2) present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control-Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedules, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements, on the financial statement schedules, and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
PEPCO HOLDINGS
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
Washington, D.C.
February 27, 2014
PEPCO HOLDINGS
PEPCO HOLDINGS, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF (LOSS) INCOME
The accompanying Notes are an integral part of these Consolidated Financial Statements.
PEPCO HOLDINGS
PEPCO HOLDINGS, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME
The accompanying Notes are an integral part of these Consolidated Financial Statements.
PEPCO HOLDINGS
PEPCO HOLDINGS, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
The accompanying Notes are an integral part of these Consolidated Financial Statements.
PEPCO HOLDINGS
PEPCO HOLDINGS, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
The accompanying Notes are an integral part of these Consolidated Financial Statements.
PEPCO HOLDINGS
PEPCO HOLDINGS, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying Notes are an integral part of these Consolidated Financial Statements.
PEPCO HOLDINGS
PEPCO HOLDINGS, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EQUITY
The accompanying Notes are an integral part of these Consolidated Financial Statements.
PEPCO HOLDINGS
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PEPCO HOLDINGS, INC.
(1) ORGANIZATION
Pepco Holdings, Inc. (PHI or Pepco Holdings), a Delaware corporation incorporated in 2001, is a holding company that, through the following regulated public utility subsidiaries, is engaged primarily in the transmission, distribution and default supply of electricity and the distribution and supply of natural gas (Power Delivery):
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Potomac Electric Power Company (Pepco), which was incorporated in Washington, D.C. in 1896 and became a domestic Virginia corporation in 1949,
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Delmarva Power & Light Company (DPL), which was incorporated in Delaware in 1909 and became a domestic Virginia corporation in 1979, and
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Atlantic City Electric Company (ACE), which was incorporated in New Jersey in 1924.
Each of PHI, Pepco, DPL and ACE is also a reporting company under the Securities Exchange Act of 1934, as amended. Together, Pepco, DPL and ACE constitute the Power Delivery segment for financial reporting purposes.
Through Pepco Energy Services, Inc. and its subsidiaries (collectively, Pepco Energy Services), PHI provides energy savings performance contracting services, underground transmission and distribution construction and maintenance services, and steam and chilled water under long-term contracts.
PHI Service Company, a subsidiary service company of PHI, provides a variety of support services, including legal, accounting, treasury, tax, purchasing and information technology services to PHI and its operating subsidiaries. These services are provided pursuant to service agreements among PHI, PHI Service Company and the participating operating subsidiaries. The expenses of PHI Service Company are charged to PHI and the participating operating subsidiaries in accordance with cost allocation methodologies set forth in the service agreements.
Power Delivery
Each of Pepco, DPL and ACE is a regulated public utility in the jurisdictions that comprise its service territory. Each utility owns and operates a network of wires, substations and other equipment that is classified as transmission facilities, distribution facilities or common facilities (which are used for both transmission and distribution). Transmission facilities are high-voltage systems that carry wholesale electricity into, or across, the utility’s service territory. Distribution facilities are low-voltage systems that carry electricity to end-use customers in the utility’s service territory.
Each utility is responsible for the distribution of electricity, and in the case of DPL, the distribution and supply of natural gas, in its service territory, for which it is paid tariff rates established by the applicable local public service commissions. Each utility also supplies electricity at regulated rates to retail customers in its service territory who do not elect to purchase electricity from a competitive energy supplier. The regulatory term for this supply service is Standard Office Service (SOS) in Delaware, the District of Columbia and Maryland, and Basic Generation Service (BGS) in New Jersey. In these Notes to the consolidated financial statements, these supply service obligations are referred to generally as Default Electricity Supply.
PEPCO HOLDINGS
Pepco Energy Services
Pepco Energy Services is engaged in the following businesses:
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Energy savings performance contracting business: designing, constructing and operating energy efficiency projects and distributed generation equipment, including combined heat and power plants, principally for federal, state and local government customers;
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Underground transmission and distribution business: providing underground transmission and distribution construction and maintenance services for electric utilities in North America; and
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Thermal business: providing steam and chilled water under long-term contracts through systems owned and operated by Pepco Energy Services, primarily to hotels and casinos in Atlantic City, New Jersey.
During 2012, Pepco Energy Services deactivated its Buzzard Point and Benning Road oil-fired generation facilities. Pepco Energy Services placed the facilities into an idle condition termed a “cold closure.” A cold closure requires that the utility service be disconnected so that the facilities are no longer operable and require only essential maintenance until they are completely decommissioned. During the third quarter of 2013, Pepco Energy Services determined that it would be more cost effective to pursue the demolition of the Benning Road generation facility and realization of the scrap metal salvage value of the facility instead of maintaining cold closure status. As a result of this change in intent, Pepco Energy Services reduced its asset retirement obligation related to the facility by $2 million. The demolition of the facility commenced in the fourth quarter of 2013 and is expected to be completed by the end of 2014. Pepco Energy Services will recognize the salvage proceeds associated with the scrap metals at the facility as realized.
Other Non-Regulated
Between 1990 and 1999, PCI, through various subsidiaries, entered into certain transactions involving investments in aircraft and aircraft equipment, railcars and other assets. In connection with these transactions, PCI recorded deferred tax assets in prior years of $101 million in the aggregate. Following events that took place during the first quarter of 2013, which included (i) court decisions in favor of the Internal Revenue Service (IRS) with respect to both Consolidated Edison’s cross-border lease transaction and another taxpayer’s structured transactions (see additional discussion at “- Discontinued Operations - Cross-Border Energy Lease Investments” below), (ii) the change in PHI’s tax position with respect to the tax benefits associated with its cross-border energy leases, and (iii) PHI’s decision in March 2013 to begin to pursue the early termination of its remaining cross-border energy lease investments (which represented a substantial portion of the remaining assets within PCI) without the intent to reinvest these proceeds in income-producing assets, management evaluated the likelihood that PCI would be able to realize the $101 million of deferred tax assets in the future. Based on this evaluation, PCI established valuation allowances against these deferred tax assets totaling $101 million in the first quarter of 2013. Further, during the fourth quarter of 2013, in light of additional court decisions in favor of the IRS involving other taxpayers, and after consideration of all relevant factors, management determined that it would abandon the further pursuit of these deferred tax assets, and these assets totaling $101 million were charged off against the previously established valuation allowances.
Discontinued Operations
Cross-Border Energy Lease Investments
Through its subsidiary PCI, PHI held a portfolio of cross-border energy lease investments. During July 2013, PHI completed the termination of its interest in its cross-border energy lease investments. With the completion of the termination of the cross-border energy leases, the cross-border energy lease investments are being accounted for as discontinued operations.
PEPCO HOLDINGS
As discussed in Note (15), “Commitments and Contingencies - PHI’s Cross-Border Energy Lease Investments,” PHI is involved in ongoing litigation with the IRS concerning certain benefits associated with previously held investments in cross-border energy leases. On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit issued an opinion in Consolidated Edison Company of New York, Inc. & Subsidiaries v. United States (to which PHI is not a party) that disallowed tax benefits associated with Consolidated Edison’s cross-border lease transaction. As a result of the court’s ruling in this case, PHI determined in the first quarter of 2013 that its tax position with respect to the benefits associated with its cross-border energy leases no longer met the more-likely-than-not standard of recognition for accounting purposes, and PCI recorded non-cash charges of $323 million (after-tax) in the first quarter of 2013 and $6 million (after-tax) in the second quarter of 2013, consisting of the following components:
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A non-cash pre-tax charge of $373 million ($313 million after-tax) to reduce the carrying value of these cross-border energy lease investments under Financial Accounting Standards Board (FASB) guidance on leases (Accounting Standards Codification (ASC) 840). This pre-tax charge was originally recorded in the consolidated statements of (loss) income as a reduction in operating revenue and is now reflected in (loss) income from discontinued operations, net of income taxes.
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A non-cash charge of $16 million after-tax to reflect the anticipated additional net interest expense under FASB guidance for income taxes (ASC 740), related to estimated federal and state income tax obligations for the period over which the tax benefits may be disallowed. This after-tax charge was originally recorded in the consolidated statements of (loss) income as an increase in income tax expense and is now reflected in (loss) income from discontinued operations, net of income taxes. The after-tax interest charge for PHI on a consolidated basis was $70 million and this amount was allocated to each member of PHI’s consolidated group as if each member was a separate taxpayer, resulting in the recognition of a $12 million interest benefit for the Power Delivery segment and interest expense of $16 million for PCI and $66 million for Corporate and Other, respectively.
Pepco Energy Services
In December 2009, PHI announced the wind-down of the retail energy supply component of the Pepco Energy Services business which was comprised of the retail electric and natural gas supply businesses. Pepco Energy Services implemented the wind-down by not entering into any new retail electric or natural gas supply contracts while continuing to perform under its existing retail electric and natural gas supply contracts through their respective expiration dates. On March 21, 2013, Pepco Energy Services entered into an agreement whereby a third party assumed all the rights and obligations of the remaining retail natural gas supply customer contracts, and the associated supply obligations, inventory and derivative contracts. The transaction was completed on April 1, 2013. In addition, Pepco Energy Services completed the wind-down of its retail electric supply business in the second quarter of 2013 by terminating its remaining customer supply and wholesale purchase obligations beyond June 30, 2013.
The operations of Pepco Energy Services’ retail electric and natural gas supply businesses have been classified as discontinued operations and are no longer a part of the Pepco Energy Services segment for financial reporting purposes.
(2) SIGNIFICANT ACCOUNTING POLICIES
Consolidation Policy
The accompanying consolidated financial statements include the accounts of Pepco Holdings and its wholly owned subsidiaries. All material intercompany balances and transactions between subsidiaries have been eliminated. Pepco Holdings uses the equity method to report investments, corporate joint ventures, partnerships, and affiliated companies in which it holds an interest and can exercise significant influence over the operations and policies of the entity. Certain transmission and other facilities currently held, are consolidated in proportion to PHI’s percentage interest in the facility.
PEPCO HOLDINGS
Consolidation of Variable Interest Entities
PHI assesses its contractual arrangements with variable interest entities to determine whether it is the primary beneficiary and thereby has to consolidate the entities in accordance with FASB ASC 810. The guidance addresses conditions under which an entity should be consolidated based upon variable interests rather than voting interests. See Note (16), “Variable Interest Entities,” for additional information.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) requires management to make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities in the consolidated financial statements and accompanying notes. Although Pepco Holdings believes that its estimates and assumptions are reasonable, they are based upon information available to management at the time the estimates are made. Actual results may differ significantly from these estimates.
Significant matters that involve the use of estimates include the assessment of contingencies, the calculation of future cash flows and fair value amounts for use in asset and goodwill impairment calculations, fair value calculations for derivative instruments, pension and other postretirement benefit assumptions, the assessment of the probability of recovery of regulatory assets, accrual of storm restoration costs, accrual of unbilled revenue, recognition of changes in network service transmission rates for prior service year costs, accrual of loss contingency liabilities for general and auto liability claims, accrual of interest related to income taxes, the recognition of lease income and income tax benefits for investments in finance leases held in trust associated with PHI’s portfolio of cross-border energy lease investments (see Note (19), “Discontinued Operations - Cross-Border Energy Lease Investments”), and income tax provisions and reserves. Additionally, PHI is subject to legal, regulatory and other proceedings and claims that arise in the ordinary course of its business. PHI records an estimated liability for these proceedings and claims when it is probable that a loss has been incurred and the loss is reasonably estimable.
Revenue Recognition
Regulated Revenue
Power Delivery recognizes revenue upon distribution of electricity and natural gas to its customers, including unbilled revenue for services rendered but not yet billed. PHI’s unbilled revenue was $177 million and $182 million as of December 31, 2013 and 2012, respectively, and these amounts are included in Accounts receivable. PHI’s utility subsidiaries calculate unbilled revenue using an output-based methodology. This methodology is based on the supply of electricity or natural gas intended for distribution to customers. The unbilled revenue process requires management to make assumptions and judgments about input factors such as customer sales mix, temperature and estimated line losses (estimates of electricity and natural gas expected to be lost in the process of its transmission and distribution to customers). The assumptions and judgments are inherently uncertain and susceptible to change from period to period, and if the actual results differ from the projected results, the impact could be material.
Taxes related to the consumption of electricity and natural gas by the utility customers, such as fuel, energy, or other similar taxes, are components of the tariff rates charged by PHI’s utility subsidiaries and, as such, are billed to customers and recorded in Operating revenue. Accruals for the remittance of these taxes are recorded in Other taxes.
PEPCO HOLDINGS
Pepco Energy Services Revenue
Revenue for Pepco Energy Services’ energy savings performance construction business is recognized using the percentage-of-completion method which recognizes revenue as work is completed on its contracts. Revenues from its operation and maintenance activities and measurement and verification activities in its energy savings business are recognized when earned.
Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions
Taxes included in PHI’s gross revenues were $346 million, $356 million and $378 million for the years ended December 31, 2013, 2012 and 2011, respectively.
Accounting for Derivatives
PHI and its subsidiaries may use derivative instruments primarily to manage risk associated with commodity prices and interest rates. Risk management policies are determined by PHI’s Corporate Risk Management Committee (CRMC). The CRMC monitors interest rate fluctuation, commodity price fluctuation and credit risk exposure, and sets risk management policies that establish limits on unhedged risk.
PHI accounts for its derivative activities in accordance with FASB guidance on derivatives and hedging. Derivatives are recorded on the consolidated balance sheets as Derivative assets or Derivative liabilities and measured at fair value.
Changes in the fair value of derivatives held by DPL that do not qualify for hedge accounting or are not designated as hedges are presented on the consolidated statements of (loss) income as Fuel and purchased energy expense or Operating revenue, respectively. Changes in the fair value of derivatives held by DPL are deferred as regulatory assets or liabilities under the accounting guidance for regulated operations.
The gain or loss on a derivative that qualifies as a cash flow hedge of an exposure to variable cash flows of a forecasted transaction is initially recorded in accumulated other comprehensive loss (AOCL) (a separate component of equity) to the extent that the hedge is effective and is subsequently reclassified into earnings, in the same category as the item being hedged, when the gain or loss from the forecasted transaction occurs. If it is probable that a forecasted transaction will not occur, the deferred gain or loss in AOCL is immediately reclassified to earnings. Gains or losses related to any ineffective portion of cash flow hedges are also recognized in earnings immediately.
Changes in the fair value of derivatives designated as fair value hedges, as well as changes in the fair value of the hedged asset, liability or firm commitment, are recorded in the consolidated statements of (loss) income.
The impact of derivatives that are marked to market through current earnings, the ineffective portion of cash flow hedges, and the portion of fair value hedges that flows to current earnings are presented on a net basis in the consolidated statements of (loss) income as Operating revenue or as Fuel and purchased energy expense. When a hedging gain or loss is realized, it is presented on a net basis in the same line item as the underlying item being hedged. Unrealized derivative gains and losses are presented gross on the consolidated balance sheets except where contractual netting agreements are in place with individual counterparties.
The fair value of derivatives is determined using quoted exchange prices where available. For instruments that are not traded on an exchange, pricing services and external broker quotes may also be used to determine fair value. For some custom and complex instruments, internal models use market-based information when external broker quotes are not available. For certain long-dated instruments, broker or exchange data are extrapolated, or capacity prices are forecasted, for future periods where information is limited. Models are also used to estimate volumes for certain transactions.
PEPCO HOLDINGS
PHI may enter into master netting arrangements to mitigate credit risk related to its derivatives. Under FASB guidance on offsetting of balance sheet accounts (ASC 210-20), amounts recognized for derivative assets and liabilities and the fair value amounts recognized for any related collateral positions executed with the same counterparty under such master netting agreements are offset.
See Note (13), “Derivative Instruments and Hedging Activities,” for more information about the types of derivatives employed by PHI, the components of any unrealized and realized gains and losses and Note (14), “Fair Value Disclosures,” for the methodologies used to value them.
Stock-Based Compensation
PHI recognizes compensation expense for stock-based awards, modifications or cancellations based on the grant-date fair value. Compensation expense is recognized over the requisite service period. A deferred tax asset and deferred tax benefit are also recognized concurrently with compensation expense for the tax effect of the deduction of stock options and restricted stock awards, which are deductible only upon exercise and vesting.
Historically, PHI’s compensation awards had included both time-based restricted stock awards that vest over a three-year service period and performance-based restricted stock units that were earned based on performance over a three-year period. Beginning in 2011, stock-based compensation awards have been granted primarily in the form of restricted stock units. The compensation expense associated with these awards is calculated based on the estimated fair value of the awards at the grant date and is recognized over the service or performance period.
PHI estimated the fair value of stock option awards on the date of grant using the Black-Scholes-Merton option pricing model. This model used assumptions related to expected term, expected volatility, expected dividend yield, and the risk-free interest rate. PHI used historical data to estimate award exercises and employee terminations within the valuation model; groups of employees that have similar historical exercise behavior were considered separately for valuation purposes.
PHI’s current policy is to issue new shares to satisfy vested awards of restricted stock units.
Income Taxes
PHI and the majority of its subsidiaries file a consolidated federal income tax return. Federal income taxes are allocated among PHI and the subsidiaries included in its consolidated group pursuant to a written tax sharing agreement, which was approved by the Securities and Exchange Commission (SEC) in 2002 in connection with the establishment of PHI as a public utility holding company. Under this tax sharing agreement, PHI’s consolidated federal income tax liability is allocated based upon PHI’s and its subsidiaries’ separate taxable income or loss amounts.
The consolidated financial statements include current and deferred income taxes. Current income taxes represent the amount of tax expected to be reported on PHI’s and its subsidiaries’ federal and state income tax returns. Deferred income tax assets and liabilities represent the tax effects of temporary differences between the financial statement basis and tax basis of existing assets and liabilities, and they are measured using presently enacted tax rates. See Note (11), “Income Taxes,” for a listing of primary deferred tax assets and liabilities. The portions of Pepco’s, DPL’s and ACE’s deferred tax liabilities applicable to their utility operations that have not been recovered from utility customers represent income taxes recoverable in the future and are included in Regulatory Assets on the consolidated balance sheets. See Note (7), “Regulatory Matters - Regulatory Assets and Regulatory Liabilities,” for additional information.
PEPCO HOLDINGS
PHI recognizes interest on underpayments and overpayments of income taxes, interest on uncertain tax positions and tax-related penalties in income tax expense. Deferred income tax expense generally represents the net change during the reporting period in the net deferred tax liability and deferred recoverable income taxes.
Investment tax credits are amortized to income over the useful lives of the related property.
Cash and Cash Equivalents
Cash and cash equivalents include cash on hand, cash invested in money market funds and commercial paper held with original maturities of three months or less.
Restricted Cash Equivalents
The Restricted cash equivalents included in Current assets and the Restricted cash equivalents included in Other assets consist of (i) cash held as collateral that is restricted from use for general corporate purposes and (ii) cash equivalents that are specifically segregated based on management’s intent to use such cash equivalents for a particular purpose. The classification as current or non-current conforms to the classification of the related liabilities.
Accounts Receivable and Allowance for Uncollectible Accounts
PHI’s Accounts receivable balances primarily consist of customer accounts receivable arising from the sale of goods and services to customers within PHI’s service territories, other accounts receivable, and accrued unbilled revenue. Accrued unbilled revenue represents revenue earned in the current period but not billed to the customer until a future date (usually within one month after the receivable is recorded).
PHI maintains an allowance for uncollectible accounts and changes in the allowance are recorded as an adjustment to Other operation and maintenance expense in the consolidated statements of (loss) income. PHI determines the amount of the allowance based on specific identification of material amounts at risk by customer and maintains a reserve based on its historical collection experience. The adequacy of this allowance is assessed on a quarterly basis by evaluating all known factors, such as the aging of the receivables, historical collection experience, the economic and competitive environment and changes in the creditworthiness of its customers. Accounts receivable are written off in the period in which the receivable is deemed uncollectible and collection efforts have been exhausted. Recoveries of Accounts receivable previously written off are recorded when it is probable they will be recovered. Although PHI believes its allowance is adequate, it cannot anticipate with any certainty the changes in the financial condition of its customers. As a result, PHI records adjustments to the allowance for uncollectible accounts in the period in which the new information that requires an adjustment to the reserve becomes known.
Inventories
Inventory is valued at the lower of cost or market value. Included in Inventories are generation, transmission and distribution materials and supplies, natural gas and fuel oil.
PHI utilizes the weighted average cost method of accounting for inventory items. Under this method, an average price is determined for the quantity of units acquired at each price level and is applied to the ending quantity to calculate the total ending inventory balance. Materials and supplies are recorded in Inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed.
The cost of natural gas, including transportation costs, is included in Inventory when purchased and charged to Fuel and Purchased Energy expense when used.
PEPCO HOLDINGS
Goodwill
Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired at the acquisition date. PHI tests its goodwill for impairment annually as of November 1 and whenever an event occurs or circumstances change in the interim that would more likely than not (that is, a greater than 50% chance) reduce the estimated fair value of a reporting unit below the carrying amount of its net assets. Factors that may result in an interim impairment test include, but are not limited to: a change in the identified reporting units; an adverse change in business conditions; a protracted decline in PHI’s stock price causing market capitalization to fall significantly below book value; an adverse regulatory action; or an impairment of long-lived assets in the reporting unit. PHI performed its most recent annual impairment test as of November 1, 2013, and its goodwill was not impaired as described in Note (6), “Goodwill.”
Regulatory Assets and Regulatory Liabilities
The operations of Pepco are regulated by the District of Columbia Public Service Commission (DCPSC) and the Maryland Public Service Commission (MPSC). The operations of DPL are regulated by the Delaware Public Service Commission (DPSC) and the MPSC. DPL’s interstate transportation and wholesale sale of natural gas are regulated by the Federal Energy Regulatory Commission (FERC). The operations of ACE are regulated by the New Jersey Board of Public Utilities (NJBPU). The transmission of electricity by Pepco, DPL and ACE is regulated by FERC.
The FASB guidance on regulated operations (ASC 980) applies to Power Delivery. It allows regulated entities, in appropriate circumstances, to defer the income statement impact of certain costs that are expected to be recovered in future rates through the establishment of regulatory assets and defer certain revenues that are expected to be refunded to customers through the establishment of regulatory liabilities. Management’s assessment of the probability of recovery of regulatory assets requires judgment and interpretation of laws, regulatory commission orders and other factors. If management subsequently determines, based on changes in facts or circumstances, that a regulatory asset is not probable of recovery, then the regulatory asset would be eliminated through a charge to earnings.
Effective June 2007, the MPSC approved a bill stabilization adjustment (BSA) mechanism for retail customers of Pepco and DPL. Effective November 2009, the DCPSC approved a BSA for Pepco’s retail customers. For customers to whom the BSA applies, Pepco and DPL recognize distribution revenue based on an approved distribution charge per customer. From a revenue recognition standpoint, the BSA has the effect of decoupling the distribution revenue recognized in a reporting period from the amount of power delivered during that period. Pursuant to this mechanism, Pepco and DPL recognize either (i) a positive adjustment equal to the amount by which revenue from Maryland and the District of Columbia retail distribution sales falls short of the revenue that Pepco and DPL are entitled to earn based on the approved distribution charge per customer, or (ii) a negative adjustment equal to the amount by which revenue from such distribution sales exceeds the revenue that Pepco and DPL are entitled to earn based on the approved distribution charge per customer (a Revenue Decoupling Adjustment). A net positive Revenue Decoupling Adjustment is recorded as a regulatory asset and a net negative Revenue Decoupling Adjustment is recorded as a regulatory liability.
Leasing Activities
Pepco Holdings’ lease transactions include plant, office space, equipment, software, vehicles and elements of power purchase agreements (PPAs). In accordance with FASB guidance on leases (ASC 840), these leases are classified as either leveraged leases, operating leases or capital leases.
PEPCO HOLDINGS
Leveraged Leases
Income from investments in leveraged lease transactions, in which PHI is an equity participant, was accounted for using the financing method. In accordance with the financing method, investments in leased property were recorded as a receivable from the lessee to be recovered through the collection of future rentals. Income was recognized over the life of the lease at a constant rate of return on the positive net investment. Each quarter, PHI reviewed the carrying value of each lease, which included a review of the underlying financial assumptions, the timing and collectibility of cash flows, and the credit quality of the lessee. Changes to the underlying assumptions, if any, were accounted for in accordance with FASB guidance on leases and reflected in the carrying value of the lease effective for the quarter within which they occurred.
Operating Leases
An operating lease in which PHI or a subsidiary is the lessee generally results in a level income statement charge over the term of the lease, reflecting the rental payments required by the lease agreement. If rental payments are not made on a straight-line basis, PHI’s policy is to recognize rent expense on a straight-line basis over the lease term unless another systematic and rational allocation basis is more representative of the time pattern in which the leased property is physically employed.
Capital Leases
For ratemaking purposes, capital leases in which PHI or a subsidiary is the lessee are treated as operating leases; therefore, in accordance with FASB guidance on regulated operations (ASC 980), the amortization of the leased asset is based on the recovery of rental payments through customer rates. Investments in equipment under capital leases are stated at cost, less accumulated depreciation. Depreciation is recorded on a straight-line basis over the equipment’s estimated useful life.
Arrangements Containing a Lease
PPAs contain a lease if the arrangement conveys the right to control the use of property, plant or equipment. If so, PHI determines the appropriate lease accounting classification.
Property, Plant and Equipment
Property, plant and equipment is recorded at original cost, including labor, materials, asset retirement costs and other direct and indirect costs including capitalized interest. The carrying value of Property, plant and equipment is evaluated for impairment whenever circumstances indicate the carrying value of those assets may not be recoverable. Upon retirement, the cost of regulated property, net of salvage, is charged to Accumulated depreciation. For non-regulated property, the cost and accumulated depreciation of the property, plant and equipment retired or otherwise disposed of are removed from the related accounts and included in the determination of any gain or loss on disposition.
The annual provision for depreciation on electric and natural gas property, plant and equipment is computed on a straight-line basis using composite rates by classes of depreciable property. Accumulated depreciation is charged with the cost of depreciable property retired, less salvage and other recoveries. Non-operating and other property is generally depreciated on a straight-line basis over the useful lives of the assets. The table below provides system-wide composite annual depreciation rates for the years ended December 31, 2013, 2012 and 2011.
(a) Percentages reflect accelerated depreciation of the Benning Road and Buzzard Point generating facilities retired during 2012.
PEPCO HOLDINGS
In 2010, subsidiaries of PHI received awards from the U.S. Department of Energy (DOE) under the American Recovery and Reinvestment Act of 2009. Pepco was awarded $149 million from DOE to fund a portion of the costs incurred for the implementation of an advanced metering infrastructure (AMI) system (a system that collects, measures and analyzes energy usage data from advanced digital meters known as smart meters), direct load control, distribution automation and communications infrastructure in its Maryland and District of Columbia service territories. ACE was awarded $19 million from DOE to fund a portion of the costs incurred for the implementation of direct load control, distribution automation and communications infrastructure in its New Jersey service territory. PHI has elected to recognize the award proceeds as a reduction in the carrying value of the assets acquired rather than grant income over the service period.
Long-Lived Asset Impairment Evaluation
PHI evaluates long-lived assets to be held and used, such as generating property and equipment, and real estate, for impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. Examples of such events or changes include a significant decrease in the market price of a long-lived asset or a significant adverse change in the manner in which an asset is being used or its physical condition. A long-lived asset to be held and used is written down to its estimated fair value if the expected future undiscounted cash flow from the asset is less than its carrying value.
For long-lived assets held for sale, an impairment loss is recognized to the extent that the asset’s carrying value exceeds its estimated fair value including costs to sell.
Capitalized Interest and Allowance for Funds Used During Construction
In accordance with FASB guidance on regulated operations (ASC 980), PHI’s utility subsidiaries can capitalize the capital costs of financing the construction of plant and equipment as allowance for funds used during construction (AFUDC). This results in the debt portion of AFUDC being recorded as a reduction of Interest expense and the equity portion of AFUDC being recorded as an increase to Other income in the accompanying consolidated statements of (loss) income.
Pepco Holdings recorded AFUDC for borrowed funds of $7 million, $7 million and $11 million for the years ended December 31, 2013, 2012 and 2011, respectively.
Pepco Holdings recorded amounts for the equity component of AFUDC of $11 million, $14 million and $15 million for the years ended December 31, 2013, 2012 and 2011, respectively.
Amortization of Debt Issuance and Reacquisition Costs
Pepco Holdings defers and amortizes debt issuance costs and long-term debt premiums and discounts over the lives of the respective debt issuances. When PHI utility subsidiaries refinance existing debt or redeem existing debt, any unamortized premiums, discounts and debt issuance costs, as well as debt redemption costs, are classified as Regulatory assets and are amortized over the life of the original or new issue.
Asset Removal Costs
In accordance with FASB guidance, asset removal costs are recorded by PHI utility subsidiaries as Regulatory liabilities. At December 31, 2013 and 2012, $275 million and $324 million, respectively, of asset removal costs are included in Regulatory liabilities in the accompanying consolidated balance sheets.
PEPCO HOLDINGS
Pension and Postretirement Benefit Plans
PHI sponsors the PHI Retirement Plan, a non-contributory, defined benefit pension plan that covers substantially all employees of Pepco, DPL, ACE and certain employees of other PHI subsidiaries. PHI also provides supplemental retirement benefits to certain eligible executives and key employees through nonqualified retirement plans and provides certain postretirement health care and life insurance benefits for eligible retired employees. Most employees hired after January 1, 2005 will not have retiree health care coverage.
Net periodic benefit cost is included in Other operation and maintenance expense, net of the portion of the net periodic benefit cost capitalized as part of the cost of labor for internal construction projects. After intercompany allocations, the three utility subsidiaries are responsible for substantially all of the total PHI net periodic benefit cost.
PHI accounts for the PHI Retirement Plan, the nonqualified retirement plans, and the retirement health care and life insurance benefit plans in accordance with FASB guidance on retirement benefits (ASC 715).
See Note (9), “Pension and Other Postretirement Benefits,” for additional information.
Reclassifications and Adjustments
Certain prior period amounts have been reclassified in order to conform to the current period presentation. The following adjustments have been recorded and are not considered material individually or in the aggregate to either the current period or prior period financial results:
Income Tax Expense Related to Continuing Operations
During 2013, Pepco recorded certain adjustments to correct prior period errors related to income taxes. These adjustments resulted from the completion of additional analysis of deferred tax balances and resulted in an increase in Income tax expense of $4 million, for the year ended December 31, 2013.
During 2011, PHI recorded adjustments to correct certain income tax errors related to prior periods associated with the interest on uncertain tax positions. The adjustment resulted in an increase in Income tax expense of $2 million for the year ended December 31, 2011.
Pepco Energy Services Derivative Accounting Adjustment
During 2011, PHI recorded an adjustment associated with an increase in the value of certain derivatives from October 1, 2010 to December 31, 2010, which had been erroneously recorded in other comprehensive income at December 31, 2010. This adjustment resulted in a decrease in Loss from discontinued operations, net of income taxes of $1 million for the year ended December 31, 2011.
DPL Operating Revenue Adjustment
During 2012, DPL recorded an adjustment to correct an overstatement of unbilled revenue in its natural gas distribution business related to prior periods. The adjustment resulted in a decrease in Operating revenue of $1 million for the year ended December 31, 2012.
DPL Default Electricity Supply Revenue and Cost Adjustments
During 2011, DPL recorded adjustments to correct certain errors associated with the accounting for Default Electricity Supply revenue and costs. These adjustments primarily arose from the under-recognition of allowed returns on the cost of working capital and resulted in a pre-tax decrease in Other operation and maintenance expense of $11 million for the year ended December 31, 2011.
PEPCO HOLDINGS
ACE BGS Deferred Electric Service Costs Adjustments
In 2012, ACE recorded an adjustment to correct errors associated with its calculation of deferred electric service costs. This adjustment resulted in an increase of $3 million to deferred electric service costs, all of which relates to periods prior to 2012.
Revision to Prior Period Financial Statements
PCI Deferred Income Tax Liability Adjustment
Since 1999, PCI had not recorded a deferred tax liability related to a temporary difference between the financial reporting basis and the tax basis of an investment in a wholly owned partnership. In the second quarter of 2013, PHI re-evaluated this accounting treatment and found it to be in error, requiring an adjustment related to prior periods. PHI determined that the cumulative adjustment required, representing a charge to earnings of $32 million, related to a period prior to the year ended December 31, 2009 (the earliest period for which selected consolidated financial data is presented in the table entitled “Selected Financial Data” in Part II, Item 6 of this Annual Report on Form 10-K). Consistent with PHI’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2013, the accompanying consolidated financial statements reflect the correction of this error as an adjustment to shareholders’ equity for the earliest period presented. The adjustment to correct the error did not affect PHI’s consolidated statements of (loss) income, comprehensive (loss) income and cash flows for each of the three years in the period ended December 31, 2013, and only affected PHI’s reported balances of deferred income tax liabilities and retained earnings as reflected in the consolidated balance sheets as of December 31, 2013 and 2012 and the reported balances of retained earnings and total equity as reflected in the consolidated statements of equity for each of the three years in the period ended December 31, 2013. The adjustment is not considered to be material to PHI’s reported balances of retained earnings and total equity reflected in the PHI consolidated financial statements included in this Annual Report on Form 10-K. The table below illustrates the effects of the revision on reported balances in PHI’s consolidated financial statements.
(a) The amount of total deferred credits differs from the amount orginially reported in PHI’s 2012 Form 10-K due to certain reclassifications.
(b) The amount represents total shareholders’ equity, which excludes a non-controlling interest of $6 million.
PEPCO HOLDINGS
(3) NEWLY ADOPTED ACCOUNTING STANDARDS
Balance Sheet (ASC 210)
In December 2011, the FASB issued new disclosure requirements for financial assets and financial liabilities, such as derivatives, that are subject to contractual netting arrangements. The new disclosure requirements include information about the gross exposure of the instruments and the net exposure of the instruments under contractual netting arrangements, how the exposures are presented in the financial statements, and the terms and conditions of the contractual netting arrangements. PHI adopted the new guidance during the first quarter of 2013 and concluded it did not have a material impact on its consolidated financial statements.
Comprehensive Income (ASC 220)
The new disclosure requirements for reclassifications from accumulated other comprehensive income were effective for PHI beginning with its March 31, 2013 consolidated financial statements and required PHI to present additional information about its reclassifications from accumulated other comprehensive income in a single footnote or on the face of its consolidated financial statements. The additional information required to be disclosed includes a presentation of the components of accumulated other comprehensive income that have been reclassified by source (e.g., commodity derivatives), and the income statement line item (e.g., Fuel and purchased energy) affected by the reclassification. PHI has provided the new required disclosures in Note (17), “Accumulated Other Comprehensive Loss.”
(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED
Joint and Several Liability Arrangements (ASC 405)
In February 2013, the FASB issued new recognition and disclosure requirements for certain joint and several liability arrangements where the total amount of the obligation is fixed at the reporting date. For arrangements within the scope of this standard, PHI will be required to include in its liabilities the additional amounts it expects to pay on behalf of its co-obligors, if any. PHI will also be required to provide additional disclosures including the nature of the arrangements with its co-obligors, the total amounts outstanding under the arrangements between PHI and its co-obligors, the carrying value of the liability, and the nature and limitations of any recourse provisions that would enable recovery from other entities.
The new requirements are effective retroactively beginning on January 1, 2014, with implementation required for prior periods if joint and several liability arrangement obligations exist as of January 1, 2014. PHI does not expect this new guidance to have a material impact on its consolidated financial statements.
Income Taxes (ASC 740)
In July 2013, the FASB issued new guidance that will require the netting of certain unrecognized tax benefits against a deferred tax asset for a loss or other similar tax carryforward that would apply upon settlement of the uncertain tax position. The new requirements are effective prospectively beginning with PHI’s March 31, 2014 consolidated financial statements for all unrecognized tax benefits existing at the adoption date. Retrospective implementation and early adoption of the guidance are permitted. PHI does not expect this new guidance to have a material impact on its consolidated financial statements.
PEPCO HOLDINGS
(5) SEGMENT INFORMATION
Pepco Holdings’ management has identified its operating segments at December 31, 2013 as Power Delivery and Pepco Energy Services. In the tables below, the Corporate and Other column is included to reconcile the segment data with consolidated data and includes unallocated Pepco Holdings’ (parent company) capital costs, such as financing costs. Through its subsidiary PCI, PHI maintained a portfolio of cross-border energy lease investments. PHI completed the termination of its interests in its cross-border energy lease investments during 2013. As a result, the cross-border energy lease investments, which comprised substantially all of the operations of the former Other Non-Regulated segment, are being accounted for as discontinued operations. The remaining operations of the former Other Non-Regulated segment, which no longer meet the definition of a separate segment for financial reporting purposes, are now included in Corporate and Other. Segment financial information for continuing operations at and for the years ended December 31, 2013, 2012 and 2011, is as follows:
(a) Total Assets in this column includes Pepco Holdings’ goodwill balance of $1.4 billion, all of which is allocated to Power Delivery for purposes of assessing impairment. Total assets also include capital expenditures related to certain hardware and software expenditures which primarily benefit Power Delivery. These expenditures are recorded as incurred in Corporate and Other and are allocated to Power Delivery once the assets are placed in service. Corporate and Other includes intercompany amounts of $(10) million for Operating Revenue, $(9) million for Operating Expenses and $(5) million for Interest Expense.
(b) Includes depreciation and amortization expense of $473 million, consisting of $439 million for Power Delivery, $6 million for Pepco Energy Services and $28 million for Corporate and Other.
(c) Includes after-tax interest associated with uncertain and effectively settled tax positions allocated to each member of the consolidated group, including a $12 million interest benefit for Power Delivery and interest expense of $66 million for Corporate and Other.
(d) Includes non-cash charges of $101 million representing the establishment of valuation allowances against certain deferred tax assets of PCI included in Corporate and Other.
(e) Includes pre-tax impairment losses of $4 million ($3 million after-tax) at Pepco Energy Services associated with a landfill gas-fired electric generation facility.
PEPCO HOLDINGS
(a) Total Assets in this column includes Pepco Holdings’ goodwill balance of $1.4 billion, all of which is allocated to Power Delivery for purposes of assessing impairment. Total assets also include capital expenditures related to certain hardware and software expenditures which primarily benefit Power Delivery. These expenditures are recorded as incurred in Corporate and Other and are allocated to Power Delivery once the assets are placed in service. Corporate and Other includes intercompany amounts of $(11) million for Operating Revenue, $(10) million for Operating Expenses, $(21) million for Interest Income and $(18) million for Interest Expense.
(b) Includes $9 million of intra-company revenues (and associated costs) previously eliminated in consolidation which will continue to be recognized from third parties subsequent to the completion of the wind-down of the Pepco Energy Services’ retail electric and natural gas supply businesses.
(c) Includes depreciation and amortization expense of $454 million, consisting of $416 million for Power Delivery, $14 million for Pepco Energy Services and $24 million for Corporate and Other.
(d) Includes impairment losses of $12 million pre-tax ($7 million after-tax) at Pepco Energy Services associated primarily with investments in landfill gas-fired electric generation facilities, and the combustion turbines at Buzzard Point.
(a) Total Assets in this column includes Pepco Holdings’ goodwill balance of $1.4 billion, all of which is allocated to Power Delivery for purposes of assessing impairment. Total assets also include capital expenditures related to certain hardware and software expenditures which primarily benefit Power Delivery. These expenditures are recorded as incurred in Corporate and Other and are allocated to Power Delivery once the assets are placed in service. Corporate and Other includes intercompany amounts of $(16) million for Operating Revenue, $(15) million for Operating Expense, $(22) million for Interest Income and $(22) million for Interest Expense.
(b) Includes $15 million of intra-company revenues (and associated costs) previously eliminated in consolidation which will continue to be recognized from third parties subsequent to the completion of the wind-down of the Pepco Energy Services’ retail electric and natural gas supply businesses.
(c) Includes depreciation and amortization expense of $425 million, consisting of $394 million for Power Delivery, $16 million for Pepco Energy Services and $15 million for Corporate and Other.
(d) Includes tax benefits of $14 million for Power Delivery primarily associated with an interest benefit related to federal tax liabilities.
PEPCO HOLDINGS
(6) GOODWILL
Substantially all of PHI’s goodwill balance as of December 31, 2013 and 2012 was generated by Pepco’s acquisition of Conectiv in 2002 and is allocated entirely to the Power Delivery reporting unit based on the aggregation of its regulated public utility company components for purposes of assessing impairment under FASB guidance on goodwill and other intangibles (ASC 350).
In order to estimate the fair value of the Power Delivery reporting unit, PHI uses two valuation techniques: an income approach and a market approach. The income approach estimates fair value based on a discounted future cash flow analysis and a terminal value that is consistent with Power Delivery’s long-term view of the business. This approach uses a discount rate based on the estimated weighted average cost of capital (WACC) for the reporting unit. PHI determines the estimated WACC by considering appropriate market-based information for the cost of equity and cost of debt as of the measurement date. The market approach estimates fair value based on a multiple of earnings before interest, taxes, depreciation, and amortization (EBITDA) that management believes is consistent with EBITDA multiples for comparable utilities. PHI has consistently used this valuation technique to estimate the fair value of Power Delivery.
The estimation of fair value is dependent on a number of factors including but not limited to interest rates, growth assumptions, returns on rate base, operating and capital expenditure requirements, and other factors, changes in which could materially affect the results of impairment testing. Assumptions used were consistent with historical experience, including assumptions concerning the recovery of operating costs and capital expenditures and current market-based information. Sensitive, interrelated and uncertain variables that could decrease the estimated fair value of the Power Delivery reporting unit include utility sector market performance, sustained adverse business conditions, changes in forecasted revenues, higher operating and maintenance capital expenditure requirements, a significant increase in the weighted-average cost of capital and other factors.
In addition to estimating the fair value of its Power Delivery reporting unit, PHI estimated the fair value of its other reporting units at November 1, 2013. The sum of the estimated fair values of all reporting units was reconciled to PHI’s market capitalization at November 1, 2013 to corroborate PHI’s estimates of the fair values of its reporting units. The sum of the estimated fair values of all reporting units exceeded the market capitalization of PHI at November 1, 2013. PHI believes that the excess of the estimated fair value of PHI’s reporting units as compared to PHI’s market capitalization reflects a control premium that is reasonable when compared to control premiums observed in historical acquisitions in the utility industry and giving consideration to the current economic environment.
As of December 31, 2013 and 2012, PHI’s goodwill balance was $1,407 million, which is net of accumulated impairment losses of $18 million.
PEPCO HOLDINGS
(7) REGULATORY MATTERS
Regulatory Assets and Regulatory Liabilities
The components of Pepco Holdings’ regulatory asset and liability balances at December 31, 2013 and 2012 are as follows:
(a) A return is generally earned on these deferrals.
A description for each category of regulatory assets and regulatory liabilities follows:
Pension and OPEB Costs: Represents unrecognized net actuarial losses and prior service cost (credit) for Pepco Holdings’ defined benefit pension and other postretirement benefit (OPEB) plans that are expected to be recovered by Pepco, DPL and ACE in rates. The utilities have historically included these items as a part of its cost of service in its customer rates. This regulatory asset is adjusted at least annually when the funded status of Pepco Holdings’ defined benefit pension and OPEB plans are re-measured. See Note (9), “Pension and Other Postretirement Benefits,” for more information about the components of the unrecognized pension and OPEB costs.
Securitized Stranded Costs: Certain contract termination payments under a contract between ACE and an unaffiliated non-utility generator (NUG) and costs associated with the regulated operations of ACE’s electricity generation business are no longer recoverable through customer rates (collectively referred to as “stranded costs”). The stranded costs are amortized over the life of Transition Bonds issued by Atlantic City Electric Transition Funding LLC (ACE Funding) (Transition Bonds) to securitize the recoverability of these stranded costs. These bonds mature between 2014 and 2023. A customer surcharge is collected by ACE to fund principal and interest payments on the Transition Bonds.
PEPCO HOLDINGS
Smart Grid Costs: Represents AMI costs associated with the installation of smart meters and the early retirement of existing meters throughout Pepco’s and DPL’s service territories that are recoverable from customers. AMI has not been approved by the NJBPU for ACE in New Jersey.
Recoverable Income Taxes: Represents amounts recoverable from Power Delivery’s customers for tax benefits applicable to utility operations of Pepco, DPL and ACE previously recognized in income tax expense before the companies were ordered to account for the tax benefits as deferred income taxes. As the temporary differences between the financial statement basis and tax basis of assets reverse, the deferred recoverable balances are reversed.
Deferred Energy Supply Costs: The regulatory asset represents primarily deferred costs associated with a net under-recovery of Default Electricity Supply costs incurred by Pepco, DPL and ACE that are probable of recovery in rates. The regulatory liability represents primarily deferred costs associated with a net over-recovery of Default Electricity Supply costs incurred that will be refunded by Pepco, DPL and ACE to customers.
Demand-Side Management Costs: Represents recoverable costs associated with customer energy efficiency and conservation programs in Pepco’s and DPL’s Maryland jurisdictions.
Incremental Storm Restoration Costs: Represents total incremental storm restoration costs incurred for repair work due to major storm events in 2012 and 2011, including Hurricane Sandy, the June 2012 derecho, Hurricane Irene and the 2011 severe winter storm (for Pepco), that are recoverable from customers in the Maryland and New Jersey jurisdictions. Pepco’s and DPL’s costs related to Hurricane Sandy, the June 2012 derecho, Hurricane Irene and Pepco’s costs related to the 2011 severe winter storm are being amortized and recovered in rates, each over a five-year period. ACE’s costs related to Hurricane Sandy, the June 2012 derecho and Hurricane Irene are being amortized and recovered in rates, each over a three-year period.
MAPP Abandonment Costs: Represents the probable recovery of abandoned costs prudently incurred in connection with the Mid-Atlantic Power Pathway (MAPP) project which was terminated by PJM Interconnection, LLC (PJM) on August 24, 2012. The regulatory asset includes the costs of land, land rights, supplies and materials, engineering and design, environmental services, and project management and administration. The regulatory asset will be reduced as the result of sale or alternative use of these assets. As of December 31, 2013, these assets were earning a return of 12.8%. For additional information, see “MAPP Project” discussion below.
Deferred Debt Extinguishment Costs: Represents the costs of debt extinguishment of Pepco, DPL and ACE associated with issuances of debt for which recovery through regulated utility rates is considered probable, and if approved, will be amortized to interest expense during the authorized rate recovery period.
Recoverable Workers’ Compensation and Long-Term Disability Costs: Represents accrued workers’ compensation and long-term disability costs for Pepco, which are recoverable from customers when actual claims are paid to employees.
Deferred Losses on Gas Derivatives: Represents losses associated with hedges of natural gas purchases that are recoverable through the Gas Cost Rate approved by the DPSC.
Other: Represents miscellaneous regulatory assets that generally are being amortized over 1 to 20 years.
Asset Removal Costs: The depreciation rates for Pepco and DPL include a component for removal costs, as approved by the relevant federal and state regulatory commissions. Accordingly, Pepco and DPL have recorded regulatory liabilities for their estimate of the difference between incurred removal costs and the amount of removal costs recovered through depreciation rates.
PEPCO HOLDINGS
Deferred Income Taxes Due to Customers: Represents the portions of deferred income tax assets applicable to utility operations of Pepco and DPL that have not been reflected in current customer rates for which future payment to customers is probable. As the temporary differences between the financial statement basis and tax basis of assets reverse, deferred recoverable income taxes are amortized.
Deferred Gains on Gas Derivatives: Represents gains associated with hedges of natural gas purchases that will be refunded to customers through the Gas Cost Rate approved by the DPSC.
Excess Depreciation Reserve: The excess depreciation reserve was recorded as part of an ACE New Jersey rate case settlement. This excess reserve is the result of a change in estimated depreciable lives and a change in depreciation technique from remaining life to whole life that caused an over-recovery for depreciation expense from customers when the remaining life method had been used. The excess was amortized as a reduction in Depreciation and amortization expense over an 8.25 year period, and expired in 2013.
Other: Includes miscellaneous regulatory liabilities.
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.
(a) Reflects Pepco’s updated revenue requirement as filed on December 3, 2013.
(b) Reflects DPL’s updated revenue requirement as filed on September 20, 2013.
The following table shows, for each of PHI’s utility subsidiaries, the distribution base rate cases completed in 2013. Additional information concerning each of these cases is provided in the discussion below.
(a) Return on equity (ROE) has not been determined by any proceeding and is specified only for the purposes of calculating the AFUDC and regulatory asset carrying costs.
(b) ROE has not been determined by any proceeding and is specified only for reporting purposes and for calculating the AFUDC, construction work in process (CWIP), regulatory asset carrying costs and other accounting metrics.
PEPCO HOLDINGS
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:
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A BSA has been approved and implemented for Pepco and DPL electric service in Maryland and for Pepco electric service in the District of Columbia.
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A proposed modified fixed variable rate design (MFVRD) for DPL electric and natural gas service in Delaware was filed in 2009 for consideration by the DPSC and while there was little activity associated with this filing in 2013, the proceeding remains open.
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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 filing seeks approval of an annual rate increase of approximately $39 million (as adjusted by DPL on September 20, 2013), based on a requested 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. A final DPSC decision is expected by the second quarter of 2014.
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 pending electric distribution base rate case discussed above was concluded. DPL expects that the FLRP will be updated and re-filed at the conclusion of the electric distribution base rate case. A schedule for the FLRP docket has not yet been established.
PEPCO HOLDINGS
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 sought approval of an annual rate increase of approximately $12.0 million (as adjusted by DPL on July 15, 2013), based on a requested ROE of 10.25%. The requested rate increase sought to recover expenses associated with DPL’s ongoing efforts to maintain safe and reliable gas service. On October 22, 2013, the DPSC approved a settlement entered into on August 27, 2013 by the DPSC Staff, the Delaware Division of the Public Advocate and DPL, which provides for an annual rate increase of $6.8 million. While the approved settlement provided that no understanding was reached concerning the appropriate ROE, it specified that for reporting purposes and for calculating the AFUDC, CWIP, regulatory asset carrying costs and other accounting metrics, the rate of 9.75% should be used. The new rates became effective on November 1, 2013.
The approved settlement also provides 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 its 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 May 1, 2014, and the remainder will be put into rates on March 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.
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.
District of Columbia
On March 8, 2013, Pepco filed an application with the DCPSC to increase its annual electric distribution base rates by approximately $44.8 million (as adjusted by Pepco on December 3, 2013), 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. Evidentiary hearings were held in November 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 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 sought to recover expenses associated with DPL’s ongoing investments in reliability enhancement improvements and efforts to maintain safe and reliable service. 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 “Resiliency 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 did 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.
PEPCO HOLDINGS
On August 30, 2013, the MPSC issued a final order approving a settlement among DPL, the MPSC staff and the Maryland Office of People’s Counsel (OPC). The approved settlement provides for an annual rate increase of approximately $15 million. While the settlement does not specify an overall ROE, the parties did agree that the ROE for purposes of calculating the AFUDC and regulatory asset carrying costs would be 9.81%. The approved settlement also provides for (i) 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, and (ii) 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 before implementing the surcharge, DPL provides additional information to the MPSC 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 approved 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. The new rates became effective on September 15, 2013.
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 additionally authorized Pepco to recover the actual cost of AMI meters installed during the 2011 test year and states 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 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 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.
PEPCO HOLDINGS
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 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 provides additional information to the MPSC 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 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.
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, 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.
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 (a customer charge to recover 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 seeks to recover expenses associated with ACE’s ongoing investments in reliability enhancement improvements and efforts to maintain safe and reliable service and to recover 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 providing for an increase in ACE’s electric 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
PEPCO HOLDINGS
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. Rates were effective on July 1, 2013.
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 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. 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.
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.
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. Consequently, this policy has substantially reduced ACE’s rate base 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 for the remainder of the proceeding or for the issuance of a decision.
PEPCO HOLDINGS
Federal Energy Regulatory Commission
On October 17, 2013, the 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 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 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 CWIP related to the 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. This challenge is pending at FERC. 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 it 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.
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.
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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, as more fully described in 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 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,
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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. On October 31, 2013, one of the SOCA generation companies filed a notice of appeal of the October 25, 2013 Federal district court decision with the U.S. Court of Appeals for the Third Circuit (the Federal circuit court). On November 8, 2013, the other remaining SOCA generating company filed a motion to intervene in the proceedings and a notice of appeal of the October 25, 2013 Federal district court decision. On November 21, 2013, the NJBPU filed its notice of appeal of the October 25, 2013 Federal district court decision. On November 14, 2013, the Federal circuit court granted the motion to intervene and on December 13, 2013, the Federal circuit court issued an order consolidating the appeals filed by the NJBPU and the SOCA generating companies of the October 25, 2013 Federal district court decision. The matter has been placed on an expedited schedule and appeal proceedings remain pending. The Federal circuit court is tentatively scheduled to hear the appeal on March 27, 2014.
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
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$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 is awaiting the signature of the Mayor of the District of Columbia. Once signed by the Mayor and transmitted to Congress, the legislation will undergo a 30-day Congressional review period before becoming law, which is expected to occur in the second quarter of 2014. The final step would be DCPSC approval of the underground project plan and 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.
MAPP Project
On August 24, 2012, the board of PJM terminated the 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. In December 2012, PHI submitted a filing to FERC seeking recovery of approximately $88 million of abandoned MAPP costs over a five-year recovery period. 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.
In February 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.
On December 18, 2013, PHI submitted a settlement agreement to FERC, which provides for recovery of PHI’s abandoned MAPP costs over a three-year recovery period beginning June 1, 2013. The settlement agreement, which is subject to FERC approval, would resolve all issues concerning the recovery of abandonment costs associated with the cancellation of the MAPP project. PHI cannot predict the timing or results of a final FERC decision in this proceeding.
As of December 31, 2013, PHI had a regulatory asset related to the MAPP abandoned costs of approximately $68 million, representing the original filing amount of approximately $88 million of abandoned costs referred to above less: (i) approximately $2 million of disallowed costs written off in 2013; (ii) $4 million of materials transferred to inventories for use on other projects; and (iii) $14 million of amortization expense recorded in 2013. The regulatory asset balance includes the costs of land, land rights, engineering and design, environmental services, and project management and administration.
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(8) PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment is comprised of the following:
The non-operating and other property amounts include balances for general plant, intangible plant, distribution plant and transmission plant held for future use as well as other property held by non-utility subsidiaries. Utility plant is generally subject to a first mortgage lien.
Pepco Holdings’ utility subsidiaries use separate depreciation rates for each electric plant account. The rates vary from jurisdiction to jurisdiction.
Jointly Owned Plant
PHI’s consolidated balance sheets include its proportionate share of assets and liabilities related to jointly owned plant. At December 31, 2013 and 2012, PHI’s subsidiaries had a net book value ownership interest of $12 million and $13 million, respectively, in transmission and other facilities in which various parties also have ownership interests. PHI’s share of the operating and maintenance expenses of the jointly-owned plant is included in the corresponding expenses in the consolidated statements of (loss) income. PHI is responsible for providing its share of the financing for the above jointly-owned facilities.
Capital Leases
Pepco leases its consolidated control center, which is an integrated energy management center used by Pepco to centrally control the operation of its transmission and distribution systems. This lease is accounted for as a capital lease and was initially recorded at the present value of future lease payments, which totaled $152 million. The lease requires semi-annual payments of approximately $8 million over a 25-year period that began in December 1994, and provides for transfer of ownership of the system to Pepco for $1 at the end of the lease term. Under FASB guidance on regulated operations, the amortization of leased assets is modified so that the total interest expense charged on the obligation and amortization expense of the leased asset is equal to the rental expense allowed for rate-making purposes. The amortization expense is included within Depreciation and amortization in the consolidated statements of (loss) income. This lease is treated as an operating lease for rate-making purposes.
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Capital lease assets recorded within Property, Plant and Equipment at December 31, 2013 and 2012, in millions of dollars, are comprised of the following:
The approximate annual commitments under all capital leases are $15 million for each year 2014 through 2018, and $16 million thereafter.
Deactivation of Pepco Energy Services’ Generating Facilities
During 2012, Pepco Energy Services deactivated its Buzzard Point and Benning Road oil-fired generation facilities. The facilities were located in Washington, D.C. and had a generating capacity of approximately 790 megawatts. During the years ended December 31, 2012 and 2011, PHI has recorded decommissioning costs of $3 million and $2 million, respectively, related to these generating facilities.
Pepco Energy Services placed the facilities into an idle condition termed a “cold closure.” A cold closure requires that the utility service be disconnected so that the facilities are no longer operable and require only essential maintenance until they are completely decommissioned. During the third quarter of 2013, Pepco Energy Services determined that it would be more cost effective to pursue the demolition of the Benning Road generation facility and realization of the scrap metal salvage value of the facility instead of maintaining cold closure status. The demolition of the facility commenced in the fourth quarter of 2013 and is expected to be completed by the end of 2014. Pepco Energy Services will recognize the salvage proceeds associated with the scrap metals at the facility as realized.
Long-Lived Asset Impairment
For the years ended December 31, 2013 and 2012, PHI recorded impairment losses of $4 million ($3 million after-tax) and $12 million ($7 million after-tax), respectively, at Pepco Energy Services associated primarily with its investments in landfill gas-fired electric generation facilities. In 2012, the impairment loss also included the reduction in the estimated net realizable value of the combustion turbines at Buzzard Point. PHI performed a long-lived asset impairment test on the landfill generation facilities of Pepco Energy Services as a result of a sustained decline in energy prices and recent production levels. The asset value of the facilities was written down to their estimated fair value because the future expected cash flows of the facilities were not sufficient to provide recovery of the facilities’ carrying value. PHI estimated the fair value of the facilities by calculating the present value of expected future cash flows using an appropriate discount rate. Both the expected future cash flows and the discount rate used primarily unobservable inputs.
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Asset Retirement Obligations
PHI recognizes liabilities related to the retirement of long-lived assets in accordance with ASC 410. In connection with Pepco Energy Services’ decommissioning of the Buzzard Point and Benning Road generation facilities, PHI has recorded an asset retirement obligation of $2 million and $9 million as of December 31, 2013 and 2012, respectively on its consolidated balance sheets.
During 2013, Pepco Energy Services determined that it would be more cost effective to pursue the demolition of the Benning Road generation facility instead of maintaining cold closure status. As a result of this change in intent, Pepco Energy Services reduced its asset retirement obligation related to the facility by $2 million.
The sale of the Conectiv Energy wholesale power generation business to Calpine Corporation (Calpine) did not include a coal ash landfill site located at the Edge Moor generating facility, which PHI intends to close. The preliminary estimate of the costs to PHI to close the coal ash landfill ranges from approximately $2 million to $3 million, plus annual post-closure operations, maintenance and monitoring costs for 30 years. PHI has recorded an asset retirement obligation of $6 million on its consolidated balance sheet related to the Edge Moor landfill.
(9) PENSION AND OTHER POSTRETIREMENT BENEFITS
The following table shows changes in the benefit obligation and plan assets for the years ended December 31, 2013 and 2012:
(a) Other Postretirement Benefits paid is net of Medicare Part D subsidy receipts of zero and $4 million in 2013 and 2012, respectively.
At December 31, 2013 and 2012, the PHI Retirement Plan’s accumulated benefit obligation was approximately $2.1 billion and $2.3 billion, respectively. The accumulated benefit obligation differs from the pension benefit obligation presented in the table above in that the accumulated benefit obligation includes no assumption about future compensation levels.
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The following table provides the amounts recorded in PHI’s consolidated balance sheets as of December 31, 2013 and 2012:
Amounts included in AOCL (pre-tax) and Regulatory assets at December 31, 2013 and 2012, consist of:
Under FASB guidance on regulated operations, a portion of actuarial gains and losses and prior service costs (credits) are included in Regulatory assets (liabilities) in the consolidated balance sheets to reflect expected regulatory recovery of such amounts, which otherwise would be recorded to AOCL. The table below provides the changes in plan assets and benefit obligations recognized in AOCL and Regulatory assets for the years ended December 31, 2013, 2012 and 2011.
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The estimated net actuarial loss and prior service cost for the defined benefit pension plans that will be amortized from AOCL or Regulatory assets into net periodic benefit cost over the next reporting year are $44 million and $2 million, respectively. The estimated net actuarial loss and prior service credit for the OPEB plan that will be amortized from AOCL or Regulatory assets into net periodic benefit cost over the next reporting year are $6 million and $13 million, respectively.
The table below provides the components of net periodic benefit costs recognized for the years ended December 31, 2013, 2012 and 2011:
The table below provides the split of the combined pension and other postretirement net periodic benefit costs among subsidiaries for the years ended December 31, 2013, 2012 and 2011:
The following weighted average assumptions were used to determine the benefit obligations at December 31:
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Assumed health care cost trend rates may have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects, in millions of dollars:
The following weighted average assumptions were used to determine the net periodic benefit cost for the years ended December 31:
(a) The discount rate was updated for remeasurement to 4.95% on July 1, 2013.
PHI utilizes an analytical tool developed by its actuaries to select the discount rate. The analytical tool utilizes a high-quality bond portfolio with cash flows that match the benefit payments expected to be made under the plans.
PHI uses a building block approach to estimate the expected rate of return on plan assets. Under this approach, the percentage of plan assets in each asset class according to PHI’s target asset allocation, at the beginning of the year, is applied to the expected asset return for the related asset class. PHI incorporates long-term assumptions for real returns, inflation expectations, volatility and correlations among asset classes to determine expected returns for a given asset allocation. The pension and postretirement benefit plan assets consist of equity, fixed income, real estate and private equity investments. PHI periodically reviews its asset mix and rebalances assets to the target allocation.
The average remaining service periods for participating employees of the benefit plans was approximately 11 years for both 2013 and 2012. PHI utilizes plan census data to estimate these average remaining service periods. PHI uses the IRS prescribed mortality tables to estimate the average life expectancy. The IRS prescribed tables for 2013 and 2012 were used to determine net periodic pension and OPEB cost for the same respective years. The tables for 2014 and 2013 were used for determining the benefit obligations as of December 31, 2013 and 2012, respectively.
Benefit Plan Modifications
During 2013, PHI approved two amendments to its other postretirement benefits plan. These amendments impacted the retiree health care and the retiree life insurance benefits, and were effective on January 1, 2014. As a result of the amendments, which were cumulatively significant, PHI remeasured its accumulated postretirement benefit obligation for other postretirement benefits as of July 1, 2013. The remeasurement resulted in a $193 million reduction of the accumulated postretirement benefit obligation, which included recording a prior service credit of $124 million, which will be amortized over approximately ten years, and a $69 million reduction from a change in the discount rate from 4.10% as of December 31, 2012 to 4.95% as of July 1, 2013. The remeasurement resulted in a $17 million reduction in net periodic benefit cost for other postretirement benefits during 2013, when compared to 2012. Approximately 37% of net periodic other postretirement benefit costs were capitalized in 2013.
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Plan Assets
Investment Policies and Strategies
In developing its allocation policy for the assets in the PHI Retirement Plan and the other postretirement benefit plan, PHI examined projections of asset returns and volatility over a long-term horizon. In connection with this analysis, PHI evaluated the risk and return tradeoffs of alternative asset classes and asset mixes given long-term historical relationships as well as prospective capital market returns. PHI also conducted an asset-liability study to match projected asset growth with projected liability growth to determine whether there is sufficient liquidity for projected benefit payments. PHI developed its asset mix guidelines by incorporating the results of these analyses with an assessment of its risk posture, and taking into account industry practices. PHI periodically evaluates its investment strategy to ensure that plan assets are sufficient to meet the benefit obligations of the plans. As part of the ongoing evaluation, PHI may make changes to its targeted asset allocations and investment strategy.
PHI’s pension investment strategy is designed to meet the following investment objectives:
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Generate investment returns that, in combination with funding contributions from PHI, provide adequate funding to meet all current and future benefit obligations of the plan.
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Provide investment results that meet or exceed the assumed long-term rate of return, while maintaining the funded status of the plan at acceptable levels.
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Improve funded status over time.
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Decrease contribution and expense volatility as funded status improves.
To achieve these investment objectives, PHI’s investment strategy divides the pension program into two primary portfolios:
Return-Seeking Assets-These assets are intended to provide investment returns in excess of pension liability growth and reduce existing deficits in the funded status of the plan. The category includes a diversified mix of U.S. large and small cap equities, non-U.S. developed and emerging market equities, real estate, and private equity.
Liability-Hedging Assets-These assets are intended to reflect the sensitivity of the plan’s liabilities to changes in discount rates. This category includes a diversified mix of long duration, primarily investment grade credit and U.S. treasury securities.
PHI follows an asset-liability management strategy for PHI Retirement Plan assets in order to reduce the effects of future volatility of the fair value of its pension plan assets relative to its pension plan liabilities. For example, in 2013, this strategy uses a 66% target allocation to fixed income investments, primarily in high quality, longer-maturity fixed income securities. The PHI Retirement Plan asset allocations at December 31, 2013 and 2012, by asset category, were as follows:
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PHI’s other postretirement benefit plan asset allocations at December 31, 2013 and 2012, by asset category, were as follows:
PHI will rebalance the plan asset portfolios when the actual allocations fall outside the ranges outlined in the investment policy or as funded status improves over a reasonable period of time.
Risk Management
Pension and other postretirement benefit plan assets may be invested in separately managed accounts in which there is ownership of individual securities, shares of commingled funds or mutual funds, or limited partnerships. Commingled funds and mutual funds are subject to detailed policy guidelines set forth in the fund’s prospectus or fund declaration, and limited partnerships are subject to the terms of the partnership agreement.
Separate account investment managers are responsible for achieving a level of diversification in their portfolio that is consistent with their investment approach and their role in PHI’s overall investment structure. Separate account investment managers must follow risk management guidelines established by PHI unless authorized in writing by PHI.
Derivative instruments are permissible in an investment portfolio to the extent they comply with policy guidelines and are consistent with risk and return objectives. Under no circumstances may such instruments be used speculatively or to leverage the portfolio. Separately managed accounts are prohibited from holding securities issued by the following firms:
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PHI and its subsidiaries,
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PHI’s pension plan trustee, its parent or its affiliates,
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PHI’s pension plan consultant, its parent or its affiliates, and
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PHI’s pension plan investment manager, its parent or its affiliates
Fair Value of Plan Assets
As defined in the FASB guidance on fair value measurement and disclosures (ASC 820), fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The FASB’s fair value framework includes a hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1) and the lowest priority to unobservable inputs (level 3). If the inputs used to measure the financial instruments fall within different levels of the hierarchy, the categorization is based on the lowest level input that is significant to the fair value measurement of the instrument. Investments are classified within the fair value hierarchy as follows:
Level 1: Investments are valued using quoted prices in active markets for identical instruments.
Level 2: Investments are valued using other significant observable inputs (e.g., quoted prices for similar investments, interest rates, credit risks, etc).
Level 3: Investments are valued using significant unobservable inputs, including internal assumptions.
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There were no significant transfers between level 1 and level 2 during the years ended December 31, 2013 and 2012.
The following tables present the fair values of PHI’s pension and other postretirement benefit plan assets by asset category within the fair value hierarchy levels, as of December 31, 2013 and 2012:
(a) Predominantly includes domestic common stock and commingled funds.
(b) Predominantly includes foreign common and preferred stock and warrants.
(c) Predominantly includes corporate bonds, government bonds, municipal/provincial bonds, collateralized mortgage obligations and commingled funds.
(d) Predominantly includes cash investment in short-term investment funds.
(e) Includes domestic and international commingled funds.
(f) Includes fixed income commingled funds.
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(a) Predominantly includes domestic common stock and commingled funds.
(b) Predominantly includes foreign common and preferred stock and warrants.
(c) Predominantly includes corporate bonds, government bonds, municipal/provincial bonds, collateralized mortgage obligations and commingled funds.
(d) Predominantly includes cash investment in short-term investment funds.
(e) Includes domestic and international commingled funds.
(f) Includes fixed income commingled funds.
There were no significant concentrations of risk in pension and OPEB plan assets at December 31, 2013 and 2012.
Valuation Techniques Used to Determine Fair Value
Equity
Equity securities are primarily comprised of securities issued by public companies in domestic and foreign markets plus investments in commingled funds, which are valued on a daily basis. PHI can exchange shares of the publicly traded securities and the fair values are primarily sourced from the closing prices on stock exchanges where there is active trading, therefore they would be classified as level 1 investments. If there is less active trading, then the publicly traded securities would typically be priced using observable data, such as bid/ask prices, and these measurements would be classified as level 2 investments. Investments that are not publicly traded and valued using unobservable inputs would be classified as level 3 investments.
Commingled funds with publicly quoted prices and active trading are classified as level 1 investments. For commingled funds that are not publicly traded and have ongoing subscription and redemption activity, the fair value of the investment is the net asset value (NAV) per fund share, derived from the underlying securities’ quoted prices in active markets, and are classified as level 2 investments. Investments in commingled funds with redemption restrictions that use NAV are classified as level 3 investments.
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Fixed Income
Fixed income investments are primarily comprised of fixed income securities and fixed income commingled funds. The prices for direct investments in fixed income securities are generated on a daily basis. Like the equity securities, fair values generated from active trading on exchanges are classified as level 1 investments. Prices generated from less active trading with wider bid/ask prices are classified as level 2 investments. If prices are based on uncorroborated and unobservable inputs, then the investments are classified as level 3 investments.
Commingled funds with publicly quoted prices and active trading are classified as level 1 investments. For commingled funds that are not publicly traded and have ongoing subscription and redemption activity, the fair value of the investment is the NAV per fund share, derived from the underlying securities’ quoted prices in active markets, and are classified as level 2 investments. Investments in commingled funds with redemption restrictions that use NAV are classified as level 3 investments.
Other - Private Equity and Real Estate
Investments in private equity and real estate funds are primarily invested in privately held real estate investment properties, trusts and partnerships, as well as equity and debt issued by public or private companies. As a practical expedient, PHI’s interest in the fund or partnership is estimated at NAV. PHI’s interest in these funds cannot be readily redeemed due to the inherent lack of liquidity and the primarily long-term nature of the underlying assets. Distribution is made through the liquidation of the underlying assets. PHI views these investments as part of a long-term investment strategy. These investments are valued by each investment manager based on the underlying assets. The majority of the underlying assets are valued using significant unobservable inputs and often require significant management judgment or estimation based on the best available information. Market data includes observations of the trading multiples of public companies considered comparable to the private companies being valued. The funds utilize valuation techniques consistent with the market, income and cost approaches to measure the fair value of certain real estate investments. As a result, PHI classifies these investments as level 3 investments.
The investments in private equity and real estate funds require capital commitments, which may be called over a specific number of years. Unfunded capital commitments as of December 31, 2013 and 2012 totaled $12 million and $15 million, respectively.
Reconciliations of the beginning and ending balances of PHI’s fair value measurements using significant unobservable inputs (level 3) for investments in the pension plan for the years ended December 31, 2013 and 2012 are shown below:
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Cash Flows
Contributions-PHI Retirement Plan
PHI’s funding policy with regard to the PHI Retirement Plan is to maintain a funding level that is at least equal to the target liability as defined under the Pension Protection Act of 2006. During 2013, PHI, DPL and ACE made discretionary tax-deductible contributions to the PHI Retirement Plan in the amounts of $80 million, $10 million and $30 million, respectively, which brought the PHI Retirement Plan assets to the funding target level for 2013 under the Pension Protection Act. During 2012, Pepco, DPL and ACE made discretionary tax-deductible contributions to the PHI Retirement Plan in the amounts of $85 million, $85 million and $30 million, respectively, which brought plan assets to the funding target level for 2012 under the Pension Protection Act.
Contributions-Other Postretirement Benefit Plan
In 2013 and 2012, Pepco contributed $6 million and $5 million, respectively, DPL contributed $3 million and $7 million, respectively, and ACE contributed $6 million and $7 million, respectively, to the other postretirement benefit plan. In 2013 and 2012, contributions of $7 million and $13 million, respectively, were made by other PHI subsidiaries.
Expected Benefit Payments
Estimated future benefit payments to participants in PHI’s pension and other postretirement benefit plans, which reflect expected future service as appropriate, are as follows:
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Medicare Prescription Drug Improvement and Modernization Act of 2003 (Medicare Act)
On December 8, 2003, the Medicare Act became effective. The Medicare Act introduced Medicare Part D, as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. Pepco Holdings sponsors postretirement health care plans that provide prescription drug benefits that PHI plan actuaries have determined are actuarially equivalent to Medicare Part D. In 2012, Pepco Holdings received $4 million in federal Medicare prescription drug subsidies. PHI did not receive the Part D subsidy in 2013 and will not receive it in the future due to the implementation of an Employer Group Waiver Plan which is not eligible for Part D reimbursements.
Pepco Holdings Retirement Savings Plan
Pepco Holdings has a defined contribution retirement savings plan. Participation in the plan is voluntary. All participants are 100% vested and have a nonforfeitable interest in their own contributions and in the Pepco Holdings’ company matching contributions, including any earnings or losses thereon. Pepco Holdings’ matching contributions were $12 million, $12 million and $11 million for the years ended December 31, 2013, 2012 and 2011, respectively.
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(10) DEBT
Long-Term Debt
The components of long-term debt are shown in the table below:
NOTE: Schedule is continued on next page.
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(a) Represents a series of Collateral First Mortgage Bonds securing a series of senior notes issued by Pepco.
(b) Represents a series of Collateral First Mortgage Bonds (as defined herein) which must be cancelled and released as security for the issuer’s obligations under the corresponding series of issuer notes (as defined herein) or tax-exempt bonds, at such time as the issuer does not have any first mortgage bonds outstanding (other than its Collateral First Mortgage Bonds).
(c) Represents a series of Collateral First Mortgage Bonds which must be cancelled and released as security for the issuer’s obligations under the corresponding series of issuer notes or tax-exempt bonds, at such time as the issuer does not have any first mortgage bonds outstanding (other than its Collateral First Mortgage Bonds), except that the issuer may not permit such release of collateral unless the issuer substitutes comparable obligations for such collateral.
(d) Represents a series of Collateral First Mortgage Bonds securing a series of senior notes issued by Pepco, which in turn secures a series of tax-exempt bonds issued for the benefit of Pepco.
(e) Represents a series of Collateral First Mortgage Bonds securing a series of medium term notes issued by ACE.
(f) Represents a series of Collateral First Mortgage Bonds securing a series of tax-exempt bonds issued for the benefit of ACE.
(g) Represents a series of Collateral First Mortgage Bonds securing a series of senior notes issued by ACE.
(h) Represents a series of Collateral First Mortgage Bonds securing a series of debt securities issued by DPL.
The outstanding first mortgage bonds issued by each of Pepco, DPL and ACE are issued under a mortgage and deed of trust and are secured by a first lien on substantially all of the issuing company’s property, plant and equipment, except for certain property excluded from the lien of the respective mortgage.
PHI’s long-term debt is subject to certain covenants. As of December 31, 2013, PHI and its subsidiaries were in compliance with all such covenants.
The table above does not separately identify $1,060 million, $100 million and $249 million in aggregate principal amount of senior notes, medium term notes and other debt securities (issuer notes) issued by each of Pepco, DPL and ACE, respectively, and $110 million and $62 million in aggregate principal amount of tax-exempt bonds issued for the benefit of Pepco and ACE, respectively. These issuer notes are
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secured by a like amount of first mortgage bonds (Collateral First Mortgage Bonds) of each respective issuer. In addition, these tax-exempt bonds are secured by a like amount of Collateral First Mortgage Bonds issued by the utility subsidiary for whose benefit the tax-exempt bonds were issued. The principal terms of each such series of issuer notes, or the issuer’s obligations in respect of each such series of tax-exempt bonds, are identical to the same terms of the corresponding series of Collateral First Mortgage Bonds. Payments of principal and interest made on a series of such issuer notes, or the satisfaction of the issuer’s obligations in respect of a series of such tax-exempt bonds, satisfy the corresponding obligations on the related series of Collateral First Mortgage Bonds. For these reasons, each such series of Collateral First Mortgage Bonds and the corresponding issuer notes and/or tax-exempt bonds together effectively represent a single financial obligation and are not identified in the table above separately.
Bond Issuances
During 2013, Pepco issued $250 million of 4.15% first mortgage bonds due March 15, 2043 and $150 million of 4.95% first mortgage bonds due November 15, 2043. Net proceeds from the issuance of the 4.15% bonds were used to repay Pepco’s outstanding commercial paper and for general corporate purposes. The net proceeds from the 4.95% bonds were used to repay outstanding commercial paper, including commercial paper issued to repay in full at maturity $200 million of Pepco’s 4.95% senior notes due November 15, 2013, plus accrued but unpaid interest thereon. The senior notes were secured by a like principal amount of Pepco’s first mortgage bonds, which under Pepco’s Mortgage and Deed of Trust were deemed to be satisfied with the repayment of the senior notes.
During 2013, DPL issued $300 million of 3.50% first mortgage bonds due November 15, 2023. The net proceeds from the issuance of the long-term debt were used to repay at maturity $250 million of DPL’s 6.40% first mortgage bonds, plus accrued but unpaid interest thereon, to repay outstanding commercial paper and for general corporate purposes.
Bond Redemptions
During 2013, Pepco repaid at maturity $200 million of its 4.95% senior notes, which were secured by a like principal amount of its first mortgage bonds as previously discussed.
During 2013, DPL repaid at maturity $250 million of its 6.40% first mortgage bonds.
During 2013, ACE repaid at maturity $69 million of its 6.63% non-callable first mortgage bonds. ACE also funded the redemption, prior to maturity, of $4 million of outstanding weekly variable rate pollution control revenue refunding bonds due 2017, issued by the Pollution Control Financing Authority of Salem County, New Jersey for ACE’s benefit.
ACE Term Loan Agreement
On May 10, 2013, ACE entered into a $100 million term loan agreement, pursuant to which ACE has borrowed (and may not re-borrow) $100 million at a rate of interest equal to the prevailing Eurodollar rate, which is determined by reference to the London Interbank Offered Rate (LIBOR) with respect to the relevant interest period, all as defined in the loan agreement, plus a margin of 0.75%. ACE’s Eurodollar borrowings under the loan agreement may be converted into floating rate loans under certain circumstances, and, in that event, for so long as any loan remains a floating rate loan, interest would accrue on that loan at a rate per year equal to (i) the highest of (a) the prevailing prime rate, (b) the federal funds effective rate plus 0.5%, or (c) the one-month Eurodollar rate plus 1%, plus (ii) a margin of 0.75%. As of December 31, 2013, outstanding borrowings under the loan agreement bore interest at an annual rate of 0.92%, which is subject to adjustment from time to time. All borrowings under the loan agreement are unsecured, and the aggregate principal amount of all loans, together with any accrued but unpaid interest due under the loan agreement, must be repaid in full on or before November 10, 2014.
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Under the terms of the term loan agreement, ACE must maintain compliance with specified covenants, including (i) the requirement that ACE maintain a ratio of total indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the loan agreement, which calculation excludes from the definition of total indebtedness certain trust preferred securities and deferrable interest subordinated debt (not to exceed 15% of total capitalization), (ii) a restriction on sales or other dispositions of assets, other than certain permitted sales and dispositions, and (iii) a restriction on the incurrence of liens (other than liens permitted by the loan agreement) on the assets of ACE. The loan agreement does not include any rating triggers. ACE was in compliance with all covenants under this loan agreement as of December 31, 2013.
Transition Bonds Issued by ACE Funding
The components of transition bonds are shown in the table below:
For a description of the Transition Bonds, see Note (16), “Variable Interest Entities - ACE Funding.”
Maturities of PHI’s long-term debt and Transition Bonds outstanding at December 31, 2013 are $444 million in 2014, $409 million in 2015, $338 million in 2016, $133 million in 2017, $286 million in 2018 and $3,115 million thereafter.
Long-Term Project Funding
As of December 31, 2013 and 2012, Pepco Energy Services had total outstanding long-term project funding (including current maturities) of $12 million and $13 million, respectively, related to energy savings contracts performed by Pepco Energy Services. The aggregate amounts of maturities for the project funding debt outstanding at December 31, 2013, are $2 million for 2014, $2 million for 2015, $1 million for each year 2016 and 2017, $2 million for 2018, and $4 million thereafter.
Short-Term Debt
PHI and its regulated utility subsidiaries have traditionally used a number of sources to fulfill short-term funding needs, such as commercial paper, short-term notes, and bank lines of credit. Proceeds from short-term borrowings are used primarily to meet working capital needs, but may also be used to temporarily fund long-term capital requirements. The components of PHI’s short-term debt at December 31, 2013 and 2012 are as follows:
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Commercial Paper
PHI, Pepco, DPL and ACE maintain ongoing commercial paper programs to address short-term liquidity needs. As of December 31, 2013, the maximum capacity available under these programs was $875 million, $500 million, $500 million and $350 million, respectively, subject to available borrowing capacity under the credit facility.
PHI, Pepco, DPL and ACE had $24 million, $151 million, $147 million and $120 million, respectively, of commercial paper outstanding at December 31, 2013. The weighted average interest rate for commercial paper issued by PHI, Pepco, DPL and ACE during 2013 was 0.70%, 0.34%, 0.29% and 0.31%, respectively. The weighted average maturity of all commercial paper issued by PHI, Pepco, DPL and ACE during 2013 was five, five, three and four days, respectively.
PHI, Pepco, DPL and ACE had $264 million, $231 million, $32 million and $110 million, respectively, of commercial paper outstanding at December 31, 2012. The weighted average interest rate for commercial paper issued by PHI, Pepco, DPL and ACE during 2012 was 0.87%, 0.43%, 0.43% and 0.41%, respectively. The weighted average maturity of all commercial paper issued by PHI, Pepco, DPL and ACE in 2012 was ten, five, four and three days, respectively.
Variable Rate Demand Bonds
PHI’s utility subsidiaries DPL and ACE, each have outstanding obligations in respect of Variable Rate Demand Bonds (VRDB). VRDBs are subject to repayment on the demand of the holders and, for this reason, are accounted for as short-term debt in accordance with GAAP. However, bonds submitted for purchase are remarketed by a remarketing agent on a best efforts basis. PHI expects that any bonds submitted for purchase will be remarketed successfully due to the creditworthiness of the issuer and, as applicable, the credit support, and because the remarketing resets the interest rate to the then-current market rate. The bonds may be converted to a fixed-rate, fixed-term option to establish a maturity which corresponds to the date of final maturity of the bonds. On this basis, PHI views VRDBs as a source of long-term financing. As of December 31, 2013, $105 million of VRDBs issued on behalf of DPL (of which $72 million were secured by Collateral First Mortgage Bonds issued by DPL) and $18 million of VRDBs issued on behalf of ACE were outstanding.
The VRDBs outstanding at December 31, 2013 mature as follows: 2014 to 2017 ($44 million), 2024 ($33 million) and 2028 to 2029 ($46 million). The weighted average interest rate for VRDBs was 0.24% during 2013 and 0.34% during 2012.
Credit Facility
PHI, Pepco, DPL and ACE maintain an unsecured syndicated credit facility to provide for their respective liquidity needs, including obtaining letters of credit, borrowing for general corporate purposes and supporting their commercial paper programs. On August 1, 2011, PHI, Pepco, DPL and ACE entered into an amended and restated credit agreement which, on August 2, 2012, was amended to extend the term of the credit facility to August 1, 2017 and to amend the pricing schedule to decrease certain fees and interest rates payable to the lenders under the facility. On August 1, 2013, as permitted under the existing terms of the credit agreement, a request by PHI, Pepco, DPL and ACE to extend the credit facility termination date to August 1, 2018 was approved. All of the terms and conditions as well as pricing remained the same.
The aggregate borrowing limit under the amended and restated credit facility is $1.5 billion, all or any portion of which may be used to obtain loans and up to $500 million of which may be used to obtain letters of credit. The facility also includes a swingline loan sub-facility, pursuant to which each company may make same day borrowings in an aggregate amount not to exceed 10% of the total amount of the facility. Any swingline loan must be repaid by the borrower within fourteen days of receipt. The credit sublimit is $750 million for PHI and $250 million for each of Pepco, DPL and ACE. The sublimits may
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be increased or decreased by the individual borrower during the term of the facility, except that (i) the sum of all of the borrower sublimits following any such increase or decrease must equal the total amount of the facility and (ii) the aggregate amount of credit used at any given time by (a) PHI may not exceed $1.25 billion and (b) each of Pepco, DPL or ACE may not exceed the lesser of $500 million and the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of the sublimit reallocations may not exceed eight per year during the term of the facility.
The interest rate payable by each company on utilized funds is, at the borrowing company’s election, (i) the greater of the prevailing prime rate, the federal funds effective rate plus 0.5% and the one month LIBOR plus 1.0%, or (ii) the prevailing Eurodollar rate, plus a margin that varies according to the credit rating of the borrower.
In order for a borrower to use the facility, certain representations and warranties must be true and correct, and the borrower must be in compliance with specified financial and other covenants, including (i) the requirement that each borrowing company maintain a ratio of total indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the credit agreement, which calculation excludes from the definition of total indebtedness certain trust preferred securities and deferrable interest subordinated debt (not to exceed 15% of total capitalization), (ii) with certain exceptions, a restriction on sales or other dispositions of assets, and (iii) a restriction on the incurrence of liens on the assets of a borrower or any of its significant subsidiaries other than permitted liens. The credit agreement contains certain covenants and other customary agreements and requirements that, if not complied with, could result in an event of default and the acceleration of repayment obligations of one or more of the borrowers thereunder. Each of the borrowers was in compliance with all covenants under this facility as of December 31, 2013.
The absence of a material adverse change in PHI’s business, property, results of operations or financial condition is not a condition to the availability of credit under the credit agreement. The credit agreement does not include any rating triggers.
As of December 31, 2013 and 2012, the amount of cash plus unused borrowing capacity under the credit facility available to meet the future liquidity needs of PHI and its utility subsidiaries on a consolidated basis totaled $1,063 million and $861 million, respectively. PHI’s utility subsidiaries had combined cash and unused borrowing capacity under the credit facility of $332 million and $477 million at December 31, 2013 and 2012, respectively.
Other Financing Activities
PHI Term Loan Agreement
On March 28, 2013, PHI entered into a $250 million term loan agreement due March 27, 2014, pursuant to which PHI had borrowed $250 million at a rate of interest equal to the prevailing Eurodollar rate, which is determined by reference to the LIBOR with respect to the relevant interest period, all as defined in the loan agreement, plus a margin of 0.875%. PHI used the net proceeds of the loan under the loan agreement to repay its outstanding $200 million term loan obtained in 2012, and for general corporate purposes. On May 29, 2013, PHI repaid the $250 million term loan with a portion of the net proceeds from the early termination of the cross-border energy lease investments.
Long-Term Project Funding
On October 24, 2013, Pepco Energy Services entered into an agreement with a lender to receive up to $8 million in construction financing at an interest rate of 4.68% for an energy savings project that is expected to be completed in 2014. The agreement includes a transfer of receivables from Pepco Energy Services to the lender after construction is completed, under which the customer would make contractual payments over a 23-year period to repay the financing. If there are shortfalls in Pepco Energy Services’ energy savings guarantee or other performance obligations to the customer that reduce customer payments below the contractual payment amounts, then Pepco Energy Services would compensate the lender for the unpaid amounts. PHI has guaranteed the performance obligations of Pepco Energy Services under the financing agreement.
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(11) INCOME TAXES
PHI and the majority of its subsidiaries file a consolidated federal income tax return. Federal income taxes are allocated among PHI and the subsidiaries included in its consolidated group pursuant to a written tax sharing agreement that was approved by the SEC in 2002 in connection with the establishment of PHI as a public utility holding company. Under this tax sharing agreement, PHI’s consolidated federal income tax liability is allocated based upon PHI’s and its subsidiaries’ separate taxable income or loss.
The provision for consolidated income taxes, reconciliation of consolidated income tax expense, and components of consolidated deferred tax liabilities (assets) are shown below.
Provision for Consolidated Income Taxes - Continuing Operations
Reconciliation of Consolidated Income Tax Expense - Continuing Operations
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Year ended December 31, 2013
PHI’s consolidated effective income tax rate for the year ended December 31, 2013 of 74.4% reflects a charge of $56 million for changes in estimates and interest related to uncertain and effectively settled tax positions recorded in the first quarter of 2013 and the establishment of valuation allowances of $101 million in the first quarter of 2013 against certain deferred tax assets in PCI, which is now included in Corporate and Other. The income tax charge of $56 million is primarily related to the anticipated additional interest expense on estimated federal and state income tax obligations that was allocated to PHI’s continuing operations resulting from a change in assessment of tax benefits associated with the former cross-border energy lease investments of PCI.
Between 1990 and 1999, PCI, through various subsidiaries, entered into certain transactions involving investments in aircraft and aircraft equipment, railcars and other assets. In connection with these transactions, PCI recorded deferred tax assets in prior years of $101 million in the aggregate. Following events that took place during the first quarter of 2013, which included (i) court decisions in favor of the IRS with respect to both Consolidated Edison’s cross-border lease transaction (as discussed in Note (19), “Discontinued Operations - Cross-Border Energy Lease Investments”) and another taxpayer’s structured transactions, (ii) the change in PHI’s tax position with respect to the tax benefits associated with its cross-border energy leases, and (iii) PHI’s decision in March 2013 to begin to pursue the early termination of its remaining cross-border energy lease investments (which represented a substantial portion of the remaining assets within PCI) without the intent to reinvest these proceeds in income-producing assets, management evaluated the likelihood that PCI would be able to realize the $101 million of deferred tax assets in the future. Based on this evaluation, PCI established valuation allowances against these deferred tax assets totaling $101 million in the first quarter of 2013. Further, during the fourth quarter of 2013, in light of additional court decisions in favor of the IRS involving other taxpayers, and after consideration of all relevant factors, management determined that it would abandon the further pursuit of these deferred tax assets, and these assets totaling $101 million were charged off against the previously established valuation allowances.
Year ended December 31, 2012
PHI’s consolidated effective income tax rate for the year ended December 31, 2012 of 32.1% includes income tax benefits totaling $8 million related to uncertain and effectively settled tax positions, primarily due to the effective settlement with the IRS in the first quarter of 2012 with respect to the methodology used historically to calculate deductible mixed service costs and the expiration of the statute of limitations associated with an uncertain tax position in Pepco. The rate for the year ended December 31, 2012 also reflects an increase in deductible asset removal costs for Pepco in 2012 related to a higher level of asset retirements.
Year ended December 31, 2011
PHI’s consolidated effective income tax rate for the year ended December 31, 2011 of 33.9% includes income tax benefits totaling $5 million related to uncertain and effectively settled tax positions. In 2011, PHI reached a settlement with the IRS with respect to interest due on its federal tax liabilities related to the November 2010 audit settlement for years 1996 through 2002. In connection with this agreement, PHI reallocated certain amounts that have been on deposit with the IRS since 2006 among liabilities in the settlement years and subsequent years and recorded the tax benefits, primarily in the second quarter of 2011.
In addition, as discussed further in Note (15), “Commitments and Contingencies - District of Columbia Tax Legislation,” on June 14, 2011, the Council of the District of Columbia approved the Fiscal Year 2012 Budget Support Act of 2011 (the Budget Support Act). The Budget Support Act includes a provision that requires corporate taxpayers in the District of Columbia to calculate taxable income
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allocable or apportioned to the District by reference to the income and apportionment factors applicable to commonly controlled entities organized within the United States that are engaged in a unitary business. Previously, only the income of companies with direct nexus to the District of Columbia was taxed. As a result of the change, during 2011 PHI recorded additional state income tax expense of $2 million.
Components of Consolidated Deferred Tax Liabilities (Assets)
(a) PCI established valuation allowances against certain of these other deferred taxes totaling $101 million in the first quarter of 2013. Management determined during the fourth quarter of 2013 to abandon the further pursuit of the related deferred tax assets and, accordingly, these assets were charged off against the valuation allowances.
(b) The amounts for Other, Total Deferred Tax Liabilities, net and Total Consolidated Deferred Tax Liabilities, net non-current, are presented after the effect of the revision to prior period financial statements discussed in Note (2), “ Significant Accounting Policies - Revision to Prior Period Financial Statements.”
The net deferred tax liability represents the tax effect, at presently enacted tax rates, of temporary differences between the financial statement basis and tax basis of assets and liabilities. The portion of the net deferred tax liability applicable to PHI’s utility operations, which has not been reflected in current service rates, represents income taxes recoverable through future rates, net, and is recorded as a Regulatory asset on the balance sheet. Federal and state net operating losses generally expire over 20 years from 2029 to 2032.
The Tax Reform Act of 1986 repealed the investment tax credit for property placed in service after December 31, 1985, except for certain transition property. Investment tax credits previously earned on Pepco’s, DPL’s and ACE’s property continue to be amortized to income over the useful lives of the related property.
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Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits
(a) These additions of unrecognized tax benefits in 2013 primarily relate to the cross-border energy lease investments of PCI.
(b) These reductions of unrecognized tax benefits in 2012 primarily relate to a resolution reached with the IRS for determining deductible mixed service costs for additions to property, plant and equipment.
Unrecognized Benefits That, If Recognized, Would Affect the Effective Tax Rate
Unrecognized tax benefits are related to tax positions that have been taken or are expected to be taken in tax returns that are not recognized in the financial statements because management has either measured the tax benefit at an amount less than the benefit claimed or expected to be claimed, or has concluded that it is not more likely than not that the tax position will be ultimately sustained. For the majority of these tax positions, the ultimate deductibility is highly certain, but there is uncertainty about the timing of such deductibility. Unrecognized tax benefits at December 31, 2013 included $9 million that, if recognized, would lower the effective tax rate.
Interest and Penalties
PHI recognizes interest and penalties relating to its uncertain tax positions as an element of income tax expense. For the years ended December 31, 2013, 2012 and 2011, PHI recognized $125 million of pre-tax interest expense ($75 million after-tax), $23 million of pre-tax interest income ($14 million after-tax), and $23 million of pre-tax interest income ($14 million after-tax), respectively, as a component of income tax expense related to continuing and discontinued operations. As of December 31, 2013, 2012 and 2011, PHI had accrued interest receivable of $2 million, accrued interest receivable of $10 million and accrued interest payable of $4 million, respectively, related to effectively settled and uncertain tax positions.
Possible Changes to Unrecognized Tax Benefits
It is reasonably possible that the amount of unrecognized tax benefits with respect to PHI’s uncertain tax positions will significantly increase or decrease within the next 12 months. In order to mitigate the cost of continued litigation of tax matters related to the former cross-border energy lease investments, PHI and its subsidiaries have entered into discussions with the IRS with the intention of seeking a settlement of all tax issues for open tax years 2001 through 2011. PHI currently believes that it is possible that a settlement with the IRS may be reached in 2014, which could significantly impact the balances of unrecognized tax benefits and the related interest accruals. At this time, it is estimated that there will be a $700 million to $800 million decrease in unrecognized tax benefits within the next 12 months. See Note (15), “Commitments and Contingencies - PHI’s Cross-Border Energy Lease Investments,” for additional discussion.
Tax Years Open to Examination
PHI’s federal income tax liabilities for Pepco legacy companies for all years through 2002, and for Conectiv legacy companies for all years through 2002, have been determined by the IRS, subject to adjustment to the extent of any net operating loss or other loss or credit carrybacks from subsequent years. PHI has not reached final settlement with the IRS with respect to the cross-border energy lease deductions. The open tax years for the significant states where PHI files state income tax returns (District of Columbia, Maryland, Delaware, New Jersey, Pennsylvania and Virginia) are the same as for the Federal returns.
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Final IRS Regulations on Repair of Tangible Property
In September 2013, the IRS issued final regulations on expense versus capitalization of repairs with respect to tangible personal property. The regulations are effective for tax years beginning on or after January 1, 2014, and provide an option to early adopt the final regulations for tax years beginning on or after January 1, 2012. It is expected that the IRS will issue revenue procedures that will describe how taxpayers may implement the final regulations. The final repair regulations retain the operative rule that the Unit of Property for network assets is determined by the taxpayer’s particular facts and circumstances except as provided in published guidance. In 2012, with the filing of its 2011 tax return, PHI filed a request for an automatic change in accounting method related to repairs of its network assets in accordance with IRS Revenue Procedure 2011-43. PHI does not expect the effects of the final regulations to be significant and will continue to evaluate the impact of the new guidance on its consolidated financial statements.
Other Taxes
Other taxes for continuing operations are shown below. The annual amounts include $422 million, $426 million and $445 million for the years ended December 31, 2013, 2012 and 2011, respectively, related to Power Delivery, which are recoverable through rates.
(12) STOCK-BASED COMPENSATION, DIVIDEND RESTRICTIONS, AND CALCULATIONS OF EARNINGS PER SHARE OF COMMON STOCK
Stock-Based Compensation
Pepco Holdings maintains the 2012 Long-Term Incentive Plan (2012 LTIP), the successor plan to the Long-Term Incentive Plan (LTIP), the objective of which is to increase shareholder value by providing long-term and equity incentives to reward officers, key employees and non-employee directors of Pepco Holdings and its subsidiaries and to increase the ownership of Pepco Holdings common stock by such individuals. Any officer, key employee or non-employee director of Pepco Holdings or its subsidiaries may be designated as a participant. Under these plans, awards to officers, key employees and non-employee directors may be in the form of restricted stock, restricted stock units, stock options, performance shares and/or units, stock appreciation rights, unrestricted stock and dividend equivalents. At inception, 10 million and 8 million shares of common stock were authorized for issuance under the LTIP and the 2012 LTIP, respectively. The LTIP expired in accordance with its terms in 2012 and no new awards may be granted thereunder.
Total stock-based compensation expense recorded in the consolidated statements of (loss) income for the years ended December 31, 2013, 2012 and 2011 was $12 million, $11 million and $6 million, respectively, all of which was associated with restricted stock unit and unrestricted stock awards.
No material amount of stock compensation expense was capitalized for the years ended December 31, 2013, 2012 and 2011.
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Restricted Stock and Restricted Stock Unit Awards
Description of Awards
A number of programs have been established under the LTIP and the 2012 LTIP involving the issuance of restricted stock and restricted stock unit awards, including awards of performance-based restricted stock units, time-based restricted stock and restricted stock units, and retention restricted stock and restricted stock units. A summary of each of these programs is as follows:
•
Under the performance-based program, performance criteria are selected and measured over the specified performance period. Depending on the extent to which the performance criteria are satisfied, the participants are eligible to earn shares of common stock at the end of the performance period, ranging from 25% to 200% of the target award, and dividend equivalents accrued thereon.
•
Generally, time-based restricted stock and restricted stock unit award opportunities have a requisite service period of up to three years and, with respect to restricted stock awards, participants have the right to receive dividends on the shares during the vesting period. Under restricted stock unit awards, dividends are credited quarterly in the form of additional restricted stock units, which are paid when vested at the end of the service period.
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In January, April and September 2012, four retention awards in the form of 150,330 time-based and performance-based restricted stock units and 5,305 shares of unrestricted stock were granted to certain PHI executives. In January and February 2013, two retention awards in the form of 45,444 performance-based restricted stock units were granted to certain PHI executives. The time-based retention awards vest at varying rates over a period of three years, and the performance-based retention awards have a one-year performance period and are subject to the continued employment of the executive at the end of the performance period.
•
In 2013 and 2012, restricted stock units totaling 37,735 and 40,749, respectively, were granted to PHI’s non-employee directors under the 2012 LTIP. These restricted stock units vest over a service period which ends upon the first to occur of (i) one year after the date of grant or (ii) the date of the next annual meeting of stockholders. These awards represent the equity portion of the annual retainer paid to non-employee directors for their service as a director of PHI.
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Activity for the year
The 2013 activity for non-vested, time-based restricted stock, restricted stock units and performance-based restricted stock unit awards, including retention awards, is summarized in the table below. For performance-based restricted stock unit awards, the table reflects awards projected, for purposes of computing the weighted average grant date fair value, to achieve 100% of targeted performance criteria for each outstanding award cycle.
Grants included in the table above reflect 2013 grants of performance-based and time-based restricted stock units, including retention awards. PHI recognizes compensation expense related to performance-based restricted stock unit awards and time-based restricted stock and restricted stock unit awards based on the fair value of the awards at date of grant. The fair value is based on the market value of PHI common stock at the date the award opportunity is granted. The estimated fair value of the performance-based awards is also a function of PHI’s projected future performance relative to established performance criteria and the resulting payout of shares based on the achieved performance levels. PHI employed a Monte Carlo simulation to forecast PHI’s performance relative to the performance criteria and to estimate the potential payout of shares under the performance-based awards.
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The following table provides the weighted average grant date fair value per share of those awards granted during each of the years ended December 31, 2013, 2012 and 2011:
As of December 31, 2013, there was approximately $11 million of future compensation cost (net of estimated forfeitures) related to restricted stock unit awards granted under the LTIP and the 2012 LTIP that PHI expects to recognize over a weighted-average period of approximately two years.
Stock Options
Stock options to purchase shares of PHI’s common stock granted under the LTIP and the 2012 LTIP must have an exercise price at least equal to the fair market value of the underlying stock on the grant date. Stock options generally become exercisable on a specified vesting date or dates. All stock options must have an expiration date of no greater than ten years from the date of grant. No options have been granted under the LTIP or the 2012 LTIP since 2002. As of December 31, 2012, all outstanding stock options under predecessor plans have vested or expired. Total intrinsic value and tax benefits recognized for stock options exercised in 2012 and 2011 were immaterial.
Directors’ Deferred Compensation
Under the Pepco Holdings’ Executive and Director Deferred Compensation Plan, Pepco Holdings non-employee directors may elect to defer all or part of their cash retainer and meeting fees. Deferred retainer or meeting fees, at the election of the director, can be credited with interest at the prime rate or the return on selected investment funds or can be deemed invested in phantom shares of Pepco Holdings common stock on which dividend equivalent accruals are credited when dividends are paid on the common stock (or a combination of these options). All deferrals are settled in cash. The amount deferred by directors for each of the years ended December 31, 2013, 2012 and 2011 was not material.
Compensation expense recognized in respect of dividends and the increase in fair value for each of the years ended December 31, 2013, 2012 and 2011 was not material. The deferred compensation balances under this program were approximately $2 million and $1 million at December 31, 2013 and 2012, respectively.
A separate deferral option under the 2012 LTIP gives non-employee directors the right to elect to defer the receipt of common stock upon vesting of restricted stock unit awards.
Dividend Restrictions
PHI, on a stand-alone basis, generates no operating income of its own. Accordingly, its ability to pay dividends to its shareholders depends on dividends received from its subsidiaries. In addition to their future financial performance, the ability of PHI’s direct and indirect subsidiaries to pay dividends is subject to limits imposed by: (i) state corporate laws, which impose limitations on the funds that can be used to pay dividends and, in the case of ACE, the regulatory requirement that it obtain the prior approval of the NJBPU before dividends can be paid if its equity as a percent of its total capitalization, excluding securitization debt, falls below 30%; (ii) the prior rights of holders of mortgage bonds and other long-term debt issued by the subsidiaries, and any other restrictions imposed in connection with the incurrence of
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liabilities; and (iii) certain provisions of ACE’s charter that impose restrictions on payment of common stock dividends for the benefit of preferred stockholders. Pepco, DPL and ACE have no shares of preferred stock outstanding at December 31, 2013. Currently, the capitalization ratio limitation to which ACE is subject and the restriction in the ACE charter do not limit ACE’s ability to pay common stock dividends. PHI had approximately $595 million and $1,077 million of retained earnings free of restrictions at December 31, 2013 and 2012, respectively. These amounts represent the total retained earnings balances at those dates.
For the years ended December 31, 2013, 2012 and 2011, dividends paid by PHI’s subsidiaries were as follows:
Calculations of Earnings per Share of Common Stock
The numerator and denominator for basic and diluted earnings per share of common stock calculations are shown below.
(a) The number of options to purchase shares of common stock that were excluded from the calculation of diluted earnings per share as they are considered to be anti-dilutive were zero, zero and 14,900 for the years ended December 31, 2013, 2012 and 2011, respectively.
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Equity Forward Transaction
During 2012, PHI entered into an equity forward transaction in connection with a public offering of PHI common stock. Pursuant to the terms of this transaction, a forward counterparty borrowed 17,922,077 shares of PHI’s common stock from third parties and sold them to a group of underwriters for $19.25 per share, less an underwriting discount equal to $0.67375 per share. Under the terms of the equity forward transaction, upon physical settlement thereof, PHI was required to issue and deliver shares of PHI common stock to the forward counterparty at the then applicable forward sale price. The forward sale price was initially determined to be $18.57625 per share at the time the equity forward transaction was entered into and was subject to reduction from time to time in accordance with the terms of the equity forward transaction. PHI believed that the equity forward transaction substantially eliminated future equity price risk because the forward sale price was determinable as of the date that PHI entered into the equity forward transaction and was only reduced pursuant to the contractual terms of the equity forward transaction through the settlement date, which reductions were not affected by a future change in the market price of the PHI common stock. On February 27, 2013, PHI physically settled the equity forward at the then applicable forward sale price of $17.39 per share. The proceeds of approximately $312 million were used to repay outstanding commercial paper, a portion of which had been issued in order to make capital contributions to the utilities, and for general corporate purposes.
Direct Stock Purchase and Dividend Reinvestment Plan
PHI maintains a Direct Stock Purchase and Dividend Reinvestment Plan (DRP) through which participants may reinvest cash dividends. In addition, participants can make purchases of shares of PHI common stock through the investment of not less than $25 per purchase nor more than $300,000 each calendar year. Shares of common stock purchased through the DRP may be new shares, treasury shares held by PHI, or, at the election of PHI, shares purchased in the open market. Approximately 2 million new shares were issued and sold under the DRP in each of 2013, 2012 and 2011.
Pepco Holdings Common Stock Reserved and Unissued
The following table presents Pepco Holdings’ common stock reserved and unissued at December 31, 2013:
(a) No further awards will be made under this plan.
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(13) DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
Derivative Instruments
DPL uses derivative instruments in the form of swaps and over-the-counter options primarily to reduce natural gas commodity price volatility and to limit its customers’ exposure to increases in the market price of natural gas under a hedging program approved by the DPSC. DPL uses these derivatives to manage the commodity price risk associated with its physical natural gas purchase contracts. All premiums paid and other transaction costs incurred as part of DPL’s natural gas hedging activity, in addition to all gains and losses related to hedging activities, are deferred under FASB guidance on regulated operations (ASC 980) until recovered from its customers through a fuel adjustment clause approved by the DPSC. The natural gas purchase contracts qualify as normal purchases, which are not required to be recorded in the financial statements until settled.
ACE was ordered to enter into the SOCAs by the NJBPU, and under the SOCAs, ACE would have received payments from or made payments to electric generation facilities based on i) the difference between the fixed price in the SOCAs and the price for capacity that clears PJM and ii) ACE’s annual proportion of the total New Jersey load relative to the other EDCs in New Jersey. ACE began applying derivative accounting to two of its SOCAs as of June 30, 2012 because these generators cleared the 2015-2016 PJM capacity auction in May 2012. The fair value of the derivatives embedded in these SOCAs were deferred as regulatory assets or regulatory liabilities because the NJBPU allowed full recovery from ACE’s distribution customers for any payments made by ACE, and ACE’s distribution customers would be entitled to payments received by ACE. As further discussed in Note (7), “Regulatory Matters,” in light of a Federal district court order, which ruled that the SOCAs are void, invalid and unenforceable, and ACE’s subsequent termination of the SOCAs in the fourth quarter of 2013, ACE derecognized the derivative assets and derivative liabilities related to the SOCAs.
The tables below identify the balance sheet location and fair values of derivative instruments as of December 31, 2013 and 2012:
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All derivative assets and liabilities available to be offset under master netting arrangements were netted as of December 31, 2013 and 2012. The amount of cash collateral that was offset against these derivative positions is as follows:
As of December 31, 2013 and 2012, all PHI cash collateral pledged related to derivative instruments accounted for at fair value was entitled to be offset under master netting agreements.
Derivatives Designated as Hedging Instruments
Cash Flow Hedges
Power Delivery
All premiums paid and other transaction costs incurred as part of DPL’s natural gas hedging activity, in addition to all of DPL’s gains and losses related to hedging activities, are deferred under FASB guidance on regulated operations until recovered from customers based on the fuel adjustment clause approved by the DPSC. For the years ended December 31, 2013, 2012 and 2011, DPL had no net unrealized derivative losses and zero, zero and $5 million, respectively, of net realized losses associated with cash flow hedges recognized in the consolidated statements of (loss) income (through Fuel and purchased energy expense) that were deferred as Regulatory assets.
Cash Flow Hedges Included in Accumulated Other Comprehensive Loss
PHI also may use derivative instruments from time to time to mitigate the effects of fluctuating interest rates on debt issued in connection with the operation of its businesses. In June 2002, PHI entered into several treasury rate lock transactions in anticipation of the issuance of several series of fixed-rate debt commencing in August 2002. Upon issuance of the fixed-rate debt in August 2002, the treasury rate locks were terminated at a loss. The loss has been deferred in AOCL and is being recognized in interest expense over the life of the debt issued as interest payments are made.
The tables below provide details regarding terminated cash flow hedges included in PHI’s consolidated balance sheets as of December 31, 2013 and 2012. The data in the following tables indicate the cumulative net loss after-tax related to terminated cash flow hedges by contract type included in AOCL, the portion of AOCL expected to be reclassified to income during the next 12 months, and the maximum hedge or deferral term:
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Other Derivative Activity
DPL and ACE have certain derivatives that are not in hedge accounting relationships and are not designated as normal purchases or normal sales. These derivatives are recorded at fair value on the consolidated balance sheets with the gain or loss for changes in fair value recorded in income. In accordance with FASB guidance on regulated operations, offsetting regulatory liabilities or regulatory assets are recorded on the consolidated balance sheets and the recognition of the derivative gain or loss is deferred because of the DPSC-approved fuel adjustment clause for DPL’s derivatives and the NJBPU order (prior to the order in October 2013 of a Federal district court as described in Note (7), “Regulatory Matters” which caused ACE to derecognize the derivative assets and derivative liabilities related to the SOCAs in the fourth quarter of 2013) pertaining to the SOCAs within which ACE’s capacity derivatives are embedded. The following table indicates the net unrealized and net realized derivative gains and (losses) arising during the period associated with these derivatives that were recognized in the consolidated statements of (loss) income (through Fuel and purchased energy expense) and that were also deferred as Regulatory assets for the years ended December 31, 2013, 2012 and 2011:
As of December 31, 2013 and 2012, the quantities and positions of DPL’s net outstanding natural gas commodity forward contracts and ACE’s capacity derivatives associated with the SOCAs that did not qualify for hedge accounting were:
Contingent Credit Risk Features
The primary contracts used by the Power Delivery segment for derivative transactions are entered into under the International Swaps and Derivatives Association Master Agreement (ISDA) or similar agreements that closely mirror the principal credit provisions of the ISDA. The ISDAs include a Credit Support Annex (CSA) that governs the mutual posting and administration of collateral security. The failure of a party to comply with an obligation under the CSA, including an obligation to transfer collateral security when due or the failure to maintain any required credit support, constitutes an event of default under the ISDA for which the other party may declare an early termination and liquidation of all transactions entered into under the ISDA, including foreclosure against any collateral security. In addition, some of the ISDAs have cross default provisions under which a default by a party under another commodity or derivative contract, or the breach by a party of another borrowing obligation in excess of a specified threshold, is a breach under the ISDA.
Under the ISDA or similar agreements, the parties establish a dollar threshold of unsecured credit for each party in excess of which the party would be required to post collateral to secure its obligations to the other party. The amount of the unsecured credit threshold varies according to the senior, unsecured debt rating of the respective parties or that of a guarantor of the party’s obligations. The fair values of all transactions between the parties are netted under the master netting provisions. Transactions may include derivatives accounted for on-balance sheet as well as those designated as normal purchases and normal sales that are accounted for off-balance sheet. If the aggregate fair value of the transactions in a net loss position exceeds the unsecured credit threshold, then collateral is required to be posted in an amount equal to the
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amount by which the unsecured credit threshold is exceeded. The obligations of DPL are stand-alone obligations without the guarantee of PHI. If DPL’s debt rating were to fall below “investment grade,” the unsecured credit threshold would typically be set at zero and collateral would be required for the entire net loss position. Exchange-traded contracts are required to be fully collateralized without regard to the credit rating of the holder.
The gross fair values of DPL’s derivative liabilities with credit risk-related contingent features as of December 31, 2013 and 2012, were zero and $4 million, respectively, before giving effect to offsetting transactions or collateral under master netting agreements. As of December 31, 2013 and 2012, DPL had posted no cash collateral against its gross derivative liability. If DPL’s debt ratings had been downgraded below investment grade as of December 31, 2013 and 2012, DPL’s net settlement amounts, including both the fair value of its derivative liabilities and its normal purchase and normal sale contracts would have been approximately zero and $2 million, respectively, and DPL would have been required to post collateral with the counterparties of approximately zero and $2 million, respectively. The net settlement and additional collateral amounts reflect the effect of offsetting transactions under master netting agreements.
DPL’s primary source for posting cash collateral or letters of credit is PHI’s credit facility, under which DPL is a borrower. As of December 31, 2013 and 2012, the aggregate amount of cash plus borrowing capacity under the credit facility available to meet the future liquidity needs of PHI’s utility subsidiaries was $332 million and $477 million, respectively.
(14) FAIR VALUE DISCLOSURES
Financial Instruments Measured at Fair Value on a Recurring Basis
PHI applies FASB guidance on fair value measurement and disclosures (ASC 820) that established a framework for measuring fair value and expanded disclosures about fair value measurements. As defined in the guidance, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). PHI utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. Accordingly, PHI utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1) and the lowest priority to unobservable inputs (level 3).
The following tables set forth, by level within the fair value hierarchy, PHI’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2013 and 2012. As required by the guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. PHI’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.
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(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2013.
(b) The fair values of derivative assets and liabilities reflect netting by counterparty before the impact of collateral.
(c) Represents natural gas swaps purchased by DPL as part of a natural gas hedging program approved by the DPSC.
(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2012.
(b) The fair values of derivative assets and liabilities reflect netting by counterparty before the impact of collateral.
(c) Represents natural gas options purchased by DPL as part of a natural gas hedging program approved by the DPSC.
(d) Represents derivatives associated with the ACE SOCAs.
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PHI classifies its fair value balances in the fair value hierarchy based on the observability of the inputs used in the fair value calculation as follows:
Level 1 - Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis, such as the New York Mercantile Exchange (NYMEX).
Level 2 - Pricing inputs are other than quoted prices in active markets included in level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using broker quotes in liquid markets and other observable data. Level 2 also includes those financial instruments that are valued using methodologies that have been corroborated by observable market data through correlation or by other means. Significant assumptions are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.
Executive deferred compensation plan assets and liabilities categorized as level 2 consist of life insurance policies and certain employment agreement obligations. The life insurance policies are categorized as level 2 assets because they are valued based on the assets underlying the policies, which consist of short-term cash equivalents and fixed income securities that are priced using observable market data and can be liquidated for the value of the underlying assets as of December 31, 2013. The level 2 liability associated with the life insurance policies represents a deferred compensation obligation, the value of which is tracked via underlying insurance sub-accounts. The sub-accounts are designed to mirror existing mutual funds and money market funds that are observable and actively traded.
The value of certain employment agreement obligations (which are included with life insurance contracts in the tables above) is derived using a discounted cash flow valuation technique. The discounted cash flow calculations are based on a known and certain stream of payments to be made over time that are discounted to determine their net present value. The primary variable input, the discount rate, is based on market-corroborated and observable published rates. These obligations have been classified as level 2 within the fair value hierarchy because the payment streams represent contractually known and certain amounts and the discount rate is based on published, observable data.
Level 3 - Pricing inputs that are significant and generally less observable than those from objective sources. Level 3 includes those financial instruments that are valued using models or other valuation methodologies.
Derivative instruments categorized as level 3 include natural gas options used by DPL as part of a natural gas hedging program approved by the DPSC and capacity under the SOCAs entered into by ACE:
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DPL applies a Black-Scholes model to value its options with inputs, such as forward price curves, contract prices, contract volumes, the risk-free rate and implied volatility factors that are based on a range of historical NYMEX option prices. DPL maintains valuation policies and procedures and reviews the validity and relevance of the inputs used to estimate the fair value of its options. As of December 31, 2013, all of these contracts classified as level 3 derivative instruments have settled.
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ACE used a discounted cash flow methodology to estimate the fair value of the capacity derivatives embedded in the SOCAs. ACE utilized an external valuation specialist to estimate annual zonal PJM capacity prices through the 2030-2031 auction. The capacity price forecast was based on various assumptions that impact the cost of constructing new generation facilities, including zonal load forecasts, zonal fuel and energy prices, generation capacity and transmission planning, and environmental legislation and regulation. ACE reviewed the assumptions and resulting capacity price forecast for reasonableness. ACE used the capacity price forecast to estimate future cash flows. A significant change in the forecasted prices would have a significant
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impact on the estimated fair value of the SOCAs. ACE employed a discount rate reflective of the estimated weighted average cost of capital for merchant generation companies since payments under the SOCAs are contingent on providing generation capacity. As further discussed in Note (7), “Regulatory Matters,” ACE derecognized the derivative assets and derivative liabilities related to the SOCAs in the fourth quarter of 2013.
The tables below summarize the primary unobservable inputs used to determine the fair value of PHI’s level 3 instruments and the range of values that could be used for those inputs as of December 31, 2012:
PHI used values within these ranges as part of its fair value estimates. A significant change in any of the unobservable inputs within these ranges would have an insignificant impact on the reported fair value as of December 31, 2012.
Executive deferred compensation plan assets include certain life insurance policies that are valued using the cash surrender value of the policies, net of loans against those policies. The cash surrender values do not represent a quoted price in an active market; therefore, those inputs are unobservable and the policies are categorized as level 3. Cash surrender values are provided by third parties and reviewed by PHI for reasonableness.
Reconciliations of the beginning and ending balances of PHI’s fair value measurements using significant unobservable inputs (Level 3) for the years ended December 31, 2013 and 2012 are shown below:
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The breakdown of realized and unrealized gains or (losses) on level 3 instruments included in income as a component of Other income or Other operation and maintenance expense for the periods below were as follows:
Other Financial Instruments
The estimated fair values of PHI’s Long-term debt instruments that are measured at amortized cost in PHI’s consolidated financial statements and the associated level of the estimates within the fair value hierarchy as of December 31, 2013 and 2012 are shown in the tables below. As required by the fair value measurement guidance, debt instruments are classified in their entirety within the fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. PHI’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, which may affect the valuation of fair value debt instruments and their placement within the fair value hierarchy levels.
The fair value of Long-term debt and Transition Bonds categorized as level 2 is based on a blend of quoted prices for the debt and quoted prices for similar debt on the measurement date. The blend places more weight on current pricing information when determining the final fair value measurement. The fair value information is provided by brokers, and PHI reviews the methodologies and results.
The fair value of Long-term debt categorized as level 3 is based on a discounted cash flow methodology using observable inputs, such as the U.S. Treasury yield, and unobservable inputs, such as credit spreads, because quoted prices for the debt or similar debt in active markets were insufficient. The Long-term project funding represents debt instruments issued by Pepco Energy Services related to its energy savings contracts. Long-term project funding is categorized as level 3 because PHI concluded that the amortized cost carrying amounts for these instruments approximates fair value, which does not represent a quoted price in an active market.
(a) The carrying amount for Long-term debt is $4,456 million as of December 31, 2013.
(b) The carrying amount for Transition Bonds, including amounts due within one year, is $255 million as of December 31, 2013.
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(a) Certain debt instruments that were categorized as level 1 at December 31, 2012, have been reclassified as level 2 to conform to the current period presentation.
(b) The carrying amount for Long-term debt is $4,177 million as of December 31, 2012.
(c) The carrying amount for Transition Bonds, including amounts due within one year, is $295 million as of December 31, 2012.
The carrying amounts of all other financial instruments in the accompanying consolidated financial statements approximate fair value.
(15) COMMITMENTS AND CONTINGENCIES
General Litigation and Other Matters
From time to time, PHI and its subsidiaries are named as defendants in litigation, usually relating to general liability or auto liability claims that resulted in personal injury or property damage to third parties. PHI and each of its subsidiaries are self-insured against such claims up to a certain self-insured retention amount and maintain insurance coverage against such claims at higher levels, to the extent deemed prudent by management. In addition, PHI’s contracts with its vendors generally require the vendors to name PHI and/or its subsidiaries as additional insureds for the amounts at least equal to PHI’s self-insured retention. Further, PHI’s contracts with its vendors require the vendors to indemnify PHI for various acts and activities that may give rise to claims against PHI. Loss contingency liabilities for both asserted and unasserted claims are recognized if it is probable that a loss will result from such a claim and if the amounts of the losses can be reasonably estimated. Although the outcome of the claims and proceedings cannot be predicted with any certainty, management believes that there are no existing claims or proceedings that are likely to have a material adverse effect on PHI’s or its subsidiaries’ financial condition, results of operations or cash flows. At December 31, 2013, PHI had loss contingency liabilities for general litigation totaling approximately $30 million (including amounts related to the matters specifically described below) and the portion of these loss contingency liabilities in excess of the self-insured retention amount was substantially offset by insurance receivables.
Pepco Substation Injury Claim
In May 2013, a contract worker erecting a scaffold at a Pepco substation came into contact with an energized station service feeder and suffered serious injuries. In August 2013, the individual filed suit against Pepco in the Circuit Court for Montgomery County, Maryland, seeking damages for medical expenses, loss of future earning capacity, pain and suffering and the cost of a life care plan aggregating to a maximum claim of approximately $28.1 million. Discovery is ongoing in the case and, if a settlement cannot be reached with respect to this matter, a trial is expected to begin in October 2014. Pepco has notified its insurers of the incident and believes that the insurance policies in force at the time of the incident, including the policies of the contractor performing the scaffold work (which name Pepco as an additional insured), will offset substantially all of Pepco’s costs associated with the resolution of this matter, including Pepco’s self-insured retention amount. At December 31, 2013, Pepco has concluded that a loss is probable with respect to this matter and has recorded an estimated loss contingency liability, which is included in the liability for general litigation referred to above as of December 31, 2013. Pepco has also concluded as of December 31, 2013 that realization of its insurance claims associated with this matter is probable and, accordingly, has recorded an estimated insurance receivable offsetting substantially all of the related loss contingency liability.
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ACE Asbestos Claim
In September 2011, an asbestos complaint was filed in the New Jersey Superior Court, Law Division, against ACE (among other defendants) asserting claims under New Jersey’s Wrongful Death and Survival statutes. The complaint, filed by the estate of a decedent who was the wife of a former employee of ACE, alleges that the decedent’s mesothelioma was caused by exposure to asbestos brought home by her husband on his work clothes. New Jersey courts have recognized a cause of action against a premise owner in a so-called “take home” case if it can be shown that the harm was foreseeable. In this case, the complaint seeks recovery of an unspecified amount of damages for, among other things, the decedent’s past medical expenses, loss of earnings, and pain and suffering between the time of injury and death, and asserts a punitive damage claim. At December 31, 2013, ACE has concluded that a loss is probable with respect to this matter and has recorded an estimated loss contingency liability, which is included in the liability for general litigation referred to above as of December 31, 2013. However, due to the inherent uncertainty of litigation, ACE is unable to estimate a maximum amount of possible loss because the damages sought are indeterminate and the matter involves facts that ACE believes are distinguishable from the facts of the “take-home” cause of action recognized by the New Jersey courts.
ACE Electrical Contact Injury Claims
In October 2010, a farm combine came into and remained in contact with a primary electric line in ACE’s service territory in New Jersey. As a result, two individuals operating the combine received fatal electrical contact injuries. While attempting to rescue those two individuals, another individual sustained third-degree burns to his torso and upper extremities. In September 2012, the individual who received third-degree burns filed suit in New Jersey Superior Court, Salem County. In October 2012, additional suits were filed in the same court by or on behalf of the estates of the deceased individuals. Plaintiffs in each of the cases are seeking indeterminate damages and allege that ACE was negligent in the design, construction, erection, operation and maintenance of its poles, power lines, and equipment, and that ACE failed to warn and protect the public from the foreseeable dangers of farm equipment contacting electric lines. Discovery is ongoing in this matter and the litigation involves a number of other defendants and the filing of numerous cross-claims. ACE has notified its insurers of the incident and believes that the insurance policies in force at the time of the incident will offset ACE’s costs associated with the resolution of this matter in excess of ACE’s self-insured retention amount. At December 31, 2013, ACE has concluded that a loss is probable with respect to these claims and has recorded an estimated loss contingency liability, which is included in the liability for general litigation referred to above as of December 31, 2013. ACE has also concluded as of December 31, 2013 that realization of its insurance claims associated with this matter is probable and, accordingly, has recorded an estimated insurance receivable offsetting substantially all of the loss contingency liability in excess of ACE’s self-insured retention amount.
Pepco Energy Services Billing Claims
During 2012, Pepco Energy Services received letters on behalf of two school districts in Maryland, which claim that invoices in connection with electricity supply contracts contained certain allegedly unauthorized charges, totaling approximately $7 million. The school districts also claim additional compounded interest totaling approximately $9 million. Although no litigation involving Pepco Energy Services related to these claims has commenced, in August and September 2013, Pepco Energy Services received correspondence from the Superintendent of each of the school districts advising of the intention to render a decision regarding an unresolved dispute between the school district and Pepco Energy Services. Pepco Energy Services filed timely answers to the Superintendents challenging the authority of the respective Superintendents to render decisions on the claims and also disputing the merits of the
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allegations regarding unauthorized charges as well as the claims of entitlement to compounded interest. To date, one of the two districts has submitted a late response to the answer of Pepco Energy Services maintaining that its Superintendent does have authority to render a decision but acknowledging the availability of administrative and judicial review of the merits of any decision. The response of the other district is overdue. As of December 31, 2013, Pepco Energy Services has concluded that a loss is reasonably possible with respect to these claims, but the amount of loss, if any, is not reasonably estimable.
Environmental Matters
PHI, through its subsidiaries, is subject to regulation by various federal, regional, state and local authorities with respect to the environmental effects of its operations, including air and water quality control, solid and hazardous waste disposal and limitations on land use. Although penalties assessed for violations of environmental laws and regulations are not recoverable from customers of PHI’s utility subsidiaries, environmental clean-up costs incurred by Pepco, DPL and ACE generally are included by each company in its respective cost of service for ratemaking purposes. The total accrued liabilities for the environmental contingencies described below of PHI and its subsidiaries at December 31, 2013 are summarized as follows:
Conectiv Energy Wholesale Power Generation Sites
In July 2010, PHI sold the Conectiv Energy wholesale power generation business to Calpine. Under New Jersey’s Industrial Site Recovery Act (ISRA), the transfer of ownership triggered an obligation on the part of Conectiv Energy to remediate any environmental contamination at each of the nine Conectiv Energy generating facility sites located in New Jersey. Under the terms of the sale, Calpine has assumed responsibility for performing the ISRA-required remediation and for the payment of all related ISRA compliance costs up to $10 million. PHI is obligated to indemnify Calpine for any ISRA compliance remediation costs in excess of $10 million. According to PHI’s estimates, the costs of ISRA-required remediation activities at the nine generating facility sites located in New Jersey are in the range of approximately $7 million to $18 million. The amount accrued by PHI for the ISRA-required remediation activities at the nine generating facility sites is included in the table above in the column entitled “Legacy Generation - Non-Regulated.”
In September 2011, PHI received a request for data from the U.S. Environmental Protection Agency (EPA) regarding operations at the Deepwater generating facility in New Jersey (which was included in the sale to Calpine) between February 2004 and July 1, 2010, to demonstrate compliance with the Clean Air Act’s new source review permitting program. PHI responded to the data request. Under the terms of the Calpine sale, PHI is obligated to indemnify Calpine for any failure of PHI, on or prior to the closing date of the sale, to comply with environmental laws attributable to the construction of new, or modification of existing, sources of air emissions. At this time, PHI does not expect this inquiry to have a material adverse effect on its consolidated financial condition, results of operations or cash flows.
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Franklin Slag Pile Site
In November 2008, ACE received a general notice letter from EPA concerning the Franklin Slag Pile site in Philadelphia, Pennsylvania, asserting that ACE is a potentially responsible party (PRP) that may have liability for clean-up costs with respect to the site and for the costs of implementing an EPA-mandated remedy. EPA’s claims are based on ACE’s sale of boiler slag from the B.L. England generating facility, then owned by ACE, to MDC Industries, Inc. (MDC) during the period June 1978 to May 1983. EPA claims that the boiler slag ACE sold to MDC contained copper and lead, which are hazardous substances under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA), and that the sales transactions may have constituted an arrangement for the disposal or treatment of hazardous substances at the site, which could be a basis for liability under CERCLA. The EPA letter also states that, as of the date of the letter, EPA’s expenditures for response measures at the site have exceeded $6 million. EPA’s feasibility study for this site conducted in 2007 identified a range of alternatives for permanent remedial measures with varying cost estimates, and the estimated cost of EPA’s preferred alternative is approximately $6 million.
ACE believes that the B.L. England boiler slag sold to MDC was a valuable material with various industrial applications and, therefore, the sale was not an arrangement for the disposal or treatment of any hazardous substances as would be necessary to constitute a basis for liability under CERCLA. ACE intends to contest any claims to the contrary made by EPA. In a May 2009 decision arising under CERCLA, which did not involve ACE, the U.S. Supreme Court rejected an EPA argument that the sale of a useful product constituted an arrangement for disposal or treatment of hazardous substances. While this decision supports ACE’s position, at this time ACE cannot predict how EPA will proceed with respect to the Franklin Slag Pile site, or what portion, if any, of the Franklin Slag Pile site response costs EPA would seek to recover from ACE. Costs to resolve this matter are not expected to be material and are expensed as incurred.
Peck Iron and Metal Site
EPA informed Pepco in a May 2009 letter that Pepco may be a PRP under CERCLA with respect to the cleanup of the Peck Iron and Metal site in Portsmouth, Virginia, and for costs EPA has incurred in cleaning up the site. The EPA letter states that Peck Iron and Metal purchased, processed, stored and shipped metal scrap from military bases, governmental agencies and businesses and that Peck’s metal scrap operations resulted in the improper storage and disposal of hazardous substances. EPA bases its allegation that Pepco arranged for disposal or treatment of hazardous substances sent to the site on information provided by former Peck Iron and Metal personnel, who informed EPA that Pepco was a customer at the site. Pepco has advised EPA by letter that its records show no evidence of any sale of scrap metal by Pepco to the site. Even if EPA has such records and such sales did occur, Pepco believes that any such scrap metal sales may be entitled to the recyclable material exemption from CERCLA liability. In a Federal Register notice published in November 2009, EPA placed the Peck Iron and Metal site on the National Priorities List. The National Priorities List, among other things, serves as a guide to EPA in determining which sites warrant further investigation to assess the nature and extent of the human health and environmental risks associated with a site. In September 2011, EPA initiated a remedial investigation/feasibility study (RI/FS) using federal funds. Pepco cannot at this time estimate an amount or range of reasonably possible loss associated with this RI/FS, any remediation activities to be performed at the site or any other costs that EPA might seek to impose on Pepco.
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Ward Transformer Site
In April 2009, a group of PRPs with respect to the Ward Transformer site in Raleigh, North Carolina, filed a complaint in the U.S. District Court for the Eastern District of North Carolina, alleging cost recovery and/or contribution claims against a number of entities, including Pepco, DPL and ACE, based on their alleged sale of transformers to Ward Transformer, with respect to past and future response costs incurred by the PRP group in performing a removal action at the site. In a March 2010 order, the court denied the defendants’ motion to dismiss. The litigation is moving forward with certain “test case” defendants (not including Pepco, DPL and ACE) filing summary judgment motions regarding liability. The case has been stayed as to the remaining defendants pending rulings upon the test cases. In a January 31, 2013 order, the Federal district court granted summary judgment for the test case defendant whom plaintiffs alleged was liable based on its sale of transformers to Ward Transformer. The Federal district court’s order, which plaintiffs have appealed to the U.S. Court of Appeals for the Fourth Circuit, addresses only the liability of the test case defendant. PHI has concluded that a loss is reasonably possible with respect to this matter, but is unable to estimate an amount or range of reasonably possible losses to which it may be exposed. PHI does not believe that any of its three utility subsidiaries had extensive business transactions, if any, with the Ward Transformer site.
Benning Road Site
In September 2010, PHI received a letter from EPA identifying the Benning Road location, consisting of a generation facility operated by Pepco Energy Services until the facility was deactivated in June 2012, and a transmission and distribution facility operated by Pepco, as one of six land-based sites potentially contributing to contamination of the lower Anacostia River. The letter stated that the principal contaminants of concern are polychlorinated biphenyls and polycyclic aromatic hydrocarbons. In December 2011, the U.S. District Court for the District of Columbia approved a consent decree entered into by Pepco and Pepco Energy Services with the District of Columbia Department of the Environment (DDOE), which requires Pepco and Pepco Energy Services to conduct a RI/FS for the Benning Road site and an approximately 10 to 15 acre portion of the adjacent Anacostia River. The RI/FS will form the basis for DDOE’s selection of a remedial action for the Benning Road site and for the Anacostia River sediment associated with the site. The consent decree does not obligate Pepco or Pepco Energy Services to pay for or perform any remediation work, but it is anticipated that DDOE will look to the companies to assume responsibility for cleanup of any conditions in the river that are determined to be attributable to past activities at the Benning Road site.
In December 2012, DDOE approved the RI/FS work plan. RI/FS field work commenced in January 2013 and is still in progress. In October 2013, Pepco and Pepco Energy Services submitted a work plan addendum for approval by DDOE identifying the location of groundwater monitoring wells to be installed at the site and sampled as the last phase of the field work. The work plan addendum has been revised in response to comments from DDOE, and it is expected that the addendum will be approved and the next phase of field work will commence before the end of the first quarter of 2014. Once all of the field work has been completed, Pepco and Pepco Energy Services will prepare RI/FS reports for review and approval by DDOE after solicitation and consideration of public comment. The next status report to the court is due on May 24, 2014.
The remediation costs accrued for this matter are included in the table above in the columns entitled “Transmission and Distribution,” “Legacy Generation - Regulated,” and “Legacy Generation - Non-Regulated.”
Indian River Oil Release
In 2001, DPL entered into a consent agreement with the Delaware Department of Natural Resources and Environmental Control for remediation, site restoration, natural resource damage compensatory projects and other costs associated with environmental contamination resulting from an oil release at the Indian River generating facility, which was sold in June 2001. The amount of remediation costs accrued for this matter is included in the table above in the column entitled “Legacy Generation - Regulated.”
PEPCO HOLDINGS
Potomac River Mineral Oil Release
In January 2011, a coupling failure on a transformer cooler pipe resulted in a release of non-toxic mineral oil at Pepco’s Potomac River substation in Alexandria, Virginia. An overflow of an underground secondary containment reservoir resulted in approximately 4,500 gallons of mineral oil flowing into the Potomac River.
Beginning in March 2011, DDOE issued a series of compliance directives requiring Pepco to prepare an incident report, provide certain records, and prepare and implement plans for sampling surface water and river sediments and assessing ecological risks and natural resources damages. Pepco completed field sampling during the fourth quarter of 2011 and submitted sampling results to DDOE during the second quarter of 2012. Pepco is continuing discussions with DDOE regarding the need for any further response actions but expects that additional monitoring of shoreline sediments may be required.
In June 2012, Pepco commenced discussions with DDOE regarding a possible consent decree that would resolve DDOE’s threatened enforcement action, including civil penalties, for alleged violation of the District’s Water Pollution Control Law, as well as for damages to natural resources. Pepco and DDOE have reached an agreement in principle that would consist of a combination of a civil penalty and Supplemental Environmental Projects (SEPs) with a total cost to Pepco of approximately $1 million. DDOE has endorsed Pepco’s proposed SEP involving the installation and operation of a trash collection system at a stormwater outfall that drains to the Anacostia River. DDOE and Pepco are completing negotiations on the text of a consent decree to document the settlement of DDOE’s enforcement action and a written statement of work describing the details of the trash collection system SEP. It is expected that the consent decree will be filed with the District of Columbia Superior Court by the end of the first quarter of 2014, with a request that the court approve the consent decree following a period of at least 30 days for public comment. Discussions will proceed separately with DDOE and the federal resource trustees regarding the settlement of a natural resource damage (NRD) claim under federal law. Based on discussions to date, PHI and Pepco do not believe that the resolution of DDOE’s enforcement action or the federal NRD claim will have a material adverse effect on their respective financial condition, results of operations or cash flows.
As a result of the mineral oil release, Pepco implemented certain interim operational changes to the secondary containment systems at the facility which involve pumping accumulated storm water to an aboveground holding tank for off-site disposal. In December 2011, Pepco completed the installation of a treatment system designed to allow automatic discharge of accumulated storm water from the secondary containment system. Pepco currently is seeking DDOE’s and EPA’s approval to commence operation of the new system on a pilot basis to demonstrate its effectiveness in meeting both secondary containment requirements and water quality standards related to the discharge of storm water from the facility. In the meantime, Pepco is continuing to use the aboveground holding tank to manage storm water from the secondary containment system. Pepco also is evaluating other technical and regulatory options for managing storm water from the secondary containment system as alternatives to the proposed treatment system discharge currently under discussion with EPA and DDOE.
The amount accrued for this matter is included in the table above in the column entitled “Transmission and Distribution.”
Metal Bank Site
In the first quarter of 2013, the National Oceanic and Atmospheric Administration (NOAA) contacted Pepco and DPL on behalf of itself and other federal and state trustees to request that Pepco and DPL execute a tolling agreement to facilitate settlement negotiations concerning natural resource damages allegedly caused by releases of hazardous substances, including polychlorinated biphenyls, at the Metal Bank Superfund Site located in Philadelphia, Pennsylvania. Pepco and DPL have executed the tolling agreement and will participate in settlement discussions with the NOAA, the trustees and other PRPs.
PEPCO HOLDINGS
The amount accrued for this matter is included in the table above in the column entitled “Transmission and Distribution.”
Brandywine Fly Ash Disposal Site
In February 2013, Pepco received a letter from the Maryland Department of the Environment (MDE) requesting that Pepco investigate the extent of waste on a Pepco right-of-way that traverses the Brandywine fly ash disposal site in Brandywine, Prince George’s County, Maryland, owned by GenOn MD Ash Management, LLC (GenOn). In July 2013, while reserving its rights and related defenses under a 2000 asset purchase and sale agreement covering the sale of this site, Pepco indicated its willingness to investigate the extent of, and propose an appropriate closure plan to address, ash on the right-of-way. Pepco submitted a schedule for development of a closure plan to MDE on September 30, 2013 and, by letter dated October 18, 2013, MDE approved the schedule.
PHI and Pepco have determined that a loss associated with this matter for PHI and Pepco is probable and have estimated that the costs for implementation of a closure plan and cap on the site are in the range of approximately $3 million to $6 million. PHI and Pepco believe that the costs incurred in this matter will be recoverable from GenOn under the 2000 sale agreement.
The amount accrued for this matter is included in the table above in the column entitled “Transmission and Distribution.”
Watts Branch Insulating Fluid Release
On September 13, 2013, a Washington Metropolitan Area Transit Authority contractor damaged a Pepco underground transmission feeder while drilling a grout column for a subway tunnel under a city street. The damage caused the release of approximately 11,250 gallons of insulating fluid, a small amount of which reached the Watts Branch, a tributary of the Anacostia River. The U.S. Coast Guard (USCG) issued a notice of federal interest for an oil pollution incident, informing Pepco of its responsibility under the Oil Pollution Act of 1990 for removal costs and damages from the release. In addition, on September 25, 2013, DDOE issued a compliance directive that required Pepco to prepare an incident investigation report describing the events leading up to the release. The compliance directive also required Pepco to prepare work plans for sampling the insulating fluid and for developing and implementing a biological assessment and physical habitat quality assessment to be conducted in Watts Branch. Pepco prepared the incident investigation report and work plans and submitted them to DDOE and USCG. In December 2013, Pepco received and responded to an EPA information request regarding this incident.
PHI and Pepco believe that a loss in this matter is probable; however, the costs to resolve this matter are expected to be less than $1 million and are being expensed as incurred. PHI and Pepco further believe that the costs incurred will be recoverable from the party or parties responsible for the release. On December 4, 2013, the USCG delivered a Notice of Violation with respect to this matter, which imposed a $3,000 penalty on Pepco, which Pepco has paid.
PHI’s Cross-Border Energy Lease Investments
As discussed in Note (19), “Discontinued Operations - Cross-Border Energy Lease Investments,” PHI held a portfolio of cross-border energy lease investments involving public utility assets located outside of the United States. Each of these investments was comprised of multiple leases and was structured as a sale and leaseback transaction commonly referred to by the IRS as a sale-in, lease-out, or SILO, transaction.
PEPCO HOLDINGS
Since 2005, PHI’s cross-border energy lease investments have been under examination by the IRS as part of the PHI federal income tax audits. In connection with the audit of PHI’s 2001-2002 income tax returns, the IRS disallowed the depreciation and interest deductions in excess of rental income claimed by PHI for six of the eight lease investments and, in connection with the audits of PHI’s 2003-2005 and 2006-2008 income tax returns, the IRS disallowed such deductions in excess of rental income for all eight of the lease investments. In addition, the IRS has sought to recharacterize each of the leases as a loan transaction in each of the years under audit as to which PHI would be subject to original issue discount income. PHI has disagreed with the IRS’ proposed adjustments to the 2001-2008 income tax returns and has filed protests of these findings for each year with the Office of Appeals of the IRS. In November 2010, PHI entered into a settlement agreement with the IRS for the 2001 and 2002 tax years for the purpose of commencing litigation associated with this matter and subsequently filed refund claims in July 2011 for the disallowed tax deductions relating to the leases for these years. In January 2011, as part of this settlement, PHI paid $74 million of additional tax for 2001 and 2002, penalties of $1 million, and $28 million in interest associated with the disallowed deductions. Since the July 2011 refund claims were not approved by the IRS within the statutory six-month period, in January 2012 PHI filed complaints in the U.S. Court of Federal Claims seeking recovery of the tax payment, interest and penalties. The 2003-2005 and 2006-2011 income tax return audits continue to be in process with the IRS Office of Appeals and the IRS Exam Division, respectively, and are not presently a part of the U.S. Court of Federal Claims litigation discussed above.
On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit issued an opinion in Consolidated Edison Company of New York, Inc. & Subsidiaries v. United States (to which PHI is not a party) that disallowed tax benefits associated with Consolidated Edison’s cross-border lease transaction. While PHI believes that its tax position with regard to its cross-border energy lease investments is appropriate, after analyzing the recent U.S. Court of Appeals ruling, PHI determined in the first quarter of 2013 that its tax position with respect to the tax benefits associated with the cross-border energy leases no longer met the more-likely-than-not standard of recognition for accounting purposes. Accordingly, PHI recorded a non-cash after-tax charge of $377 million in the first quarter of 2013 (as discussed in Note (19), “Discontinued Operations - Cross-Border Energy Lease Investments”), consisting of a charge to reduce the carrying value of the cross-border energy lease investments and a charge to reflect the anticipated additional interest expense related to changes in PHI’s estimated federal and state income tax obligations for the period over which the tax benefits ultimately may be disallowed. PHI had also previously made certain business assumptions regarding foreign investment opportunities available at the end of the full lease terms. During the first quarter of 2013, management believed that its conclusions regarding these business assumptions were no longer supportable, and the tax effects of this change in conclusion were included in the charge. While the IRS could require PHI to pay a penalty of up to 20% of the amount of additional taxes due, PHI believes that it is more likely than not that no such penalty will be incurred, and therefore no amount for any potential penalty was included in the charge recorded in the first quarter of 2013.
In the event that the IRS were to be successful in disallowing 100% of the tax benefits associated with these lease investments and recharacterizing these lease investments as loans, PHI estimated that, as of March 31, 2013, it would have been obligated to pay approximately $192 million in additional federal taxes (net of the $74 million tax payment described above) and approximately $50 million of interest on the additional federal taxes. These amounts, totaling $242 million, were estimated after consideration of certain tax benefits arising from matters unrelated to the leases that would offset the taxes and interest due, including PHI’s best estimate of the expected resolution of other uncertain and effectively settled tax positions, the carrying back and carrying forward of any existing net operating losses, and the application of certain amounts paid in advance to the IRS. In order to mitigate PHI’s ongoing interest costs associated with the $242 million estimate of additional taxes and interest, PHI made an advanced payment to the IRS of $242 million in the first quarter of 2013. This advanced payment was funded from currently available sources of liquidity and short-term borrowings. A portion of the proceeds from lease terminations was used to repay the short-term borrowings utilized to fund the advanced payment.
PEPCO HOLDINGS
In order to mitigate the cost of continued litigation related to the cross-border energy lease investments, PHI and its subsidiaries have entered into discussions with the IRS with the intention of seeking a settlement of all tax issues for open tax years 2001 through 2011, including the cross-border energy lease issue. PHI currently believes that it is possible that a settlement with the IRS may be reached in 2014. If a settlement of all tax issues or a standalone settlement on the leases is not reached, PHI may move forward with its litigation with the IRS. Further discovery in the case is stayed until April 24, 2014, pursuant to an order issued by the court on January 30, 2014.
District of Columbia Tax Legislation
In 2011, the Council of the District of Columbia approved the Budget Support Act which requires that corporate taxpayers in the District of Columbia calculate taxable income allocable or apportioned to the District of Columbia by reference to the income and apportionment factors applicable to commonly controlled entities organized within the United States that are engaged in a unitary business. In the aggregate, this new tax reporting method reduced pre-tax earnings for the year ended December 31, 2011 by $7 million ($5 million after-tax) as further discussed in Note (11), “Income Taxes,” and Note (19), “Discontinued Operations.” During 2012, the District of Columbia Office of Tax and Revenue adopted regulations to implement this reporting method. PHI has analyzed these regulations and determined that the regulations did not impact PHI’s results of operations for the years ended December 31, 2013 and 2012.
Third Party Guarantees, Indemnifications, and Off-Balance Sheet Arrangements
PHI and certain of its subsidiaries have various financial and performance guarantees and indemnification obligations that they have entered into in the normal course of business to facilitate commercial transactions with third parties as discussed below.
As of December 31, 2013, PHI and its subsidiaries were parties to a variety of agreements pursuant to which they were guarantors for standby letters of credit, energy procurement obligations, and other commitments and obligations. The commitments and obligations, in millions of dollars, were as follows:
(a) PHI has continued contractual commitments for performance and related payments of Pepco Energy Services primarily to Independent System Operators and distribution companies.
(b) Represents guarantees by PHI of Conectiv Energy’s derivatives portfolio transferred in connection with the disposition of Conectiv Energy’s wholesale business. The derivative portfolio guarantee is currently $13 million and covers Conectiv Energy’s performance prior to the assignment. This guarantee will remain in effect until the end of 2015.
(c) Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $55 million, $10 million of which is a guarantee by PHI, $15 million by Pepco, $17 million by DPL and $13 million by ACE. The minimum lease term associated with these assets ranges from 1 to 4 years. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.
PHI and certain of its subsidiaries have entered into various indemnification agreements related to purchase and sale agreements and other types of contractual agreements with vendors and other third parties. These indemnification agreements typically cover environmental, tax, litigation and other matters, as well as breaches of representations, warranties and covenants set forth in these agreements. Typically, claims may be made by third parties under these indemnification agreements over various periods of time depending on the nature of the claim. The maximum potential exposure under these indemnification agreements can range from a specified dollar amount to an unlimited amount depending on the nature of the claim and the particular transaction. The total maximum potential amount of future payments under these indemnification agreements is not estimable due to several factors, including uncertainty as to whether or when claims may be made under these indemnities.
PEPCO HOLDINGS
Energy Savings Performance Contracts
Pepco Energy Services has a diverse portfolio of energy savings performance contracts that are associated with the installation of energy savings equipment or combined heat and power facilities for federal, state and local government customers. As part of the energy savings contracts, Pepco Energy Services typically guarantees that the equipment or systems it installs will generate a specified amount of energy savings on an annual basis over a multi-year period. As of December 31, 2013, the remaining notional amount of Pepco Energy Services’ energy savings guarantees over the life of the multi-year performance contracts on: i) completed projects was $252 million with the longest guarantee having a remaining term of 12 years; and, ii) projects under construction was $187 million with the longest guarantee having a term of 23 years after completion of construction. On an annual basis, Pepco Energy Services undertakes a measurement and verification process to determine the amount of energy savings for the year and whether there is any shortfall in the annual energy savings compared to the guaranteed amount.
As of December 31, 2013, Pepco Energy Services had a performance guarantee contract associated with the production at a combined heat and power facility that is under construction totaling $15 million in notional value over 20 years.
Pepco Energy Services recognizes a liability for the value of the estimated energy savings or production shortfalls when it is probable that the guaranteed amounts will not be achieved and the amount is reasonably estimable. As of December 31, 2013, Pepco Energy Services had an accrued liability of $1 million for its energy savings contracts that it established during 2012. There was no significant change in the type of contracts issued during the year ended December 31, 2013 as compared to the year ended December 31, 2012.
Dividends
On January 23, 2014, Pepco Holdings’ Board of Directors declared a dividend on common stock of 27 cents per share payable March 31, 2014, to stockholders of record on March 10, 2014.
Contractual Obligations
Power Purchase Contracts
As of December 31, 2013, Pepco Holdings’ contractual obligations under non-derivative power purchase contracts were $278 million in 2014, $562 million in 2015 to 2016, $486 million in 2017 to 2018, and $1,386 million in 2019 and thereafter.
Lease Commitments
Rental expense for operating leases was $54 million, $52 million and $46 million for the years ended December 31, 2013, 2012 and 2011, respectively.
Total future minimum operating lease payments for Pepco Holdings as of December 31, 2013, are $44 million in 2014, $42 million in 2015, $39 million in 2016, $36 million in 2017, $37 million in 2018 and $342 million thereafter.
(16) VARIABLE INTEREST ENTITIES
PHI is required to consolidate a variable interest entity (VIE) in accordance with FASB ASC 810 if PHI or a subsidiary is the primary beneficiary of the VIE. The primary beneficiary of a VIE is typically the entity with both the power to direct activities most significantly impacting economic performance of the VIE and the obligation to absorb losses or receive benefits of the VIE that could potentially be significant to the VIE. PHI performs a qualitative analysis to determine whether a variable interest provides a controlling financial interest in a VIE. Set forth below are the relationships with respect to which PHI conducted a VIE analysis as of December 31, 2013:
PEPCO HOLDINGS
DPL Renewable Energy Transactions
DPL is subject to Renewable Energy Portfolio Standards (RPS) in the state of Delaware that require it to obtain renewable energy credits (RECs) for energy delivered to its customers. DPL’s costs associated with obtaining RECs to fulfill its RPS obligations are recoverable from its customers by law. As of December 31, 2013, PHI, through its DPL subsidiary, is a party to three land-based wind PPAs in the aggregate amount of 128 MWs and one solar PPA with a 10 MW facility. Each of the facilities associated with these PPAs is operational, and DPL is obligated to purchase energy and RECs in amounts generated and delivered by the wind facilities and solar renewable energy credits (SRECs) from the solar facility up to certain amounts (as set forth below) at rates that are primarily fixed under the respective PPA. PHI and DPL have concluded that while VIEs exist under these contracts, consolidation is not required for any of these PPAs under the FASB guidance on the consolidation of variable interest entities as DPL is not the primary beneficiary. DPL has not provided financial or other support under these arrangements that it was not previously contractually required to provide during the periods presented, nor does DPL have any intention to provide such additional support.
Because DPL has no equity or debt interest in these renewable energy transactions, the maximum exposure to loss relates primarily to any above-market costs incurred for power or RECs. Due to unpredictability in amount of MW’s ultimately purchased under the PPAs for purchased renewable energy and SRECs, PHI and DPL are unable to quantify the maximum exposure to loss. The power purchase and REC costs are recoverable from DPL’s customers through regulated rates.
DPL is obligated to purchase energy and RECs from one of the wind facilities through 2024 in amounts not to exceed 50 MWs, from the second wind facility through 2031 in amounts not to exceed 40 MWs, and from the third wind facility through 2031 in amounts not to exceed 38 MWs. DPL’s purchases under the three wind PPAs totaled $30 million, $27 million and $18 million for the years ended December 31, 2013, 2012 and 2011, respectively.
The term of the agreement with the solar facility is 20 years and DPL is obligated to purchase SRECs in an amount up to 70 percent of the energy output at a fixed price. DPL’s purchases under the solar agreement were $3 million, $2 million and $1 million for the years ended December 31, 2013, 2012 and 2011, respectively.
On October 18, 2011, the DPSC approved a tariff submitted by DPL in accordance with the requirements of the RPS specific to fuel cell facilities totaling 30 MWs to be constructed by a qualified fuel cell provider. The tariff and the RPS establish that DPL would be an agent to collect payments in advance from its distribution customers and remit them to the qualified fuel cell provider for each MW hour (MWh) of energy produced by the fuel cell facilities over 21 years. DPL has no obligation to the qualified fuel cell provider other than to remit payments collected from its distribution customers pursuant to the tariff. The RPS provides for a reduction in DPL’s REC requirements based upon the actual energy output of the facilities. At December 31, 2013 and 2012, 15 MWs and 3 MWs of capacity were available from fuel cell facilities placed in service under the tariff, respectively. DPL billed $23 million and $4 million to distribution customers during the years ended December 31, 2013 and 2012, respectively. PHI and DPL have concluded that while a VIE exists under this arrangement, consolidation is not required for this arrangement under the FASB guidance on consolidation of variable interest entities as DPL is not the primary beneficiary.
ACE Power Purchase Agreements
PHI, through its ACE subsidiary, is a party to three PPAs with unaffiliated NUGs totaling 459 MWs. One of the agreements ends in 2016 and the other two end in 2024. PHI and ACE were not involved in the creation of these contracts and have no equity or debt invested in these entities. In performing its VIE analysis, PHI has been unable to obtain sufficient information to determine whether these three entities were variable interest entities or if ACE was the primary beneficiary. As a result, PHI has applied the scope exemption from the consolidation guidance.
PEPCO HOLDINGS
Because ACE has no equity or debt invested in the NUGs, the maximum exposure to loss relates primarily to any above-market costs incurred for power. Due to unpredictability in the PPAs pricing for purchased energy, PHI and ACE are unable to quantify the maximum exposure to loss. The power purchase costs are recoverable from ACE’s customers through regulated rates. Purchase activities with the NUGs, including excess power purchases not covered by the PPAs, for the years ended December 31, 2013, 2012 and 2011 were approximately $221 million, $206 million and $218 million, respectively, of which approximately $206 million, $201 million and $206 million, respectively, consisted of power purchases under the PPAs.
ACE Funding
In 2001, ACE established ACE Funding solely for the purpose of securitizing authorized portions of ACE’s recoverable stranded costs through the issuance and sale of Transition Bonds. The proceeds of the sale of each series of Transition Bonds were transferred to ACE in exchange for the transfer by ACE to ACE Funding of the right to collect a non-bypassable Transition Bond Charge from ACE customers pursuant to bondable stranded costs rate orders issued by the NJBPU in an amount sufficient to fund the principal and interest payments on the Transition Bonds and related taxes, expenses and fees (Bondable Transition Property). The assets of ACE Funding, including the Bondable Transition Property, and the Transition Bond Charges (representing revenue ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds and related taxes, expenses and fees) collected from ACE’s customers, are not available to creditors of ACE. The holders of Transition Bonds have recourse only to the assets of ACE Funding. ACE owns 100 percent of the equity of ACE Funding, and PHI and ACE consolidate ACE Funding in their consolidated financial statements as ACE is the primary beneficiary of ACE Funding under the variable interest entity consolidation guidance.
PEPCO HOLDINGS
(17) ACCUMULATED OTHER COMPREHENSIVE LOSS
The components of Pepco Holdings’ AOCL relating to continuing and discontinued operations are as follows. For additional information, see the consolidated statements of comprehensive income.
PEPCO HOLDINGS
(18) QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
The quarterly data presented below reflect all adjustments necessary in the opinion of management for a fair presentation of the interim results. Quarterly data normally vary seasonally because of temperature variations and differences between summer and winter rates. The totals of the four quarterly basic and diluted earnings per common share amounts may not equal the basic and diluted earnings per common share for the year due to changes in the number of shares of common stock outstanding during the year.
(a) Includes a pre-tax impairment loss of $4 million ($3 million after-tax) at Pepco Energy Services associated with a landfill gas-fired electric generation facility.
(b) Includes an income tax charge of $56 million (after-tax) primarily associated with interest on uncertain and effectively settled tax positions and an income tax charge of $101 million associated with the establishment of valuation allowances against certain deferred tax assets of PCI.
(a) Includes $9 million of intra-company revenues (and associated costs) previously eliminated in consolidation which will continue to be recognized from third parties subsequent to the completion of the wind-down of the Pepco Energy Services’ retail electric and natural gas supply businesses.
(b) Includes impairment losses of $12 million pre-tax ($7 million after-tax) at Pepco Energy Services associated primarily with investments in landfill gas-fired electric generation facilities, and the combustion turbines at Buzzard Point.
PEPCO HOLDINGS
(19) DISCONTINUED OPERATIONS
PHI’s (loss) income from discontinued operations, net of income taxes, is comprised of the following:
Cross-Border Energy Lease Investments
Between 1994 and 2002, PCI entered into cross-border energy lease investments consisting of hydroelectric generation facilities, coal-fired electric generation facilities and natural gas distribution networks located outside of the United States. Each of these lease investments was structured as a sale and leaseback transaction commonly referred to as a sale-in, lease-out, or SILO, transaction. As of December 31, 2013 and 2012, the lease portfolio consisted of zero investments and six investments, respectively, with a net investment value of zero and $1,237 million, respectively.
During the second and third quarters of 2013, PHI terminated early all of its interests in the six remaining lease investments. PHI received aggregate net cash proceeds from these early terminations of $873 million (net of aggregate termination payments of $2.0 billion used to retire the non-recourse debt associated with the terminated leases) and recorded an aggregate pre-tax loss, including transaction costs, of approximately $3 million ($2 million after-tax), representing the excess of the carrying value of the terminated leases over the net cash proceeds received. As a result, PHI has reported the results of operations of the cross-border energy lease investments as discontinued operations in all periods presented in the accompanying consolidated statements of (loss) income. Further, the assets and liabilities related to the cross-border energy lease investments are reported as held for disposition as of each date in the accompanying consolidated balance sheets.
Operating Results
The operating results for the cross-border energy lease investments are as follows:
(a) Includes income tax (benefit) expense of approximately $(44) million, $5 million and $(2) million for the years ended December 31, 2013, 2012 and 2011, respectively.
(b) Includes income tax (benefit) expense of approximately $(1) million, $30 million and $36 million for the years ended December 31, 2013, 2012 and 2011, respectively.
PEPCO HOLDINGS
On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit issued an opinion in Consolidated Edison Company of New York, Inc. & Subsidiaries v. United States (to which PHI is not a party) that disallowed tax benefits associated with Consolidated Edison’s cross-border lease transaction. As a result of the court’s ruling in this case, PHI determined in the first quarter of 2013 that its tax position with respect to the benefits associated with its cross-border energy leases no longer met the more-likely-than-not standard of recognition for accounting purposes, and PCI recorded after-tax non-cash charges of $323 million in the first quarter of 2013 and $6 million in the second quarter of 2013, consisting of the following components:
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A non-cash pre-tax charge of $373 million ($313 million after-tax) to reduce the carrying value of these cross-border energy lease investments under FASB guidance on leases (ASC 840). This pre-tax charge was originally recorded in the consolidated statements of (loss) income as a reduction in operating revenue and is now reflected in (loss) income from discontinued operations, net of income taxes.
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A non-cash charge of $16 million after-tax to reflect the anticipated additional net interest expense under FASB guidance for income taxes (ASC 740) related to estimated federal and state income tax obligations for the period over which the tax benefits may be disallowed. This after-tax charge was originally recorded in the consolidated statements of (loss) income as an increase in income tax expense and is now reflected in (loss) income from discontinued operations, net of income taxes. The after-tax interest charge for PHI on a consolidated basis was $70 million and this amount was allocated to each member of PHI’s consolidated group as if each member was a separate taxpayer, resulting in the recognition of a $12 million interest benefit for the Power Delivery segment, and interest expense of $16 million for PCI and $66 million for Corporate and Other, respectively.
PHI had also previously made certain business assumptions regarding foreign investment opportunities available at the end of the full lease terms. In view of the change in PHI’s tax position with respect to the tax benefits associated with the cross-border energy lease investments and PHI’s resulting decision to pursue the early termination of these investments, management concluded in the first quarter of 2013 that these business assumptions were no longer supportable and the tax effects of this conclusion were reflected in the after-tax charge of $313 million described above.
PHI accrued no penalties associated with its re-assessment of the likely outcome of tax positions associated with the cross-border energy lease investments. While the IRS could require PHI to pay a penalty of up to 20% of the amount of additional taxes due, PHI believes that it is more likely than not that no such penalty will be incurred, and therefore no amount for any potential penalty was included in the charge.
During 2012, PHI entered into early termination agreements with two lessees involving all of the leases comprising one of the original eight lease investments. The early terminations of the leases were negotiated at the request of the lessees. PHI received net cash proceeds of $202 million (net of a termination payment of $520 million used to retire the non-recourse debt associated with the terminated leases) and recorded a pre-tax gain of $39 million, representing the excess of the net cash proceeds over the carrying value of the lease investments.
During 2011, PHI entered into early termination agreements with two lessees involving all of the leases comprising one of the original eight lease investments and a small portion of the leases comprising a second lease investment. The early terminations of the leases were negotiated at the request of the lessees. PHI received net cash proceeds of $161 million (net of a termination payment of $423 million used to retire the non-recourse debt associated with the terminated leases) and recorded a pre-tax gain of $39 million, representing the excess of the net cash proceeds over the carrying value of the lease investments.
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With respect to the leases terminated in 2012 and 2011, PHI had previously made certain business assumptions regarding foreign investment opportunities available at the end of the full lease terms. Because the leases were terminated in each case earlier than full term, management decided not to pursue these opportunities and recognized the related tax consequences by recording income tax charges in the amounts of $16 million and $22 million for the years ended December 31, 2012 and 2011, respectively. The after-tax gains on the lease terminations were $9 million and $3 million for the years ended December 31, 2012 and 2011, respectively, including the income tax charges discussed above and an income tax provision at the statutory Federal rate of $14 million for each early lease termination. As of December 31, 2012, PHI had no intent to terminate early any other leases in the lease portfolio and maintained its assertion that the foreign earnings recognized at the end of the lease term with respect to certain of these remaining leases will remain invested abroad. See Note (15), “Commitments and Contingencies - PHI’s Cross-Border Energy Lease Investments,” regarding a subsequent change in management’s intent.
PHI was required to assess on a periodic basis the likely outcome of tax positions relating to its cross-border energy lease investments and, if there was a change or a projected change in the timing of the tax benefits generated by the transactions, PHI was required to recalculate the value of its net investment. In that regard, PHI modified its tax cash flow assumptions in 2011 and recorded a non-cash pre-tax charge of $7 million to reduce the carrying value of its net investment. The tax cash flow assumptions changed in 2011 as a result of the enactment of tax regulations in the District of Columbia to implement the mandatory unitary combined reporting method. The charge was recorded as a reduction in cross-border energy lease investment revenue in 2011.
For additional information concerning these cross-border energy lease investments, see Note (15), “Commitments and Contingencies - PHI’s Cross-Border Energy Lease Investments.”
Balance Sheet Information
As of December 31, 2013 and 2012, the assets held for disposition and liabilities associated with assets held for disposition related to the cross-border energy lease investments are:
To ensure credit quality, PHI regularly monitored the financial performance and condition of the lessees under the former cross-border energy lease investments. Changes in credit quality were assessed to determine whether they affected the carrying value of the leases. PHI compared each lessee’s performance to annual compliance requirements set by the terms and conditions of the leases and compared published credit ratings to minimum credit rating requirements in the leases for lessees with public credit ratings. In addition, PHI routinely met with senior executives of the lessees to discuss their company and asset performance. If the annual compliance requirements or minimum credit ratings were not met, remedies would have been available under the leases.
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The table below shows PHI’s net investment in these leases by the published credit ratings of the lessees as of December 31:
(a) Excludes the credit ratings associated with collateral posted by the lessees in these transactions.
Retail Electric and Natural Gas Supply Businesses of Pepco Energy Services
On March 21, 2013, Pepco Energy Services entered into an agreement whereby a third party assumed all the rights and obligations of the remaining natural gas supply customer contracts, and the associated supply obligations, inventory and derivative contracts. The transaction was completed on April 1, 2013. In addition, in the second quarter of 2013, Pepco Energy Services completed the wind-down of its retail electric supply business by terminating its remaining customer supply and wholesale purchase obligations beyond June 30, 2013. As a result, PHI has reported the results of operations of Pepco Energy Services’ retail electric and natural gas supply businesses as discontinued operations in all periods presented in the accompanying consolidated statements of (loss) income. Further, the assets and liabilities of Pepco Energy Services’ retail electric and natural gas supply businesses are reported as held for disposition as of each date presented in the accompanying consolidated balance sheets.
Operating Results
The operating results for the retail electric and natural gas supply businesses of Pepco Energy Services are as follows:
(a) Includes income tax expense of approximately $3 million, $18 million and $1 million for the years ended December 31, 2013, 2012 and 2011, respectively.
Balance Sheet Information
As of December 31, 2013 and 2012, the retail electric and natural gas supply businesses of Pepco Energy Services had net accounts receivable of zero and $33 million, respectively, inventory assets of $1 million and $3 million, respectively, gross derivative assets of zero and $1 million respectively, other current assets of zero and $1 million, respectively, accrued liabilities of $1 million and $20 million, respectively, gross derivative liabilities of zero and $21 million, respectively, exclusive of the collateral pledged by Pepco Energy Services against the derivative liabilities, and other current liabilities of zero and $1 million, respectively. As of December 31, 2012, the derivative assets were considered level 1 within the fair value hierarchy, and $11 million and $10 million of the derivative liabilities were considered levels 1 and 2, respectively, within the fair value hierarchy.
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Derivative Instruments and Hedging Activities
Derivatives were used by the retail electric and natural gas supply businesses of Pepco Energy Services to hedge commodity price risk.
The retail electric and natural gas supply businesses of Pepco Energy Services entered into energy commodity contracts in the form of natural gas futures, swaps, options and forward contracts to hedge commodity price risk in connection with the purchase of physical natural gas and electricity for distribution to customers. The primary risk management objective was to manage the spread between retail sales commitments and the cost of supply used to service those commitments to ensure stable cash flows and lock in favorable prices and margins when they became available. There were no derivatives for Pepco Energy Services as of December 31, 2013.
Commodity contracts held by the retail electric and natural gas supply businesses of Pepco Energy Services that were not designated for hedge accounting, did not qualify for hedge accounting, or did not meet the requirements for normal purchase and normal sale accounting, were marked to market through current earnings. Forward contracts that met the requirements for normal purchase and normal sale accounting were recorded on an accrual basis.
The table below identifies the balance sheet location and fair values of the retail electric and natural gas supply businesses’ derivative instruments as of December 31, 2012:
(a) Amounts included in Derivatives Designated as Hedging Instruments primarily consist of derivatives that were designated as cash flow hedges prior to Pepco Energy Services’ election to discontinue cash flow hedge accounting for these derivatives.
Under FASB guidance on the offsetting of balance sheet accounts (ASC 210-20), the retail electric and natural gas supply businesses of Pepco Energy Services offset the fair value amounts recognized for derivative instruments and the fair value amounts recognized for related collateral positions executed with the same counterparty under master netting agreements. No derivative assets or liabilities were available to be offset under master netting agreements as of December 31, 2012. Cash collateral pledged to counterparties with the right to reclaim of $18 million (including cash deposits on commodity brokerage accounts) was offset against these derivative positions.
As of December 31, 2013 and 2012, all cash collateral pledged by the retail electric and natural gas supply businesses related to derivative instruments accounted for at fair value was entitled to be offset under master netting agreements.
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Derivatives Designated as Hedging Instruments
At December 31, 2012, the cumulative net pre-tax loss related to effective cash flow hedges of the retail electric and natural gas supply businesses of Pepco Energy Services included in AOCL was $10 million ($6 million after-tax). With the assumption by a third party, on April 1, 2013, of all the rights and obligations of the derivative contracts associated with the retail natural gas supply business, and the completion of the wind-down of the retail electric supply business in the second quarter of 2013, all of the losses deferred in AOCL associated with derivatives that Pepco Energy Services had previously designated as cash flow hedges were reclassified into income. As a result, a loss of $10 million ($6 million after-tax) was reclassified from AOCL to (Loss) income from discontinued operations, net of income taxes, for the year ended December 31, 2013.
Other Derivative Activity
The retail electric and natural gas supply businesses of Pepco Energy Services held certain derivatives that were not in hedge accounting relationships and were not designated as normal purchases or normal sales. These derivatives were recorded at fair value on the balance sheet with the gain or loss for changes in fair value recorded through (Loss) income from discontinued operations, net of income taxes.
For the years ended December 31, 2013, 2012, and 2011, the amount of the derivative gain (loss) for the retail electric and natural gas supply businesses of Pepco Energy Services recognized in (Loss) income from discontinued operations, net of income taxes is provided in the table below:
As of December 31, 2013, the retail electric and natural gas supply businesses of Pepco Energy Services had no outstanding commodity forward contracts or derivative positions.
As of December 31, 2012, the retail electric and natural gas supply businesses of Pepco Energy Services had the following net outstanding commodity forward contract quantities and net position on derivatives that did not qualify for hedge accounting:
As of December 31, 2013, Pepco Energy Services had posted net cash collateral of $3 million and letters of credit of less than $1 million. As December 31, 2012, Pepco Energy Services had posted net cash collateral of $25 million and letters of credit of less than $1 million.
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Conectiv Energy
In April 2010, the Board of Directors approved a plan for the disposition of PHI’s competitive wholesale power generation, marketing and supply business, which had been conducted through Conectiv Energy. On July 1, 2010, PHI completed the sale of Conectiv Energy’s wholesale power generation business to Calpine. The disposition of Conectiv Energy’s remaining assets and businesses, consisting of its load service supply contracts, energy hedging portfolio, certain tolling agreements and other assets not included in the Calpine sale, has been completed.
Conectiv Energy’s loss from discontinued operations, net of income taxes, for the years ended December 31, 2013, 2012 and 2011, was zero, zero and $3 million, respectively. Conectiv Energy’s other comprehensive income from discontinued operations, net of income taxes, for each of the years ended December 31, 2013, 2012 and 2011, was zero.
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Management’s Report on Internal Control over Financial Reporting
The management of Potomac Electric Power Company (Pepco) is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management of Pepco assessed Pepco’s internal control over financial reporting as of December 31, 2013 based on the framework in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its assessment, the management of Pepco concluded that Pepco’s internal control over financial reporting was effective as of December 31, 2013.
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Report of Independent Registered Public Accounting Firm
To the Shareholder and Board of Directors of
Potomac Electric Power Company
In our opinion, the financial statements of Potomac Electric Power Company (a wholly owned subsidiary of Pepco Holdings, Inc.) listed in the accompanying index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Potomac Electric Power Company at December 31, 2013 and December 31, 2012, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2013 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule of Potomac Electric Power Company listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
Washington, D.C.
February 27, 2014
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POTOMAC ELECTRIC POWER COMPANY
STATEMENTS OF INCOME
The accompanying Notes are an integral part of these Financial Statements.
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POTOMAC ELECTRIC POWER COMPANY
BALANCE SHEETS
The accompanying Notes are an integral part of these Financial Statements.
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POTOMAC ELECTRIC POWER COMPANY
BALANCE SHEETS
The accompanying Notes are an integral part of these Financial Statements.
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POTOMAC ELECTRIC POWER COMPANY
STATEMENTS OF CASH FLOWS
The accompanying Notes are an integral part of these Financial Statements.
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POTOMAC ELECTRIC POWER COMPANY
STATEMENTS OF EQUITY
The accompanying Notes are an integral part of these Financial Statements.
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NOTES TO FINANCIAL STATEMENTS
POTOMAC ELECTRIC POWER COMPANY
(1) ORGANIZATION
Potomac Electric Power Company (Pepco) is engaged in the transmission and distribution of electricity in the District of Columbia and major portions of Prince George’s County and Montgomery County in suburban Maryland. Pepco also provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its service territories who do not elect to purchase electricity from a competitive energy supplier. Default Electricity Supply is known as Standard Offer Service in both the District of Columbia and Maryland. Pepco is a wholly owned subsidiary of Pepco Holdings, Inc. (Pepco Holdings or PHI).
(2) SIGNIFICANT ACCOUNTING POLICIES
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities in the financial statements and accompanying notes. Although Pepco believes that its estimates and assumptions are reasonable, they are based upon information available to management at the time the estimates are made. Actual results may differ significantly from these estimates.
Significant matters that involve the use of estimates include the assessment of contingencies, the calculation of future cash flows and fair value amounts for use in asset impairment evaluations, pension and other postretirement benefits assumptions, the assessment of the probability of recovery of regulatory assets, accrual of storm restoration costs, accrual of unbilled revenue, recognition of changes in network service transmission rates for prior service year costs, accrual of loss contingency liabilities for general and auto liability claims and income tax provisions and reserves. Additionally, Pepco is subject to legal, regulatory, and other proceedings and claims that arise in the ordinary course of its business. Pepco records an estimated liability for these proceedings and claims when it is probable that a loss has been incurred and the loss is reasonably estimable.
Revenue Recognition
Pepco recognizes revenue upon distribution of electricity to its customers, including unbilled revenue for services rendered, but not yet billed. Pepco’s unbilled revenue was $80 million and $81 million as of December 31, 2013 and 2012, respectively, and these amounts are included in Accounts receivable. Pepco calculates unbilled revenue using an output-based methodology. This methodology is based on the supply of electricity intended for distribution to customers. The unbilled revenue process requires management to make assumptions and judgments about input factors such as customer sales mix, temperature, and estimated line losses (estimates of electricity expected to be lost in the process of its transmission and distribution to customers). The assumptions and judgments are inherently uncertain and susceptible to change from period to period, and if actual results differ from projected results, the impact could be material.
Taxes related to the consumption of electricity by its customers, such as fuel, energy, or other similar taxes, are components of Pepco’s tariffs and, as such, are billed to customers and recorded in Operating revenue. Accruals for the remittance of these taxes by Pepco are recorded in Other taxes.
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Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions
Taxes included in Pepco’s gross revenues were $318 million, $324 million and $338 million for the years ended December 31, 2013, 2012 and 2011, respectively.
Long-Lived Assets Impairment Evaluation
Pepco evaluates certain long-lived assets to be held and used (for example, equipment and real estate) for impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. Examples of such events or changes include a significant decrease in the market price of a long-lived asset or a significant adverse change in the manner in which an asset is being used or its physical condition. A long-lived asset to be held and used is written down to its estimated fair value if the expected future undiscounted cash flow from the asset is less than its carrying value.
For long-lived assets that can be classified as assets to be disposed of by sale, an impairment loss is recognized to the extent that the asset’s carrying value exceeds its estimated fair value including costs to sell.
Income Taxes
Pepco, as a direct subsidiary of Pepco Holdings, is included in the consolidated federal income tax return of PHI. Federal income taxes are allocated to Pepco based upon the taxable income or loss amounts, determined on a separate return basis.
The financial statements include current and deferred income taxes. Current income taxes represent the amount of tax expected to be reported on Pepco’s state income tax returns and the amount of federal income tax allocated from Pepco Holdings.
Deferred income tax assets and liabilities represent the tax effects of temporary differences between the financial statement basis and tax basis of existing assets and liabilities and they are measured using presently enacted tax rates. The portion of Pepco’s deferred tax liability applicable to its utility operations that has not been recovered from utility customers represents income taxes recoverable in the future and is included in Regulatory assets on the balance sheets. See Note (6), “Regulatory Matters,” for additional information.
Deferred income tax expense generally represents the net change during the reporting period in the net deferred tax liability and deferred recoverable income taxes.
Pepco recognizes interest on underpayments and overpayments of income taxes, interest on uncertain tax positions, and tax-related penalties in income tax expense.
Investment tax credits are being amortized to income over the useful lives of the related property.
Cash and Cash Equivalents
Cash and cash equivalents include cash on hand, cash invested in money market funds and commercial paper held with original maturities of three months or less. Additionally, deposits in PHI’s money pool, which Pepco and certain other PHI subsidiaries use to manage short-term cash management requirements, are considered cash equivalents. Deposits in the money pool are guaranteed by PHI. PHI deposits funds in the money pool to the extent that the pool has insufficient funds to meet the needs of its participants, which may require PHI to borrow funds for deposit from external sources.
Restricted Cash Equivalents
The Restricted cash equivalents included in Current assets consist of (i) cash held as collateral that is restricted from use for general corporate purposes and (ii) cash equivalents that are specifically segregated based on management’s intent to use such cash equivalents for a particular purpose. The classification as current conforms to the classification of the related liabilities.
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Accounts Receivable and Allowance for Uncollectible Accounts
Pepco’s Accounts receivable balance primarily consists of customer accounts receivable arising from the sale of goods and services to customers within its service territory, other accounts receivable, and accrued unbilled revenue. Accrued unbilled revenue represents revenue earned in the current period but not billed to the customer until a future date (usually within one month after the receivable is recorded).
Pepco maintains an allowance for uncollectible accounts and changes in the allowance are recorded as an adjustment to Other operation and maintenance expense in the statements of income. Pepco determines the amount of the allowance based on specific identification of material amounts at risk by customer and maintains a reserve based on its historical collection experience. The adequacy of this allowance is assessed on a quarterly basis by evaluating all known factors such as the aging of the receivables, historical collection experience, the economic and competitive environment and changes in the creditworthiness of its customers. Accounts receivable are written off in the period in which the receivable is deemed uncollectible and collection efforts have been exhausted. Recoveries of Accounts receivable previously written off are recorded when it is probable they will be recovered. Although Pepco believes its allowance is adequate, it cannot anticipate with any certainty the changes in the financial condition of its customers. As a result, Pepco records adjustments to the allowance for uncollectible accounts in the period in which the new information that requires an adjustment to the reserve becomes known.
Inventories
Included in Inventories are transmission and distribution materials and supplies. Pepco utilizes the weighted average cost method of accounting for inventory items. Under this method, an average price is determined for the quantity of units acquired at each price level and is applied to the ending quantity to calculate the total ending inventory balance. Materials and supplies are recorded in Inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed.
Regulatory Assets and Regulatory Liabilities
Pepco is regulated by the Maryland Public Service Commission (MPSC) and the District of Columbia Public Service Commission (DCPSC). The transmission of electricity by Pepco is regulated by the Federal Energy Regulatory Commission (FERC).
Based on the regulatory framework in which it has operated, Pepco has historically applied, and in connection with its transmission and distribution business continues to apply, the Financial Accounting Standards Board (FASB) guidance on regulated operations (Accounting Standards Codification (ASC) 980). The guidance allows regulated entities, in appropriate circumstances, to defer the income statement impact of certain costs that are expected to be recovered in future rates through the establishment of regulatory assets and defer certain revenues that are expected to be refunded to customers through the establishment of regulatory liabilities. Management’s assessment of the probability of recovery of regulatory assets requires judgment and interpretation of laws, regulatory commission orders and other factors. If management subsequently determines, based on changes in facts or circumstances, that a regulatory asset is not probable of recovery, the regulatory asset would be eliminated through a charge to earnings.
Effective June 2007, the MPSC approved a bill stabilization adjustment (BSA) mechanism for retail customers. Effective November 2009, the DCPSC approved a BSA for retail customers. For customers to whom the BSA applies, Pepco recognizes distribution revenue based on an approved distribution charge per customer. From a revenue recognition standpoint, the BSA has the effect of decoupling the distribution revenue recognized in a reporting period from the amount of power delivered during that period. Pursuant to this mechanism, Pepco recognizes either (i) a positive adjustment equal to the amount by which revenue from Maryland and the District of Columbia retail distribution sales falls short of the revenue that Pepco is entitled to earn based on the approved distribution charge per customer, or (ii) a
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negative adjustment equal to the amount by which revenue from such distribution sales exceeds the revenue that Pepco is entitled to earn based on the approved distribution charge per customer (a Revenue Decoupling Adjustment). A net positive Revenue Decoupling Adjustment is recorded as a regulatory asset and a net negative Revenue Decoupling Adjustment is recorded as a regulatory liability.
Investment in Trust
Represents assets held in a trust for the benefit of participants in the Pepco Owned Life Insurance plan.
Property, Plant and Equipment
Property, plant and equipment is recorded at original cost, including labor, materials, asset retirement costs and other direct and indirect costs including capitalized interest. The carrying value of Property, plant and equipment is evaluated for impairment whenever circumstances indicate the carrying value of those assets may not be recoverable. Upon retirement, the cost of regulated property, net of salvage, is charged to Accumulated depreciation. For additional information regarding the treatment of asset removal obligations, see the “Asset Removal Costs” section included in this Note.
The annual provision for depreciation on electric property, plant and equipment is computed on a straight-line basis using composite rates by classes of depreciable property. Accumulated depreciation is charged with the cost of depreciable property retired, less salvage and other recoveries. Non-operating and other property is generally depreciated on a straight-line basis over the useful lives of the assets. The system-wide composite annual depreciation rates for the years ended December 31, 2013, 2012 and 2011 for Pepco’s property were approximately 2.2%, 2.5% and 2.6%, respectively.
In 2010, Pepco was awarded $149 million from the U.S. Department of Energy (DOE) to fund a portion of the costs incurred for the implementation of an advanced metering infrastructure system, direct load control, distribution automation and communications infrastructure in its Maryland and District of Columbia service territories. Pepco has elected to recognize the award proceeds as a reduction in the carrying value of the assets acquired rather than grant income over the service period.
Capitalized Interest and Allowance for Funds Used During Construction
In accordance with FASB guidance on regulated operations (ASC 980), utilities can capitalize the capital costs of financing the construction of plant and equipment as Allowance for Funds Used During Construction (AFUDC). This results in the debt portion of AFUDC being recorded as a reduction of Interest expense and the equity portion of AFUDC being recorded as an increase to Other income in the accompanying statements of income.
Pepco recorded AFUDC for borrowed funds of $5 million, $4 million and $8 million for the years ended December 31, 2013, 2012 and 2011, respectively.
Pepco recorded amounts for the equity component of AFUDC of $9 million, $8 million and $12 million for the years ended December 31, 2013, 2012 and 2011, respectively.
Leasing Activities
Pepco’s lease transactions include office space, equipment, software and vehicles. In accordance with FASB guidance on leases (ASC 840), these leases are classified as either operating leases or capital leases.
Operating Leases
An operating lease in which Pepco is the lessee generally results in a level income statement charge over the term of the lease, reflecting the rental payments required by the lease agreement. If rental payments are not made on a straight-line basis, Pepco’s policy is to recognize rent expense on a straight-line basis over the lease term unless another systematic and rational allocation basis is more representative of the time pattern in which the leased property is physically employed.
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Capital Leases
For ratemaking purposes, capital leases in which Pepco is the lessee are treated as operating leases; therefore, in accordance with FASB guidance on regulated operations (ASC 980), the amortization of the leased asset is based on the recovery of rental payments through customer rates. Investments in equipment under capital leases are stated at cost, less accumulated depreciation. Depreciation is recorded on a straight-line basis over the equipment’s estimated useful life.
Amortization of Debt Issuance and Reacquisition Costs
Pepco defers and amortizes debt issuance costs and long-term debt premiums and discounts over the lives of the respective debt issuances. When refinancing or redeeming existing debt, any unamortized premiums, discounts and debt issuance costs, as well as debt redemption costs, are classified as Regulatory assets and are amortized generally over the life of the new issue.
Asset Removal Costs
In accordance with FASB guidance, asset removal costs are recorded as regulatory liabilities. At December 31, 2013 and 2012, $102 million and $122 million, respectively, of asset removal costs are included in Regulatory liabilities in the accompanying balance sheets.
Pension and Postretirement Benefit Plans
Pepco Holdings sponsors the PHI Retirement Plan, a non-contributory, defined benefit pension plan that covers substantially all employees of Pepco and certain employees of other Pepco Holdings subsidiaries. Pepco Holdings also provides supplemental retirement benefits to certain eligible executives and key employees through nonqualified retirement plans and provides certain postretirement health care and life insurance benefits for eligible retired employees.
The PHI Retirement Plan is accounted for in accordance with FASB guidance on retirement benefits (ASC 715).
Dividend Restrictions
All of Pepco’s shares of outstanding common stock are held by PHI, its parent company. In addition to its future financial performance, the ability of Pepco to pay dividends to its parent company is subject to limits imposed by: (i) state corporate laws, which impose limitations on the funds that can be used to pay dividends, and (ii) the prior rights of holders of future preferred stock, if any, and existing and future mortgage bonds and other long-term debt issued by Pepco and any other restrictions imposed in connection with the incurrence of liabilities. Pepco has no shares of preferred stock outstanding. Pepco had approximately $992 million and $888 million of retained earnings available for payment of common stock dividends at December 31, 2013 and 2012, respectively. These amounts represent the total retained earnings balances at those dates.
Reclassifications and Adjustments
Certain prior period amounts have been reclassified in order to conform to the current period presentation. The following adjustments have been recorded and are not considered material individually or in the aggregate to either the current period or prior period financial results:
Income Tax Adjustments
During 2013, Pepco recorded certain adjustments to correct prior period errors related to income taxes. These adjustments resulted from the completion of additional analysis of deferred tax balances and resulted in an increase in Income tax expense of $4 million for the year ended December 31, 2013.
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During 2011, Pepco recorded an adjustment to correct certain income tax errors related to prior periods associated with the interest on uncertain tax positions. The adjustment resulted in an increase in Income tax expense of $1 million for the year ended December 31, 2011.
(3) NEWLY ADOPTED ACCOUNTING STANDARDS
None.
(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED
Joint and Several Liability Arrangements (ASC 405)
In February 2013, the FASB issued new recognition and disclosure requirements for certain joint and several liability arrangements where the total amount of the obligation is fixed at the reporting date. For arrangements within the scope of this standard, Pepco will be required to include in its liabilities the additional amounts it expects to pay on behalf of its co-obligors, if any. Pepco will also be required to provide additional disclosures including the nature of the arrangements with its co-obligors, the total amounts outstanding under the arrangements between Pepco and its co-obligors, the carrying value of the liability, and the nature and limitations of any recourse provisions that would enable recovery from other entities.
The new requirements are effective retroactively beginning on January 1, 2014, with implementation required for prior periods if joint and several liability arrangement obligations exist as of January 1, 2014. Pepco does not expect this new guidance to have a material impact on its financial statements.
Income Taxes (ASC 740)
In July 2013, the FASB issued new guidance that will require the netting of certain unrecognized tax benefits against a deferred tax asset for a loss or other similar tax carryforward that would apply upon settlement of the uncertain tax position. The new requirements are effective prospectively beginning with Pepco’s March 31, 2014 financial statements for all unrecognized tax benefits existing at the adoption date. Retrospective implementation and early adoption of the guidance are permitted. Pepco does not expect this new guidance to have a material impact on its financial statements.
(5) SEGMENT INFORMATION
The company operates its business as one regulated utility segment, which includes all of its services as described above.
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(6) REGULATORY MATTERS
Regulatory Assets and Regulatory Liabilities
The components of Pepco’s regulatory asset and liability balances at December 31, 2013 and 2012 are as follows:
(a) A return is generally earned on these deferrals.
A description for each category of regulatory assets and regulatory liabilities follows:
Smart Grid Costs: Represents advanced metering infrastructure (AMI) costs associated with the installation of smart meters and the early retirement of existing meters throughout Pepco’s service territory that are recoverable from customers.
Recoverable Income Taxes: Represents amounts recoverable from Pepco’s customers for tax benefits applicable to utility operations that were previously recognized in income tax expense before the company was ordered to account for the tax benefits as deferred income taxes. As the temporary differences between the financial statement basis and tax basis of assets reverse, the deferred recoverable balances are reversed.
Demand-Side Management Costs: Represents recoverable costs associated with customer energy efficiency and conservation programs in Pepco’s Maryland jurisdiction.
Incremental Storm Restoration Costs: Represents total incremental storm restoration costs incurred for repair work due to major storm events in 2012 and 2011, including Hurricane Sandy, the June 2012 derecho, Hurricane Irene, and the 2011 severe winter storm, that are recoverable from customers in the Maryland jurisdiction. Pepco’s costs related to Hurricane Sandy, the June 2012 derecho, Hurricane Irene and the 2011 severe winter storm are being amortized and recovered in rates, each over a five-year period.
MAPP Abandonment Costs: Represents the probable recovery of abandoned costs prudently incurred in connection with the Mid-Atlantic Power Pathway (MAPP) project which was terminated on August 24, 2012. The regulatory asset includes the costs of land, land rights, supplies and materials, engineering and design, environmental services, and project management and administration. The regulatory asset will be reduced as the result of sale or alternative use of these assets. As of December 31, 2013, these assets were earning a return of 12.8%. For additional information, see “MAPP Project” discussion below.
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Recoverable Workers’ Compensation and Long-Term Disability Costs: Represents accrued workers’ compensation and long-term disability costs for Pepco, which are recoverable from customers when actual claims are paid to employees.
Deferred Debt Extinguishment Costs: Represents the costs of debt extinguishment associated with issuances of debt for which recovery through regulated utility rates is considered probable, and if approved, will be amortized to interest expense during the authorized rate recovery period.
Deferred Energy Supply Costs: The regulatory asset represents primarily deferred costs associated with a net under-recovery of Default Electricity Supply costs incurred by Pepco that are probable of recovery in rates.
Other: Represents miscellaneous regulatory assets that generally are being amortized over 1 to 20 years.
Asset Removal Costs: The depreciation rates for Pepco include a component for removal costs, as approved by the relevant federal and state regulatory commissions. Accordingly, Pepco has recorded regulatory liabilities for its estimate of the difference between incurred removal costs and the amount of removal costs recovered through depreciation rates.
Other: Includes miscellaneous regulatory liabilities.
Rate Proceedings
Bill Stabilization Adjustment
Pepco proposed in each of its respective jurisdictions the adoption of a BSA mechanism to decouple retail distribution revenue from the amount of power delivered to retail customers. The BSA proposal has been approved and implemented for Pepco electric service in Maryland and in the District of Columbia.
Under the BSA, customer distribution rates are subject to adjustment (through a credit or surcharge mechanism), depending on whether actual distribution revenue per customer exceeds or falls short of the revenue-per-customer amount approved by the applicable public service commission.
District of Columbia
On March 8, 2013, Pepco filed an application with the DCPSC to increase its annual electric distribution base rates by approximately $44.8 million (as adjusted by Pepco on December 3, 2013), 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. Evidentiary hearings were held in November 2013 and a final DCPSC decision is expected in the first quarter of 2014.
Maryland
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
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among various plant accounts. Among other things, the order additionally authorized Pepco to recover the actual cost of AMI meters installed during the 2011 test year and states 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 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 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 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 provides additional information to the MPSC 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 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.
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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, 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.
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 Pepco and its utility affiliates 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 it 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.
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 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.
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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
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$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 is awaiting the signature of the Mayor of the District of Columbia. Once signed by the Mayor and transmitted to Congress, the legislation will undergo a 30-day Congressional review period before becoming law, which is expected to occur in the second quarter of 2014. The final step would be DCPSC approval of the underground project plan and 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.
MAPP Project
On August 24, 2012, the board of PJM terminated the MAPP project and removed it from PJM’s regional transmission expansion plan. Pepco 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. In December 2012, Pepco submitted a filing to FERC seeking recovery of approximately $50 million of abandoned MAPP costs over a five-year recovery period. 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.
In February 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.
On December 18, 2013, Pepco submitted a settlement agreement to FERC, which provides for recovery of Pepco’s abandoned MAPP costs over a three-year recovery period beginning June 1, 2013. The settlement agreement, which is subject to FERC approval, would resolve all issues concerning the recovery of abandonment costs associated with the cancellation of the MAPP project. Pepco cannot predict the timing or results of a final FERC decision in this proceeding.
As of December 31, 2013, Pepco had a regulatory asset related to the MAPP abandoned costs of approximately $37 million, representing the original filing amount of approximately $50 million of abandoned costs referred to above less: (i) approximately $1 million of disallowed costs written off in 2013; (ii) $4 million of materials transferred to inventories for use on other projects; and (iii) $8 million of amortization expense recorded in 2013. The regulatory asset balance includes the costs of land, land rights, engineering and design, environmental services, and project management and administration.
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(7) PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment is comprised of the following:
The non-operating and other property amounts include balances for general plant, distribution plant and transmission plant held for future use, intangible plant and non-utility property. Utility plant is generally subject to a first mortgage lien.
Capital Leases
Pepco leases its consolidated control center, which is an integrated energy management center used by Pepco to centrally control the operation of its transmission and distribution systems. This lease is accounted for as a capital lease and was initially recorded at the present value of future lease payments. The lease requires semi-annual payments of approximately $8 million over a 25-year period that began in December 1994, and provides for transfer of ownership of the system to Pepco for $1 at the end of the lease term. Under FASB guidance on regulated operations, the amortization of leased assets is modified so that the total interest expense charged on the obligation and amortization expense of the leased asset is equal to the rental expense allowed for rate-making purposes. The amortization expense is included within Depreciation and amortization in the statements of income. This lease is treated as an operating lease for rate-making purposes.
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Capital lease assets recorded within Property, plant and equipment at December 31, 2013 and 2012 are comprised of the following:
The approximate annual commitments under capital leases are $15 million for each year 2014 through 2018, and $16 million thereafter.
(8) PENSION AND OTHER POSTRETIREMENT BENEFITS
Pepco accounts for its participation in its parent’s single-employer plans, Pepco Holding’s non-contributory retirement plan (the PHI Retirement Plan) and the Pepco Holdings, Inc. Welfare Plan for Retirees (the PHI OPEB Plan), as participation in multiemployer plans. For 2013, 2012 and 2011, Pepco was responsible for $34 million, $39 million and $43 million, respectively, of the pension and other postretirement net periodic benefit cost incurred by PHI. Pepco made a discretionary, tax-deductible contribution of zero, $85 million and $40 million to the PHI Retirement Plan for the years ended December 31, 2013, 2012 and 2011, respectively. In addition, Pepco made contributions of $6 million, $5 million and $7 million, respectively, to the PHI OPEB Plan for the years ended December 31, 2013, 2012 and 2011. At December 31, 2013 and 2012, Pepco’s Prepaid pension expense of $332 million and $353 million, respectively, and Other postretirement benefit obligations of $61 million and $66 million, respectively, effectively represent assets and benefit obligations resulting from Pepco’s participation in the Pepco Holdings benefit plans.
Other Postretirement Benefit Plan Amendments
During 2013, PHI approved two amendments to its other postretirement benefits plan. These amendments impacted the retiree health care and the retiree life insurance benefits, and were effective on January 1, 2014. As a result of the amendments, which were cumulatively significant, PHI remeasured its accumulated postretirement benefit obligation for other postretirement benefits as of July 1, 2013. The remeasurement resulted in a $4 million reduction in Pepco’s net periodic benefit cost for other postretirement benefits in 2013. Approximately 38% of net periodic other postretirement benefit costs were capitalized in 2013.
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(9) DEBT
Long-Term Debt
The components of long-term debt are shown in the table below:
(a) Represents a series of Collateral First Mortgage Bonds securing a series of senior notes issued by Pepco.
(b) Represents a series of Collateral First Mortgage Bonds (as defined herein) which must be cancelled and released as security for Pepco’s obligations under the corresponding series of senior notes or tax-exempt bonds, at such time as Pepco does not have any first mortgage bonds outstanding (other than its Collateral First Mortgage Bonds).
(c) Represents a series of Collateral First Mortgage Bonds which must be cancelled and released as security for Pepco’s obligations under the corresponding series of senior notes or tax-exempt bonds, at such time as Pepco does not have any first mortgage bonds outstanding (other than its Collateral First Mortgage Bonds), except that Pepco may not permit such release of collateral unless Pepco substitutes comparable obligations for such collateral.
(d) Represents a series of Collateral First Mortgage Bonds securing a series of senior notes issued by Pepco, which in turn secures a series of tax-exempt bonds issued for the benefit of Pepco.
The outstanding first mortgage bonds are issued under a mortgage and deed of trust and are secured by a first lien on substantially all of Pepco’s property, plant and equipment, except for certain property excluded from the lien of the mortgage.
Maturities of Pepco’s long-term debt outstanding at December 31, 2013, are $175 million in 2014, zero in 2015 through 2018 and $1,735 million thereafter.
Pepco’s long-term debt is subject to certain covenants. As of December 31, 2013, Pepco is in compliance with all such covenants.
The table above does not separately identify $1,060 million in aggregate principal amount of senior notes issued by Pepco and $110 million in aggregate principal amount of tax-exempt bonds issued for the benefit of Pepco. These senior notes are secured by a like amount of first mortgage bonds (Collateral First Mortgage Bonds) of Pepco. In addition, these tax-exempt bonds are secured by a like amount of Collateral First Mortgage Bonds issued by Pepco. The principal terms of each such series of senior notes, or Pepco’s obligations in respect of each such series of tax-exempt bonds, are identical to the same terms of the corresponding series of Collateral First Mortgage Bonds. Payments of principal and interest made on a series of such senior notes, or the satisfaction of Pepco’s obligations in respect of a series of such tax-exempt bonds, satisfy the corresponding obligations on the related series of Collateral First Mortgage Bonds. For these reasons, each such series of Collateral First Mortgage Bonds and the corresponding senior notes and/or tax-exempt bonds together effectively represent a single financial obligation and are not identified in the table above separately.
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Bond Issuances
During 2013, Pepco issued $250 million of 4.15% first mortgage bonds due March 15, 2043 and $150 million of 4.95% first mortgage bonds due November 15, 2043. Net proceeds from the issuance of the 4.15% bonds were used to repay Pepco’s outstanding commercial paper and for general corporate purposes. The net proceeds from the 4.95% bonds were used to repay outstanding commercial paper, including commercial paper issued to repay in full at maturity $200 million of 4.95% senior notes due November 15, 2013, plus accrued but unpaid interest thereon. The senior notes were secured by a like principal amount of first mortgage bonds, which under the mortgage and deed of trust were deemed to be satisfied with the repayment of the senior notes.
Bond Redemptions
During 2013, Pepco repaid at maturity $200 million of its 4.95% senior notes, which were secured by a like principal amount of its first mortgage bonds.
Short-Term Debt
Pepco has traditionally used a number of sources to fulfill short-term funding needs, such as commercial paper, short-term notes, and bank lines of credit. Proceeds from short-term borrowings are used primarily to meet working capital needs, but may also be used to temporarily fund long-term capital requirements.
The components of Pepco’s short-term debt at December 31, 2013 and 2012 are as follows:
Commercial Paper
Pepco maintains an ongoing commercial paper program to address its short-term liquidity needs. As of December 31, 2013, the maximum capacity available under the program was $500 million, subject to available borrowing capacity under the credit facility.
Pepco had $151 million and $231 million of commercial paper outstanding at December 31, 2013 and 2012, respectively. The weighted average interest rates for commercial paper issued by Pepco during 2013 and 2012 were 0.34% and 0.43%, respectively. The weighted average maturity of all commercial paper issued by Pepco during each of 2013 and 2012 was five days.
Credit Facility
PHI, Pepco, DPL and ACE maintain an unsecured syndicated credit facility to provide for their respective liquidity needs, including obtaining letters of credit, borrowing for general corporate purposes and supporting their commercial paper programs. On August 1, 2011, PHI, Pepco, DPL and ACE entered into an amended and restated credit agreement which, on August 2, 2012, was amended to extend the term of the credit facility to August 1, 2017 and to amend the pricing schedule to decrease certain fees and interest rates payable to the lenders under the facility. On August 1, 2013, as permitted under the existing terms of the credit agreement, a request by PHI, Pepco, DPL and ACE to extend the credit facility termination date to August 1, 2018 was approved. All of the terms and conditions as well as pricing remained the same.
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The aggregate borrowing limit under the amended and restated credit facility is $1.5 billion, all or any portion of which may be used to obtain loans and up to $500 million of which may be used to obtain letters of credit. The facility also includes a swingline loan sub-facility, pursuant to which each company may make same day borrowings in an aggregate amount not to exceed 10% of the total amount of the facility. Any swingline loan must be repaid by the borrower within fourteen days of receipt. The credit sublimit is $750 million for PHI and $250 million for each of Pepco, DPL and ACE. The sublimits may be increased or decreased by the individual borrower during the term of the facility, except that (i) the sum of all of the borrower sublimits following any such increase or decrease must equal the total amount of the facility and (ii) the aggregate amount of credit used at any given time by (a) PHI may not exceed $1.25 billion and (b) each of Pepco, DPL or ACE may not exceed the lesser of $500 million and the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of the sublimit reallocations may not exceed eight per year during the term of the facility.
The interest rate payable by each company on utilized funds is, at the borrowing company’s election, (i) the greater of the prevailing prime rate, the federal funds effective rate plus 0.5% and the one month London Interbank Offered Rate plus 1.0%, or (ii) the prevailing Eurodollar rate, plus a margin that varies according to the credit rating of the borrower.
In order for a borrower to use the facility, certain representations and warranties must be true and correct, and the borrower must be in compliance with specified financial and other covenants, including (i) the requirement that each borrowing company maintain a ratio of total indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the credit agreement, which calculation excludes from the definition of total indebtedness certain trust preferred securities and deferrable interest subordinated debt (not to exceed 15% of total capitalization), (ii) with certain exceptions, a restriction on sales or other dispositions of assets, and (iii) a restriction on the incurrence of liens on the assets of a borrower or any of its significant subsidiaries other than permitted liens. The credit agreement contains certain covenants and other customary agreements and requirements that, if not complied with, could result in an event of default and the acceleration of repayment obligations of one or more of the borrowers thereunder. Each of the borrowers was in compliance with all covenants under this facility as of December 31, 2013.
The absence of a material adverse change in PHI’s business, property, results of operations or financial condition is not a condition to the availability of credit under the credit agreement. The credit agreement does not include any rating triggers.
As of December 31, 2013 and 2012, the amount of cash plus borrowing capacity under the credit facility available to meet the liquidity needs of PHI’s utility subsidiaries in the aggregate was $332 million and $477 million, respectively. Pepco’s borrowing capacity under the credit facility at any given time depends on the amount of the subsidiary borrowing capacity being utilized by DPL and ACE and the portion of the total capacity being used by PHI.
(10) INCOME TAXES
Pepco, as a direct subsidiary of PHI, is included in the consolidated federal income tax return of PHI. Federal income taxes are allocated to Pepco pursuant to a written tax sharing agreement that was approved by the Securities and Exchange Commission in connection with the establishment of PHI as a holding company. Under this tax sharing agreement, PHI’s consolidated federal income tax liability is allocated based upon PHI’s and its subsidiaries’ separate taxable income or loss.
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The provision for income taxes, reconciliation of income tax expense, and components of deferred income tax liabilities (assets) are shown below.
Provision for Income Taxes
Reconciliation of Income Tax Expense
Year ended December 31, 2013
Pepco’s effective income tax rate for the year ended December 31, 2013 of 34.5% reflects income tax benefits totaling $3 million related to uncertain and effectively settled tax positions.
On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit issued an opinion in Consolidated Edison Company of New York, Inc. & Subsidiaries v. United States (to which Pepco is not a party) that disallowed tax benefits associated with Consolidated Edison’s cross-border lease transaction. As a result of the court’s ruling in this case, PHI determined in the first quarter of 2013 that it could no longer support its current assessment with respect to the likely outcome of tax positions associated with its cross-border energy lease investments held by its wholly-owned subsidiary Potomac Capital Investment Corporation, and PHI recorded an after-tax charge of $377 million in the first quarter of 2013. Included in the $377 million charge was an after-tax interest charge of $54 million and this amount was allocated to each member of PHI’s consolidated group as if each member was a separate taxpayer, resulting in Pepco recording a $5 million (after-tax) interest benefit in the first quarter of 2013.
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Year ended December 31, 2012
Pepco’s effective income tax rate for the year ended December 31, 2012 of 27.6% primarily reflects tax benefits related to asset removal costs and changes in estimates and interest related to uncertain and effectively settled tax positions.
During 2012, Pepco recorded income tax benefits of $10 million related to uncertain and effectively settled tax positions primarily due to the effective settlement with the Internal Revenue Service (IRS) with respect to the methodology used historically to calculate deductible mixed service costs and the expiration of the statute of limitations associated with an uncertain tax position.
The effective income tax rate also reflects an increase in deductible asset removal costs for Pepco in 2012 related to a higher level of asset retirements.
Year ended December 31, 2011
Pepco’s effective income tax rate for the year ended December 31, 2011 of 26.7% includes income tax benefits totaling $9 million related to uncertain and effectively settled tax positions.
During 2011, PHI reached a settlement with the IRS with respect to interest due on its federal tax liabilities related to the November 2010 audit settlement for years 1996 through 2002. In connection with this agreement, PHI reallocated certain amounts that have been on deposit with the IRS since 2006 among liabilities in the settlement years and subsequent years. Primarily related to the settlement and reallocations, Pepco recorded a tax benefit of $5 million (after-tax) in the second quarter of 2011.
During the third quarter of 2011, Pepco recalculated interest on its uncertain tax positions for open tax years based on different assumptions related to the application of its deposit made with the IRS in 2006. This resulted in an additional tax expense of $1 million (after-tax).
During 2011, Pepco decided to adopt the safe harbor tax accounting method for certain repairs pursuant to IRS guidance. As a result, Pepco reversed $23 million of previously recorded liabilities on uncertain tax positions and reversed the associated $1 million of accrued interest.
In May 2011, Pepco received refunds of approximately $5 million and recorded tax benefits of approximately $4 million (after-tax) related to the filing of amended state tax returns. These amended returns reduced state taxable income due to an increase in tax basis on certain prior years’ asset dispositions.
Components of Deferred Income Tax Liabilities (Assets)
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The net deferred tax liability represents the tax effect, at presently enacted tax rates, of temporary differences between the financial statement basis and tax basis of assets and liabilities. The portion of the net deferred tax liability applicable to Pepco’s operations, which has not been reflected in current service rates, represents income taxes recoverable through future rates, net, and is recorded as a regulatory asset on the balance sheet. No valuation allowance for deferred tax assets was required or recorded at December 31, 2013 and 2012. Federal and state net operating losses generally expire over 20 years from 2029 to 2032.
The Tax Reform Act of 1986 repealed the investment tax credit for property placed in service after December 31, 1985, except for certain transition property. Investment tax credits previously earned on Pepco’s property continue to be amortized to income over the useful lives of the related property.
Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits
(a) These reductions of unrecognized tax benefits in 2012 primarily relate to a resolution reached with the IRS for determining deductible mixed service costs for additions to property, plant and equipment.
Unrecognized Benefits That, If Recognized, Would Affect the Effective Tax Rate
Unrecognized tax benefits are related to tax positions that have been taken or are expected to be taken in tax returns that are not recognized in the financial statements because management has either measured the tax benefit at an amount less than the benefit claimed, or expected to be claimed, or has concluded that it is not more likely than not that the tax position will be ultimately sustained. For the majority of these tax positions, the ultimate deductibility is highly certain, but there is uncertainty about the timing of such deductibility. At December 31, 2013, Pepco had less than $1 million of unrecognized tax benefits that, if recognized, would lower the effective tax rate.
Interest and Penalties
Pepco recognizes interest and penalties relating to its uncertain tax positions as an element of income tax expense. For the years ended December 31, 2013, 2012 and 2011, Pepco recognized $5 million of pre-tax interest income ($3 million after-tax), $18 million of pre-tax interest income ($11 million after-tax), and $8 million of pre-tax interest income ($5 million after-tax), respectively, as a component of income tax expense. As of December 31, 2013, 2012 and 2011, Pepco had accrued interest receivable of $9 million, accrued interest receivable of $5 million and accrued interest payable of $6 million, respectively, related to effectively settled and uncertain tax positions.
Possible Changes to Unrecognized Tax Benefits
It is reasonably possible that the amount of the unrecognized tax benefit with respect to some of Pepco’s uncertain tax positions will significantly increase or decrease within the next 12 months. PHI and its subsidiaries have entered into discussions with the IRS with the intention of seeking a settlement of all tax issues of Pepco for open tax years 2001 through 2011. PHI currently believes that it is possible that a settlement with the IRS may be reached in 2014, which could significantly impact the balances of unrecognized tax benefits and the related interest accruals of Pepco. At this time, it is estimated that there will be a $65 million to $85 million decrease in unrecognized tax benefits within the next 12 months.
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Tax Years Open to Examination
Pepco, as a direct subsidiary of PHI, is included on PHI’s consolidated Federal income tax return. Pepco’s federal income tax liabilities for all years through 2002 have been determined, subject to adjustment to the extent of any net operating loss or other loss or credit carrybacks from subsequent years. The open tax years for the significant states where Pepco files state income tax returns (District of Columbia and Maryland) are the same as for the Federal returns. As a result of the final determination of these years, Pepco filed amended state returns requesting $20 million in refunds which are subject to review by the various states. To date, Pepco has received $4 million in refunds and legislation has been enacted in the District of Columbia (subject to a 30-day Congressional review period before becoming law) which will allow for the recovery of the remaining $16 million in refunds.
Final IRS Regulations on Repair of Tangible Property
In September 2013, the IRS issued final regulations on expense versus capitalization of repairs with respect to tangible personal property. The regulations are effective for tax years beginning on or after January 1, 2014, and provide an option to early adopt the final regulations for tax years beginning on or after January 1, 2012. It is expected that the IRS will issue revenue procedures that will describe how taxpayers may implement the final regulations. The final repair regulations retain the operative rule that the Unit of Property for network assets is determined by the taxpayer’s particular facts and circumstances except as provided in published guidance. In 2012, with the filing of its 2011 tax return, PHI filed a request for an automatic change in accounting method related to repairs of its network assets in accordance with IRS Revenue Procedure 2011-43. Pepco does not expect the effects of the final regulations to be significant and will continue to evaluate the impact of the new guidance on its financial statements.
Other Taxes
Taxes other than income taxes for each year are shown below. These amounts are recoverable through rates.
(11) FAIR VALUE DISCLOSURES
Financial Instruments Measured at Fair Value on a Recurring Basis
Pepco applies FASB guidance on fair value measurement and disclosures (ASC 820) that established a framework for measuring fair value and expanded disclosures about fair value measurements. As defined in the guidance, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Pepco utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. Accordingly, Pepco utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1) and the lowest priority to unobservable inputs (level 3).
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The following tables set forth, by level within the fair value hierarchy, Pepco’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2013 and 2012. As required by the guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Pepco’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.
(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2013.
(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2012.
Pepco classifies its fair value balances in the fair value hierarchy based on the observability of the inputs used in the fair value calculation as follows:
Level 1 - Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
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Level 2 - Pricing inputs are other than quoted prices in active markets included in level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using broker quotes in liquid markets and other observable data. Level 2 also includes those financial instruments that are valued using methodologies that have been corroborated by observable market data through correlation or by other means. Significant assumptions are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.
Executive deferred compensation plan assets and liabilities categorized as level 2 consist of life insurance policies and certain employment agreement obligations. The life insurance policies are categorized as level 2 assets because they are valued based on the assets underlying the policies, which consist of short-term cash equivalents and fixed income securities that are priced using observable market data and can be liquidated for the value of the underlying assets as of December 31, 2013. The level 2 liability associated with the life insurance policies represents a deferred compensation obligation, the value of which is tracked via underlying insurance sub-accounts. The sub-accounts are designed to mirror existing mutual funds and money market funds that are observable and actively traded.
The value of certain employment agreement obligations (which are included in life insurance contracts in the tables above) is derived using a discounted cash flow valuation technique. The discounted cash flow calculations are based on a known and certain stream of payments to be made over time that are discounted to determine their net present value. The primary variable input, the discount rate, is based on market-corroborated and observable published rates. These obligations have been classified as level 2 within the fair value hierarchy because the payment streams represent contractually known and certain amounts and the discount rate is based on published, observable data.
Level 3 - Pricing inputs that are significant and generally less observable than those from objective sources. Level 3 includes those financial instruments that are valued using models or other valuation methodologies.
Executive deferred compensation plan assets include certain life insurance policies that are valued using the cash surrender value of the policies, net of loans against those policies. The cash surrender values do not represent a quoted price in an active market; therefore, those inputs are unobservable and the policies are categorized as level 3. Cash surrender values are provided by third parties and reviewed by Pepco for reasonableness.
Reconciliations of the beginning and ending balances of Pepco’s fair value measurements using significant unobservable inputs (Level 3) for the years ended December 31, 2013 and 2012 are shown below.
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The breakdown of realized and unrealized gains on level 3 instruments included in income as a component of Other operation and maintenance expense for the periods below were as follows:
Other Financial Instruments
The estimated fair values of Pepco’s Long-term debt instruments that are measured at amortized cost in Pepco’s financial statements and the associated level of the estimates within the fair value hierarchy as of December 31, 2013 and 2012 are shown in the tables below. As required by the fair value measurement guidance, debt instruments are classified in their entirety within the fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. Pepco’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, which may affect the valuation of fair value debt instruments and their placement within the fair value hierarchy levels.
The fair value of Long-term debt categorized as level 2 is based on a blend of quoted prices for the debt and quoted prices for similar debt on the measurement date. The blend places more weight on current pricing information when determining the final fair value measurement. The fair value information is provided by brokers and Pepco reviews the methodologies and results.
(a) The carrying amount for Long-term debt is $1,899 million as of December 31, 2013.
(a) Certain debt instruments that were categorized as level 1 at December 31, 2012, have been reclassified as level 2 to conform to the current period presentation.
(b) The carrying amount for Long-term debt is $1,701 million as of December 31, 2012.
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The carrying amount of all other financial instruments in the accompanying financial statements approximate fair value.
(12) COMMITMENTS AND CONTINGENCIES
General Litigation
From time to time, Pepco is named as a defendant in litigation, usually relating to general liability or auto liability claims that resulted in personal injury or property damage to third parties. Pepco is self-insured against such claims up to a certain self-insured retention amount and maintains insurance coverage against such claims at higher levels, to the extent deemed prudent by management. In addition, Pepco’s contracts with its vendors generally require the vendors to name Pepco as an additional insured for the amount at least equal to Pepco’s self-insured retention. Further, Pepco’s contracts with its vendors require the vendors to indemnify Pepco for various acts and activities that may give rise to claims against Pepco. Loss contingency liabilities for both asserted and unasserted claims are recognized if it is probable that a loss will result from such a claim and if the amounts of the losses can be reasonably estimated. Although the outcome of the claims and proceedings cannot be predicted with any certainty, management believes that there are no existing claims or proceedings that are likely to have a material adverse effect on Pepco’s financial condition, results of operations or cash flows. At December 31, 2013, Pepco had loss contingency liabilities for general litigation totaling approximately $19 million (including amounts related to the matter specifically described below) and the portion of these loss contingency liabilities in excess of the self-insured retention amount was substantially offset by insurance receivables.
Substation Injury Claim
In May 2013, a contract worker erecting a scaffold at a Pepco substation came into contact with an energized station service feeder and suffered serious injuries. In August 2013, the individual filed suit against Pepco in the Circuit Court for Montgomery County, Maryland, seeking damages for medical expenses, loss of future earning capacity, pain and suffering and the cost of a life care plan aggregating to a maximum claim of approximately $28.1 million. Discovery is ongoing in the case and, if a settlement cannot be reached with respect to this matter, a trial is expected to begin in October 2014. Pepco has notified its insurers of the incident and believes that the insurance policies in force at the time of the incident, including the policies of the contractor performing the scaffold work (which name Pepco as an additional insured), will offset substantially all of Pepco’s costs associated with the resolution of this matter, including Pepco’s self-insured retention amount. At December 31, 2013, Pepco has concluded that a loss is probable with respect to this matter and has recorded an estimated loss contingency liability, which is included in the liability for general litigation referred to above as of December 31, 2013. Pepco has also concluded as of December 31, 2013 that realization of its insurance claims associated with this matter is probable and, accordingly, has recorded an estimated insurance receivable offsetting substantially all of the related loss contingency liability.
Environmental Matters
Pepco is subject to regulation by various federal, regional, state and local authorities with respect to the environmental effects of its operations, including air and water quality control, solid and hazardous waste disposal and limitations on land use. Although penalties assessed for violations of environmental laws and regulations are not recoverable from customers of Pepco, environmental clean-up costs incurred by Pepco generally are included in its cost of service for ratemaking purposes. The total accrued liabilities for the environmental contingencies of Pepco described below at December 31, 2013 are summarized as follows:
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Peck Iron and Metal Site
The U.S. Environmental Protection Agency (EPA) informed Pepco in a May 2009 letter that Pepco may be a potentially responsible party (PRP) under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA) with respect to the cleanup of the Peck Iron and Metal site in Portsmouth, Virginia, and for costs EPA has incurred in cleaning up the site. The EPA letter states that Peck Iron and Metal purchased, processed, stored and shipped metal scrap from military bases, governmental agencies and businesses and that Peck’s metal scrap operations resulted in the improper storage and disposal of hazardous substances. EPA bases its allegation that Pepco arranged for disposal or treatment of hazardous substances sent to the site on information provided by former Peck Iron and Metal personnel, who informed EPA that Pepco was a customer at the site. Pepco has advised EPA by letter that its records show no evidence of any sale of scrap metal by Pepco to the site. Even if EPA has such records and such sales did occur, Pepco believes that any such scrap metal sales may be entitled to the recyclable material exemption from CERCLA liability. In a Federal Register notice published in November 2009, EPA placed the Peck Iron and Metal site on the National Priorities List. The National Priorities List, among other things, serves as a guide to EPA in determining which sites warrant further investigation to assess the nature and extent of the human health and environmental risks associated with a site. In September 2011, EPA initiated a remedial investigation/feasibility study (RI/FS) using federal funds. Pepco cannot at this time estimate an amount or range of reasonably possible loss associated with this RI/FS, any remediation activities to be performed at the site or any other costs that EPA might seek to impose on Pepco.
Ward Transformer Site
In April 2009, a group of PRPs with respect to the Ward Transformer site in Raleigh, North Carolina, filed a complaint in the U.S. District Court for the Eastern District of North Carolina, alleging cost recovery and/or contribution claims against a number of entities, including Pepco, based on its alleged sale of transformers to Ward Transformer, with respect to past and future response costs incurred by the PRP group in performing a removal action at the site. In a March 2010 order, the court denied the defendants’ motion to dismiss. The litigation is moving forward with certain “test case” defendants (not including Pepco) filing summary judgment motions regarding liability. The case has been stayed as to the remaining defendants pending rulings upon the test cases. In a January 31, 2013 order, the Federal district court granted summary judgment for the test case defendant whom plaintiffs alleged was liable based on its sale of transformers to Ward Transformer. The Federal district court’s order, which plaintiffs have appealed to the U.S. Court of Appeals for the Fourth Circuit, addresses only the liability of the test case defendant. Pepco has concluded that a loss is reasonably possible with respect to this matter, but is unable to estimate an amount or range of reasonably possible losses to which it may be exposed. Pepco does not believe that it had extensive business transactions, if any, with the Ward Transformer site.
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Benning Road Site
In September 2010, PHI received a letter from EPA identifying the Benning Road location, consisting of a generation facility operated by Pepco Energy Services until the facility was deactivated in June 2012, and a transmission and distribution facility operated by Pepco, as one of six land-based sites potentially contributing to contamination of the lower Anacostia River. The letter stated that the principal contaminants of concern are polychlorinated biphenyls and polycyclic aromatic hydrocarbons. In December 2011, the U.S. District Court for the District of Columbia approved a consent decree entered into by Pepco and Pepco Energy Services with the District of Columbia Department of the Environment (DDOE), which requires Pepco and Pepco Energy Services to conduct a RI/FS for the Benning Road site and an approximately 10 to 15 acre portion of the adjacent Anacostia River. The RI/FS will form the basis for DDOE’s selection of a remedial action for the Benning Road site and for the Anacostia River sediment associated with the site. The consent decree does not obligate Pepco or Pepco Energy Services to pay for or perform any remediation work, but it is anticipated that DDOE will look to the companies to assume responsibility for cleanup of any conditions in the river that are determined to be attributable to past activities at the Benning Road site.
In December 2012, DDOE approved the RI/FS work plan. RI/FS field work commenced in January 2013 and is still in progress. In October 2013, Pepco and Pepco Energy Services submitted a work plan addendum for approval by DDOE identifying the location of groundwater monitoring wells to be installed at the site and sampled as the last phase of the field work. The work plan addendum has been revised in response to comments from DDOE, and it is expected that the addendum will be approved and the next phase of field work will commence before the end of the first quarter of 2014. Once all of the field work has been completed, Pepco and Pepco Energy Services will prepare RI/FS reports for review and approval by DDOE after solicitation and consideration of public comment. The next status report to the court is due on May 24, 2014.
The remediation costs accrued for this matter are included in the table above in the columns entitled “Transmission and Distribution” and “Legacy Generation - Regulated.”
Potomac River Mineral Oil Release
In January 2011, a coupling failure on a transformer cooler pipe resulted in a release of non-toxic mineral oil at Pepco’s Potomac River substation in Alexandria, Virginia. An overflow of an underground secondary containment reservoir resulted in approximately 4,500 gallons of mineral oil flowing into the Potomac River.
Beginning in March 2011, DDOE issued a series of compliance directives requiring Pepco to prepare an incident report, provide certain records, and prepare and implement plans for sampling surface water and river sediments and assessing ecological risks and natural resources damages. Pepco completed field sampling during the fourth quarter of 2011 and submitted sampling results to DDOE during the second quarter of 2012. Pepco is continuing discussions with DDOE regarding the need for any further response actions but expects that additional monitoring of shoreline sediments may be required.
In June 2012, Pepco commenced discussions with DDOE regarding a possible consent decree that would resolve DDOE’s threatened enforcement action, including civil penalties, for alleged violation of the District’s Water Pollution Control Law, as well as for damages to natural resources. Pepco and DDOE have reached an agreement in principle that would consist of a combination of a civil penalty and Supplemental Environmental Projects (SEPs) with a total cost to Pepco of approximately $1 million. DDOE has endorsed Pepco’s proposed SEP involving the installation and operation of a trash collection system at a stormwater outfall that drains to the Anacostia River. DDOE and Pepco are completing negotiations on the text of a consent decree to document the settlement of DDOE’s enforcement action and a written statement of work describing the details of the trash collection system SEP. It is expected that the consent decree will be filed with the District of Columbia Superior Court by the end of the first quarter of 2014, with a request that the court approve the consent decree following a period of at least
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days for public comment. Discussions will proceed separately with DDOE and the federal resource trustees regarding the settlement of a natural resource damage (NRD) claim under federal law. Based on discussions to date, Pepco does not believe that the resolution of DDOE’s enforcement action or the federal NRD claim will have a material adverse effect on its financial condition, results of operations or cash flows.
As a result of the mineral oil release, Pepco implemented certain interim operational changes to the secondary containment systems at the facility which involve pumping accumulated storm water to an aboveground holding tank for off-site disposal. In December 2011, Pepco completed the installation of a treatment system designed to allow automatic discharge of accumulated storm water from the secondary containment system. Pepco currently is seeking DDOE’s and EPA’s approval to commence operation of the new system on a pilot basis to demonstrate its effectiveness in meeting both secondary containment requirements and water quality standards related to the discharge of storm water from the facility. In the meantime, Pepco is continuing to use the aboveground holding tank to manage storm water from the secondary containment system. Pepco also is evaluating other technical and regulatory options for managing storm water from the secondary containment system as alternatives to the proposed treatment system discharge currently under discussion with EPA and DDOE.
The amount accrued for this matter is included in the table above in the column entitled “Transmission and Distribution.”
Metal Bank Site
In the first quarter of 2013, the National Oceanic and Atmospheric Administration (NOAA) contacted Pepco on behalf of itself and other federal and state trustees to request that Pepco execute a tolling agreement to facilitate settlement negotiations concerning natural resource damages allegedly caused by releases of hazardous substances, including polychlorinated biphenyls, at the Metal Bank Superfund Site located in Philadelphia, Pennsylvania. Pepco has executed the tolling agreement and will participate in settlement discussions with the NOAA, the trustees and other PRPs.
The amount accrued for this matter is included in the table above in the column entitled “Transmission and Distribution.”
Brandywine Fly Ash Disposal Site
In February 2013, Pepco received a letter from the Maryland Department of the Environment (MDE) requesting that Pepco investigate the extent of waste on a Pepco right-of-way that traverses the Brandywine fly ash disposal site in Brandywine, Prince George’s County, Maryland, owned by GenOn MD Ash Management, LLC (GenOn). In July 2013, while reserving its rights and related defenses under a 2000 asset purchase and sale agreement covering the sale of this site, Pepco indicated its willingness to investigate the extent of, and propose an appropriate closure plan to address, ash on the right-of-way. Pepco submitted a schedule for development of a closure plan to MDE on September 30, 2013 and, by letter dated October 18, 2013, MDE approved the schedule.
Pepco has determined that a loss associated with this matter for Pepco is probable and has estimated that the costs for implementation of a closure plan and cap on the site are in the range of approximately $3 million to $6 million. Pepco believes that the costs incurred in this matter will be recoverable from GenOn under the 2000 sale agreement.
The amount accrued for this matter is included in the table above in the column entitled “Transmission and Distribution.”
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Watts Branch Insulating Fluid Release
On September 13, 2013, a Washington Metropolitan Area Transit Authority contractor damaged a Pepco underground transmission feeder while drilling a grout column for a subway tunnel under a city street. The damage caused the release of approximately 11,250 gallons of insulating fluid, a small amount of which reached the Watts Branch, a tributary of the Anacostia River. The U.S. Coast Guard (USCG) issued a notice of federal interest for an oil pollution incident, informing Pepco of its responsibility under the Oil Pollution Act of 1990 for removal costs and damages from the release. In addition, on September 25, 2013, DDOE issued a compliance directive that required Pepco to prepare an incident investigation report describing the events leading up to the release. The compliance directive also required Pepco to prepare work plans for sampling the insulating fluid and for developing and implementing a biological assessment and physical habitat quality assessment to be conducted in Watts Branch. Pepco prepared the incident investigation report and work plans and submitted them to DDOE and USCG. In December 2013, Pepco received and responded to an EPA information request regarding this incident.
Pepco believes that a loss in this matter is probable; however, the costs to resolve this matter are expected to be less than $1 million and are being expensed as incurred. Pepco further believes that the costs incurred will be recoverable from the party or parties responsible for the release. On December 4, 2013, the USCG delivered a Notice of Violation with respect to this matter, which imposed a $3,000 penalty on Pepco, which Pepco has paid.
District of Columbia Tax Legislation
In 2011, the Council of the District of Columbia approved the Fiscal Year 2012 Budget Support Act of 2011, which requires that corporate taxpayers in the District of Columbia calculate taxable income allocable or apportioned to the District of Columbia by reference to the income and apportionment factors applicable to commonly controlled entities organized within the United States that are engaged in a unitary business. In the aggregate, this new tax reporting method reduced pre-tax earnings for the year ended December 31, 2011 by less than $1 million. During 2012, the District of Columbia Office of Tax and Revenue adopted regulations to implement this reporting method. PHI has analyzed these regulations and determined that the regulations did not impact PHI’s results of operations for the years ended December 31, 2013 and 2012.
Contractual Obligations
Power Purchase Contracts
As of December 31, 2013, Pepco had no contractual obligations under non-derivative power purchase contracts.
Lease Commitments
Rental expense for operating leases was $7 million, $6 million and $4 million for the years ended December 31, 2013, 2012 and 2011, respectively.
Total future minimum operating lease payments for Pepco as of December 31, 2013 are $6 million in 2014, $6 million in 2015, $6 million in 2016, $5 million in 2017, $4 million in 2018 and $21 million thereafter.
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(13) RELATED PARTY TRANSACTIONS
PHI Service Company provides various administrative and professional services to PHI and its regulated and unregulated subsidiaries, including Pepco. The cost of these services is allocated in accordance with cost allocation methodologies set forth in the service agreement using a variety of factors, including the subsidiaries’ share of employees, operating expenses, assets and other cost methods. These intercompany transactions are eliminated by PHI in consolidation and no profit results from these transactions at PHI. PHI Service Company costs directly charged or allocated to Pepco for the years ended December 31, 2013, 2012 and 2011 were approximately $209 million, $211 million and $185 million, respectively.
Pepco Energy Services performs utility maintenance services and high voltage underground transmission cabling, including services that are treated as capital costs, for Pepco. Amounts charged to Pepco by Pepco Energy Services for the years ended December 31, 2013, 2012 and 2011 were approximately $20 million, $16 million and $20 million, respectively.
As of December 31, 2013 and 2012, Pepco had the following balances on its balance sheets due to related parties:
(a) Included in Accounts payable due to associated companies.
(b) Pepco bills customers on behalf of Pepco Energy Services where Pepco Energy Services has performed work for certain government agencies under a General Services Administration area-wide agreement. Amount also includes charges for utility work performed by Pepco Energy Services on behalf of Pepco. Prior to the wind-down of Pepco Energy Services’ retail electric and natural gas businesses, Pepco billed customers on behalf of Pepco Energy Services where customers had selected Pepco Energy Services as their alternative energy supplier.
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(14) QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
The quarterly data presented below reflect all adjustments necessary, in the opinion of management, for a fair presentation of the interim results. Quarterly data normally vary seasonally because of temperature variations and differences between summer and winter rates. Therefore, comparisons by quarter within a year are not meaningful.
(a) Includes tax benefits of $5 million (after-tax) allocated to Pepco associated with interest on uncertain and effectively settled tax positions resulting from a change in assessment of tax benefits associated with the cross-border energy leases of a PHI affiliate.
(a) Includes tax benefits of $10 million (after-tax), primarily related to the settlement of an uncertain tax position with the IRS related to the methodology used historically to calculate deductible mixed service costs and the expiration of the statute of limitations associated with an uncertain tax position.
DPL
Management’s Report on Internal Control over Financial Reporting
The management of Delmarva Power & Light Company (DPL) is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management of DPL assessed DPL’s internal control over financial reporting as of December 31, 2013 based on the framework in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its assessment, the management of DPL concluded that DPL’s internal control over financial reporting was effective as of December 31, 2013.
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Report of Independent Registered Public Accounting Firm
To the Shareholder and Board of Directors of
Delmarva Power & Light Company
In our opinion, the financial statements of Delmarva Power & Light Company (a wholly owned subsidiary of Pepco Holdings, Inc.) listed in the accompanying index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Delmarva Power & Light Company at December 31, 2013 and December 31, 2012, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2013 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule of Delmarva Power & Light Company listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
Washington, D.C.
February 27, 2014
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DELMARVA POWER & LIGHT COMPANY
STATEMENTS OF INCOME
The accompanying Notes are an integral part of these Financial Statements.
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DELMARVA POWER & LIGHT COMPANY
BALANCE SHEETS
The accompanying Notes are an integral part of these Financial Statements.
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DELMARVA POWER & LIGHT COMPANY
BALANCE SHEETS
The accompanying Notes are an integral part of these Financial Statements.
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DELMARVA POWER & LIGHT COMPANY
STATEMENTS OF CASH FLOWS
The accompanying Notes are an integral part of these Financial Statements.
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DELMARVA POWER & LIGHT COMPANY
STATEMENTS OF EQUITY
The accompanying Notes are an integral part of these Financial Statements.
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NOTES TO FINANCIAL STATEMENTS
DELMARVA POWER & LIGHT COMPANY
(1) ORGANIZATION
Delmarva Power & Light Company (DPL) is engaged in the transmission and distribution of electricity in Delaware and portions of Maryland and provides natural gas distribution service in northern Delaware. Additionally, DPL provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its service territories who do not elect to purchase electricity from a competitive supplier. Default Electricity Supply is known as Standard Offer Service in both Delaware and Maryland. DPL is a wholly owned subsidiary of Conectiv, LLC (Conectiv), which is wholly owned by Pepco Holdings, Inc. (Pepco Holdings or PHI).
(2) SIGNIFICANT ACCOUNTING POLICIES
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) requires management to make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities in the financial statements and accompanying notes. Although DPL believes that its estimates and assumptions are reasonable, they are based upon information available to management at the time the estimates are made. Actual results may differ significantly from these estimates.
Significant matters that involve the use of estimates include the assessment of contingencies, the calculation of future cash flows and fair value amounts for use in asset and goodwill impairment evaluations, fair value calculations for derivative instruments, pension and other postretirement benefits assumptions, the assessment of the probability of recovery of regulatory assets, accrual of storm restoration costs, accrual of unbilled revenue, recognition of changes in network service transmission rates for prior service year costs, accrual of loss contingency liabilities for general and auto liability claims, and income tax provisions and reserves. Additionally, DPL is subject to legal, regulatory, and other proceedings and claims that arise in the ordinary course of its business. DPL records an estimated liability for these proceedings and claims when it is probable that a loss has been incurred and the loss is reasonably estimable.
Revenue Recognition
DPL recognizes revenues upon distribution of electricity and natural gas to its customers, including unbilled revenue for services rendered, but not yet billed. DPL’s unbilled revenue was $61 million and $62 million as of December 31, 2013 and 2012, respectively, and these amounts are included in Accounts receivable. DPL calculates unbilled revenue using an output-based methodology. This methodology is based on the supply of electricity or natural gas intended for distribution to customers. The unbilled revenue process requires management to make assumptions and judgments about input factors such as customer sales mix, temperature, and estimated line losses (estimates of electricity and natural gas expected to be lost in the process of its transmission and distribution to customers). The assumptions and judgments are inherently uncertain and susceptible to change from period to period, and if the actual results differ from the projected results, the impact could be material. Revenues from non-regulated electricity and natural gas sales are included in Electric revenues and Natural gas revenues, respectively.
Taxes related to the consumption of electricity and natural gas by its customers, such as fuel, energy, or other similar taxes, are components of DPL’s tariffs and, as such, are billed to customers and recorded in Operating revenue. Accruals for the remittance of these taxes by DPL are recorded in Other taxes.
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Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions
Taxes included in DPL’s gross revenues were $17 million, $15 million and $18 million for the years ended December 31, 2013, 2012 and 2011, respectively.
Accounting for Derivatives
DPL uses derivative instruments primarily to reduce natural gas commodity price volatility and to limit its customers’ exposure to natural gas price fluctuations under a hedging program approved by the Delaware Public Service Commission (DPSC). Derivatives are recorded in the balance sheets as Derivative assets or Derivative liabilities and measured at fair value. DPL enters physical natural gas contracts as part of the hedging program that qualify as normal purchases or normal sales, which are not required to be recorded in the financial statements until settled. DPL’s capacity contracts are not classified as derivatives. Changes in the fair value of derivatives that are not designated as cash flow hedges are reflected in income.
All premiums paid and other transaction costs incurred as part of DPL’s natural gas hedging activity, in addition to all gains and losses related to hedging activities, are fully recoverable through the fuel adjustment clause approved by the DPSC, and are deferred under Financial Accounting Standards Board (FASB) guidance on regulated operations (Accounting Standards Codification (ASC) 980) until recovered.
Long-Lived Asset Impairment Evaluation
DPL evaluates certain long-lived assets to be held and used (for example, equipment and real estate) for impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. Examples of such events or changes include a significant decrease in the market price of a long-lived asset or a significant adverse change in the manner in which an asset is being used or its physical condition. A long-lived asset to be held and used is written down to its estimated fair value if the expected future undiscounted cash flow from the asset is less than its carrying value.
For long-lived assets that can be classified as assets to be disposed of by sale, an impairment loss is recognized to the extent that the assets’ carrying value exceeds its estimated fair value including costs to sell.
Income Taxes
DPL, as an indirect subsidiary of Pepco Holdings, is included in the consolidated federal income tax return of PHI. Federal income taxes are allocated to DPL based upon the taxable income or loss amounts, determined on a separate return basis.
The financial statements include current and deferred income taxes. Current income taxes represent the amount of tax expected to be reported on DPL’s state income tax returns and the amount of federal income tax allocated from Pepco Holdings.
Deferred income tax assets and liabilities represent the tax effects of temporary differences between the financial statement basis and tax basis of existing assets and liabilities, and they are measured using presently enacted tax rates. The portion of DPL’s deferred tax liability applicable to its utility operations that has not been recovered from utility customers represents income taxes recoverable in the future and is included in Regulatory assets on the balance sheets. See Note (7), “Regulatory Matters,” for additional information.
Deferred income tax expense generally represents the net change during the reporting period in the net deferred tax liability and deferred recoverable income taxes.
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DPL recognizes interest on underpayments and overpayments of income taxes, interest on uncertain tax positions, and tax-related penalties in income tax expense.
Investment tax credits are being amortized to income over the useful lives of the related property.
Consolidation of Variable Interest Entities
DPL assesses its contractual arrangements with variable interest entities to determine whether it is the primary beneficiary and thereby has to consolidate the entities in accordance with ASC 810. The guidance addresses conditions under which an entity should be consolidated based upon variable interests rather than voting interests. See Note (17), “Variable Interest Entities, “ for additional information.
Cash and Cash Equivalents
Cash and cash equivalents include cash on hand, cash invested in money market funds and commercial paper held with original maturities of three months or less. Additionally, deposits in PHI’s money pool, which DPL and certain other PHI subsidiaries use to manage short-term cash management requirements, are considered cash equivalents. Deposits in the money pool are guaranteed by PHI. PHI deposits funds in the money pool to the extent that the pool has insufficient funds to meet the needs of its participants, which may require PHI to borrow funds for deposit from external sources.
Accounts Receivable and Allowance for Uncollectible Accounts
DPL’s Accounts receivable balance primarily consists of customer accounts receivable arising from the sale of goods and services to customers within its service territory, other accounts receivable, and accrued unbilled revenue. Accrued unbilled revenue represents revenue earned in the current period but not billed to the customer until a future date (usually within one month after the receivable is recorded).
DPL maintains an allowance for uncollectible accounts and changes in the allowance are recorded as an adjustment to Other operation and maintenance expense in the statements of income. DPL determines the amount of the allowance based on specific identification of material amounts at risk by customer and maintains a reserve based on its historical collection experience. The adequacy of this allowance is assessed on a quarterly basis by evaluating all known factors such as the aging of the receivables, historical collection experience, the economic and competitive environment and changes in the creditworthiness of its customers. Accounts receivable are written off in the period in which the receivable is deemed uncollectible and collection efforts have been exhausted. Recoveries of Accounts receivable previously written off are recorded when it is probable they will be recovered. Although DPL believes its allowance is adequate, it cannot anticipate with any certainty the changes in the financial condition of its customers. As a result, DPL records adjustments to the allowance for uncollectible accounts in the period in which the new information that requires an adjustment to the reserve becomes known.
Inventories
Included in Inventories are transmission and distribution materials and supplies and natural gas. DPL utilizes the weighted average cost method of accounting for inventory items. Under this method, an average price is determined for the quantity of units acquired at each price level and is applied to the ending quantity to calculate the total ending inventory balance. Materials and supplies are recorded in Inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed.
The cost of natural gas, including transportation costs, is included in Inventory when purchased and charged to Gas purchased expense when used.
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Goodwill
Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired at the acquisition date. DPL tests its goodwill for impairment annually as of November 1 and whenever an event occurs or circumstances change in the interim that would more likely than not (that is, a greater than 50% chance) reduce the estimated fair value of DPL below the carrying amount of its net assets. Factors that may result in an interim impairment test include, but are not limited to: a change in the identified reporting unit; an adverse change in business conditions; an adverse regulatory action; or an impairment of DPL’s long-lived assets. DPL performed its most recent annual impairment test as of November 1, 2013, and its goodwill was not impaired as described in Note (6), “Goodwill.”
Regulatory Assets and Regulatory Liabilities
Certain aspects of DPL’s business are subject to regulation by the DPSC and the Maryland Public Service Commission (MPSC). The transmission of electricity by DPL is regulated by the Federal Energy Regulatory Commission (FERC). DPL’s interstate transportation and wholesale sale of natural gas are regulated by FERC.
Based on the regulatory framework in which it has operated, DPL has historically applied, and in connection with its transmission and distribution business continues to apply, FASB guidance on regulated operations (ASC 980). The guidance allows regulated entities, in appropriate circumstances, to defer the income statement impact of certain costs that are expected to be recovered in future rates through the establishment of regulatory assets and defer certain revenues that are expected to be refunded to customers through the establishment of regulatory liabilities. Management’s assessment of the probability of recovery of regulatory assets requires judgment and interpretation of laws, regulatory commission orders and other factors. If management subsequently determines, based on changes in facts or circumstances, that a regulatory asset is not probable of recovery, the regulatory asset would be eliminated through a charge to earnings.
Effective June 2007, the MPSC approved a bill stabilization adjustment (BSA) mechanism for retail customers. For customers to whom the BSA applies, DPL recognizes distribution revenue based on an approved distribution charge per customer. From a revenue recognition standpoint, the BSA has the effect of decoupling the distribution revenue recognized in a reporting period from the amount of power delivered during that period. Pursuant to this mechanism, DPL recognizes either (i) a positive adjustment equal to the amount by which revenue from Maryland retail distribution sales falls short of the revenue that DPL is entitled to earn based on the approved distribution charge per customer, or (ii) a negative adjustment equal to the amount by which revenue from such distribution sales exceeds the revenue that DPL is entitled to earn based on the approved distribution charge per customer (a Revenue Decoupling Adjustment). A net positive Revenue Decoupling Adjustment is recorded as a regulatory asset and a net negative Revenue Decoupling Adjustment is recorded as a regulatory liability.
Property, Plant and Equipment
Property, plant and equipment is recorded at original cost, including labor, materials, asset retirement costs and other direct and indirect costs including capitalized interest. The carrying value of Property, plant and equipment is evaluated for impairment whenever circumstances indicate the carrying value of those assets may not be recoverable. Upon retirement, the cost of regulated property, net of salvage, is charged to Accumulated depreciation. For additional information regarding the treatment of asset retirement obligations, see the “Asset Removal Costs” section included in this Note.
The annual provision for depreciation on electric and natural gas property, plant and equipment is computed on a straight-line basis using composite rates by classes of depreciable property. Accumulated depreciation is charged with the cost of depreciable property retired, less salvage and other recoveries. Non-operating and other property is generally depreciated on a straight-line basis over the useful lives of the assets. The system-wide composite annual depreciation rates for the years ended December 31, 2013, 2012 and 2011 for DPL’s property were approximately 2.6%, 2.7% and 2.8%, respectively.
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Capitalized Interest and Allowance for Funds Used During Construction
In accordance with FASB guidance on regulated operations (ASC 980), utilities can capitalize the capital costs of financing the construction of plant and equipment as Allowance for Funds Used During Construction (AFUDC). This results in the debt portion of AFUDC being recorded as a reduction of Interest expense and the equity portion of AFUDC being recorded as an increase to Other income in the accompanying statements of income.
DPL recorded AFUDC for borrowed funds of $2 million, $2 million and $1 million for the years ended December 31, 2013, 2012 and 2011, respectively.
DPL recorded amounts for the equity component of AFUDC of $2 million, $3 million and $3 million for the years ended December 31, 2013, 2012 and 2011, respectively.
Leasing Activities
DPL’s lease transactions include plant, office space, equipment, software and vehicles. In accordance with FASB guidance on leases (ASC 840), these leases are classified as operating leases.
An operating lease in which DPL is the lessee generally results in a level income statement charge over the term of the lease, reflecting the rental payments required by the lease agreement. If rental payments are not made on a straight-line basis, DPL’s policy is to recognize rent expense on a straight-line basis over the lease term unless another systematic and rational allocation basis is more representative of the time pattern in which the leased property is physically employed.
Amortization of Debt Issuance and Reacquisition Costs
DPL defers and amortizes debt issuance costs and long-term debt premiums and discounts over the lives of the respective debt issuances. When refinancing or redeeming existing debt, any unamortized premiums, discounts and debt issuance costs, as well as debt redemption costs, are classified as Regulatory assets and are amortized generally over the life of the original issue.
Asset Removal Costs
In accordance with FASB guidance, asset removal costs are recorded as regulatory liabilities. At December 31, 2013 and 2012, $173 million and $202 million, respectively, of asset removal costs are included in Regulatory liabilities in the accompanying balance sheets.
Pension and Postretirement Benefit Plans
Pepco Holdings sponsors the PHI Retirement Plan, a non-contributory, defined benefit pension plan that covers substantially all employees of DPL and certain employees of other Pepco Holdings subsidiaries. Pepco Holdings also provides supplemental retirement benefits to certain eligible executives and key employees through nonqualified retirement plans and provides certain postretirement health care and life insurance benefits for eligible retired employees.
The PHI Retirement Plan is accounted for in accordance with FASB guidance on retirement benefits (ASC 715).
Dividend Restrictions
All of DPL’s shares of outstanding common stock are held by Conectiv, its parent company. In addition to its future financial performance, the ability of DPL to pay dividends to its parent company is subject to limits imposed by: (i) state corporate laws, which impose limitations on the funds that can be used to pay dividends, and (ii) the prior rights of holders of existing and future preferred stock, mortgage bonds and
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other long-term debt issued by DPL and any other restrictions imposed in connection with the incurrence of liabilities. DPL has no shares of preferred stock outstanding. DPL had approximately $637 million and $578 million of retained earnings available for payment of common stock dividends at December 31, 2013 and 2012, respectively. These amounts represent the total retained earnings balances at those dates.
Reclassifications and Adjustments
Certain prior period amounts have been reclassified in order to conform to the current period presentation. The following adjustments have been recorded and are not considered material individually or in the aggregate to either the current period or prior period financial results:
Natural Gas Operating Revenue Adjustment
During 2012, DPL recorded an adjustment to correct an overstatement of unbilled revenue in its natural gas distribution business related to prior periods. The adjustment resulted in a decrease in Operating revenue of $1 million for the year ended December 31, 2012.
Default Electricity Supply Revenue and Costs Adjustments
During 2011, DPL recorded adjustments to correct certain errors associated with the accounting for Default Electricity Supply revenue and costs. These adjustments primarily arose from the under-recognition of allowed returns on the cost of working capital and resulted in a pre-tax decrease in Other operation and maintenance expense of $11 million for the year ended December 31, 2011.
(3) NEWLY ADOPTED ACCOUNTING STANDARDS
Balance Sheet (ASC 210)
In December 2011, the FASB issued new disclosure requirements for financial assets and financial liabilities, such as derivatives, that are subject to contractual netting arrangements. The new disclosure requirements include information about the gross exposure of the instruments and the net exposure of the instruments under contractual netting arrangements, how the exposures are presented in the financial statements, and the terms and conditions of the contractual netting arrangements. DPL adopted the new guidance during the first quarter of 2013 and concluded it did not have a material impact on its financial statements.
(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED
Joint and Several Liability Arrangements (ASC 405)
In February 2013, the FASB issued new recognition and disclosure requirements for certain joint and several liability arrangements where the total amount of the obligation is fixed at the reporting date. For arrangements within the scope of this standard, DPL will be required to include in its liabilities the additional amounts it expects to pay on behalf of its co-obligors, if any. DPL will also be required to provide additional disclosures including the nature of the arrangements with its co-obligors, the total amounts outstanding under the arrangements between DPL and its co-obligors, the carrying value of the liability, and the nature and limitations of any recourse provisions that would enable recovery from other entities.
The new requirements are effective retroactively beginning on January 1, 2014, with implementation required for prior periods if joint and several liability arrangement obligations exist as of January 1, 2014. DPL does not expect this new guidance to have a material impact on its financial statements.
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Income Taxes (ASC 740)
In July 2013, the FASB issued new guidance that will require the netting of certain unrecognized tax benefits against a deferred tax asset for a loss or other similar tax carryforward that would apply upon settlement of the uncertain tax position. The new requirements are effective prospectively beginning with DPL’s March 31, 2014 financial statements for all unrecognized tax benefits existing at the adoption date. Retrospective implementation and early adoption of the guidance are permitted. DPL does not expect this new guidance to have a material impact on its financial statements.
(5) SEGMENT INFORMATION
The company operates its business as one regulated utility segment, which includes all of its services as described above.
(6) GOODWILL
All of DPL’s goodwill was generated by its acquisition of Conowingo Power Company in 1995. In order to estimate the fair value of the DPL reporting unit, DPL uses two valuation techniques: an income approach and a market approach. The income approach estimates fair value based on a discounted future cash flow analysis and a terminal value that is consistent with DPL’s long-term view of the business. This approach uses a discount rate based on the estimated weighted average cost of capital (WACC) for the reporting unit. DPL determines the estimated WACC by considering appropriate market-based information for the cost of equity and cost of debt as of the measurement date . The market approach estimates fair value based on a multiple of earnings before interest, taxes, depreciation, and amortization (EBITDA) that management believes is consistent with EBITDA multiples for comparable utilities. DPL has consistently used this valuation technique to estimate the fair value of the DPL reporting unit.
The estimation of fair value is dependent on a number of factors including but not limited to interest rates, growth assumptions, returns on rate base, operating and capital expenditure requirements, and other factors, changes in which could materially affect the results of impairment testing. Assumptions used were consistent with historical experience, including assumptions concerning the recovery of operating costs and capital expenditures and current market-based information. Sensitive, interrelated and uncertain variables that could decrease the estimated fair value of the DPL reporting unit include utility sector market performance, sustained adverse business conditions, changes in forecasted revenues, higher operating and maintenance capital expenditure requirements, a significant increase in the weighted average cost of capital and other factors.
As of December 31, 2013 and 2012, DPL’s goodwill balance was $8 million. There are no accumulated impairment losses.
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(7) REGULATORY MATTERS
Regulatory Assets and Regulatory Liabilities
The components of DPL’s regulatory asset and liability balances at December 31, 2013 and 2012 are as follows:
(a) A return is earned on these deferrals.
(b) A return is generally earned in Delaware on this deferral.
A description for each category of regulatory assets and regulatory liabilities follows:
Smart Grid Costs: Represents advanced metering infrastructure (AMI) costs associated with the installation of smart meters and the early retirement of existing meters throughout DPL’s service territory that are recoverable from customers.
Recoverable Income Taxes: Represents amounts recoverable from DPL’s customers for tax benefits applicable to utility operations that were previously recognized in income tax expense before the company was ordered to account for the tax benefits as deferred income taxes. As the temporary differences between the financial statement basis and tax basis of assets reverse, the deferred recoverable balances are reversed.
MAPP Abandonment Costs: Represents the probable recovery of abandoned costs prudently incurred in connection with the Mid-Atlantic Power Pathway (MAPP) project which was terminated on August 24, 2012. The regulatory asset includes the costs of land, land rights, supplies and materials, engineering and design, environmental services, and project management and administration. The regulatory asset will be reduced as the result of sale or alternative use of these assets. As of December 31, 2013, these assets were earning a return of 12.8%. For additional information, see “MAPP Project” discussion below.
Demand-Side Management Costs: Represents recoverable costs associated with customer energy efficiency and conservation programs in DPL’s Maryland jurisdiction.
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COPCO Acquisition Adjustment: On July 19, 2007, the MPSC issued an order which provided for the recovery of a portion of DPL’s goodwill. As a result of this order, $41 million in DPL goodwill was transferred to a regulatory asset. This item is being amortized from August 2007 through August 2018. The return earned is 12.95%.
Deferred Debt Extinguishment Costs: Represents the costs of debt extinguishment associated with issuances of debt for which recovery through regulated utility rates is considered probable, and if approved, will be amortized to interest expense during the authorized rate recovery period.
Deferred Energy Supply Costs: The regulatory asset represents primarily deferred costs associated with a net under-recovery of Default Electricity Supply costs incurred by DPL that are probable of recovery in rates. The regulatory liability represents primarily deferred costs associated with a net over-recovery of Default Electricity Supply costs incurred that will be refunded by DPL to customers.
Incremental Storm Restoration Costs: Represents total incremental storm restoration costs incurred for repair work due to major storm events in 2012 and 2011, including Hurricane Sandy, the June 2012 derecho, and Hurricane Irene, that are recoverable from customers in the Maryland jurisdiction. DPL’s costs related to Hurricane Sandy, the June 2012 derecho and Hurricane Irene are being amortized and recovered in rates, each over a five-year period.
Deferred Losses on Gas Derivatives: Represents losses associated with hedges of natural gas purchases that are recoverable through the Gas Cost Rate approved by the DPSC.
Other: Represents miscellaneous regulatory assets that generally are being amortized over 1 to 20 years.
Asset Removal Costs: The depreciation rates for DPL include a component for removal costs, as approved by the relevant federal and state regulatory commissions. Accordingly, DPL has recorded regulatory liabilities for its estimate of the difference between incurred removal costs and the amount of removal costs recovered through depreciation rates.
Deferred Income Taxes Due to Customers: Represents the portions of deferred income tax assets applicable to utility operations of DPL that have not been reflected in current customer rates for which future payment to customers is probable. As the temporary differences between the financial statement basis and tax basis of assets reverse, deferred recoverable income taxes are amortized.
Deferred Gains on Gas Derivatives: Represents gains associated with hedges of natural gas purchases that will be refunded to customers through the Gas Cost Rate approved by the DPSC.
Other: Includes miscellaneous regulatory liabilities.
Rate Proceedings
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:
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A BSA has been approved and implemented for DPL electric service in Maryland.
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A proposed modified fixed variable rate design (MFVRD) for DPL electric and natural gas service in Delaware was filed in 2009 for consideration by the DPSC and while there was little activity associated with this filing in 2013, the proceeding remains open.
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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 filing seeks approval of an annual rate increase of approximately $39 million (as adjusted by DPL 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. A final DPSC decision is expected by the second quarter of 2014.
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 pending electric distribution base rate case discussed above was concluded. DPL expects that the FLRP will be updated and re-filed at the conclusion of the electric distribution base rate case. A schedule for the FLRP docket has not yet been established.
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 sought approval of an annual rate increase of approximately $12.0 million (as adjusted by DPL on July 15, 2013), based on a requested ROE of 10.25%. The requested rate increase sought to recover expenses associated with DPL’s ongoing efforts to maintain safe and reliable gas service. On October 22, 2013, the DPSC approved a settlement entered into on August 27, 2013 by the DPSC Staff, the Delaware Division of the Public Advocate and DPL, which provides for an annual rate increase of $6.8 million. While the approved settlement provided that no understanding was reached concerning the appropriate ROE, it specified that for reporting purposes and for calculating the AFUDC, construction work in process (CWIP), regulatory asset carrying costs and other accounting metrics, the rate of 9.75% should be used. The new rates became effective on November 1, 2013.
The approved settlement also provides 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 its AMI and allows for the remote reading of gas meters. Recovery of such costs will occur through base rates over a two-year
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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 May 1, 2014, and the remainder will be put into rates on March 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.
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.
Maryland
On March 29, 2013, DPL submitted an application with the 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 sought to recover expenses associated with DPL’s ongoing investments in reliability enhancement improvements and efforts to maintain safe and reliable service. 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 “Resiliency 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 did 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 August 30, 2013, the MPSC issued a final order approving a settlement among DPL, the MPSC staff and the Maryland Office of People’s Counsel (OPC). The approved settlement provides for an annual rate increase of approximately $15 million. While the settlement does not specify an overall ROE, the parties did agree that the ROE for purposes of calculating the AFUDC and regulatory asset carrying costs would be 9.81%. The approved settlement also provides for (i) 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, and (ii) 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 before implementing the surcharge, DPL provides additional information to the MPSC 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 approved 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. The new rates became effective on September 15, 2013.
Federal Energy Regulatory Commission
On October 17, 2013, FERC issued a ruling on challenges filed by the Delaware Municipal Electric Corporation, Inc. (DEMEC) to DPL’s 2011 and 2012 annual formula rate updates. 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 FERC order sets various issues in this
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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 CWIP related to the 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. This challenge is pending at FERC. 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 DPL and its utility affiliates 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 it 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.
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 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 and Pepco 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.
DPL
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 Project
On August 24, 2012, the board of PJM terminated the MAPP project and removed it from PJM’s regional transmission expansion plan. DPL 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. In December 2012, DPL submitted a filing to FERC seeking recovery of approximately $38 million of abandoned MAPP costs over a five-year recovery period. 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.
DPL
In February 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.
On December 18, 2013, DPL submitted a settlement agreement to FERC, which provides for recovery of DPL’s abandoned MAPP costs over a three-year recovery period beginning June 1, 2013. The settlement agreement, which is subject to FERC approval, would resolve all issues concerning the recovery of abandonment costs associated with the cancellation of the MAPP project. DPL cannot predict the timing or results of a final FERC decision in this proceeding.
As of December 31, 2013, DPL had a regulatory asset related to the MAPP abandoned costs of approximately $31 million, representing the original filing amount of approximately $38 million of abandoned costs referred to above less: (i) approximately $1 million of disallowed costs written off in 2013; and (ii) $6 million of amortization expense recorded in 2013. The regulatory asset balance includes the costs of land, land rights, engineering and design, environmental services, and project management and administration.
(8) PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment is comprised of the following:
The non-operating and other property amounts include balances for general plant, plant held for future use, intangible plant and non-utility property. Utility plant is generally subject to a first mortgage lien.
DPL
(9) PENSION AND OTHER POSTRETIREMENT BENEFITS
DPL accounts for its participation in its parent’s single-employer plans, Pepco Holdings’ non-contributory retirement plan (the PHI Retirement Plan) and the Pepco Holdings, Inc. Welfare Plan for Retirees (the PHI OPEB Plan), as participation in multiemployer plans. For 2013, 2012 and 2011, DPL was responsible for $18 million, $23 million and $23 million, respectively, of the pension and other postretirement net periodic benefit cost incurred by PHI. DPL made discretionary tax-deductible contributions to the PHI Retirement Plan of $10 million, $85 million and $40 million for the years ended December 31, 2013, 2012 and 2011, respectively. In addition, DPL made contributions of $3 million, $7 million and $6 million, respectively, to the PHI OPEB Plan for the years ended December 31, 2013, 2012 and 2011. At December 31, 2013 and 2012, DPL’s Prepaid pension expense of $228 million and $232 million, respectively, and Other postretirement benefit obligations of $23 million and $22 million, respectively, effectively represent assets and benefit obligations resulting from DPL’s participation in the PHI benefit plans.
Other Postretirement Benefit Plan Amendments
During 2013, PHI approved two amendments to its other postretirement benefits plan. These amendments impacted the retiree health care and the retiree life insurance benefits, and were effective on January 1, 2014. As a result of the amendments, which were cumulatively significant, PHI remeasured its accumulated postretirement benefit obligation for other postretirement benefits as of July 1, 2013. The remeasurement resulted in a $3 million reduction in DPL’s net periodic benefit cost for other postretirement benefits in 2013. Approximately 29% of net periodic other postretirement benefit costs were capitalized in 2013.
DPL
(10) DEBT
Long-Term Debt
The components of long-term debt are shown in the table below:
(a) Represents a series of Collateral First Mortgage Bonds securing a series of debt securities issued by DPL.
The outstanding first mortgage bonds issued by DPL are issued under a Mortgage and Deed of Trust and are secured by a first lien on substantially all of DPL’s property, plant and equipment, except for certain property excluded from the lien of the mortgage.
Maturities of DPL’s long-term debt outstanding at December 31, 2013 are $100 million for each year 2014 through 2016, $14 million in 2017, $4 million in 2018 and $650 million thereafter.
DPL’s long-term debt is subject to certain covenants. As of December 31, 2013, DPL is in compliance with all such covenants.
The table above does not separately identify $100 million in aggregate principal amount of debt securities issued by DPL. These debt securities are secured by a like amount of first mortgage bonds (Collateral First Mortgage Bonds) of DPL. The principal terms of each such series of debt securities, are identical to the same terms of the corresponding series of Collateral First Mortgage Bonds. Payments of principal and interest made on a series of such debt securities, satisfy the corresponding obligations on the related series of Collateral First Mortgage Bonds. For these reasons, each such series of Collateral First Mortgage Bonds and the corresponding debt securities together effectively represent a single financial obligation and are not identified in the table above separately.
DPL
Bond Issuances
During 2013, DPL issued $300 million of 3.50% first mortgage bonds due November 15, 2023. The net proceeds from the issuance of the long-term debt were used to repay at maturity $250 million of 6.40% first mortgage bonds, plus accrued but unpaid interest thereon, to repay outstanding commercial paper and for general corporate purposes.
Bond Redemptions
During 2013, DPL repaid at maturity $250 million of its 6.40% first mortgage bonds.
Short-Term Debt
DPL has traditionally used a number of sources to fulfill short-term funding needs, such as commercial paper, short-term notes, and bank lines of credit. Proceeds from short-term borrowings are used primarily to meet working capital needs, but may also be used to temporarily fund long-term capital requirements. The components of DPL’s short-term debt at December 31, 2013 and 2012 are as follows:
Commercial Paper
DPL maintains an ongoing commercial paper program to address its short-term liquidity needs. As of December 31, 2013, the maximum capacity available under the program was $500 million, subject to available borrowing capacity under the credit facility.
DPL had $147 million and $32 million of commercial paper outstanding at December 31, 2013 and 2012, respectively. The weighted average interest rates for commercial paper issued by DPL during 2013 and 2012 were 0.29% and 0.43%, respectively. The weighted average maturity of all commercial paper issued by DPL during 2013 and 2012 was three days and four days, respectively.
Variable Rate Demand Bonds
Variable Rate Demand Bonds (VRDBs) are subject to repayment on the demand of the holders and, for this reason, are accounted for as short-term debt in accordance with GAAP. However, bonds submitted for purchase are remarketed by a remarketing agent on a best efforts basis. DPL expects that any bonds submitted for purchase will continue to be remarketed successfully due to the creditworthiness of the company and because the remarketing agent resets the interest rate to the then-current market rate. The bonds may be converted to a fixed rate, fixed term option to establish a maturity which corresponds to the date of final maturity of the bonds. On this basis, DPL views VRDBs as a source of long-term financing. The VRDBs outstanding in 2013 mature as follows: 2017 ($26 million), 2024 ($33 million), 2028 ($16 million), and 2029 ($30 million). The weighted average interest rate for VRDBs was 0.26% during 2013 and 0.38% during 2012. As of December 31, 2013, $105 million in VRDBs issued on behalf of DPL were outstanding (of which $72 million were secured by Collateral First Mortgage Bonds issued by DPL).
DPL
Credit Facility
PHI, Pepco, DPL and ACE maintain an unsecured syndicated credit facility to provide for their respective liquidity needs, including obtaining letters of credit, borrowing for general corporate purposes and supporting their commercial paper programs. On August 1, 2011, PHI, Pepco, DPL and ACE entered into an amended and restated credit agreement which, on August 2, 2012, was amended to extend the term of the credit facility to August 1, 2017 and to amend the pricing schedule to decrease certain fees and interest rates payable to the lenders under the facility. On August 1, 2013, as permitted under the existing terms of the credit agreement, a request by PHI, Pepco, DPL and ACE to extend the credit facility termination date to August 1, 2018 was approved. All of the terms and conditions as well as pricing remained the same.
The aggregate borrowing limit under the amended and restated credit facility is $1.5 billion, all or any portion of which may be used to obtain loans and up to $500 million of which may be used to obtain letters of credit. The facility also includes a swingline loan sub-facility, pursuant to which each company may make same day borrowings in an aggregate amount not to exceed 10% of the total amount of the facility. Any swingline loan must be repaid by the borrower within fourteen days of receipt. The credit sublimit is $750 million for PHI and $250 million for each of Pepco, DPL and ACE. The sublimits may be increased or decreased by the individual borrower during the term of the facility, except that (i) the sum of all of the borrower sublimits following any such increase or decrease must equal the total amount of the facility, and (ii) the aggregate amount of credit used at any given time by (a) PHI may not exceed $1.25 billion, and (b) each of Pepco, DPL or ACE may not exceed the lesser of $500 million or the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of the sublimit reallocations may not exceed eight per year during the term of the facility.
The interest rate payable by each company on utilized funds is, at the borrowing company’s election, (i) the greater of the prevailing prime rate, the federal funds effective rate plus 0.5% and the one month London Interbank Offered Rate plus 1.0%, or (ii) the prevailing Eurodollar rate, plus a margin that varies according to the credit rating of the borrower.
In order for a borrower to use the facility, certain representations and warranties must be true and correct, and the borrower must be in compliance with specified financial and other covenants, including (i) the requirement that each borrowing company maintain a ratio of total indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the credit agreement, which calculation excludes from the definition of total indebtedness certain trust preferred securities and deferrable interest subordinated debt (not to exceed 15% of total capitalization), (ii) with certain exceptions, a restriction on sales or other dispositions of assets, and (iii) a restriction on the incurrence of liens on the assets of a borrower or any of its significant subsidiaries other than permitted liens. The credit agreement contains certain covenants and other customary agreements and requirements that, if not complied with, could result in an event of default and the acceleration of repayment obligations of one or more of the borrowers thereunder. Each of the borrowers was in compliance with all covenants under this facility as of December 31, 2013.
The absence of a material adverse change in PHI’s business, property, results of operations or financial condition is not a condition to the availability of credit under the credit agreement. The credit agreement does not include any rating triggers.
As of December 31, 2013 and 2012, the amount of cash plus borrowing capacity under the credit facility available to meet the liquidity needs of PHI’s utility subsidiaries in the aggregate was $332 million and $477 million, respectively. DPL’s borrowing capacity under the credit facility at any given time depends on the amount of the subsidiary borrowing capacity being utilized by Pepco and ACE and the portion of the total capacity being used by PHI.
DPL
(11) INCOME TAXES
DPL, as an indirect subsidiary of PHI, is included in the consolidated federal income tax return of PHI. Federal income taxes are allocated to DPL pursuant to a written tax sharing agreement that was approved by the Securities and Exchange Commission in connection with the establishment of PHI as a holding company. Under this tax sharing agreement, PHI’s consolidated federal income tax liability is allocated based upon PHI’s and its subsidiaries’ separate taxable income or loss.
The provision for income taxes, reconciliation of income tax expense, and components of deferred income tax liabilities (assets) are shown below.
Provision for Income Taxes
Reconciliation of Income Tax Expense
DPL
Year ended December 31, 2013
On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit issued an opinion in Consolidated Edison Company of New York, Inc. & Subsidiaries v. United States (to which DPL is not a party) that disallowed tax benefits associated with Consolidated Edison’s cross-border lease transaction. As a result of the court’s ruling in this case, PHI determined in the first quarter of 2013 that it could no longer support its current assessment with respect to the likely outcome of tax positions associated with its cross-border energy lease investments held by its wholly-owned subsidiary Potomac Capital Investment Corporation, and PHI recorded an after-tax charge of $377 million in the first quarter of 2013. Included in the $377 million charge was an after-tax interest charge of $54 million and this amount was allocated to each member of PHI’s consolidated group as if each member was a separate taxpayer, resulting in DPL recording a $1 million interest benefit in the first quarter of 2013.
Year ended December 31, 2011
During 2011, PHI reached a settlement with the Internal Revenue Service (IRS) with respect to interest due on its federal tax liabilities related to the November 2010 audit settlement for years 1996 through 2002. In connection with this agreement, PHI reallocated certain amounts that have been on deposit with the IRS since 2006 among liabilities in the settlement years and subsequent years. Primarily related to the settlement and reallocations, DPL recorded a $4 million (after-tax) interest benefit. This is partially offset by adjustments recorded in the third quarter of 2011 related to DPL’s settlement with the state taxing authorities resulting in $1 million (after-tax) of additional tax expense and the recalculation of interest on its uncertain tax positions for open tax years based on different assumptions related to the application of its deposit made with the IRS in 2006 resulting in an additional tax expense of $1 million (after-tax).
Components of Deferred Income Tax Liabilities (Assets)
The net deferred tax liability represents the tax effect, at presently enacted tax rates, of temporary differences between the financial statement basis and tax basis of assets and liabilities. The portion of the net deferred tax liability applicable to DPL’s operations, which has not been reflected in current service rates, represents income taxes recoverable through future rates, net, and is recorded as a regulatory asset on the balance sheet. No valuation allowance for deferred tax assets was required or recorded at December 31, 2013 and 2012. Federal and state net operating losses generally expire over 20 years from 2029 to 2032.
The Tax Reform Act of 1986 repealed the investment tax credit for property placed in service after December 31, 1985, except for certain transition property. Investment tax credits previously earned on DPL’s property continue to be amortized to income over the useful lives of the related property.
DPL
Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits
(a) These reductions of unrecognized tax benefits in 2012 primarily relate to a resolution reached with the IRS for determining deductible mixed service costs for additions to property, plant and equipment.
Unrecognized Benefits That, If Recognized, Would Affect the Effective Tax Rate
Unrecognized tax benefits are related to tax positions that have been taken or are expected to be taken in tax returns that are not recognized in the financial statements because management has either measured the tax benefit at an amount less than the benefit claimed, or expected to be claimed, or has concluded that it is not more likely than not that the tax position will be ultimately sustained. For the majority of these tax positions, the ultimate deductibility is highly certain, but there is uncertainty about the timing of such deductibility. At December 31, 2013, DPL had $1 million of unrecognized tax benefits that, if recognized, would lower the effective tax rate.
Interest and Penalties
DPL recognizes interest and penalties relating to its uncertain tax positions as an element of income tax expense. For the years ended December 31, 2013, 2012 and 2011, DPL recognized less than $1 million of pre-tax interest income, less than $1 million of pre-tax interest income and $6 million of pre-tax interest income ($4 million after-tax), respectively, as a component of income tax expense. As of December 31, 2013, 2012 and 2011, DPL had accrued interest receivable of $2 million, accrued interest receivable of $1 million and accrued interest receivable of $1 million, respectively, related to effectively settled and uncertain tax positions.
Possible Changes to Unrecognized Tax Benefits
It is reasonably possible that the amount of the unrecognized tax benefit with respect to some of DPL’s uncertain tax positions will significantly increase or decrease within the next 12 months. PHI and its subsidiaries have entered into discussions with the IRS with the intention of seeking a settlement of all tax issues of DPL for open tax years 2001 through 2011. PHI currently believes that it is possible that a settlement with the IRS may be reached in 2014, which could significantly impact the balances of unrecognized tax benefits and the related interest accruals of DPL. At this time, it is estimated that there will be a $4 million to $6 million decrease in unrecognized tax benefits within the next 12 months.
Tax Years Open to Examination
DPL, as an indirect subsidiary of PHI, is included on PHI’s consolidated Federal tax return. DPL’s federal income tax liabilities for all years through 2002 have been determined, subject to adjustment to the extent of any net operating loss or other loss or credit carrybacks from subsequent years. The open tax years for the significant states where DPL files state income tax returns (Maryland and Delaware) are the same as for the Federal returns.
DPL
Final IRS Regulations on Repair of Tangible Property
In September 2013, the IRS issued final regulations on expense versus capitalization of repairs with respect to tangible personal property. The regulations are effective for tax years beginning on or after January 1, 2014, and provide an option to early adopt the final regulations for tax years beginning on or after January 1, 2012. It is expected that the IRS will issue revenue procedures that will describe how taxpayers may implement the final regulations. The final repair regulations retain the operative rule that the Unit of Property for network assets is determined by the taxpayer’s particular facts and circumstances except as provided in published guidance. In 2012, with the filing of its 2011 tax return, PHI filed a request for an automatic change in accounting method related to repairs of its network assets in accordance with IRS Revenue Procedure 2011-43. DPL does not expect the effects of the final regulations to be significant and will continue to evaluate the impact of the new guidance on its financial statements.
Other Taxes
Taxes other than income taxes for each year are shown below. These amounts are recoverable through rates.
(12) DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
DPL uses derivative instruments in the form of swaps and over-the-counter options primarily to reduce natural gas commodity price volatility and limit its customers’ exposure to increases in the market price of natural gas under a hedging program approved by the DPSC. DPL uses these derivatives to manage the commodity price risk associated with its physical natural gas purchase contracts. The natural gas purchase contracts qualify as normal purchases, which are not required to be recorded in the financial statements until settled. All premiums paid and other transaction costs incurred as part of DPL’s natural gas hedging activity, in addition to all gains and losses related to hedging activities, are deferred under FASB guidance on regulated operations (ASC 980) until recovered from its customers through a fuel adjustment clause approved by the DPSC.
The tables below identify the balance sheet location and fair values of derivative instruments as of December 31, 2013 and 2012:
DPL
All derivative assets and liabilities available to be offset under master netting arrangements were netted as of December 31, 2013 and 2012. The amount of cash collateral that was offset against these derivative positions is as follows:
As of December 31, 2013 and 2012, all DPL cash collateral pledged related to derivative instruments accounted for at fair value was entitled to be offset under master netting agreements.
Derivatives Designated as Hedging Instruments
Cash Flow Hedges
All premiums paid and other transaction costs incurred as part of DPL’s natural gas hedging activity, in addition to all of DPL’s gains and losses related to hedging activities, are deferred under FASB guidance on regulated operations until recovered from customers based on the fuel adjustment clause approved by the DPSC. For the years ended December 31, 2013, 2012 and 2011, DPL had no net unrealized derivative losses and zero, zero and $5 million, respectively, of net realized losses associated with cash flow hedges recognized in the statements of income (through Purchased energy or Gas purchased expense) that were deferred as Regulatory assets.
Other Derivative Activity
DPL holds certain derivatives that are not in hedge accounting relationships and are not designated as normal purchases or normal sales. These derivatives are recorded at fair value on the balance sheets with the gain or loss for changes in the fair value recorded in income. In accordance with FASB guidance on regulated operations, offsetting regulatory liabilities or regulatory assets are recorded on the balance sheets and the recognition of the derivative gain or loss is deferred because of the DPSC-approved fuel adjustment clause. For the years ended December 31, 2013, 2012 and 2011, the net unrealized derivative losses arising during the period that were deferred as Regulatory assets and the net realized losses recognized in the statements of income (through Purchased energy and Gas purchased expense) that were also deferred as Regulatory assets are provided in the table below:
DPL
As of December 31, 2013 and 2012, DPL had the following net outstanding natural gas commodity forward contracts that did not qualify for hedge accounting:
Contingent Credit Risk Features
The primary contracts used by DPL for derivative transactions are entered into under the International Swaps and Derivatives Association Master Agreement (ISDA) or similar agreements that closely mirror the principal credit provisions of the ISDA. The ISDAs include a Credit Support Annex (CSA) that governs the mutual posting and administration of collateral security. The failure of a party to comply with an obligation under the CSA, including an obligation to transfer collateral security when due or the failure to maintain any required credit support, constitutes an event of default under the ISDA for which the other party may declare an early termination and liquidation of all transactions entered into under the ISDA, including foreclosure against any collateral security. In addition, some of the ISDAs have cross default provisions under which a default by a party under another commodity or derivative contract, or the breach by a party of another borrowing obligation in excess of a specified threshold, is a breach under the ISDA.
Under the ISDA or similar agreements, the parties establish a dollar threshold of unsecured credit for each party in excess of which the party would be required to post collateral to secure its obligations to the other party. The amount of the unsecured credit threshold varies according to the senior, unsecured debt rating of the respective parties or that of a guarantor of the party’s obligations. The fair values of all transactions between the parties are netted under the master netting provisions. Transactions may include derivatives accounted for on-balance sheet as well as normal purchases and normal sales that are accounted for off-balance sheet. If the aggregate fair value of the transactions in a net loss position exceeds the unsecured credit threshold, then collateral is required to be posted in an amount equal to the amount by which the unsecured credit threshold is exceeded. The obligations of DPL are stand-alone obligations without the guarantee of PHI. If DPL’s credit rating were to fall below “investment grade,” the unsecured credit threshold would typically be set at zero and collateral would be required for the entire net loss position. Exchange-traded contracts are required to be fully collateralized without regard to the credit rating of the holder.
The gross fair value of DPL’s derivative liabilities with credit-risk-related contingent features on December 31, 2013 and 2012, was zero and $4 million, respectively. As of those dates, DPL had posted no cash collateral in the normal course of business against its gross derivative liabilities. If DPL’s debt ratings had been downgraded below investment grade as of December 31, 2013 and 2012, DPL’s net settlement amounts would have been approximately zero and $2 million, respectively, and DPL would have been required to post collateral with the counterparties of approximately zero and $2 million, respectively. The net settlement and additional collateral amounts reflect the effect of offsetting transactions under master netting agreements.
DPL’s primary sources for posting cash collateral or letters of credit are PHI’s credit facilities, under which DPL is a borrower. As of December 31, 2013 and 2012, the aggregate amount of cash plus borrowing capacity under the credit facilities available to meet the liquidity needs of PHI’s utility subsidiaries was $332 million and $477 million, respectively.
DPL
(13) FAIR VALUE DISCLOSURES
Financial Instruments Measured at Fair Value on a Recurring Basis
DPL applies FASB guidance on fair value measurement and disclosures (ASC 820) that established a framework for measuring fair value and expanded disclosures about fair value measurements. As defined in the guidance, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). DPL utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. Accordingly, DPL utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1) and the lowest priority to unobservable inputs (level 3).
The following tables set forth, by level within the fair value hierarchy, DPL’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2013 and 2012. As required by the guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. DPL’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.
(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2013.
(b) The fair value of derivative assets reflect netting by counterparty before the impact of collateral.
(c) Represents natural gas swaps purchased by DPL as part of a natural gas hedging program approved by the DPSC.
DPL
(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2012.
(b) The fair value of derivative liabilities reflect netting by counterparty before the impact of collateral.
(c) Represents natural gas options purchased by DPL as part of a natural gas hedging program approved by the DPSC.
DPL classifies its fair value balances in the fair value hierarchy based on the observability of the inputs used in the fair value calculation as follows:
Level 1 - Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis, such as the New York Mercantile Exchange (NYMEX).
Level 2 - Pricing inputs are other than quoted prices in active markets included in level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using broker quotes in liquid markets and other observable data. Level 2 also includes those financial instruments that are valued using methodologies that have been corroborated by observable market data through correlation or by other means. Significant assumptions are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.
Level 2 executive deferred compensation plan liabilities associated with the life insurance policies represent a deferred compensation obligation, the value of which is tracked via underlying insurance sub-accounts. The sub-accounts are designed to mirror existing mutual funds and money market funds that are observable and actively traded.
Level 3 - Pricing inputs that are significant and generally less observable than those from objective sources. Level 3 includes those financial instruments that are valued using models or other valuation methodologies.
Derivative instruments categorized as level 3 represent natural gas options used by DPL as part of a natural gas hedging program approved by the DPSC. DPL applies a Black-Scholes model to value its options with inputs, such as forward price curves, contract prices, contract volumes, the risk-free rate and implied volatility factors that are based on a range of historical NYMEX option prices. DPL maintains valuation policies and procedures and reviews the validity and relevance of the inputs used to estimate the fair value of its options. As of December 31, 2013, all of these contracts classified as level 3 derivative instruments have settled.
DPL
The table below summarizes the primary unobservable input used to determine the fair value of DPL’s level 3 instruments and the range of values that could be used for the input as of December 31, 2012:
DPL used values within this range as part of its fair value estimates. A significant change in the unobservable input within this range would have an insignificant impact on the reported fair value as of December 31, 2012.
Executive deferred compensation plan assets include certain life insurance policies that are valued using the cash surrender value of the policies, net of loans against those policies. The cash surrender values do not represent a quoted price in an active market; therefore, those inputs are unobservable and the policies are categorized as level 3. Cash surrender values are provided by third parties and reviewed by DPL for reasonableness.
Reconciliations of the beginning and ending balances of DPL’s fair value measurements using significant unobservable inputs (Level 3) for the years ended December 31, 2013 and 2012 are shown below:
Other Financial Instruments
The estimated fair values of DPL’s Long-term debt instruments that are measured at amortized cost in DPL’s financial statements and the associated level of the estimates within the fair value hierarchy as of December 31, 2013 and 2012 are shown in the tables below. As required by the fair value measurement guidance, debt instruments are classified in their entirety within the fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. DPL’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, which may affect the valuation of fair value debt instruments and their placement within the fair value hierarchy levels.
The fair value of Long-term debt categorized as level 2 is based on a blend of quoted prices for the debt and quoted prices for similar debt on the measurement date. The blend places more weight on current pricing information when determining the final fair value measurement. The fair value information is provided by brokers and DPL reviews the methodologies and results.
DPL
The fair value of Long-term debt categorized as level 3 is based on a discounted cash flow methodology using observable inputs, such as the U.S. Treasury yield, and unobservable inputs, such as credit spreads, because quoted prices for the debt or similar debt in active markets were insufficient.
(a) The carrying amount for Long-term debt is $967 million as of December 31, 2013.
(a) The carrying amount for Long-term debt is $917 million as of December 31, 2012.
The carrying amounts of all other financial instruments in the accompanying financial statements approximate fair value.
DPL
(14) COMMITMENTS AND CONTINGENCIES
General Litigation
From time to time, DPL is named as a defendant in litigation, usually relating to general liability or auto liability claims that resulted in personal injury or property damage to third parties. DPL is self-insured against such claims up to a certain self-insured retention amount and maintains insurance coverage against such claims at higher levels, to the extent deemed prudent by management. In addition, DPL’s contracts with its vendors generally require the vendors to name DPL as an additional insured for the amount at least equal to DPL’s self-insured retention. Further, DPL’s contracts with its vendors require the vendors to indemnify DPL for various acts and activities that may give rise to claims against DPL. Loss contingency liabilities for both asserted and unasserted claims are recognized if it is probable that a loss will result from such a claim and if the amounts of the losses can be reasonably estimated. Although the outcome of the claims and proceedings cannot be predicted with any certainty, management believes that there are no existing claims or proceedings that are likely to have a material adverse effect on DPL’s financial condition, results of operations or cash flows. At December 31, 2013, DPL had loss contingency liabilities for general litigation totaling approximately $2 million.
Environmental Matters
DPL is subject to regulation by various federal, regional, state, and local authorities with respect to the environmental effects of its operations, including air and water quality control, solid and hazardous waste disposal, and limitations on land use. Although penalties assessed for violations of environmental laws and regulations are not recoverable from DPL’s customers, environmental clean-up costs incurred by DPL generally are included in its cost of service for ratemaking purposes. The total accrued liabilities for the environmental contingencies of DPL described below at December 31, 2013 are summarized as follows:
Ward Transformer Site
In April 2009, a group of potentially responsible parties (PRPs) with respect to the Ward Transformer site in Raleigh, North Carolina, filed a complaint in the U.S. District Court for the Eastern District of North Carolina, alleging cost recovery and/or contribution claims against a number of entities, including DPL, based on its alleged sale of transformers to Ward Transformer, with respect to past and future response costs incurred by the PRP group in performing a removal action at the site. In a March 2010 order, the court denied the defendants’ motion to dismiss. The litigation is moving forward with certain “test case” defendants (not including DPL) filing summary judgment motions regarding liability. The case has been stayed as to the remaining defendants pending rulings upon the test cases. In a January 31, 2013 order, the Federal district court granted summary judgment for the test case defendant whom plaintiffs alleged was liable based on its sale of transformers to Ward Transformer. The Federal district court’s order, which plaintiffs have appealed to the U.S. Court of Appeals for the Fourth Circuit, addresses only the liability of the test case defendant. DPL has concluded that a loss is reasonably possible with respect to this matter, but is unable to estimate an amount or range of reasonably possible losses to which it may be exposed. DPL does not believe that it had extensive business transactions, if any, with the Ward Transformer site.
DPL
Indian River Oil Release
In 2001, DPL entered into a consent agreement with the Delaware Department of Natural Resources and Environmental Control for remediation, site restoration, natural resource damage compensatory projects and other costs associated with environmental contamination resulting from an oil release at the Indian River generating facility, which was sold in June 2001. The amount of remediation costs accrued for this matter is included in the table above in the column entitled “Legacy Generation - Regulated.”
Metal Bank Site
In the first quarter of 2013, the National Oceanic and Atmospheric Administration (NOAA) contacted DPL on behalf of itself and other federal and state trustees to request that DPL execute a tolling agreement to facilitate settlement negotiations concerning natural resource damages allegedly caused by releases of hazardous substances, including polychlorinated biphenyls, at the Metal Bank Superfund Site located in Philadelphia, Pennsylvania. DPL has executed the tolling agreement and will participate in settlement discussions with the NOAA, the trustees and other PRPs.
The amount accrued for this matter is included in the table above in the column entitled “Transmission and Distribution.”
Contractual Obligations
Power Purchase Contracts
As of December 31, 2013, DPL’s contractual obligations under non-derivative power purchase contracts were $64 million in 2014, $131 million in 2015 to 2016, $131 million in 2017 to 2018, and $300 million in 2019 and thereafter.
Lease Commitments
DPL leases an 11.9% interest in the Merrill Creek Reservoir. The lease is an operating lease and payments over the remaining lease term, which ends in 2032, are $84 million in the aggregate. DPL also has long-term leases for certain other facilities and equipment. Total future minimum operating lease payments for DPL, including the Merrill Creek Reservoir lease, as of December 31, 2013, are $13 million in 2014, $13 million in 2015, $11 million in 2016, $10 million in 2017, $14 million in 2018, and $111 million thereafter.
Rental expense for operating leases, including the Merrill Creek Reservoir lease, was $13 million, $12 million and $11 million for the years ended December 31, 2013, 2012 and 2011, respectively.
(15) RELATED PARTY TRANSACTIONS
PHI Service Company provides various administrative and professional services to PHI and its regulated and unregulated subsidiaries, including DPL. The cost of these services is allocated in accordance with cost allocation methodologies set forth in the service agreement using a variety of factors, including the subsidiaries’ share of employees, operating expenses, assets and other cost methods. These intercompany transactions are eliminated by PHI in consolidation and no profit results from these transactions at PHI. PHI Service Company costs directly charged or allocated to DPL for the years ended December 31, 2013, 2012 and 2011 were $154 million, $153 million and $133 million, respectively.
DPL
In addition to the PHI Service Company charges described above, DPL’s financial statements include the following related party transactions in its statements of income:
(a) Included in Purchased energy expense.
(b) Included in Electric revenue.
As of December 31, 2013 and 2012, DPL had the following balances on its balance sheets due to related parties:
(a) Included in Accounts payable due to associated companies.
(16) QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
The quarterly data presented below reflect all adjustments necessary, in the opinion of management, for a fair presentation of the interim results. Quarterly data normally vary seasonally because of temperature variations and differences between summer and winter rates. Therefore, comparisons by quarter within a year are not meaningful.
DPL
(17) VARIABLE INTEREST ENTITIES
DPL is required to consolidate a variable interest entity (VIE) in accordance with FASB ASC 810 if DPL is the primary beneficiary of the VIE. The primary beneficiary of a VIE is typically the entity with both the power to direct activities most significantly impacting economic performance of the VIE and the obligation to absorb losses or receive benefits of the VIE that could potentially be significant to the VIE. DPL performed a qualitative analysis to determine whether a variable interest provided a controlling financial interest in a VIE at December 31, 2013, which is described below.
DPL is subject to Renewable Energy Portfolio Standards (RPS) in the state of Delaware that require it to obtain renewable energy credits (RECs) for energy delivered to its customers. DPL’s costs associated with obtaining RECs to fulfill its RPS obligations are recoverable from its customers by law. As of December 31, 2013, DPL is a party to three land-based wind power purchase agreements (PPAs) in the aggregate amount of 128 MWs and one solar PPA with a 10 MW facility. Each of the facilities associated with these PPAs is operational, and DPL is obligated to purchase energy and RECs in amounts generated and delivered by the wind facilities and solar renewable energy credits (SRECs) from the solar facility up to certain amounts (as set forth below) at rates that are primarily fixed under the respective PPA. DPL has concluded that while VIEs exist under these contracts, consolidation is not required for any of these PPAs under the FASB guidance on the consolidation of variable interest entities as DPL is not the primary beneficiary. DPL has not provided financial or other support under these arrangements that it was not previously contractually required to provide during the periods presented, nor does DPL have any intention to provide such additional support.
Because DPL has no equity or debt interest in these renewable energy transactions, the maximum exposure to loss relates primarily to any above-market costs incurred for power or RECs. Due to unpredictability in amount of MW’s ultimately purchased under the PPAs for purchased renewable energy and SRECs, PHI and DPL are unable to quantify the maximum exposure to loss. The power purchase and REC costs are recoverable from DPL’s customers through regulated rates.
DPL is obligated to purchase energy and RECs from one of the wind facilities through 2024 in amounts not to exceed 50 MWs, from the second wind facility through 2031 in amounts not to exceed 40 MWs, and from the third wind facility through 2031 in amounts not to exceed 38 MWs. DPL’s purchases under the three wind PPAs totaled $30 million, $27 million and $18 million for the years ended December 31, 2013, 2012 and 2011, respectively.
The term of the agreement with the solar facility is 20 years and DPL is obligated to purchase SRECs in an amount up to 70 percent of the energy output at a fixed price. DPL’s purchases under the solar agreement were $3 million, $2 million and $1 million for the years ended December 31, 2013, 2012 and 2011, respectively.
On October 18, 2011, the DPSC approved a tariff submitted by DPL in accordance with the requirements of the RPS specific to fuel cell facilities totaling 30 MWs to be constructed by a qualified fuel cell provider. The tariff and the RPS establish that DPL would be an agent to collect payments in advance from its distribution customers and remit them to the qualified fuel cell provider for each MW hour (MWh) of energy produced by the fuel cell facilities over 21 years. DPL has no obligation to the qualified fuel cell provider other than to remit payments collected from its distribution customers pursuant to the tariff. The RPS provides for a reduction in DPL’s REC requirements based upon the actual energy output of the facilities. At December 31, 2013 and 2012, 15 MWs and 3 MWs of capacity were available from fuel cell facilities placed in service under the tariff, respectively. DPL billed $23 million and $4 million to distribution customers during the years ended December 31, 2013 and 2012, respectively. DPL has concluded that while a VIE exists under this arrangement, consolidation is not required for this arrangement under the FASB guidance on consolidation of variable interest entities as DPL is not the primary beneficiary.
ACE
Management’s Report on Internal Control over Financial Reporting
The management of Atlantic City Electric Company (ACE) is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management of ACE assessed ACE’s internal control over financial reporting as of December 31, 2013 based on the framework in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its assessment, the management of ACE concluded that ACE’s internal control over financial reporting was effective as of December 31, 2013.
ACE
Report of Independent Registered Public Accounting Firm
To the Shareholder and Board of Directors of
Atlantic City Electric Company
In our opinion, the consolidated financial statements of Atlantic City Electric Company (a wholly owned subsidiary of Pepco Holdings, Inc.) listed in the accompanying index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Atlantic City Electric Company and its subsidiary at December 31, 2013 and December 31, 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule of Atlantic City Electric Company listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
Washington, D.C.
February 27, 2014
ACE
ATLANTIC CITY ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF INCOME
The accompanying Notes are an integral part of these Consolidated Financial Statements.
ACE
ATLANTIC CITY ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
The accompanying Notes are an integral part of these Consolidated Financial Statements.
ACE
ATLANTIC CITY ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
The accompanying Notes are an integral part of these Consolidated Financial Statements.
ACE
ATLANTIC CITY ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying Notes are an integral part of these Consolidated Financial Statements.
ACE
ATLANTIC CITY ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF EQUITY
The accompanying Notes are an integral part of these Consolidated Financial Statements.
ACE
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
ATLANTIC CITY ELECTRIC COMPANY
(1) ORGANIZATION
Atlantic City Electric Company (ACE) is engaged in the transmission and distribution of electricity in southern New Jersey. ACE also provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its service territory who do not elect to purchase electricity from a competitive energy supplier. Default Electricity Supply is known as Basic Generation Service in New Jersey. ACE is a wholly owned subsidiary of Conectiv, LLC (Conectiv), which is wholly owned by Pepco Holdings, Inc. (Pepco Holdings or PHI).
(2) SIGNIFICANT ACCOUNTING POLICIES
Consolidation Policy
The accompanying consolidated financial statements include the accounts of ACE and its wholly owned subsidiary Atlantic City Electric Transition Funding, LLC (ACE Funding). All intercompany balances and transactions between subsidiaries have been eliminated. ACE uses the equity method to report investments, corporate joint ventures, partnerships, and affiliated companies where it holds an interest and can exercise significant influence over the operations and policies of the entity. Certain transmission and other facilities currently held are consolidated in proportion to ACE’s percentage interest in the facility.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) requires management to make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities in the consolidated financial statements and accompanying notes. Although ACE believes that its estimates and assumptions are reasonable, they are based upon information available to management at the time the estimates are made. Actual results may differ significantly from these estimates.
Significant matters that involve the use of estimates include the assessment of contingencies, the calculation of future cash flows and fair value amounts for use in asset impairment evaluations, fair value calculations for derivative instruments, pension and other postretirement benefits assumptions, the assessment of the probability of recovery of regulatory assets, accrual of storm restoration costs, accrual of unbilled revenue, recognition of changes in network service transmission rates for prior service year costs, accrual of loss contingency liabilities for general and auto liability claims, and income tax provisions and reserves. Additionally, ACE is subject to legal, regulatory, and other proceedings and claims that arise in the ordinary course of its business. ACE records an estimated liability for these proceedings and claims when it is probable that a loss has been incurred and the loss is reasonably estimable.
Revenue Recognition
ACE recognizes revenue upon distribution of electricity to its customers, including unbilled revenue for electricity delivered but not yet billed. ACE’s unbilled revenue was $36 million and $39 million as of December 31, 2012 and 2011, respectively, and these amounts are included in Accounts receivable. ACE calculates unbilled revenue using an output-based methodology. This methodology is based on the supply of electricity intended for distribution to customers. The unbilled revenue process requires management to make assumptions and judgments about input factors such as customer sales mix, temperature, and estimated line losses (estimates of electricity expected to be lost in the process of its transmission and distribution to customers). The assumptions and judgments are inherently uncertain and susceptible to change from period to period, and if the actual results differ from the projected results, the impact could be material.
ACE
Taxes related to the consumption of electricity by its customers are a component of ACE’s tariffs and, as such, are billed to customers and recorded in Operating revenue. Accruals for the remittance of these taxes by ACE are recorded in Other taxes.
Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions
Taxes included in ACE’s gross revenues were $11 million, $15 million and $22 million for the years ended December 31, 2013, 2012 and 2011, respectively.
Accounting for Derivatives
ACE began applying derivative accounting to two of its Standard Offer Capacity Agreements (SOCAs), as of June 30, 2012 because the generators cleared the 2015-2016 PJM Interconnection, LLC (PJM) capacity auction in May 2012. Changes in the fair value of the derivatives embedded in the SOCAs are deferred as regulatory assets or liabilities because the New Jersey Board of Public Utilities (NJBPU) has ordered that ACE is obligated to distribute to or recover from its distribution customers, all payments received or made by ACE, respectively, under the SOCAs. See Note (6), “Regulatory Matters,” for additional information on the SOCAs.
Long-Lived Asset Impairment Evaluation
ACE evaluates certain long-lived assets to be held and used (for example, equipment and real estate) for impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. Examples of such events or changes include a significant decrease in the market price of a long-lived asset or a significant adverse change in the manner in which an asset is being used or its physical condition. A long-lived asset to be held and used is written down to its estimated fair value if the expected future undiscounted cash flow from the asset is less than its carrying value.
For long-lived assets that can be classified as assets to be disposed of by sale, an impairment loss is recognized to the extent that the asset’s carrying value exceeds its estimated fair value including costs to sell.
Income Taxes
ACE, as an indirect subsidiary of Pepco Holdings, is included in the consolidated federal income tax return of PHI. Federal income taxes are allocated to ACE based upon the taxable income or loss amounts, determined on a separate return basis.
The consolidated financial statements include current and deferred income taxes. Current income taxes represent the amount of tax expected to be reported on ACE’s state income tax returns and the amount of federal income tax allocated from Pepco Holdings.
Deferred income tax assets and liabilities represent the tax effects of temporary differences between the financial statement basis and tax basis of existing assets and liabilities, and they are measured using presently enacted tax rates. The portion of ACE’s deferred tax liability applicable to its utility operations that has not been recovered from utility customers represents income taxes recoverable in the future and is included in Regulatory assets on the consolidated balance sheets. See Note (6), “Regulatory Matters,” for additional information.
Deferred income tax expense generally represents the net change during the reporting period in the net deferred tax liability and deferred recoverable income taxes.
ACE recognizes interest on underpayments and overpayments of income taxes, interest on uncertain tax positions, and tax-related penalties in income tax expense.
Investment tax credits are being amortized to income over the useful lives of the related property.
ACE
Consolidation of Variable Interest Entities
ACE assesses its contractual arrangements with variable interest entities to determine whether it is the primary beneficiary and thereby has to consolidate the entities in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 810. The guidance addresses conditions under which an entity should be consolidated based upon variable interests rather than voting interests. See Note (16), “Variable Interest Entities,” for additional information.
Cash and Cash Equivalents
Cash and cash equivalents include cash on hand, cash invested in money market funds and commercial paper held with original maturities of three months or less. Additionally, deposits in PHI’s money pool, which ACE and certain other PHI subsidiaries use to manage short-term cash management requirements, are considered cash equivalents. Deposits in the money pool are guaranteed by PHI. PHI deposits funds in the money pool to the extent that the pool has insufficient funds to meet the needs of its participants, which may require PHI to borrow funds for deposit from external sources.
Restricted Cash Equivalents
The Restricted cash equivalents included in Current assets and the Restricted cash equivalents included in Other assets consist of (i) cash held as collateral that is restricted from use for general corporate purposes and (ii) cash equivalents that are specifically segregated based on management’s intent to use such cash equivalents for a particular purpose. The classification as current or non-current conforms to the classification of the related liabilities.
Accounts Receivable and Allowance for Uncollectible Accounts
ACE’s Accounts receivable balance primarily consists of customer accounts receivable arising from the sale of goods and services to customers within its service territories, other accounts receivable, and accrued unbilled revenue. Accrued unbilled revenue represents revenue earned in the current period but not billed to the customer until a future date (usually within one month after the receivable is recorded).
ACE maintains an allowance for uncollectible accounts and changes in the allowance are recorded as an adjustment to Other operation and maintenance expense in the consolidated statements of income. ACE determines the amount of allowance based on specific identification of material amounts at risk by customer and maintains a reserve based on its historical collection experience. The adequacy of this allowance is assessed on a quarterly basis by evaluating all known factors such as the aging of the receivables, historical collection experience, the economic and competitive environment and changes in the creditworthiness of its customers. Accounts receivable are written off in the period in which the receivable is deemed uncollectible and collection efforts have been exhausted. Recoveries of Accounts receivable previously written off are recorded when it is probable they will be recovered. Although ACE believes its allowance is adequate, it cannot anticipate with any certainty the changes in the financial condition of its customers. As a result, ACE records adjustments to the allowance for uncollectible accounts in the period in which the new information that requires an adjustment to the reserve becomes known.
Inventories
Included in inventories are transmission and distribution materials and supplies. ACE utilizes the weighted average cost method of accounting for inventory items. Under this method, an average price is determined for the quantity of units acquired at each price level and is applied to the ending quantity to calculate the total ending inventory balance. Materials and supplies are recorded in Inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed.
ACE
Regulatory Assets and Regulatory Liabilities
Certain aspects of ACE’s business are subject to regulation by the NJBPU. The transmission of electricity by ACE is regulated by the Federal Energy Regulatory Commission (FERC).
Based on the regulatory framework in which it has operated, ACE has historically applied, and in connection with its transmission and distribution business continues to apply, FASB guidance on regulated operations (ASC 980). The guidance allows regulated entities, in appropriate circumstances, to defer the income statement impact of certain costs that are expected to be recovered in future rates through the establishment of regulatory assets and defer certain revenues that are expected to be refunded to customers through the establishment of regulatory liabilities. Management’s assessment of the probability of recovery of regulatory assets requires judgment and interpretation of laws, regulatory commission orders and other factors. If management subsequently determines, based on changes in facts or circumstances, that a regulatory asset is not probable of recovery, the regulatory asset would be eliminated through a charge to earnings.
Property, Plant and Equipment
Property, plant and equipment is recorded at original cost, including labor, materials, asset retirement costs and other direct and indirect costs, including capitalized interest. The carrying value of Property, plant and equipment is evaluated for impairment whenever circumstances indicate the carrying value of those assets may not be recoverable. Upon retirement, the cost of regulated property, net of salvage, is charged to accumulated depreciation.
The annual provision for depreciation on electric property, plant and equipment is computed on a straight-line basis using composite rates by classes of depreciable property. Accumulated depreciation is charged with the cost of depreciable property retired, less salvage and other recoveries. Non-operating and other property is generally depreciated on a straight-line basis over the useful lives of the assets. The system-wide composite annual depreciation rates for the years ended December 31, 2013, 2012 and 2011 for ACE’s property were approximately 2.8%, 3.0% and 3.0%, respectively.
In 2010, ACE was awarded $19 million from the U.S. Department of Energy (DOE) to fund a portion of the costs incurred for the implementation of direct load control, distribution automation and communications infrastructure in its New Jersey service territory. ACE has elected to recognize the award proceeds as a reduction in the carrying value of the assets acquired rather than grant income over the service period.
Capitalized Interest and Allowance for Funds Used During Construction
In accordance with FASB guidance on regulated operations (ASC 980), utilities can capitalize the capital costs of financing the construction of plant and equipment as Allowance for Funds Used During Construction (AFUDC). This results in the debt portion of AFUDC being recorded as a reduction of Interest expense and the equity portion of AFUDC being recorded as an increase to Other income in the accompanying consolidated statements of income.
ACE recorded AFUDC for borrowed funds of less than $1 million for the year ended December 31, 2013, $2 million for the year ended December 31, 2012 and $2 million for the year ended December 31, 2011.
ACE recorded amounts for the equity component of AFUDC of less than $1 million for the year ended December 31, 2013, $3 million for the year ended December 31, 2012 and less than $1 million for the year ended December 31, 2011.
ACE
Leasing Activities
ACE’s lease transactions include plant, office space, equipment, software and vehicles. In accordance with FASB guidance on leases (ASC 840), these leases are classified as operating leases.
An operating lease in which ACE is the lessee generally results in a level income statement charge over the term of the lease, reflecting the rental payments required by the lease agreement. If rental payments are not made on a straight-line basis, ACE’s policy is to recognize rent expense on a straight-line basis over the lease term unless another systematic and rational allocation basis is more representative of the time pattern in which the leased property is physically employed.
Amortization of Debt Issuance and Reacquisition Costs
ACE defers and amortizes debt issuance costs and long-term debt premiums and discounts over the lives of the respective debt issuances. When refinancing or redeeming existing debt, any unamortized premiums, discounts and debt issuance costs, as well as debt redemption costs, are classified as regulatory assets and are amortized generally over the life of the original issue.
Pension and Postretirement Benefit Plans
Pepco Holdings sponsors the PHI Retirement Plan, a non-contributory, defined benefit pension plan that covers substantially all employees of ACE and certain employees of other Pepco Holdings subsidiaries. Pepco Holdings also provides supplemental retirement benefits to certain eligible executives and key employees through nonqualified retirement plans and provides certain postretirement health care and life insurance benefits for eligible retired employees.
The PHI Retirement Plan is accounted for in accordance with FASB guidance on retirement benefits (ASC 715).
Dividend Restrictions
All of ACE’s shares of outstanding common stock are held by Conectiv, its parent company. In addition to its future financial performance, the ability of ACE to pay dividends to its parent company is subject to limits imposed by: (i) state corporate laws, which impose limitations on the funds that can be used to pay dividends and the regulatory requirement that ACE obtain the prior approval of the NJBPU before dividends can be paid if its equity as a percent of its total capitalization, excluding securitization debt, falls below 30%; (ii) the prior rights of holders of existing and future preferred stock, mortgage bonds and other long-term debt issued by ACE and any other restrictions imposed in connection with the incurrence of liabilities; and (iii) certain provisions of the charter of ACE which impose restrictions on payment of common stock dividends for the benefit of preferred stockholders. Currently, the restriction in the ACE charter does not limit its ability to pay common stock dividends. ACE had approximately $190 million and $200 million of retained earnings available for payment of common stock dividends at December 31, 2013 and 2012, respectively. These amounts represent the total retained earnings balances at those dates.
Reclassifications and Adjustments
Certain prior period amounts have been reclassified in order to conform to the current period presentation. The following adjustments have been recorded and are not considered material individually or in the aggregate to either the current period or prior period financial results:
Deferred Electric Service Costs Adjustments
In 2012, ACE recorded an adjustment to correct errors associated with its calculation of deferred electric service costs. This adjustment resulted in an increase of $3 million to deferred electric service costs, all of which relates to periods prior to 2012.
ACE
Income Tax Expense
During 2011, ACE completed a reconciliation of its deferred taxes associated with certain regulatory assets and recorded adjustments which resulted in an increase to income tax expense of $1 million for the year ended December 31, 2011.
(3) NEWLY ADOPTED ACCOUNTING STANDARDS
Balance Sheet (ASC 210)
In December 2011, the FASB issued new disclosure requirements for financial assets and financial liabilities, such as derivatives, that are subject to contractual netting arrangements. The new disclosure requirements include information about the gross exposure of the instruments and the net exposure of the instruments under contractual netting arrangements, how the exposures are presented in the financial statements, and the terms and conditions of the contractual netting arrangements. ACE adopted the new guidance during the first quarter of 2013 and concluded it did not have a material impact on its consolidated financial statements.
(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED
Joint and Several Liability Arrangements (ASC 405)
In February 2013, the FASB issued new recognition and disclosure requirements for certain joint and several liability arrangements where the total amount of the obligation is fixed at the reporting date. For arrangements within the scope of this standard, ACE will be required to include in its liabilities the additional amounts it expects to pay on behalf of its co-obligors, if any. ACE will also be required to provide additional disclosures including the nature of the arrangements with its co-obligors, the total amounts outstanding under the arrangements between ACE and its co-obligors, the carrying value of the liability, and the nature and limitations of any recourse provisions that would enable recovery from other entities.
The new requirements are effective retroactively beginning on January 1, 2014, with implementation required for prior periods if joint and several liability arrangement obligations exist as of January 1, 2014. ACE does not expect this new guidance to have a material impact on its consolidated financial statements.
Income Taxes (ASC 740)
In July 2013, the FASB issued new guidance that will require the netting of certain unrecognized tax benefits against a deferred tax asset for a loss or other similar tax carryforward that would apply upon settlement of the uncertain tax position. The new requirements are effective prospectively beginning with ACE’s March 31, 2014 consolidated financial statements for all unrecognized tax benefits existing at the adoption date. Retrospective implementation and early adoption of the guidance are permitted. ACE does not expect this new guidance to have a material impact on its consolidated financial statements.
(5) SEGMENT INFORMATION
The company operates its business as one regulated utility segment, which includes all of its services as described above.
ACE
(6) REGULATORY MATTERS
Regulatory Assets and Regulatory Liabilities
The components of ACE’s regulatory asset and liability balances at December 31, 2013 and 2012 are as follows:
(a) A return is generally earned on these deferrals.
A description for each category of regulatory assets and regulatory liabilities follows:
Securitized Stranded Costs: Certain contract termination payments under a contract between ACE and an unaffiliated non-utility generator (NUG) and costs associated with the regulated operations of ACE’s electricity generation business are no longer recoverable through customer rates (collectively referred to as “stranded costs”). The stranded costs are amortized over the life of Transition Bonds issued by ACE Funding to securitize the recoverability of these stranded costs. These Transition Bonds mature between 2013 and 2023. A customer surcharge is collected by ACE to fund principal and interest payments on the Transition Bonds.
Deferred Energy Supply Costs: The regulatory asset represents primarily deferred costs associated with a net under-recovery of Basic Generation Service costs incurred by ACE that are probable of recovery in rates. The regulatory liability represents primarily deferred costs associated with a net over-recovery of Basic Generation Service costs incurred that will be refunded by ACE to customers.
Recoverable Income Taxes: Represents amounts recoverable from ACE’s customers for tax benefits applicable to utility operations previously recognized in income tax expense before the company was ordered to account for the tax benefits as deferred income taxes. As the temporary differences between the financial statement basis and tax basis of assets reverse, the deferred recoverable balances are reversed.
Incremental Storm Restoration Costs: Represents total incremental storm restoration costs incurred for repair work due to major storm events in 2012 and 2011, including Hurricane Sandy, the June 2012 derecho, and Hurricane Irene, that are recoverable from customers in the New Jersey jurisdiction. ACE’s costs related to Hurricane Sandy, the June 2012 derecho and Hurricane Irene are being amortized and recovered in rates, each over a three-year period.
ACE
ACE SOCAs: The regulatory asset represented unrealized losses associated with the SOCAs that ACE had entered into by order of the NJBPU. The NJBPU had ordered full recovery from distribution customers of payments made by ACE related to the SOCAs. Since these unrealized losses were non-cash, the related regulatory asset does not earn a return. The regulatory liability represented unrealized gains associated with the SOCAs that ACE had entered into by order of the NJBPU. The NJBPU had ordered that any amounts that ACE receives related to the SOCAs be remitted to its distribution customers. As further discussed below, ACE has derecognized their regulatory assets and liabilities related to the SOCAs in the fourth quarter of 2013.
Other: Represents miscellaneous regulatory assets that generally are being amortized over 1 to 20 years.
Federal and State Tax Benefits, Related to Securitized Stranded Costs: Securitized stranded costs include a portion attributable to the future tax benefit expected to be realized when the higher tax basis of the generating facilities divested by ACE is deducted for New Jersey state income tax purposes, as well as the future benefit to be realized through the reversal of federal excess deferred taxes. To account for the possibility that these tax benefits may be given to ACE’s customers through lower rates in the future, ACE established a regulatory liability. The regulatory liability related to federal excess deferred taxes will remain until such time as the Internal Revenue Service (IRS) issues its final regulations with respect to normalization of these federal excess deferred taxes.
Excess Depreciation Reserve: The excess depreciation reserve was recorded as part of an ACE New Jersey rate case settlement. This excess reserve is the result of a change in estimated depreciable lives and a change in depreciation technique from remaining life to whole life that caused an over-recovery for depreciation expense from customers when the remaining life method had been used. The excess was amortized as a reduction in Depreciation and amortization expense over an 8.25 year period, and expired in 2013.
Other: Includes miscellaneous regulatory liabilities.
Rate Proceedings
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 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 return on equity (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 (a customer charge to recover 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 seeks to recover expenses associated with ACE’s ongoing investments in reliability enhancement improvements and efforts to maintain safe and reliable service. and to recover 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 providing for an increase in ACE’s electric 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. Rates were effective on July 1, 2013.
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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 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. 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.
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 NJBPU will commence a rulemaking proceeding to further implement the directives of the Appellate Division decision.
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. Consequently, this policy has substantially reduced ACE’s rate base 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 for the remainder of the proceeding or for the issuance of a decision.
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 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 ACE and its utility affiliates 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
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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. ACE cannot predict when a final FERC decision in this proceeding will be issued.
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 (13), “Derivative Instruments and Hedging Activities.” 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. On October 31, 2013, one of the SOCA generation companies filed a notice of appeal of the October 25, 2013 Federal district court decision with the U.S. Court of Appeals for the Third Circuit (the Federal circuit court). On November 8, 2013, the other remaining SOCA generating company filed a motion to intervene in the proceedings and a notice of appeal of the October 25, 2013 Federal district court decision. On November 21, 2013, the NJBPU filed its notice of appeal of the October 25, 2013 Federal district court decision. On November 14, 2013, the Federal circuit court granted the motion to intervene and on December 13, 2013, the Federal circuit court issued an order consolidating the appeals filed by the NJBPU and the SOCA generating companies of the October 25, 2013 Federal district court decision. The matter has been placed on an expedited schedule and appeal proceedings remain pending. The Federal circuit court is tentatively scheduled to hear the appeal on March 27, 2014.
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.
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(7) PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment is comprised of the following:
The non-operating and other property amounts include balances for general plant, plant held for future use, intangible plant and non-utility property. Utility plant is generally subject to a first mortgage lien.
Jointly Owned Plant
ACE’s consolidated balance sheets include its proportionate share of assets and liabilities related to jointly owned plant. At December 31, 2013 and 2012, ACE’s subsidiaries had a net book value ownership interest of $8 million in transmission and other facilities in which various parties also have ownership interests. ACE’s share of the operating and maintenance expenses of the jointly-owned plant is included in the corresponding expenses in the consolidated statements of income. ACE is responsible for providing its share of the financing for the above jointly-owned facilities.
(8) PENSION AND OTHER POSTRETIREMENT BENEFITS
ACE accounts for its participation in its parent’s single-employer plans, Pepco Holdings’ non-contributory retirement plan (the PHI Retirement Plan) and the Pepco Holdings, Inc. Welfare Plan for Retirees (the PHI OPEB Plan), as participation in multiemployer plans. For 2013, 2012 and 2011, ACE was responsible for $17 million, $24 million and $21 million, respectively, of the pension and other postretirement net periodic benefit cost incurred by PHI. ACE made discretionary tax-deductible contributions to the PHI Retirement Plan of $30 million in each of the years ended December 31, 2013, 2012 and 2011. In addition, ACE made contributions of $6 million, $7 million and $7 million, respectively, to the PHI OPEB Plan for the years ended December 31, 2013, 2012 and 2011. At December 31, 2013 and 2012, ACE’s Prepaid pension expense of $106 million and $88 million, and Other postretirement benefit obligations of $35 million and $34 million, respectively, effectively represent assets and benefit obligations resulting from ACE’s participation in the PHI benefit plans.
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Other Postretirement Benefit Plan Amendments
During 2013, PHI approved two amendments to its other postretirement benefits plan. These amendments impacted the retiree health care and the retiree life insurance benefits, and were effective on January 1, 2014. As a result of the amendments, which were cumulatively significant, PHI remeasured its accumulated postretirement benefit obligation for other postretirement benefits as of July 1, 2013. The remeasurement resulted in a $2 million reduction in ACE’s net periodic benefit cost for other postretirement benefits in 2013. Approximately 42% of net periodic other postretirement benefit costs were capitalized in 2013.
(9) DEBT
Long-Term Debt
The components of long-term debt are shown in the table below:
(a) Represents a series of Collateral First Mortgage Bonds securing a series of medium term notes issued by ACE.
(b) Represents a series of Collateral First Mortgage Bonds (as defined herein) which must be cancelled and released as security for ACE’s obligations under the corresponding series of issuer notes (as defined herein) or tax-exempt bonds, at such time as ACE does not have any first mortgage bonds outstanding (other than its Collateral First Mortgage Bonds).
(c) Represents a series of Collateral First Mortgage Bonds securing a series of tax-exempt bonds issued for the benefit of ACE.
(d) Represents a series of Collateral First Mortgage Bonds which must be cancelled and released as security for ACE’s obligations under the corresponding series of issuer notes or tax-exempt bonds, at such time as ACE does not have any first mortgage bonds outstanding (other than its Collateral First Mortgage Bonds), except that ACE may not permit such release of collateral unless ACE substitutes comparable obligations for such collateral.
(e) Represents a series of Collateral First Mortgage Bonds securing a series of senior notes issued by ACE.
The outstanding first mortgage bonds issued by ACE are issued under a mortgage and deed of trust and are secured by a first lien on substantially all of ACE’s property, plant and equipment, except for certain property excluded from the lien of the mortgage.
Maturities of ACE’s long-term debt outstanding at December 31, 2013 are $107 million in 2014, $15 million in 2015, $2 million in 2016, zero in 2017, $250 million in 2018 and $487 million thereafter.
ACE’s long-term debt is subject to certain covenants. As of December 31, 2013, ACE was in compliance with all such covenants.
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The table above which does not separately identify $249 million in aggregate principal amount of senior notes and medium term notes (issuer notes) issued by ACE and $62 million in aggregate principal amount of tax-exempt bonds issued for the benefit of ACE. These issuer notes and tax-exempt bonds are secured by a like amount of first mortgage bonds (Collateral First Mortgage Bonds) of ACE. The principal terms of each such series of issuer notes, or ACE’s obligations in respect of each such series of tax-exempt bonds, are identical to the same terms of the corresponding series of Collateral First Mortgage Bonds. Payments of principal and interest made on a series of such issuer notes, or the satisfaction of ACE obligations in respect of a series of such tax-exempt bonds, satisfy the corresponding obligations on the related series of Collateral First Mortgage Bonds. For these reasons, each such series of Collateral First Mortgage Bonds and the corresponding issuer notes or tax-exempt bonds together effectively represent a single financial obligation and are not identified in the table above separately.
Bond Redemptions
During 2013, ACE repaid at maturity $69 million of its 6.63% non-callable first mortgage bonds. ACE also funded the redemption, prior to maturity, of $4 million of outstanding weekly variable rate pollution control revenue refunding bonds due 2017, issued by the Pollution Control Financing Authority of Salem County, New Jersey for ACE’s benefit.
Term Loan Agreement
On May 10, 2013, ACE entered into a $100 million term loan agreement, pursuant to which ACE has borrowed (and may not re-borrow) $100 million at a rate of interest equal to the prevailing Eurodollar rate, which is determined by reference to the London Interbank Offered Rate (LIBOR) with respect to the relevant interest period, all as defined in the loan agreement, plus a margin of 0.75%. ACE’s Eurodollar borrowings under the loan agreement may be converted into floating rate loans under certain circumstances, and, in that event, for so long as any loan remains a floating rate loan, interest would accrue on that loan at a rate per year equal to (i) the highest of (a) the prevailing prime rate, (b) the federal funds effective rate plus 0.5%, or (c) the one-month Eurodollar rate plus 1%, plus (ii) a margin of 0.75%. As of December 31, 2013, outstanding borrowings under the loan agreement bore interest at an annual rate of 0.92%, which is subject to adjustment from time to time. All borrowings under the loan agreement are unsecured, and the aggregate principal amount of all loans, together with any accrued but unpaid interest due under the loan agreement, must be repaid in full on or before November 10, 2014.
Under the terms of the term loan agreement, ACE must maintain compliance with specified covenants, including (i) the requirement that ACE maintain a ratio of total indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the loan agreement, which calculation excludes from the definition of total indebtedness certain trust preferred securities and deferrable interest subordinated debt (not to exceed 15% of total capitalization), (ii) a restriction on sales or other dispositions of assets, other than certain permitted sales and dispositions, and (iii) a restriction on the incurrence of liens (other than liens permitted by the loan agreement) on the assets of ACE. The loan agreement does not include any rating triggers. ACE was in compliance with all covenants under this loan agreement as of December 31, 2013.
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Transition Bonds Issued by ACE Funding
The components of transition bonds are shown in the table below:
For a description of the Transition Bonds, see Note (16), “Variable Interest Entities - ACE Funding.” Maturities of ACE’s Transition Bonds outstanding at December 31, 2013 are $41 million in 2014, $44 million in 2015, $46 million in 2016, $35 million in 2017, $31 million in 2018 and $58 million thereafter.
Short-Term Debt
ACE has traditionally used a number of sources to fulfill short-term funding needs, such as commercial paper, short-term notes, and bank lines of credit. Proceeds from short-term borrowings are used primarily to meet working capital needs, but may also be used to temporarily fund long-term capital requirements. The components of ACE’s short-term debt at December 31, 2013 and 2012 are as follows:
Commercial Paper
ACE maintains an ongoing commercial paper program to address its short-term liquidity needs. As of December 31, 2013, the maximum capacity available under the program was $350 million, subject to available borrowing capacity under the credit facility.
ACE had $120 million and $110 million of commercial paper outstanding at December 31, 2013 and 2012, respectively. The weighted average interest rates for commercial paper issued by ACE during 2013 and 2012 were 0.31% and 0.41%, respectively. The weighted average maturity of all commercial paper issued by ACE during 2013 and 2012 was four days and three days, respectively.
Variable Rate Demand Bonds
Variable Rate Demand Bonds (VRDBs) are subject to repayment on the demand of the holders and, for this reason, are accounted for as short-term debt in accordance with GAAP. However, bonds submitted for purchase are remarketed by a remarketing agent on a best efforts basis. ACE expects that any bonds submitted for purchase will be remarketed successfully due to the creditworthiness of the company and because the remarketing resets the interest rate to the then-current market rate. The bonds may be converted to a fixed rate, fixed term option to establish a maturity which corresponds to the date of final maturity of the bonds. On this basis, ACE views VRDBs as a source of long-term financing. As of December 31, 2013, $18 million of VRDBs issued on behalf of ACE were outstanding. The outstanding VRDBs all mature in 2014. The weighted average interest rate for VRDBs was 0.11% and 0.18% during 2013 and 2012, respectively.
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Credit Facility
PHI, Pepco, DPL and ACE maintain an unsecured syndicated credit facility to provide for their respective liquidity needs, including obtaining letters of credit, borrowing for general corporate purposes and supporting their commercial paper programs. On August 1, 2011, PHI, Pepco, DPL and ACE entered into an amended and restated credit agreement which, on August 2, 2012, was amended to extend the term of the credit facility to August 1, 2017 and to amend the pricing schedule to decrease certain fees and interest rates payable to the lenders under the facility. On August 1, 2013, as permitted under the existing terms of the credit agreement, a request by PHI, Pepco, DPL and ACE to extend the credit facility termination date to August 1, 2018 was approved. All of the terms and conditions as well as pricing remained the same.
The aggregate borrowing limit under the amended and restated credit facility is $1.5 billion, all or any portion of which may be used to obtain loans and up to $500 million of which may be used to obtain letters of credit. The facility also includes a swingline loan sub-facility, pursuant to which each company may make same day borrowings in an aggregate amount not to exceed 10% of the total amount of the facility. Any swingline loan must be repaid by the borrower within fourteen days of receipt. The credit sublimit is $750 million for PHI and $250 million for each of Pepco, DPL and ACE. The sublimits may be increased or decreased by the individual borrower during the term of the facility, except that (i) the sum of all of the borrower sublimits following any such increase or decrease must equal the total amount of the facility, and (ii) the aggregate amount of credit used at any given time by (a) PHI may not exceed $1.25 billion, and (b) each of Pepco, DPL or ACE may not exceed the lesser of $500 million or the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of the sublimit reallocations may not exceed eight per year during the term of the facility.
The interest rate payable by each company on utilized funds is, at the borrowing company’s election, (i) the greater of the prevailing prime rate, the federal funds effective rate plus 0.5% and the one month LIBOR plus 1.0%, or (ii) the prevailing Eurodollar rate, plus a margin that varies according to the credit rating of the borrower.
In order for a borrower to use the facility, certain representations and warranties must be true and correct, and the borrower must be in compliance with specified financial and other covenants, including (i) the requirement that each borrowing company maintain a ratio of total indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the credit agreement, which calculation excludes from the definition of total indebtedness certain trust preferred securities and deferrable interest subordinated debt (not to exceed 15% of total capitalization), (ii) with certain exceptions, a restriction on sales or other dispositions of assets, and (iii) a restriction on the incurrence of liens on the assets of a borrower or any of its significant subsidiaries other than permitted liens. The credit agreement contains certain covenants and other customary agreements and requirements that, if not complied with, could result in an event of default and the acceleration of repayment obligations of one or more of the borrowers thereunder. Each of the borrowers was in compliance with all covenants under this facility at December 31, 2013.
The absence of a material adverse change in PHI’s business, property, results of operations or financial condition is not a condition to the availability of credit under the credit agreement. The credit agreement does not include any rating triggers.
As of December 31, 2013 and 2012, the amount of cash plus borrowing capacity under the credit facility available to meet the liquidity needs of PHI’s utility subsidiaries in the aggregate was $332 million and $477 million, respectively. ACE’s borrowing capacity under the credit facility at any given time depends on the amount of the subsidiary borrowing capacity being utilized by Pepco and DPL and the portion of the total capacity being used by PHI.
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(10) INCOME TAXES
ACE, as an indirect subsidiary of PHI, is included in the consolidated federal income tax return of PHI. Federal income taxes are allocated to ACE pursuant to a written tax sharing agreement that was approved by the Securities and Exchange Commission in connection with the establishment of PHI as a holding company. Under this tax sharing agreement, PHI’s consolidated federal income tax liability is allocated based upon PHI’s and its subsidiaries’ separate taxable income or loss.
The provision for consolidated income taxes, reconciliation of consolidated income tax expense, and components of consolidated deferred income tax liabilities (assets) are shown below.
Provision for Consolidated Income Taxes
Reconciliation of Consolidated Income Tax Expense
Year ended December 31, 2013
ACE’s consolidated effective income tax rate for the year ended December 31, 2013 of 27.5% includes income tax benefits totaling $9 million related to uncertain and effectively settled tax positions.
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On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit issued an opinion in Consolidated Edison Company of New York, Inc. & Subsidiaries v. United States (to which ACE is not a party) that disallowed tax benefits associated with Consolidated Edison’s cross-border lease transaction. As a result of the court’s ruling in this case, PHI determined in the first quarter of 2013 that it could no longer support its current assessment with respect to the likely outcome of tax positions associated with its cross-border energy lease investments held by its wholly-owned subsidiary Potomac Capital Investment Corporation, and PHI recorded an after-tax charge of $377 million in the first quarter of 2013. Included in the $377 million charge was an after-tax interest charge of $54 million and this amount was allocated to each member of PHI’s consolidated group as if each member was a separate taxpayer, resulting in ACE recording a $6 million interest benefit in the first quarter of 2013.
Year ended December 31, 2012
ACE’s consolidated effective income tax rate for the year ended December 31, 2012 of 34.0% reflects a $1 million benefit associated with the effective settlement with the Internal Revenue Service (IRS) with respect to the methodology used historically to calculate deductible mixed service costs.
Year ended December 31, 2011
ACE’s consolidated effective income tax rate for the year ended December 31, 2011 of 45.8% includes a charge totaling $5 million related to uncertain and effectively settled tax positions.
During 2011, PHI reached a settlement with the IRS with respect to interest due on its federal tax liabilities related to the November 2010 audit settlement for years 1996 through 2002. In connection with this agreement, PHI reallocated certain amounts that have been on deposit with the IRS since 2006 among liabilities in the settlement years and subsequent years. Primarily related to the settlement and reallocations, ACE has recorded a $1 million (after-tax) interest charge in the second quarter of 2011. Additionally, in the third quarter of 2011, ACE recorded a $3 million (after-tax) interest charge related to the recalculation of interest on its uncertain tax positions for open tax years using different assumptions related to the application of its deposit made with the IRS in 2006.
Components of Consolidated Deferred Income Tax Liabilities (Assets)
The net deferred tax liability represents the tax effect, at presently enacted tax rates, of temporary differences between the financial statement basis and tax basis of assets and liabilities. The portion of the net deferred tax liability applicable to ACE’s operations, which has not been reflected in current service rates, represents income taxes recoverable through future rates, net, and is recorded as a regulatory asset on the balance sheet. No valuation allowance for deferred tax assets was required or recorded at December 31, 2013 and 2012. Federal and State net operating losses generally expire over 20 years from 2029 to 2032.
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The Tax Reform Act of 1986 repealed the investment tax credit for property placed in service after December 31, 1985, except for certain transition property. Investment tax credits previously earned on ACE’s property continue to be amortized to income over the useful lives of the related property.
Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits
(a) These reductions of unrecognized tax benefits in 2012 primarily relate to a resolution reached with the IRS for determining deductible mixed service costs for additions to property, plant and equipment.
Unrecognized Benefits That, If Recognized, Would Affect the Effective Tax Rate
Unrecognized tax benefits are related to tax positions that have been taken or are expected to be taken in tax returns that are not recognized in the financial statements because management has either measured the tax benefit at an amount less than the benefit claimed, or expected to be claimed, or has concluded that it is not more likely than not that the tax position will be ultimately sustained. For the majority of these tax positions, the ultimate deductibility is highly certain, but there is uncertainty about the timing of such deductibility. At December 31, 2013, ACE had no unrecognized tax benefits that, if recognized, would lower the effective tax rate.
Interest and Penalties
ACE recognizes interest and penalties relating to its uncertain tax positions as an element of income tax expense. For the years ended December 31, 2013, 2012 and 2011, ACE recognized $12 million of pre-tax interest income ($7 million after-tax), $2 million of pre-tax interest income ($1 million after-tax), and $5 million of pre-tax interest expense ($3 million after-tax), respectively, as a component of income tax expense. As of December 31, 2013, 2012 and 2011, ACE had accrued interest receivable of $14 million, $7 million and $6 million, respectively, related to effectively settled and uncertain tax positions.
Possible Changes to Unrecognized Tax Benefits
It is reasonably possible that the amount of the unrecognized tax benefit with respect to some of ACE’s uncertain tax positions will significantly increase or decrease within the next 12 months. PHI and its subsidiaries have entered into discussions with the IRS with the intention of seeking a settlement of all tax issues of ACE for open tax years 2001 through 2011. PHI currently believes that it is possible that a settlement with the IRS may be reached in 2014, which could significantly impact the balances of unrecognized tax benefits and the related interest accruals of ACE. At this time, it is estimated that there will be a $4 million to $6 million decrease in unrecognized tax benefits within the next 12 months.
Tax Years Open to Examination
ACE, as an indirect subsidiary of PHI, is included on PHI’s consolidated Federal tax return. ACE’s federal income tax liabilities for all years through 2002 have been determined, subject to adjustment to the extent of any net operating loss or other loss or credit carrybacks from subsequent years. The open tax years for the significant states where ACE files state income tax returns (New Jersey and Pennsylvania) are the same as for the Federal returns. As a result of the final determination of these years, ACE filed amended state returns receiving $1 million in refunds.
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Final IRS Regulations on Repair of Tangible Property
In September 2013, the IRS issued final regulations on expense versus capitalization of repairs with respect to tangible personal property. The regulations are effective for tax years beginning on or after January 1, 2014, and provide an option to early adopt the final regulations for tax years beginning on or after January 1, 2012. It is expected that the IRS will issue revenue procedures that will describe how taxpayers may implement the final regulations. The final repair regulations retain the operative rule that the Unit of Property for network assets is determined by the taxpayer’s particular facts and circumstances except as provided in published guidance. In 2012, with the filing of its 2011 tax return, PHI filed a request for an automatic change in accounting method related to repairs of its network assets in accordance with IRS Revenue Procedure 2011-43. ACE does not expect the effects of the final regulations to be significant and will continue to evaluate the impact of the new guidance on its consolidated financial statements.
Other Taxes
Taxes other than income taxes for each year are shown below. These amounts are recoverable through rates.
(11) DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
ACE was ordered to enter into the SOCAs by the NJBPU, and under the SOCAs, ACE would have received payments from or made payments to electric generation facilities based on (i) the difference between the fixed price in the SOCAs and the price for capacity that clears PJM and (ii) ACE’s annual proportion of the total New Jersey load relative to the other EDCs in New Jersey. ACE began applying derivative accounting to two of its SOCAs as of June 30, 2012 because these generators cleared the 2015-2016 PJM capacity auction in May 2012. The fair value of the derivatives embedded in the SOCAs were deferred as Regulatory assets or Regulatory liabilities because the NJBPU allowed full recovery from ACE’s distribution customers for any payments made by ACE, and ACE’s distribution customers would be entitled to any payments received by ACE.
As further discussed in Note (6), “Regulatory Matters,” in light of a Federal district court order, which ruled that the SOCAs are void, invalid and unenforceable, and ACE’s subsequent termination of the SOCAs in the fourth quarter of 2013, ACE derecognized the derivative assets and derivative liabilities related to the SOCAs in the fourth quarter of 2013.
As of December 31, 2012, ACE had non-current Derivative assets of $8 million, and non-current Derivative liabilities of $11 million associated with the two SOCAs and offsetting Regulatory liability and Regulatory asset amounts, respectively. As of December 31, 2012, ACE had 180 megawatts (MWs) of capacity in a long position, with no collateral or netting applicable to the capacity. Unrealized gains and losses associated with these capacity derivatives, which netted to unrealized gains of $3 million and unrealized losses of $3 million for the years ended December 31, 2013 and 2012, respectively, have been deferred as Regulatory liabilities and Regulatory assets.
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(12) FAIR VALUE DISCLOSURES
Financial Instruments Measured at Fair Value on a Recurring Basis
ACE applies FASB guidance on fair value measurement and disclosures (ASC 820) that established a framework for measuring fair value and expanded disclosures about fair value measurements. As defined in the guidance, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). ACE utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. Accordingly, ACE utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1) and the lowest priority to unobservable inputs (level 3).
The following tables set forth by level within the fair value hierarchy ACE’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2013 and 2012. As required by the guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. ACE’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.
(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2013.
(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2012.
(b) The fair value of derivative assets and liabilities reflect netting by counterparty before the impact of collateral.
(c) Represents derivatives associated with ACE SOCAs.
ACE
ACE classifies its fair value balances in the fair value hierarchy based on the observability of the inputs used in the fair value calculation as follows:
Level 1 - Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2 - Pricing inputs are other than quoted prices in active markets included in level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using broker quotes in liquid markets and other observable data. Level 2 also includes those financial instruments that are valued using methodologies that have been corroborated by observable market data through correlation or by other means. Significant assumptions are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.
The level 2 liability associated with the life insurance policies represents a deferred compensation obligation, the value of which is tracked via underlying insurance sub-accounts. The sub-accounts are designed to mirror existing mutual funds and money market funds that are observable and actively traded.
Level 3 - Pricing inputs that are significant and generally less observable than those from objective sources. Level 3 includes those financial instruments that are valued using models or other valuation methodologies.
Derivative instruments categorized as level 3 represent capacity under the SOCAs entered into by ACE.
ACE used a discounted cash flow methodology to estimate the fair value of the capacity derivatives embedded in the SOCAs. ACE utilized an external consulting firm to estimate annual zonal PJM capacity prices through the 2030-2031 auction. The capacity price forecast was based on various assumptions that impact the cost of constructing new generation facilities, including zonal load forecasts, zonal fuel and energy prices, generation capacity and transmission planning, and environmental legislation and regulation. ACE reviewed the assumptions and resulting capacity price forecast for reasonableness. ACE used the capacity price forecast to estimate future cash flows. A significant change in the forecasted prices would have a significant impact on the estimated fair value of the SOCAs. ACE employed a discount rate reflective of the estimated weighted average cost of capital for merchant generation companies since payments under the SOCAs are contingent on providing generation capacity. As further discussed in Note (6), “Regulatory Matters,” ACE derecognized the derivative assets and derivative liabilities related to the SOCAs in the fourth quarter of 2013.
The table below summarizes the primary unobservable input used to determine the fair value of ACE’s level 3 instruments and the range of values that could be used for the input as of December 31, 2012:
ACE used a value within this range as part of its fair value estimates. A significant change in the unobservable input within this range would have an insignificant impact on the reported fair value as of December 31, 2012.
ACE
A reconciliation of the beginning and ending balances of ACE’s fair value measurements using significant unobservable inputs (level 3) for the years ended December 31, 2013 and 2012 are shown below:
Other Financial Instruments
The estimated fair values of ACE’s Long-term debt instruments that are measured at amortized cost in ACE’s consolidated financial statements and the associated level of the estimates within the fair value hierarchy as of December 31, 2013 and 2012 are shown in the table below. As required by the fair value measurement guidance, debt instruments are classified in their entirety within the fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. ACE’s assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, which may affect the valuation of fair value debt instruments and their placement within the fair value hierarchy levels.
The fair value of Long-term debt and Transition Bonds categorized as level 2 is based on a blend of quoted prices for the debt and quoted prices for similar debt on the measurement date. The blend places more weight on current pricing information when determining the final fair value measurement. The fair value information is provided by brokers and ACE reviews the methodologies and results.
The fair value of Long-term debt categorized as level 3 is based on a discounted cash flow methodology using observable inputs, such as the U.S. Treasury yield, and unobservable inputs, such as credit spreads, because quoted prices for the debt or similar debt in active markets were insufficient.
(a) The carrying amount for Long-term debt is $860 million as of December 31, 2013.
(b) The carrying amount for Transition Bonds, including amounts due within one year, is $255 million as of December 31, 2013.
ACE
(a) The carrying amount for Long-term debt is $829 million as of December 31, 2012.
(b) The carrying amount for Transition Bonds, including amounts due within one year, is $295 million as of December 31, 2012.
The carrying amounts of all other financial instruments in the accompanying consolidated financial statements approximate fair value.
(13) COMMITMENTS AND CONTINGENCIES
General Litigation
From time to time, ACE is named as a defendant in litigation, usually relating to general liability or auto liability claims that resulted in personal injury or property damage to third parties. ACE is self-insured against such claims up to a certain self-insured retention amount and maintains insurance coverage against such claims at higher levels, to the extent deemed prudent by management. In addition, ACE’s contracts with its vendors generally require the vendors to name ACE as an additional insured for the amount at least equal to ACE’s self-insured retention. Further, ACE’s contracts with its vendors require the vendors to indemnify ACE for various acts and activities that may give rise to claims against ACE. Loss contingency liabilities for both asserted and unasserted claims are recognized if it is probable that a loss will result from such a claim and if the amounts of the losses can be reasonably estimated. Although the outcome of the claims and proceedings cannot be predicted with any certainty, management believes that there are no existing claims or proceedings that are likely to have a material adverse effect on ACE’s financial condition, results of operations or cash flows. At December 31, 2013, ACE had loss contingency liabilities for general litigation totaling approximately $9 million (including amounts related to the matters specifically described below) and the portion of these loss contingency liabilities in excess of the self-insured retention amount was substantially offset by insurance receivables.
Asbestos Claim
In September 2011, an asbestos complaint was filed in the New Jersey Superior Court, Law Division, against ACE (among other defendants) asserting claims under New Jersey’s Wrongful Death and Survival statutes. The complaint, filed by the estate of a decedent who was the wife of a former employee of ACE, alleges that the decedent’s mesothelioma was caused by exposure to asbestos brought home by her husband on his work clothes. New Jersey courts have recognized a cause of action against a premise owner in a so-called “take home” case if it can be shown that the harm was foreseeable. In this case, the complaint seeks recovery of an unspecified amount of damages for, among other things, the decedent’s past medical expenses, loss of earnings, and pain and suffering between the time of injury and death, and asserts a punitive damage claim. At December 31, 2013, ACE has concluded that a loss is probable with respect to this matter and has recorded an estimated loss contingency liability, which is included in the liability for general litigation referred to above as of December 31, 2013. However, due to the inherent uncertainty of litigation, ACE is unable to estimate a maximum amount of possible loss because the damages sought are indeterminate and the matter involves facts that ACE believes are distinguishable from the facts of the “take-home” cause of action recognized by the New Jersey courts.
ACE
Electrical Contact Injury Claims
In October 2010, a farm combine came into and remained in contact with a primary electric line in ACE’s service territory in New Jersey. As a result, two individuals operating the combine received fatal electrical contact injuries. While attempting to rescue those two individuals, another individual sustained third-degree burns to his torso and upper extremities. In September 2012, the individual who received third-degree burns filed suit in New Jersey Superior Court, Salem County. In October 2012, additional suits were filed in the same court by or on behalf of the estates of the deceased individuals. Plaintiffs in each of the cases are seeking indeterminate damages and allege that ACE was negligent in the design, construction, erection, operation and maintenance of its poles, power lines, and equipment, and that ACE failed to warn and protect the public from the foreseeable dangers of farm equipment contacting electric lines. Discovery is ongoing in this matter and the litigation involves a number of other defendants and the filing of numerous cross-claims. ACE has notified its insurers of the incident and believes that the insurance policies in force at the time of the incident will offset ACE’s costs associated with the resolution of this matter in excess of ACE’s self-insured retention amount. At December 31, 2013, ACE has concluded that a loss is probable with respect to these claims and has recorded an estimated loss contingency liability, which is included in the liability for general litigation referred to above as of December 31, 2013. ACE has also concluded as of December 31, 2013 that realization of its insurance claims associated with this matter is probable and, accordingly, has recorded an estimated insurance receivable offsetting substantially all of the loss contingency liability in excess of ACE’s self-insured retention amount.
Environmental Matters
ACE is subject to regulation by various federal, regional, state and local authorities with respect to the environmental effects of its operations, including air and water quality control, solid and hazardous waste disposal and limitations on land use. Although penalties assessed for violations of environmental laws and regulations are not recoverable from customers of ACE, environmental clean-up costs incurred by ACE generally are included in its cost of service for ratemaking purposes. The total accrued liabilities for the environmental contingencies of ACE described below at December 31, 2013 are summarized as follows:
Franklin Slag Pile Site
In November 2008, ACE received a general notice letter from the U.S. Environmental Protection Agency (EPA) concerning the Franklin Slag Pile site in Philadelphia, Pennsylvania, asserting that ACE is a potentially responsible party (PRP) that may have liability for clean-up costs with respect to the site and for the costs of implementing an EPA-mandated remedy. EPA’s claims are based on ACE’s sale of boiler slag from the B.L. England generating facility, then owned by ACE, to MDC Industries, Inc. (MDC) during the period June 1978 to May 1983. EPA claims that the boiler slag ACE sold to MDC contained copper and lead, which are hazardous substances under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA), and that the sales transactions may have constituted an arrangement for the disposal or treatment of hazardous substances at the site, which could be a basis for liability under CERCLA. The EPA letter also states that, as of the date of the letter, EPA’s expenditures for response measures at the site have exceeded $6 million. EPA’s feasibility study for this site conducted in 2007 identified a range of alternatives for permanent remedial measures with varying cost estimates, and the estimated cost of EPA’s preferred alternative is approximately $6 million.
ACE
ACE believes that the B.L. England boiler slag sold to MDC was a valuable material with various industrial applications and, therefore, the sale was not an arrangement for the disposal or treatment of any hazardous substances as would be necessary to constitute a basis for liability under CERCLA. ACE intends to contest any claims to the contrary made by EPA. In a May 2009 decision arising under CERCLA, which did not involve ACE, the U.S. Supreme Court rejected an EPA argument that the sale of a useful product constituted an arrangement for disposal or treatment of hazardous substances. While this decision supports ACE’s position, at this time ACE cannot predict how EPA will proceed with respect to the Franklin Slag Pile site, or what portion, if any, of the Franklin Slag Pile site response costs EPA would seek to recover from ACE. Costs to resolve this matter are not expected to be material and are expensed as incurred.
Ward Transformer Site
In April 2009, a group of PRPs with respect to the Ward Transformer site in Raleigh, North Carolina, filed a complaint in the U.S. District Court for the Eastern District of North Carolina, alleging cost recovery and/or contribution claims against a number of entities, including ACE, based on its alleged sale of transformers to Ward Transformer, with respect to past and future response costs incurred by the PRP group in performing a removal action at the site. In a March 2010 order, the court denied the defendants’ motion to dismiss. The litigation is moving forward with certain “test case” defendants (not including ACE) filing summary judgment motions regarding liability. The case has been stayed as to the remaining defendants pending rulings upon the test cases. In a January 31, 2013 order, the Federal district court granted summary judgment for the test case defendant whom plaintiffs alleged was liable based on its sale of transformers to Ward Transformer. The Federal district court’s order, which plaintiffs have appealed to the U.S. Court of Appeals for the Fourth Circuit, addresses only the liability of the test case defendant. ACE has concluded that a loss is reasonably possible with respect to this matter, but is unable to estimate an amount or range of reasonably possible losses to which it may be exposed. ACE does not believe that it had extensive business transactions, if any, with the Ward Transformer site.
Contractual Obligations
Power Purchase Contracts
As of December 31, 2013, ACE’s contractual obligations under non-derivative power purchase contracts were $214 million in 2014, $431 million in 2015 to 2016, $355 million in 2017 to 2018 and $1,086 million in 2019 and thereafter.
Lease Commitments
ACE leases certain types of property and equipment for use in its operations. Rental expense for operating leases was $12 million, $11 million and $10 million for the years ended December 31, 2013, 2012 and 2011, respectively.
Total future minimum operating lease payments for ACE as of December 31, 2013 are $5 million in each of the years 2014 through 2016, $4 million in each of the years 2017 and 2018, and $29 million thereafter.
(14) RELATED PARTY TRANSACTIONS
PHI Service Company provides various administrative and professional services to PHI and its regulated and unregulated subsidiaries, including ACE. The cost of these services is allocated in accordance with cost allocation methodologies set forth in the service agreement using a variety of factors, including the subsidiaries’ share of employees, operating expenses, assets and other cost methods. These intercompany transactions are eliminated by PHI in consolidation and no profit results from these transactions at PHI. PHI Service Company costs directly charged or allocated to ACE for the years ended December 31, 2013, 2012 and 2011 were $115 million, $117 million and $102 million, respectively.
ACE
In addition to the PHI Service Company charges described above, ACE’s consolidated financial statements include the following related party transactions in its consolidated statements of income:
(a) Included in Other operation and maintenance expense.
(b) Included in Operating revenue.
As of December 31, 2013 and 2012, ACE had the following balances on its consolidated balance sheets due to related parties:
(a) Included in Accounts payable due to associated companies.
During 2011, PHI, through Conectiv, LLC, made a $60 million capital contribution to ACE.
(15) QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
The quarterly data presented below reflect all adjustments necessary, in the opinion of management, for a fair presentation of the interim results. Quarterly data normally vary seasonally because of temperature variations and differences between summer and winter rates. Therefore, comparisons by quarter within a year are not meaningful.
ACE
(16) VARIABLE INTEREST ENTITIES
ACE is required to consolidate a variable interest entity (VIE) in accordance with FASB ASC 810 if ACE or a subsidiary is the primary beneficiary of the VIE. The primary beneficiary of a VIE is typically the entity with both the power to direct activities most significantly impacting economic performance of the VIE and the obligation to absorb losses or receive benefits of the VIE that could potentially be significant to the VIE. ACE performed a qualitative analysis to determine whether a variable interest provided a controlling financial interest in a VIE at December 31, 2013, which is described below.
ACE Power Purchase Agreements
ACE is a party to three power purchase agreements (PPAs) with unaffiliated NUGs totaling 459 MWs. One of the agreements ends in 2016 and the other two end in 2024. ACE was not involved in the creation of these contracts and has no equity or debt invested in these entities. In performing its VIE analysis, ACE has been unable to obtain sufficient information to determine whether these three entities were variable interest entities or if ACE was the primary beneficiary. As a result, ACE has applied the scope exemption from the consolidation guidance.
Because ACE has no equity or debt invested in the NUGs, the maximum exposure to loss relates primarily to any above-market costs incurred for power. Due to unpredictability in the PPAs pricing for purchased energy, ACE is unable to quantify the maximum exposure to loss. The power purchase costs are recoverable from ACE’s customers through regulated rates. Purchase activities with the NUGs, including excess power purchases not covered by the PPAs, for the years ended December 31, 2013, 2012 and 2011 were approximately $221 million, $206 million and $218 million, respectively, of which approximately $206 million, $201 million and $206 million, respectively, consisted of power purchases under the PPAs.
ACE Funding
In 2001, ACE established ACE Funding solely for the purpose of securitizing authorized portions of ACE’s recoverable stranded costs through the issuance and sale of Transition Bonds. The proceeds of the sale of each series of Transition Bonds were transferred to ACE in exchange for the transfer by ACE to ACE Funding of the right to collect a non-bypassable Transition Bond Charge from ACE customers pursuant to bondable stranded costs rate orders issued by the NJBPU in an amount sufficient to fund the principal and interest payments on the Transition Bonds and related taxes, expenses and fees (Bondable Transition Property). The assets of ACE Funding, including the Bondable Transition Property, and the Transition Bond Charges (representing revenue ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds and related taxes, expenses and fees) collected from ACE’s customers, are not available to creditors of ACE. The holders of Transition Bonds have recourse only to the assets of ACE Funding. ACE owns 100 percent of the equity of ACE Funding and consolidates ACE Funding in its consolidated financial statements as ACE is the primary beneficiary of ACE Funding under the variable interest entity consolidation guidance.
Item 9.
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
Pepco Holdings, Inc.
None.
Potomac Electric Power Company
None.
Delmarva Power & Light Company
None.
Atlantic City Electric Company
None.
Item 9A.
Item 9A. CONTROLS AND PROCEDURES
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
Each Reporting Company maintains disclosure controls and procedures that are designed to ensure that information required to be disclosed in such Reporting Company’s reports under the Exchange Act, is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC, and that such information is accumulated and communicated to management of such Reporting Company, including such Reporting Company’s Chief Executive Officer (CEO) and Chief Financial Officer (CFO), as appropriate, to allow timely decisions regarding required disclosure. This control system, no matter how well designed and operated, can provide only reasonable assurance that the objectives of the control system are met. Such Reporting Company’s disclosure controls and procedures were designed to provide reasonable assurance of achieving their stated objectives. Under the supervision, and with the participation of management, including the CEO and the CFO, each Reporting Company has evaluated the effectiveness of the design and operation of its disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of December 31, 2013, and, based upon this evaluation, the CEO and the CFO of such Reporting Company have concluded that these disclosure controls and procedures are effective to provide reasonable assurance that material information relating to such Reporting Company and its subsidiaries that is required to be disclosed in reports filed with, or submitted to, the SEC under the Exchange Act (i) is recorded, processed, summarized and reported within the time periods specified by the SEC rules and forms and (ii) is accumulated and communicated to management, including its CEO and CFO, as appropriate to allow timely decisions regarding required disclosure.
Management’s Annual Report on Internal Control Over Financial Reporting
See “Management’s Report on Internal Control over Financial Reporting” with respect to each Reporting Company.
Attestation Report of the Registered Public Accounting Firm
The “Report of Independent Registered Public Accounting Firm” with respect to the attestation report of PHI’s registered public accounting firm is hereby incorporated by reference in response to this Item 9A.
The Dodd-Frank Wall Street Reform and Consumer Protection Act enacted on July 21, 2010, exempts any company that is not a “large accelerated filer” or an “accelerated filer” (as defined by SEC rules) from the requirement that such company obtain an external audit of the effectiveness of its internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act. As a result, each of Pepco, DPL and ACE is exempt from the requirement that it include in its Annual Report on Form 10-K an attestation report on internal control over financial reporting by an independent registered public accounting firm; however, management’s annual report on internal control over financial reporting, pursuant to Section 404(a) of the Sarbanes-Oxley Act, is still required with respect to each of them.
Reports of Changes in Internal Control Over Financial Reporting
Under the supervision and with the participation of management, including the CEO and CFO of each Reporting Company, each such Reporting Company has evaluated changes in internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the three months ended December 31, 2013, and has concluded there was no change in such Reporting Company’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, such Reporting Company’s internal control over financial reporting.
Item 9B.
Item 9B. OTHER INFORMATION
Pepco Holdings, Inc.
None.
Potomac Electric Power Company
None.
Delmarva Power & Light Company
None.
Atlantic City Electric Company
None.
Part III
Item 10.
Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Pepco Holdings, Inc.
Information required by this Item 10 is incorporated herein by reference to (1) PHI’s definitive proxy statement for its 2014 Annual Meeting of Stockholders, which is expected to be filed with the SEC no later than 120 days after December 31, 2013, and (2) the section entitled “Executive Officers of PHI” contained in Part I, Item 1. “Business,” of this Form 10-K.
INFORMATION FOR THIS ITEM IS NOT REQUIRED FOR PEPCO, DPL AND ACE AS THEY MEET THE CONDITIONS SET FORTH IN GENERAL INSTRUCTIONS I(1)(a) AND (b) OF FORM 10-K AND THEREFORE ARE FILING THIS FORM WITH THE REDUCED FILING FORMAT.
Item 11.
Item 11. EXECUTIVE COMPENSATION
Pepco Holdings, Inc.
Information required by this Item 11 is incorporated herein by reference to PHI’s definitive proxy statement for its 2014 Annual Meeting of Stockholders, which is expected to be filed with the SEC no later than 120 days after December 31, 2013.
INFORMATION FOR THIS ITEM IS NOT REQUIRED FOR PEPCO, DPL AND ACE AS THEY MEET THE CONDITIONS SET FORTH IN GENERAL INSTRUCTIONS I(1)(a) AND (b) OF FORM 10-K AND THEREFORE ARE FILING THIS FORM WITH THE REDUCED FILING FORMAT.
Item 12.
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Pepco Holdings, Inc.
Information required by this Item 12 is incorporated herein by reference to PHI’s definitive proxy statement for its 2014 Annual Meeting of Stockholders, which is expected to be filed with the SEC no later than 120 days after December 31, 2013.
INFORMATION FOR THIS ITEM IS NOT REQUIRED FOR PEPCO, DPL AND ACE AS THEY MEET THE CONDITIONS SET FORTH IN GENERAL INSTRUCTIONS I(1)(a) AND (b) OF FORM 10-K AND THEREFORE ARE FILING THIS FORM WITH THE REDUCED FILING FORMAT.
Item 13.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Pepco Holdings, Inc.
Information required by this Item 13 is incorporated herein by reference to PHI’s definitive proxy statement for its 2014 Annual Meeting of Stockholders, which is expected to be filed with the SEC no later than 120 days after December 31, 2013.
INFORMATION FOR THIS ITEM IS NOT REQUIRED FOR PEPCO, DPL AND ACE AS THEY MEET THE CONDITIONS SET FORTH IN GENERAL INSTRUCTIONS I(1)(a) AND (b) OF FORM 10-K AND THEREFORE ARE FILING THIS FORM WITH THE REDUCED FILING FORMAT.
Item 14.
Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Pepco Holdings, Pepco, DPL and ACE
Audit Fees
The aggregate fees billed by PricewaterhouseCoopers LLP for professional services rendered for the audit of the annual financial statements of Pepco Holdings and its subsidiary reporting companies for the 2013 and 2012 fiscal years, reviews of the financial statements included in the 2013 and 2012 Forms 10-Q of Pepco Holdings and its subsidiary reporting companies, reviews of other public filings, comfort letters and other attest services were $6,180,416 and $6,140,106, respectively. The amount for 2012 includes a reduction of $65,564 to reflect actual invoices received that were less than the estimated invoices included within the 2012 audit amount that was disclosed in Pepco Holdings’ proxy statement for the 2013 Annual Meeting of Stockholders.
Audit-Related Fees
The aggregate fees billed by PricewaterhouseCoopers LLP for audit-related services rendered for the 2013 and 2012 fiscal years were $497,177 and zero, respectively. The 2013 fees consist of amounts billed in connection with advice and recommendations related to financial and accounting systems implementation, and for attest services performed in connection with public service commission rate case filings.
Tax Fees
The aggregate fees billed by PricewaterhouseCoopers LLP for tax services rendered for the 2013 and 2012 fiscal years were $1,292,685 and $644,012, respectively. These services generally consisted of tax compliance, tax advice and tax planning. In addition, the amount for the 2013 fiscal year included $560,236 in fees for assistance with issues related to the evaluation of potential settlement scenarios with respect to the former cross-border energy lease investments.
All Other Fees
The aggregate fees billed by PricewaterhouseCoopers LLP for all other services other than those covered under “Audit Fees,” “Audit-Related Fees” and “Tax Fees” were $7,200 for each of the 2013 and 2012 fiscal years. These fees for 2013 and 2012 represented the costs of an online accounting and financial reporting research tool.
All of the services described in “Audit Fees,” “Audit-Related Fees,” “Tax Fees” and “All Other Fees” were approved in advance by the Audit Committee, in accordance with the Audit Committee Policy on the Approval of Services Provided By the Independent Auditor, which will be attached as Annex A to Pepco Holdings’ definitive proxy statement for the 2014 Annual Meeting of Stockholders, which is expected to be filed with the SEC no later than 120 days after December 31, 2013, and is incorporated herein by reference.
Part IV
Item 15.
Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) Documents List
1. Financial Statements
Pepco Holdings, Inc.
Consolidated Statements of (Loss) Income for each of the years ended December 31, 2013, 2012 and 2011
Consolidated Statements of Comprehensive (Loss) Income for each of the years ended December 31, 2013, 2012 and 2011
Consolidated Balance Sheets as of December 31, 2013 and 2012
Consolidated Statements of Cash Flows for each of the years ended December 31, 2013, 2012 and 2011
Consolidated Statements of Equity for each of the years ended December 31, 2013, 2012 and 2011
Notes to Consolidated Financial Statements
Potomac Electric Power Company
Statements of Income for each of the years ended December 31, 2013, 2012 and 2011
Balance Sheets as of December 31, 2013 and 2012
Statements of Cash Flows for each of the years ended December 31, 2013, 2012 and 2011
Statements of Equity for each of the years ended December 31, 2013, 2012 and 2011
Notes to Financial Statements
Delmarva Power & Light Company
Statements of Income for each of the years ended December 31, 2013, 2012 and 2011
Balance Sheets as of December 31, 2013 and 2012
Statements of Cash Flows for each of the years ended December 31, 2013, 2012 and 2011
Statements of Equity for each of the years ended December 31, 2013, 2012 and 2011
Notes to Financial Statements
Atlantic City Electric Company
Consolidated Statements of Income for each of the years ended December 31, 2013, 2012 and 2011
Consolidated Balance Sheets as of December 31, 2013 and 2012
Consolidated Statements of Cash Flows for each of the years ended December 31, 2013, 2012 and 2011
Consolidated Statements of Equity for each of the years ended December 31, 2013, 2012 and 2011
Notes to Consolidated Financial Statements
2. Financial Statement Schedules
The financial statement schedules specified by Regulation S-X, other than those listed below, are omitted because either they are not applicable or the required information is presented in the financial statements included in Part II, Item 8. “Financial Statements and Supplementary Data” of this Form 10-K.
Schedule I, Condensed Financial Information of Parent Company is submitted below.
PEPCO HOLDINGS, INC. (Parent Company)
STATEMENTS OF (LOSS) INCOME
The accompanying Notes are an integral part of these financial statements.
PEPCO HOLDINGS, INC. (Parent Company)
BALANCE SHEETS
The accompanying Notes are an integral part of these financial statements.
PEPCO HOLDINGS, INC. (Parent Company)
STATEMENTS OF CASH FLOWS
The accompanying Notes are an integral part of these financial statements.
NOTES TO FINANCIAL INFORMATION
(1) BASIS OF PRESENTATION
Pepco Holdings, Inc. (Pepco Holdings) is a holding company and conducts substantially all of its business operations through its subsidiaries. These condensed financial statements and related footnotes have been prepared in accordance with Rule 12-04, Schedule I of Regulation S-X. These statements should be read in conjunction with the consolidated financial statements and notes thereto of Pepco Holdings included in Part II, Item 8 of this Form 10-K.
Pepco Holdings owns 100% of the common stock of all its significant subsidiaries.
(2) RECLASSIFICATIONS AND ADJUSTMENTS
Certain prior period amounts have been reclassified in order to conform to the current period presentation.
Revision to Prior Period Financial Statements
PCI Deferred Income Tax Liability Adjustment
Since 1999, PCI had not recorded a deferred tax liability related to a temporary difference between the financial reporting basis and the tax basis of an investment in a wholly owned partnership. In the second quarter of 2013, PHI re-evaluated this accounting treatment and found it to be in error, requiring an adjustment related to prior periods. PHI determined that the cumulative adjustment required, representing a charge to earnings of $32 million, related to a period prior to the year ended December 31, 2009 (the earliest period for which selected consolidated financial data were presented in the table entitled “Selected Financial Data” in Part II, Item 6 of this Annual Report on Form 10-K). Consistent with PHI’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2013, the accompanying PHI parent company financial statements reflect the correction of this error as an adjustment to shareholders’ equity for the earliest period presented. The adjustment to correct the error did not affect PHI’s parent company statements of income and cash flows for each of the three years in the period ended December 31, 2013, and only affected the reported balances of investment in consolidated companies and retained earnings as reflected in PHI’s parent company balance sheets as of December 31, 2013 and 2012. The adjustment is not considered to be material to the reported balances of retained earnings and total equity reflected in PHI’s parent company financial statements included in this Annual Report on Form 10-K. The table below illustrates the effects of the revision on reported balances in PHI’s parent company financial statements.
(a) The amount differs from the amount originally reported in the 2012 Form 10-K due to the reclassification of net assets associated with investment in consolidated companies to assets held for disposition.
(3) DEBT
For information concerning Pepco Holdings’ long-term debt obligations, see Note (10), “Debt,” to the consolidated financial statements of Pepco Holdings.
(4) COMMITMENTS AND CONTINGENCIES
For information concerning Pepco Holdings’ material contingencies and guarantees, see Note (15), “Commitments and Contingencies” to the consolidated financial statements of Pepco Holdings.
Pepco Holdings guarantees the obligations of Pepco Energy Services under certain contracts in its energy savings performance contracting businesses and underground transmission and distribution construction business. At December 31, 2013, Pepco Holdings’ guarantees of Pepco Energy Services’ obligations under these contracts totaled $190 million. PHI also guarantees the obligations of Pepco Energy Services under surety bonds obtained by Pepco Energy Services for construction projects in these businesses. These guarantees totaled $229 million at December 31, 2013.
In addition, Pepco Holdings guarantees certain obligations of Pepco, DPL, and ACE under surety bonds obtained by these subsidiaries, for construction projects and self-insured workers compensation matters. These guarantees totaled $29 million at December 31, 2013.
Pepco Holdings, pursuant to an intercompany guarantee agreement with Potomac Capital Investment Corporation (PCI), guarantees certain intercompany obligations of PCI to its subsidiaries. This guarantee totaled $725 million at December 31, 2013.
(5) INVESTMENT IN CONSOLIDATED COMPANIES
Pepco Holdings’ majority owned subsidiaries are recorded using the equity method of accounting. A breakout of the balance in Investment in consolidated companies is as follows:
(a) The investment in PCI excludes net assets held for disposition at December 31, 2012 and primarily represents income tax obligations related to the assets held for disposition.
(6) DISCONTINUED OPERATIONS
During the second and third quarters of 2013, PCI terminated all of its interests in its six remaining cross-border energy lease investments. PCI received aggregate net cash proceeds from these early terminations of $873 million (net of aggregate termination payments of $2.0 billion used to retire the non-recourse debt associated with the terminated leases) and recorded an aggregate pre-tax loss, including transaction costs, of approximately $3 million ($2 million after-tax), representing the excess of the carrying value of the terminated leases over the net cash proceeds received. As a result, PHI has reported the results of operations of the cross-border energy lease investments as discontinued operations in all periods presented in the accompanying statements of (loss) income. Further, the assets and liabilities related to the cross-border energy lease investments are reported as held for disposition as of each date in the accompanying balance sheets.
In December 2009, PHI announced the wind-down of the retail energy supply component of the Pepco Energy Services business, which was comprised of the retail electric and natural gas supply businesses. Pepco Energy Services implemented the wind-down by not entering into any new retail electric or natural gas supply contracts while continuing to perform under its existing retail electric and natural gas supply contracts through their respective expiration dates. On March 21, 2013, Pepco Energy Services entered into an agreement whereby a third party assumed all the rights and obligations of the remaining retail natural gas supply customer contracts, and the associated supply obligations, inventory and derivative contracts. The transaction was completed on April 1, 2013. In addition, Pepco Energy Services completed the wind-down of its retail electric supply business in the second quarter of 2013 by terminating its remaining customer supply and wholesale purchase obligations beyond June 30, 2013. The operations of Pepco Energy Services’ retail electric and natural gas supply businesses have been classified as discontinued operations for financial reporting purposes.
In April 2010, the Board of Directors approved a plan for the disposition of PHI’s competitive wholesale power generation, marketing and supply business, which had been conducted through Conectiv Energy. On July 1, 2010, PHI completed the sale of Conectiv Energy’s wholesale power generation business to Calpine for $1.64 billion. The disposition of Conectiv Energy’s remaining assets and businesses, consisting of its load service supply contracts, energy hedging portfolio, certain tolling agreements and other assets not included in the Calpine sale, has been completed.
(7) RELATED PARTY TRANSACTIONS
As of December 31, 2013 and 2012, PHI had the following balances on its balance sheets due (to) from related parties:
(a) Included in Accounts payable due to associated companies.
(b) Included in Notes payable due to subsidiary companies.
Schedule II, Valuation and Qualifying Accounts, for each registrant is submitted below.
Pepco Holdings, Inc.
(a) Collection of accounts previously written off.
(b) Uncollectible accounts written off.
Potomac Electric Power Company
(a) Collection of accounts previously written off.
(b) Uncollectible accounts written off.
Delmarva Power & Light Company
(a) Collection of accounts previously written off.
(b) Uncollectible accounts written off.
Atlantic City Electric Company
(a) Collection of accounts previously written off.
(b) Uncollectible accounts written off.
3. EXHIBITS
The documents listed below are being filed or furnished on behalf of PHI, Pepco, DPL and/or ACE, as indicated. The warranties, representations and covenants contained in any of the agreements included or incorporated by reference herein or which appear as exhibits hereto should not be relied upon by buyers, sellers or holders of PHI’s or its subsidiaries’ securities and are not intended as warranties, representations or covenants to any individual or entity except as specifically set forth in such agreement.
Exhibit No.
Registrant(s)
Description of Exhibit
Reference
101. DEF
PHI
Pepco
DPL
ACE
XBRL Taxonomy Extension
Definition Linkbase Document
Filed herewith.
101. LAB
PHI
Pepco
DPL
ACE
XBRL Taxonomy Extension Label
Linkbase Document
Filed herewith.
101. PRE
PHI
Pepco
DPL
ACE
XBRL Taxonomy Extension
Presentation Linkbase Document
Filed herewith.
* Management contract or compensatory plan or arrangement.
** The information required by this Exhibit is set forth in Note (12), “Stock-Based Compensation, Dividend Restrictions and Calculations of Earnings Per Share of Common Stock,” of the consolidated financial statements of Pepco Holdings, Inc. included in Part II, Item 8 “Financial Statements and Supplementary Data” of this Form 10-K.
Regulation S-K Item 10(d) requires registrants to identify the physical location, by SEC file number reference, of all documents incorporated by reference that are not included in a registration statement and have been on file with the SEC for more than five years. The SEC file number references for PHI, those of its subsidiaries that are currently registrants, Conectiv and ACE Funding are provided below:
Pepco Holdings, Inc. (File Nos. 001-31403 and 030-00359)
Potomac Electric Power Company (File No. 001-01072)
Delmarva Power & Light Company (File No. 001-01405)
Atlantic City Electric Company (File No. 001-03559)
Conectiv (File No. 001-13895)
Atlantic City Electric Transition Funding LLC (File No. 333-59558)
Certain instruments defining the rights of the holders of long-term debt of PHI, Pepco, DPL and ACE (including medium-term notes, unsecured notes, senior notes and tax-exempt financing instruments) have not been filed as exhibits in accordance with Regulation S-K Item 601(b)(4)(iii) because such instruments do not authorize securities in an amount which exceeds 10% of the total assets of the applicable registrant and its subsidiaries on a consolidated basis. Each of PHI, Pepco, DPL or ACE agrees to furnish to the SEC upon request a copy of any such instruments omitted by it.
INDEX TO FURNISHED EXHIBITS
The documents listed below are being furnished herewith:
(b) Exhibits.
The list of exhibits filed or furnished with this Form 10-K are set forth on the exhibit index appearing at the end of this Form 10-K.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, each of the registrants has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the above named registrants and in the capacities and on the dates indicated:
/s/ JOSEPH M. RIGBY
Joseph M. Rigby
Chairman of the Board, President and Chief
Executive Officer of Pepco Holdings,
Director of Pepco, DPL and ACE
(Principal Executive Officer of Pepco Holdings)
February 27, 2014
/s/ DAVID M. VELAZQUEZ
David M. Velazquez
President and Chief Executive Officer of
Pepco, DPL and ACE, Director of Pepco and DPL
(Principal Executive Officer of Pepco,
DPL and ACE)
February 27, 2014
/s/ FRED BOYLE
Frederick J. Boyle
Senior Vice President and Chief Financial
Officer of Pepco Holdings, Pepco, and
DPL, Chief Financial Officer of ACE and
Director of Pepco
(Principal Financial
Officer of Pepco Holdings, Pepco, DPL and ACE)
February 27, 2014
/s/ RONALD K. CLARK
Ronald K. Clark
Vice President and Controller of Pepco Holdings,
Pepco and DPL and Controller of ACE
(Principal Accounting Officer of Pepco
Holdings, Pepco, DPL and ACE)
February 27, 2014
INDEX TO EXHIBITS FILED HEREWITH
101. LAB
PHI
Pepco
DPL
ACE
XBRL Taxonomy Extension Label
Linkbase Document
101. PRE
PHI
Pepco
DPL
ACE
XBRL Taxonomy Extension
Presentation Linkbase Document
* Management contract or compensatory plan or arrangement.
INDEX TO EXHIBITS FURNISHED HEREWITH