Item 1. BUSINESS
Overview
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, to a lesser extent, the distribution and supply of natural gas (Power Delivery):
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Potomac Electric Power Company, 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, which was incorporated in Delaware in 1909 and became a domestic Virginia corporation in 1979, and
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Atlantic City Electric Company, which was incorporated in New Jersey in 1924.
Through Pepco Energy Services, Inc. and its subsidiaries (collectively, Pepco Energy Services), PHI provides energy savings performance contracting services primarily to government customers, high voltage underground transmission cabling for industrial customers, construction and operations of combined heat and power and central energy plants for government and commercial customers, and is in the process of winding down its competitive electricity and natural gas retail supply business.
In addition, through Potomac Capital Investment Corporation (PCI), PHI holds six cross-border energy lease investments as described below under the heading “Other Business Operations.”
The following chart shows, in simplified form, the corporate structure of PHI and its principal subsidiaries:
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 a service agreement 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 methods set forth in the service agreement.
Pepco Holdings’ management has identified its operating segments at December 31, 2012 as (i) Power Delivery, consisting of the operations of Pepco, DPL and ACE, engaged primarily in the transmission, distribution and default supply of electricity and the distribution and supply of natural gas, (ii) Pepco Energy Services and (iii) Other Non-Regulated, consisting primarily of the operations of PCI. For financial information relating to PHI’s segments, see Note (5), “Segment Information,” to the consolidated financial statements of PHI.
Business Strategy
PHI’s business strategy is to be a top-performing, regulated power delivery company focused on:
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investing in transmission and distribution infrastructure to provide safe and reliable electric and natural gas service;
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building a smarter grid to automate certain functions on the electric system, restore power more efficiently and provide customers detailed energy information to help them control their energy costs;
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enhancing the customer experience and PHI’s communications with its customers through the development and use of the smart grid and other technology; and
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providing comprehensive energy management solutions and developing, installing and operating renewable energy solutions.
The elements of PHI’s business strategy support PHI’s core values of safety, diversity and environmental stewardship. PHI’s success in achieving this business strategy is dependent on its ability to earn reasonable rates of return on, and timely cost recovery of, its investments through its regulatory proceedings.
To further its business strategy, Pepco Holdings may consider transactions involving its existing businesses, including joint ventures, and dispositions and acquisitions of businesses. Pepco Holdings also may refine components of its business strategy as it deems necessary or appropriate in response to business factors and conditions, including regulatory requirements.
Description of Business
Power Delivery
PHI’s primary business is Power Delivery. Power Delivery in 2012, 2011 and 2010, produced 86%, 78% and 73%, respectively, of PHI’s consolidated operating revenues and 79%, 78% and 81%, respectively, of PHI’s consolidated operating income.
Each utility comprising Power Delivery is regulated in the jurisdictions that encompass its electricity distribution service territory and is regulated by the Federal Energy Regulatory Commission (FERC) for its electricity transmission facilities. DPL also is a regulated natural gas utility serving portions of Delaware. In the aggregate, Power Delivery distributes electricity to more than 1.8 million customers in the mid-Atlantic region and delivers natural gas to approximately 125,000 customers in Delaware. PHI no longer owns any electric generation facilities except for 17,400 kilowatts of generating capacity owned and operated by Pepco Energy Services.
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:
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Commercial activities in the region include banking and other professional services, government, insurance, real estate, shopping malls, casinos, stand alone construction and tourism.
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Industrial activities in the region include chemical, glass, pharmaceutical, steel manufacturing, food processing and oil refining.
Distribution and Default Supply of Electricity
Pepco, DPL and ACE each 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 utilties’ service territories. Distribution facilities carry electricity from the transmission facilities to the end-use customers located in the utilities’ service territories.
Each utility is responsible for the distribution of electricity 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 retail supplier. The regulatory term for this default supply service is Standard Offer Service (SOS) in Delaware, the District of Columbia and Maryland, and Basic Generation Service (BGS) in New Jersey. In this Annual Report on Form 10-K, these supply services are referred to generally as Default Electricity Supply.
Transmission of Electricity and Relationship with PJM
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 the mid-Atlantic portion of the United States and parts of the Midwest. Pepco, DPL and ACE each is a member of the PJM Regional Transmission Organization (PJM RTO), the regional transmission organization designated by FERC to coordinate the movement of wholesale electricity within a region consisting of all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia.
PJM, the FERC-approved independent grid operator, manages the transmission grid and the wholesale electricity market in the PJM RTO region. Any entity that wishes to have wholesale electricity delivered at any point within the PJM RTO region must obtain transmission services from PJM. In accordance with FERC-approved rules, Pepco, DPL, ACE and the other transmission-owning utilities in the region make their transmission facilities available to the PJM RTO, and PJM directs and controls the operation of these transmission facilities. For transmission services, transmission owners are paid rates proposed by the transmission owner and approved by FERC. 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 the PJM RTO region. The PJM Board of Managers reviews and approves each PJM regional transmission expansion plan, including whether to include new construction of transmission facilities proposed by PJM RTO members in the plan and, if so, the target in-service date for those facilities.
Reliability Enhancement
Since 2010, PHI has implemented comprehensive reliability enhancement plans which include various initiatives to improve electrical system reliability, including:
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the identification and upgrading of under-performing feeder lines;
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the addition of new facilities to support load;
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the installation of distribution automation systems on both the overhead and underground network system;
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the rejuvenation and replacement of underground residential cables;
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selective undergrounding of portions of existing above-ground primary feeder lines, where appropriate to improve reliability;
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improvements to substation supply lines; and
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enhanced vegetation management.
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.”
Smart Grid
A key initiative for PHI in 2012 was the continued transformation of the electric grid owned and operated by Pepco Holdings’ utility subsidiaries into a “smart grid,” a sophisticated network of automated digital devices capable of communicating vast amounts of real-time information. The smart grid is designed to meet the challenges of rising energy costs, respond to concerns about the environment, improve reliability, provide timely and accurate customer information and address government energy reduction goals. During 2012, Power Delivery continued its development of the smart grid by replacing existing meters with smart meters, continuing construction of a wireless network and related information technology infrastructure to collect, manage and provide customers with the data made available by the smart meters and installing equipment to automate certain functions on the electric grid.
A central component of the smart grid is advanced metering infrastructure (AMI) which is a system that collects, measures and analyzes energy usage data from advanced digital electric and gas meters known as smart meters. In total, Power Delivery is deploying 1.3 million smart meters across the Pepco and DPL service territories. 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 AMI and distribution automation are enabled by advanced technology that is able to communicate with devices on the electric and gas delivery system and carry energy usage data to the host utility. The smart grid system will provide customers access to detailed energy information to help them better manage energy usage and costs, improve the customer experience during power restoration and enhance the ability of PHI’s utilities to manage and operate their electrical and natural gas distribution systems. The implementation of the AMI system and distribution automation involves an integration of technologies provided by multiple vendors.
The installation of smart meters is subject to the approval of applicable state regulators. Electric meter installation and activation are substantially complete for DPL electric customers in Delaware; installation of smart meters for natural gas delivery customers in Delaware is ongoing. Meter installation is substantially complete for Pepco customers in the District of Columbia, with activation expected to be completed in the first quarter of 2013. For Pepco customers in Maryland, installation and activation are expected to be completed in the third quarter of 2013. In 2012, the Maryland Public Service Commission (MPSC) approved the deployment of AMI for electric customers in DPL’s Maryland service territory, and installation is scheduled to begin in the first quarter of 2013.
The respective public service commissions have approved the creation of regulatory assets to defer AMI costs between rate cases, as well as the accrual of returns on the deferred costs. Thus, these costs will be recovered in the future through base rates. Approval of AMI has been deferred by the New Jersey Board of Public Utilities (NJBPU) for ACE in New Jersey.
PHI’s implementation of dynamic pricing rate structures helps ensure that customers experience additional benefits from the smart grid. Dynamic pricing provides bill credits to reward eligible customers for lowering their energy use during those times when energy demand and, consequently, the cost of supplying electricity, are higher. In 2011, the Delaware Public Service Commission (DPSC) approved DPL’s request to implement dynamic pricing for Delaware customers. In Delaware, approximately 6,700 SOS customers participated in the phase-in stage of the program in 2012; the remaining residential SOS customers will be eligible to participate in 2013.
Dynamic pricing has been approved for all Pepco customers in Maryland, and the phase-in for approximately 5,000 residential customers has been completed; the remaining Maryland residential customers will be eligible to participate in 2013. Pepco intends to re-file the dynamic pricing proposal in its District of Columbia jurisdiction in 2013. Dynamic pricing has been approved in concept pending AMI deployment for DPL’s Maryland SOS customers, and has been deferred by the NJBPU for ACE’s customers in New Jersey.
In April 2010, PHI signed agreements to formalize $168 million in awards from the U.S. Department of Energy to support the rollout of smart grid initiatives. In the Pepco service area, $149 million was awarded for AMI, direct load control, distribution automation and communications infrastructure, while in the Atlantic City Electric service area, $19 million was awarded for direct load control, distribution automation and communications infrastructure. The grants effectively reduce the project costs of these initiatives. The cumulative award payments received by Pepco and ACE as of December 31, 2012, were $115 million and $13 million, respectively.
For projected 2013 through 2017 capital expenditures associated with the smart grid, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity - Capital Requirements.”
Regulated Utility Subsidiaries
The following is a more detailed description of the business of each of PHI’s three regulated utility subsidiaries:
Pepco
Pepco is engaged in the transmission, distribution and default supply of electricity in the District of Columbia and major portions of Prince George’s County and Montgomery County in Maryland. Pepco’s service territory covers approximately 640 square miles and has a population of approximately 2.2 million. As of December 31, 2012, Pepco distributed electricity to 793,000 customers (of which 260,000 were located in the District of Columbia and 533,000 were located in Maryland), as compared to 788,000 customers as of December 31, 2011 (of which 257,000 were located in the District of Columbia and 531,000 were located in Maryland). As of December 31, 2010, Pepco distributed electricity to 787,000 customers (of which 256,000 were located in the District of Columbia and 531,000 were located in Maryland).
In 2012, Pepco distributed a total of 26,006,000 megawatt hours of electricity, of which 57% was distributed within its Maryland territory and 43% within the District of Columbia. Of this amount, 30% of the total megawatt hours were delivered to residential customers, 50% to commercial customers, and 20% to United States and District of Columbia government customers. In 2011, Pepco distributed a total of 26,895,000 megawatt hours of electricity, of which 57% was distributed within its Maryland territory and 43% within the District of Columbia. Of this amount, 30% of the total megawatt hours were distributed to residential customers, 50% to commercial customers, and 20% to United States and District of Columbia government customers. In 2010, Pepco distributed a total of 27,665,000 megawatt hours of electricity, of which 57% was distributed within its Maryland territory and 43% within the District of Columbia. Of this amount, 30% of the total megawatt hours were distributed to residential customers, 49% to commercial customers, and 21% to United States and District of Columbia government customers.
Pepco has been providing SOS in Maryland since July 2004. Pursuant to orders issued by the MPSC, Pepco is obligated to provide SOS (i) to residential and small commercial customers until further action of the Maryland General Assembly and (ii) to medium-sized commercial customers through November 2013. Pepco purchases the electricity required to satisfy these SOS obligations from wholesale suppliers under contracts entered into in accordance with competitive bid procedures approved and supervised by the MPSC. Pepco also is obligated to provide Standard Offer Service, known as Hourly Priced Service (HPS), for large Maryland customers. Power to supply HPS customers is acquired in next-day and other short-term PJM RTO markets. Pepco is entitled to recover from its SOS customers the cost of acquiring the SOS supply, plus an administrative charge that is intended to allow Pepco to recover the administrative costs incurred to provide the SOS and a modest margin. Because the margin varies by customer class, the actual average margin over any given time period depends on the number of Maryland SOS customers in each customer class and the electricity used by such customers. Pepco is paid tariff rates for the distribution of electricity over its transmission and distribution facilities to all electricity customers in its Maryland service territory regardless of whether the customer receives SOS or purchases electricity from another supplier.
Pepco has been providing SOS in the District of Columbia since February 2005. Pursuant to orders issued by the District of Columbia Public Service Commission (DCPSC), Pepco is obligated to provide SOS to residential and small, medium-sized and large commercial customers indefinitely. Pepco purchases the electricity required to satisfy its SOS obligations from wholesale suppliers under contracts entered into in accordance with a competitive bid procedure approved and supervised by the DCPSC. Pepco is entitled to recover from its SOS customers the costs of acquiring the SOS supply, plus an administrative charge that is intended to allow Pepco to recover the administrative costs incurred to provide the SOS and a modest margin. Because the margin varies by customer class, the actual average margin over any given time period depends on the number of District of Columbia SOS customers in each customer class and the amount of electricity used by such customers. Pepco is paid tariff rates for the distribution of electricity over its transmission and distribution facilities to all electricity customers in its District of Columbia service territory regardless of whether the customer receives SOS or purchases electricity from another supplier.
For the year ended December 31, 2012, 40% of Pepco’s Maryland distribution sales (measured by megawatt hours) were to SOS customers, as compared to 43% and 46% in 2011 and 2010, respectively, and 25% of its District of Columbia distribution sales (measured by megawatt hours) were to SOS customers in 2012, as compared to 27% and 29% in 2011 and 2010, respectively.
DPL
DPL is engaged in the transmission, distribution and default supply of electricity in Delaware and portions of 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.
Distribution and Supply of Electricity
DPL’s electricity 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 has a population of approximately 1.4 million. As of December 31, 2012, DPL delivered electricity to 503,000 customers (of which 303,000 were located in Delaware and 200,000 were located in Maryland), as compared to 501,000 customers as of December 31, 2011 (of which 301,000 were located in Delaware and 200,000 were located in Maryland). As of December 31, 2010, DPL delivered electricity to 500,000 customers (of which 301,000 were located in Delaware and 199,000 were located in Maryland).
In 2012, DPL distributed a total of 12,641,000 megawatt hours of electricity to its customers, of which 67% was distributed within its Delaware territory and 33% within its Maryland territory. Of this amount, 40% of the total megawatt hours were distributed to residential customers, 41% to commercial customers and 19% to industrial customers. In 2011, DPL distributed a total of 12,688,000 megawatt hours of electricity, of which 66% was distributed within its Delaware territory and 34% within its Maryland territory. Of this amount, 41% of the total megawatt hours were distributed to residential customers, 42% to commercial customers and 17% to industrial customers. In 2010, DPL distributed a total of 12,853,000 megawatt hours of electricity, of which 66% was distributed within its Delaware territory and 34% within its Maryland territory. Of this amount, 42% of the total megawatt hours were distributed to residential customers, 41% to commercial customers and 17% to industrial customers.
DPL has been providing SOS in Delaware since May 2006. Pursuant to orders issued by the DPSC, DPL is obligated to provide SOS to residential, small commercial and industrial customers through May 2015, and to medium, large and general service commercial customers through May 2013. DPL purchases the electricity required to satisfy these SOS obligations from wholesale suppliers under contracts entered into in accordance with competitive bid procedures approved and supervised by the DPSC. DPL also has an obligation to provide SOS, known as HPS, for the largest Delaware customers. Power to supply the HPS customers is acquired in next-day and other short-term PJM RTO markets. DPL’s rates for supplying SOS and HPS reflect the associated capacity, energy (including satisfaction of renewable energy requirements), transmission and ancillary services costs and an amount referred to as a Reasonable Allowance for Retail Margin. Components of the Reasonable Allowance for Retail Margin include a fixed annual margin of approximately $2.75 million, plus estimated incremental expenses and a cash working capital allowance. DPL is paid tariff rates for the distribution of electricity over its transmission and distribution facilities to all electricity customers in its Delaware service territory regardless of whether the customer receives SOS or purchases electricity from another supplier.
DPL has been providing SOS in Maryland since June 2004. Pursuant to orders issued by the MPSC, DPL is obligated to provide SOS to residential and small commercial customers until further action of the Maryland General Assembly, and to medium-sized commercial customers through November 2013. DPL purchases the electricity required to satisfy these SOS obligations from wholesale suppliers under contracts entered into in accordance with a competitive bid procedure approved and supervised by the MPSC. DPL also is obligated to provide HPS for large Maryland customers. Power to supply the HPS customers is acquired in next-day and other short-term PJM RTO markets. DPL is entitled to recover from its SOS customers the costs of acquiring the SOS supply, plus an administrative charge that is intended to allow DPL to recover the administrative costs incurred to provide the SOS and a modest margin. Because the margin varies by customer class, the actual average margin over any given time period depends on the number of Maryland SOS customers in each customer class and the electricity used by such customers. DPL is paid tariff rates for the distribution of electricity over its transmission and distribution facilities to all electricity customers in its Maryland service territory regardless of whether the customer receives SOS or purchases electricity from another supplier.
For the year ended December 31, 2012, 47% of DPL’s Delaware distribution sales (measured by megawatt hours) were to SOS customers, as compared to 51% and 53% in 2011 and 2010, respectively, and 53% of its Maryland distribution sales (measured by megawatt hours) were to SOS customers in 2012, as compared to 58% in 2011 and 63% in 2010.
Supply and Distribution 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 has a population of approximately 500,000. Large volume commercial, institutional, and industrial natural gas customers may purchase natural gas either from DPL or from other suppliers. DPL uses its natural gas distribution facilities to deliver natural gas to customers that choose to purchase natural gas from another supplier. Intrastate transportation customers pay DPL distribution service rates approved by the DPSC. 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. For the year ended December 31, 2012, DPL supplied 60% of the natural gas that it delivered, compared to 64% in 2011 and 65% in 2010.
As of December 31, 2012, DPL delivered natural gas to 125,000 customers as compared to 124,000 customers in 2011 and 123,000 customers in 2010. In 2012, DPL delivered 16,815,000 Mcf (thousand cubic feet) of natural gas to customers in its Delaware service territory, of which 38% were sales to residential customers, 22% to commercial customers, less than 1% to industrial customers and 40% to customers receiving a transportation-only service. In 2011, DPL delivered 18,754,000 Mcf of natural gas, of which 40% were sales to residential customers, 23% were sales to commercial customers, 1% were sales to industrial customers and 36% were sales to customers receiving a transportation-only service. In 2010, DPL delivered 19,336,000 Mcf of natural gas, of which 41% were sales to residential customers, 23% were sales to commercial customers, 1% were sales to industrial customers and 35% were sales to customers receiving a transportation-only service.
ACE
ACE is primarily engaged in the transmission, distribution and default supply of electricity in a service territory consisting of Gloucester, Camden, Burlington, Ocean, Atlantic, Cape May, Cumberland and Salem counties in southern New Jersey. ACE’s service territory covers approximately 2,700 square miles and has a population of approximately 1.1 million. As of December 31, 2012, ACE distributed electricity to 545,000 customers in its service territory, as compared to 547,000 and 548,000 customers as of December 31, 2011 and 2010, respectively.
In 2012, ACE distributed a total of 9,495,000 megawatt hours of electricity to its customers, of which 46% of the total was distributed to residential customers, 45% to commercial customers and 9% to industrial customers. In 2011, ACE distributed a total of 9,683,000 megawatt hours of electricity to its customers, of which 46% of the total was distributed to residential customers, 45% to commercial customers, and 9% to industrial customers. In 2010, ACE distributed a total of 10,185,000 megawatt hours of electricity to its customers, of which 46% was distributed to residential customers, 44% to commercial customers, and 10% to industrial customers.
Electric customers in New Jersey who do not choose another supplier receive BGS from their electric distribution company. New Jersey’s electric distribution companies, including ACE, jointly obtain the electricity to meet their 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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BGS-Fixed Price (BGS-FP), which is supplied to smaller commercial and residential customers at seasonally-adjusted fixed prices. BGS-FP rates change annually on June 1 and are based on the average BGS price obtained at auction in the current year and the two prior years. As of December 31, 2012, ACE’s BGS-FP peak load was approximately 1,320 megawatts, which represents approximately 96% of ACE’s total BGS load.
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BGS-Commercial and Industrial Energy Price (BGS-CIEP), which is supplied to large customers at hourly PJM RTO real-time market prices for a term of 12 months. As of December 31, 2012, ACE’s peak BGS-CIEP load was approximately 54 megawatts, which represents approximately 4% of ACE’s 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 on the supply component of the BGS it supplies to customers. ACE is paid tariff rates for the distribution of electricity over its transmission and distribution facilities to all electricity customers in its service territory regardless of whether the customer receives BGS or purchases electricity from another supplier.
For the year ended December 31, 2012, 51% of ACE’s total distribution sales (measured by megawatt hours) were to BGS customers, as compared to 56% and 65% in 2011 and 2010, respectively.
ACE has contracts with three unaffiliated non-utility generators (NUGs) under which ACE is obligated to purchase capacity and the entire generation output of the facilities. One of the contracts expires in 2016 and the other two expire in 2024. In 2012, ACE purchased 1.7 million megawatt hours of power from the NUGs. ACE sells this electricity into the wholesale market administered by PJM.
In 2001, ACE established Atlantic City Electric Transitional 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.
Seasonality
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 long standing practice by which the applicable public service commissions set distribution rates based on a fixed charge per kilowatt-hour of electricity used by the customer. 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 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 for DPL electricity and natural gas customers in Delaware is under consideration by the DPSC. 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.
MAPP Project
On August 24, 2012, the board of PJM terminated the Mid-Atlantic Power Pathway (MAPP) project and removed it from PJM’s regional transmission expansion plan. PHI had been directed to construct a 152-mile high-voltage interstate transmission line, to address the reliability needs of the region’s transmission system.
In a 2008 FERC order approving incentives for the MAPP project, FERC authorized the recovery of prudently incurred abandoned costs in connection with the MAPP project. Consistent with this order, on December 21, 2012, PHI submitted a filing to FERC seeking recovery over a period of five years of approximately $88 million of abandoned MAPP capital expenditures. 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 (see Note (7), “Regulatory Matters - MAPP Project” to the consolidated financial statements of PHI for additional information).
Pepco Energy Services
Pepco Energy Services is engaged in the following businesses:
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providing energy savings performance contracting services principally to federal, state and local government customers, and designing, constructing and operating combined heat and power and central energy plants,
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providing high voltage electric construction and maintenance services to customers throughout the United States, as well as low voltage electric construction and maintenance services and streetlight construction services to utilities, municipalities and other customers in the Washington, D.C. area, and
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providing retail customers electricity and natural gas under its remaining contractual obligations.
Since 2010, Pepco Energy Services has been focused on growing its energy savings performance contracting services business in the federal, state and local government markets. Activity in the state and local government markets, which are Pepco Energy Services’ largest markets, has slowed significantly in 2012, due to, among other factors, lower energy prices that have lessened the economic benefits of energy savings projects and the reluctance of state and local governments to incur new debt associated with these projects. As a result of this slowdown, Pepco Energy Services believes that new business in these markets will remain challenged for the foreseeable future. Consequently, during 2012, Pepco Energy Services reduced resources and personnel and limited geographic expansion in the energy savings services business, and has refocused its existing resources on developing business in the federal government market while continuing to pursue combined heat and power projects.
Most of Pepco Energy Services’ contracts with federal, state and local governments, as well as 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 that, 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. In addition, Pepco Energy Services provides energy services guarantees in connection with its energy services performance contracts.
PHI guarantees the obligations of Pepco Energy Services under certain of its energy savings, combined heat and power and construction contracts. At December 31, 2012, PHI’s guarantees of Pepco Energy Services’ obligations under these contracts totaled $198 million.
Pepco Energy Services also has historically been engaged in the business of providing retail energy supply services, consisting of the sale of electricity, including electricity from renewable resources, primarily to commercial, industrial and government customers located in the mid-Atlantic and northeastern regions of the United States, as well as Texas and Illinois, and the sale of natural gas to customers located primarily in the mid-Atlantic region. In December 2009, PHI announced that it will wind down the retail energy supply component of the Pepco Energy Services business.
Pepco Energy Services’ retail natural gas sales volumes and revenues are seasonally dependent. Colder weather from November through March of each year generally translates into increased sales volumes, which, when coupled with higher natural gas prices during these months, allows Pepco Energy Services to recognize generally higher revenues as compared to other months of the year. Retail electricity sales volumes are also seasonally dependent, with sales in the summer and winter months being generally higher than other months of the year, which, when coupled with higher electricity prices during these periods, allows Pepco Energy Services to recognize generally higher revenues as compared to other periods during the year. The impact of this seasonality on Pepco Energy Services’ results is diminishing with the wind-down of the business. The energy services business is not seasonal.
To effectuate the wind-down of the retail energy supply business, Pepco Energy Services is continuing to fulfill all of its commercial and regulatory obligations and perform its customer service functions to ensure that it meets the needs of its existing customers, but is not entering into any new retail energy supply contracts.
Substantially all of Pepco Energy Services’ retail customer obligations will be fully performed by June 1, 2014. PHI is reviewing strategic alternatives that could accelerate into 2013 the completion of the wind-down of its remaining portfolio of retail energy contracts.
Pepco Energy Services’ remaining businesses will not be affected by the wind-down of the retail energy supply business.
During 2012, Pepco Energy Services deactivated its Buzzard Point and Benning Road oil-fired generation facilities. Pepco Energy Services has 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 that the facilities require only essential maintenance until they are completely decommissioned.
Competition
Pepco Energy Services’ energy services business is highly competitive. 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 (as is the case with Pepco Energy Services). Among the factors as to which the energy services business competes are the amount and duration of the guarantees provided in energy savings performance contracts and the quality and value of service provided to customers. The energy services business is impacted by new entrants into the market, financial strength of customers, energy prices, and general economic conditions.
Other Business Operations
Between 1994 and 2002, PCI, a subsidiary of PHI, entered into eight cross-border energy lease investments involving public utility assets (primarily consisting of hydroelectric generation and coal-fired electric generation facilities, and natural gas distribution networks) located outside of the United States. Each of these investments is structured as a sale and leaseback transaction commonly referred to as a sale-in, lease-out, or SILO, transaction. During the second quarter of 2011 and the third quarter of 2012, PHI entered into early termination agreements with several lessees involving all of the leases comprising two of the eight lease investments and a small portion of the leases comprising a third lease investment. As of December 31, 2012, PHI’s net investment in its six remaining cross-border energy lease investments was approximately $1.2 billion.
The net investment value of the cross-border energy lease investments and the pattern of recognizing the related cross-border energy lease income are based on the estimated timing and amount of all cash flows related to the investments, including the income tax-related cash flows. The Treasury Department and the Internal Revenue Service (IRS) have identified SILO transactions, such as PCI’s cross-border energy lease investments, as tax avoidance transactions and the IRS disallowed a substantial portion of the tax benefits claimed by PHI related to its cross-border energy lease investments beginning with PHI’s 2001 income tax return. IRS challenges related to SILO and lease-in, lease-out, or LILO, transactions also have been the subject of litigation, including litigation commenced by PHI in the U.S. Court of Federal Claims in January 2012 related to certain tax benefits claimed by PHI on its federal income tax returns for 2001 and 2002. PHI is required to assess on a periodic basis the likely outcome of tax positions relating to its cross-border energy lease investments and, if there is a change or a projected change in the timing of the estimated tax benefits generated by the transactions, PHI is required to recalculate the value of its net investment. In 2008, after evaluating court rulings that had been recently decided in favor of the IRS on certain SILO and LILO transactions, PHI significantly revised the projected timing of the tax benefits generated by the transactions and reduced the carrying value of its net investment by recording a non-cash charge of $86 million after tax.
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 LILO transaction. PHI had viewed the initial trial court ruling on this matter, in which the U.S. Court of Federal Claims issued a decision in favor of the taxpayer in October 2009, as a favorable development in PHI’s dispute with the IRS. After analyzing the U.S. Court of Appeals ruling in this case, PHI has determined that its tax position with respect to the tax benefits associated with the cross-border energy lease investments no longer meets the more likely than not standard of recognition for accounting purposes. Accordingly, PHI expects to record a non-cash charge of between $355 million and $380 million (after-tax) in the first quarter of 2013, 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 its estimated federal and state income tax obligations for the period over which the tax benefits may be disallowed. While the IRS could require PHI to pay a penalty of up to 20 percent 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 will be included in the charge expected to be recorded in the first quarter of 2013. PHI also is evaluating the liquidation of all or a portion of its remaining cross-border energy lease investments. The aggregate financial impact of a partial or complete liquidation of the cross-border leases is not determinable at this time, but could result in material gains or losses. PHI continues to weigh its options with respect to its litigation with the IRS.
For additional information concerning these cross-border energy lease investments, see Note (8), “Leasing Activities,” Note (16), “Commitments and Contingencies - PHI’s Cross-Border Energy Lease Investments,” and Note (20), “Subsequent Event,” to the consolidated financial statements of PHI.
Discontinued Operations
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 subsidiaries of Conectiv Energy Holding Company (collectively, Conectiv Energy). On July 1, 2010, PHI completed the sale of Conectiv Energy’s wholesale power generation business to Calpine Corporation (Calpine) for $1.64 billion. The disposition of Conectiv Energy’s remaining assets and businesses not included in the Calpine sale, including its load service supply contracts, energy hedging portfolio and certain tolling agreements, has been completed. The former operations of Conectiv Energy, which previously comprised a separate segment for financial reporting purposes, have been classified as a discontinued operation in PHI’s consolidated financial statements, and the business is no longer treated as a separate segment for financial reporting purposes. For further information on the former Conectiv Energy segment, see Note (19), “Discontinued Operations,” to the consolidated financial statements of PHI.
Regulation
The operations of PHI’s utility subsidiaries, including the rates and tariffs they are permitted to charge customers for the distribution and transmission 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 follows:
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Pepco’s electricity distribution operations are regulated in Maryland by the MPSC and in the District of Columbia by the DCPSC.
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DPL’s electricity distribution operations are regulated in Maryland by the MPSC and in Delaware by the DPSC.
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DPL’s natural gas distribution and intrastate transportation operations in Delaware are regulated by the DPSC.
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ACE’s electricity distribution operations are regulated by the NJBPU.
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Each utility subsidiary’s transmission facilities are regulated by FERC.
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DPL’s interstate transportation and wholesale sale of natural gas are regulated by FERC.
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Each utility subsidiary’s bulk power system is subject to reliability standards established by NERC.
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.
Regulatory Lag
An important factor in the ability of each of Pepco, DPL and ACE to earn its authorized rate of return is the willingness of applicable public service commissions to adequately recognize forward-looking costs in the utility’s rate structure in order to address the shortfall in revenues 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.” Each of Pepco, DPL and ACE is currently experiencing significant regulatory lag because its investment in the rate base and its operating expenses are outpacing revenue growth.
Each of PHI’s utility subsidiaries will continue to seek cost recovery from applicable public service commissions to reduce the effects of regulatory lag. 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. Until such time as any cost recovery mechanisms are approved, PHI’s utility subsidiaries plan to file rate cases at least annually in an effort to align more closely the revenue and cash flow levels of PHI’s utility subsidiaries with other operation and maintenance spending and capital investments. For additional discussion on this matter, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations - General Overview - Power Delivery Initiatives and Activities - Regulatory Lag.”
Reliability Task Forces
In July 2012, the Maryland governor signed an Executive Order directing his energy advisor, in collaboration with certain state agencies, to solicit input and recommendations from experts on how to improve the resiliency and reliability of the electric distribution system in Maryland (see Note (7), “Regulatory Matters - Reliability Task Forces” to the consolidated financial statements of PHI). 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, addresses the Grid Resiliency Task Force recommendations. See Note (7), “Regulatory Matters - Rate Proceedings - Pepco Electric Distribution Bases Rates,” to the consolidated financial statements of PHI. DPL will consider the Grid Resiliency Task Force recommendations in its next electric distribution base rate case expected to be filed with the MPSC in the first quarter of 2013.
In August 2012, the District of Columbia mayor issued an Executive Order establishing the Mayor’s Power Line Undergrounding Task Force. The purpose of the Power Line Undergrounding Task Force is 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 include legislative bodies, regulators, utility personnel, experts and other parties who could contribute in a meaningful way to the Power Line Undergrounding Task Force. The options that are available for financing these efforts are also to be evaluated to identify required legislative or regulatory actions to implement these recommendations. The results of this analysis are intended to help determine the path forward for these types of infrastructure improvements and additions. A written report from the Power Line Undergrounding Task Force setting forth the findings and recommendations was originally due on January 31, 2013 but has been extended to early March 2013.
MPSC New Generation Contract Requirement
In September 2009, the MPSC initiated an investigation into whether the electricity distribution companies (EDCs) in Maryland should be required to enter into long-term contracts with entities that construct, acquire or lease, and operate, new electric generation facilities in Maryland.
In April 2012, the MPSC issued an order determining that there is a need for one new power plant in the range of 650 to 700 megawatts (MW) beginning in 2015. The order requires certain Maryland EDCs, including Pepco and DPL, 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 acknowledges certain of the EDCs’ concerns about the requirements of the contract and directs them to negotiate with the winning bidder and submit any proposed changes in the contract to the MPSC for approval. The order further specifies that the EDCs entering into the contract will recover the associated costs, in amounts proportional to their relative SOS loads, through surcharges on their respective SOS customers.
In April 2012, a group of generating companies operating in the PJM region filed a complaint in the U.S. District Court for the District of Maryland challenging the MPSC’s order on the grounds that it violates the Commerce Clause and the Supremacy Clause of the U.S. Constitution. In May 2012, Pepco, DPL, and other parties filed notices of appeal in circuit courts in Maryland requesting judicial review of the MPSC’s order. These appeals have been consolidated in the Circuit Court for Baltimore City and have
been stayed pending the issuance of a final order from the MPSC approving the form of contract, including the payment obligations of the utilities in the event the utilities do not recover the costs for such payments from their customers.
Until the final form of the contract with the winning bidder and associated cost recovery are approved, PHI cannot predict (i) the extent of the negative effect that the order and, once finalized, the contract for new generation may have on PHI’s, Pepco’s and DPL’s balance sheets, as well as their respective credit metrics, as calculated by independent rating agencies that evaluate and rate PHI, Pepco and DPL and each of their debt issuances, (ii) the effect on Pepco’s and DPL’s ability to recover their associated costs of the contract for new generation if a significant number of SOS customers elect to buy their energy from alternative energy suppliers, and (iii) the effect of the order 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 (2), “Significant Accounting Policies - Consolidation of Variable Interest Entities - ACE Standard Offer Capacity Agreements” and Note (14), “Derivative Instruments and Hedging Activities.” ACE and the other New Jersey EDCs entered into the SOCAs under protest based on concerns about the potential cost to distribution customers. The dispute is pending before the NJBPU and has been referred to an Administrative Law Judge for further consideration.
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 constitutionality of the New Jersey law under which the SOCAs were established. In September 2012, the District Court denied motions for summary judgment filed by ACE and the other plaintiffs, as well as cross-motions filed by defendants. The litigation remains pending and trial is tentatively scheduled to begin in March 2013.
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 expands 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 (2), “Significant Accounting Policies - Consolidation of Variable Interest Entities - DPL Renewable Energy Transactions,” to the consolidated financial statements of PHI.
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, ACE and Pepco Energy Services. There are eight NERC regional oversight entities, including ReliabilityFirst Corporation (RFC), of which Pepco, DPL, ACE and Pepco Energy Services are members, and Northeast Power Coordinating Council (NPCC), of which Pepco Energy Services is a member. These oversight entities are charged with the day-to-day implementation and enforcement of NERC’s reliability standards, which impose certain operating, planning and cyber security requirements on the bulk power systems of Pepco, DPL, ACE and Pepco Energy Services. 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. Each of PHI’s utility subsidiaries and Pepco Energy Services 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 cyber security assets) subject to NERC’s cyber security standards. NERC is empowered to impose financial penalties, fines and other sanctions for non-compliance with certain rules and regulations.
Employees
At December 31, 2012, PHI had the following number of employees:
PHI’s subsidiaries are parties to five collective bargaining agreements with four local unions. All five collective bargaining agreements will expire within the next four years, including two agreements, covering approximately 977 employees in total, that expire in 2013. Collective bargaining agreements are generally renegotiated every three to five years.
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 (16), “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 $12 million in 2013, $7 million in each of 2014 and 2015, and $2 million in each of 2016 and 2017. Because of a comprehensive review of environmental control facilities undertaken in 2012, during which a substantially greater number of replacements of control facilities were identified, the estimated spending for each of these years is significantly higher than the estimates reported last year. 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 environmental regulations prospectively 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 deactivation of the Pepco Energy Services generating facilities, both of which are considered major sources under the CAA, in June 2012, Pepco Energy Services requested exclusion for these major sources from the CAA Title V operating permits. For the remaining minor sources (e.g., Pepco-operated emergency generators) currently covered by a CAA Title V operating permit, Pepco intends to secure minor source permits.
Sulfur Dioxide and Nitrogen Oxide Emissions
The acid rain provisions of the Clean Air Act regulate total sulfur dioxide (SO2) emissions from affected generating units and allocate “allowances” to each affected unit that permit the unit to emit a specified amount of SO2. Until their deactivation in 2012, the generating facilities of Pepco Energy Services that required allowances used allocated allowances or allowances acquired, as necessary, in the open market to satisfy the applicable regulatory requirements.
Federal Regional Haze Rule
The federal Regional Haze Rule was adopted by the U.S. Environmental Protection Agency (EPA) to address a type of visibility impairment known as regional haze created by the emission of specified pollutants by certain types of large stationary sources. The regulation requires installation of best available retrofit technology to boilers that (i) emit 250 tons or more per year of a visibility-impairing air pollutant, (ii) were placed in service between 1962 and 1977, and (iii) may reasonably be anticipated to cause or contribute to visibility impairment in any federally protected park or wilderness area. Pepco Energy Services’ Benning Road generating units were subject to this regulation for particulate matter less than ten microns in diameter and for SO2 and nitrogen oxide to the extent not addressed by other regulations. Under Pepco Energy Services’ current operating permit issued by the District of Columbia Department of the Environment (DDOE), the Benning Road generating units are not required to implement any remedial actions because the facilities were deactivated in 2012.
Pepco Energy Services’ other generating units are not subject to the Regional Haze Rule.
Hazardous Air Pollutant Emissions
In December 2011, EPA finalized a rule to reduce the emission of toxic air pollutants from generating facilities. The Mercury and Air Toxics Standards will reduce emissions of heavy metals, including mercury, arsenic, chromium and nickel, as well as emissions of acid gases, including hydrochloric and hydrofluoric acid. Because existing generating sources generally have up to four years from the Standards’ effective date to comply with the Mercury and Air Toxics Standards, this rule will not impact the Benning Road or Buzzard Point generating facilities, which were retired in June 2012.
Greenhouse Gas Emissions Reporting
In October 2009, 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 generating units’ deactivation in June 2012, Pepco Energy Services reported CO2, methane and nitrous oxide for its Benning Road units.
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DPL currently reports 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 distributes to its customers. Beginning in September 2012, DPL is required to report fugitive CO2 and methane emissions for its gas distribution operations for the previous calendar year (hence, the 2012 report contained data from calendar year 2011). DPL’s liquefied natural gas storage facility does not meet the reporting threshold (25,000 metric tons) for fugitive emissions.
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Beginning in September 2012, 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 in July 2009, which authorizes discharges from the Benning Road facility, including the now deactivated generating station. 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 studies to identify the source of the regulated substances to determine appropriate best management practices for minimizing the presence of the substances in storm water. The initial study reports were completed in May 2012. Pepco has completed the implementation of the first two phases of the best management practices recommended in the study reports (consisting principally of installing screens and booms to capture contaminants from storm water flows, removing stored equipment and materials 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 initial best management practices.
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 2012 for Pepco, DPL and ACE collectively were approximately $8 million, as of December 31, 2012. In addition to the costs to comply with EPA’s oil pollution prevention regulations, PHI companies project expenditures of approximately $9 million over the next four years, which amount is included in the capital expenditure projection set forth in “Environmental Matters” above, 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 (CERCLA) of 1980 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. Pepco, DPL and ACE each has been named by EPA or a state environmental agency as a potentially responsible party in pending proceedings involving certain contaminated sites. See 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 (16), “Commitments and Contingencies - Environmental Matters,” to the consolidated financial statements of PHI.
Executive Officers of PHI
The names of the executive officers of PHI, their ages and the positions they held as of February 27, 2013, 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.
(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 DPL Inc. and The Dayton Power and Light Company 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 was Vice President of Public Policy from 2009 to 2012 and President, ACE from 2005 to 2009.
(6) Mr. Emge was Senior Vice President and General Counsel from March 2008 through September 2012. Prior to such time, Mr. Emge was Vice President, Legal Services of PHI from August 2002 until March 2008. Mr. Emge has served as General Counsel of ACE, DPL and Pepco from August 2002 to September 2012 and as Senior Vice President of Pepco and DPL from March 2009 to September 2012. Mr. Emge has announced that he will retire from PHI effective April 1, 2013.
(7) Ms. Perry was Senior Vice President Regulatory Affairs and Corporate Citizenship from October 2002 through August 2012. Ms. Perry has announced that she will retire from PHI effective June 1, 2013.
(8) 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.
(9) 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 may significantly affect 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 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. The MPSC also stated that it would consider in Pepco’s latest Maryland retail base rate case the potential disallowance of the recovery of costs which may be determined to have been imprudently incurred. In this base rate case, the MPSC set rates at a level that was not adequate to recover costs that Pepco will incur during the period the rates are in effect.
NERC’s eight regional oversight entities, including RFC, of which Pepco, DPL, ACE and Pepco Energy Services are members, and 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 to obtain timely recognition of costs in its 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, ACE and DPL 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.
PHI’s utility subsidiaries are also exposed to “regulatory lag,” which refers to a shortfall in revenues 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 investment in the rate base and their operating expenses are outpacing 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.
In recent rate cases, Pepco (in the District of Columbia and Maryland), DPL (in Maryland and Delaware) and ACE (in New Jersey) have proposed mechanisms that would track reliability and other expenses and permit each utility to make adjustments in its approved rates to account for prudent investments as made, thereby seeking to reduce the magnitude of regulatory lag. However, the MPSC and the DCPSC did not approve in substantial part requests by Pepco (in Maryland and the District of Columbia) and DPL (in Maryland) to implement regulatory lag mitigation mechanisms. In Delaware, a settlement agreement approved by the DPSC in DPL’s electric distribution base rate case did not include these mechanisms, but it did provide that the parties will meet and discuss alternate regulatory methodologies for the mitigation of regulatory lag. In New Jersey, the NJBPU has previously approved a similar mechanism; however, ACE agreed as part of the settlement of its electric distribution base rate case to withdraw without
prejudice its filing with the NJBPU to extend and expand that previously approved mechanism. There can be no assurance that any of the outstanding proposals or any other attempts by Pepco, DPL and ACE to mitigate regulatory lag will be approved, or that even if approved, the rate recovery mechanisms will fully mitigate the effects of regulatory lag. If necessary to address in whole or in part the problem of regulatory lag, each utility can file (and each utility presently intends to file) base rate cases annually (or even more frequently) to seek to align its revenue and related cash flow levels allowed by the applicable public service commissions with operation and maintenance spending and capital investments. The inability of PHI’s utility subsidiaries to obtain relief from the impact of regulatory lag through base rate cases or otherwise may have an 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 and the retail energy supply business of Pepco Energy Services 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.
The retail energy supply business of Pepco Energy Services, the wind-down of which is expected to be completed at the latest in 2014, generally produces higher gross margins when temperatures are colder than normal in winter or warmer than normal in summer, and less gross margin when weather conditions are milder than normal in the winter and cooler than normal in the summer. The energy services business of Pepco Energy Services, which includes providing energy savings performance contracting services principally to federal, state and local government customers, and designing, constructing and operating combined heat and power energy plants for customers, is not seasonal.
Facilities 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 involves many risks, including the breakdown or failure of equipment, accidents, labor disputes, theft of copper wire or pipe, scams, failure of software or hardware, and performance below expected levels. Older facilities 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 can reduce revenues and result in the incurrence of additional expenses that may not be recoverable from customers or through insurance.
PHI is replacing customers’ existing electric and gas meters with an AMI system. In addition to the replacement of existing meters, the AMI system involves the construction of a wireless network across the service territories of PHI’s utility subsidiaries and the implementation and integration of new and existing information technology systems to collect and manage data made available by the advanced meters. 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, 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 or increased regulatory oversight. Unfavorable regulatory outcomes can include 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 enhanced 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, the MPSC has adopted new rules (which became effective in May 2012), establishing reliability and customer service regulations. Furthermore, in its most recent electric distribution base rate case filing, Pepco has proposed (subject to MPSC review and approval) 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 provides a credit to customers of up to $1 million in total if Pepco does not meet at least the minimum targets.
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 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.
A recent case law decision involving lease transactions could impact our ongoing litigation against the IRS involving certain cross-border energy lease investments, could cause us to seek to unwind those lease investments, which may have a material negative impact on our results of operations and financial condition. (PHI only)
PCI maintains a portfolio of cross-border energy lease investments involving public utility assets located outside of the United States, which as of December 31, 2012, had a net investment value of approximately $1.2 billion and from which PHI currently derives approximately $43 million per year in tax benefits in the form of interest and depreciation deductions in excess of rental income. PHI’s cross-border energy lease investments, each of which is 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. PHI commenced litigation in the U.S. Court of Federal Claims in January 2012 to review certain tax benefits claimed by PHI on its federal tax returns for 2001 and 2002.
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 a lease-in, lease-out transaction. Under applicable accounting standards, the financial statement recognition of the tax benefits of PHI’s uncertain tax position associated with the cross-border energy lease investments is permitted only if it is more likely than not that the position will be sustained. Further, the carrying value of the cross-border energy lease investments must be recalculated if there is a change or a projected change in the timing of the estimated tax benefits generated from these investments.
After analyzing the Consolidated Edison ruling, PHI has determined that its tax position with respect to the tax benefits associated with the cross-border energy leases no longer meets the more-likely-than-not standard of recognition for accounting purposes. Accordingly, PHI expects to record a non-cash charge of between $355 million and $380 million (after-tax) in the first quarter of 2013, 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 its estimated federal and state income tax obligations for the period over which the tax benefits may be disallowed.
After accounting for certain tax benefits arising from matters unrelated to these lease investments, PHI estimates that it would be obligated to pay between $170 million and $200 million in additional federal and state taxes and between $50 million and $60 million of interest on the additional federal and state taxes as of March 31, 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. PHI continues to weigh its options with respect to its litigation with the IRS.
PHI is also evaluating the liquidation of all or a portion of its remaining cross-border energy lease investments. While PHI estimates that a complete liquidation could be accomplished within one year, the liquidation of any of the lease investments would generally require the consent of the counterparty to that lease investment, and negotiations with the respective lessee or a purchaser of the lease investment may take longer than anticipated. PHI is unable to presently estimate the amount of proceeds that would be realized upon the liquidation of the lease portfolio in whole or in part. Furthermore, even if PHI is able to successfully liquidate a lease investment, it may incur losses and additional earnings charges if the net proceeds from such liquidation were less than the then carrying value of the liquidated lease investment. As a result of these and other uncertainties, the aggregate financial impact of a partial or complete liquidation of the lease investments by PHI cannot be presently determined at this time, but PHI believes that any such impact on PHI’s consolidated results of operations and financial condition may be material.
The transmission facilities of Power Delivery 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 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 and conservation measures may adversely affect Power Delivery.
Increased conservation and end-user generation made possible through advances in technology could reduce demand for the transmission and distribution facilities of Power Delivery and adversely affect PHI and one or more of its utility subsidiaries. Alternative technologies to produce electricity, the development of which has expanded due to climate change and other environmental concerns, could ultimately provide alternative sources of electricity. As these new technologies are developed and become available, the quantity and pattern 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 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, 2012, 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.
One of the collective bargaining agreements to which PHI’s subsidiaries are a party was set to expire on February 1, 2013 and a second agreement will expire on June 25, 2013. The parties amended the agreement that was to expire in February to extend its expiration date, which is now currently March 1, 2013. Further extensions of this expiration date may be possible. Though PHI believes that a protracted work stoppage is 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 services business of Pepco Energy Services is highly competitive and is exposed to customer concentration. (PHI only)
Unlike PHI’s regulated business, Pepco Energy Services’ business is highly competitive and is not assured a rate of return on capital investments through a predetermined rate structure. This competition puts downward pressure on margins and increases costs. The energy services business is impacted by new entrants into the market, energy prices, and general economic conditions. These factors may negatively impact 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 services 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 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, or “sequestration,” becomes 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. The American Taxpayer Relief Act of 2012 does not address spending issues or sequestration issues that Congress intends to address later in 2013. Substantial Federal spending cuts could make it more difficult for Pepco Energy Services to enter into new energy services performance contracts with Federal, state and local government agencies and thus could have a material adverse effect on the energy savings performance services business of Pepco Energy Services.
In addition, revenues associated with Pepco Energy Services’ combined heat and power generating plant in Atlantic City, New Jersey are concentrated with a few major customers in the hotel and casino industry. Pepco Energy Services has long-term contracts with these customers, and for the largest customer, the contracts expire in 2017. Pepco Energy Services is exposed to the risk that it is not able to renew these contracts or that the contract counterparties fail to perform, and in either case, Pepco Energy Services’ results of operations and financial condition could be adversely affected.
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 adversely affect PHI’s results of operations, cash flow and financial condition.
The inability of Pepco Energy Services to perform its obligations in connection with its energy services construction projects may have a material adverse effect on PHI. (PHI only)
Projects undertaken by Pepco Energy Services include design, construction, startup and testing activities related to combined heat and power and other energy facilities, 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. Ultimately, however, Pepco Energy Services will bear responsibility in the event of unexcused failures by these subcontractors and vendors, as well as other third parties, to perform in accordance with the terms of these contracts or otherwise pursuant to the expectations of the parties. When such events occur, Pepco Energy Services may experience reputational harm and claims for money damages and other relief, which could, depending upon the cause and severity of the failure of performance, adversely affect 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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our 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 our 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, including risks related to economic conditions and changes in demand for electricity and natural gas in the service territories of PHI’s utility subsidiaries, 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.
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. For example, Pepco Energy Services has entered into commercial transactions for the purchase and sale of electricity and natural gas, as well as derivative and other transactions to manage the risk of commodity price fluctuations. Under these arrangements, Pepco Energy Services is exposed to the
risk that the counterparty may fail to perform its obligation to make or take delivery under the contract, fail to make a required payment or fail to return collateral posted by Pepco Energy Services when the counterparty is required to do so. In addition, PHI’s PCI subsidiary has entered into several cross-border energy lease investments located outside the United States. Under these leases, PCI is exposed to the risk that the counterparty may fail to make lease payments on time or at all.
Many of these contracts provide for PHI or a subsidiary to receive collateral or other types of performance assurance from the counterparty, 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 can prevent the counterparty from meeting its collateral obligations or degrade the value of letters of credit and guarantees as a result of the lowered rating or insolvency of the issuer or guarantor. 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 held or payments received. In the case of PCI, the fact that the counterparties are located outside the United States could make it more difficult for PCI to seek redress or obtain a judgment or compensation against a foreign counterparty for any breach of the lease agreement by that counterparty.
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.
Mark-to-market accounting treatment for instruments Pepco Energy Services uses to hedge the cost of supply used to satisfy retail customer load obligations could cause earnings volatility. (PHI only)
Pepco Energy Services purchases energy commodity contracts in the form of electricity and natural gas futures, swaps, options and forward contracts to hedge commodity price risk in connection with the purchase of natural gas and electricity for delivery to customers. Certain commodity contracts that do not qualify as cash flow hedges of forecasted transactions or do not meet the requirements for normal purchase and normal sale accounting are marked to market through current earnings. Any change in the fair value of the transactions used to hedge price risk that do not qualify for hedge accounting and receive mark-to-market accounting treatment will be reflected in PHI’s current earnings without any offsetting change in the fair value of its retail load obligations until the settlement date of these contracts in future periods. Pepco Energy Services has discontinued hedge accounting, so PHI’s earnings could be more volatile due to the mark-to-market accounting treatment associated with these commodity contracts. As of December 31, 2012, the commodity contracts that currently qualify for normal purchase and normal sale accounting and an exception from mark-to-market accounting are in a significant net loss position on a
fair value basis. If PHI could no longer sustain the normal purchase and normal sale designation for these contracts, it would be required to recognize these net losses and future changes in the fair value in earnings, which could result in greater earnings volatility. It is anticipated that the notional value and the fair value of the supply contracts will decrease considerably during 2013 with the wind-down of the retail energy business.
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 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, laws and regulations, taxation requirements and federal securities laws and regulations 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 the companies might incur.
PHI and its subsidiaries, including Pepco, DPL and ACE, 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, such as weather related casualties, may not be insurable. In the case of loss or damage to property, plant or equipment, there is no assurance that the insurance proceeds received, if any, will be sufficient to cover the entire cost of replacement or repair.
PHI and its subsidiaries are dependent on obtaining access to capital markets and bank financing to satisfy their capital and liquidity requirements. The inability to obtain required financing would have an adverse effect on their respective businesses.
PHI, Pepco, DPL and ACE each have significant capital requirements, including the funding of construction expenditures and the refinancing of maturing debt. These companies rely primarily on cash flow from operations and access to the capital markets to meet these financing needs. The operating activities of PHI and its subsidiaries also require access to short-term money markets and bank financing as sources of liquidity that are not met by cash flow 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 one or more financial markets. Events that could cause or contribute to a disruption of the financial markets include, but are not limited to:
•
a recession or an economic slowdown;
•
the bankruptcy of one or more energy companies or financial institutions;
•
a significant change in energy prices;
•
a terrorist or cyber attack or threatened attacks;
•
the outbreak of a pandemic or other similar event; or
•
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 PHI, Pepco, DPL and ACE, 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 PHI, Pepco, DPL or ACE under review for potential downgrade in certain circumstances or if any of them seek to take certain actions. 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 collateral requirements of Pepco Energy Services’ retail energy supply business also are determined in part by the unsecured debt rating of PHI. Negative ratings actions by one or more of the credit rating agencies resulting from a change in PHI’s or the utility’s operating results or prospects would increase funding costs. Any increases in collateral requirements could make such contractual obligations more expensive and make financing more difficult to obtain.
The agreements that govern PHI’s primary credit facility and its term loan agreement 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 PHI’s term loan agreement entered into in April 2012, 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 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 the affected 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, a further write-down of PHI’s 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 restrictions on its ability to operate its business in its sole discretion 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 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 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, 2012, 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 a decline in PHI’s stock price causing market capitalization to fall below book value, an adverse change in business conditions or an adverse regulatory action. 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 and results of operations, but would not have an impact on 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 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 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 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 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. 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. 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
Generating Facilities
The following table identifies the electric generating facilities owned by PHI’s subsidiaries at December 31, 2012.
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.
Transmission and Distribution Systems
On a combined basis, the electric transmission and distribution systems owned by Pepco, DPL and ACE at December 31, 2012, 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 110 pipeline miles of natural gas transmission mains, 1,927 pipeline miles of natural gas distribution mains, and 1,313 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 (11), “Debt” to the consolidated financial statements of PHI.
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 (16), “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 (13), “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 (15), “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 (14), “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 15, 2013, there were 49,824 holders of record of Pepco Holdings common stock.
Dividends
On January 24, 2013, the PHI Board of Directors declared a dividend on common stock of 27 cents per share payable March 28, 2013, to shareholders of record on March 11, 2013.
See “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity - Capital Requirements - Dividends,” and Note (13), “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 2012, PHI made capital contributions of $50 million and $60 million to Pepco and DPL, respectively, and in 2011, PHI made a capital contribution to ACE of $60 million.
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 PHI (through Conectiv), during each quarter in the last two years. Dividends received by PHI in 2012 and 2011 were used to support the payment of its common stock dividend. Dividends paid by ACE in 2012 were used by Conectiv to pay down its short-term debt owed to PHI and in 2011 were passed through to PHI to support the payment of its common stock dividend.
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 the years ended December 31, 2012, 2011, 2010, 2009, and 2008, derived from PHI’s audited financial statements.
PEPCO HOLDINGS CONSOLIDATED FINANCIAL HIGHLIGHTS
(a) 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.
(b) Includes $39 million pre-tax ($9 million after-tax) gain from the early termination of finance leases held in trust.
(c) Includes a $16 million charge related to the recognition of the tax consequences associated with the early termination of finance leases held in trust.
(d) Includes $39 million pre-tax ($3 million after-tax) gain from the early termination of certain cross-border energy leases held in trust.
(e) Includes tax benefits of $14 million primarily associated with an interest benefit related to federal tax liabilities and a $22 million charge related to the recognition of the tax consequences associated with the early termination of cross-border energy leases held in trust.
(f) Includes $30 million ($18 million after-tax) related to a restructuring charge and an $11 million ($6 million after-tax) charge related to the effects of Pepco divestiture-related claims.
(g) Includes a loss on extinguishment of debt of $189 million ($113 million after-tax).
(h) Includes $12 million of net Federal and state income tax benefits primarily related to adjustments of accrued interest on uncertain and effectively settled tax positions, $14 million of state tax benefits resulting from the restructuring of certain PHI subsidiaries and $17 million of state income tax benefits associated with the loss on extinguishment of debt.
(i) Includes $40 million ($24 million after-tax) gain related to the effects of Pepco divestiture-related claims.
(j) Includes a $13 million state income tax benefit (after Federal tax) related to a change in the state income tax reporting for the disposition of certain assets in prior years and a benefit of $6 million related to additional analysis of current and deferred tax balances completed in 2009.
(k) Includes a pre-tax charge of $124 million ($86 million after-tax) related to the adjustment to the equity value of cross-border energy lease investments, and included in Income Taxes is a $7 million after-tax charge for the additional interest accrued on the related tax obligation.
(l) Includes $18 million of after-tax net interest income on uncertain and effectively settled tax positions (primarily associated with the reversal of previously accrued interest payable resulting from the tentative settlement with the IRS on the mixed service cost issue and a claim made with the IRS related to the tax reporting for fuel over- and under-recoveries) and a benefit of $8 million (including a $3 million correction of prior period errors) related to additional analysis of deferred tax balances completed in 2008.
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 the distribution and supply of natural gas (Power Delivery). Through Pepco Energy Services, PHI provides energy savings performance contracting services, high voltage underground transmission cabling, construction and operations of combined heat and power and central energy plants and is in the process of winding down its competitive electricity and natural gas retail supply business.
Each of Power Delivery and Pepco Energy Services constitutes a separate segment for financial reporting purposes. A third segment, Other Non-Regulated, consists of a portfolio of cross-border energy lease investments.
The following table sets forth the percentage contributions to consolidated operating revenue and operating income from continuing operations attributable to PHI segments:
(a) For presentation purposes, this category includes Other Non-Regulated and Corporate and Other.
(b) Includes gains on early termination of finance leases held in trust that represent 6% of the consolidated operating income in 2012 and 2011.
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. Power Delivery represents a single operating segment for financial reporting purposes.
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. In this report, these supply service obligations are referred to generally as Default Electricity Supply.
PEPCO HOLDINGS
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, 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 for retail customers 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.
Since 2010, PHI has implemented comprehensive reliability enhancement plans which include various initiatives to improve electrical system reliability, including:
•
the identification and upgrading of under-performing feeder lines;
•
the addition of new facilities to support load;
•
the installation of distribution automation systems on both the overhead and underground network systems;
•
the rejuvenation and replacement of underground residential cables;
•
selective undergrounding of portions of existing above-ground primary feeder lines, where appropriate to improve reliability;
•
improvements to substation supply lines; and
•
enhanced vegetation management.
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.”
PEPCO HOLDINGS
Power Delivery Initiatives and Activities
Smart Grid
PHI is building a “smart grid” which is designed to meet the challenges of rising energy costs, concerns about the environment, reliability improvement, providing timely and accurate customer information and meeting government energy reduction goals. The installation of smart meters is subject to the approval of applicable state regulators. The DCPSC, MPSC and DPSC have approved the creation of regulatory assets to defer AMI costs between rate cases, as well as the accrual of returns on the deferred costs. Thus, these costs will be recovered in the future through base rates. Approval of AMI has been deferred by the New Jersey Board of Public Utilities (NJBPU) for ACE in New Jersey.
In April 2010, PHI signed agreements to formalize $168 million in awards from the U.S. Department of Energy to support the rollout of smart grid initiatives. In the Pepco service area, $149 million was awarded for AMI, direct load control, distribution automation and communications infrastructure, while in the Atlantic City Electric service area, $19 million was awarded for direct load control, distribution automation and communications infrastructure. The grants effectively reduce the project costs of these initiatives. The cumulative award payments received by Pepco and ACE as of December 31, 2012, were $115 million and $13 million, respectively.
For projected 2013 through 2017 capital expenditures associated with the smart grid, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity - Capital Requirements.”
Regulatory Lag
An important factor in the ability of each of Pepco, DPL and ACE to earn its authorized rate of return is the willingness of applicable public service commissions to adequately recognize forward-looking costs in the utility’s rate structure in order to address the shortfall in revenues 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.” Each of Pepco, DPL and ACE is currently experiencing significant regulatory lag because its investment in the rate base and its operating expenses are outpacing revenue growth.
In an effort to minimize the effects of regulatory lag, Pepco’s and DPL’s Delaware, District of Columbia and Maryland base rate case filings in 2011 each included a request for approval from the applicable state regulatory commissions of (i) a reliability investment recovery mechanism (RIM) to recover reliability-related capital expenditures incurred between base rate cases and (ii) the use by the applicable utility of fully forecasted test years in future base rate cases. See Note (7), “Regulatory Matters - Rate Proceedings,” to the consolidated financial statements of PHI for a discussion of each of these mechanisms. In both the Pepco and DPL base rate case orders in Maryland, the MPSC did not approve Pepco’s and DPL’s requests to implement the RIM and did not endorse the use by Pepco and DPL of fully forecasted test years in future rate cases. However, the MPSC did permit an adjustment to the rate base of Pepco and DPL to reflect the actual cost of reliability plant additions outside the test year. In the District of Columbia, the DCPSC denied Pepco’s request for approval of a RIM, and reserved final judgment on the appropriateness of the use by Pepco of a fully forecasted test year in future rate cases. In Delaware, a settlement agreement approved by the DPSC in DPL’s electric distribution base rate case did not include approval of a RIM or the use of fully forecasted test years in future DPL rate cases, but it did provide that the parties will meet and discuss alternate regulatory methodologies for the mitigation of regulatory lag.
Each of PHI’s utility subsidiaries will continue to seek cost recovery from applicable public service commissions to reduce the effects of regulatory lag. 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. Until such time as any cost recovery mechanisms are approved, PHI’s utility subsidiaries plan to file rate cases at least annually in an effort to align more closely the revenue and cash flow levels of PHI’s utility subsidiaries with other operation and maintenance spending and capital investments. In addition to the electric distribution base rate cases filed by Pepco and to be filed by DPL in the first quarter of 2013 in Maryland, DPL filed a natural gas distribution case on December 7, 2012 and ACE filed an electric distribution base rate case on December 11, 2012. Additionally, Pepco intends to file its next electric distribution base rate case with the DCPSC, and DPL with the DPSC, in the first quarter of 2013.
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.
PHI had included in its five-year projected capital expenditures $205 million of MAPP-related expenditures for the period from 2012 to 2016. PHI has updated its five-year projected capital expenditures to remove MAPP-related expenditures to reflect the PJM decision. See “Capital Resources and Liquidity - Capital Requirements - Capital Expenditures” for a discussion of PHI’s projected capital expenditures. As of December 31, 2012, PHI’s total capital expenditures related to the MAPP project were approximately $102 million. In a 2008 FERC order approving incentives for the MAPP project, FERC authorized the recovery of prudently incurred abandoned costs in connection with the MAPP project. Consistent with this order, on December 21, 2012, PHI submitted a filing to FERC seeking recovery over a period of five years of approximately $88 million of abandoned MAPP capital expenditures. 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 (see Note (7), “Regulatory Matters - MAPP Project” to the consolidated financial statements of PHI for additional information).
As of December 31, 2012, PHI had placed in service approximately $11 million of its total capital expenditures with respect to the MAPP project, which represented upgrades of existing substation assets that were expected to support the MAPP transmission line, transferred approximately $3 million of materials to inventories for use on other projects and reclassified the remaining $88 million of capital expenditures to a regulatory asset. The regulatory asset includes the costs of land, land rights, supplies and materials, engineering and design, environmental services, and project management and administration. PHI intends to reduce the regulatory asset by any amounts recovered from the sale or alternative use of the land, land rights, supplies and materials.
PEPCO HOLDINGS
Pepco Energy Services
Since 2010, Pepco Energy Services has been focused on growing its energy savings performance contracting services business in the federal, state and local government markets. Activity in the state and local government markets, which are Pepco Energy Services’ largest markets, slowed significantly in 2012, due to, among other factors, lower energy prices that have lessened the economic benefits of energy savings projects and the reluctance of state and local governments to incur new debt associated with these projects. As a result of the slowdown, Pepco Energy Services believes that new business in these markets will remain challenged for the foreseeable future. Consequently, Pepco Energy Services reduced resources and personnel and limited geographic expansion in the energy savings services business, and has refocused its existing resources on developing business in the federal government market and continuing to pursue combined heat and power projects.
PHI guarantees the obligations of Pepco Energy Services under certain of its energy savings performance, combined heat and power and construction contracts. At December 31, 2012, PHI’s guarantees of Pepco Energy Services’ obligations under these contracts totaled $198 million.
Pepco Energy Services also has historically been engaged in the business of providing retail energy supply services, consisting of the sale of electricity, including electricity from renewable resources, primarily to commercial, industrial and government customers located in the mid-Atlantic and northeastern regions of the United States, as well as Texas and Illinois, and the sale of natural gas to customers located primarily in the mid-Atlantic region. In December 2009, PHI announced that it will wind down the retail energy supply component of the Pepco Energy Services business.
To effectuate the wind-down of the retail energy supply business, Pepco Energy Services is continuing to fulfill all of its commercial and regulatory obligations and perform its customer service functions to ensure that it meets the needs of its existing customers, but is not entering into any new retail energy supply contracts. Operating revenues related to the retail energy supply business for the years ended December 31, 2012, 2011 and 2010 were $418 million, $962 million and $1,609 million, respectively, and operating income for the same periods was $46 million, $11 million and $59 million, respectively.
PHI expects the operating results of the retail energy supply business, excluding the effects of unrealized mark-to-market gains or losses on derivatives contracts, to have immaterial losses in 2013 and 2014. Substantially all of Pepco Energy Services’ retail customer obligations will be fully performed by June 1, 2014. PHI is reviewing strategic alternatives to accelerate into 2013 the completion of the wind-down of its remaining portfolio of retail energy contracts.
In connection with the operation of the retail energy supply business, as of December 31, 2012 and 2011, Pepco Energy Services had net collateral pledged to counterparties, primarily in connection with the instruments it uses to hedge commodity price risk, of approximately $26 million and $113 million, respectively. The collateral pledged as of December 31, 2012 included less than $1 million in the form of letters of credit and $25 million posted in cash. Pepco Energy Services does not expect to have any such collateral obligations beyond June 1, 2014.
Pepco Energy Services’ remaining businesses will not be affected by the wind-down of the retail energy supply business.
During 2012, Pepco Energy Services deactivated its Buzzard Point and Benning Road oil-fired generation facilities. Pepco Energy Services has 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 that the facilities require only essential maintenance until they are completely decommissioned.
PEPCO HOLDINGS
Other Non-Regulated
Through its subsidiary Potomac Capital Investment Corporation and its subsidiaries, PHI maintains a portfolio of cross-border energy lease investments with a net investment value at December 31, 2012 of approximately $1.2 billion. This activity comprises the “Other Non-Regulated” segment. PHI expects to record a non-cash charge of between $355 million and $380 million (after-tax) in the first quarter of 2013, 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 resulting from the disallowance of certain tax benefits associated with the cross-border energy lease investments. PHI also is evaluating the liquidation of all or a portion of its remaining cross-border energy lease investments. The aggregate financial impact of a partial or complete liquidation of the cross-border leases is not determinable at this time, but could result in material gains or losses. Further, the earnings from the cross-border energy leases represent a substantial portion of the “Other Non-Regulated” segment’s earnings and a partial or complete liquidation of the leases would reduce significantly the earnings of the segment. For additional information concerning these cross-border energy lease investments, see Note (8), “Leasing Activities - Investment in Finance Leases Held in Trust,” Note (16), “Commitments and Contingencies - PHI’s Cross-Border Energy Lease Investments,” and Note (20), “Subsequent Event” to the consolidated financial statements of PHI.
Discontinued Operations
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 not included in the Calpine sale, including its load service supply contracts, energy hedging portfolio and certain tolling agreements, has been completed. The former operations of Conectiv Energy, which previously comprised a separate segment for financial reporting purposes, have been classified as a discontinued operation in PHI’s consolidated financial statements, and the business is no longer treated as a separate segment for financial reporting purposes. Accordingly, in this Management’s Discussion and Analysis of Financial Condition and Results of Operations, all references to continuing operations exclude the operations of the former Conectiv Energy segment.
Earnings Overview
Year Ended December 31, 2012 Compared to Year Ended December 31, 2011
Net income from continuing operations for the year ended December 31, 2012 was $285 million, or $1.25 per share ($1.24 per share on a diluted basis), compared to $260 million, or $1.15 per share ($1.15 per share on a diluted basis), for the year ended December 31, 2011.
Net loss from discontinued operations for the year ended December 31, 2011 was $3 million, or $0.01 per share.
PEPCO HOLDINGS
Discussion of Operating Segment Net Income Variances:
Power Delivery’s $25 million increase in earnings was primarily due to the following:
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An increase of $27 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) and the DPL gas distribution rate increase in Delaware.
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An increase of $15 million from higher transmission revenue, primarily attributable to higher rates effective June 1, 2012 and June 1, 2011, related to increases in transmission plant investment.
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An increase of $5 million primarily due to the net effect of income tax benefits resulting from changes in estimates and interest related to uncertain and effectively settled income tax positions.
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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 $7 million associated with Default Electricity Supply margins for Pepco and DPL, primarily due to regulatory approvals by the respective public service commissions in the District of Columbia, Maryland and Delaware in 2011 of adjustments providing for recovery of higher cash working capital, administrative costs and miscellaneous taxes, partially offset by favorable Default Electricity Supply margin adjustments in 2012 related to the under-recognition of allowed revenues on procurement and transmission taxes in Delaware.
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A decrease of $7 million due to higher operation and maintenance expenses, primarily associated with higher customer support service and system support costs and higher employee-related costs in 2012, and a reduction in self-insurance reserves in 2011, partially offset by regulatory approval in 2012 for the establishment of regulatory assets for recovery of 2011 storm restoration costs and regulatory expenses.
Pepco Energy Services’ $6 million decrease in earnings was primarily due to lower energy services construction activity, the closure of its oil-fired generation facilities and asset impairment charges in 2012, partially offset by higher gross margins in the retail energy supply business attributable to mark-to-market accounting.
Other Non-Regulated’s $5 million increase in earnings was primarily due to an increase of $6 million in gains from early terminations of certain cross-border energy leases ($9 million in 2012, as compared to $3 million in 2011), partially offset by favorable income tax adjustments related to uncertain and effectively settled income tax positions in 2011.
Corporate and Other’s $1 million decrease in net loss was primarily due to the write-off of an equity investment in 2011, partially offset by higher interest expense in 2012.
PEPCO HOLDINGS
The following results of operations discussion is for the year ended December 31, 2012, compared 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 Business
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.
PEPCO HOLDINGS
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
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:
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Commercial activities in the region include banking and other professional services, government, insurance, real estate, shopping malls, casinos, stand alone construction and tourism.
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Industrial activities in the region include chemical, glass, pharmaceutical, steel manufacturing, food processing and oil refining.
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.
PEPCO HOLDINGS
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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 (related to the New Jersey Societal Benefit Program, a 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 $7 million due to Pepco customer growth in 2012, 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 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.
PEPCO HOLDINGS
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.
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
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 and other professional services, government, insurance, real estate, shopping malls and stand alone construction.
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Industrial activities in the region include chemical and pharmaceutical.
PEPCO HOLDINGS
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 Gas Cost Rate (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.
Pepco Energy Services
Pepco Energy Services’ operating revenue decreased by $607 million primarily due to:
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A decrease of $534 million due to lower retail supply sales volume primarily attributable to the ongoing wind-down of the retail energy supply business.
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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 $18 million due to decreased energy services 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 Business
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.
PEPCO HOLDINGS
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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).
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 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 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 $598 million primarily due to:
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A decrease of $379 million due to lower volumes of electricity purchased to serve decreased retail electricity sales volumes as a result of the ongoing wind-down of the retail energy supply business.
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A decrease of $189 million due to lower volumes of gas purchased to serve decreased retail gas sales volumes as a result of the ongoing wind-down of the retail energy supply business.
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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 $2 million due to lower energy services construction activity partially offset by costs associated with increased high voltage construction activity and existing energy services contracts.
PEPCO HOLDINGS
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.
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.
PEPCO HOLDINGS
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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 currently 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 currently 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 currently 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 $13 million primarily due to the closing of the oil-fired generation facilities in the second quarter of 2012 and the wind-down of the retail energy supply business.
Depreciation and Amortization
Depreciation and Amortization expense increased by $28 million to $454 million in 2012 from $426 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).
PEPCO HOLDINGS
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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).
Gains on Early Terminations of Finance Leases Held in Trust
PHI’s operating expenses include a $39 million pre-tax gain for each of the years ended December 31, 2012 and 2011, associated with the early termination of several leases included in its cross-border energy lease portfolio. The after-tax gains were $9 million and $3 million for the years ended December 31, 2012 and 2011, respectively.
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.
PEPCO HOLDINGS
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 $1 million to a net expense of $229 million in 2012 from a net expense of $228 million in 2011. The increase reflects an $11 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 increased by $7 million to $156 million in 2012 from $149 million in 2011.
PHI’s consolidated effective income tax rates for the years ended December 31, 2012 and 2011 were 35.4% and 36.4%, respectively.
The effective income tax rate for the year ended December 31, 2012 reflects charges related to the recognition of the tax consequences associated with the early termination of cross-border energy leases in the third quarter of 2012 of $16 million as discussed in Note (8), “Leasing Activities,” to the consolidated financial statements of PHI.
In addition, 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.
PEPCO HOLDINGS
Consolidated Results of Operations
The following results of operations discussion compares the year ended December 31, 2011, to the year ended December 31, 2010. 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 Business
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.
PEPCO HOLDINGS
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
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.
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Commercial activity in the region includes banking and other professional services, government, insurance, real estate, shopping malls, casinos, stand alone construction and tourism.
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Industrial activity in the region includes chemical, glass, pharmaceutical, steel manufacturing, food processing and oil refining.
Regulated T&D Electric Revenue increased by $33 million primarily due to:
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An increase of $32 million due to distribution rate increases (Pepco in the District of Columbia effective March 2010 and July 2010, and in Maryland effective July 2010; DPL in Maryland effective July 2011, and in Delaware effective February 2011; and ACE in New Jersey effective June 2010).
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An increase of $32 million in transmission revenue primarily attributable to higher rates effective June 1, 2010 and June 1, 2011 related to increases in transmission plant investment.
PEPCO HOLDINGS
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An increase of $11 million due to higher pass-through revenue (which is substantially offset by a corresponding increase in Other Taxes) primarily the result of rate increases in Montgomery County, Maryland utility taxes that are collected by Pepco on behalf of the county.
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An increase of $7 million primarily due to Pepco customer growth in 2011, primarily in the residential class.
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An increase of $2 million due to the implementation of the EmPower Maryland surcharge in March 2010 (which is substantially offset by a corresponding increase in Depreciation and Amortization).
The aggregate amount of these increases was partially offset by:
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A decrease of $30 million due to an ACE New Jersey Societal Benefit Charge rate decrease that became effective in January 2011 (which is offset in Deferred Electric Service Costs).
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A decrease of $11 million due to lower sales as a result of cooler weather during the spring and summer months of 2011, and warmer weather during the fall months of 2011, as compared to the corresponding periods in 2010.
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A decrease of $10 million due to lower non-weather related average customer usage.
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.
PEPCO HOLDINGS
Default Electricity Supply Revenue decreased by $489 million primarily due to:
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A decrease of $200 million due to lower sales, primarily as a result of customer migration to competitive suppliers.
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A net decrease of $153 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 $94 million due to lower sales as a result of cooler weather during the spring and summer months of 2011, and warmer weather during the fall months of 2011, as compared to the corresponding periods in 2010.
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A decrease of $40 million in wholesale energy and capacity resale revenues primarily due to the sale of lower volumes of electricity and capacity purchased from NUGs.
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A decrease of $3 million due to a decrease in revenue from Transmission Enhancement Credits.
The aggregate amount of these decreases was partially offset by:
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An increase of $3 million resulting from an approval by the DCPSC of an increase in Pepco’s cost recovery rate for providing Default Electricity Supply in the District of Columbia to provide for recovery of higher cash working capital costs incurred in prior periods. The higher cash working capital costs were incurred when the billing cycle for providers of Default Electricity Supply was shortened from a monthly to a weekly period, effective in June 2009.
Total Default Electricity Supply Revenue for the 2011 period includes a decrease of $8 million in unbilled revenue attributable to ACE’s BGS ($5 million decrease in net income), primarily due to lower customer usage and lower Default Electricity Supply rates during the unbilled revenue period at the end of 2011 as compared to the corresponding period in 2010. Under the BGS terms approved by the NJBPU, ACE’s BGS unbilled revenue is not included in the deferral calculation until it is billed to customers, and therefore has an impact on the results of operations in the period during which it is accrued.
Regulated Gas
PEPCO HOLDINGS
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 and other professional services, government, insurance, real estate, shopping malls, stand alone construction and tourism.
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Industrial activities in the region include chemical and pharmaceutical.
Regulated Gas Revenue decreased by $8 million primarily due to:
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A decrease of $17 million due to lower non-weather related average customer usage.
The decrease was partially offset by:
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An increase of $6 million due to higher sales primarily as a result of colder weather during the winter of 2011 as compared to the winter of 2010.
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An increase of $2 million due to a distribution rate increase effective February 2011.
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An increase of $2 million due to customer growth in 2011.
Pepco Energy Services
Pepco Energy Services’ operating revenue decreased $615 million primarily due to:
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A decrease of $642 million due to lower retail supply sales volume primarily attributable to the ongoing wind-down of the retail energy supply business.
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A decrease of $33 million due to lower generation and capacity revenues at the generating facilities.
The aggregate amount of these decreases was partially offset by:
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An increase of $61 million due to increased energy services 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 Business
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 $596 million primarily due to:
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A decrease of $300 million due to lower average electricity costs under Default Electricity Supply contracts.
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A decrease of $221 million primarily due to customer migration to competitive suppliers.
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A decrease of $83 million due to lower electricity sales primarily as a result of cooler weather during the spring and summer months of 2011, and warmer weather during the fall months of 2011, as compared to the corresponding periods in 2010.
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A decrease of $16 million in the cost of gas purchases for on-system sales as a result of lower average gas prices, lower volumes purchased and lower withdrawals from storage.
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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.
The aggregate amount of these decreases was partially offset by:
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An increase of $18 million in deferred electricity expense primarily due to lower Default Electricity Supply rates, which resulted in a higher rate of recovery of Default Electricity Supply costs.
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An increase of $18 million in deferred natural gas expense as a result of a higher rate of recovery of natural gas supply costs.
Pepco Energy Services
Pepco Energy Services’ Fuel and Purchased Energy and Other Services Cost of Sales decreased $555 million primarily due to:
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A decrease of $591 million due to lower volumes of electricity and gas purchased to serve decreased retail supply sales volume as a result of the ongoing wind-down of the retail energy supply business.
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A decrease of $10 million due to lower fuel usage associated with the generating facilities.
The aggregate amount of these decreases was partially offset by:
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An increase of $46 million due to increased energy services activities.
Other Operation and Maintenance
A detail of PHI’s Other Operation and Maintenance expense is as follows:
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Other Operation and Maintenance expense for Power Delivery increased by $75 million primarily due to:
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An increase of $38 million associated with higher tree trimming and preventative maintenance costs.
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An increase of $9 million in employee-related costs, primarily benefit expenses.
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An increase of $8 million primarily due to an increase in total incremental storm restoration costs for major storm events as described in the following table:
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During 2011, Pepco, DPL and ACE incurred incremental storm restoration costs of $28 million associated with Hurricane Irene which also 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. ACE’s stipulation of settlement approved by the NJBPU in October 2012 provides for recovery of these costs in New Jersey. The remaining costs of $6 million relate to repair work completed in Delaware and the District of Columbia which are not currently deferrable in those jurisdictions.
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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.
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In February 2010, Pepco, DPL and ACE incurred incremental storm restoration costs of $13 million associated with a severe winter storm, all of which were expensed in 2010. In August 2010, the MPSC issued an order allowing for the deferral and recovery of $5 million of such costs for Pepco.
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An increase of $8 million primarily due to higher 2011 DCPSC rate case costs and reliability audit expenses and due to 2010 Pepco adjustments for the deferral of distribution rate case costs of $4 million that previously were charged to other operation and maintenance expense. The adjustments were recorded in accordance with a MPSC rate order issued in August 2010 and a DCPSC rate order issued in February 2010, allowing for the recovery of the costs.
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An increase of $8 million primarily due to Pepco’s emergency restoration improvement project and reliability improvement costs.
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An increase of $8 million in customer support service and system support costs.
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An increase of $6 million in communication costs.
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An increase of $5 million in corporate cost allocations, primarily due to higher contractor and outside legal counsel fees.
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An increase of $5 million related to New Jersey Societal Benefit Program costs that are deferred and recoverable.
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An increase of $3 million in costs related to customer requested and mutual assistance work (primarily offset in other Electric T&D Revenue).
The aggregate amount of these increases was partially offset by:
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A decrease of $17 million resulting from adjustments recorded by PHI in 2011 associated with the accounting for DPL and Pepco Default Electricity Supply. These adjustments were primarily due to the under-recognition of allowed returns on working capital, uncollectible accounts, late fees and administrative costs.
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A decrease of $15 million in environmental remediation costs.
Restructuring Charge
As a result of PHI’s organizational review in the second quarter of 2010, PHI’s operating expenses include a pre-tax restructuring charge of $30 million for the year ended December 31, 2010, related to severance and health and welfare benefits to be provided to terminated employees.
Depreciation and Amortization
Depreciation and Amortization expense increased by $33 million to $426 million in 2011 from $393 million in 2010 primarily due to:
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An increase of $16 million in amortization of stranded costs as the result of higher revenue due to rate increases effective October 2010 for the ACE Transition Bond Charge and Market Transition Charge Tax (partially offset in Default Electricity Supply Revenue).
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An increase of $14 million due to utility plant additions.
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An increase of $4 million in amortization of regulatory assets primarily associated with the EmPower Maryland surcharge that became effective in March 2010 (which is substantially offset by a corresponding increase in Regulated T&D Electric Revenue).
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An increase of $1 million in amortization of software upgrades to Pepco’s Energy Management System.
The aggregate amount of these increases was partially offset by:
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A decrease of $3 million primarily due to the higher 2010 recognition of asset retirement obligations associated with Pepco Energy Services generating facilities scheduled for deactivation in May 2012.
Other Taxes
Other Taxes increased by $17 million to $451 million in 2011 from $434 million in 2010. The increase was primarily due to:
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An increase of $16 million primarily due to rate increases in the Montgomery County, Maryland utility taxes that are collected and passed through by Pepco (substantially offset by a corresponding increase in Regulated T&D Electric Revenue).
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An increase of $5 million due to an adjustment in the third quarter of 2010 to correct certain errors related to other taxes.
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The aggregate amount of these increases was partially offset by:
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A decrease of $5 million in the Energy Assistance Trust Fund surcharge primarily due to rate decreases effective October 2010 (substantially offset by a corresponding decrease in Regulated T&D Electric Revenue).
Gains on Early Terminations of Finance Leases Held in Trust
PHI’s operating expenses include a $39 million pre-tax gain for the year ended December 31, 2011 associated with the early termination of several lease investments included in its cross-border energy lease portfolio.
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 $45 million, to an expense reduction of $63 million in 2011 as compared to an expense reduction of $108 million in 2010, primarily due to higher Default Electricity Supply Revenue rates and lower electricity supply costs.
Effects of Pepco Divestiture-Related Claims
The DCPSC on May 18, 2010 issued an order addressing all of the outstanding issues relating to Pepco’s obligation to share with its District of Columbia customers the net proceeds realized by Pepco from the sale of its generation-related assets in 2000. This order disallowed certain items that Pepco had included in the costs it deducted in calculating the net proceeds of the sale. The disallowance of these costs, together with interest, increased the aggregate amount Pepco is required to distribute to customers by approximately $11 million. PHI recognized a pre-tax expense of $11 million for the year ended December 31, 2010.
Other Income (Expenses)
Other Expenses (which are net of Other Income) decreased by $246 million primarily due to the loss on extinguishment of debt that was recorded in 2010 and lower interest expense in 2011 resulting from the reduction in outstanding long-term debt in 2010 with the proceeds from the Conectiv Energy sale.
Loss on Extinguishment of Debt
In 2010, PHI purchased or redeemed senior notes in the aggregate principal amount of $1,194 million. In connection with these transactions, PHI recorded a pre-tax loss on extinguishment of debt of $189 million in 2010, $174 million of which was attributable to the retirement of the debt and $15 million of which related to the acceleration of losses on treasury rate lock transactions associated with the retired debt. For a further discussion of these transactions, see Note (11), “Debt,” to the consolidated financial statements of PHI.
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Income Tax Expense
PHI’s consolidated effective tax rates from continuing operations for the years ended December 31, 2011 and 2010 were 36.4% and 7.3%, respectively. The increase in the effective tax rate was primarily due to the recognition of certain tax benefits in 2010 that did not recur in 2011 and PHI’s early termination of its interest in certain cross-border energy leases in 2011.
In 2010, certain PHI subsidiaries were restructured which subjected PHI to state income taxes in new jurisdictions and resulted in current state tax benefits that were recorded in 2010 and did not recur in 2011. Specifically, on April 1, 2010, as part of an ongoing effort to simplify PHI’s organizational structure, certain of PHI’s subsidiaries were converted from corporations to single member limited liability companies. In addition to increased organizational flexibility and reduced administrative costs, converting these entities to limited liability companies allows PHI to include income or losses in the former corporations in a single state income tax return, thus increasing the utilization of state income tax attributes. As a result of inclusions of income or losses in a single state return as discussed above, PHI recorded an $8 million benefit by reversing a valuation allowance on certain state net operating losses and an additional benefit of $6 million resulting from changes to certain state deferred tax benefits.
In addition, in November 2010, PHI reached final settlement with the IRS with respect to its federal tax returns for the years 1996 to 2002 for all issues except its cross-border energy lease investments. In connection with the settlement, PHI reallocated certain amounts on deposit with the IRS since 2006 among liabilities in the settlement years and subsequent years. In light of the settlement and reallocations, PHI has recalculated the estimated interest due for the tax years 1996 to 2002. The revised estimate resulted in the reversal of $15 million (after-tax) of estimated interest due to the IRS which was recorded as an income tax benefit in the fourth quarter of 2010.
In 2011, a $17 million (after-tax) income tax benefit was recorded in the first quarter when PHI reached a settlement with the IRS related to the calculation of interest due as a result of the November 2010 audit settlement. This benefit was more than offset during the second quarter of 2011, when PHI terminated early its interest in certain cross-border energy leases prior to the end of their stated term. As a result, PHI recognized a $22 million charge related to the tax consequences associated with the early terminations.
Discontinued Operations
For the year ended December 31, 2011, the $3 million loss from discontinued operations, net of income taxes, consists of an after-tax loss from operations of $1 million and after-tax net loss of $2 million from dispositions of assets and businesses.
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, 2012, PHI’s current assets on a consolidated basis totaled $1.2 billion and its consolidated current liabilities totaled $2.5 billion, resulting in a working capital deficit of $1.3 billion. PHI expects the working capital deficit at December 31, 2012 to be funded during 2013 in part through cash flows from operations, from the February 2013 settlement of the equity forward transaction discussed below and from the issuance of long-term debt. At December 31, 2011, PHI’s current assets on a consolidated basis totaled $1.4 billion and its current liabilities totaled $1.9 billion, for a working capital deficit of $422 million. The increase of $856 million in the working capital deficit from December 31, 2011 to December 31, 2012 was primarily due to an increase in long-term debt that will mature within one year and an increase in short-term debt for PHI, Pepco and ACE to temporarily support higher spending by the utilities on infrastructure investments and reliability initiatives.
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At December 31, 2012, PHI’s consolidated cash and cash equivalents totaled $25 million, which consisted of cash and uncollected funds but excludes current Restricted Cash Equivalents (cash that is available to be used only for designated purposes) that totaled $10 million. At December 31, 2011, PHI’s consolidated cash and cash equivalents totaled $109 million, of which $87 million was invested in money market funds, and the balance was held as cash and uncollected funds. At December 31, 2011, PHI’s current Restricted Cash Equivalents totaled $11 million.
A detail of PHI’s short-term debt balance and current portion of long-term debt and project funding balance was as follows:
Commercial Paper
PHI, Pepco, DPL and ACE maintain commercial paper programs to address short-term liquidity needs. As of December 31, 2012, the maximum capacity available under these programs was $875 million, $500 million, $500 million and $250 million, respectively, subject to available borrowing capacity under the credit facility.
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 during 2012 was ten, five, four and three days, respectively.
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Equity Forward Transaction
During 2012, PHI entered into an equity forward transaction in connection with a public offering of 17,922,077 shares of PHI common stock. The use of an equity forward transaction substantially eliminates future equity market price risk by fixing a common equity offering sales price under the then existing market conditions, while mitigating immediate share dilution resulting from the offering by postponing the actual issuance of common stock until funds are needed in accordance with PHI’s capital investment and regulatory plans.
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.
The equity forward transaction had no initial fair value since it was entered into at the then market price of the common stock. PHI did not receive any proceeds from the sale of common stock until the equity forward transaction was settled, and at that time PHI recorded the proceeds in equity. PHI concluded that the equity forward transaction was an equity instrument based on the accounting guidance in ASC 480 and ASC 815, and that it qualified for an exception from derivative accounting under ASC 815 because the forward sale transaction was indexed to its own stock.
As allowed by the terms of the transaction, PHI physically settled the equity forward transaction on February 27, 2013 by issuing 17,922,077 shares of common stock at $17.39 per share to the forward counterparty. The net proceeds of approximately $312 million were used to pay down outstanding commercial paper, a portion of which was issued in order to make capital contributions to the utilities, and for general corporate purposes.
During 2012, the equity forward transaction was reflected in PHI’s diluted earnings per share calculations using the treasury stock method. Under this method, the number of shares of PHI’s common stock used in calculating diluted earnings per share for a reporting period would be increased by the number of shares, if any, that would be issued upon physical settlement of the equity forward transaction less the number of shares that could be purchased by PHI in the market (based on the average market price during that reporting period) using the proceeds receivable upon settlement of the equity forward transaction (based on the adjusted forward sale price at the end of that reporting period). The excess number of shares is weighted for the portion of the reporting period in which the equity forward transaction is outstanding. For the year ended December 31, 2012, the equity forward transaction had a dilutive effect of $0.01 on PHI’s earnings per share.
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, among other changes, extended the expiration date of the facility to August 1, 2016. On August 2, 2012, the amended and restated credit agreement 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.
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 at December 31, 2012 was $650 million for PHI, $350 million for Pepco and $250 million for each of 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
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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 (11), “Debt,” to the consolidated financial statements of PHI.
Term Loan Agreement
During 2012, PHI entered into a $200 million term loan agreement, pursuant to which PHI has borrowed (and may not reborrow) $200 million at a rate of interest equal to the prevailing Eurodollar rate, which is determined by reference to the London Interbank Offered Rate with respect to the relevant interest period, all as defined in the loan agreement, plus a margin of 0.875%. As of December 31, 2012, outstanding borrowings under the loan agreement bore interest at an annual rate of 1.095%.
PHI used the net proceeds of the borrowings under the term loan agreement to repay outstanding commercial paper obligations and for general corporate purposes. For additional discussion of the Term Loan Agreement, see Note (11), “Debt,” to the consolidated financial statements of PHI.
Cash and Credit Facility Available as of December 31, 2012
(a) Cash and cash equivalents reported on the PHI consolidated balance sheet total $25 million which was held in cash and uncollected funds.
Collateral Requirements of Pepco Energy Services
In the ordinary course of its retail energy supply business, which is in the process of being wound down, Pepco Energy Services entered into various contracts to buy and sell electricity, fuels and related products, including derivative instruments, designed to reduce its financial exposure to changes in the value of its assets and obligations due to energy price fluctuations. These contracts typically have collateral requirements. Depending on the contract terms, the collateral required to be posted by Pepco Energy Services can be of varying forms, including cash and letters of credit.
As of December 31, 2012, Pepco Energy Services had posted net cash collateral of $25 million and letters of credit of less than $1 million. At December 31, 2011, Pepco Energy Services had posted net cash collateral of $112 million and letters of credit of $1 million.
At December 31, 2012 and 2011, the amount of cash, plus borrowing capacity under PHI’s credit facility available to meet the future liquidity needs of Pepco Energy Services, totaled $384 million and $283 million, respectively.
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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. PHI currently estimates 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 be obligated to pay between $170 million and $200 million in additional federal and state taxes and between $50 million and $60 million of interest on the additional federal and state taxes as of March 31, 2013. The estimate of additional federal and state taxes due takes into account 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 on deposit with the IRS.
PHI anticipates that it will make a deposit with the IRS for the additional taxes and related interest of approximately $220 million to $260 million in the first quarter of 2013 in order to mitigate PHI’s ongoing interest costs associated with the dispute. This deposit is expected to be funded from currently available sources of liquidity and short-term borrowings. PHI is evaluating the liquidation of all or a portion of its remaining cross-border energy lease investments, which had a net carrying value of approximately $1.2 billion as of December 31, 2012. Any liquidation proceeds could be used to repay any borrowings utilized to fund the deposit discussed above. PHI estimates that a partial or complete liquidation could be accomplished within one year.
Pension and Other Postretirement Benefit Plans
Based on the results of the 2012 actuarial valuation, PHI’s net periodic pension and other postretirement benefit (OPEB) costs were approximately $110 million in 2012 versus $94 million in 2011. The current estimate of benefit cost for 2013 is $99 million. The utility subsidiaries are responsible for substantially all of the total PHI net periodic pension and OPEB costs. Approximately 30% of net periodic pension and OPEB costs are capitalized. PHI estimates that its net periodic pension and OPEB expense will be approximately $69 million in 2013, as compared to $77 million in 2012 and $66 million in 2011.
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 medical coverage; however, they will be able to purchase coverage at full cost through PHI.
In 2012 and 2011, Pepco contributed $5 million and $7 million, respectively, DPL contributed $7 million and $6 million, respectively, and ACE contributed $7 million and $7 million, respectively, to the other postretirement benefit plan. In 2012 and 2011, contributions of $13 million were made by other PHI subsidiaries.
Pension benefits are provided under PHI’s non-contributory retirement plan (PHI Retirement Plan), a defined benefit pension plan that covers substantially all employees of Pepco, DPL and ACE and certain employees of other PHI subsidiaries. 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. On January 9, 2013, PHI, DPL and ACE made discretionary tax-deductible contributions to the PHI Retirement Plan in the amounts of $20 million, $10 million and $30 million, respectively, which is expected to bring 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. During 2011, Pepco, DPL and ACE made discretionary tax-deductible contributions to the PHI Retirement Plan in the amounts of $40
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million, $40 million and $30 million, respectively. PHI satisfied the minimum required contribution rules under the Pension Protection Act in 2012, 2011 and 2010. For additional discussion of PHI’s Pension and Other Postretirement Benefits, see Note (10), “Pension and Other Postretirement Benefits,” to the consolidated financial statements of PHI.
Cash Flow Activity
PHI’s cash flows during 2012, 2011 and 2010 are summarized below:
Operating Activities
Cash flows from operating activities during 2012, 2011 and 2010 are summarized below:
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 decrease in accounts payable due to the wind-down of the retail energy supply business of Pepco Energy Services. This was partially offset by a $79 million decrease in cash collateral related to derivative activities.
Net cash related to operating activities decreased $127 million for the year ended December 31, 2011, compared to the same period in 2010. The decrease was due primarily to a $206 million reduction in Conectiv Energy net assets held for sale as well as $10 million increase in pension contributions compared to 2010. A significant portion of the decline in Conectiv Energy assets held for sale was associated with the transfer of derivative instruments to a third party as further described in Note (19), “Discontinued Operations,” to the consolidated financial statements of PHI. Partially offsetting this decrease in operating cash flows was a $121 million increase in cash flows from continuing operations.
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Investing Activities
Cash flows used by investing activities during 2012, 2011 and 2010 are summarized below:
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 leases.
Net cash related to investing activities decreased $1,465 million for the year ended December 31, 2011 compared to the same period in 2010. The decrease was due primarily to the $1,640 million in proceeds from the sale of the Conectiv Energy wholesale power generation business in 2010 and $139 million increase in capital expenditures, partially offset by the $161 million of proceeds from the early termination of certain cross-border energy lease investments in 2011.
Financing Activities
Cash flows from financing activities during 2012, 2011 and 2010 are summarized below:
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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 $35 million increase in net short-term debt issuances to temporarily support higher spending by the utilities on infrastructure investments and reliability initiatives, and a $109 million net increase in long-term debt.
Net cash related to financing activities increased $1,705 million for the year ended December 31, 2011 compared to the same period in 2010 primarily due to a $1,656 million decrease in reacquisitions of long-term debt in 2011 as a result of debt extinguishments in 2010.
Common Stock Dividends
Common stock dividend payments were $248 million in 2012, $244 million in 2011, and $241 million in 2010. The increase in common stock dividends paid in 2012 and 2011 was the result of additional shares outstanding, primarily shares issued under the Shareholder Dividend Reinvestment Plan (DRP).
Changes in Outstanding Common Stock
Under the Long-Term Incentive Plan, PHI issued approximately 1 million shares of common stock in each of 2012, 2011 and 2010.
Under the DRP, PHI issued 1.7 million shares of common stock in 2012, 1.6 million shares of common stock in 2011, and 1.8 million shares of common stock in 2010.
In February 2013, PHI issued 17.9 million shares of common stock pursuant to the settlement of the equity forward transaction discussed above.
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Changes in Outstanding Long-Term Debt
Cash flows from issuances and reacquisitions of long-term debt in 2012, 2011 and 2010 are summarized in the charts 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 (c) 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 changed from 4.90% to a fixed rate of 0.75%.
(b) Consists of Gas Facilities Refunding Revenue Bonds issued by DEDA for the benefit of DPL.
(c) Consists of Pollution Control Refunding Revenue Bonds issued by DEDA for the benefit of DPL that were purchased by DPL in July 2010. See footnote (d) to the Reacquisitions table below. The bonds were resold to the public in December 2010. While DPL held the bonds, they remained outstanding as a contractual matter, but were considered extinguished for accounting purposes. In connection with the resale of the bonds, the interest rate on the bonds was changed (i) from 5.50% to a fixed rate of 1.80% with respect to the tax-exempt bonds due 2025 and (ii) from 5.65% to a fixed rate of 2.30% with respect to the tax-exempt bonds due 2028. The bonds were purchased by DPL on June 1, 2012 pursuant to a mandatory purchase obligation and then retired.
(d) Consists of Pollution Control Revenue Refunding Bonds (ACE Bonds) issued by The Pollution Control Financing Authority of Salem County for the benefit of ACE that were purchased by ACE in 2008. In connection with the resale of these bonds by ACE, the interest rate on the ACE Bonds was changed from an auction rate to a fixed rate. The ACE Bonds are secured by an outstanding series of senior notes issued by ACE, and the senior notes are in turn secured by a series of Collateral First Mortgage Bonds issued by ACE. Both the senior notes and the Collateral First Mortgage Bonds have maturity dates, optional and mandatory redemption provisions, interest rates and interest payment dates that are identical to the terms of the ACE Bonds. The payment by ACE of its obligations with respect to the ACE Bonds satisfies the corresponding payment obligations on the senior notes and Collateral First Mortgage Bonds. See Note (11), “Debt,” to the consolidated financial statements of PHI.
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(a) Consists of Pollution Control Revenue Refunding Bonds (Pepco 2010 Bonds) issued by Prince George’s County for the benefit of Pepco. The Pepco 2010 Bonds were secured by an outstanding series of Collateral First Mortgage Bonds issued by Pepco. The Collateral First Mortgage Bonds had maturity dates, optional and mandatory redemption provisions, interest rates and interest payment dates that were identical to the terms of the Pepco 2010 Bonds. Accordingly, the redemption of the Pepco 2010 Bonds at maturity automatically effected the redemption of the Collateral First Mortgage Bonds.
(b) 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.
(c) 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.
(d) Repurchased by DPL in July 2010 pursuant to a mandatory repurchase 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 December 2010. See footnote (c) to the Issuances table above.
(e) 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 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.
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
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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 (c) 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.
In 2010, DEDA issued $78 million of 5.40% Gas Facilities Refunding Revenue Bonds due 2031 for the benefit of DPL. The proceeds were used by DPL to redeem $78 million in principal amount of Exempt Facilities Refunding Revenue Bonds issued by DEDA purchased in 2008. See footnote (b) to the Issuances table above. In March 2010, $23 million in aggregate principal amount of Pollution Control Revenue Refunding Bonds were resold by ACE to the public. See footnote (d) to the Issuances table above.
Tax Exempt Auction Rate and First Mortgage Bond Redemptions
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.
During 2012, DPL redeemed, prior to maturity, $31 million of 5.20% tax-exempt pollution control refunding revenue bonds due 2019, issued by the 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.
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Changes in Short-Term Debt
As of December 31, 2012, PHI had a total of $637 million of commercial paper outstanding as compared to $586 million and $388 million of commercial paper outstanding at December 31, 2011 and 2010, respectively.
As of December 31, 2012, PHI had $200 million of term loan debt outstanding as compared to zero in 2011 and 2010.
Capital Requirements
Capital Expenditures
Pepco Holdings’ capital expenditures for the year ended December 31, 2012 totaled $1,216 million, up $275 million from $941 million in 2011. Capital expenditures in 2012 were $592 million for Pepco, $320 million for DPL, $256 million for ACE, $11 million for Pepco Energy Services and $37 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 2013 through 2017. Pepco Holdings expects to fund these expenditures through internally generated cash and external financing.
(a) Reflects remaining anticipated reimbursements for capital expenditures pursuant to awards from the Department of Energy (DOE) under the American Recovery and Reinvestment Act of 2009.
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.”
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DOE Capital Reimbursement Awards
In 2009, the 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 an AMI system, direct load control, distribution automation, and communications infrastructure.
During 2010, Pepco, ACE and the DOE signed agreements formalizing the $168 million in awards. Of the $168 million, $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 expenses associated with direct load control and other Pepco and ACE programs. During 2012, Pepco and ACE received award payments of $47 million and $5 million, respectively. The cumulative award payments received by Pepco and ACE as of December 31, 2012, were $115 million and $13 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 2012, PHI’s Board of Directors declared quarterly dividends of 27 cents per share of common stock payable on March 30, 2012, June 29, 2012, September 28, 2012 and December 31, 2012.
On January 24, 2013, the Board of Directors declared a dividend on common stock of 27 cents per share payable March 28, 2013, to shareholders of record on March 11, 2013.
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 $1,109 million and $1,072 million of retained earnings free of restrictions at December 31, 2012 and 2011, 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, 2012, 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 $167 million of net non-current liabilities related to uncertain tax positions due to uncertainty in the timing of the associated cash payments.
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 transaction with third parties.
PHI guarantees the obligations of Pepco Energy Services under certain of its energy savings, combined heat and power and construction contracts. At December 31, 2012, PHI’s guarantees of Pepco Energy Services’ obligations under these contracts totaled $198 million.
For additional discussion of PHI’s third party guarantees, indemnifications, obligations and off-balance sheet arrangements, see Note (16), “Commitments and Contingencies,” to the consolidated financial statements of PHI.
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Energy Contract Activity
The following table provides detail on changes in the net asset or liability positions of the Pepco Energy Services segment with respect to energy commodity contracts for the year ended December 31, 2012. The balances in the table are pre-tax and the derivative assets and liabilities reflect netting by counterparty before the impact of collateral.
(a) Includes all effective hedging activities from continuing operations recorded at fair value through Accumulated Other Comprehensive Loss (AOCL) or trading activities from continuing operations recorded at fair value in the consolidated statements of income.
The $20 million net liability on energy contracts at December 31, 2012 was primarily attributable to losses on power swaps and natural gas futures held by Pepco Energy Services. The decrease from $83 million at December 31, 2011 is primarily due to the reclassification of mark-to-market losses to realized losses on settled derivatives. PHI expects that future revenues from existing customer sales obligations that are accounted for on an accrual basis will largely offset expected realized net losses on Pepco Energy Services’ energy contracts.
The fair values of Pepco Energy Services’ commodity derivative contracts in each category presented below reflect forward prices and volatility factors as of December 31, 2012, and the fair values are subject to change as a result of changes in these prices and factors.
(a) Includes all effective hedging activities recorded at fair value through AOCL, and hedge ineffectiveness and trading activities on the statements of income.
(b) Prices provided by other external sources reflect information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms that are readily observable in the market.
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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, 2012, 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 $144 million. Of this amount, $40 million is attributable to derivatives, normal purchase and normal sale contracts, collateral, and other contracts under master netting agreements as described in Note (14), “Derivative Instruments and Hedging Activities,” to the consolidated financial statements of PHI. The remaining $104 million is attributable primarily to energy services contracts and accounts payable to independent system operators and distribution companies on full requirements contracts entered into by Pepco Energy Services. 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 competitive energy and 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. As of December 31, 2012, Pepco Energy Services provided net cash collateral in the amount of $25 million in connection with these activities.
Environmental Remediation Obligations
PHI’s accrued liabilities for environmental remediation obligations as of December 31, 2012 totaled approximately $29 million, of which approximately $6 million is expected to be incurred in 2013, 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 (16), “Commitments and Contingencies,” to the consolidated financial statements of PHI. For information regarding projected expenditures for environmental control facilities, see “Business - Environmental Matters.” The most significant environmental remediation obligations as of December 31, 2012, 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 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.
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Sources of Capital
Pepco Holdings’ 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, 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. See Item 1A. “Risk Factors,” for additional discussion of important factors that may impact these sources of capital.
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.
PHI, Pepco, DPL and ACE maintain ongoing commercial paper programs to address short-term liquidity needs. As of December 31, 2012, the maximum capacity available under these programs was $875 million, $500 million, $500 million and $250 million, respectively, subject to available borrowing capacity under the credit facility.
During 2012, PHI entered into a $200 million term loan agreement pursuant to which PHI has borrowed (and may not reborrow) $200 million. Proceeds were used to repay outstanding commercial paper obligations and for general corporate purposes.
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 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 a 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. Borrowings from the money pool are unsecured. 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.
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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, 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 (see “Management’s Discussion and Analysis of Financial Condition and Results of Operations - General Overview - Power Delivery Initiatives and Activities - Regulatory Lag”).
During 2012, Pepco, DPL and ACE concluded electric distribution base rate cases filed during 2011 in their respective state regulatory jurisdictions. In the fourth quarter of 2012, Pepco filed an electric distribution base rate increase application in Maryland, ACE filed an electric distribution base rate increase application in New Jersey and DPL filed a natural gas distribution base rate case in Delaware. Electric distribution base rate increase applications are expected to be filed in early 2013 by Pepco in the District of Columbia and by DPL in Delaware and Maryland.
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:
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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 and depreciation rates, can be changed only in a FERC 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. Return on equity 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 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 (16), “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 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 operations 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). Management has identified Power Delivery as a single reporting unit because its components have similar economic characteristics, similar products and services and operate in a similar regulatory environment.
PHI tests its goodwill impairment at least annually as of November 1 and on an interim basis if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Factors that may result in an interim impairment test include, but are not limited to: a change in identified reporting units; an adverse change in business conditions; a protracted decline in stock price causing market capitalization to fall below book value; an adverse regulatory action; or impairment of long-lived assets in the reporting unit.
The first step of the goodwill impairment test compares the fair value of the reporting unit with its carrying amount, including goodwill. Management uses its best judgment to make reasonable projections of future cash flows for Power Delivery when estimating the reporting unit’s fair value. In addition, PHI selects a discount rate for the associated risk with those estimated cash flows. These judgments are
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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, 2012 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 uses two valuation techniques: an income approach and a market approach. The income approach estimates fair value based on a discounted cash flow analysis using estimated future cash flows 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 market-based information for the cost of equity and cost of debt that is appropriate for Power Delivery 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 framework to estimate the fair value of Power Delivery.
The estimation of fair value is dependent on a number of factors that are sourced from the Power Delivery reporting unit’s business forecast, 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 and methodologies used in the models were consistent with historical experience. A hypothetical 10 percent decrease in fair value of the Power Delivery reporting unit at November 1, 2012 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 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 management makes assumptions and judgments, and the impact of a change in 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 management 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
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regulator, (iv) an accumulation of costs significantly in excess of the amount originally expected for the 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 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. In order to estimate an asset’s future cash flows, PHI considers historical cash flows. PHI uses reasonable estimates in making these evaluations and considers various factors, including forward price curves for energy, fuel costs, legislative initiatives, and operating costs. If necessary, the process of determining fair value is performed consistently with the process described in assessing the fair value of goodwill discussed above.
Accounting for Derivatives
PHI believes that the estimates involved in accounting for its derivative instruments represent “Critical Accounting Estimates” because management 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 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 (14), “Derivative Instruments and Hedging Activities,” to the consolidated financial statements of PHI.
PHI and its subsidiaries use derivative instruments primarily to manage risk associated with commodity prices. The definition of a derivative in the FASB guidance results in management having to exercise judgment, such as whether there is a notional amount or net settlement provision in contracts. Management 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 are used to determine fair value. For some custom and complex instruments, internal models use market 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 plans and would have an impact on the projected benefit obligations, which affect the reported amount of annual net periodic pension and OPEB cost on the 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 and participant compensation have a significant impact on employee benefit costs.
The discount rate for determining the pension benefit obligation was 4.15% and 5.00% as of December 31, 2012 and 2011, respectively. The discount rate for determining the postretirement benefit obligation was 4.10% and 4.90% as of December 31, 2012 and 2011, 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 plan assets was 7.25% and 7.75% as of December 31, 2012 and 2011, respectively. The expected long-term rate of return on postretirement benefit plan assets was 7.25% and 7.75% as of December 31, 2012 and 2011, 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 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 the related asset class. The pension and postretirement benefit plan assets consist of equity, fixed income, real estate and private equity investments, and when viewed over a long-term horizon, are expected to yield a return on assets of 7.25% as of December 31, 2012.
The following table reflects the effect on the projected benefit obligation for the pension plan and the accumulated benefit obligation for the OPEB plan, as well as the net periodic cost for both plans, if there were changes in these critical actuarial assumptions while holding all other actuarial assumptions constant:
(a) A change in the expected return assumption has no impact on the Projected Benefit Obligation.
The impact of changes in assumptions and the difference between actual and expected or estimated results on pension and postretirement obligations is generally recognized over the average remaining service period of the employees who benefit under the plans rather than immediate recognition in the statements of income.
For additional discussion, see Note (10), “Pension and Other Postretirement Benefits,” to the consolidated financial statements of PHI.
Accounting for Regulated Activities
FASB guidance on the accounting for regulated activities, 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 activities represent “Critical Accounting Estimates” because (i) management must interpret laws and regulatory
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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 management 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.
Management’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, management 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. Management 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 management is required to make assumptions and judgments about input 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 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 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 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 asserts that foreign earnings will continue to be indefinitely reinvested abroad; (vii) it must consider the effect of newly enacted tax law on its estimated effective tax rate and in measuring deferred tax balances; and (viii) 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.
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Assumptions, judgment and the use of estimates are required in determining if the “more likely than not” standard (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” standard quarterly.
PHI also evaluates quarterly the probability of realizing deferred tax assets by reviewing a forecast of future taxable income and 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 by PHI and its subsidiaries or that one or more of the companies will be required to adopt on or before a specified date in the future, 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 significant 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 has a population of approximately 2.2 million. As of December 31, 2012, approximately 56% 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.
Reliability Enhancement
Since 2010, Pepco has implemented comprehensive reliability enhancement plans in its service territory. These reliability enhancement plans include various initiatives to improve electrical system reliability, such as:
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the identification and upgrading of under-performing feeder lines;
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the addition of new facilities to support load;
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the installation of distribution automation systems on both the overhead and underground network systems;
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the rejuvenation and replacement of underground residential cables;
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selective undergrounding of portions of existing above-ground primary feeder lines, where appropriate to improve reliability;
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improvements to substation supply lines; and
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enhanced vegetation management.
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, concerns about the environment, reliability improvement, providing timely and accurate customer information and meeting government energy reduction goals. For a discussion of the smart grid, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations - General Overview - Power Delivery Initiatives and Activities - Smart Grid.”
Regulatory Lag
An important factor in the ability of Pepco to earn its authorized rate of return is the willingness of applicable public service commissions to adequately recognize forward-looking costs in its rate structure in order to address regulatory lag. Pepco is currently experiencing significant regulatory lag because its investment in the rate base and its operating expenses are outpacing revenue growth.
In an effort to minimize the effects of regulatory lag, Pepco’s District of Columbia and Maryland base rate case filings in 2011 each included a request for approval from the applicable state regulatory commissions of (i) a RIM to recover reliability-related capital expenditures incurred between base rate cases and (ii) the use by the applicable utility of fully forecasted test years in future base rate cases. See Note (6), “Regulatory Matters - Rate Proceedings,” to the financial statements of Pepco for a discussion of each of these mechanisms. In Pepco’s base rate case order in Maryland, the MPSC did not approve its request to implement the RIM and did not endorse the use of fully forecasted test years in future rate cases. However, the MPSC did permit an adjustment to the rate base to reflect the actual cost of reliability plant additions outside the test year. In the District of Columbia, the DCPSC denied Pepco’s request for approval of a RIM, and reserved final judgment on the appropriateness of the use by Pepco of a fully forecasted test year in future rate cases.
Pepco will continue to seek cost recovery from the MPSC and the DCPSC to reduce the effects of regulatory lag. There can be no assurance that any attempts by Pepco to mitigate regulatory lag will be approved, or that even if approved, the cost recovery mechanisms will fully mitigate the effects of regulatory lag. Until such time as any cost recovery mechanisms are approved, Pepco plans to file rate cases at least annually in an effort to align more closely the revenue and cash flow levels of Pepco with its other operation and maintenance spending and capital investments. In addition to the electric distribution base rate case filed by Pepco in Maryland on November 30, 2012, Pepco intends to file its next electric distribution base rate case with the DCPSC in the first quarter of 2013.
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.
Pepco had included in its five-year projected capital expenditures $138 million of MAPP-related expenditures for the period from 2012 to 2016. Pepco has updated its five-year projected capital expenditures to remove MAPP-related expenditures to reflect the PJM decision. See “Capital Requirements - Capital Expenditures” for a discussion of Pepco’s projected capital expenditures. As of December 31, 2012, Pepco’s total capital expenditures related to the MAPP project were approximately $64 million. In a 2008 FERC order approving incentives for the MAPP project, FERC authorized the recovery of prudently incurred abandoned costs in connection with the MAPP project. Consistent with this order, on December 21, 2012, PHI submitted a filing to FERC seeking recovery of approximately $50 million of abandoned MAPP capital expenditures. 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 (see Note (6), “Regulatory Matters - MAPP Project” to the financial statements of Pepco for additional information).
As of December 31, 2012, Pepco had placed in service $11 million of its total capital expenditures with respect to the MAPP project, which represented upgrades of existing substation assets that were expected to support the MAPP transmission line, transferred approximately $3 million of materials to inventories for use on other projects and reclassified the remaining $50 million of capital expenditures to a regulatory asset. The regulatory asset includes the costs of land, land rights, supplies and materials, engineering and
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design, environmental services, and project management and administration. Pepco intends to reduce the regulatory asset by any amounts recovered from the sale or alternative use of the land, land rights, supplies and materials.
Results of Operations
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.
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 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 includes mutual assistance to other utilities, highway relocation, rentals of pole attachments, late payment fees and collection fees.
Regulated T&D Electric
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Regulated T&D Electric Revenue increased by $48 million primarily due to:
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An increase of $26 million in transmission revenue primarily attributable to higher 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 a distribution rate increase in the District of Columbia effective October 2012 and in Maryland effective July 2012.
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An increase of $11 million due to an EmPower Maryland rate increase effective February 2012 (which is substantially offset by a corresponding increase in Depreciation and Amortization).
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An increase of $7 million due to customer growth in 2012, primarily in the residential class.
The aggregate amount of these increases was partially offset by 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 lower sales that resulted in a decrease in Montgomery County, Maryland utility taxes that are collected by Pepco on behalf of the jurisdiction.
Default Electricity Supply
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Default Electricity Supply Revenue decreased by $178 million primarily due to:
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A decrease of $94 million as a result of lower Default Electricity Supply rates.
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A decrease of $51 million due to lower sales, primarily as a result of customer migration to competitive suppliers.
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A decrease of $18 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 decrease of $17 million due to lower non-weather related average residential customer usage.
The aggregate amount of these decreases was partially offset by an increase of $5 million due higher revenue from transmission enhancement credits.
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 decreased by $167 million to $726 million in 2012 from $893 million in 2011 primarily due to:
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A decrease of $86 million due to lower average electricity costs under Default Electricity Supply contracts.
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A decrease of $61 million primarily due to customer migration to competitive suppliers.
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A decrease of $15 million due to lower electricity sales primarily as a result of milder weather during the 2012 winter and spring months, as compared to 2011.
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A decrease of $7 million in deferred electricity expense primarily due to lower Default Electricity Supply revenue rates, which resulted in a lower rate of recovery of Default Electricity Supply costs.
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Other Operation and Maintenance
Other Operation and Maintenance expense decreased by $17 million to $403 million in 2012 from $420 million in 2011 primarily due to:
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A decrease of $16 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 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 and will be pursuing recovery of these incremental storm restoration costs in this jurisdiction in its electric distribution base rate case. The remaining costs of $3 million primarily relate to repair work completed in the District of Columbia which are not currently 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 a regulatory asset to reflect the probable recovery of these storm restoration costs in Maryland and will be pursuing recovery of these incremental storm restoration costs in this jurisdiction in its electric distribution base rate case. The remaining costs of $2 million relate to repair work completed in the District of Columbia which are not currently deferrable.
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During 2011, Pepco incurred incremental storm restoration costs of $12 million associated with Hurricane Irene which resulted in widespread damage to the electric distribution system in each of Pepco’s service territories. Pepco deferred $10 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 in Maryland for Pepco in its July 2012 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 currently deferrable.
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A decrease of $6 million in bad debt expenses.
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A decrease of $3 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.
The aggregate amount of these decreases was partially offset by:
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An increase of $7 million in employee-related costs, primarily pension and other employee benefits.
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An increase of $2 million in expenses related to regulatory filings.
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An increase of $1 million in customer support service and system support costs.
Depreciation and Amortization
Depreciation and Amortization expense increased by $19 million to $190 million in 2012 from $171 million in 2011 primarily due to:
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An increase of $12 million in amortization of regulatory assets primarily due to EmPower Maryland surcharge rate increases effective February 2012 (which is substantially offset by a corresponding increase in Regulated T&D Electric Revenue).
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An increase of $4 million in amortization of software primarily related to AMI projects.
The MPSC reduced Pepco’s depreciation rates in Pepco’s most recent electric distribution base rate case, which is expected to lower annual Depreciation and Amortization expense by approximately $27 million effective July 20, 2012.
Other Taxes
Other Taxes decreased by $10 million to $372 million in 2012 from $382 million in 2011. 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 $6 million to a net expense of $83 million in 2012 from a net expense of $77 million in 2011. The increase was primarily due to an increase of $7 million in interest expense primarily associated with higher long-term debt and lower capitalized interest.
Income Tax Expense
Pepco’s income tax expense increased by $12 million to $48 million in 2012 from $36 million in 2011. Pepco’s effective income tax rates for the years ended December 31, 2012 and 2011 were 27.6% and 26.7%, respectively. The effective income tax rates primarily reflect tax benefits recorded in each period related to asset removal costs and changes in estimates and interest related to uncertain and effectively settled tax positions, and a tax benefit recorded in 2011 for state tax refunds associated with prior years’ asset dispositions.
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 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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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.
During 2011, PHI reached a settlement with the IRS with respect to interest due on its federal tax liabilities related to the tax 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 an additional tax benefit in the amount of $5 million (after-tax) in the second quarter of 2011.
During 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.
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. See Item 1A. “Risk Factors,” for additional discussion of important factors that may have an effect on Pepco’s sources of capital.
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. 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, 2012, is set forth in Note (10), “Debt,” to the financial statements of Pepco.
Bank Financing
As further discussed in Note (10), “Debt,” to the financial statements of Pepco, Pepco is a borrower under a $1.5 billion credit facility, along with PHI, DPL and ACE, which expires in 2017. Pepco’s credit limit under the facility is the lesser of $350 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.
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Commercial Paper Program
Pepco maintains an ongoing commercial paper program to address its short-term liquidity needs. As of December 31, 2012, the maximum capacity available under the program was $500 million, subject to available borrowing capacity under the credit facility.
Pepco had $231 million of commercial paper outstanding at December 31, 2012. The weighted average interest rate for commercial paper issued by Pepco during 2012 was 0.43% and the weighted average maturity of all commercial paper issued by Pepco during 2012 was five days.
Money Pool
Pepco participates in the money pool operated by PHI under authorization received from FERC. The money pool is a 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. Borrowings from the money pool are unsecured. 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, 2012 and 2011, 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, 2012 were $592 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.
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The following table shows Pepco’s projected capital expenditures for the five-year period from 2013 through 2017. Pepco expects to fund these expenditures through internally generated cash, external financing and capital contributions from PHI.
(a) Reflects remaining anticipated reimbursements for capital expenditures pursuant to awards from the DOE under the American Recovery and Reinvestment Act of 2009.
Transmission and Distribution
The projected capital expenditures listed in the table above for distribution (other than the smart grid) and transmission are primarily for facility replacements and upgrades to accommodate customer growth and service reliability, including capital expenditures for continuing reliability enhancement efforts, see “General Overview - Reliability Enhancement.”
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 expenses associated with direct load control and other programs. During 2012, Pepco received award payments of $47 million. The cumulative award payments received by Pepco as of December 31, 2012, were $115 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 and $40 million to the PHI Retirement Plan during 2012 and 2011, respectively. In 2012 and 2011, Pepco contributed $5 million and $7 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 Delaware and portions of Maryland. DPL also provides Default Electricity Supply. DPL’s electricity distribution service territory covers approximately 5,000 square miles and has a population of approximately 1.4 million. As of December 31, 2012, approximately 67% of delivered electricity sales were to Delaware customers and approximately 33% 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 has 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 comparable revenue decoupling mechanism for DPL electricity and natural gas customers in Delaware is under consideration by the DPSC. 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.
Smart Grid
DPL is building a smart grid which is designed to meet the challenges of rising energy costs, concerns about the environment, reliability improvement, providing timely and accurate customer information and meeting government energy reduction goals. For a discussion of the smart grid, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations - General Overview - Power Delivery Initiatives and Activities - Smart Grid.”
DPL
Regulatory Lag
An important factor in the ability of DPL to earn its authorized rate of return is the willingness of applicable public service commissions to adequately recognize forward-looking costs in its rate structure in order to address regulatory lag. DPL is currently experiencing significant regulatory lag because its investment in the rate base and its operating expenses are outpacing revenue growth.
In an effort to minimize the effects of regulatory lag, DPL’s Delaware and Maryland base rate case filings in 2011 each included a request for approval from the applicable state regulatory commissions of (i) a RIM to recover reliability-related capital expenditures incurred between base rate cases and (ii) the use by the applicable utility of fully forecasted test years in future base rate cases. See Note (7), “Regulatory Matters - Rate Proceedings,” to the financial statements of DPL for a discussion of each of these mechanisms. In DPL’s base rate case order in Maryland, the MPSC did not approve its request to implement the RIM and did not endorse the use of fully forecasted test years in future rate cases. However, the MPSC did permit an adjustment to the rate base to reflect the actual cost of reliability plant additions outside the test year. In Delaware, a settlement agreement approved by the DPSC in DPL’s electric distribution base rate case did not include approval of a RIM or the use of fully forecasted test years in future DPL rate cases, but it did provide that the parties will meet and discuss alternate regulatory methodologies for the mitigation of regulatory lag.
DPL will continue to seek cost recovery from the MPSC and the DPSC to reduce the effects of regulatory lag. There can be no assurance that any attempts by DPL to mitigate regulatory lag will be approved, or that even if approved, the cost recovery mechanisms will fully mitigate the effects of regulatory lag. Until such time as any cost recovery mechanisms are approved, DPL plans to file rate cases at least annually in an effort to align more closely the revenue and cash flow levels of DPL with its other operation and maintenance spending and capital investments. DPL intends to file its next electric distribution base rate cases with the MPSC and the DPSC in the first quarter of 2013.
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.
DPL had included in its five-year projected capital expenditures $67 million of MAPP-related expenditures for the period from 2012 to 2016. DPL has updated its five-year projected capital expenditures to remove MAPP-related expenditures to reflect the PJM decision. See “Capital Requirements - Capital Expenditures” for a discussion of DPL’s projected capital expenditures. As of December 31, 2012, DPL’s total capital expenditures related to the MAPP project were approximately $38 million. In a 2008 FERC order approving incentives for the MAPP project, FERC authorized the recovery of prudently incurred abandoned costs in connection with the MAPP project. Consistent with this order, on December 21, 2012, PHI submitted a filing to FERC seeking recovery of approximately $38 million of abandoned MAPP capital expenditures. 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 (see Note (7), “Regulatory Matters - MAPP Project” to the financial statements of DPL for additional information).
As of December 31, 2012, DPL had reclassified all $38 million of capital expenditures with respect to the MAPP project to a regulatory asset. The regulatory asset includes the costs of land, land rights, engineering and design, environmental services, and project management and administration. DPL intends to reduce the regulatory asset by any amounts recovered from the sale or alternative use of the land and land rights.
DPL
Results of Operations
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.
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 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 includes mutual assistance to other utilities, highway relocation, rentals of pole attachments, late payment fees and collection fees.
Regulated T&D Electric
DPL
Regulated T&D Electric Revenue increased by $61 million primarily due to:
•
An increase of $22 million due to distribution rate increases in Maryland effective July 2012 and July 2011; and in Delaware effective July 2012.
•
An increase of $15 million in transmission revenue primarily attributable to higher rates effective June 1, 2012 and June 1, 2011 related to increases in transmission plant investment and operating expenses.
•
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 Purchased Energy and Depreciation and Amortization).
•
An increase of $6 million due to an EmPower Maryland rate increase in February 2012 (which is substantially offset by a corresponding increase in Depreciation and Amortization).
•
An increase of $1 million due to higher non-weather related average customer usage.
Default Electricity Supply
DPL
Default Electricity Supply Revenue decreased by $85 million primarily due to:
•
A decrease of $43 million as a result of lower Default Electricity Supply rates.
•
A decrease of $31 million due to lower sales, primarily as a result of customer migration to competitive suppliers.
•
A decrease of $16 million due to lower sales as a result of milder weather during the 2012 winter and spring months, as compared to 2011.
The aggregate amount of these decreases was partially offset by an increase of $6 million due to higher non-weather related average residential customer usage.
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
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
DPL
Regulated Gas Revenue decreased by $32 million primarily due to:
•
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.
•
A decrease of $9 million due to GCR decreases effective November 2012 and November 2011.
•
A decrease of $5 million due to lower non-weather related average customer usage.
•
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 Gas Purchased).
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.
Operating Expenses
Purchased Energy
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 $67 million to $568 million in 2012 from $635 million in 2011 primarily due to:
•
A decrease of $28 million primarily due to customer migration to competitive suppliers.
•
A decrease of $23 million due to lower average electricity costs under Default Electricity Supply contracts.
•
A decrease of $12 million due to lower electricity sales primarily as a result of milder weather during the 2012 winter and spring months, as compared to 2011.
•
A decrease of $11 million in deferred electricity expense primarily due to lower Default Electricity Supply revenue rates, which resulted in a lower rate of recovery of Default Electricity Supply costs.
DPL
The aggregate amount of these decreases was partially offset by 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).
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 $42 million to $113 million in 2012 from $155 million in 2011 primarily due to:
•
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.
•
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.
•
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.
•
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).
The aggregate amount of these decreases was partially offset by 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.
Other Operation and Maintenance
Other Operation and Maintenance increased by $21 million to $260 million in 2012 from $239 million in 2011 primarily due to:
•
An increase of $10 million resulting from a decrease in deferred cost adjustments associated with DPL Default Electricity Supply. The deferred cost 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 regulatory taxes.
•
An increase of $5 million in employee-related costs, primarily pension and other employee benefits.
•
An increase of $3 million in customer support service and system support costs.
•
An increase of $2 million in expenses related to regulatory filings.
•
An increase of $1 million in self-insurance reserves for general and auto liability claims.
DPL
•
An increase of $1 million in total incremental storm restoration costs for major storm events, as described in the following table:
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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 and will be pursuing recovery of these incremental storm restoration costs in this jurisdiction in its electric distribution base rate case. The remaining costs of $1 million relate to repair work completed in Delaware which are not currently deferrable.
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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 and will be pursuing recovery of these incremental storm restoration costs in this jurisdiction in its electric distribution base rate case. The remaining costs of $4 million relate to repair work completed in Delaware which are not currently deferrable.
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During 2011, DPL incurred incremental storm restoration costs of $8 million associated with Hurricane Irene which resulted in widespread damage to the electric distribution system in each of DPL’s service territories. DPL deferred $4 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 in Maryland for DPL in its July 2012 rate order over a five-year period. The remaining costs of $4 million relate to repair work completed in Delaware which are not currently deferrable.
The aggregate amount of these increases was partially offset by a decrease of $1 million in bad debt expenses.
Depreciation and Amortization
Depreciation and Amortization expense increased by $13 million to $102 million in 2012 from $89 million in 2011 primarily due to:
•
An increase of $6 million in amortization of regulatory assets primarily due to an Empower Maryland surcharge rate increase effective February 2012 and expanding Demand Side Management Programs (which are substantially offset by corresponding increases in Regulated T&D Electric Revenue).
•
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).
•
An increase of $2 million due to utility plant additions.
DPL
The MPSC reduced DPL’s depreciation rates in DPL’s most recent electric distribution base rate case, which is expected to lower annual Depreciation and Amortization expense by approximately $4 million effective July 20, 2012.
Income Tax Expense
DPL’s income tax expense increased by $2 million to $44 million in 2012 from $42 million in 2011. DPL’s effective income tax rates for the years ended December 31, 2012 and 2011 were 37.6% and 37.2%, respectively. The increase in the effective income tax rate primarily resulted from changes in estimates and interest related to uncertain and effectively settled tax positions.
During the second quarter of 2011, PHI reached a settlement with the IRS with respect to interest due on its federal tax liabilities related to the tax 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 an additional $4 million (after-tax) interest benefit in the second quarter of 2011. This benefit is partially offset by the 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 tax expense of $1 million (after-tax) associated with the recalculation of interest on uncertain tax positions for open tax years using different assumptions related to the application of its deposit made with the IRS in 2006.
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, 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. See Item 1A. “Risk Factors,” for additional discussion of important factors that may have an effect on DPL’s sources of capital.
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. 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.
DPL
Information concerning the principal amount and terms of DPL’s outstanding First Mortgage Bonds, senior notes, medium-term notes and VRDBs, and tax-exempt bonds issued for the benefit of DPL, as of December 31, 2012, is set forth in Note (11), “Debt,” to the financial statements of DPL.
Bank Financing
As further discussed in Note (11), “Debt,” to the financial statements of DPL, DPL is a borrower under a $1.5 billion credit facility, along with PHI, Pepco and ACE, which expires in 2017. 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, 2012, the maximum capacity available under the program was $500 million, subject to available borrowing capacity under the credit facility.
DPL had $32 million of commercial paper outstanding at December 31, 2012. The weighted average interest rate for commercial paper issued by DPL during 2012 was 0.43% and the weighted average maturity of all commercial paper issued by DPL during 2012 was four days.
Money Pool
DPL participates in the money pool operated by PHI under authorization received from FERC. The money pool is a 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. Borrowings from the money pool are unsecured. 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.
Capital Expenditures
DPL’s capital expenditures for the year ended December 31, 2012 were $320 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
The following table shows DPL’s projected capital expenditures for the five-year period from 2013 through 2017. 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. On January 9, 2013, DPL made a discretionary tax-deductible contribution to the PHI Retirement Plan in the amount of $10 million. DPL contributed $85 million and $40 million to the PHI Retirement Plan during 2012 and 2011, respectively. In 2012 and 2011, DPL contributed $7 million and $6 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 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 has 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.
Smart Grid
ACE is building a smart grid which is designed to meet the challenges of rising energy costs, concerns about the environment, reliability improvement, providing timely and accurate customer information and meeting government energy reduction goals. The installation of smart meters currently has been deferred by the NJBPU. For a discussion of the smart grid, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations - General Overview - Power Delivery Initiatives and Activities - Smart Grid.”
Regulatory Lag
An important factor in the ability of ACE to earn its authorized rate of return is the willingness of the NJBPU to adequately recognize forward-looking costs in its rate structure in order to address the shortfall in revenues due to regulatory lag. ACE is currently experiencing significant regulatory lag because its investment in the rate base and its operating expenses are outpacing revenue growth. The NJBPU has approved certain cost recovery mechanisms in connection with ACE’s Infrastructure Investment Program, which ACE had proposed in 2011 to extend and expand; however, in connection with the settlement in October 2012 of its electric distribution base rate case, ACE withdrew this proposal without prejudice. There can be no assurance that any future attempts by ACE to mitigate regulatory lag will be approved, or that even if approved, any proposed cost recovery mechanisms will fully ameliorate the effects of regulatory lag. Until such time as any cost recovery mechanisms are approved, ACE plans to file rate cases at least annually in an effort to align more closely its revenue and cash flow levels with other operation and maintenance spending and capital investments. ACE filed an electric distribution base rate case on December 11, 2012.
ACE
Results of Operations
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.
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 issued by ACE Funding, 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.
Regulated T&D Electric
ACE
Regulated T&D Electric Revenue increased by $6 million primarily due to:
•
An increase of $15 million due to a rate increase in the New Jersey Societal Benefit Charge effective July 2012 (which is offset in Deferred Electric Service Costs).
•
An increase of $7 million due to distribution rate and customer charge rate increases, each effective November 2012.
The aggregate amount of these increases was partially offset by:
•
A decrease of $6 million in transmission revenue primarily attributable to lower rates effective June 1, 2011.
•
A decrease of $6 million in 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).
•
A decrease of $4 million due to lower non-weather related average customer usage.
Default Electricity Supply
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.
ACE
Default Electricity Supply Revenue decreased by $75 million primarily due to:
•
A decrease of $58 million due to lower sales, primarily as a result of customer migration to competitive suppliers.
•
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.
•
A decrease of $15 million due to lower non-weather related average residential customer usage.
The aggregate amount of these decreases was partially offset by an increase of $37 million as a result of higher Default Electricity Supply rates, primarily due to Basic Generation Charge rate increases that became effective in June 2011 and June 2012.
For the years ended December 31, 2012 and 2011, the percentages of ACE’s total distribution sales that are derived from customers receiving Default Electricity Supply are 51% and 56%, 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 $104 million to $703 million in 2012 from $807 million in 2011 primarily due to:
•
A decrease of $53 million primarily due to customer migration to competitive suppliers.
•
A decrease of $49 million due to lower average electricity costs under Default Electricity Supply contracts.
•
A decrease of $5 million due to lower electricity sales primarily as a result of milder weather during the 2012 winter and spring months, as compared to 2011.
Other Operation and Maintenance
Other Operation and Maintenance expense increased by $13 million to $239 million in 2012 from $226 million in 2011 primarily due to:
•
An increase of $5 million in employee-related-costs, primarily due to pension and other benefit expenses.
•
An increase of $5 million in New Jersey Societal Benefit Program costs that are deferred and recoverable.
•
An increase of $4 million in customer support service and system support costs.
•
An increase of $2 million in self-insurance reserves for general and auto liability claims.
The aggregate amount of these increases was partially offset by:
•
A decrease of $1 million associated with lower preventative maintenance and tree trimming costs due to accelerated efforts made in 2011 to improve reliability.
•
A decrease of $1 million in bad debt expenses.
ACE
Other Operation and Maintenance expense also includes the effects of 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 and is pursuing recovery of these incremental storm restoration costs in its electric distribution base rate case filed on December 11, 2012.
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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 and is pursuing recovery of these incremental storm restoration costs in its electric distribution base rate case filed on December 11, 2012.
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During 2011, ACE incurred incremental storm restoration costs of $8 million associated with Hurricane Irene 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 October 2012 provides for recovery of these costs in New Jersey over a three-year period.
Depreciation and Amortization
Depreciation and Amortization expense decreased by $10 million to $124 million in 2012 from $134 million in 2011 primarily due to 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 (partially offset in Default Electricity Supply Revenue). The decrease was partially offset by an increase of $4 million due to utility plant additions.
Other Taxes
Other Taxes decreased by $7 million to $18 million in 2012 from $25 million in 2011. The decrease was primarily due to decreased TEFA tax collections due to a rate decrease effective January 2012 (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 New Jersey Societal Benefit Programs is reported under Other Operation and Maintenance and the corresponding revenue is reported under Regulated T&D Electric Revenue.
ACE
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.
Income Tax Expense
ACE’s consolidated income tax expense decreased by $15 million to $18 million in 2012 from $33 million in 2011. ACE’s consolidated effective income tax rates for the years ended December 31, 2012 and 2011 were 34.0% and 45.8%, respectively. The decrease in the effective income tax rate primarily resulted from changes in estimates and interest related to uncertain and effectively settled tax positions and a deferred tax adjustment.
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 recorded an additional $1 million (after-tax) of interest due to the IRS. This additional interest expense was recorded in the second quarter of 2011. This expense was further impacted by the adjustment recorded in the third quarter of 2011 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.
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 short-term funding needs, including commercial paper, 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. See Item 1A. “Risk Factors,” for additional discussion of important factors that may have an effect on ACE’s sources of capital.
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. 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.
ACE
Information concerning the principal amount and terms of ACE’s outstanding First Mortgage Bonds, senior notes and VRDBs, and tax-exempt bonds issued for the benefit of ACE, as of December 31, 2012, is set forth in Note (10), “Debt,” to the consolidated financial statements of ACE.
Bank Financing
As further discussed in Note (10), “Debt,” to the consolidated financial statements of ACE, ACE is a borrower under a $1.5 billion credit facility, along with PHI, Pepco and DPL, which expires in 2017. 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 $250 million.
Commercial Paper Program
ACE maintains an ongoing commercial paper program to address its short-term liquidity needs. As of December 31, 2012, the maximum capacity available under the program was $250 million, subject to available borrowing capacity under the credit facility.
ACE had $110 million of commercial paper outstanding at December 31, 2012. The weighted average interest rate for commercial paper issued by ACE during 2012 was 0.41% and the weighted average maturity of all commercial paper issued by ACE during 2012 was three days.
Money Pool
ACE participates in the money pool operated by PHI under authorization received from the NJBPU. The money pool is a 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. Borrowings from the money pool are unsecured. 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.
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, 2012 and 2011, 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.
ACE
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, 2012, 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, 2012 were $256 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.
The following table shows ACE’s projected capital expenditures for the five-year period from 2013 through 2017. ACE expects to fund these expenditures through internally generated cash, external financing and capital contributions from PHI.
(a) Reflects remaining anticipated reimbursements for capital expenditures pursuant to awards from the DOE under the American Recovery and Reinvestment Act of 2009.
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.
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 expenses associated with direct load control and other programs. During 2012, ACE received award payments of $5 million. The cumulative award payments received by ACE as of December 31, 2012, were $13 million.
The IRS has announced that, to the extent these grants are expended on capital items, they will not be considered taxable income.
ACE
Pension and Other Postretirement Benefit Plans
ACE participates in pension and OPEB plans sponsored by PHI for its employees. On January 9, 2013, ACE made a discretionary tax-deductible contribution to the PHI Retirement Plan in the amount of $30 million. ACE also contributed $30 million to the PHI Retirement Plan during each of 2012 and 2011. In 2012 and 2011, ACE contributed $4 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, Chief Operating Officer, 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 (14), “Derivative Instruments and Hedging Activities” of the consolidated financial statements of PHI.
Pepco Holdings, Inc.
Commodity Price Risk
The Pepco Energy Services segment engages in commodity risk management activities to reduce its financial exposure to changes in the value of its assets and obligations due to commodity price fluctuations. Certain of these risk management activities are conducted using instruments classified as derivatives based on FASB guidance on derivatives and hedging, ASC 815. Pepco Energy Services also manages commodity risk with contracts that are not classified as derivatives.
PHI’s risk management policies place oversight at the senior management level through the CRMC, which has the responsibility for establishing corporate compliance requirements for energy market participation. PHI collectively refers to these energy market activities, including its commodity risk management activities, as “energy commodity” activities. PHI uses a value-at-risk (VaR) model to assess the market risk of the energy commodity activities of Pepco Energy Services. PHI also uses other measures to limit and monitor risk in its energy commodity activities, including limits on the nominal size of positions and periodic loss limits. VaR represents the potential fair value loss on energy contracts or portfolios due to changes in market prices for a specified time period and confidence level. PHI uses a delta-gamma VaR estimation model. The other parameters include a 95 percent, one-tailed confidence level and a one-day holding period. Since VaR is an estimate, it is not necessarily indicative of actual results that may occur.
The table below provides the VaR associated with energy contracts of the Pepco Energy Services segment for the year ended December 31, 2012 in millions of dollars:
(a) This column represents all energy derivative contracts, normal purchase and normal sales contracts, modeled generation output and fuel requirements, and modeled customer load obligations for Pepco Energy Services’ energy commodity activities.
Pepco Energy Services purchases electric and natural gas futures, swaps, options and forward contracts to hedge price risk in connection with the purchase of physical natural gas and electricity for distribution to customers. Pepco Energy Services accounts for its derivatives as either cash flow hedges of forecasted transactions or they are marked to market through current earnings. Forward contracts that meet the requirements for normal purchase and normal sale accounting under FASB guidance on derivatives and hedging are recorded on an accrual basis.
Credit and Nonperformance Risk
The following table provides information on the credit exposure on competitive wholesale energy contracts, net of collateral, to wholesale counterparties as of December 31, 2012, in millions of dollars:
(a) Investment Grade - primarily determined using publicly available credit ratings of the counterparty. If the counterparty has provided a guarantee by a higher-rated entity (e.g., its parent), it is determined based upon the rating of its guarantor. Included in “Investment Grade” are counterparties with a minimum Standard & Poor’s or Moody’s Investor Service rating of BBB- or Baa3, respectively.
(b) Exposure before credit collateral - includes the marked to market energy contract net assets for open/unrealized transactions, the net receivable/payable for realized transactions and net open positions for contracts not marked to market. Amounts due from counterparties are offset by liabilities payable to those counterparties to the extent that legally enforceable netting arrangements are in place. Thus, this column presents the net credit exposure to counterparties after reflecting all allowable netting, but before considering collateral held.
(c) Credit collateral - the face amount of cash deposits, letters of credit and performance bonds received from counterparties, not adjusted for probability of default, and, if applicable, property interests (including oil and natural gas reserves).
(d) Using a percentage of the total exposure.
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 rates 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, 2012.
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 rates 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, 2012.
Delmarva Power & Light Company
Commodity Price Risk
DPL uses derivative instruments (forward contracts, futures, swaps, and exchange-traded and over-the-counter options) primarily to reduce natural gas commodity price volatility while limiting its customers’ exposure to increases in the market price of natural gas. 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, 2012, after the effects of cash collateral and netting, DPL had a net derivative liability of $4 million, offset by a $4 million regulatory asset. At December 31, 2011, after the effects of cash collateral and netting, DPL had a net derivative liability of $15 million, offset by a $17 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 rates 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, 2012.
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 rates 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, 2012.
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 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, 2012 based on the framework in Internal Control - Integrated Framework 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, 2012.
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, 2012 and December 31, 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012 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, 2012, based on criteria established in Internal Control - Integrated Framework 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 28, 2013
PEPCO HOLDINGS
PEPCO HOLDINGS, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
The accompanying Notes are an integral part of these Consolidated Financial Statements.
PEPCO HOLDINGS
PEPCO HOLDINGS, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE 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):
•
Potomac Electric Power Company (Pepco), which was incorporated in Washington, D.C. in 1896 and became a domestic Virginia corporation in 1949,
•
Delmarva Power & Light Company (DPL), which was incorporated in Delaware in 1909 and became a domestic Virginia corporation in 1979, and
•
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, high voltage underground transmission cabling, low voltage construction and maintenance services, and construction and operation of combined heat and power and central energy plants. Pepco Energy Services is in the process of winding down its competitive electricity and natural gas retail supply business. Pepco Energy Services constitutes a separate segment for financial reporting purposes.
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 a service agreement 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 agreement.
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.
PEPCO HOLDINGS
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 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 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 Energy Services
Pepco Energy Services is engaged in the following businesses:
•
providing energy savings performance contracting services principally to federal, state and local government customers, and designing, constructing and operating combined heat and power and central energy plants,
•
providing high voltage electric construction and maintenance services to customers throughout the United States, as well as low voltage electric construction and maintenance services and streetlight construction services to utilities, municipalities and other customers in the Washington, D.C. metropolitan area, and
•
providing retail customers electricity and natural gas under its remaining contractual obligations.
Pepco Energy Services deactivated its Buzzard Point oil-fired generation facility on May 31, 2012 and its Benning Road oil-fired generation facility on June 30, 2012. Pepco Energy Services has 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 that the facilities require only essential maintenance until they are completely decommissioned.
In December 2009, PHI announced the wind-down of the retail energy supply component of the Pepco Energy Services business. Pepco Energy Services is implementing this wind-down by not entering into any new retail energy supply contracts while continuing to perform under its existing supply contracts through their respective expiration dates, the last of which is June 1, 2014. PHI is reviewing strategic alternatives to accelerate into 2013 the completion of the wind-down of its remaining portfolio of retail energy contracts.
The retail energy supply business has historically generated a substantial portion of the operating revenues and net income of the Pepco Energy Services segment. Operating revenues related to the retail energy supply business for the years ended December 31, 2012, 2011 and 2010 were $418 million, $962 million and $1,609 million, respectively, while operating income for the same periods was $46 million, $11 million and $59 million, respectively.
In connection with the operation of the retail energy supply business, Pepco Energy Services provided letters of credit of less than $1 million and posted net cash collateral of $25 million as of December 31, 2012. These collateral requirements, which are based on existing wholesale energy purchase and sale contracts and current market prices, will decrease as the contracts expire, with the collateral expected to be fully released by June 1, 2014. The energy savings services business will not be affected by the wind-down of the retail energy supply business.
Other Business Operations
Through its subsidiary Potomac Capital Investment Corporation (PCI), PHI maintains a portfolio of cross-border energy lease investments. This activity constitutes a third operating segment for financial reporting purposes, which is designated as “Other Non-Regulated.” For a discussion of PHI’s cross-border energy lease investments, see Note (8), “Leasing Activities - Investment in Finance Leases Held in Trust,” Note (16), “Commitments and Contingencies - PHI’s Cross-Border Energy Lease Investments,” and Note (20), “Subsequent Event.”
PEPCO HOLDINGS
Discontinued Operations
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 subsidiaries of Conectiv Energy Holding Company (collectively, Conectiv Energy). On July 1, 2010, PHI completed the sale of Conectiv Energy’s wholesale power generation business to Calpine Corporation (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. The former operations of Conectiv Energy have been classified as a discontinued operation and are no longer treated as a separate 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.
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 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. Subsidiaries of PHI have the following contractual arrangements to which the guidance applies.
ACE Power Purchase Agreements
PHI, through its ACE subsidiary, is a party to three power purchase agreements (PPAs) with unaffiliated, non-utility generators (NUGs) totaling 459 megawatts (MWs). One of the agreements ends in 2016 and the other two end in 2024. PHI was 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 applied the scope exemption from the consolidation guidance for enterprises that have not been able to obtain such information.
Net purchase activities with the NUGs for the years ended December 31, 2012, 2011 and 2010, were approximately $206 million, $218 million and $292 million, respectively, of which approximately $201 million, $206 million and $270 million, respectively, consisted of power purchases under the PPAs. The power purchase costs are recoverable from ACE’s customers through regulated rates.
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, 2012, PHI, through its DPL subsidiary, has entered into 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 PPAs. PHI has concluded that consolidation is not required for any of these PPAs under the FASB guidance on the consolidation of variable interest entities.
PEPCO HOLDINGS
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, in each case at the rates primarily fixed by the PPA. DPL’s purchases under the three wind PPAs totaled $27 million, $18 million and $12 million for the years ended December 31, 2012, 2011 and 2010, 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 $2 million and $1 million for the years ended December 31, 2012 and 2011, respectively.
On October 18, 2011, the Delaware Public Service Commission (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 would have no liability 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. In June 2012, a 3 MW fuel cell generation facility was placed into service under the tariff. DPL billed $4 million to distribution customers during the year ended December 31, 2012. A 27 MW fuel cell generation facility is expected to be placed into service over time, with the first 5 MW increment having been placed into service at the end of 2012. DPL is accounting for this arrangement as an agency transaction.
Atlantic City Electric Transition Funding LLC
Atlantic City Electric Transition Funding LLC (ACE Funding) was established in 2001 by ACE 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 have been transferred to ACE in exchange for the transfer by ACE to ACE Funding of the right to collect non-bypassable transition bond charges (the Transition Bond Charges) from ACE customers pursuant to bondable stranded costs rate orders issued by the New Jersey Board of Public Utilities (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). ACE collects the Transition Bond Charges from its customers on behalf of ACE Funding and the holders of the Transition Bonds. The assets of ACE Funding, including the Bondable Transition Property, and the Transition Bond Charges collected from ACE’s customers, are not available to creditors of ACE. The holders of the Transition Bonds have recourse only to the assets of ACE Funding. ACE owns 100 percent of the equity of ACE Funding and PHI consolidates ACE Funding in its consolidated financial statements as ACE is the primary beneficiary of ACE Funding under the variable interest entity consolidation guidance.
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. The SOCAs were established under a New Jersey law enacted to promote the construction of qualified electric generation facilities in New Jersey. The SOCAs are 15-year, financially settled transactions approved by the NJBPU that allow generation companies to receive payments from, or require them to make payments to, ACE based on the difference between the fixed price in the SOCAs and the price for capacity that clears PJM Interconnection, LLC (PJM). Each of the other electric distribution companies (EDCs) in New Jersey has entered into SOCAs having the same terms with the same generation companies. ACE’s share of the payments received from or the payments made to the generation companies is currently estimated to be approximately 15 percent, based on its proportionate share of the total New Jersey electric load for all EDCs. The NJBPU has ordered that ACE
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is obligated to distribute to its distribution customers all payments it receives from the generation companies and may recover from its distribution customers all payments it makes to the generation companies. For additional discussion about the SOCAs, see Note (7), “Regulatory Matters.”
In May 2012, all three generation companies under the SOCAs bid into the PJM 2015-2016 capacity auction and two of the generators cleared that capacity auction. ACE recorded a derivative asset (liability) for the estimated fair value of each SOCA and recorded an offsetting regulatory liability (asset) as described in more detail in Note (14), “Derivative Instruments and Hedging Activities,” and Note (15), “Fair Value Disclosures.” FASB guidance on derivative accounting and the accounting for regulated operations would apply to ACE’s obligations under the third SOCA once the related capacity has cleared a PJM auction. The next PJM capacity auction is scheduled for May 2013. PHI has concluded that consolidation of the generation companies is not required.
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 self-insurance reserves for general and auto liability claims, accrual of interest related to income taxes, the recognition of income tax benefits for investments in finance leases held in trust associated with PHI’s portfolio of 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.
Storm Restoration Costs
The respective service territories of Pepco, DPL and ACE were affected by a rapidly moving thunderstorm with hurricane-force winds, known as a “derecho,” on June 29, 2012, and Hurricane Sandy on October 29, 2012. Both of these storms resulted in widespread customer outages in each of the service territories and caused extensive damage to the electric transmission and distribution systems of each utility.
Total incremental storm restoration costs incurred by PHI for the derecho and Hurricane Sandy through December 31, 2012 were $138 million, with $66 million incurred for repair work and $72 million incurred as capital expenditures. Costs incurred for repair work of $56 million were deferred as regulatory assets to reflect the probable recovery of these storm restoration costs in Maryland and New Jersey, and $10 million was charged to Other operation and maintenance expense. As of December 31, 2012, total incremental storm restoration costs include $33 million of estimated costs for unbilled restoration services provided by certain outside contractors. Actual costs for these services may vary from the estimates. PHI’s utility subsidiaries are pursuing recovery of these incremental storm restoration costs in their respective jurisdictions in their electric distribution base rate cases.
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General and Auto Liability
During 2011, PHI’s utility subsidiaries reduced their self-insurance reserves for general and auto liability claims by approximately $4 million, based on obtaining an actuarial estimate of the unpaid losses attributed to general and auto liability claims for each of PHI’s utility subsidiaries. A similar evaluation was performed during 2012 and a reduction of less than $1 million was made to these reserves.
Accrual of Interest Associated with 1996 to 2002 Federal Income Tax Returns
In November 2010, PHI reached final settlement with the Internal Revenue Service (IRS) with respect to its federal tax returns for the years 1996 to 2002 for all issues except its cross-border energy lease investments. PHI also reallocated certain amounts on deposit with the IRS since 2006 among liabilities in the settlement years and subsequent years. In connection with these activities, PHI has recalculated the estimated interest due for the tax years 1996 to 2002. These calculations resulted in the reversal of $15 million (after-tax) of previously accrued estimated interest due to the IRS which was recorded as an income tax benefit in the fourth quarter of 2010. PHI recorded a further $17 million (after-tax) income tax benefit in the second quarter of 2011.
Network Service Transmission Rates
In May of each year, each of PHI’s utility subsidiaries provides its updated network service transmission rate to the Federal Energy Regulatory Commission (FERC) effective for the service year beginning June 1 of the current year and ending May 31 of the following year. The network service transmission rate includes a true-up for costs incurred in the prior service year not yet reflected in rates charged to customers.
Investments in Finance Leases Held in Trust
As further discussed in Note (8), “Leasing Activities,” Note (12), “Income Taxes,” Note (16), “Commitments and Contingencies - PHI’s Cross-Border Energy Lease Investments,” and Note (20), Subsequent Event,” PHI maintains a portfolio of cross-border energy lease investments. The book equity value of these cross-border energy lease investments and the pattern of recognizing the related cross-border energy lease income are based on the estimated timing and amount of all cash flows related to the cross-border energy lease investments, including income tax-related cash flows. These investments are more commonly referred to as sale-in lease-out, or SILO, transactions. PHI currently derives tax benefits from these investments to the extent that rental income is exceeded by depreciation deductions based on the purchase price of the assets and interest deductions on the non-recourse debt financing (obtained to fund a substantial portion of the purchase price of the assets). The IRS has announced broadly its intention to disallow the tax benefits recognized by all taxpayers on these types of investments. More specifically, the IRS has disallowed interest and depreciation deductions claimed by PHI related to its cross-border energy lease investments on its 2001 through 2008 federal income tax returns, which currently are under audit and the IRS has sought to recharacterize the leases as loan transactions as to which PHI would be subject to original issue discount income.
In the last several years, IRS challenges to certain cross-border energy lease investment transactions have been the subject of litigation. PHI believes that its tax position with regard to its cross-border energy lease investments was appropriate based on applicable statutes, regulations and case law. However, after evaluating the court rulings available at the time, there have been several decisions in favor of the IRS that were factored into PHI’s decision to adjust the values of the cross-border energy lease investments at certain points in time.
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Revenue Recognition
Regulated Revenue
Power Delivery recognizes revenue upon distribution of electricity and gas to its customers, including unbilled revenue for services rendered but not yet billed. PHI’s unbilled revenue was $182 million and $179 million as of December 31, 2012 and 2011, 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 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 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 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. Excise tax related generally to the consumption of gasoline by PHI and its subsidiaries in the normal course of business is charged to operations, maintenance or construction, and is not material.
Pepco Energy Services Revenue
Pepco Energy Services has recognized revenue upon distribution of electricity and gas to customers, including amounts for electricity and gas delivered, but not yet billed. Sales and purchases of electric power to independent system operators are netted hourly and classified as operating revenue or operating expenses, as appropriate. Unrealized derivative gains and losses are recognized in current earnings as revenue if the derivatives do not qualify for hedge accounting or normal purchases or normal sales treatment under FASB guidance on derivatives and hedging (ASC 815). Revenue for Pepco Energy Services’ energy savings services business is recognized using the percentage-of-completion method, for its construction activities, which recognizes revenue as work is completed on the contract. Revenues from its operation and maintenance activities and measurement and verification activities in its energy savings services business are recognized when earned.
Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions
Taxes included in PHI’s gross revenues were $356 million, $378 million and $362 million for the years ended December 31, 2012, 2011 and 2010, respectively.
Accounting for Derivatives
PHI and its subsidiaries 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 unless designated as normal purchases or normal sales.
Changes in the fair value of derivatives held by Pepco Energy Services, DPL or ACE that do not qualify for hedge accounting or are not designated as hedges are presented on the consolidated statements of income as Fuel and purchased energy expense or Operating revenue, respectively. Changes in the fair value of derivatives held by DPL and ACE are deferred as regulatory assets or liabilities under the accounting guidance for regulated activities.
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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 as Operating revenue or as Fuel and purchased energy expense.
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 as Operating revenue in the consolidated statements of 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 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. See Note (14), “Derivative Instruments and Hedging Activities,” for more information about the components of unrealized and realized gains and losses on derivatives.
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 are used to determine fair value. For some custom and complex instruments, internal models are used to interpolate broker-quality price information. For certain long-dated instruments, broker or exchange data are extrapolated, or capacity prices are forecasted, for future periods where limited market information is available. Models are also used to estimate volumes for certain transactions. See Note (14), “Derivative Instruments and Hedging Activities,” for more information about the types of derivatives employed by PHI and Note (15), “Fair Value Disclosures,” for the methodologies used to value them.
PHI designates certain commodity forwards as normal purchases or normal sales, which are not required to be recorded in the financial statements until they are settled. These commodity forwards are used in normal operations, settle physically and follow standard accrual accounting. Unrealized gains and losses on these contracts are not recorded in the financial statements. Examples of these commodity forwards include purchases by Pepco Energy Services of natural gas or electricity for delivery to customers. Normal sales transactions include agreements by Pepco Energy Services to deliver natural gas and electric power to customers. Normal purchases and normal sales transactions are separately presented on a gross basis when they settle, with normal sales recorded as Operating revenue and normal purchases recorded as Fuel and purchased energy expenses.
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. In addition, compensation expense recognized includes the cost for all stock-based awards granted prior to, but not yet vested as of January 1, 2006, measured at the grant-date fair value. 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.
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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 estimates the fair value of stock option awards on the date of grant using the Black-Scholes-Merton option pricing model. This model uses assumptions related to expected term, expected volatility, expected dividend yield, and the risk-free interest rate. PHI uses historical data to estimate award exercises and employee terminations within the valuation model; groups of employees that have similar historical exercise behavior are 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 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 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 (12), “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.
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 Investments and 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.
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Accounts Receivable and Allowance for Uncollectible Accounts
Pepco Holdings’ Accounts receivable balances primarily consist of customer accounts receivable, other accounts receivable, and accrued unbilled revenue generated by subsidiaries in Power Delivery and at Pepco Energy Services. 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 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. Although management 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.
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. Substantially all of Pepco Holdings’ goodwill was generated by Pepco’s acquisition of Conectiv in 2002 and is allocated entirely to Power Delivery for purposes of impairment testing based on the aggregation of its components because its utilities have similar characteristics. Pepco Holdings 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 reduce the 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 below book value; an adverse regulatory action; or an impairment of long-lived assets in the reporting unit. PHI performed its annual impairment test on November 1, 2012 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 DPSC and the MPSC. DPL’s interstate transportation and wholesale sale of natural gas are regulated by FERC. The operations of ACE are regulated by the NJBPU. The transmission of electricity by Pepco, DPL, and ACE is regulated by FERC.
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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. 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 PPAs. In accordance with FASB guidance on leases (ASC 840), these leases are classified as either leveraged leases, operating leases or capital leases.
Leveraged Leases
Income from investments in leveraged lease transactions, in which PHI is an equity participant, is accounted for using the financing method. In accordance with the financing method, investments in leased property are recorded as a receivable from the lessee to be recovered through the collection of future rentals. Income is recognized over the life of the lease at a constant rate of return on the positive net investment. Each quarter, PHI reviews the carrying value of each lease, which includes 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, would be 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 occur.
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.
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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 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, 2012, 2011 and 2010.
(a) Percentages reflect accelerated depreciation of the Benning Road and Buzzard Point generating facilities retired during 2012.
In 2010, subsidiaries of PHI received awards from the U.S. Department of Energy under the American Recovery and Reinvestment Act of 2009. Pepco was awarded $149 million 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 electric and gas 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 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 awards as a reduction in the carrying value of the assets acquired rather than grant income over the service period.
Long-Lived Asset Impairment Evaluation
Pepco Holdings 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 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 fair value including costs to sell.
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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 income.
Pepco Holdings recorded AFUDC for borrowed funds of $7 million, $11 million and $8 million for the years ended December 31, 2012, 2011 and 2010, respectively.
Pepco Holdings recorded amounts for the equity component of AFUDC of $14 million, $15 million and $10 million for the years ended December 31, 2012, 2011 and 2010, 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, 2012 and 2011, $324 million and $388 million of asset removal costs, respectively, are included in Regulatory liabilities in the accompanying consolidated 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, DPL, ACE and certain employees of other Pepco Holdings subsidiaries. Pepco Holdings also provides supplemental retirement benefits to certain eligible executives and key employees through a nonqualified retirement plan and provides certain postretirement health care and life insurance benefits for eligible retired employees.
Pepco Holdings 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 (10), “Pension and Other Postretirement Benefits,” for additional information.
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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:
Pepco Energy Services Derivative Accounting Reclassifications and Adjustments
During 2012, PHI recorded an adjustment to reclassify certain 2011 and 2010 mark-to-market losses from Operating revenue to Fuel and purchased energy expenses for Pepco Energy Services. The reclassification resulted in an increase in Operating revenue and an increase in Fuel and purchased energy expenses of $31 million and $1 million for the years ended December 31, 2011 and 2010, respectively. This reclassification did not result in a change in net income.
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 an increase in revenue and pre-tax earnings of $2 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.
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.
Operating Expenses
During 2010, Pepco recorded an adjustment to correct certain errors related to other taxes which resulted in a decrease to Other taxes expense of $5 million (pre-tax) for the year ended December 31, 2010.
As further described in Note (9), “Property, Plant and Equipment,” in the fourth quarter of 2010, PHI recorded an accrual of $4 million for the obligations associated with the planned deactivation of Pepco Energy Services’ two oil-fired generating facilities. Of this amount, $1 million should have been recorded in each of 2009, 2008 and 2007.
Income Tax Expense Related to Continuing Operations
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.
During 2010, PHI recorded an adjustment to correct certain income tax errors related to prior periods. The adjustment resulted in a decrease in income tax expense of $5 million for the year ended December 31, 2010.
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(3) NEWLY ADOPTED ACCOUNTING STANDARDS
Goodwill (ASC 350)
The FASB issued new guidance that changes the annual and interim assessments of goodwill for impairment. The new guidance modifies the required annual impairment test by giving entities the option to perform a qualitative assessment of whether it is more likely than not that goodwill is impaired before performing a quantitative assessment. The new guidance also amends the events and circumstances that entities should assess to determine whether an interim quantitative impairment test is necessary. As of January 1, 2012, PHI has adopted the new guidance and concluded it did not have a material impact on its consolidated financial statements.
Fair Value Measurements and Disclosures (ASC 820)
The FASB issued new guidance on fair value measurement and disclosures that was effective beginning with PHI’s March 31, 2012 consolidated financial statements. The new measurement guidance did not have a material impact on PHI’s consolidated financial statements and the new disclosure requirements are in Note (15), “Fair Value Disclosures,” of PHI’s consolidated financial statements.
Comprehensive Income (ASC 220)
The FASB issued new disclosure requirements for reporting comprehensive income that were effective beginning with PHI’s March 31, 2012 consolidated financial statements. PHI did not have to change the presentation of its comprehensive income because it had already reported comprehensive income in two separate but consecutive statements of income and comprehensive income. PHI also has provided the new required disclosures of the income tax effects of items in other comprehensive income and amounts reclassified from other comprehensive income to income on a quarterly basis in Note (17), “Accumulated Other Comprehensive Loss.”
(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED
Balance Sheet (ASC 210)
The FASB issued new disclosure requirements for derivatives that will include information about the gross exposures 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. The new disclosures are effective beginning with PHI’s March 31, 2013 consolidated financial statements. PHI does not expect this guidance to have a material impact on its consolidated financial statements.
Comprehensive Income (ASC 220)
In February 2013, the FASB issued new disclosure requirements for reclassifications from accumulated other comprehensive income. The new disclosure requirements are effective for PHI beginning with its March 31, 2013 consolidated financial statements and will require 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 will include 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 does not expect this guidance to have a material impact on its consolidated financial statements.
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(5) SEGMENT INFORMATION
Pepco Holdings’ management has identified its operating segments at December 31, 2012 as Power Delivery, Pepco Energy Services and Other Non-Regulated. 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. Segment financial information for continuing operations for the years ended December 31, 2012, 2011 and 2010, 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 the Corporate and Other segment 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, $(18) million for Interest Expense and $(3) million for Preferred Stock Dividends.
(b) Includes depreciation and amortization expense of $454 million, consisting of $416 million for Power Delivery, $14 million for Pepco Energy Services, $2 million for Other Non-Regulated and $22 million for Corporate and Other.
(c) 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.
(d) Includes $39 million pre-tax ($9 million after-tax) gain from the early termination of finance leases held in trust.
(e) Includes a $16 million charge related to the recognition of the tax consequences associated with the early termination of finance leases held in trust.
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(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 the Corporate and Other segment 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, $(22) million for Interest Expense, and $(3) million for Preferred Stock Dividends.
(b) Includes depreciation and amortization expense of $426 million, consisting of $394 million for Power Delivery, $17 million for Pepco Energy Services, $2 million for Other Non-Regulated, and $13 million for Corporate and Other.
(c) Includes $39 million pre-tax ($3 million after-tax) gain from the early termination of cross-border energy leases held in trust.
(d) Includes tax benefits of $14 million for Power Delivery primarily associated with an interest benefit related to federal tax liabilities and a $22 million charge for Other Non-Regulated related to the recognition of the tax consequences associated with the early termination of cross-border energy leases held in trust.
(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 the Corporate and Other segment and are allocated to Power Delivery once the assets are placed in service. Corporate and Other includes intercompany amounts of $(12) million for Operating Revenue, $(10) million for Operating Expense, $(36) million for Interest Income, $(36) million for Interest Expense, and $(3) million for Preferred Stock Dividends.
(b) Includes depreciation and amortization expense of $393 million, consisting of $357 million for Power Delivery, $24 million for Pepco Energy Services, $1 million for Other Non-Regulated, and $11 million for Corporate and Other.
(c) Includes restructuring charge of $30 million, consisting of $29 million for Power Delivery and $1 million for Corporate and Other.
(d) Includes $11 million expense related to effects of Pepco divestiture-related claims.
(e) Includes $174 million ($104 million after-tax) related to loss on extinguishment of debt and $15 million ($9 million after-tax) related to the reclassification of treasury rate lock losses from AOCL to income related to cash tender offers for debt made in 2010.
(f) Includes $12 million of net Federal and state income tax benefits primarily related to adjustments of accrued interest on uncertain and effectively settled tax positions.
(g) Includes $14 million of state tax benefits resulting from the restructuring of certain PHI subsidiaries and $17 million of state income tax benefits associated with the loss on extinguishment of debt, partially offset by a charge of $3 million to write off deferred tax assets related to the subsidy pursuant to the prescription drug benefit (Medicare Part D) under the Medicare Prescription Drug Improvement and Modernization Act of 2003 (the Medicare Act).
PEPCO HOLDINGS
(6) GOODWILL
Substantially all of PHI’s $1.4 billion goodwill balance as of December 31, 2012 and 2011 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). PHI’s annual impairment test as of November 1, 2012 indicated that goodwill was not impaired.
In order to estimate the fair value of its 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 cash flow analysis using estimated future cash flows 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 Power Delivery reporting unit. PHI determines the estimated WACC by considering market-based information for the cost of equity and cost of debt that is appropriate for Power Delivery 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 framework to estimate the fair value of Power Delivery.
The estimation of fair value is dependent on a number of factors that are derived from the Power Delivery reporting unit’s business forecast, 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 in the models were consistent with historical experience, including assumptions concerning the recovery of operating costs and capital expenditures. 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 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 (Pepco Energy Services and Other Non-Regulated) at November 1, 2012. The sum of the fair value of all reporting units was reconciled to PHI’s market capitalization at November 1, 2012 to corroborate estimates of the fair value of its reporting units. The sum of the estimated fair values of all reporting units exceeded the market capitalization of PHI at November 1, 2012. 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.
PHI’s gross amount of goodwill, accumulated impairment losses and carrying amount of goodwill for the years ended December 31, 2012 and 2011 were as follows:
PEPCO HOLDINGS
(7) REGULATORY MATTERS
Regulatory Assets and Regulatory Liabilities
The components of Pepco Holdings’ regulatory asset and liability balances at December 31, 2012 and 2011 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, prior service cost (credit) and transition liability 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 (10), “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 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 bonds mature between 2013 and 2023. A customer surcharge is collected by ACE to fund principal and interest payments on the Transition Bonds.
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Smart Grid: 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. Approval of AMI has been deferred by the NJBPU for ACE in New Jersey.
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.
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.
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), for which recovery through regulated utility rates is considered probable in the Maryland and New Jersey jurisdictions. Pepco’s and DPL’s costs related to Hurricane Irene and Pepco’s costs related to the 2011 severe winter storm are being amortized and recovered in rates over a five-year period. ACE’s costs related to Hurricane Irene are being amortized and recovered in rates 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 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. These assets are currently earning a return of 12.8%.
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.
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.
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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 is being amortized as a reduction in Depreciation and amortization expense over an 8.25 year period, which began in June 2005 and expires in 2013.
Other: Includes miscellaneous regulatory liabilities.
Rate Proceedings
Over the last several years, PHI’s utility subsidiaries have proposed in each of their respective jurisdictions the adoption of a mechanism to decouple retail distribution revenue from the amount of power delivered to retail customers. To date:
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A BSA was approved and implemented for Pepco and DPL electric service in Maryland and for Pepco electric service in the District of Columbia. In October 2012, the MPSC modified the BSA so that a BSA surcharge is not permitted to be collected for revenues lost during the first 24 hours of a major storm. For further information on the BSA in Maryland, see “Maryland - BSA Proceeding” below.
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A modified fixed variable rate design (MFVRD) for DPL electric and natural gas service in Delaware is under consideration by the DPSC.
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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 under consideration by the DPSC in Delaware provides for a fixed customer charge (i.e., not tied to the customer’s volumetric consumption of electricity or natural gas) to recover the utility’s fixed costs, plus a reasonable rate of return. Although different from the BSA, PHI views the MFVRD as an appropriate distribution revenue decoupling mechanism.
In an effort to reduce the shortfall in revenues due to the delay in time or lag between when costs are incurred and when they are reflected in rates (regulatory lag), Pepco and DPL had proposed, in each of their respective jurisdictions, (i) a reliability investment recovery mechanism (RIM) to recover reliability-related capital expenditures incurred between base rate cases, and (ii) the use of fully forecasted test years in future rate cases (which reflect forward-looking costs in lieu of costs incurred over historical test years, and if approved, would be more reflective of current costs and would mitigate the effects of regulatory lag). These proposals were generally not adopted in any of the jurisdictions in which they were filed, as discussed below in connection with the discussions of Pepco’s and DPL’s respective electric distribution base rate proceedings.
Delaware
Gas Cost Rates
DPL makes an annual Gas Cost Rate (GCR) filing with the DPSC for the purpose of allowing DPL to recover natural gas procurement costs through customer rates. In August 2011, DPL made its 2011 GCR filing. The filing included the second year of the effect of a two-year amortization of under-recovered gas costs proposed by DPL in its 2010 GCR filing (the settlement approved by the DPSC in its 2010 GCR case included only the first year of the proposed two-year amortization). The rates proposed in the 2011 GCR would result in a GCR decrease of approximately 5.6%. On August 21, 2012, the DPSC issued a final order approving the rates as filed.
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In August 2012, DPL made its 2012 GCR filing. The rates proposed in the 2012 GCR would result in a GCR decrease of approximately 22.3%. On September 18, 2012, the DPSC issued an order allowing DPL to place the new rates into effect on November 1, 2012, subject to refund and pending final DPSC approval.
Electric Distribution Base Rates
In December 2011, DPL submitted an application with the DPSC to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $31.8 million, based on a requested return on equity (ROE) of 10.75%, and requested approval of implementation of the MFVRD. The filing included a request for DPSC approval of a RIM and the use of fully forecasted test years in future DPL rate cases. In January 2012, the DPSC entered an order suspending the full increase and allowing a temporary rate increase of $2.5 million to go into effect on January 31, 2012, subject to refund and pending final DPSC approval. In July 2012, in accordance with an agreement with DPSC staff, DPL placed an additional $22.3 million of the requested rate increase into effect, also subject to refund and pending final DPSC order. On November 29, 2012, the DPSC approved a proposed settlement agreement entered into by DPL and the other parties to the proceeding that provides for an annual rate increase of $22 million, based on an ROE of 9.75%. The settlement agreement also permits DPL to collect from its standard offer service (SOS) customers (retail customers who do not elect to purchase electricity from a competitive supplier but instead purchase such electricity from DPL at regulated rates) approximately $3.4 million related to various state and local taxes that were assessed upon DPL’s SOS customers, but actually paid by DPL rather than by the SOS customers upon whom they were assessed. These taxes would be collected over a three-year period. In addition, the settlement agreement allows for the phase-in of the recovery of costs associated with DPL’s AMI system. The settlement agreement does not include approval of a RIM or the use of fully forecasted test years in future DPL rate cases, but it does provide that the parties will meet and discuss alternate regulatory methodologies for the mitigation of regulatory lag. DPL refunded the billed amounts that exceeded the increase approved by the DPSC in February 2013.
Gas Distribution Base Rates
On December 7, 2012, DPL submitted an application with the DPSC to increase its natural gas distribution base rates. The filing seeks approval of an annual rate increase of approximately $12.2 million, based on a requested ROE of 10.25%. The requested rate increase is for the purposes of recovering expenses associated with DPL’s ongoing efforts to maintain safe and reliable service and to provide enhanced customer service technology. In January 2013, the DPSC suspended the full proposed increase and, as permitted by state law, DPL implemented an interim increase of $2.5 million on February 5, 2013, subject to refund and pending final DPSC approval. In compliance with state law and DPSC regulations, DPL also is requesting from the DPSC approval of a Utility Facilities Relocation Charge rider for recovery of future costs associated with the relocation of certain gas delivery service facilities that may be requested by the Delaware Department of Transportation. A final DPSC decision is expected by the third quarter of 2013.
District of Columbia
In July 2011, Pepco filed an application with the DCPSC to increase its electric distribution base rates by approximately $42 million annually (subsequently reduced to approximately $39 million), based on a requested ROE of 10.75%, of which approximately $9 million was sought so that Pepco could recover its costs associated with the AMI system. The filing included a request for DCPSC approval of a RIM and the use of fully forecasted test years in future Pepco rate cases. On September 26, 2012, the DCPSC
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issued its decision approving a rate increase of $24 million, based on an ROE of 9.5%, of which approximately $9 million allows Pepco to recover costs associated with the AMI system. The DCPSC denied Pepco’s request for approval of a RIM, and reserved final judgment on the appropriateness of the use by Pepco of a fully forecasted test year in future rate cases. In addition, the DCPSC approved an adjustment by Pepco to normalize operation and maintenance expenses associated with storm restoration efforts to its three-year average, but added approximately $2 million of costs associated with Hurricane Irene from August 2011 in the calculation of the three-year average storm costs.
Maryland
DPL Electric Distribution Base Rates
In December 2011, DPL submitted an application with the MPSC to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $25.2 million (subsequently reduced by DPL to $23.5 million), based on a requested ROE of 10.75%. The filing included a request for MPSC approval of a RIM and the use of fully forecasted test years in future DPL rate cases. In July 2012, the MPSC issued an order approving an annual rate increase of approximately $11.3 million, based on an ROE of 9.81%. The MPSC reduced DPL’s depreciation rates, which is expected to lower annual depreciation and amortization expenses by an estimated $4.1 million. The order did not approve DPL’s request to implement a RIM and did not endorse the use by DPL of fully forecasted test years in future rate cases; however, the MPSC did permit an adjustment to DPL’s rate base to reflect the actual costs of reliability plant additions outside the test year. The order also authorizes DPL to recover in rates over a five-year period $4.3 million of the $4.6 million of incremental storm restoration costs associated with Hurricane Irene that had been deferred previously as a regulatory asset by DPL. The new revenue rates and lower depreciation rates were effective on July 20, 2012.
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%. The filing included a request for MPSC approval of a RIM and the use of fully forecasted test years in future Pepco rate cases. 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 MPSC also directed Pepco to reduce the amount of the rate increase by approximately $1.6 million, the annual costs of certain energy advisory programs, resulting in a final rate increase of approximately $16.5 million. Pepco would be required to seek recovery of these annual costs through the EmPower Maryland Program (a demand-side management program) surcharge. The MPSC reduced Pepco’s depreciation rates, which is expected to lower annual depreciation and amortization expenses by an estimated $27.3 million. The order did not approve Pepco’s request to implement a RIM and did not endorse the use by Pepco of fully forecasted test years in future rate cases; however, the MPSC did permit an adjustment to Pepco’s rate base to reflect the actual costs of reliability plant additions outside the test year. The order authorizes Pepco to recover in rates over a five-year period $18.5 million of incremental storm restoration costs associated with major weather events in 2011, including $9.7 million of the $9.9 million of incremental storm restoration costs associated with Hurricane Irene that had been deferred previously as a regulatory asset by Pepco and $8.8 million of incremental storm restoration costs incurred by Pepco associated with a severe winter storm in the first quarter of 2011 that had been expensed previously through other operation and maintenance expense in 2011. The incremental storm restoration costs of $8.8 million were reversed and deferred as a regulatory asset in the third quarter of 2012. The order also authorizes Pepco to recover the actual cost of AMI meters installed during the test year and states that cost recovery for AMI deployment will only be allowed in future rate cases in which Pepco demonstrates that the system is proven to be cost effective. The new revenue rates and lower depreciation rates were effective on July 20, 2012. The Maryland Office of People’s Counsel has sought rehearing on the portion of the order allowing Pepco to recover the costs of installed AMI meters; that motion remains pending.
PEPCO HOLDINGS
On November 30, 2012, 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 $60.8 million, based on a requested ROE of 10.25%. The requested rate increase is for the purpose of recovering reliability enhancements to serve Maryland customers. Pepco also proposes a three-year Grid Resiliency surcharge 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 is one of several recommendations included in a September 2012 report from Maryland’s Grid Resiliency Task Force (as discussed below). The surcharge, if approved, would become effective January 1, 2014 and would be implemented as a rider that is separate from base rates and would include a return on investment. Specific projects under Pepco’s plan include 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 proposes 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 provides a credit to customers of up to $1 million in total if Pepco does not meet at least the minimum targets. Pepco requests that any credits/charges would flow through the proposed Grid Resiliency Charge rider. An MPSC decision is expected by the end of the second quarter of 2013.
BSA Proceeding
As in effect for electric utilities in Maryland prior to October 26, 2012, including Pepco and DPL, a utility was not permitted to collect a BSA surcharge for distribution revenues lost as a result of major storm outages, beginning 24 hours after the commencement of a major storm, if electric service is not restored to the pre-major storm levels within 24 hours of the start of the storm. On October 26, 2012, the MPSC issued an order that no longer permits certain Maryland utilities, including Pepco and DPL, to collect a BSA surcharge for revenues lost during the first 24 hours of a major storm.
New Jersey
Electric Distribution Base Rates
In August 2011, ACE filed a petition with the NJBPU to increase its electric distribution rates by the net amount of approximately $54.6 million (which was increased to approximately $74.3 million on February 24, 2012, to reflect the 2011 test year), based on a requested ROE of 10.75%. The modified net increase consists of a rate increase proposal of approximately $90.3 million, less a deduction from base rates of approximately $16 million through a credit rider expected to expire August 31, 2013, which is designed to refund to customers certain excess depreciation reserve funds as previously directed by the NJBPU (the Excess Depreciation Rider). ACE also proposed an increase of approximately $6.3 million in sales-and-use taxes related to the increase in base rates. On October 23, 2012, the NJBPU approved a stipulation of settlement signed by the parties (the New Jersey Settlement), which provides for an annual increase in ACE’s electric distribution base rates by the net amount of approximately $28 million, based on an ROE that, as part of the overall settlement, is deemed to be 9.75%. The net increase consists of a rate increase of approximately $44 million, less a deduction from base rates of approximately $16 million through the Excess Depreciation Rider. Upon expiration of the Excess Depreciation Rider, ACE will not realize an increase in operating income because the resulting increase in revenues will be offset by a substantially equivalent increase in depreciation expense. The New Jersey Settlement also provides for an increase of approximately $2 million in sales-and-use taxes related to the increase in base rates, and allows ACE to fully amortize over a three-year period the approximately $7.7 million in costs incurred as a result of Hurricane Irene in August 2011. The new rates became effective for utility services rendered on and after November 1, 2012.
On December 11, 2012, ACE filed with the NJBPU an application, 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
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Regulatory Asset Recovery Charge (costs associated with deferred, NJBPU-approved expenses incurred as part of ACE’s obligation to serve the public) in the amount of approximately $1.7 million. The requested rate increase is for the purposes of continuing to implement reliability-related investments, recovering system restoration costs associated with the June derecho storm and Hurricane Sandy, and providing an opportunity to earn a reasonable rate of return on its investment. An NJBPU decision is expected by the fourth quarter of 2013.
Infrastructure Investment Program
In July 2009, the NJBPU approved certain rate recovery mechanisms in connection with ACE’s Infrastructure Investment Program (the IIP). In exchange for the increase in infrastructure investment, the NJBPU, through the IIP, allowed recovery by ACE of its infrastructure investment capital expenditures through a special rate outside the normal rate recovery mechanism of a base rate filing. The IIP was designed to stimulate the New Jersey economy and provide incremental employment in ACE’s service territory by increasing the infrastructure expenditures to a level above otherwise normal budgeted levels. In an October 18, 2011 petition (subsequently amended December 16, 2011) filed with the NJBPU, ACE requested an extension and expansion to the IIP. The New Jersey Settlement approved by the NJBPU provided for full cost recovery of ACE’s initial IIP, as approved by the NJBPU in 2009, but required ACE to withdraw its request for extension and expansion to the IIP, without prejudice to file such request again in the future. On November 8, 2012, ACE withdrew its request for extension and expansion to the IIP.
Update and Reconciliation of Certain Under-Recovered Balances
In February 2012, ACE filed a petition with the NJBPU seeking to reconcile and update (i) charges related to the recovery of above-market costs associated with ACE’s long-term power purchase contracts with the NUGs, (ii) costs related to surcharges for the New Jersey Societal Benefit Program (a statewide public interest program for low income customers) and ACE’s uncollected accounts, and (iii) operating costs associated with ACE’s residential appliance cycling program. The filing proposed to recover the projected deferred under-recovered balance related to the NUGs of $113.8 million as of May 31, 2012 through a four-year amortization schedule. The net impact of adjusting the charges as proposed (consisting of both the annual impact of the proposed four-year amortization of the historical under-recovered NUG balances and the going-forward cost recovery of all the other charges for the period June 1, 2012 through May 31, 2013, and including associated changes in sales-and-use taxes) is an overall annual rate increase of approximately $55.3 million. In June 2012, the NJBPU approved a stipulation of settlement signed by the parties, which provided for provisional rates that went into effect on July 1, 2012. The rates are deemed “provisional” because ACE’s filing will not be updated for actual revenues and expenses (if necessary) for May and June 2012 until after July 1, 2012, and a review of the final underlying costs for reasonableness and prudence will be completed after such filing.
MPSC New Generation Contract Requirement
In September 2009, the MPSC initiated an investigation into whether the EDCs in Maryland should be required to enter into long-term contracts with entities that construct, acquire or lease, and operate, new electric generation facilities in Maryland.
In April 2012, the MPSC issued an order determining that there is a need for one new power plant in the range of 650 to 700 MW beginning in 2015. The order requires certain Maryland EDCs, including Pepco and DPL, 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 acknowledges certain of the EDCs’ concerns about the requirements of the contract and directs them to negotiate with the winning bidder and submit any proposed changes in the contract to the MPSC for approval. The order further specifies that the EDCs entering into the contract will recover the associated costs, in amounts proportional to their relative SOS loads, through surcharges on their respective SOS customers.
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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, Pepco, DPL, and other parties filed notices of appeal in circuit courts in Maryland requesting judicial review of the MPSC’s order. These appeals have been consolidated in the Circuit Court for Baltimore City and have been stayed pending the issuance of a final order from the MPSC approving the form of contract, including the payment obligations of the utilities in the event the utilities do not recover the costs for such payments from their customers.
Until the final form of the contract with the winning bidder and associated cost recovery are approved, PHI cannot predict (i) the extent of the negative effect that the order and, once finalized, the contract for new generation may have on PHI’s, Pepco’s and DPL’s balance sheets, as well as their respective credit metrics, as calculated by independent rating agencies that evaluate and rate PHI, Pepco and DPL and each of their debt issuances, (ii) the effect on Pepco’s and DPL’s ability to recover their associated costs of the contract for new generation if a significant number of SOS customers elect to buy their energy from alternative energy suppliers, and (iii) the effect of the order on the financial condition, results of operations and cash flows of each of PHI, Pepco and DPL.
Reliability Task Forces
In July 2012, the Maryland governor signed an Executive Order directing his energy advisor, in collaboration with certain state agencies, to solicit input and recommendations from experts on how to improve the resiliency and reliability of the electric distribution system in Maryland. The resulting Grid Resiliency Task Force issued its report in September 2012, in which it made 11 recommendations. The governor forwarded the report to the MPSC in October 2012, urging the MPSC to quickly implement the first four recommendations: (i) strengthen existing reliability and storm restoration regulations; (ii) accelerate the investment necessary to meet the enhanced metrics; (iii) allow surcharge recovery for the accelerated investment; and (iv) implement clearly defined performance metrics into the traditional ratemaking scheme. Pepco’s electric distribution base rate case filed with the MPSC on November 30, 2012, addresses the Grid Resiliency Task Force recommendations. DPL will consider the Grid Resiliency Task Force recommendations in its next electric distribution base rate case expected to be filed with the MPSC in the first quarter of 2013.
In August 2012, the District of Columbia mayor issued an Executive Order establishing the Mayor’s Power Line Undergrounding Task Force. The purpose of the Power Line Undergrounding Task Force is 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 include legislative bodies, regulators, utility personnel, experts and other parties who could contribute in a meaningful way to the Power Line Undergrounding Task Force. The options that are available for financing these efforts are also to be evaluated to identify required legislative or regulatory actions to implement these recommendations. The results of this analysis are intended to help determine the path forward for these types of infrastructure improvements and additions. A written report from the Power Line Undergrounding Task Force setting forth the findings and recommendations was originally due on January 31, 2013 but has been extended to early March 2013.
ACE Standard Offer Capacity Agreements
In April 2011, ACE entered into three SOCAs by order of the NJBPU, each with a different generation company, as more fully described in Note (2), “Significant Accounting Policies - Consolidation of Variable Interest Entities - ACE Standard Offer Capacity Agreements” and Note (14), “Derivative
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Instruments and Hedging Activities.” ACE and the other New Jersey EDCs entered into the SOCAs under protest based on concerns about the potential cost to distribution customers. The dispute is pending before the NJBPU and has been referred to an Administrative Law Judge for further consideration.
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 constitutionality of the New Jersey law under which the SOCAs were established. In September 2012, the District Court denied motions for summary judgment filed by ACE and the other plaintiffs, as well as cross-motions filed by defendants. The litigation remains pending and trial is tentatively scheduled to begin in March 2013.
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.
As of December 31, 2012, PHI’s total capital expenditures related to the MAPP project were approximately $102 million. In a 2008 FERC order approving incentives for the MAPP project, FERC authorized the recovery of prudently incurred abandoned costs in connection with the MAPP project. Consistent with this order, on December 21, 2012, PHI submitted a filing to FERC seeking recovery of approximately $88 million of abandoned MAPP capital expenditures. The FERC filing addressed, among other things, the prudence of the recoverable costs incurred, the proposed period over which the abandoned costs are to be amortized and the rate of return on these costs during the recovery period. Various protests have been submitted in response to the December 21, 2012 filing, arguing, among other things, that FERC should disallow a portion of the rate of return involving an incentive adder that would be applied to the abandonment costs, and requesting a hearing on various issues such as the amount of the ROE and the prudence of the costs. PHI cannot at this time estimate when a final FERC decision in this proceeding will be issued.
As of December 31, 2012, PHI had placed in service approximately $11 million of its total capital expenditures with respect to the MAPP project, which represented upgrades of existing substation assets that were expected to support the MAPP transmission line, transferred approximately $3 million of materials to inventories for use on other projects and reclassified the remaining approximately $88 million of capital expenditures to a regulatory asset. The regulatory asset includes the costs of land, land rights, supplies and materials, engineering and design, environmental services, and project management and administration. PHI intends to reduce the regulatory asset by any amounts recovered from the sale or alternative use of the land, land rights, supplies and materials.
(8) LEASING ACTIVITIES
Investment in Finance Leases Held in Trust
PHI has a portfolio of cross-border energy lease investments (the lease portfolio) consisting of hydroelectric generation facilities, coal-fired electric generation facilities and natural gas distribution networks located outside of the United States. Each lease investment is comprised of a number of leases. As of December 31, 2012 and 2011, the lease portfolio consisted of six and seven investments with a net investment value of $1.2 billion and $1.3 billion, respectively.
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The components of the cross-border energy lease investments as of December 31, are summarized below:
Income recognized from cross-border energy lease investments, excluding the gains on the terminated leases discussed below, was comprised of the following for the years ended December 31:
During 2012, PHI entered into early termination agreements with two lessees involving all of the leases comprising one of the seven remaining 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.
With respect to the terminated leases, 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
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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 (20), “Subsequent Event,” regarding an expected change in management’s intent.
PHI is required to assess on a periodic basis the likely outcome of tax positions relating to its cross-border energy lease investments and, if there is a change or a projected change in the timing of the tax benefits generated by the transactions, PHI is required to recalculate the value of its net investment. In that regard, PHI modified its tax cash flow assumptions both in 2011 and 2010 and recorded non-cash pre-tax charges of $7 million and $2 million, respectively, 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 and in 2010 as a result of an overall reassessment of tax cash flow assumptions. These charges as a result of the reassessments were recorded as reductions in cross-border energy lease investment revenue in each of 2011 and 2010.
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 has determined that it can no longer support its current assessment with respect to the likely outcome of tax positions associated with the cross-border energy lease investments and expects to record an after-tax non-cash charge of between $355 million and $380 million in the first quarter of 2013, 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 its estimated federal and state income tax obligations for the period over which the tax benefits may be disallowed. While the IRS could require PHI to pay a penalty of up to 20 percent 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 will be included in the charge expected to be recorded in the first quarter of 2013.
For additional information concerning these cross-border energy lease investments, see Note (16), “Commitments and Contingencies - PHI’s Cross-Border Energy Lease Investments,” and Note (20), “Subsequent Event.”
Scheduled lease payments from the cross-border energy lease investments are net of non-recourse debt. Minimum lease payments receivable from the cross-border energy lease investments are zero for each year 2013 through 2017, and $1,237 million thereafter.
To ensure credit quality, PHI regularly monitors the financial performance and condition of the lessees under its cross-border energy lease investments. Changes in credit quality are also assessed to determine if they should be reflected in the carrying value of the leases. PHI compares each lessee’s performance to annual compliance requirements set by the terms and conditions of the leases. This includes a comparison of published credit ratings to minimum credit rating requirements in the leases for lessees with public credit ratings. In addition, PHI routinely meets with senior executives of the lessees to discuss their company and asset performance. If the annual compliance requirements or minimum credit ratings are not met, remedies are available under the leases. At December 31, 2012, all lessees were in compliance with the terms and conditions of their lease agreements.
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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 of collateral posted by the lessees in these transactions.
Lease Commitments
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 income. This lease is treated as an operating lease for rate-making purposes.
Capital lease assets recorded within Property, Plant and Equipment at December 31, 2012 and 2011, in millions of dollars, are comprised of the following:
The approximate annual commitments under all capital leases are $15 million for each year 2013 through 2017, and $32 million thereafter.
Rental expense for operating leases was $52 million, $46 million and $45 million for the years ended December 31, 2012, 2011 and 2010, respectively.
Total future minimum operating lease payments for Pepco Holdings as of December 31, 2012, are $43 million in 2013, $40 million in 2014, $38 million in 2015, $36 million in 2016, $35 million in 2017 and $369 million thereafter.
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(9) 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, 2012 and 2011, PHI’s subsidiaries had a net book value ownership interest of $13 million 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 income. PHI is responsible for providing its share of the financing for the above jointly-owned facilities.
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.
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Long-Lived Asset Impairment
At December 31, 2012, PHI recorded impairment losses of $12 million ($7 million after-tax) at Pepco Energy Services associated primarily with its investments in landfill gas-fired electric generation facilities and 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. 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.
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 $9 million as of December 31, 2012 on its consolidated balance sheet.
The sale of the Conectiv Energy wholesale power generation business to 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.
(10) PENSION AND OTHER POSTRETIREMENT BENEFITS
Pension Benefits and Other Postretirement Benefits
Pepco Holdings sponsors the PHI Retirement Plan, which covers substantially all employees of Pepco, DPL, ACE and certain employees of other Pepco Holdings’ subsidiaries. Pepco Holdings also provides supplemental retirement benefits to certain eligible executive and key employees through nonqualified retirement plans.
Pepco Holdings 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 medical coverage; however, they will be able to purchase coverage at full cost through PHI.
Net periodic benefit cost is included in Other operation and maintenance expense, net of the portion of the net periodic benefit cost that is 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.
Pepco Holdings accounts for the PHI Retirement Plan, nonqualified retirement plans, and its postretirement health care and life insurance benefits for eligible employees in accordance with FASB guidance on retirement benefits. PHI’s financial statement disclosures are also prepared in accordance with FASB guidance on retirement benefits.
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(a) Other Postretirement Benefits paid is net of Medicare Part D subsidy receipts of $4 million and $2 million in 2012 and in 2011, respectively.
At December 31, 2012, PHI Retirement Plan assets were $2.0 billion and the accumulated benefit obligation was approximately $2.3 billion. At December 31, 2011, PHI’s Retirement Plan assets were approximately $1.7 billion and the accumulated benefit obligation was approximately $2.0 billion.
The following table provides the amounts recognized in PHI’s consolidated balance sheets as of December 31, 2012 and 2011:
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Amounts included in AOCL (pre-tax) and Regulatory assets at December 31, 2012 and 2011 consist of:
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 $68 million and $1 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 $15 million and $4 million, respectively.
The table below provides the components of net periodic benefit costs recognized for the years ended December 31, 2012, 2011 and 2010:
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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, 2012, 2011 and 2010:
The following weighted average assumptions were used to determine the benefit obligations at December 31:
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:
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.
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The expected long-term rate of return on pension plan assets and postretirement benefit plan assets was 7.25% and 7.75% as of December 31, 2012 and 2011, 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 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, and when viewed over a long-term horizon, are expected to yield a return on assets of 7.25% at December 31, 2012. PHI periodically reviews its asset mix and rebalances assets back to the target allocation.
In addition, for the 2012 Other Postretirement Benefit Plan valuation, the health care cost trend rate was 8.0% from 2012 to 2013, declining 0.5% per year to a rate of 5.0% for 2018 to 2019 and beyond. The 2011 valuation assumption was 8.0% from 2011 to 2012, declining 0.5% per year to a rate of 5.0% for 2017 to 2018 and beyond.
Benefit Plan Modifications
During 2011, PHI’s Board of Directors approved revisions to certain of PHI’s existing benefit programs, including the PHI Retirement Plan. The changes to the PHI Retirement Plan were effected by PHI in order to establish a more unified approach to PHI’s retirement programs and to further align the benefits offered under PHI’s retirement programs. The changes to the PHI Retirement Plan were effective on or after July 1, 2011 and affect the retirement benefits payable to approximately 750 of PHI’s employees. All full-time employees of PHI and certain subsidiaries are eligible to participate in the PHI Retirement Plan. Retirement benefits for all other employees remain unchanged.
During 2011, PHI’s Board also approved a new, non-qualified Supplemental Executive Retirement Plan (SERP) which replaced PHI’s two pre-existing supplemental retirement plans, effective August 1, 2011. As of the effective date of the new SERP, the Conectiv SERP and the PHI Combined SERP were closed to new participants. The establishment of the new SERP is consistent with PHI’s efforts to align retirement benefits for PHI and its subsidiaries with current market practices and to provide similarly situated participants with retirement benefits that are the same or similar in value as compared to the benefits provided under the prior SERPs.
During 2011, PHI approved an increase in the medical benefit limits for certain employees in its postretirement health care benefit plan to align the limits with those provided to other employees. The amendment affects approximately 1,400 employees, of which 400 are retirees and 1,000 are active union employees. The effective date of the plan modification is January 1, 2012.
The additional liabilities and expenses for the benefit plan modifications described above did not have a material impact on PHI’s overall consolidated financial condition, results of operations or cash flows.
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.
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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.
During 2011, PHI modified its pension investment policy and strategy to reduce the effects of future volatility of the fair value of its pension assets relative to its pension liabilities. The new asset-liability management strategy was implemented during 2011. Under the new asset-liability management strategy, the plan’s allocation to fixed income investments, primarily high quality, longer-maturity fixed income securities was increased, with a reduction in the allocation to equity investments. As a result of this modification, during 2011, PHI allocated approximately 54% of its pension plan assets to longer-maturity fixed income investments, 38% to public equity investments and 8% to alternative investments (real estate, private equity). At December 31, 2010, the PHI pension trust’s asset allocation included 40% in fixed income investments (intermediate maturity fixed income), 53% in public equity investments and 7% in alternative investments (real estate, private equity). PHI anticipates further increases in the allocation to fixed income investments, with a corresponding reduction in the allocation to equity and alternative investments as the funded status of its plan increases.
The change in overall investment strategy may result in a lower expected long-term rate of return assumption because of the shift in allocation from equities and alternative investments to fixed income. PHI’s 2012 pension costs are based on a 7.25% expected long-term rate of return assumption.
The PHI Retirement Plan asset allocations at December 31, 2012 and 2011, by asset category, were as follows:
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PHI’s other postretirement benefit plan asset allocations at December 31, 2012 and 2011, 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, 2012 and 2011.
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, 2012 and 2011:
(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 bonds, 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, 2012 and 2011.
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, 2012 and 2011 totaled $15 million and $28 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, 2012 and 2011 are shown below:
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Cash Flows
Contributions - PHI Retirement Plan
PHI’s funding policy with regard to PHI’s non-contributory retirement plan (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 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 the PHI Retirement Plan assets to the funding target level for 2012 under the Pension Protection Act. During 2011, Pepco, DPL and ACE made discretionary tax-deductible contributions to the PHI Retirement Plan in the amounts of $40 million, $40 million and $30 million, respectively, which brought plan assets to the funding target level for 2011 under the Pension Protection Act.
On January 9, 2013, PHI, DPL and ACE made discretionary tax-deductible contributions to the PHI Retirement Plan in the amounts of $20 million, $10 million and $30 million, respectively, which is expected to bring the PHI Retirement Plan assets to at least the funding target level for 2013 under the Pension Protection Act.
Contributions - Other Postretirement Benefit Plan
In 2012 and 2011, Pepco contributed $5 million and $7 million, respectively, DPL contributed $7 million and $6 million, respectively, and ACE contributed $7 million and $7 million, respectively, to the other postretirement benefit plan. In 2012 and 2011, contributions of $13 million 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
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 and 2011, Pepco Holdings received $4 million and $2 million, respectively, in Federal Medicare prescription drug subsidies. PHI will not be receiving the Part D subsidy in 2013 and beyond 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, $11 million and $11 million for the years ended December 31, 2012, 2011 and 2010, respectively.
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(11) DEBT
Long-Term Debt
The components of long-term debt are shown below.
(a) Represents a series of first mortgage bonds issued by the indicated company (Collateral First Mortgage Bonds) as collateral for an outstanding series of senior notes issued by the company or tax-exempt bonds issued for the benefit of the company. The maturity date, optional and mandatory prepayment provisions, if any, interest rate, and interest payment dates on each series of senior notes or the company’s obligations in respect of the tax-exempt bonds are identical to the terms of the corresponding series of Collateral First Mortgage Bonds. Payments of principal and interest on a series of senior notes or the company’s obligations in respect of the tax-exempt bonds satisfy the corresponding payment obligations on the related series of Collateral First Mortgage Bonds. Because each series of senior notes or the company’s obligations in respect of the tax-exempt bonds and the corresponding series of Collateral First Mortgage Bonds securing that series of senior notes or tax-exempt bonds obligations effectively represents a single financial obligation, the senior notes and the tax-exempt bonds are not separately shown on the table.
(b) Represents a series of Collateral First Mortgage Bonds issued by the indicated company that in accordance with its terms will, at such time as there are no first mortgage bonds of the issuing company outstanding (other than Collateral First Mortgage Bonds securing payment of senior notes), cease to secure the corresponding series of senior notes and will be cancelled.
(c) Represents a series of Collateral First Mortgage Bonds as to which the indicated company has agreed in connection with the issuance of the corresponding series of senior notes that, notwithstanding the terms of the Collateral First Mortgage Bonds described in footnote (b) above, it will not permit the release of the Collateral First Mortgage Bonds as security for the series of senior notes for so long as the senior notes remain outstanding, unless the company delivers to the senior note trustee comparable secured obligations to secure the senior notes.
(d) On July 1, 2010, DPL purchased this series of tax-exempt bonds issued for the benefit of DPL by the Delaware Economic Development Authority (DEDA) pursuant to a mandatory repurchase provision in the indenture for the bonds that was triggered by the expiration of the original interest period for the bonds. While DPL held the bonds, they remained outstanding as a contractual matter, but were considered extinguished for accounting purposes. On December 1, 2010, DPL resold the bonds to the public, at which time the interest rate on the bonds was changed from 5.50% to a fixed rate of 1.80%. The bonds were purchased by DPL on June 1, 2012 pursuant to a mandatory purchase obligation and then retired.
(e) These bonds bearing an interest rate of 4.90% were repurchased. On June 1, 2011, DPL resold these bonds that were subject to mandatory repurchase on May 1, 2011 at an interest rate of 0.75%. The bonds were purchased by DPL on June 1, 2012 pursuant to a mandatory purchase obligation and then retired.
(f) On July 1, 2010, DPL purchased this series of tax-exempt bonds issued for the benefit of DPL by DEDA pursuant to a mandatory repurchase provision in the indenture for the bonds that was triggered by the expiration of the original interest period for the bonds. While DPL held the bonds, they remained outstanding as a contractual matter, but were considered extinguished for accounting purposes. On December 1, 2010, DPL resold the bonds to the public, at which time the interest rate on the bonds was changed from 5.65% to a fixed rate of 2.30%. The bonds were purchased by DPL on June 1, 2012 pursuant to a mandatory purchase obligation and then retired.
NOTE: Schedule is continued on next page.
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The outstanding First Mortgage Bonds issued by each of Pepco, DPL and ACE are subject to a lien on substantially all of the issuing company’s property, plant and equipment.
For a description of the Transition Bonds issued by ACE Funding, see Note (2), “Significant Accounting Policies - Consolidation of Variable Interest Entities - ACE Transition Funding, LLC.” The aggregate amounts of maturities for long-term debt and Transition Bonds outstanding at December 31, 2012, are $568 million in 2013, $334 million in 2014, $409 million in 2015, $338 million in 2016, $135 million in 2017, and $2,701 million thereafter.
PHI’s long-term debt is subject to certain covenants. As of December 31, 2012, PHI and its subsidiaries were in compliance with all such covenants.
Long-Term Project Funding
As of December 31, 2012 and 2011, Pepco Energy Services had total outstanding long-term project funding (including current maturities) of $13 million and $15 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, 2012, are $1 million for 2013, $2 million for each year 2014 and 2015, $1 million for each year 2016 and 2017, and $6 million thereafter.
Bond Issuances
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.
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.
Bond Redemptions
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.
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. A detail of the components of PHI’s short-term debt at December 31, 2012 and 2011 is as follows:
Commercial Paper
PHI, Pepco, DPL and ACE maintain ongoing commercial paper programs to address short-term liquidity needs. As of December 31, 2012, the maximum capacity available under these programs was $875 million, $500 million, $500 million and $250 million, respectively, subject to available borrowing capacity under the credit facility.
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 during 2012 was ten, five, four and three days, respectively.
PHI, Pepco and DPL had $465 million, $74 million and $47 million, respectively, of commercial paper outstanding at December 31, 2011. ACE had no commercial paper outstanding at December 31, 2011. The weighted average interest rate for commercial paper issued by PHI, Pepco, DPL and ACE during 2011 was 0.64%, 0.35%, 0.34% and 0.33%, respectively. The weighted average maturity of all commercial paper issued by PHI, Pepco, DPL and ACE in 2011 was eleven, two, two and six 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
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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, 2012, $105 million of VRDBs issued by DPL (of which $72 million was secured by Collateral First Mortgage Bonds issued by DPL) and $23 million of VRDBs issued by ACE were outstanding.
The VRDBs outstanding at December 31, 2012 mature as follows: 2014 to 2017 ($49 million), 2024 ($33 million) and 2028 to 2029 ($46 million). The weighted average interest rate for VRDBs was 0.34% during 2012 and 0.44% during 2011.
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, among other changes, extended the expiration date of the facility to August 1, 2016. On August 2, 2012, the amended and restated credit agreement 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.
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 at December 31, 2012 was $650 million for PHI, $350 million for Pepco and $250 million for each of 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 (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, 2012.
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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.
At December 31, 2012 and 2011, 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 $861 million and $994 million, respectively. PHI’s utility subsidiaries had combined cash and unused borrowing capacity under the credit facility of $477 million and $711 million at December 31, 2012 and 2011, respectively.
Term Loan Agreement
During 2012, PHI entered into a $200 million term loan agreement, pursuant to which PHI has borrowed (and may not reborrow) $200 million at a rate of interest equal to the prevailing Eurodollar rate, which is determined by reference to LIBOR with respect to the relevant interest period, all as defined in the loan agreement, plus a margin of 0.875%. PHI’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 0.875%. As of December 31, 2012, outstanding borrowings under the loan agreement bore interest at an annual rate of 1.095%, 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 April 23, 2013.
PHI used the net proceeds of the borrowings under the term loan agreement to repay outstanding commercial paper obligations and for general corporate purposes. Under the terms of the term loan agreement, PHI must maintain compliance with specified covenants, including (i) the requirement that PHI 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 PHI or any of its significant subsidiaries. The loan agreement does not include any rating triggers. PHI was in compliance with all covenants under this agreement as of December 31, 2012.
Loss on Extinguishment of Debt
During 2010, PHI recorded a pre-tax loss on extinguishment of debt of $189 million ($113 million after-tax), which is further discussed below.
During 2010, PHI purchased, pursuant to a cash tender offer, $640 million in principal amount of its 6.45% Senior Notes due 2012 (6.45% Notes), redeemed the remaining $110 million of outstanding 6.45% Notes, and purchased, pursuant to a cash tender offer, $129 million of its 6.125% Senior Notes due 2017 (6.125% Notes) and $65 million of 7.45% Senior Notes due 2032 (7.45% Notes). In connection with these transactions, PHI recorded a pre-tax loss on extinguishment of debt of $120 million.
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During 2010, PHI purchased, pursuant to a cash tender offer, an additional $40 million of outstanding 6.125% Notes. In addition, PHI redeemed all of its $200 million 6% Notes due 2019 and $10 million of its 5.9% Notes due 2016. PHI recorded a pre-tax loss on extinguishment of debt of approximately $54 million in 2010 in connection with this transaction.
In connection with the purchases of the 6.45% Notes and the 7.45% Notes, PHI accelerated the recognition of $15 million of pre-tax hedging losses attributable to the issuance of the 6.45% Notes and 7.45% Notes by reclassifying these hedging losses from AOCL to income. These hedging losses originally arose when PHI entered into several treasury rate lock transactions in June 2002 to hedge changes in interest rates related to the anticipated issuance in August 2002 of several series of senior notes, including the 6.45% Notes and the 7.45% Notes. Upon issuance of the fixed rate debt in August 2002, the rate locks were terminated at a loss that has been deferred in AOCL and is being recognized in income over the life of the debt issued as interest payments on the debt are made. The accelerated recognition of these losses has also been included as a component of pre-tax loss on extinguishment of debt.
Collateral Requirements of Pepco Energy Services
In the ordinary course of its retail energy supply business, which is in the process of being wound down, Pepco Energy Services entered into various contracts to buy and sell electricity, fuels and related products, including derivative instruments, designed to reduce its financial exposure to changes in the value of its assets and obligations due to energy price fluctuations. These contracts typically have collateral requirements. Depending on the contract terms, the collateral required to be posted by Pepco Energy Services can be of varying forms, including cash and letters of credit.
As of December 31, 2012, Pepco Energy Services had posted net cash collateral of $25 million and letters of credit of less than $1 million. At December 31, 2011, Pepco Energy Services had posted net cash collateral of $112 million and letters of credit of $1 million.
At December 31, 2012 and 2011, the amount of cash, plus borrowing capacity under PHI’s credit facility available to meet the future liquidity needs of Pepco Energy Services, totaled $384 million and $283 million, respectively.
(12) 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 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 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, 2012
The effective income tax rate for the year ended December 31, 2012 reflects charges related to the recognition of the tax consequences associated with the early termination of cross-border energy leases in the third quarter of 2012 of $16 million as discussed in Note (8), “Leasing Activities.”
In addition, 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.
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 effective income tax rate in 2011 was significantly affected by changes in estimates and interest 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 (discussed below) 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, PHI recorded an additional tax benefit of $17 million (after-tax) which was recorded in the second quarter of 2011. Further, PHI recalculated 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, which resulted in additional tax expense of $3 million (after-tax).
As discussed further in Note (8), “Leasing Activities,” during the second quarter of 2011, PHI terminated early its interest in certain cross-border energy leases prior to the end of their stated terms. As a result, PHI recognized a $22 million charge related to the tax consequences associated with the early terminations.
In addition, as discussed further in Note (16), “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 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.
Year ended December 31, 2010
In April 2010, as part of an ongoing effort to simplify PHI’s organizational structure, certain of PHI’s subsidiaries were converted from corporations to single member limited liability companies. In addition to increased organizational flexibility and reduced administrative costs, converting these entities to limited liability companies allows PHI to include income or losses in the former corporations in a single state income tax return, thus increasing the utilization of state income tax attributes. As a result of inclusions of income or losses in a single state return as discussed above, PHI recorded an $8 million benefit by reversing valuation allowances on certain state net operating losses and an additional benefit of $6 million resulting from changes to certain state deferred income tax benefits. In addition, conversion to limited liability companies caused PHI’s separate company losses (primarily related to the loss on the extinguishment of debt) to be subjected to state income taxes in new jurisdictions, resulting in minimal consolidated state taxable income in 2010.
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In November 2010, PHI reached final settlement with the IRS with respect to its federal tax returns for the years 1996 to 2002 for all issues except its cross-border energy lease investments. In connection with the settlement, PHI reallocated certain amounts on deposit with the IRS since 2006 among liabilities in the settlement years and subsequent years. In light of the settlement and reallocations, PHI recalculated the estimated interest due for the tax years 1996 to 2002. The revised estimate resulted in the reversal of $15 million (after-tax) of estimated interest due to the IRS. This reversal was recorded as an income tax benefit in the fourth quarter of 2010 and PHI recorded an additional tax benefit of $17 million (after-tax) in the second quarter of 2011 when the IRS finalized its calculation of the amount due. Offsetting the 2010 benefit was the reversal of $6 million (after-tax) of erroneously accrued state interest receivable recorded in the first quarter of 2010 and $2 million (after-tax) of other adjustments.
Also in the fourth quarter of 2010, PHI corrected the tax accounting for software amortization. Accordingly, a regulatory asset was established and income tax expense was reduced by $4 million.
Components of Consolidated Deferred 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 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
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, 2012 included $36 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, 2012, 2011 and 2010, PHI recognized $23 million of pre-tax interest income ($14 million after-tax), $23 million of pre-tax interest income ($14 million after-tax), and $2 million of pre-tax interest income ($1 million after-tax), respectively, as a component of income tax expense related to continuing operations. As of December 31, 2012, 2011 and 2010, PHI had accrued interest receivable of $10 million, accrued interest payable of $4 million and accrued interest payable of $12 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 PHI’s uncertain tax positions will significantly increase or decrease within the next 12 months. The possible resolution of the cross-border energy lease investments issue, the 2003 to 2008 Federal audits or state audits could impact the balances and related interest accruals significantly. See Note (16), “Commitments and Contingencies” and Note (20), “Subsequent Event,” 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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Resolution of Certain IRS Audit Matters
In 2010, PHI resolved all tax matters that were raised in IRS audits related to the 2001 and 2002 tax years except for the cross-border energy lease issue. Adjustments recorded relating to these resolved tax matters resulted in a $1 million increase in income tax expense exclusive of interest.
Other Taxes
Other taxes for continuing operations are shown below. The annual amounts include $426 million, $445 million and $427 million for the years ended December 31, 2012, 2011 and 2010, respectively, related to Power Delivery, which are recoverable through rates.
(13) STOCK-BASED COMPENSATION, DIVIDEND RESTRICTIONS, AND CALCULATIONS OF EARNINGS PER SHARE OF COMMON STOCK
Stock-Based Compensation
Pepco Holdings maintains a Long-Term Incentive Plan (LTIP) and a 2012 Long-Term Incentive Plan (2012 LTIP), the objective of each 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 income for the years ended December 31, 2012, 2011 and 2010 was $11 million, $6 million and $5 million, respectively, all of which was associated with restricted stock and restricted stock unit awards.
No material amount of stock compensation expense was capitalized for the years ended December 31, 2012, 2011 and 2010.
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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:
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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.
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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, 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. The time-based retention awards have a vesting 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.
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In May and September 2012, restricted stock units were granted to each non-employee director under the 2012 LTIP. A total of 40,749 units were granted and 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.
Activity for the year
The 2012 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 to achieve 100% of targeted performance criteria for the 2010-2012, 2011-2013 and 2012-2014 award cycles.
PEPCO HOLDINGS
Grants included in the table above reflect 2012 grants of performance-based and retention restricted stock units, time-based and retention restricted stock units and unrestricted stock 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.
The following table provides the weighted average grant date fair value of those awards granted during each of the years ended December 31, 2012, 2011 and 2010:
As of December 31, 2012, there was approximately $13 million of future compensation cost (net of estimated forfeitures) related to non-vested restricted stock awards and 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 since 2002. As of January 1, 2012, 30,925 options were outstanding at a weighted average exercise price of $20.75 and a weighted-average remaining contractual term of 0.03 years. As of December 31, 2012, all outstanding stock options under predecessor plans have expired. Total intrinsic value and tax benefits recognized for stock options exercised in 2011 and 2010 were immaterial. No options were exercised in 2012.
PEPCO HOLDINGS
Non-employee directors were entitled, under the terms of the LTIP, to a grant on May 1 of each year of a nonqualified stock option for 1,000 shares of common stock. However, the Board of Directors previously determined not to make these grants and the LTIP expired by its terms on August 1, 2012.
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, 2012, 2011 and 2010 was not material.
Compensation expense recognized in respect of dividends and the increase in fair value for each of the years ended December 31, 2012, 2011 and 2010 was not material. The deferred compensation balance under this program was approximately $1 million at December 31, 2012 and 2011.
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 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, 2012. 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 $1,109 million and $1,072 million of retained earnings free of restrictions at December 31, 2012 and 2011, respectively. These amounts represent the total retained earnings balances at those dates.
For the years ended December 31, Pepco Holdings received dividends from its subsidiaries as follows:
PEPCO HOLDINGS
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, 14,900 and 280,266 for the years ended December 31, 2012, 2011 and 2010, respectively.
Equity Forward Transaction
During 2012, PHI entered into an equity forward transaction in connection with a public offering of 17,922,077 shares of PHI common stock. The use of an equity forward transaction substantially eliminates future equity market price risk by fixing a common equity offering sales price under the then existing market conditions, while mitigating immediate share dilution resulting from the offering by postponing the actual issuance of common stock until funds are needed in accordance with PHI’s capital investment and regulatory plans.
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.
The equity forward transaction had no initial fair value since it was entered into at the then market price of the common stock. PHI did not receive any proceeds from the sale of common stock until the equity forward transaction was settled, and at that time PHI recorded the proceeds in equity. PHI concluded that the equity forward transaction was an equity instrument based on the accounting guidance in ASC 480 and ASC 815, and that it qualified for an exception from derivative accounting under ASC 815 because the forward sale transaction was indexed to its own stock.
PEPCO HOLDINGS
As allowed by the terms of the transaction, PHI physically settled the equity forward transaction on February 27, 2013 by issuing 17,922,077 shares of common stock at $17.39 per share to the forward counterparty. The proceeds of approximately $312 million were used to pay down outstanding commercial paper, a portion of which was issued in order to make capital contributions to the utilities, and for general corporate purposes.
During 2012, the equity forward transaction was reflected in PHI’s diluted earnings per share calculations using the treasury stock method. Under this method, the number of shares of PHI’s common stock used in calculating diluted earnings per share for a reporting period would be increased by the number of shares, if any, that would be issued upon physical settlement of the equity forward transaction less the number of shares that could be purchased by PHI in the market (based on the average market price during that reporting period) using the proceeds receivable upon settlement of the equity forward transaction (based on the adjusted forward sale price at the end of that reporting period). The excess number of shares is weighted for the portion of the reporting period in which the equity forward transaction is outstanding. For the year ended December 31, 2012, the equity forward transaction had a dilutive effect of $0.01 on PHI’s earnings per share.
Shareholder Dividend Reinvestment Plan
PHI maintains a Shareholder Dividend Reinvestment Plan (DRP) through which shareholders may reinvest cash dividends. In addition, existing shareholders can make purchases of shares of PHI common stock through the investment of not less than $25 each calendar month nor more than $200,000 each calendar year. Shares of common stock purchased through the DRP may be new shares or, at the election of PHI, shares purchased in the open market or in negotiated transactions. Approximately 2 million new shares were issued and sold under the DRP in each of 2012, 2011 and 2010.
Pepco Holdings Common Stock Reserved and Unissued
The following table presents Pepco Holdings’ common stock reserved and unissued at December 31, 2012:
(a) Excludes up to 31 million shares authorized by the Board of Directors on February 23, 2012 for potential issuance pursuant to the terms of the equity forward transaction.
(b) No further awards will be made under this plan.
PEPCO HOLDINGS
(14) DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
Derivatives are used by Pepco Energy Services and Power Delivery to hedge commodity price risk, as well as by PHI, from time to time, to hedge interest rate risk.
The retail energy supply business of Pepco Energy Services, which is in the process of being wound down, enters into energy commodity contracts in the form of electricity and 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 is 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 become available.
Pepco Energy Services’ commodity contracts that are not designated for hedge accounting, do not qualify for hedge accounting, or do not meet the requirements for normal purchase and normal sale accounting, are marked to market through current earnings. Forward contracts that meet the requirements for normal purchase and normal sale accounting are recorded on an accrual basis.
In Power Delivery, 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. 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.
ACE was ordered to enter into the SOCAs by the NJBPU, and under the SOCAs, ACE would receive payments from or make 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, which is currently estimated to be approximately 15 percent. ACE began applying derivative accounting to two of its SOCAs as of June 30, 2012 because the generators cleared the 2015-2016 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 NJBPU has allowed full recovery from ACE’s distribution customers for all payments made by ACE and ACE’s distribution customers would be entitled to all payments received by ACE.
PHI also uses derivative instruments from time to time to mitigate the effects of fluctuating interest rates on debt issued in connection with the operation of their 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 income over the life of the debt issued as interest payments are made. As further described in Note (11), “Debt,” $15 million of these pre-tax losses ($9 million after-tax) was reclassified into income during 2010.
PEPCO HOLDINGS
The tables below identify the balance sheet location and fair values of derivative instruments as of December 31, 2012 and 2011:
(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.
(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), PHI offsets 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. The amount of cash collateral that was offset against these derivative positions is as follows:
(a) Includes cash deposits on commodity brokerage accounts.
As of December 31, 2012 and 2011, all PHI cash collateral pledged related to derivative instruments accounted for at fair value was entitled to be offset under master netting agreements.
PEPCO HOLDINGS
Derivatives Designated as Hedging Instruments
Cash Flow Hedges
Pepco Energy Services
For energy commodity contracts that are designated and qualify as cash flow hedges, the effective portion of the gain or loss on the derivative is reported as a component of AOCL and is reclassified into income in the same period or periods during which the hedged transactions affect income. Gains and losses on the derivative that are related to hedge ineffectiveness or the forecasted hedged transaction being probable not to occur are recognized in income. Pepco Energy Services has elected to no longer apply cash flow hedge accounting to certain of its electricity derivatives and all of its natural gas derivatives. Amounts included in AOCL for these cash flow hedges as of December 31, 2012 and 2011 represent net losses on derivatives prior to the election to discontinue cash flow hedge accounting less amounts reclassified into income as the hedged transactions occur or because the hedged transactions were deemed probable not to occur. Gains or losses on these derivatives after the election to discontinue cash flow hedge accounting are recognized in income.
The cash flow hedge activity during the years ended December 31, 2012, 2011 and 2010 is provided in the tables below:
(a) Included in the above table is a loss of $1 million for the years ended December 31, 2012 and 2011, respectively, which was reclassified from AOCL to income because the forecasted hedged transactions were deemed probable not to occur.
As of December 31, 2012 and 2011, Pepco Energy Services had the following types and quantities of outstanding energy commodity contracts employed as cash flow hedges of forecasted purchases and forecasted sales.
PEPCO HOLDINGS
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. The following table indicates the net unrealized derivative losses arising during the period that were deferred as Regulatory assets and the net realized losses recognized in the consolidated statements of income (through Fuel and purchased energy expense) that were also deferred as Regulatory assets for the years ended December 31, 2012, 2011 and 2010 associated with cash flow hedges:
Cash Flow Hedges Included in Accumulated Other Comprehensive Loss
The tables below provide details regarding effective cash flow hedges included in PHI’s consolidated balance sheets as of December 31, 2012 and 2011. Cash flow hedges are marked to market on the consolidated balance sheet with corresponding adjustments to AOCL for effective cash flow hedges. As of December 31, 2012, $11 million of the losses in AOCL were associated with derivatives that Pepco Energy Services previously designated as cash flow hedges. Although Pepco Energy Services no longer designates these derivatives as cash flow hedges, gains or losses previously deferred in AOCL prior to the decision to discontinue cash flow hedge accounting will remain in AOCL until the hedged forecasted transaction occurs unless it is deemed probable that the hedged forecasted transaction will not occur. The data in the following tables indicate the cumulative net loss after-tax related to effective 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:
(a) The unrealized derivative losses recorded in AOCL relate to forecasted physical natural gas and electricity purchases which are used to supply retail natural gas and electricity contracts that are in gain positions and subject to accrual accounting. Under accrual accounting, no asset is recorded on PHI’s consolidated balance sheet and the purchase cost is not recognized until the period of distribution.
(a) The unrealized derivative losses recorded in AOCL relate to forecasted physical natural gas and electricity purchases which are used to supply retail natural gas and electricity contracts that are in gain positions and subject to accrual accounting. Under accrual accounting, no asset is recorded on PHI’s consolidated balance sheet and the purchase cost is not recognized until the period of distribution.
PEPCO HOLDINGS
Other Derivative Activity
Pepco Energy Services
Pepco Energy Services 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 sheet with the gain or loss for changes in fair value recorded through Fuel and purchased energy expense.
For the years ended December 31, 2012, 2011 and 2010, the amount of the derivative gain (loss) for Pepco Energy Services recognized in income is provided in the table below:
As of December 31, 2012 and 2011, Pepco Energy Services had the following net outstanding commodity forward contract quantities and net position on derivatives that did not qualify for hedge accounting:
PEPCO HOLDINGS
Power Delivery
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 pertaining to the SOCAs within which ACE’s capacity derivatives are embedded. The following table indicates the net unrealized derivative losses arising during the period that were deferred as Regulatory assets and the net realized losses recognized in the consolidated statements of income (through Fuel and purchased energy expense) that were also deferred as Regulatory assets for the years ended December 31, 2012 and 2011 associated with these derivatives:
As of December 31, 2012 and 2011, 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 Pepco Energy Services and Power Delivery segments 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 amount by which the unsecured credit threshold is exceeded. The obligations of Pepco Energy Services are usually guaranteed by PHI. The obligations of DPL are stand-alone obligations without the guaranty of PHI. If PHI’s or 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 debt rating of the holder.
PEPCO HOLDINGS
The gross fair values of PHI’s derivative liabilities with credit risk-related contingent features as of December 31, 2012 and 2011, were $8 million and $54 million, respectively, before giving effect to offsetting transactions or collateral under master netting agreements. As of December 31, 2012, PHI had posted no cash collateral against its gross derivative liability, resulting in a net liability of $8 million. As of December 31, 2011, PHI had posted cash collateral of $1 million against its gross derivative liability, resulting in a net liability of $53 million. If PHI’s and DPL’s debt ratings had been downgraded below investment grade as of December 31, 2012 and 2011, PHI’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 $40 million and $124 million, respectively, and PHI would have been required to post collateral with the counterparties of approximately $40 million and $123 million, respectively, in addition to that which was posted as of December 31, 2012 and 2011. The net settlement and additional collateral amounts reflect the effect of offsetting transactions under master netting agreements.
PHI’s primary source for posting cash collateral or letters of credit is its credit facility. At December 31, 2012 and 2011, the aggregate amount of cash plus borrowing capacity under the credit facility available to meet the future liquidity needs of PHI and its subsidiaries totaled $861 million and $994 million, respectively, of which $384 million and $283 million, respectively, was available to Pepco Energy Services.
(15) 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).
PEPCO HOLDINGS
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, 2012 and 2011. 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.
(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 wholesale electricity futures and swaps that are used mainly as part of Pepco Energy Services’ retail energy supply business.
(d) Level 1 instruments represent wholesale gas futures and swaps that are used mainly as part of Pepco Energy Services’ retail energy supply business and level 3 instruments represent natural gas options purchased by DPL as part of a natural gas hedging program approved by the DPSC.
(e) Represents derivatives associated with ACE SOCAs.
PEPCO HOLDINGS
(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2011.
(b) The fair value of derivative assets and liabilities reflect netting by counterparty before the impact of collateral.
(c) Represents wholesale electricity futures and swaps that are used mainly as part of Pepco Energy Services’ retail energy supply business.
(d) Level 1 instruments represent wholesale gas futures and swaps that are used mainly as part of Pepco Energy Services’ retail energy supply business and level 3 instruments represent natural gas options purchased by DPL as part of a natural gas hedging program approved by the DPSC, as well as Pepco Energy Services physical basis contracts.
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.
PHI’s level 2 derivative instruments primarily consist of electricity derivatives at December 31, 2012. Level 2 power swaps are provided by a pricing service that uses liquid trading hub prices or liquid hub prices plus a congestion adder to estimate the fair value at zonal locations within trading hubs.
Executive deferred compensation plan assets 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, 2012. 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.
PEPCO HOLDINGS
The value of certain employment agreement obligations 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, natural gas physical basis contracts held by Pepco Energy Services, 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.
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The natural gas physical basis contracts held by Pepco Energy Services were valued using liquid hub prices plus a congestion adder. The congestion adder was an internally derived adder based on historical data and experience. Pepco Energy Services obtained the liquid hub prices from a third party and reviewed the valuation methodologies, inputs, and reasonableness of the congestion adder on a quarterly basis. As of December 31, 2012, all of these contracts 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 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.
The table below summarizes 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:
PEPCO HOLDINGS
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 and liabilities 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, 2012 and 2011 are shown below:
PEPCO HOLDINGS
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 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, 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. 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 categorized as level 1 is based on actual quoted trade prices for the debt in active markets on the measurement date.
The fair value of Long-term debt and Transition Bonds issued by ACE Funding categorized as level 2 is based on a blend of quoted prices for the debt and quoted prices for similar debt in active markets, but not 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 $4,177 million as of December 31, 2012.
(b) The carrying amount for Transition Bonds issued by ACE Funding, including amounts due within one year, is $295 million as of December 31, 2012.
PEPCO HOLDINGS
The estimated fair values of PHI’s debt instruments at December 31, 2011 are shown below:
The carrying amounts of all other financial instruments in the accompanying consolidated financial statements approximate fair value.
(16) COMMITMENTS AND CONTINGENCIES
General Litigation and Other Matters
In 1993, Pepco was served with Amended Complaints filed in the state Circuit Courts of Prince George’s County, Baltimore City and Baltimore County, Maryland in separate ongoing, consolidated proceedings known as “In re: Personal Injury Asbestos Case.” Pepco and other corporate entities were brought into these cases on a theory of premises liability. Under this theory, the plaintiffs argued that Pepco was negligent in not providing a safe work environment for employees or its contractors, who allegedly were exposed to asbestos while working on Pepco’s property. Initially, a total of approximately 448 individual plaintiffs added Pepco to their complaints. While the pleadings were not entirely clear, it appeared that each plaintiff sought $2 million in compensatory damages and $4 million in punitive damages from each defendant. In the intervening years, most of the cases were voluntarily dismissed by the plaintiffs prior to their respective trial dates. At the beginning of the first quarter of 2012, there were approximately 90 cases pending against Pepco in the Maryland State Courts (excluding those tendered to Mirant Corporation (Mirant) for defense and indemnification in connection with the sale by Pepco of its generation assets to Mirant in 2000), with an aggregate amount of monetary damages sought of approximately $360 million. In March 2012, the parties to these consolidated proceedings (each represented by the same law firm) filed a stipulation of dismissal, by which the plaintiffs voluntarily dismissed Pepco as a defendant, eliminating any reasonably possible liability Pepco may have had with respect to these proceedings.
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 this time, ACE has concluded that a loss is reasonably possible with respect to this matter, but ACE was unable to estimate an amount or range of reasonably possible loss because (i) the damages sought are indeterminate, (ii) the proceedings are in the early stages, and (iii) 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. A trial date has been set for May 20, 2013.
PEPCO HOLDINGS
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 letters also claim compounded interest totaling an additional approximately $9 million. Pepco Energy Services disputes both the allegations regarding unauthorized charges and the claims of entitlement to compounded interest in their entirety, and has been in discussions with the school districts to attempt to resolve these claims. No litigation involving Pepco Energy Services related to these claims has commenced. At this time, Pepco Energy Services has concluded that a loss is reasonably possible with respect to this matter, but Pepco Energy Services cannot estimate an amount or range of reasonably possible loss associated with these claims because the discussions with the school districts are in the early stages.
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, 2012 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 preliminary 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.”
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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.
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 estimates the additional cost for future response measures will be approximately $6 million. ACE believes that EPA sent similar general notice letters to three other companies and various individuals.
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 on November 4, 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 the 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 ACE, DPL and Pepco, 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 ACE, DPL and 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 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 district court’s order addresses only the liability of the test case defendant. PHI has concluded that a loss is reasonably possible with respect to this matter, but PHI was 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 stating that EPA and the District of Columbia Department of the Environment (DDOE) have identified 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 DDOE, which requires Pepco and Pepco Energy Services to conduct a RI/FS for the Benning Road site and an approximately 10-15 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. The court order entering the consent decree requires the parties to submit a written status report to the court on May 24, 2013 regarding the implementation of the requirements of the consent decree and any related plans for remediation. In addition, if the RI/FS has not been completed by May 24, 2013, the status report must provide an explanation and a showing of good cause for why the work has not been completed.
Pepco and Pepco Energy Services submitted a proposed RI/FS work plan in July 2012, and filed a revised work plan in December 2012 based on comments from DDOE and the public. DDOE approved the revised work plan on December 28, 2012 and RI/FS field work commenced in January 2013.
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.”
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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.
The release falls within the regulatory jurisdiction of multiple federal and state agencies. 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 claims for 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. Discussions with DDOE continue regarding the specific nature and scope of the SEPs, as well as the amount of DDOE’s and the federal resource trustees’ natural resource damage claim. This matter is expected to be resolved through the entry of a consent decree sometime in 2013. Based on discussions to date, PHI and Pepco do not believe that the resolution of these claims will have a material adverse effect on their respective financial conditions, results of operations or cash flows.
In March 2011, the Virginia Department of Environmental Quality (VADEQ) requested documentation regarding the release and the preparation of an emergency response report, which Pepco submitted to the agency in April 2011. In March 2011, Pepco received a notice of violation from VADEQ and in December 2011, entered into a consent decree with VADEQ, pursuant to which Pepco paid a civil penalty of approximately $40,000. The U.S. Coast Guard assessed a $5,000 penalty against Pepco for the release of oil into the waters of the United States, which Pepco has paid.
During March 2011, EPA conducted an inspection of the Potomac River substation to review compliance with federal regulations regarding Spill Prevention, Control, and Countermeasure (SPCC) plans for facilities using oil-containing equipment in proximity to surface waters. EPA identified several potential violations of the SPCC regulations relating to SPCC plan content, recordkeeping, and secondary containment. As a result of the oil release, Pepco submitted a revised SPCC plan to EPA in August 2011 and 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 and, after receiving such approval, will submit a further revised SPCC plan to EPA. In the meantime, Pepco is continuing to use the aboveground holding tank to manage storm water from the secondary containment system. In April 2012, EPA advised Pepco that it is not seeking civil penalties at this time for alleged non-compliance with SPCC regulations.
The amounts accrued for these matters are included in the table above in the column entitled “Transmission and Distribution.”
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Fauquier County Landfill Site
In October 2011, Pepco Energy Services received a notice of violation from the VADEQ, which advised Pepco Energy Services of information on which VADEQ may rely to institute an administrative or judicial enforcement action in connection with alleged violation of Virginia air pollution control laws and regulations at the facility of Pepco Energy Services’ subsidiary Fauquier County Landfill Gas, L.L.C. in Warrenton, Virginia. The notice of violation was based on an on-site VADEQ inspection during which VADEQ observed certain alleged deficiencies relating to the facility’s permit to construct and operate. In February 2012, Pepco Energy Services signed a proposed consent order sent by VADEQ, pursuant to which Pepco Energy Services agreed to perform certain remedial actions and agreed to pay a civil charge of approximately $10,000.
PHI’s Cross-Border Energy Lease Investments
As discussed in Note (8), “Leasing Activities,” PHI has a portfolio of cross-border energy lease investments involving public utility assets located outside of the United States with a net investment value of approximately $1.2 billion as of December 31, 2012. Each of these investments is comprised of multiple leases and each investment is structured as a sale and leaseback transaction commonly referred to by the IRS as a sale-in, lease-out, or SILO, transaction.
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 solely 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 2006-2008 income tax return audits continue to be in process with the IRS Office of Appeals and the IRS case manager, respectively, and are not presently a part of the U.S. Court of Federal Claims litigation discussed above.
PHI’s current annual tax benefits from these lease investments are approximately $43 million. After taking into consideration the $74 million paid with the 2001-2002 audit (as discussed above), the net federal and state tax benefits received for the remaining leases from January 1, 2001, the earliest year that remains open to audit, to December 31, 2012, has been approximately $489 million. 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 estimates that, as of December 31, 2012, it would be obligated to pay approximately $600 million in additional federal and state taxes (net of the $74 million tax payment described above) and approximately $144 million of interest on the remaining leases. These amounts have been estimated without 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 on deposit with the IRS. After consideration of these benefits, PHI would be obligated to pay between $170 million and $200 million in additional federal and state taxes and between $50 million and $60 million of interest on the additional federal and state taxes as of March 31, 2013. In addition, the IRS could require PHI to pay a penalty of up to 20% of the amount of additional taxes due.
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See Note (20), “Subsequent Event,” for further information on PHI’s cross-border energy lease investments.
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 (8), “Leasing Activities,” and Note (12), “Income Taxes.” 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 year ended December 31, 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, 2012, 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 contractual commitments for performance and related payments of Pepco Energy Services to counterparties under routine energy sales and procurement obligations.
(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 $54 million, $9 million of which is a guaranty by PHI, $15 million by Pepco, $18 million by DPL and $12 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.
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Energy Services Performance Contracts
Pepco Energy Services has a diverse portfolio of energy savings services 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, 2012, the remaining notional amount of Pepco Energy Services’ energy savings guarantees on both completed projects and projects under construction totaled $446 million over the life of the multi-year performance contracts with the longest guarantee having a remaining term of 13 years. 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, 2012, 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 the life of the multi-year contracts, with the longest guarantee having a remaining term of 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, 2012, Pepco Energy Services had an accrued liability of $1 million for its energy savings or combined heat and power performance contracts that it established during 2012. There was no significant change in the type of contracts issued during the year ended December 31, 2012 as compared to the year ended December 31, 2011.
Dividends
On January 24, 2013, Pepco Holdings’ Board of Directors declared a dividend on common stock of 27 cents per share payable March 28, 2013, to stockholders of record on March 11, 2013.
Contractual Obligations
As of December 31, 2012, Pepco Holdings’ contractual obligations under non-derivative fuel and purchase power contracts were $355 million in 2013, $707 million in 2014 to 2015, $653 million in 2016 to 2017, and $1,911 million in 2018 and thereafter.
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(17) ACCUMULATED OTHER COMPREHENSIVE LOSS
The components of Pepco Holdings’ AOCL relating to continuing operations are as follows. For additional information, see the consolidated statements of comprehensive income.
The income tax expense (benefit) for each component of Pepco Holdings’ other comprehensive income is as follows.
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(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 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.
(b) Includes $39 million pre-tax ($9 million after-tax) gain from the early termination of cross-border energy leases.
(c) Includes a $16 million charge related to the recognition of the tax consequences associated with the early termination of cross-border energy leases.
(a) Includes $39 million pre-tax ($3 million after-tax) gain from the early termination of cross-border energy leases.
(b) Includes tax benefits of $14 million in the second quarter primarily associated with an interest benefit related to federal tax liabilities and a $22 million charge related to the recognition of the tax consequences associated with the early termination of cross-border energy leases.
(19) DISCONTINUED OPERATIONS
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.
The loss from discontinued operations, net of income taxes, for the years ended December 31, 2012, 2011 and 2010, was zero, $3 million and $107 million, respectively.
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(20) SUBSEQUENT EVENT
In the last several years, IRS challenges related to SILO transactions, such as PHI’s cross-border energy lease investments, and lease-in, lease-out (LILO) transactions have been the subject of litigation, including litigation commenced by PHI in the U.S. Court of Federal Claims in January 2012 related to certain tax benefits claimed by PHI on its federal tax returns for 2001 and 2002.
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 LILO transaction. PHI had viewed the initial trial court ruling on this matter, in which the U.S. Court of Federal Claims issued a decision in favor of the taxpayer in October 2009, as a favorable development in PHI’s dispute with the IRS.
Under the FASB guidance for income taxes (ASC 740), the financial statement recognition of the tax benefits of PHI’s uncertain tax position associated with the cross-border energy lease investments is permitted only if it is more likely than not that the position will be sustained. Further, the FASB guidance for leases (ASC 840) requires a company to assess on a periodic basis the likely outcome of tax positions relating to its cross-border energy lease investments and, if there is a change or a projected change in the timing of the estimated tax benefits generated from these investments, a recalculation of the carrying value of its net investment is required.
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 described above, PHI has determined that its tax position with respect to the tax benefits associated with the cross-border energy leases no longer meets the more likely than not standard of recognition for accounting purposes. Accordingly, PHI expects to record a non-cash charge of between $355 million and $380 million (after-tax) in the first quarter of 2013, 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. While the IRS could require PHI to pay a penalty of up to 20 percent 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 will be included in the charge expected to be recorded in the first quarter of 2013.
PHI currently estimates 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 be obligated to pay between $170 million and $200 million in additional federal and state taxes and between $50 million and $60 million of interest on the additional federal and state taxes as of March 31, 2013. These amounts have been estimated taking into consideration certain tax benefits arising from matters unrelated to the leases that would offset the amount of taxes and interest due, including PHI’s estimate of the expected resolution of other uncertain and effectively settled tax positions, the carrying back or carrying forward of any existing net operating losses, and the application of certain amounts on deposit with the IRS. Without consideration of these benefits, PHI estimates that it would have been obligated to pay approximately $600 million in additional federal and state taxes and approximately $150 million of interest on the additional federal and state taxes as of March 31, 2013.
In the first quarter of 2013, PHI anticipates that it will make a deposit with the IRS for the additional taxes and related interest of approximately $220 million to $260 million in order to mitigate PHI’s ongoing interest costs. This deposit is expected to be funded from currently available sources of liquidity and short-term borrowings. PHI also is evaluating the liquidation of all or a portion of its remaining cross-border energy lease investments and the liquidation proceeds could be used to repay any borrowings utilized to fund the deposit discussed above. PHI estimates that a partial or complete liquidation could be accomplished within one year. The aggregate financial impact of a partial or complete liquidation of the cross-border leases is not determinable at this time, but could result in material gains or losses. PHI continues to weigh its options with respect to its litigation with the IRS.
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Management’s Report on Internal Control over Financial Reporting
The management of 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, 2012 based on the framework in Internal Control - Integrated Framework 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, 2012.
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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, 2012 and December 31, 2011, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2012 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 28, 2013
PEPCO
POTOMAC ELECTRIC POWER COMPANY
STATEMENTS OF INCOME
The accompanying Notes are an integral part of these Financial Statements.
PEPCO
POTOMAC ELECTRIC POWER COMPANY
BALANCE SHEETS
The accompanying Notes are an integral part of these Financial Statements.
PEPCO
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.
PEPCO
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 self-insurance reserves 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.
Storm Restoration Costs
The respective service territories of Pepco were affected by a rapidly moving thunderstorm with hurricane-force winds, known as a “derecho,” on June 29, 2012, and Hurricane Sandy on October 29, 2012. Both of these storms resulted in widespread customer outages in each of the service territories and caused extensive damage to Pepco’s electric distribution systems.
Total incremental storm restoration costs incurred by Pepco for the derecho and Hurricane Sandy through December 31, 2012 were $49 million, with $28 million incurred for repair work and $21 million incurred as capital expenditures. Costs incurred for repair work of $23 million were deferred as regulatory assets to reflect the probable recovery of these storm restoration costs in Maryland, and $5 million was charged to Other operation and maintenance expense. As of December 31, 2012, total incremental storm restoration costs include $4 million of estimated costs for unbilled restoration services provided by certain outside contractors. Actual costs for these services may vary from the estimates. Pepco is pursuing recovery of these incremental storm restoration costs in its electric distribution base rate cases.
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General and Auto Liability
During 2011, Pepco reduced its self-insurance reserves for general and auto liability claims by approximately $1 million, based on obtaining an actuarial estimate of the unpaid losses attributed to general and auto liability claims for Pepco. A similar evaluation was performed during 2012 and a reduction of less than $1 million was made to these reserves.
Network Service Transmission Rates
In May of each year, Pepco provides its updated network service transmission rate to the Federal Energy Regulatory Commission (FERC) effective for the service year beginning June 1 of the current year and ending May 31 of the following year. The network service transmission rate includes a true-up for costs incurred in the prior service year that had not yet been reflected in rates charged to customers.
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 $81 million and $82 million as of December 31, 2012 and 2011, 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. Excise tax related generally to the consumption of gasoline by Pepco in the normal course of business is charged to operations, maintenance or construction, and is not material.
Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions
Taxes included in Pepco’s gross revenues were $324 million, $338 million and $322 million for the years ended December 31, 2012, 2011 and 2010, 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 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 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.
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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.
Accounts Receivable and Allowance for Uncollectible Accounts
Pepco’s Accounts receivable balance primarily consists of customer accounts receivable, 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. Although management 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.
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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 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. 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 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 2012, 2011 and 2010 for Pepco’s property were approximately 2.5%, 2.6% and 2.6%, respectively.
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In 2010, Pepco received an award from the U.S. Department of Energy under the American Recovery and Reinvestment Act of 2009. Pepco was awarded $149 million 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 awards 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 $4 million, $8 million and $4 million for the years ended December 31, 2012, 2011 and 2010, respectively.
Pepco recorded amounts for the equity component of AFUDC of $8 million, $12 million and $6 million for the years ended December 31, 2012, 2011 and 2010, 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.
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, 2012 and 2011, $122 million and $144 million of asset removal costs, respectively, are included in Regulatory liabilities in the accompanying balance sheets.
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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 $888 million and $797 million of retained earnings available for payment of common stock dividends at December 31, 2012 and 2011, 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:
Income Tax Adjustments
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.
Operating Expense
In 2010, Pepco recorded an adjustment to correct certain errors related to other taxes which resulted in a decrease to Other taxes expense of $5 million (pre-tax) for the year ended December 31, 2010.
(3) NEWLY ADOPTED ACCOUNTING STANDARDS
Fair Value Measurements and Disclosures (ASC 820)
The FASB issued new guidance on fair value measurement and disclosures that was effective beginning with Pepco’s March 31, 2012 financial statements. The new measurement guidance did not have a material impact on Pepco’s financial statements and the new disclosure requirements are in Note (12), “Fair Value Disclosures,” of Pepco’s financial statements.
(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED
None.
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(5) SEGMENT INFORMATION
The company operates its business as one regulated utility segment, which includes all of its services as described above.
(6) REGULATORY MATTERS
Regulatory Assets and Regulatory Liabilities
The components of Pepco’s regulatory asset and liability balances at December 31, 2012 and 2011 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: Represents 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.
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. These assets are currently earning a return of 12.8%.
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Demand-Side Management: Represents recoverable costs associated with customer energy efficiency programs.
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 which recovery through regulated utility rates is considered probable in the Maryland jurisdictions. Pepco’s costs related to Hurricane Irene and the 2011 severe winter storm are being amortized and recovered in rates over a five-year 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 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
Over the last several years, Pepco has proposed in each of its jurisdictions the adoption of a mechanism to decouple retail distribution revenue from the amount of power delivered to retail customers. To date, a BSA was approved and implemented for electric service in Maryland and the District of Columbia. In October 2012, the MPSC modified the BSA so that a BSA surcharge is not permitted to be collected for revenues lost during the first 24 hours of a major storm. For further information on the BSA in Maryland, see “Maryland - BSA Proceeding” below. 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.
In an effort to reduce the shortfall in revenues due to the delay in time or lag between when costs are incurred and when they are reflected in rates (regulatory lag), Pepco proposed, in each of its jurisdictions, (i) a reliability investment recovery mechanism (RIM) to recover reliability-related capital expenditures incurred between base rate cases, and (ii) the use of fully forecasted test years in future rate cases (which reflect forward-looking costs in lieu of costs incurred over historical test years, and if approved, would be more reflective of current costs and would mitigate the effects of regulatory lag). These proposals were generally not adopted in any of the jurisdictions in which they were filed, as discussed below in connection with the discussions of Pepco’s electric distribution base rate proceedings.
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District of Columbia
In July 2011, Pepco filed an application with the DCPSC to increase its electric distribution base rates by approximately $42 million annually (subsequently reduced to approximately $39 million), based on a requested return on equity (ROE) of 10.75%, of which approximately $9 million was sought so that Pepco could recover its costs associated with the AMI system. The filing included a request for DCPSC approval of a RIM and the use of fully forecasted test years in future Pepco rate cases. On September 26, 2012, the DCPSC issued its decision approving a rate increase of $24 million, based on an ROE of 9.5%, of which approximately $9 million allows Pepco to recover costs associated with the AMI system. The DCPSC denied Pepco’s request for approval of a RIM, and reserved final judgment on the appropriateness of the use by Pepco of a fully forecasted test year in future rate cases. In addition, the DCPSC approved an adjustment by Pepco to normalize operation and maintenance expenses associated with storm restoration efforts to its three-year average, but added approximately $2 million of costs associated with Hurricane Irene from August 2011 in the calculation of the three-year average storm costs.
Maryland
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%. The filing included a request for MPSC approval of a RIM and the use of fully forecasted test years in future Pepco rate cases. 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 MPSC also directed Pepco to reduce the amount of the rate increase by approximately $1.6 million, the annual costs of certain energy advisory programs, resulting in a final rate increase of approximately $16.5 million. Pepco would be required to seek recovery of these annual costs through the EmPower Maryland Program (a demand-side management program) surcharge. The MPSC reduced Pepco’s depreciation rates, which is expected to lower annual depreciation and amortization expenses by an estimated $27.3 million. The order did not approve Pepco’s request to implement a RIM and did not endorse the use by Pepco of fully forecasted test years in future rate cases; however, the MPSC did permit an adjustment to Pepco’s rate base to reflect the actual costs of reliability plant additions outside the test year. The order authorizes Pepco to recover in rates over a five-year period $18.5 million of incremental storm restoration costs associated with major weather events in 2011, including $9.7 million of the $9.9 million of incremental storm restoration costs associated with Hurricane Irene that had been deferred previously as a regulatory asset by Pepco and $8.8 million of incremental storm restoration costs incurred by Pepco associated with a severe winter storm in the first quarter of 2011 that had been expensed previously through other operation and maintenance expense in 2011. The incremental storm restoration costs of $8.8 million were reversed and deferred as a regulatory asset in the third quarter of 2012. The order also authorizes Pepco to recover the actual cost of AMI meters installed during the test year and states that cost recovery for AMI deployment will only be allowed in future rate cases in which Pepco demonstrates that the system is proven to be cost effective. The new revenue rates and lower depreciation rates were effective on July 20, 2012. The Maryland Office of People’s Counsel has sought rehearing on the portion of the order allowing Pepco to recover the costs of installed AMI meters; that motion remains pending.
On November 30, 2012, 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 $60.8 million, based on a requested ROE of 10.25%. The requested rate increase is for the purpose of recovering reliability enhancements to serve Maryland customers. Pepco also proposes a three-year Grid Resiliency surcharge 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 is one of several recommendations included in a September 2012 report from Maryland’s
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Grid Resiliency Task Force (as discussed below). The surcharge, if approved, would become effective January 1, 2014 and would be implemented as a rider that is separate from base rates and would include a return on investment. Specific projects under Pepco’s plan include 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 proposes 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 provides a credit to customers of up to $1 million in total if Pepco does not meet at least the minimum targets. Pepco requests that any credits/charges would flow through the proposed Grid Resiliency Charge rider. An MPSC decision is expected by the end of the second quarter of 2013.
BSA Proceeding
As in effect for electric utilities in Maryland prior to October 26, 2012, including Pepco, a utility was not permitted to collect a BSA surcharge for distribution revenues lost as a result of major storm outages, beginning 24 hours after the commencement of a major storm, if electric service is not restored to the pre-major storm levels within 24 hours of the start of the storm. On October 26, 2012, the MPSC issued an order that no longer permits certain Maryland utilities, including Pepco, to collect a BSA surcharge for revenues lost during the first 24 hours of a major storm.
MPSC New Generation Contract Requirement
In September 2009, the MPSC initiated an investigation into whether the electric distribution companies (EDCs) in Maryland should be required to enter into long-term contracts with entities that construct, acquire or lease, and operate, new electric generation facilities in Maryland.
In April 2012, the MPSC issued an order determining that there is a need for one new power plant in the range of 650 to 700 megawatts (MW) beginning in 2015. The order requires certain Maryland EDCs, including Pepco, 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 (the supply of electricity by Pepco at regulated rates to retail customers who do not elect to purchase electricity from a competitive supplier) (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 acknowledges certain of the EDCs’ concerns about the requirements of the contract and directs them to negotiate with the winning bidder and submit any proposed changes in the contract to the MPSC for approval. The order further specifies that the EDCs entering into the contract will recover the associated costs, in amounts proportional to their relative SOS loads, through surcharges on their respective SOS customers.
In April 2012, a group of generating companies operating in the PJM Interconnection, LLC (PJM) region filed a complaint in the U.S. District Court for the District of Maryland challenging the MPSC’s order on the grounds that it violates the Commerce Clause and the Supremacy Clause of the U.S. Constitution. In May 2012, Pepco and other parties filed notices of appeal in circuit courts in Maryland requesting judicial review of the MPSC’s order. These appeals have been consolidated in the Circuit Court for Baltimore City and have been stayed pending the issuance of a final order from the MPSC approving the form of contract, including the payment obligations of the utilities in the event the utilities do not recover the costs for such payments from their customers.
Until the final form of the contract with the winning bidder and associated cost recovery are approved, Pepco cannot predict (i) the extent of the negative effect that the order and, once finalized, the contract for new generation may have on Pepco’s balance sheets, as well as its credit metrics, as calculated by independent rating agencies that evaluate and rate Pepco and each of its debt issuances, (ii) the effect on Pepco’s ability to recover their associated costs of the contract for new generation if a significant number of SOS customers elect to buy their energy from alternative energy suppliers, and (iii) the effect of the order on the financial condition, results of operations and cash flows of Pepco.
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Reliability Task Forces
In July 2012, the Maryland governor signed an Executive Order directing his energy advisor, in collaboration with certain state agencies, to solicit input and recommendations from experts on how to improve the resiliency and reliability of the electric distribution system in Maryland. The resulting Grid Resiliency Task Force issued its report in September 2012, in which it made 11 recommendations. The governor forwarded the report to the MPSC in October 2012, urging the MPSC to quickly implement the first four recommendations: (i) strengthen existing reliability and storm restoration regulations; (ii) accelerate the investment necessary to meet the enhanced metrics; (iii) allow surcharge recovery for the accelerated investment; and (iv) implement clearly defined performance metrics into the traditional ratemaking scheme. Pepco’s electric distribution base rate case filed with the MPSC on November 30, 2012, addresses the Grid Resiliency Task Force recommendations.
In August 2012, the District of Columbia mayor issued an Executive Order establishing the Mayor’s Power Line Undergrounding Task Force. The purpose of the Power Line Undergrounding Task Force is 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 include legislative bodies, regulators, utility personnel, experts and other parties who could contribute in a meaningful way to the Power Line Undergrounding Task Force. The options that are available for financing these efforts are also to be evaluated to identify required legislative or regulatory actions to implement these recommendations. The results of this analysis are intended to help determine the path forward for these types of infrastructure improvements and additions. A written report from the Power Line Undergrounding Task Force setting forth the findings and recommendations was originally due on January 31, 2013, but has been extended to early March 2013.
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.
As of December 31, 2012, Pepco’s total capital expenditures related to the MAPP project were approximately $64 million. In a 2008 FERC order approving incentives for the MAPP project, FERC authorized the recovery of prudently incurred abandoned costs in connection with the MAPP project. Consistent with this order, on December 21, 2012, PHI submitted a filing to FERC seeking recovery of approximately $50 million of abandoned MAPP capital expenditures. The FERC filing addressed, among other things, the prudence of the recoverable costs incurred, the proposed period over which the abandoned costs are to be amortized and the rate of return on these costs during the recovery period. Various protests have been submitted in response to the December 21, 2012 filing, arguing, among other things, that FERC should disallow a portion of the rate of return involving an incentive adder that would be applied to the abandonment costs, and requesting a hearing on various issues such as the amount of the ROE and the prudence of the costs. Pepco cannot at this time estimate when a final FERC decision in this proceeding will be issued.
As of December 31, 2012, Pepco had placed in service $11 million of its total capital expenditures with respect to the MAPP project, which represented upgrades of existing substation assets that were expected to support the MAPP transmission line, transferred approximately $3 million of materials to inventories for use on other projects and reclassified the remaining $50 million of capital expenditures to a regulatory asset. The regulatory asset includes the costs of land, land rights, supplies and materials, engineering and design, environmental services, and project management and administration. Pepco intends to reduce the regulatory asset by any amounts recovered from the sale or alternative use of the land, land rights, supplies and materials.
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(7) LEASING ACTIVITIES
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.
Capital lease assets recorded within Property, plant and equipment at December 31, 2012 and 2011 are comprised of the following:
The approximate annual commitments under capital leases are $15 million for each year 2013 through 2017, and $32 million thereafter.
Rental expense for operating leases was $6 million, $4 million and $4 million for the years ended December 31, 2012, 2011 and 2010, respectively.
Total future minimum operating lease payments for Pepco as of December 31, 2012 are $6 million in 2013, $6 million in 2014, $6 million in 2015, $5 million in 2016, $4 million in 2017 and $21 million thereafter.
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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, 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.
(9) 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 2012, 2011 and 2010, Pepco was responsible for $39 million, $43 million and $40 million, respectively, of the pension and other postretirement net periodic benefit cost incurred by PHI. During 2012, Pepco made a discretionary tax-deductible contribution to the PHI Retirement Plan in the amount of $85 million. Pepco made a discretionary, tax-deductible contribution of $40 million to the PHI Retirement Plan for the year ended December 31, 2011. No contribution was made for the year ended December 31, 2010. In addition, Pepco made contributions of $5 million, $7 million and $10 million, respectively, to the PHI OPEB Plan for the years ended December 31, 2012, 2011 and 2010. At December 31, 2012 and 2011, Pepco’s Prepaid pension expense of $353 million and $289 million, respectively, and Other postretirement benefit obligations of $66 million, effectively represent assets and benefit obligations resulting from Pepco’s participation in the Pepco Holdings benefit plans.
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(10) DEBT
Long-Term Debt
Long-term debt outstanding as of December 31, 2012 and 2011 is presented below.
(a) Represents a series of first mortgage bonds issued by Pepco (Collateral First Mortgage Bonds) as collateral for an outstanding series of senior notes issued by the company or tax-exempt bonds issued for the benefit of the company. The maturity date, optional and mandatory prepayment provisions, if any, interest rate, and interest payment dates on each series of senior notes or the company’s obligations in respect of the tax-exempt bonds are identical to the terms of the corresponding series of Collateral First Mortgage Bonds. Payments of principal and interest on a series of senior notes or the company’s obligations in respect of the tax-exempt bonds satisfy the corresponding payment obligations on the related series of Collateral First Mortgage Bonds. Because each series of senior notes or the company’s obligations in respect of the tax-exempt bonds and the corresponding series of Collateral First Mortgage Bonds securing that series of senior notes or tax-exempt bonds obligations effectively represents a single financial obligation, the senior notes and the tax-exempt bonds are not separately shown on the table.
(b) Represents a series of Collateral First Mortgage Bonds issued by Pepco that in accordance with its terms will, at such time as there are no first mortgage bonds of Pepco outstanding (other than Collateral First Mortgage Bonds securing payment of senior notes), cease to secure the corresponding series of senior notes and will be cancelled.
(c) Represents a series of Collateral First Mortgage Bonds as to which Pepco has agreed in connection with the issuance of the corresponding series of senior notes that, notwithstanding the terms of the Collateral First Mortgage Bonds described in footnote (b) above, it will not permit the release of the Collateral First Mortgage Bonds as security for the series of senior notes for so long as the senior notes remains outstanding, unless Pepco delivers to the senior note trustee comparable secured obligations to secure the senior notes.
The outstanding First Mortgage Bonds are subject to a lien on substantially all of Pepco’s property, plant and equipment.
The aggregate principal amount of long-term debt outstanding at December 31, 2012, that will mature in each of 2013 through 2017 and thereafter is as follows: $200 million in 2013, $175 million in 2014, zero in 2015 through 2017 and $1,335 million thereafter.
Pepco’s long-term debt is subject to certain covenants. As of December 31, 2012, Pepco is in compliance with all such covenants.
Bond Issuances
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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Bond Redemptions
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.
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.
A detail of the components of Pepco’s short-term debt at December 31, 2012 and 2011 is as follows:
Commercial Paper
Pepco maintains an ongoing commercial paper program to address its short-term liquidity needs. As of December 31, 2012, the maximum capacity available under the program was $500 million, subject to available borrowing capacity under the credit facility.
Pepco had $231 million and $74 million of commercial paper outstanding at December 31, 2012 and 2011, respectively. The weighted average interest rates for commercial paper issued by Pepco during 2012 and 2011 were 0.43% and 0.35%, respectively. The weighted average maturity of all commercial paper issued by Pepco during 2012 and 2011 was five days and two days, respectively.
Credit Facility
PHI, Pepco, Delmarva Power & Light Company (DPL) and Atlantic City Electric Company (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, among other changes, extended the expiration date of the facility to August 1, 2016. On August 2, 2012, the amended and restated credit agreement 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.
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 at December 31, 2012 was $650 million for PHI, $350 million for Pepco and $250 million for each of 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.
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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, 2012.
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.
At December 31, 2012 and 2011, 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 $477 million and $711 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.
(11) 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.
The provision for income taxes, reconciliation of income tax expense, and components of deferred income tax liabilities (assets) are shown below.
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Provision for Income Taxes
Reconciliation of Income Tax Expense
Year ended December 31, 2012
The effective income tax rate primarily reflects tax benefits recorded in 2012 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 rate for the year ended December 31, 2012 reflects an increase in deductible asset removal costs for Pepco in 2012 related to a higher level of asset retirements.
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Year ended December 31, 2011
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 has recorded an additional tax benefit in the amount of $5 million (after-tax). This additional interest income was recorded 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). Further during the third quarter of 2010, Pepco reversed $2 million of previously recorded tax benefits related to changes in estimates and interest related to uncertain and effectively settled tax positions.
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.
Year ended December 31, 2010
In November 2010, PHI reached final settlement with the IRS with respect to its Federal tax returns for the years 1996 to 2002. In connection with the settlement, Pepco reallocated certain amounts on deposit with the IRS since 2006 among liabilities in the settlement years and subsequent years. In light of the settlement and reallocation, Pepco recalculated the estimated interest due for the tax years 1996 to 2002. The revised estimate resulted in the reversal of $24 million (after-tax) of previously accrued estimated interest due to the IRS. This reversal has been recorded as an income tax benefit in the fourth quarter of 2010. This benefit was partially offset by the reversal of $8 million of previously recorded tax benefits and $5 million of other adjustments.
Also in the fourth quarter of 2010, Pepco corrected the tax accounting for software amortization. Accordingly, a regulatory asset was established and income tax expense was reduced by $4 million.
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, 2012 and 2011. 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
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, 2012, Pepco had $8 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, 2012, 2011 and 2010, Pepco recognized $18 million of pre-tax interest income ($11 million after-tax), $8 million of pre-tax interest income ($5 million after-tax), and $27 million of pre-tax interest income ($16 million after-tax), respectively, as a component of income tax expense. As of December 31, 2012, 2011 and 2010, Pepco had accrued interest receivable of $5 million, accrued interest payable of $6 million and accrued interest receivable of $8 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. The final settlement of the 2003 to 2008 Federal audits or state audits could impact the balances and related interest accruals significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.
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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 has 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.
Other Taxes
Taxes other than income taxes for each year are shown below. These amounts are recoverable through rates.
(12) 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, 2012 and 2011. 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, 2012.
(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2011.
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.
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
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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 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, 2012. 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 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 and liabilities 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, 2012 and 2011 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 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, 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. 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 1 is based on actual quoted trade prices for the debt in active markets on the measurement date.
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 in active markets, but not 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 $1,701 million as of December 31, 2012.
The estimated fair value of Pepco’s debt instruments at December 31, 2011 is shown below:
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The carrying amount of all other financial instruments in the accompanying financial statements approximate fair value.
(13) COMMITMENTS AND CONTINGENCIES
General Litigation
In 1993, Pepco was served with Amended Complaints filed in the state Circuit Courts of Prince George’s County, Baltimore City and Baltimore County, Maryland in separate ongoing, consolidated proceedings known as “In re: Personal Injury Asbestos Case.” Pepco and other corporate entities were brought into these cases on a theory of premises liability. Under this theory, the plaintiffs argued that Pepco was negligent in not providing a safe work environment for employees or its contractors, who allegedly were exposed to asbestos while working on Pepco’s property. Initially, a total of approximately 448 individual plaintiffs added Pepco to their complaints. While the pleadings were not entirely clear, it appeared that each plaintiff sought $2 million in compensatory damages and $4 million in punitive damages from each defendant. In the intervening years, most of the cases were voluntarily dismissed by the plaintiffs prior to their respective trial dates. At the beginning of the first quarter of 2012, there were approximately 90 cases pending against Pepco in the Maryland State Courts (excluding those tendered to Mirant Corporation (Mirant) for defense and indemnification in connection with the sale by Pepco of its generation assets to Mirant in 2000), with an aggregate amount of monetary damages sought of approximately $360 million. In March 2012, the parties to these consolidated proceedings (each represented by the same law firm) filed a stipulation of dismissal, by which the plaintiffs voluntarily dismissed Pepco as a defendant, eliminating any reasonably possible liability Pepco may have had with respect to these proceedings.
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 Pepco’s customers, 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, 2012 are summarized as follows:
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
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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 on November 4, 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 the 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 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) 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 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 district court’s order addresses only the liability of the test case defendant. Pepco has concluded that a loss is reasonably possible with respect to this matter, but Pepco was 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.
Benning Road Site
In September 2010, PHI received a letter from EPA stating that EPA and the District of Columbia Department of the Environment (DDOE) have identified 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 DDOE, which requires Pepco and Pepco Energy Services to conduct a RI/FS for the Benning Road site and an approximately 10-15 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. The court order entering the consent decree requires the parties to submit a written status report to the court on May 24, 2013 regarding the implementation of the requirements of the consent decree and any related plans for remediation. In addition, if the RI/FS has not been completed by May 24, 2013, the status report must provide an explanation and a showing of good cause for why the work has not been completed.
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Pepco and Pepco Energy Services submitted a proposed RI/FS work plan in July 2012, and filed a revised work plan in December 2012 based on comments from DDOE and the public. DDOE approved the revised work plan on December 28, 2012 and RI/FS field work commenced in January 2013.
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.
The release falls within the regulatory jurisdiction of multiple federal and state agencies. 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 claims for 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. Discussions with DDOE continue regarding the specific nature and scope of the SEPs, as well as the amount of DDOE’s and the federal resource trustees’ natural resource damage claim. This matter is expected to be resolved through the entry of a consent decree sometime in 2013. Based on discussions to date, PHI and Pepco do not believe that the resolution of these claims will have a material adverse effect on their respective financial conditions, results of operations or cash flows.
In March 2011, the Virginia Department of Environmental Quality (VADEQ) requested documentation regarding the release and the preparation of an emergency response report, which Pepco submitted to the agency in April 2011. In March 2011, Pepco received a notice of violation from VADEQ and in December 2011, entered into a consent decree with VADEQ, pursuant to which Pepco paid a civil penalty of approximately $40,000. The U.S. Coast Guard assessed a $5,000 penalty against Pepco for the release of oil into the waters of the United States, which Pepco has paid.
During March 2011, EPA conducted an inspection of the Potomac River substation to review compliance with federal regulations regarding Spill Prevention, Control, and Countermeasure (SPCC) plans for facilities using oil-containing equipment in proximity to surface waters. EPA identified several potential violations of the SPCC regulations relating to SPCC plan content, recordkeeping, and secondary containment. As a result of the oil release, Pepco submitted a revised SPCC plan to EPA in August 2011 and 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 and, after receiving such approval, will submit a further revised SPCC plan to EPA. In the meantime, Pepco is continuing to use the aboveground holding tank to manage storm water from the secondary containment system. In April 2012, EPA advised Pepco that it is not seeking civil penalties at this time for alleged non-compliance with SPCC regulations.
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The amounts accrued for these matters are included in the table above in the column entitled “Transmission and Distribution.”
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 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 year ended December 31, 2012.
Contractual Obligations
As of December 31, 2012, Pepco had no contractual obligations under non-derivative fuel and power purchase contracts.
(14) 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, 2012, 2011 and 2010 were approximately $211 million, $185 million and $186 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, 2012, 2011 and 2010 were approximately $16 million, $20 million and $10 million, respectively.
As of December 31, 2012 and 2011, 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 customers have selected Pepco Energy Services as their alternative energy supplier or 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.
PEPCO
(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.
(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.
(a) Includes tax benefits of $5 million (after-tax) associated with an interest benefit related to federal tax liabilities and an additional tax benefit of $4 million (after-tax) related to the filing of amended state tax returns, each recorded in the second quarter.
DPL
Management’s Report on Internal Control over Financial Reporting
The management of 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, 2012 based on the framework in Internal Control - Integrated Framework 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, 2012.
DPL
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, 2012 and December 31, 2011, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2012 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 28, 2013
DPL
DELMARVA POWER & LIGHT COMPANY
STATEMENTS OF INCOME
The accompanying Notes are an integral part of these Financial Statements.
DPL
DELMARVA POWER & LIGHT COMPANY
BALANCE SHEETS
The accompanying Notes are an integral part of these Financial Statements.
DPL
DELMARVA POWER & LIGHT COMPANY
BALANCE SHEETS
The accompanying Notes are an integral part of these Financial Statements.
DPL
DELMARVA POWER & LIGHT COMPANY
STATEMENTS OF CASH FLOWS
The accompanying Notes are an integral part of these Financial Statements.
DPL
DELMARVA POWER & LIGHT COMPANY
STATEMENTS OF EQUITY
The accompanying Notes are an integral part of these Financial Statements.
DPL
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 self-insurance reserves 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.
Storm Restoration Costs
The respective service territories of DPL were affected by a rapidly moving thunderstorm with hurricane-force winds, known as a “derecho,” on June 29, 2012, and Hurricane Sandy on October 29, 2012. Both of these storms resulted in widespread customer outages in each of the service territories and caused extensive damage to DPL’s electric distribution systems.
Total incremental storm restoration costs incurred by DPL for the derecho and Hurricane Sandy through December 31, 2012 were $17 million, with $11 million incurred for repair work and $6 million incurred as capital expenditures. Costs incurred for repair work of $6 million were deferred as regulatory assets to reflect the probable recovery of these storm restoration costs in Maryland, and $5 million was charged to Other operation and maintenance expense. As of December 31, 2012, total incremental storm restoration costs include $9 million of estimated costs for unbilled restoration services provided by certain outside contractors. Actual costs for these services may vary from the estimates. DPL is pursuing recovery of these incremental storm restoration costs in its electric distribution base rate cases.
DPL
General and Auto Liability
During 2011, DPL reduced its self-insurance reserves for general and auto liability claims by approximately $2 million, based on obtaining an actuarial estimate of the unpaid losses attributed to general and auto liability claims for DPL. A similar evaluation was performed during 2012 and a reduction of approximately $1 million was made to these reserves.
Network Service Transmission Rates
In May of each year, DPL provides its updated network service transmission rate to the Federal Energy Regulatory Commission (FERC) effective for the service year beginning June 1 of the current year and ending May 31 of the following year. The network service transmission rate includes a true-up for costs incurred in the prior service year that had not yet been reflected in rates charged to customers.
Revenue Recognition
DPL recognizes revenues upon distribution of electricity and gas to its customers, including unbilled revenue for services rendered, but not yet billed. DPL’s unbilled revenue was $62 million and $56 million as of December 31, 2012 and 2011, 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 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 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 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. Excise tax related generally to the consumption of gasoline by DPL in the normal course of business is charged to operations, maintenance or construction, and is not material.
Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions
Taxes included in DPL’s gross revenues were $15 million, $18 million and $17 million for the years ended December 31, 2012, 2011 and 2010, 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 unless designated as normal purchases or normal sales. 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. The gain or loss on a derivative that is designated as a cash flow hedge is initially recorded in Accumulated Other Comprehensive Loss (a separate component of equity) to the extent that the hedge is effective.
DPL
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. At December 31, 2012, after the effects of cash collateral and netting, there was a net derivative liability of $4 million, offset by a $4 million regulatory asset. At December 31, 2011, after the effects of cash collateral and netting, there was a net derivative liability of $15 million, offset by a $17 million regulatory asset.
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 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 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.
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.
DPL
Consolidation of Variable Interest Entities - DPL Renewable Energy Transactions
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.
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, 2012, DPL has entered into three land-based wind power purchase agreements (PPAs) in the aggregate amount of 128 megawatts (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 PPAs. DPL has concluded that consolidation is not required for any of these PPAs under the FASB guidance on the consolidation of variable interest entities.
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, in each case at the rates primarily fixed by the PPA. DPL’s purchases under the three wind PPAs totaled $27 million, $18 million and $12 million for the years ended December 31, 2012, 2011 and 2010, 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 $2 million and $1 million for the years ended December 31, 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 of energy produced by the fuel cell facilities over 21 years. DPL would have no liability 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. In June 2012, a 3 MW fuel cell generation facility was placed into service under the tariff. DPL billed $4 million to distribution customers during the year ended December 31, 2012. A 27 MW fuel cell generation facility is expected to be placed into service over time with the first 5 MW increment having been placed into service at the end of 2012. DPL is accounting for this arrangement as an agency transaction.
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.
DPL
Accounts Receivable and Allowance for Uncollectible Accounts
DPL’s Accounts receivable balance primarily consists of customer accounts receivable, 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. Although management 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.
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. All of DPL’s goodwill was generated by DPL’s acquisition of Conowingo Power Company in 1995. 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 reduce the 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 units; an adverse change in business conditions; an adverse regulatory action; or an impairment of DPL’s long-lived assets. DPL performed its annual impairment test on November 1, 2012 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 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. 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.
DPL
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 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 2012, 2011 and 2010 for DPL’s property were approximately 2.7%, 2.8% and 2.8%, respectively.
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, $1 million and $2 million for the years ended December 31, 2012, 2011 and 2010, respectively.
DPL recorded amounts for the equity component of AFUDC of $3 million, $3 million and $4 million for the years ended December 31, 2012, 2011 and 2010, 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.
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.
DPL
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, 2012 and 2011, $202 million and $244 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 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 $578 million and $505 million of retained earnings available for payment of common stock dividends at December 31, 2012 and 2011, 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:
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.
DPL
(3) NEWLY ADOPTED ACCOUNTING STANDARDS
Goodwill (ASC 350)
The FASB issued new guidance that changes the annual and interim assessments of goodwill for impairment. The new guidance modifies the required annual impairment test by giving entities the option to perform a qualitative assessment of whether it is more likely than not that goodwill is impaired before performing a quantitative assessment. The new guidance also amends the events and circumstances that entities should assess to determine whether an interim quantitative impairment test is necessary. As of January 1, 2012, DPL has adopted the new guidance and concluded it did not have a material impact on its financial statements.
Fair Value Measurements and Disclosures (ASC 820)
The FASB issued new guidance on fair value measurement and disclosures that was effective beginning with DPL’s March 31, 2012 financial statements. The new measurement guidance did not have a material impact on DPL’s financial statements and the new disclosure requirements are in Note (14), “Fair Value Disclosures,” of DPL’s financial statements.
(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED
Balance Sheet (ASC 210)
The FASB issued new disclosure requirements for derivatives that will include information about the gross exposures 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. The new disclosures are effective beginning with DPL’s March 31, 2013 financial statements. DPL does not expect this 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
DPL’s goodwill balance of $8 million was unchanged during the year ended December 31, 2012. All of DPL’s goodwill was generated by its acquisition of Conowingo Power Company in 1995. DPL’s annual impairment test as of November 1, 2012 indicated that goodwill was not impaired.
In order to estimate the fair value of DPL’s business, DPL uses two valuation techniques: an income approach and a market approach. The income approach estimates fair value based on a discounted cash flow analysis using estimated future cash flows 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 market-based information for the cost of equity and cost of debt as of the measurement date appropriate for DPL’s business. 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 framework to estimate the fair value of DPL’s business.
DPL
The estimation of fair value is dependent on a number of factors that are derived from the DPL business forecast, 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 in the models were consistent with historical experience, including assumptions concerning the recovery of operating costs and capital expenditures. Sensitive, interrelated and uncertain variables that could decrease the estimated fair value of the DPL business 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 cost of capital and other factors.
DPL’s gross amount of goodwill, accumulated impairment losses and carrying amount of goodwill for the years ended December 31, 2012 and 2011 were as follows:
(7) REGULATORY MATTERS
Regulatory Assets and Regulatory Liabilities
The components of DPL’s regulatory asset and liability balances at December 31, 2012 and 2011 are as follows:
(a) A return is earned on these deferrals.
(b) A return is generally earned in Delaware on this deferral.
DPL
A description for each category of regulatory assets and regulatory liabilities follows:
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.
Smart Grid: 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.
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. These assets are currently earning a return of 12.8%.
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 will be 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, for which recovery through regulated utility rates is considered probable in the Maryland jurisdiction. DPL’s costs related to Hurricane Irene are being amortized and recovered in rates 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.
Other: Includes miscellaneous regulatory liabilities.
DPL
Rate Proceedings
Over the last several years, DPL has proposed in each its jurisdictions the adoption of a mechanism to decouple retail distribution revenue from the amount of power delivered to retail customers. To date:
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A BSA was approved and implemented for electric service in Maryland. In October 2012, the MPSC modified the BSA so that a BSA surcharge is not permitted to be collected for revenues lost during the first 24 hours of a major storm. For further information on the BSA in Maryland, see “Maryland - BSA Proceeding” below.
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A modified fixed variable rate design (MFVRD) has been approved in concept for electric and natural gas service in Delaware, but the implementation has been deferred by the DPSC pending the development of an implementation plan and a customer education plan, as well as the resolution of various matters relating to development of a statewide energy efficiency plan and attendant legislation.
Under the BSA, customer distribution rates are subject to adjustment (through a credit or surcharge mechanism), depending on whether actual distribution revenue per customer exceeds or falls short of the revenue-per-customer amount approved by the applicable public service commission. The MFVRD approved in concept in Delaware provides for a fixed customer charge (i.e., not tied to the customer’s volumetric consumption of electricity or natural gas) to recover the utility’s fixed costs, plus a reasonable rate of return. Although different from the BSA, DPL views the MFVRD as an appropriate distribution revenue decoupling mechanism.
In an effort to reduce the shortfall in revenues due to the delay in time or lag between when costs are incurred and when they are reflected in rates (regulatory lag), DPL proposed, in each of its jurisdictions, (i) a reliability investment recovery mechanism (RIM) to recover reliability-related capital expenditures incurred between base rate cases, and (ii) the use of fully forecasted test years in future rate cases (which reflect forward-looking costs in lieu of costs incurred over historical test years, and if approved, would be more reflective of current costs and would mitigate the effects of regulatory lag). These proposals were generally not adopted in any of the jurisdictions in which they were filed, as discussed below in connection with the discussions of DPL’s electric distribution base rate proceedings.
Delaware
Gas Cost Rates
DPL makes an annual Gas Cost Rate (GCR) filing with the DPSC for the purpose of allowing DPL to recover natural gas procurement costs through customer rates. In August 2011, DPL made its 2011 GCR filing. The filing included the second year of the effect of a two-year amortization of under-recovered gas costs proposed by DPL in its 2010 GCR filing (the settlement approved by the DPSC in its 2010 GCR case included only the first year of the proposed two-year amortization). The rates proposed in the 2011 GCR would result in a GCR decrease of approximately 5.6%. On August 21, 2012, the DPSC issued a final order approving the rates as filed.
In August 2012, DPL made its 2012 GCR filing. The rates proposed in the 2012 GCR would result in a GCR decrease of approximately 22.3%. On September 18, 2012, the DPSC issued an order allowing DPL to place the new rates into effect on November 1, 2012, subject to refund and pending final DPSC approval.
Electric Distribution Base Rates
In December 2011, DPL submitted an application with the DPSC to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $31.8 million, based on a requested return on equity (ROE) of 10.75%, and requested approval of implementation of the MFVRD.
DPL
The filing included a request for DPSC approval of a RIM and the use of fully forecasted test years in future DPL rate cases. In January 2012, the DPSC entered an order suspending the full increase and allowing a temporary rate increase of $2.5 million to go into effect on January 31, 2012, subject to refund and pending final DPSC approval. In July 2012, in accordance with an agreement with DPSC staff, DPL placed an additional $22.3 million of the requested rate increase into effect, also subject to refund and pending final DPSC order. On November 29, 2012, the DPSC approved a proposed settlement agreement entered into by DPL and the other parties to the proceeding that provides for an annual rate increase of $22 million, based on an ROE of 9.75%. The settlement agreement also permits DPL to collect from its standard offer service (the supply of electricity by Pepco at regulated rates to retail customers who do not elect to purchase electricity from a competitive supplier) (SOS) customers (retail customers who do not elect to purchase electricity from a competitive supplier but instead purchase such electricity from DPL at regulated rates) approximately $3.4 million related to various state and local taxes that were assessed upon DPL’s SOS customers, but actually paid by DPL rather than by the SOS customers upon whom they were assessed. These taxes would be collected over a three-year period. In addition, the settlement agreement allows for the phase-in of the recovery of costs associated with DPL’s AMI system. The settlement agreement does not include approval of a RIM or the use of fully forecasted test years in future DPL rate cases, but it does provide that the parties will meet and discuss alternate regulatory methodologies for the mitigation of regulatory lag. DPL refunded the billed amounts that exceeded the increase approved by the DPSC in February 2013.
Gas Distribution Base Rates
On December 7, 2012, DPL submitted an application with the DPSC to increase its natural gas distribution base rates. The filing seeks approval of an annual rate increase of approximately $12.2 million, based on a requested ROE of 10.25%. The requested rate increase is for the purposes of recovering expenses associated with DPL’s ongoing efforts to maintain safe and reliable service and to provide enhanced customer service technology. In January 2013, the DPSC suspended the full proposed increase and, as permitted by state law, DPL implemented an interim increase of $2.5 million on February 5, 2013, subject to refund and pending final DPSC approval. In compliance with state law and DPSC regulations, DPL also is requesting from the DPSC approval of a Utility Facilities Relocation Charge rider for recovery of future costs associated with the relocation of certain gas delivery service facilities that may be requested by the Delaware Department of Transportation. A final DPSC decision is expected by the third quarter of 2013.
Maryland
Electric Distribution Base Rates
In December 2011, DPL submitted an application with the MPSC to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $25.2 million (subsequently reduced by DPL to $23.5 million), based on a requested ROE of 10.75%. The filing included a request for MPSC approval of a RIM and the use of fully forecasted test years in future DPL rate cases. In July 2012, the MPSC issued an order approving an annual rate increase of approximately $11.3 million, based on an ROE of 9.81%. The MPSC reduced DPL’s depreciation rates, which is expected to lower annual depreciation and amortization expenses by an estimated $4.1 million. The order did not approve DPL’s request to implement a RIM and did not endorse the use by DPL of fully forecasted test years in future rate cases; however, the MPSC did permit an adjustment to DPL’s rate base to reflect the actual costs of reliability plant additions outside the test year. The order also authorizes DPL to recover in rates over a five-year period $4.3 million of the $4.6 million of incremental storm restoration costs associated with Hurricane Irene that had been deferred previously as a regulatory asset by DPL. The new revenue rates and lower depreciation rates were effective on July 20, 2012.
DPL
BSA Proceeding
As in effect for electric utilities in Maryland prior to October 26, 2012, including DPL, a utility was not permitted to collect a BSA surcharge for distribution revenues lost as a result of major storm outages, beginning 24 hours after the commencement of a major storm, if electric service is not restored to the pre-major storm levels within 24 hours of the start of the storm. On October 26, 2012, the MPSC issued an order that no longer permits certain Maryland utilities, including DPL, to collect a BSA surcharge for revenues lost during the first 24 hours of a major storm.
MPSC New Generation Contract Requirement
In September 2009, the MPSC initiated an investigation into whether the electric distribution companies (EDCs) in Maryland should be required to enter into long-term contracts with entities that construct, acquire or lease, and operate, new electric generation facilities in Maryland.
In April 2012, the MPSC issued an order determining that there is a need for one new power plant in the range of 650 to 700 MW beginning in 2015. The order requires certain Maryland EDCs, including DPL, 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 acknowledges certain of the EDCs’ concerns about the requirements of the contract and directs them to negotiate with the winning bidder and submit any proposed changes in the contract to the MPSC for approval. The order further specifies that the EDCs entering into the contract will recover the associated costs, in amounts proportional to their relative SOS loads, through surcharges on their respective SOS customers.
In April 2012, a group of generating companies operating in the PJM Interconnection, LLC (PJM) region filed a complaint in the U.S. District Court for the District of Maryland challenging the MPSC’s order on the grounds that it violates the Commerce Clause and the Supremacy Clause of the U.S. Constitution. In May 2012, DPL and other parties filed notices of appeal in circuit courts in Maryland requesting judicial review of the MPSC’s order. These appeals have been consolidated in the Circuit Court for Baltimore City and have been stayed pending the issuance of a final order from the MPSC approving the form of contract, including the payment obligations of the utilities in the event the utilities do not recover the costs for such payments from their customers.
Until the final form of the contract with the winning bidder and associated cost recovery are approved, DPL cannot predict (i) the extent of the negative effect that the order and, once finalized, the contract for new generation may have on DPL’s balance sheets, as well as its credit metrics, as calculated by independent rating agencies that evaluate and rate DPL and each of its debt issuances, (ii) the effect on DPL’s ability to recover their associated costs of the contract for new generation if a significant number of SOS customers elect to buy their energy from alternative energy suppliers, and (iii) the effect of the order on the financial condition, results of operations and cash flows of DPL.
Maryland Governor’s Grid 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 will consider the Grid Resiliency Task Force recommendations in its next electric distribution base rate case expected to be filed with the MPSC in the first quarter of 2013.
DPL
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.
As of December 31, 2012, DPL’s total capital expenditures related to the MAPP project were approximately $38 million. In a 2008 FERC order approving incentives for the MAPP project, FERC authorized the recovery of prudently incurred abandoned costs in connection with the MAPP project. Consistent with this order, on December 21, 2012, PHI submitted a filing to FERC seeking recovery of approximately $38 million of abandoned MAPP capital expenditures. The FERC filing addressed, among other things, the prudence of the recoverable costs incurred, the proposed period over which the abandoned costs are to be amortized and the rate of return on these costs during the recovery period. Various protests have been submitted in response to the December 21, 2012 filing, arguing, among other things, that FERC should disallow a portion of the rate of return involving an incentive adder that would be applied to the abandonment costs, and requesting a hearing on various issues such as the amount of the ROE and the prudence of the costs. DPL cannot at this time estimate when a final FERC decision in this proceeding will be issued.
As of December 31, 2012, DPL had reclassified all $38 million of capital expenditures with respect to the MAPP project to a regulatory asset. The regulatory asset includes the costs of land, land rights, engineering and design, environmental services, and project management and administration. DPL intends to reduce the regulatory asset by any amounts recovered from the sale or alternative use of the land and land rights.
(8) LEASING ACTIVITIES
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 $88 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, 2012, are $13 million in 2013, $13 million in 2014, $12 million in 2015, $11 million in 2016, $10 million in 2017, and $125 million thereafter.
Rental expense for operating leases, including the Merrill Creek Reservoir lease, was $12 million, $11 million and $10 million for the years ended December 31, 2012, 2011 and 2010, respectively.
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(9) 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.
(10) 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 2012, 2011 and 2010, DPL was responsible for $23 million, $23 million and $28 million, respectively, of the pension and other postretirement net periodic benefit cost incurred by PHI. On January 9, 2013, DPL made a discretionary tax-deductible contribution to the PHI Retirement Plan in the amount of $10 million. During 2012, DPL made a discretionary tax-deductible contribution in the amount of $85 million to the PHI Retirement Plan. DPL made a discretionary, tax-deductible contribution of $40 million to the PHI Retirement Plan for the year ended December 31, 2011. No contribution was made for the year ended December 31, 2010. In addition, DPL made contributions of $7 million, $6 million and $9 million, respectively, to the PHI OPEB Plan for the years ended December 31, 2012, 2011 and 2010. At December 31, 2012 and 2011, DPL’s Prepaid pension expense of $232 million and $162 million, respectively, and Other postretirement benefit obligations of $22 million, effectively represent assets and benefit obligations resulting from DPL’s participation in the PHI benefit plans.
DPL
(11) DEBT
Long-Term Debt
Long-term debt outstanding as of December 31, 2012 and 2011 is presented below:
(a) Represents a series of First Mortgage Bonds issued by DPL (Collateral First Mortgage Bonds) as collateral for an outstanding series of senior notes issued by the company or tax-exempt bonds issued for the benefit of the company. The maturity date, optional and mandatory prepayment provisions, if any, interest rate, and interest payment dates on each series of senior notes or the obligations in respect of the tax-exempt bonds are identical to the terms of the corresponding series of Collateral First Mortgage Bonds. Payments of principal and interest on a series of senior notes or the company’s obligations in respect of the tax-exempt bonds satisfy the corresponding payment obligations on the related series of Collateral First Mortgage Bonds. Because each series of senior notes and tax-exempt bonds and the corresponding series of Collateral First Mortgage Bonds securing that series of senior notes or tax-exempt bonds effectively represents a single financial obligation, the senior notes and the tax-exempt bonds are not separately shown on the table.
(b) These bonds bearing an interest note of 4.90% were repurchased. On June 1, 2011, DPL resold these bonds that were subject to mandatory repurchase on May 1, 2011 at an interest rate of 0.75%. The bonds were purchased on June 1, 2012 pursuant to a mandatory purchase obligation and then retired.
(c) On July 1, 2010, DPL purchased this series of tax-exempt bonds issued for the benefit of DPL by the Delaware Economic Development Authority (DEDA) pursuant to a mandatory repurchase provision in the indenture for the bonds that was triggered by the expiration of the original interest period for the bonds. While DPL held the bonds, they remained outstanding as a contractual matter, but were considered extinguished for accounting purposes. On December 1, 2010, DPL resold the bonds to the public, at which time the interest rate on the bonds was changed from 5.50% to a fixed rate of 1.80%. The bonds were purchased by DPL on June 1, 2012 pursuant to a mandatory purchase obligation and then retired.
(d) On July 1, 2010, DPL purchased this series of tax-exempt bonds issued for the benefit of DPL by DEDA pursuant to a mandatory repurchase provision in the indenture for the bonds that was triggered by the expiration of the original interest period for the bonds. While DPL held the bonds, they remained outstanding as a contractual matter, but were considered extinguished for accounting purposes. On December 1, 2010, DPL resold the bonds to the public, at which time the interest rate on the bonds was changed from 5.65% to a fixed rate of 2.30%. The bonds were purchased by DPL on June 1, 2012 pursuant to a mandatory purchase obligation and then retired.
DPL
The outstanding First Mortgage Bonds issued by DPL are subject to a lien on substantially all of DPL’s property, plant and equipment.
The aggregate principal amount of long-term debt outstanding at December 31, 2012, that will mature in each of 2013 through 2017 and thereafter is as follows: $250 million in 2013, $100 million for each year 2014 through 2016, $14 million in 2017 and $354 million thereafter.
DPL’s long-term debt is subject to certain covenants. As of December 31, 2012, DPL is in compliance with all such covenants.
Bond Issuances
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.
On June 1, 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.
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 is required to be provided by DPL under such agreement.
Bond Redemptions
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.
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.
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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. A detail of the components of DPL’s short-term debt at December 31, 2012 and 2011 is as follows:
Commercial Paper
DPL maintains an ongoing commercial paper program to address its short-term liquidity needs. As of December 31, 2012, the maximum capacity available under the program was $500 million, subject to available borrowing capacity under the credit facility.
DPL had $32 million and $47 million of commercial paper outstanding at December 31, 2012 and 2011, respectively. The weighted average interest rates for commercial paper issued by DPL during 2012 and 2011 were was 0.43% and 0.34%, respectively. The weighted average maturity of all commercial paper issued by DPL during 2012 and 2011 was four days and two 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 2012 mature as follows: 2017 ($26 million), 2024 ($33 million), 2028 ($16 million), and 2029 ($30 million). The weighted average interest rate for VRDBs was 0.38% during 2012 and 0.53% during 2011. Of the $105 million in VRDBs, $72 million of DPL’s obligations are secured by Collateral First Mortgage Bonds, which provide collateral to the investors in the event of a default by DPL.
Credit Facility
PHI, Potomac Electric Power Company (Pepco), DPL and Atlantic City Electric Company (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, among other changes, extended the expiration date of the facility to August 1, 2016. On August 2, 2012, the amended and restated credit agreement 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.
DPL
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 at December 31, 2012 was $650 million for PHI, $350 million for Pepco and $250 million for each of 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, 2012.
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.
At December 31, 2012 and 2011, 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 $477 million and $711 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.
(12) 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.
DPL
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, 2012
The effective income tax rate for 2012 includes the effects of deferred tax basis adjustments that resulted in a $1 million decrease in income taxes and a $1 million benefit associated with depreciation on property, plant and equipment purchased prior to 1975.
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 an additional $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
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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. This resulted in an additional tax expense of $1 million (after-tax).
Year ended December 31, 2010
In November 2010, PHI reached final settlement with the IRS with respect to its Federal tax returns for the years 1996 to 2002. In connection with the settlement, PHI reallocated certain amounts on deposit with the IRS since 2006 among liabilities in the settlement years and subsequent years. In light of the settlement and reallocations, DPL recalculated the estimated interest due for the tax years 1996 to 2002. The revised estimate resulted in an additional $3 million (after-tax) of estimated interest due to the IRS. This additional estimated interest expense was recorded in the fourth quarter of 2010. This expense is partially offset by the reversal of $2 million of previously recorded tax liabilities.
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, 2012 and 2011. 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.
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Reconciliation of Beginning and Ending Balances of Unrecognized Tax Benefits
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, 2012, 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, 2012, 2011 and 2010, DPL recognized less than $1 million of pre-tax interest income, $6 million of pre-tax interest income ($4 million after-tax), and $6 million of pre-tax interest expense ($4 million after-tax), respectively, as a component of income tax expense. As of December 31, 2012, 2011 and 2010, DPL had accrued interest receivable of $1 million, accrued interest receivable of $1 million and accrued interest payable of $5 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. The final settlement of the 2003 to 2008 Federal audits or state audits could impact the balances and related interest accruals significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.
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.
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Other Taxes
Taxes other than income taxes for each year are shown below. These amounts are recoverable through rates.
(13) 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, 2012 and 2011:
DPL
Under FASB guidance on the offsetting of balance sheet accounts (ASC 210-20), DPL offsets the fair value amounts recognized for derivative instruments and fair value amounts recognized for related collateral positions executed with the same counterparty under master netting agreements. The amount of cash collateral that was offset against these derivative positions is as follows:
As of December 31, 2012 and 2011, 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. The following table indicates 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 or Gas purchased expense) that were also deferred as Regulatory assets for the years ended December 31, 2012, 2011 and 2010 associated with cash flow hedges:
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, 2012, 2011 and 2010, the net unrealized derivative losses arising during the period that were deferred as in 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, 2012 and 2011, 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 guaranty 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, 2012 and 2011, was $4 million and $15 million, respectively. As of those dates, DPL had posted no cash collateral in the normal course of business against its gross derivative liabilities resulting in net liabilities of $4 million and $15 million, respectively. If DPL’s debt ratings had been downgraded below investment grade as of December 31, 2012 and 2011, DPL’s net settlement amounts would have been approximately $2 million and $15 million, respectively, and DPL would have been required to post collateral with the counterparties of approximately $2 million and $15 million, respectively, in addition to that which was posted as of December 31, 2012 and 2011. 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. At December 31, 2012 and 2011, the aggregate amount of cash plus borrowing capacity under the credit facilities available to meet the liquidity needs of PHI’s utility subsidiaries was $477 million and $711 million, respectively.
DPL
(14) 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, 2012 and 2011. 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, 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
(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2011.
(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 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.
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, 2012 and 2011 are shown below:
DPL
Other Financial Instruments
The estimated fair values of DPL’s 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, 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. 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 1 is based on actual quoted trade prices for the debt in active markets on the measurement date.
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 in active markets, but not 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.
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 $917 million as of December 31, 2012.
The estimated fair value of DPL’s debt instruments at December 31, 2011 is shown below:
The carrying amounts of all other financial instruments in the accompanying financial statements approximate fair value.
DPL
(15) COMMITMENTS AND CONTINGENCIES
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, 2012 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 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 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 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 district court’s order addresses only the liability of the test case defendant. DPL has concluded that a loss is reasonably possible with respect to this matter, but DPL was 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.
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.”
Contractual Obligations
As of December 31, 2012, DPL’s contractual obligations under non-derivative fuel and power purchase contracts were $62 million in 2013, $126 million in 2014 to 2015, $127 million in 2016 to 2017, and $293 million in 2018 and thereafter.
DPL
(16) 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, 2012, 2011 and 2010 were $153 million, $133 million and $139 million, respectively.
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) During 2010, PHI disposed of its Conectiv Energy segment and a third party assumed Conectiv Energy Supply, Inc.’s responsibilities under these contracts.
(c) Included in Electric revenue.
(d) Included in Gas purchased expense.
As of December 31, 2012 and 2011, DPL had the following balances on its balance sheets due to related parties:
(a) Included in Accounts payable due to associated companies.
DPL
(17) 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 $4 million (after-tax) associated with an interest benefit related to federal tax liabilities in the second quarter and an additional tax expense of $1 million (after-tax) resulting from a recalculation of interest on uncertain tax positions for open tax years in the third quarter.
ACE
Management’s Report on Internal Control over Financial Reporting
The management of 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, 2012 based on the framework in Internal Control - Integrated Framework 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, 2012.
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, 2012 and December 31, 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012 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 28, 2013
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 self-insurance reserves 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.
Storm Restoration Costs
The ACE service territory was affected by a rapidly moving thunderstorm with hurricane-force winds, known as a “derecho,” on June 29, 2012, and Hurricane Sandy on October 29, 2012. Both of these storms resulted in widespread customer outages and caused extensive damage to ACE’s electric transmission and distribution systems.
Total incremental storm restoration costs incurred by ACE for the derecho and Hurricane Sandy through December 31, 2012 were $72 million, with $27 million incurred for repair work and $45 million incurred as capital expenditures. All of the costs incurred for repair work were deferred as regulatory assets to reflect the probable recovery of these storm restoration costs. As of December 31, 2012, total incremental storm restoration costs include $20 million of estimated costs for unbilled restoration services provided by certain outside contractors. Actual costs for these services may vary from the estimates. ACE is pursuing recovery of these incremental storm restoration costs in its electric distribution base rate case filed on December 11, 2012.
ACE
General and Auto Liability
During 2011, ACE reduced its self-insurance reserves for general and auto liability claims by approximately $1 million, based on obtaining an actuarial estimate of the unpaid losses attributed to general and auto liability claims for ACE. A similar evaluation was performed during 2012 and an increase of approximately $1 million was made to these reserves.
Network Service Transmission Rates
In May of each year, ACE provides its updated network service transmission rate to the Federal Energy Regulatory Commission (FERC) effective for the service year beginning June 1 of the current year and ending May 31 of the following year. The network service transmission rate includes a true-up for costs incurred in the prior service year that had not yet been reflected in rates charged to customers.
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 $39 million and $41 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.
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. Excise tax related generally to the consumption of gasoline by ACE in the normal course of business is charged to operations, maintenance or construction, and is not material.
Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions
Taxes included in ACE’s gross revenues were $15 million, $22 million and $23 million for the years ended December 31, 2012, 2011 and 2010, 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.
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 fair value if the expected future undiscounted cash flow from the asset is less than its carrying value.
ACE
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 fair value including costs to sell.
Income Taxes
ACE, as an indirect subsidiary of PHI, is included in the consolidated federal income tax return of Pepco Holdings. 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.
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.
ACE Power Purchase Agreements
ACE is a party to three power purchase agreements (PPAs) with unaffiliated, non-utility generators (NUGs) totaling 459 megawatts (MWs). One of the agreements ends in 2016 and the other two end in 2024. ACE was 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 applied the scope exemption from the consolidation guidance for enterprises that have not been able to obtain such information.
Net purchase activities with the NUGs for the years ended December 31, 2012, 2011 and 2010 were approximately $206 million, $218 million and $292 million, respectively, of which approximately $201 million, $206 million and $270 million, respectively, consisted of power purchases under the PPAs. The power purchase costs are recoverable from ACE’s customers through regulated rates.
Atlantic City Electric Transition Funding LLC
ACE Funding was established in 2001 by ACE 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 have been transferred to ACE in exchange for the transfer by ACE to ACE Funding of the right to collect non-bypassable transition bond charges (the Transition Bond Charges) 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
ACE
and related taxes, expenses and fees (Bondable Transition Property). ACE collects the Transition Bond Charges from its customers on behalf of ACE Funding and the holders of the Transition Bonds. The assets of ACE Funding, including the Bondable Transition Property, and the Transition Bond Charges collected from ACE’s customers, are not available to creditors of ACE. The holders of the 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.
Standard Offer Capacity Agreements
In April 2011, ACE entered into three SOCAs by order of the NJBPU, each with a different generation company. The SOCAs were established under a New Jersey law enacted to promote the construction of qualified electric generation facilities in New Jersey. The SOCAs are 15-year, financially settled transactions approved by the NJBPU that allow generation companies to receive payments from, or require them to make payments to, ACE based on the difference between the fixed price in the SOCAs and the price for capacity that clears PJM. Each of the other electric distribution companies (EDCs) in New Jersey has entered into SOCAs having the same terms with the same generation companies. ACE’s share of the payments received from or the payments made to the generation companies is currently estimated to be approximately 15 percent, based on its proportionate share of the total New Jersey electric load for all EDCs. The NJBPU has ordered that ACE is obligated to distribute to its distribution customers all payments it receives from the generation companies and may recover from its distribution customers all payments it makes to the generation companies. For additional discussion about the SOCAs, see Note (6), “Regulatory Matters.”
In May 2012, all three generation companies under the SOCAs bid into the PJM 2015-2016 capacity auction and two of the generators cleared that capacity auction. ACE recorded a derivative asset (liability) for the estimated fair value of each SOCA and recorded an offsetting regulatory liability (asset) as described in more detail in Note (12), “Derivative Instruments and Hedging Activities,” and Note (13), “Fair Value Disclosures.” FASB guidance on derivative accounting and the accounting for regulated operations would apply to ACE’s obligations under the third SOCA once the related capacity has cleared a PJM auction. The next PJM capacity auction is scheduled for May 2013. ACE has concluded that consolidation of the generation companies is not required.
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 Investments and 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, 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
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. Although management 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.
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 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. 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 2012, 2011 and 2010 for ACE’s property were approximately 3.0%, 3.0% and 2.8%, respectively.
In 2010, ACE received an award from the U.S. Department of Energy under the American Recovery and Reinvestment Act of 2009. ACE was awarded $19 million 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 awards as a reduction in the carrying value of the assets acquired rather than grant income over the service period.
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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 consolidated statements of income.
ACE recorded AFUDC for borrowed funds of $1 million for the year ended December 31, 2012 and $2 million in each of the years ended December 31, 2011 and 2010, respectively.
ACE recorded amounts for the equity component of AFUDC of $3 million for the year ended December 31, 2012 and less than $1 million for each of the years ended December 31, 2011 and 2010, respectively.
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.
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 $200 million of retained earnings available for payment of common stock dividends at December 31, 2012 and 2011. These amounts represent the total retained earnings balances at those dates.
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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:
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.
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.
During 2010, ACE recorded an adjustment to correct certain income tax errors related to prior periods. The adjustment resulted in an increase in income tax expense of $6 million for the year ended December 31, 2010.
(3) NEWLY ADOPTED ACCOUNTING STANDARDS
Fair Value Measurements and Disclosures (ASC 820)
The FASB issued new guidance on fair value measurement and disclosures that was effective beginning with ACE’s March 31, 2012 consolidated financial statements. The new measurement guidance did not have a material impact on ACE’s consolidated financial statements and the new disclosure requirements are in Note (13), “Fair Value Disclosures,” of ACE’s consolidated financial statements.
(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED
Balance Sheet (ASC 210)
The FASB issued new disclosure requirements for derivatives that will include information about the gross exposures 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. The new disclosures are effective beginning with ACE’s March 31, 2013 consolidated financial statements. ACE does not expect this 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.
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(6) REGULATORY MATTERS
Regulatory Assets and Regulatory Liabilities
The components of ACE’s regulatory asset and liability balances at December 31, 2012 and 2011 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 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 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.
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, for which recovery through regulated utility rates is considered probable in the New Jersey jurisdiction. ACE’s costs related to Hurricane Irene are being amortized and recovered in rates over a three-year period.
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.
ACE SOCAs: The regulatory asset represents unrealized losses associated with SOCAs that ACE entered into by order of the NJBPU. The NJBPU has ordered full recovery from distribution customers of payments made by ACE related to the SOCAs. Since these unrealized losses are non-cash, the related
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regulatory asset does not earn a return. The regulatory liability represents unrealized gains associated with the SOCAs that ACE entered into by order of the NJBPU. The NJBPU has ordered that any amounts that ACE receives related to the SOCAs be remitted to its distribution customers.
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 is being amortized as a reduction in Depreciation and amortization expense over an 8.25 year period, which began in June 2005 and expires in 2013.
Other: Includes miscellaneous regulatory liabilities.
Rate Proceedings
Electric Distribution Base Rates
In August 2011, ACE filed a petition with the NJBPU to increase its electric distribution rates by the net amount of approximately $54.6 million (which was increased to approximately $74.3 million on February 24, 2012, to reflect the 2011 test year), based on a requested return on equity (ROE) of 10.75%. The modified net increase consists of a rate increase proposal of approximately $90.3 million, less a deduction from base rates of approximately $16 million through a credit rider expected to expire August 31, 2013, which is designed to refund to customers certain excess depreciation reserve funds as previously directed by the NJBPU (the Excess Depreciation Rider). ACE also proposed an increase of approximately $6.3 million in sales-and-use taxes related to the increase in base rates. On October 23, 2012, the NJBPU approved a stipulation of settlement signed by the parties (the New Jersey Settlement), which provides for an annual increase in ACE’s electric distribution base rates by the net amount of approximately $28 million, based on an ROE that, as part of the overall settlement, is deemed to be 9.75%. The net increase consists of a rate increase of approximately $44 million, less a deduction from base rates of approximately $16 million through the Excess Depreciation Rider. Upon expiration of the Excess Depreciation Rider, ACE will not realize an increase in operating income because the resulting increase in revenues will be offset by an equivalent increase in depreciation expense. The New Jersey Settlement also provides for an increase of approximately $2 million in sales-and-use taxes related to the increase in base rates, and allows ACE to fully amortize over a three-year period the approximately $7.7 million in costs incurred as a result of Hurricane Irene in August 2011. The new rates became effective for utility services rendered on and after November 1, 2012.
On December 11, 2012, ACE filed with the NJBPU an application, 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 (costs associated with deferred, NJBPU-approved expenses incurred as part of ACE’s obligation to serve the public) in the amount of approximately $1.7 million. The requested rate increase is for the purposes of continuing to implement reliability-related investments, recovering system restoration costs associated with the June derecho storm and Hurricane Sandy, and providing an opportunity to earn a reasonable rate of return on its investment. An NJBPU decision is expected by the fourth quarter of 2013.
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Infrastructure Investment Program
In July 2009, the NJBPU approved certain rate recovery mechanisms in connection with ACE’s Infrastructure Investment Program (the IIP). In exchange for the increase in infrastructure investment, the NJBPU, through the IIP, allowed recovery by ACE of its infrastructure investment capital expenditures through a special rate outside the normal rate recovery mechanism of a base rate filing. The IIP was designed to stimulate the New Jersey economy and provide incremental employment in ACE’s service territory by increasing the infrastructure expenditures to a level above otherwise normal budgeted levels. In an October 18, 2011 petition (subsequently amended December 16, 2011) filed with the NJBPU, ACE requested an extension and expansion to the IIP. The New Jersey Settlement approved by the NJBPU provided for full cost recovery of ACE’s initial IIP, as approved by the NJBPU in 2009, but required ACE to withdraw its request for extension and expansion to the IIP, without prejudice to file such request again in the future. On November 8, 2012, ACE withdrew its request for extension and expansion to the IIP.
Update and Reconciliation of Certain Under-Recovered Balances
In February 2012, ACE filed a petition with the NJBPU seeking to reconcile and update (i) charges related to the recovery of above-market costs associated with ACE’s long-term power purchase contracts with the NUGs, (ii) costs related to surcharges for the New Jersey Societal Benefit Program (a statewide public interest program for low income customers) and ACE’s uncollected accounts, and (iii) operating costs associated with ACE’s residential appliance cycling program. The filing proposed to recover the projected deferred under-recovered balance related to the NUGs of $113.8 million as of May 31, 2012 through a four-year amortization schedule. The net impact of adjusting the charges as proposed (consisting of both the annual impact of the proposed four-year amortization of the historical under-recovered NUG balances and the going-forward cost recovery of all the other charges for the period June 1, 2012 through May 31, 2013, and including associated changes in sales-and-use taxes) is an overall annual rate increase of approximately $55.3 million. In June 2012, the NJBPU approved a stipulation of settlement signed by the parties, which provided for provisional rates that went into effect on July 1, 2012. The rates are deemed “provisional” because ACE’s filing will not be updated for actual revenues and expenses (if necessary) for May and June 2012 until after July 1, 2012, and a review of the final underlying costs for reasonableness and prudence will be completed after such filing.
Standard Offer Capacity Agreements
In April 2011, ACE entered into three SOCAs by order of the NJBPU, each with a different generation company, as more fully described in Note (2), “Significant Accounting Policies - Consolidation of Variable Interest Entities - Standard Offer Capacity Agreements” and Note (12), “Derivative Instruments and Hedging Activities.” ACE and the other New Jersey EDCs entered into the SOCAs under protest based on concerns about the potential cost to distribution customers. The dispute is pending before the NJBPU and has been referred to an Administrative Law Judge for further consideration.
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 constitutionality of the New Jersey law under which the SOCAs were established. In September 2012, the District Court denied motions for summary judgment filed by ACE and the other plaintiffs, as well as cross-motions filed by defendants. The litigation remains pending and trial is tentatively scheduled to begin in March 2013.
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(7) LEASING ACTIVITIES
ACE leases certain types of property and equipment for use in its operations. Rental expense for operating leases was $11 million, $10 million and $9 million for the years ended December 31, 2012, 2011 and 2010, respectively.
Total future minimum operating lease payments for ACE as of December 31, 2012 are $5 million in each of the years 2013 through 2015, $4 million in each of the years 2016 and 2017, and $27 million thereafter.
(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.
Jointly Owned Plant
ACE’s consolidated balance sheets include its proportionate share of assets and liabilities related to jointly owned plant. At December 31, 2012 and 2011, 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.
(9) 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 2012, 2011 and 2010, ACE was responsible for $24 million, $21 million and $23 million, respectively, of the pension and other postretirement net periodic benefit cost incurred by PHI. On January 9, 2013, ACE made discretionary tax-deductible contributions to the PHI Retirement Plan in the amount of $30 million. During 2012, ACE made a discretionary tax-deductible contribution to the PHI Retirement Plan in the amount of $30 million. ACE made a discretionary tax-deductible contribution of $30 million to the PHI Retirement Plan for the year ended December 31, 2011. No contribution was made for the year ended December 31, 2010. In addition, ACE made contributions of $7 million, $7 million and $8 million, respectively, to the PHI
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OPEB Plan for the years ended December 31, 2012, 2011 and 2010. At December 31, 2012 and 2011, ACE’s Prepaid pension expense of $88 million and $71 million, and Other postretirement benefit obligations of $34 million and $31 million, respectively, effectively represent assets and benefit obligations resulting from ACE’s participation in the PHI benefit plans.
(10) DEBT
Long-Term Debt
Long-term debt outstanding as of December 31, 2012 and 2011 is presented below.
(a) Represents a series of First Mortgage Bonds issued by ACE (Collateral First Mortgage Bonds) as collateral for an outstanding series of senior notes issued by the company or tax-exempt bonds issued by or for the benefit of ACE. The maturity date, optional and mandatory prepayment provisions, if any, interest rate, and interest payment dates on each series of senior notes or the obligations in respect of the tax-exempt bonds are identical to the terms of the corresponding series of Collateral First Mortgage Bonds. Payments of principal and interest on a series of senior notes or the company’s obligation in respect of the tax-exempt bonds satisfy the corresponding payment obligations on the related series of Collateral First Mortgage Bonds. Because each series of senior notes and tax-exempt bonds and the corresponding series of Collateral First Mortgage Bonds securing that series of senior notes or tax-exempt bonds effectively represents a single financial obligation, the senior notes and the tax-exempt bonds are not separately shown on the table.
(b) Represents a series of Collateral First Mortgage Bonds issued by ACE that will, at such time as there are no first mortgage bonds of ACE outstanding (other than Collateral First Mortgage Bonds securing payment of senior notes), cease to secure the corresponding series of senior notes and will be cancelled.
(c) Represents a series of Collateral First Mortgage Bonds as to which the indicated company has agreed in connection with the issuance of the corresponding series of senior notes that, notwithstanding the terms of the Collateral First Mortgage Bonds described in footnote (b) above, it will not permit the release of the Collateral First Mortgage Bonds as security for the series of senior notes for so long as the senior notes remain outstanding, unless the company delivers to the senior note trustee comparable secured obligations to secure the senior notes.
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The outstanding First Mortgage Bonds issued by ACE are subject to a lien on substantially all of ACE’s property, plant and equipment.
For a description of the Transition Bonds issued by ACE Funding, see Note (2), “Significant Accounting Policies - Consolidation of Variable Interest Entities - ACE Transition Funding, LLC.” The aggregate principal amount of long-term debt including Transition Bonds outstanding at December 31, 2012, that will mature in each of 2013 through 2017 and thereafter is as follows: $108 million in 2013, $48 million in 2014, $59 million in 2015, $48 million in 2016, $35 million in 2017 and $827 million thereafter.
Bond Issuances
On April 5, 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.
ACE’s long-term debt is subject to certain covenants. As of December 31, 2012, ACE is in compliance with all such covenants.
Bond Redemptions
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.
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. A detail of the components of ACE’s short-term debt at December 31, 2012 and 2011 is as follows:
Commercial Paper
ACE maintains an ongoing commercial paper program to address its short-term liquidity needs. As of December 31, 2012, the maximum capacity available under the program was $250 million, subject to available borrowing capacity under the credit facility.
ACE had $110 million and zero of commercial paper outstanding at December 31, 2012 and 2011, respectively. The weighted average interest rates for commercial paper issued by ACE during 2012 and 2011 were 0.41% and 0.33%, respectively. The weighted average maturity of all commercial paper issued by ACE during 2012 and 2011 was three days and six 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
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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. The VRDBs outstanding in 2012 mature as follows: 2014 ($19 million) and 2017 ($4 million). The weighted average interest rate for VRDBs was 0.18% during 2012 and 2011.
Credit Facility
PHI, Potomac Electric Power Company (Pepco), Delmarva Power & Light Company (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, among other changes, extended the expiration date of the facility to August 1, 2016. On August 2, 2012, the amended and restated credit agreement 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.
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 at December 31, 2012 was $650 million for PHI, $350 million for Pepco and $250 million for each of 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 at December 31, 2012.
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.
At December 31, 2012 and 2011, 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 $477 million and $711 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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(11) 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
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Year ended December 31, 2012
The effective tax rate in 2012 reflects a $1 million benefit associated with changes in estimates and interest related to uncertain and effectively settled tax positions.
Year ended December 31, 2011
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 an additional $1 million (after-tax) of interest due to the IRS. This additional interest expense was recorded in the second quarter of 2011. This is further impacted by the adjustment recorded in the third quarter of 2011 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. This resulted in an additional tax expense of $3 million (after-tax).
Year ended December 31, 2010
In November 2010, PHI reached final settlement with the IRS with respect to its federal tax returns for the years 1996 to 2002. In connection with the settlement, PHI reallocated certain amounts on deposit with the IRS since 2006 among liabilities in the settlement years and subsequent years. In light of the settlement and reallocations, ACE recalculated the estimated interest due for the tax years 1996 to 2002. The revised estimate resulted in an additional $1 million (after-tax) of estimated interest due to the IRS for the tax years 1996 to 2002. This additional interest expense was recorded in the fourth quarter of 2010. In addition to this adjustment, in 2010 ACE reversed $6 million of accrued interest income on uncertain and effectively settled state income tax positions, as discussed in Note (2), “Significant Accounting Policies.” This is partially offset by $1 million of other adjustments.
Components of Consolidated 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 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, 2012 and 2011. 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 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
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, 2012, ACE had $6 million of 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, 2012, 2011 and 2010, ACE recognized $2 million of pre-tax interest expense ($1 million after-tax), $5 million of pre-tax interest expense ($3 million after-tax), and $8 million of pre-tax interest expense ($5 million after-tax), respectively, as a component of income tax expense. As of December 31, 2012, 2011 and 2010, ACE had accrued interest receivable of $7 million, $6 million and $14 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. The final settlement of the 2003 to 2008 Federal audits or state audits could impact the balances and related interest accruals significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.
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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 has filed amended state returns requesting $1 million in refunds which are subject to review by the various states.
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
ACE was ordered to enter into the SOCAs by the NJBPU, and under the SOCAs, ACE would receive payments from or make 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, which is currently estimated to be 15 percent. ACE began applying derivative accounting to two of its SOCAs as of June 30, 2012 because the generators cleared the 2015-2016 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 NJBPU has allowed full recovery from ACE’s distribution customers for all payments made by ACE and ACE’s distribution customers would be entitled to all payments received by ACE.
As of December 31, 2012, ACE had other non-current derivative assets of $8 million and non-current derivative liabilities of $11 million associated with the two SOCAs and an offsetting regulatory liability and asset, respectively, of the same amounts. As of December 31, 2012, ACE had 180 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 an unrealized loss of $3 million for the year ended December 31, 2012, have been deferred as regulatory liabilities and assets.
(13) 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).
ACE
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, 2012 and 2011. 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, 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.
(a) There were no transfers of instruments between level 1 and level 2 valuation categories during the year ended December 31, 2011.
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.
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 year ended December 31, 2012 is shown below:
Other Financial Instruments
The estimated fair values of ACE’s 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, 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 issued by ACE Funding categorized as level 2 is based on a blend of quoted prices for the debt and quoted prices for similar debt in active markets, but not 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 $829 million as of December 31, 2012.
(b) The carrying amount for Transition Bonds issued by ACE Funding, including amounts due within one year, is $295 million as of December 31, 2012.
ACE
The estimated fair values of ACE’s debt instruments at December 31, 2011 are shown below:
The carrying amounts of all other financial instruments in the accompanying consolidated financial statements approximate fair value.
(14) COMMITMENTS AND CONTINGENCIES
General Litigation
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 this time, ACE has concluded that a loss is reasonably possible with respect to this matter, but ACE was unable to estimate an amount or range of reasonably possible loss because (i) the damages sought are indeterminate, (ii) the proceedings are in the early stages, and (iii) 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. A trial date has been set for May 20, 2013.
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 ACE’s customers, 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 described below of ACE at December 31, 2012 are summarized as follows:
ACE
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 estimates the additional cost for future response measures will be approximately $6 million. ACE believes that EPA sent similar general notice letters to three other companies and various individuals.
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 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 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 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 district court’s order addresses only the liability of the test case defendant. ACE has concluded that a loss is reasonably possible with respect to this matter, but ACE was 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
As of December 31, 2012, ACE’s contractual obligations under non-derivative fuel and power purchase contracts were $213 million in 2013, $575 million in 2014 to 2015, $526 million in 2016 to 2017 and $1,618 million in 2018 and thereafter.
ACE
(15) 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, 2012, 2011 and 2010 were $117 million, $102 million and $100 million, respectively.
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 Purchased energy expense.
(b) During 2010, PHI disposed of its Conectiv Energy segment and a third party assumed Conectiv Energy Supply, Inc.’s responsibilities under those contracts.
(c) Included in Other operation and maintenance expense.
(d) Included in Operating revenue.
As of December 31, 2012 and 2011, 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.
ACE
(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.
(a) Includes tax expense of $1 million (after-tax) associated with interest related to federal tax liabilities in the second quarter and an additional tax expense of $3 million (after-tax) resulting from a recalculation of interest on uncertain tax positions for open tax years in the third quarter.
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, 2012, 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, 2012, 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.
Except for the information provided below, information required by this Item 10 is incorporated herein by reference to (1) PHI’s definitive proxy statement for the 2013 Annual Meeting, which is expected to be filed with the SEC no later than 120 days after December 31, 2012, and (2) the section entitled “Executive Officers of PHI” contained in Part I, Item 1. “Business” of this Form 10-K.
Adoption of Amended and Restated Bylaws
On February 28, 2013, the Board of Directors of Pepco Holdings adopted amendments to its Bylaws and restated them in their entirety. The following is a brief description of the amendments made to the Bylaws.
•
Director Meetings. The vote required by the Board of Directors to take certain specified actions at a meeting of the Board of Directors was amended from a majority of directors present at the meeting to a majority of the total number of authorized directors, disregarding the existence of vacancies on the Board of Directors. The specified actions include the Board of Directors (i) calling for a special meeting of stockholders and (ii) increasing the size of the Board of Directors; however, the amendments also clarify that, in a vote by the Board of Directors to amend the Bylaws, vacancies on the Board of Directors are to be disregarded. Also, new requirements were added for waiving notice of a Board of Directors meeting and to have the Secretary of Pepco Holdings serve as secretary of the meeting (or another person appointed by the presiding officer of the meeting in the absence of the Secretary).
•
Adjournment of Stockholder Meetings. The Bylaws were amended (i) to state that (A) adjournments of stockholder meetings may be taken regardless of whether a quorum is present, (B) the chairman of the meeting may call for an adjournment (in lieu of having to obtain stockholder approval), and (C) quorum is not broken by the subsequent withdrawal of a stockholder and a meeting may continue after such withdrawal even if less than a quorum remains, and (ii) to delete the provision that a majority in interest of stockholders shall have the power to adjourn the meeting.
•
Conduct of Stockholder Meetings. The Bylaws had provided that the chairman of a Pepco Holdings stockholder meeting had the power to determine all matters with respect to the order of business at, and rules and procedures for conducting, such meetings. The Bylaws were amended to include a non-exclusive list of the types of rules and procedures with respect to the holding and conduct of a stockholders meeting which may be adopted by the Board of Directors or the chairman of such meeting.
•
Amendments to Advance Notice Provisions. The advance notice provisions of the Bylaws were amended to (i) reduce the inside date for submitting a notice of a stockholder proposal from 100 to 90 days and to change the notice dates in the event that an annual meeting date is changed substantially from the prior year’s meeting date; (ii) require certain information and additional disclosures from proponents and nominees regarding the proponent, the nominees and the proposal; and (iii) require that the proponent promptly amend or supplement any information provided and, upon request, confirm the accuracy of information provided.
•
Proxies. The Bylaws were amended with respect to proxies, as follows: (i) to state that, in the event of shares held by multiple persons, any one of such holders may exercise a proxy unless one of them objects in writing to Pepco Holdings; (ii) to permit proxies to be voted at any adjournment of a meeting except as limited in the proxy (rather than limiting the exercise of the proxy at an adjourned meeting to cover only those matters authorized by the proxy); (iii) to add a new provision creating a presumption in favor of the validity of a proxy, unless challenged prior to exercise; (iv) to delete the requirement in the existing Bylaws that a majority of proxy holders present at the meeting may exercise the powers conferred by the proxy unless the proxy provides otherwise; and (v) to state that a proxy is generally revocable except as provided by applicable law.
•
Director Resignations. A new provision was added to the Bylaws to require delivery of a written resignation to Pepco Holdings, or to its Chairman of the Board or Secretary and to provide that all director resignations are effective upon receipt except as otherwise stated in the resignation.
•
Qualifications of Directors. The Bylaws have been amended to (i) delete the requirement that directors own stock (which is already covered by PHI’s director stock ownership policy); and (ii) add specific eligibility requirements as well as information and documentation that must be provided in connection with stockholder nominations of directors.
•
Chairman of the Board. A provision was added to the Bylaws to clarify that the Board of Directors may, but no less frequently than annually, elect a chairman who must be a director and may, but is not required to be, an officer or employee of Pepco Holdings.
•
Board Committees. The Bylaws were amended to provide that the business of committees of the Board of Directors should be conducted as nearly in the same manner as provided in the Bylaws with respect to meetings of the Board.
•
Capital Stock and Transfer Agents. New provisions to the Bylaws were added regarding the use of certificated and uncertificated shares (which would only apply to the extent that Pepco Holdings provides for uncertificated shares in the future) and the noting of restrictions upon transfer of stock on certificates representing shares. A provision was also added to the Bylaws requiring stockholders to notify the transfer agent in writing of changes in their names and addresses and exculpating Pepco Holdings from liability with respect to a failure to direct notices or pay dividends or other property to any stockholder who fails to do so.
•
Record Dates. The Bylaws were amended to (i) include additional circumstances under which a record date may be fixed; (ii) clarify that a record date may not be earlier than the date on which it is fixed; (iii) state that only stockholders on the record date (notwithstanding any transfer occurring thereafter) are entitled to the rights of a stockholder; and (iv) provide for a record date if one is not fixed by the Board.
•
Other Miscellaneous Changes. The amended Bylaws include certain other clarifying, corrective and typographical changes.
The foregoing description of the amendment and restatement of PHI’s Bylaws is qualified in its entirety by reference to the text of the amended and restated Bylaws, which are filed herewith as Exhibit 3.6 and incorporated herein by reference.
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 the 2013 Annual Meeting, which is expected to be filed with the SEC no later than 120 days after December 31, 2012.
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 the 2013 Annual Meeting, which is expected to be filed with the SEC no later than 120 days after December 31, 2012.
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 the 2013 Annual Meeting, which is expected to be filed with the SEC no later than 120 days after December 31, 2012.
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 2012 and 2011 fiscal years, reviews of the financial statements included in the 2012 and 2011 Forms 10-Q of Pepco Holdings and its subsidiary reporting companies, reviews of public filings, comfort letters and other attest services were $6,205,670 and $6,225,940, respectively. The amount for 2011 includes $336,520 for the 2011 audit that was billed after the 2011 amount was disclosed in Pepco Holdings’ proxy statement for the 2012 Annual Meeting of Stockholders.
Audit-Related Fees
There were no fees billed by PricewaterhouseCoopers LLP for audit-related services rendered for the 2012 or 2011 fiscal years.
Tax Fees
The aggregate fees billed by PricewaterhouseCoopers LLP for tax services rendered for the 2012 and 2011 fiscal years were $644,012 and $587,427, respectively. These services consisted of tax compliance, tax advice and tax planning.
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” for the 2012 and 2011 fiscal years were zero and $7,200, respectively. The fees for 2011 represented the costs of training and technical materials provided by PricewaterhouseCoopers LLP.
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 2013 Annual Meeting of Stockholders, which is expected to be filed with the SEC no later than 120 days after December 31, 2012, 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 Income for each of the years ended December 31, 2012, 2011 and 2010
Consolidated Statements of Comprehensive Income for each of the years ended December 31, 2012, 2011 and 2010
Consolidated Balance Sheets as of December 31, 2012 and 2011
Consolidated Statements of Cash Flows for each of the years ended December 31, 2012, 2011 and 2010
Consolidated Statements of Equity for each of the years ended December 31, 2012, 2011 and 2010
Notes to Consolidated Financial Statements
Potomac Electric Power Company
Statements of Income for each of the years ended December 31, 2012, 2011 and 2010
Balance Sheets as of December 31, 2012 and 2011
Statements of Cash Flows for each of the years ended December 31, 2012, 2011 and 2010
Statements of Equity for each of the years ended December 31, 2012, 2011 and 2010
Notes to Financial Statements
Delmarva Power & Light Company
Statements of Income for each of the years ended December 31, 2012, 2011 and 2010
Balance Sheets as of December 31, 2012 and 2011
Statements of Cash Flows for each of the years ended December 31, 2012, 2011 and 2010
Statements of Equity for each of the years ended December 31, 2012, 2011 and 2010
Notes to Financial Statements
Atlantic City Electric Company
Consolidated Statements of Income for each of the years ended December 31, 2012, 2011 and 2010
Consolidated Balance Sheets as of December 31, 2012 and 2011
Consolidated Statements of Cash Flows for each of the years ended December 31, 2012, 2011 and 2010
Consolidated Statements of Equity for each of the years ended December 31, 2012, 2011 and 2010
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 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.
(3) DEBT
For information concerning Pepco Holdings’ long-term debt obligations, see Note (11), “Debt,” to the consolidated financial statements of Pepco Holdings.
(4) COMMITMENTS AND CONTINGENCIES
For information concerning Pepco Holdings’ material contingencies and guarantees, see Note (16), “Commitments and Contingencies” to the consolidated financial statements of Pepco Holdings.
(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:
(6) DISCONTINUED OPERATIONS
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, 2012 and 2011, 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 receivable from 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 (13), “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.
PEPCO HOLDINGS, INC.
(Registrant)
February 28, 2013
By
/s/ JOSEPH M. RIGBY
Joseph M. Rigby
Chairman of the Board, President and
Chief Executive Officer
POTOMAC ELECTRIC POWER COMPANY (Pepco)
(Registrant)
February 28, 2013
By
/s/ DAVID M. VELAZQUEZ
David M. Velazquez,
President and Chief
Executive Officer
DELMARVA POWER & LIGHT COMPANY (DPL)
(Registrant)
February 28, 2013
By
/s/ DAVID M. VELAZQUEZ
David M. Velazquez,
President and Chief
Executive Officer
ATLANTIC CITY ELECTRIC COMPANY (ACE)
(Registrant)
February 28, 2013
By
/s/ DAVID M. VELAZQUEZ
David M. Velazquez,
President and Chief
Executive Officer
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
February 28, 2013
(Principal Executive Officer of Pepco Holdings)
/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 28, 2013
/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 28, 2013
/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 28, 2013
INDEX TO EXHIBITS FILED HEREWITH