.
Item
1. BUSINESS
OVERVIEW
Pepco Holdings, Inc. (PHI or Pepco
Holdings), a Delaware corporation incorporated in 2001, is a diversified energy
company that, through its operating subsidiaries, is engaged primarily in two
businesses:
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electricity
and natural gas delivery (Power Delivery), conducted through the following
regulated public utility companies, each of which is a reporting company
under the Securities Exchange Act of 1934, as amended (the Exchange
Act):
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Potomac
Electric Power Company (Pepco), which was incorporated in Washington, D.C.
in 1896 and became a domestic Virginia corporation in
1949.
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Delmarva
Power & Light Company (DPL), which was incorporated in Delaware in
1909 and became a domestic Virginia corporation in 1979,
and
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Atlantic
City Electric Company (ACE), which was incorporated in New Jersey in
1924.
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competitive
energy generation, marketing and supply (Competitive Energy) conducted
through subsidiaries of Conectiv Energy Holding Company (Conectiv Energy)
and Pepco Energy Services, Inc. (Pepco Energy
Services).
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The following chart shows, in
simplified form, the corporate structure of PHI and its principal
subsidiaries.
Conectiv is solely a holding company
with no business operations. The activities of Potomac Capital
Investment Corporation (PCI) are described below under the heading “Other
Business Operations.”
PHI Service Company 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 the service company are charged to PHI
and the participating operating subsidiaries in accordance with costing
methodologies set forth in the service agreement.
For financial information relating to
PHI’s segments, see Note (3), “Segment Information,” to the consolidated
financial statements of PHI set forth in Item 8 of this Form
10-K. Each of Pepco, DPL and ACE has one operating
segment.
Investor
Information
Each of PHI, Pepco, DPL and ACE files
reports under the Exchange Act. 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 of the companies are made available free of
charge on PHI’s internet Web site as soon as reasonably practicable after such
documents are electronically filed with or furnished to the Securities and
Exchange Commission (SEC). These reports may be found at http://www.pepcoholdings.com/investors.
Description of
Business
The following is a description of each
of PHI’s two principal business operations.
The largest component of PHI’s business
is Power Delivery, which consists of the transmission, distribution and default
supply of electricity. A minor portion of the Power Delivery business
consists of the supply and distribution of natural gas. In 2007, 2006
and 2005, respectively, PHI’s Power Delivery operations produced 56%, 61%, and
58% of PHI’s consolidated operating revenues (including revenue from
intercompany transactions) and 66%, 67%, and 74% of PHI’s consolidated operating
income (including income from intercompany transactions).
Each of Pepco, DPL and ACE is a
regulated public utility in the jurisdictions that comprise its service
territory. Each company owns and operates a network of wires,
substations and other equipment that is classified either as transmission or
distribution facilities. 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.
Delivery
of Electricity and Natural Gas and Default Electricity Supply
Each company is responsible for the
delivery of electricity and, in the case of DPL, natural gas in its service
territory, for which it is paid tariff rates established by the local regulatory
agency. Each company 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 varies
by jurisdiction as follows:
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Delaware
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Provider
of Last Resort service - before May 1,
2006
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Standard
Offer Service (SOS) - on and after May 1,
2006
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New
Jersey
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Basic
Generation Service (BGS)
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In this Form 10-K, these supply service
obligations are referred to generally as Default Electricity
Supply.
In the aggregate, the Power Delivery
business delivers electricity to more than 1.8 million customers in the
mid-Atlantic region and distributes natural gas to approximately 122,000
customers in Delaware.
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. The Federal Energy Regulatory
Commission (FERC) has designated a number of regional transmission organizations
to coordinate the operation and planning of portions of the interstate
transmission grid. Pepco, DPL and ACE are members of the PJM Regional
Transmission Organization (PJM RTO). In 1997, FERC approved PJM
Interconnection, LLC (PJM) as the sole provider of transmission service in the
PJM RTO region, which today consists 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. As the independent grid operator, PJM coordinates the
electric power market and the movement of electricity within the PJM RTO
region. Any entity that wishes to have electricity delivered at any
point in the PJM RTO region must obtain transmission services from PJM at rates
approved by FERC. In accordance with FERC 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. Transmission rates are proposed by
the transmission owner and approved by FERC. PJM, as the tariff
administrator, collects transmission service revenue from transmission service
customers and distributes the revenue to the transmission owners. PJM
also oversees the planning process for the enhancement and expansion of
transmission capability on a regional basis within the PJM RTO
region. PJM approval is required for transmission upgrades and
enhancements undertaken by member utilities.
Distribution of Electricity and
Deregulation
Historically, electric utilities,
including Pepco, DPL and ACE, were vertically integrated businesses that
generated all or a substantial portion of the electric power supply that they
delivered to customers in their service territories over their own distribution
facilities. Customers were charged a bundled rate approved by the
applicable regulatory authority that covered both the supply and delivery
components of the retail electric service. However, legislative and
regulatory actions in each of the service territories in which Pepco, DPL and
ACE operate have resulted in the “unbundling” of the supply and delivery
components of retail electric service and in the opening of the supply component
to competition from non-regulated providers. Accordingly, while
Pepco, DPL and ACE continue to be responsible for the distribution of
electricity in their respective service territories, as the result of
deregulation, customers in those service territories now are permitted to choose
their electricity supplier from among a number of non-regulated, competitive
suppliers. Customers who do not choose a competitive supplier receive
Default Electricity Supply on terms that vary depending on the service
territory, as described more fully below.
In connection with the deregulation of
electric power supply, Pepco, DPL and ACE have divested all of their respective
generation assets, by either selling them to third parties or transferring them
to the non-regulated affiliates of PHI that comprise PHI’s Competitive Energy
businesses. Accordingly, Pepco, DPL and ACE are no longer engaged in
generation operations.
The Power Delivery business is seasonal
and weather patterns can have a material impact on operating
performance. In the region served by PHI, 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. Historically,
the Power Delivery operations of each of PHI’s utility subsidiaries have
generated higher revenues and income when temperatures are colder than normal in
the winter and warmer than normal in the summer, and conversely revenues and
income typically are lower when the temperature is warmer than normal in the
winter and cooler than normal in the summer. In Maryland, however,
the decoupling of distribution revenue for a given reporting period from the
amount of power delivered during the period as the result of the adoption by the
Maryland Public Service Commission (MPSC) of a bill stabilization adjustment
mechanism for retail customers has had the effect of eliminating changes in
customer usage due to weather conditions or for other reasons as a factor having
an impact on reported revenue and income.
The retail operations of PHI’s utility
subsidiaries, including the rates they are permitted to charge customers for the
delivery of electricity and, in the case of DPL, natural gas, are subject to
regulation by governmental agencies in the jurisdictions in which they provide
utility service as follows:
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Pepco’s
electricity delivery operations are regulated in Maryland by the MPSC and
in Washington, D.C. by the District of Columbia Public Service Commission
(DCPSC).
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DPL’s
electricity delivery operations are regulated in Maryland by the MPSC and
in Delaware by the Delaware Public Service Commission (DPSC) and, until
the sale of its
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Virginia
operations on January 2, 2008, were regulated in Virginia by the
Virginia State Corporation Commission. |
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DPL’s
natural gas distribution operations in Delaware are regulated by the
DPSC.
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ACE’s
electricity delivery operations are regulated by the New Jersey Board of
Public Utilities (NJBPU).
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The
transmission and wholesale sale of electricity by each of PHI’s utility
subsidiaries are regulated by FERC.
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The
interstate transportation and wholesale sale of natural gas by DPL are
regulated by FERC.
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Pepco is engaged in the transmission,
distribution and default supply of electricity in Washington, D.C. and major
portions of Prince George’s and Montgomery Counties in suburban
Maryland. Pepco’s service territory covers approximately 640 square
miles and has a population of approximately 2.1 million. As of
December 31, 2007, Pepco delivered electricity to 760,000 customers (of which
241,800 were located in the District of Columbia and 518,200 were located in
Maryland), as compared to 753,000 customers as of December 31, 2006 (of which
240,960 were located in the District of Columbia and 512,040 were located in
Maryland).
In 2007, Pepco delivered a total of
27,451,000 megawatt hours of electricity, of which 30% was delivered to
residential customers, 50% to commercial customers, and 20% to United States and
District of Columbia government customers. In 2006, Pepco delivered a
total of 26,488,000 megawatt hours of electricity, of which 29% was delivered to
residential customers, 51% to commercial customers, and 20% to United States and
District of Columbia government customers.
Pepco has been providing SOS in
Maryland since July 2004. Pursuant to an order issued by the MPSC in
November 2006, Pepco will continue to be obligated to provide SOS to residential
and small commercial customers indefinitely until further action of the Maryland
General Assembly, and to medium-sized commercial customers through May
2009. Pepco also has an ongoing obligation to provide SOS service at
hourly priced rates to the largest customers. Pepco purchases the
power supply required to satisfy its SOS obligation from wholesale suppliers
under contracts entered into pursuant to competitive bid procedures approved and
supervised by the MPSC. Pepco is entitled to recover from its SOS
customers the cost of the SOS supply plus an average margin of $.001667 per
kilowatt-hour. Because margins vary by customer class, the actual
average margin over any given time period depends on the number of Maryland SOS
customers from each customer class and the load taken by such customers over the
time period. Pepco is paid tariff delivery rates for the delivery 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 energy supplier.
Pepco has been providing SOS in the
District of Columbia since February 2005. Pursuant to orders issued
by the DCPSC, Pepco will continue to be obligated to provide SOS for small
commercial and residential customers through May 2011 and for large
commercial
customers
through May 2009. Pepco purchases the power supply required to
satisfy its SOS obligation from wholesale suppliers under contracts entered into
pursuant to a competitive bid procedure approved by the DCPSC. Pepco
is entitled to recover from its SOS customers the costs associated with the
acquisition of the SOS supply plus administrative charges that are intended to
allow Pepco to recover the administrative costs incurred to provide the
SOS. These administrative charges include an average margin for Pepco
of $.00241 per kilowatt-hour. Because margins vary by customer class,
the actual average margin over any given time period depends on the number of
District of Columbia SOS customers from each customer class and the load taken
by such customers over the time period. Pepco is paid tariff delivery
rates for the delivery 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 energy supplier.
For the year ended December 31, 2007,
51% of Pepco’s Maryland sales (measured by megawatt hours) were to SOS
customers, as compared to 60% in 2006, and 35% of its District of Columbia sales
were to SOS customers in 2007, as compared to 57% in 2006.
DPL is engaged in the transmission,
distribution and default supply of electricity in Delaware and portions of
Maryland and Virginia (until the sale of its Virginia operations on January 2,
2008). In northern Delaware, DPL also supplies and distributes
natural gas to retail customers and provides transportation-only services to
retail customers that purchase natural gas from other suppliers.
Transmission and Distribution of
Electricity
In Delaware, electricity service is
provided in the counties of Kent, New Castle, and Sussex and in Maryland in the
counties of Caroline, Cecil, Dorchester, Harford, Kent, Queen Anne’s, Somerset,
Talbot, Wicomico and Worchester. Prior to January 2, 2008, DPL also
provided transmission and distribution of electricity in Accomack and
Northampton counties in Virginia. As discussed below, under the
heading “Sale of Virginia Service Territory,” DPL, on January 2, 2008, completed
the sale of substantially all of its Virginia electric service
operations.
DPL’s electricity distribution service
territory covers approximately 6,000 square miles and has a population of
approximately 1.3 million. As of December 31, 2007, DPL delivered
electricity to 519,000 customers (of which 298,000 were located in Delaware,
198,000 were located in Maryland, and 23,000 were located in Virginia), as
compared to 513,000 electricity customers as of December 31, 2006 (of which
295,000 were located in Delaware, 196,000 were located in Maryland, and 22,000
were located in Virginia).
In 2007, DPL delivered a total of
13,680,000 megawatt hours of electricity to its customers, of which 39% was
delivered to residential customers, 40% to commercial customers and 21% to
industrial customers. In 2006, DPL delivered a total of 13,477,000
megawatt hours of electricity, of which 38% was delivered to residential
customers, 40% to commercial customers and 22% to industrial
customers.
DPL has been providing SOS in Delaware
since May 2006. Pursuant to orders issued by the DPSC, DPL will
continue to be obligated to provide fixed-price SOS to residential,
small
commercial
and industrial customers through May 2009 and to medium, large and general
service customers through May 2008. DPL purchases the power supply
required to satisfy its fixed-price SOS obligation from wholesale suppliers
under contracts entered into pursuant to competitive bid procedures approved by
the DPSC. DPL also has an obligation to provide Hourly Priced Service
(HPS) for the largest customers. Power to supply the HPS customers is
acquired on next-day and other short-term PJM RTO markets. DPL’s
rates for supplying fixed-price SOS and HPS reflect the associated capacity,
energy, transmission, and ancillary services costs and a Reasonable Allowance
for Retail Margin (RARM). Components of the RARM include a fixed
annual margin of $2.75 million, plus estimated incremental expenses, a cash
working capital allowance, and recovery with a return over five years of the
capitalized costs of the billing system used for billing HPS
customers. DPL is paid tariff delivery rates for the delivery 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 energy supplier.
In Delaware, DPL sales to SOS customers
represented 54% of total sales (measured by megawatt hours) for the year ended
December 31, 2007, as compared to 69% in 2006.
DPL has
been providing SOS in Maryland since June 2004. Pursuant to an order
issued by the MPSC in November 2006, DPL will continue to be obligated to
provide SOS to residential and small commercial customers indefinitely until
further action of the Maryland General Assembly, and to medium-sized commercial
customers through May 2009. DPL purchases the power supply required
to satisfy its market rate SOS obligation from wholesale suppliers under
contracts entered into pursuant to competitive bid procedures approved and
supervised by the MPSC. DPL is entitled to recover from its SOS
customers the costs of the SOS supply plus an average margin of $.001667
kilowatt-hour. Because margins vary by customer class, the actual
average margin over any given time period depends on the number of Maryland SOS
customers from each customer class and the load taken by such customers over the
time period. DPL is paid tariff delivery rates for the delivery 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 energy supplier.
In Maryland, DPL sales to SOS customers
represented 67% of total sales (measured by megawatt hours) for the year ended
December 31, 2007, as compared to 75% in 2006.
DPL provided Default Service in
Virginia from March 2004 until the sale of its Virginia retail electric business
on January 2, 2008. DPL was paid tariff delivery rates for the
delivery of electricity over its transmission and distribution facilities to all
electricity customers in its Virginia service territory regardless of whether
the customer received Default Service or purchased electricity from another
energy supplier.
In Virginia, DPL sales to Default
Service customers represented 94% of total sales (measured by megawatt hours)
for the years ended December 31, 2007 and 2006.
Sale
of Virginia Service Territory
On January 2, 2008, DPL completed (i)
the sale of its retail electric distribution business on the Eastern Shore of
Virginia to A&N Electric Cooperative (A&N) for a purchase price
of
approximately
$45.2 million, after closing adjustments, and (ii) the sale of its
wholesale electric transmission business located on the Eastern Shore of
Virginia to Old Dominion Electric Cooperative (ODEC) for a purchase price of
approximately $5.4 million, after closing adjustments. Each of
A&N and ODEC assumed certain post-closing liabilities and unknown
pre-closing liabilities related to the respective assets they are purchasing
(including, in the A&N transaction, most environmental liabilities), except
that DPL remained liable for unknown pre-closing liabilities if they become
known within six months after the January 2, 2008 closing date. These
sales resulted in an immaterial financial gain to DPL that will be recorded
during the first quarter of 2008.
Natural
Gas Distribution
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, or industrial
natural gas customers may purchase natural gas either from DPL or from other
suppliers. DPL uses its natural gas distribution facilities to
transport natural gas for customers that choose to purchase natural gas from
other suppliers. 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 delivery
arrangements. For the twelve months ended December 31, 2007, DPL
supplied 67% of the natural gas that it delivered, compared to 66% in
2006.
As of December 31, 2007, DPL
distributed natural gas to 122,000 customers, as compared to 121,000 customers
as of December 31, 2006. In 2007, DPL distributed 20,700,000 Mcf
(thousand cubic feet) of natural gas to customers in its Delaware service
territory, of which 38% were sales to residential customers, 25% to commercial
customers, 4% to industrial customers, and 33% to customers receiving a
transportation-only service. In 2006, DPL delivered 18,300,000 Mcf of
natural gas, of which 36% were sales to residential customers, 25% were sales to
commercial customers, 4% were to industrial customers, and 35% were sales to
customers receiving a transportation-only service.
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 1.0 million. As of December 31, 2007, ACE
delivered electricity to 544,000 customers in its service territory, as compared
to 539,000 customers as of December 31, 2006. In 2007, ACE delivered
a total of 10,187,000 megawatt hours of electricity to its customers, of which
44% was delivered to residential customers, 44% to commercial customers and 12%
to industrial customers. In 2006, ACE delivered a total of 9,931,000
megawatt hours of electricity to its customers, of which 43% was delivered to
residential customers, 44% to commercial customers, and 13% 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 procure the supply to meet their BGS obligations from competitive
suppliers selected through auctions authorized by the NJBPU for New Jersey’s
total BGS requirements. The winning bidders in the auction are
required to supply a specified 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. ACE’s
BGS-FP load is approximately 2,270 megawatts, which represents
approximately 99% of ACE’s total BGS load. Approximately
one-third of this total load is auctioned off each year for a three-year
term.
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BGS-Commercial
and Industrial Energy Price (BGS-CIEP), which is supplied to larger
customers at hourly PJM RTO real-time market prices for a term of 12
months. ACE’s BGS-CIEP load is approximately 16 megawatts, which
represents approximately 1% of ACE’s BGS load. This total load
is auctioned off each year for a one-year
term.
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ACE is paid tariff rates established by
the NJBPU that compensate it for the cost of obtaining the BGS
supply. ACE does not make any profit or incur any loss on the supply
component of the BGS it provides to customers.
ACE is paid tariff delivery rates for
the delivery of electricity over its transmission and distribution facilities to
all electricity customers in its New Jersey service territory regardless of
whether the customer receives BGS or purchases electricity from another energy
supplier.
ACE sales to BGS customers represented
80% of total sales (measured by megawatt hours) for the year ended December 31,
2007 and 78% of total sales (measured by megawatt hours) for the year ended
December 31, 2006.
On February 8, 2007, ACE completed the
sale of its B.L. England generating facility. B.L. England comprised
a significant component of ACE’s generation operations and its sale required
discontinued operations presentation under Statement of Financial Accounting
Standards (SFAS) No. 144, “Accounting for the Impairment or Disposal of Long
Lived Assets,” on ACE’s consolidated statements of earnings for the years ended
December 31, 2007, 2006 and 2005. ACE’s sale of its interests in the
Keystone and Conemaugh generating facilities in September 2006 is also reflected
as discontinued operations on ACE’s consolidated statements of earnings for the
years ended December 31, 2006 and 2005.
ACE has several contracts with
non-utility generators (NUGs) under which ACE purchased 3.8 million megawatt
hours of power in 2007. ACE sells the electricity purchased under the
contracts with NUGs into the wholesale market administered by PJM.
In 2001, ACE established Atlantic City
Electric Transition Funding LLC (ACE Funding) solely for the purpose of
securitizing authorized portions of ACE’s recoverable stranded costs through the
issuance and sale of bonds (Transition Bonds). The proceeds of the
sale of each
series of
Transition Bonds have been transferred to ACE in exchange for the transfer by
ACE to ACE Funding of the right to collect a non-bypassable transition bond
charge from ACE customers pursuant to bondable stranded costs rate orders issued
by the NJBPU in an amount sufficient to fund the principal and interest payments
on the Transition Bonds and related taxes, expenses and fees (Bondable
Transition Property). The assets of ACE Funding, including the
Bondable Transition Property, and the Transition Bond charges 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.
Competitive
Energy
PHI’s Competitive Energy business is
engaged in the generation of electricity and the non-regulated marketing and
supply of electricity and natural gas, and related energy management services,
primarily in the mid-Atlantic region. In 2007, 2006 and 2005 PHI’s
Competitive Energy operations produced 48%, 43%, and 48%, respectively, of PHI’s
consolidated operating revenues. In 2007, 2006 and 2005 PHI’s
Competitive Energy operations produced 26%, 20%, and 16%, respectively, of PHI’s
consolidated operating income. PHI’s Competitive Energy operations
are conducted by Conectiv Energy and Pepco Energy Services which are separate
operating segments for financial reporting purposes.
Conectiv Energy provides wholesale
electric power, capacity, and ancillary services in the wholesale markets and
also supplies electricity to other wholesale market participants under long- and
short-term bilateral contracts. Conectiv Energy also supplies
electric power to Pepco, DPL and ACE to satisfy a portion of their Default
Electricity Supply load, as well as default electricity supply load shares of
other utilities within PJM RTO and the ISONE wholesale markets. PHI
refers to these activities as Merchant Generation & Load
Service. Other than its default electricity supply sales, Conectiv
Energy does not participate in the retail competitive power supply
market. Conectiv Energy obtains the electricity required to meet its
power supply obligations from its own generating plants, under bilateral
contracts entered into with other wholesale market participants and through
purchases in the wholesale market.
Conectiv Energy’s generation capacity
is concentrated in mid-merit plants, which due to their operating flexibility
and multi-fuel capability can quickly change their output level on an economic
basis. Like “peak-load” plants, mid-merit plants generally operate
during times when demand for electricity rises and prices are
higher. However, mid-merit plants usually operate more frequently and
for longer periods of time than peak-load plants because of better heat
rates. As of December 31, 2007, Conectiv Energy owned and operated
mid-merit plants with a combined 2,725 megawatts of capacity, peak-load plants
with a combined 639 megawatts of capacity and base-load generating plants with a
combined 340 megawatts of capacity. See Item 2
“Properties.” In addition to the generation plants it owns, Conectiv
Energy controls another nominal 480 megawatts of capacity through tolling
agreements.
On December 14, 2007, Conectiv Energy
announced a decision to construct a 545 MW natural gas and oil-fired
combined-cycle electricity generation plant to be located in Peach Bottom
Township, Pennsylvania. The plant will be owned and operated as part
of Conectiv Energy and is expected to go into commercial operation in
2011. Conectiv Energy has entered into a six-year tolling agreement
with an unaffiliated energy company under which Conectiv
Energy
will sell the energy, capacity and most of the ancillary services from the plant
for the period June 1, 2011 through May 31, 2017 to the other
party. Under the terms of the tolling agreement, Conectiv Energy will
be responsible for the operation and maintenance of the plant, subject to the
other party’s control over the dispatch of the plant’s output. The
other party will be responsible for the purchase and scheduling of the fuel to
operate the plant and all required emissions allowances.
Conectiv Energy also sells natural gas
and fuel oil to very large end-users and to wholesale market participants under
bilateral agreements and operates a short-term power desk, which generates
margin by identifying and capturing price differences between power pools and
locational and timing differences within a power pool. Conectiv
Energy obtains the natural gas and fuel oil required to meet its supply
obligations through market purchases for next day delivery and under long- and
short-term bilateral contracts with other market participants.
PHI’s Competitive Energy businesses use
derivative instruments primarily to reduce their financial exposure to changes
in the value of their assets and obligations due to commodity price
fluctuations. The derivative instruments used by the Competitive Energy
businesses include forward contracts, futures, swaps, and exchange-traded and
over-the-counter options. In addition, the Competitive Energy businesses also
manage commodity risk with contracts that are not classified as
derivatives. The two primary risk management objectives are (1) to
manage the spread between the cost of fuel used to operate electric generation
plants and the revenue received from the sale of the power produced by those
plants, and (2) to manage the spread between retail sales commitments and the
cost of supply used to service those commitments to ensure stable and known
minimum cash flows, and lock in favorable prices and margins when they become
available. To a lesser extent, Conectiv Energy also engages in energy
marketing activities. Energy marketing activities consist primarily
of wholesale natural gas and fuel oil marketing; the activities of the
short-term power desk, which generates margin by capturing price differences
between power pools, and locational and timing differences within a power pool;
and prior to October 31, 2006, provided operating services under an
agreement with an unaffiliated generating plant. PHI collectively
refers to these energy marketing activities, including its commodity risk
management activities, as “other energy commodity” activities and identifies
this activity separately from the proprietary trading activity that was
discontinued in 2003.
Conectiv Energy’s goal is to manage the
risk associated with the expected power output of its generation facilities and
their fuel requirements. The risk management goals are approved by
the CRMC and may change from time to time based on market
conditions. The actual level of coverage may vary depending on the
extent to which Conectiv Energy is successful in implementing its risk
management strategies. For additional discussion of Conectiv Energy’s
risk management activities, see Item 7A “Quantitative and Qualitative
Disclosures About Market Risk.”
Pepco Energy Services provides retail
energy supply and energy services primarily to commercial, industrial, and
government customers. Pepco Energy Services sells electricity,
including electricity from renewable resources, to customers located primarily
in the mid-Atlantic and northeastern regions of the U.S. and the Chicago,
Illinois area. As of December 31, 2007, Pepco Energy Services’
estimated retail electricity backlog was 31.8 million MWh for
delivery
through 2013, an increase of 2% over December 31, 2006. Pepco Energy
Services also sells natural gas to customers primarily located in the
mid-Atlantic region.
Pepco Energy Services also provides
energy savings performance contracting services principally to federal, state
and local government customers, and owns and operates district energy systems in
Atlantic City, New Jersey and Wilmington, Delaware and sells steam and chilled
water to customers in those cities. Pepco Energy Services also
designs, constructs, and operates combined heat and power and central energy
plants.
In addition, Pepco Energy Services
provides high voltage construction and maintenance services to utilities
throughout the United States and low voltage electric and telecommunication
construction and maintenance services to utilities and other commercial
customers and streetlight asset management services to municipalities in the
Washington, D.C. area.
During 2006, Pepco Energy Services sold
five businesses that served primarily commercial and industrial customers by
providing heating, ventilation, air conditioning, electrical testing and
maintenance, and building automation services. Net assets sold were
approximately $20.7 million.
Pepco Energy Services also owns and
operates two oil-fired power plants. The power plants are located in
Washington, D.C. and have a generating capacity rating of approximately 790
MW. See Item 2 “Properties.” Pepco Energy Services sells
the output of these plants into the wholesale market administered by
PJM. In February 2007, Pepco Energy Services provided notice to PJM
of its intention to deactivate these plants. In May 2007, Pepco
Energy Services deactivated one combustion turbine at its Buzzard Point facility
with a generating capacity of approximately 16 MW. Pepco Energy
Services currently plans to deactivate the balance of both plants by May
2012. PJM has informed Pepco Energy Services that these facilities
are not expected to be needed for reliability after that time, but that its
evaluation is dependent on the completion of transmission
upgrades. Pepco Energy Services’ timing for deactivation of these
units, in whole or in part, may be accelerated or delayed based on the operating
condition of the units, economic conditions, and reliability
considerations. Deactivation will not have a material impact on PHI’s
financial condition, results of operations or cash flows.
One of the sources of revenue of the
Competitive Energy Business is the sale of capacity by Conectiv Energy and Pepco
Energy Services associated with their respective generating facilities. The
wholesale market for capacity is administered by PJM which is responsible for
ensuring that within the transmission control area there is sufficient
generating capability available to meet the load requirements plus a reserve
margin. In accordance with PJM requirements, retail sellers of electricity in
the PJM market are required to maintain capacity from generating facilities
within the control area or generating facilities outside the control area which
have firm transmission rights into the control area that correspond to their
load service obligation. This capacity can be obtained through the ownership of
generation facilities, the entry into bilateral contracts or the purchase of
capacity credits in the auctions administered by PJM. All of the generating
facilities owned by PHI’s Competitive Energy businesses are located in the
transmission control area administered by PJM. The capacity of a generating unit
is determined based on the demonstrated generating capacity of the unit and its
forced outage rate.
Beginning on June 1, 2007, PJM replaced
its former capacity market rules with a forward capacity auction procedure known
as the Reliability Pricing Model (RPM), which provides for differentiation in
capacity prices between Locational Deliverability Areas. One of the primary
objectives of RPM is to encourage the development of new generation sources,
particularly in constrained areas.
Under RPM, PJM has held four auctions,
each covering capacity to be supplied over consecutive 12-month periods
beginning June 1, 2007. Each of these auctions has yielded higher prices for
capacity than in the period preceding implementation of RPM. Auctions
of capacity for each subsequent 12-month delivery period will be held 36 months
ahead of the scheduled delivery year. The next auction, for the period June 1,
2011 through May 31, 2012, will take place in May 2008.
In addition to participating in the PJM
auctions, PHI’s Competitive Energy businesses participate in the forward
capacity market as both sellers and buyers in accordance with PHI’s risk
management policy, and accordingly, prices realized in the PJM capacity auctions
may not be indicative of gross margin that PHI earns in respect to its capacity
purchases and sales during a given period.
The unregulated energy generation,
supply and marketing businesses primarily located in the mid-Atlantic region are
characterized by intense competition at both the wholesale and retail
levels. At the wholesale level, Conectiv Energy and Pepco Energy
Services compete with numerous non-utility generators, independent power
producers, wholesale power marketers and brokers, and traditional utilities that
continue to operate generation assets. In the retail energy supply
market and in providing energy management services, Pepco Energy Services
competes with numerous competitive energy marketers and other service
providers. Competition in both the wholesale and retail markets for
energy and energy management services is based primarily on price and, to a
lesser extent, the range of services offered to customers and quality of
service.
Like the Power Delivery business, the
power generation, supply and marketing businesses are seasonal and weather
patterns can have a material impact on operating performance. Demand
for electricity generally is higher in the summer months associated with cooling
and demand for electricity and natural gas generally is higher in the winter
months associated with heating, as compared to other times of the
year. Historically, the competitive energy operations of Conectiv
Energy and Pepco Energy Services have generated less revenue when temperatures
are milder than normal in the winter and cooler than normal in the
summer. Milder weather can also negatively impact income from these
operations. Energy management services generally are not
seasonal.
Other
Business Operations
Through its subsidiary, Potomac Capital
Investment Corporation (PCI), PHI maintains a portfolio of cross-border energy
sale-leaseback transactions, with a book value at December 31, 2007 of
approximately $1.4 billion. For additional information concerning
these cross-border lease transactions, see Note (12), “Commitments and
Contingencies,” to the consolidated financial statements of PHI included in Item
8 “Financial Statements and Supplementary Data”
and Item
7 “Management’s Discussion and Analysis of Financial Condition and Results of
Operations.” This activity constitutes a separate operating segment
for financial reporting purposes, which is designated “Other
Non-Regulated.”
EMPLOYEES
At December 31, 2007, PHI had 5,131
employees, including 1,365 employed by Pepco, 916 employed by DPL, 507 employed
by ACE and 1,805 employed by PHI Service Company. The balance were
employed by PHI’s Competitive Energy and other non-regulated
businesses. Approximately 2,666 employees (including 1,060 employed
by Pepco, 741 employed by DPL, 363 employed by ACE, 344 employed by PHI Service
Company, and 158 employed by Conectiv Energy) are covered by collective
bargaining agreements with various locals of the International Brotherhood of
Electrical Workers.
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. 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’ currently projected
capital expenditures plan for the replacement of existing or installation of new
environmental control facilities that are necessary for compliance with
environmental laws, rules or agency orders by its subsidiaries are
$51.3 million in 2008 and $43.9 million in 2009. The actual
costs of environmental compliance may be materially different from this capital
expenditures plan 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 and
regulations.
The projected capital expenditures for
2008 and 2009 include $38 million and $19.2 million, respectively, of
expenditures to comply with multipollutant regulations adopted by the Delaware
Department of Natural Resources and Environmental Control
(DNREC). Conectiv Energy has appealed these regulations, as described
below. See Item 7, “Management’s Discussion and Analysis of Financial
Condition and Results of Operations -- Capital Resources and Liquidity --
Capital Requirements -- Compliance with Delaware Multipollutant
Regulations”. The $57.2 million in expected expenditures in 2008
and 2009 for compliance with the multipollutant regulations is only a portion of
the total capital expenditures of $79 million, which PHI currently
estimates will be necessary for multipollutant regulation compliance over the
long term.
Air
Quality Regulation
The generating facilities and
operations of PHI’s subsidiaries are 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.
Sulfur Dioxide, Nitrogen Oxide, Mercury
and Nickel Emissions
Among other things, the acid rain
provisions of the CAA 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. The
generating facilities of PHI’s subsidiaries that require SO2 allowances
use allocated allowances or allowances acquired, as necessary, in the open
market to satisfy applicable regulatory requirements. Also under
current regulations implementing CAA standards, each of the states in which PHI
subsidiaries own and operate generating units regulate nitrogen oxide (NOx)
emissions from generating units and allocate NOx allowances. Most of
the generating units operated by PHI subsidiaries are subject to NOx emission
limits. These units use allocated allowances or allowances purchased
in the open market as necessary to achieve compliance with these
regulations.
In 2005, the U.S. Environmental
Protection Agency (EPA) issued its Clean Air Interstate Rule (CAIR), which
imposes additional reductions of SO2 and NOx
emissions from electric generating units in 28 eastern states and the District
of Columbia, including each of the states in which PHI subsidiaries own and
operate generating units. CAIR uses an allowance system to cap
state-wide emissions of SO2 and NOx in
two stages beginning in 2009 for NOx and 2010 for SO2. States
may implement CAIR by adopting EPA’s trading program or through regulations that
at a minimum achieve the reductions that would be achieved through
implementation of EPA’s program. Each state covered by CAIR may
determine independently which emission sources to control and which control
measures to adopt. CAIR includes model rules for multi-state cap and
trade programs for power plants that states may choose to adopt to meet the
required emissions reductions. These regulations may require
installation of pollution control devices and/or fuel modifications for
generating units owned by Conectiv Energy and Pepco Energy
Services.
The states in which PHI subsidiaries
own and operate generating units have adopted, or are in the process of
adopting, regulations to implement CAIR which will require, beginning in 2009,
the surrender of a NOx annual allowance for each ton of NOx emitted during the
year and, beginning in 2010, will require the surrender of more than one SO2 allowance
for each ton of SO2
emitted. To implement CAIR, the New Jersey Department of
Environmental Protection (NJDEP) in June 2007 adopted a new NOx trading program
that will replace the existing NOx trading program in 2009. This new
trading program will allocate NOx annual and NOx ozone season allowances to
Conectiv Energy’s Carll’s Corner, Cedar, Middle, Mickleton, Cumberland and
Sherman generating units, and will operate in a manner similar to NJDEP’s
existing NOx trading program. Conectiv Energy’s Edge Moor, Christiana
and Hay Road generating units in Delaware will be subject to federal CAIR for
NOx and SO2. Pennsylvania
is expected to promulgate CAIR regulations in 2008 that will be applicable to
Conectiv Energy’s Bethlehem generating units and the generating units being
constructed in Peach Bottom Township, Pennsylvania, known as the Delta
Project. Virginia will implement CAIR by participating in EPA’s cap
and trade program and Conectiv Energy’s Tasley peaking unit will be subject to
CAIR requirements. Conectiv Energy’s Maryland generating units are
smaller than CAIR’s applicability threshold and therefore are not subject to
CAIR.
Pepco Energy Services’ Benning Road
generating units located in the District of Columbia will be subject to CAIR
requirements. However, it is not yet certain whether the District
will adopt a state implementation plan or whether the District will rely on the
federal
program. Pepco
Energy Services’ Buzzard Point generating units and its landfill gas generating
units will not be subject to CAIR.
Conectiv Energy and Pepco Energy
Services units will use NOx annual, NOx ozone season and SO2 allowances
allocated or purchased in the open market as necessary to comply with
CAIR. Although implementation of CAIR will increase costs for
Conectiv Energy and Pepco Energy Services units, PHI currently does not
anticipate that CAIR will have a significant impact on the operation of the
affected generating units.
In 2005, EPA finalized its Clean Air
Mercury Rule (CAMR), which established mercury emissions standards for new or
modified sources and capped state-wide emissions of mercury beginning in
2010. The regulations, which permitted states to implement CAMR by
adopting EPA’s market-based cap-and trade allowance program for coal-fired
utility boilers or through regulations that at a minimum achieve the reductions
that would be achieved through EPA’s program, were vacated by the United States
Court of Appeals for the District of Columbia Circuit in February
2008.
In December 2004, NJDEP published final
rules regulating mercury emissions from power plants and industrial facilities
in New Jersey that impose standards, effective December 15, 2007, that are
significantly stricter than EPA’s now vacated federal CAMR for coal-fired
plants. Conectiv Energy has initiated a monitoring program at the
Deepwater generating facility, its only coal-fired generating plant in New
Jersey, in order to show compliance with NJDEP’s mercury
regulations.
On November 15, 2006, DNREC adopted
regulations to require large coal-fired and residual oil-fired electric
generating units to develop control strategies to address air quality in
Delaware. These control strategies are intended to assure attainment
of ambient air quality standards for ozone and fine particulate matter, address
local scale fine particulate emission problems, reduce mercury emissions,
satisfy the now vacated federal CAMR rule, improve visibility and help satisfy
Delaware’s regional haze obligations. For Conectiv Energy’s Edge Moor
coal-fired units, these multipollutant regulations establish stringent
short-term emission limits for emissions of NOx, SO2 and
mercury, and for Edge Moor’s residual oil-fired generating unit, impose more
stringent sulfur in fuel limits and establish stringent short-term emission
limits for NOx emissions. The regulations also cap annual emissions
of NOx and SO2 from Edge
Moor’s coal-fired and residual oil-fired units, and mercury from Edge Moor’s
coal-fired units. Compliance with the regulations will require the
installation of new pollution control equipment and/or the enhancement of
existing equipment, and may require the imposition of restrictions on the
operation of those units. Conectiv Energy submitted a compliance plan
for its facilities to DNREC in June 2007. Conectiv Energy estimates
that it will cost up to $80 million to install the control equipment
necessary to comply with the regulations. These estimated costs do
not include increased costs associated with operating control
equipment. In December 2006, Conectiv Energy filed a complaint
with the Delaware Superior Court seeking review of DNREC’s adoption of the
regulations. The appeal is pending.
In a March 2005 rulemaking, EPA removed
coal- and oil-fired units from the list of source categories requiring Maximum
Achievable Control Technology for hazardous air pollutants such as mercury and
nickel under CAA Section 112, thus, for the time being, eliminating the
possibility that control devices would be required under this section of the CAA
to reduce nickel emissions from the oil-fired unit at Conectiv Energy’s Edge
Moor generating
facility. In
the decision issued on February 8, 2008, the U.S. Court of Appeals for the
District of Columbia Circuit determined that the delisting of coal- and
oil-fired units from regulation under CAA Section 112 was unlawful.
Delaware, Maryland and New Jersey
(along with Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island,
Vermont and New York) are signatories to the Regional Greenhouse Gas Initiative
(RGGI). Under RGGI, each of the participating states has committed to
the adoption of legislation or regulations designed to stabilize and eventually
reduce emissions of carbon dioxide CO2 emissions,
including the implementation of a regional CO2 budget and
allowance trading program to regulate emissions from fossil fuel-fired power
plants. The regulations implementing this program are expected to
require fossil fuel-fired electric generating units commencing in 2009 to hold
CO2
allowances equivalent to their historic baseline CO2 emissions
and to reduce CO2 emissions
incrementally beginning in 2015 to achieve an overall 10% reduction from
baseline by 2019. Each state is permitted to adopt its own
regulations and can develop its own allowance allocation/auction
mechanisms. Until Delaware, Maryland and New Jersey adopt
regulations, PHI will not be in a position to determine whether the allowances
allocated to the generating facilities operated by its subsidiaries will be
sufficient to cover the CO2 emissions
from those facilities, the financial impact of acquiring allowances through
auction, or the potential financial and operational consequences of the
regulations.
In February 2007, the New Jersey
Governor signed an Executive Order which requires New Jersey to reduce its
greenhouse gas emissions to 1990 levels by 2020, and to 80% below 2006 levels by
2050. The Executive Order requires NJDEP to coordinate with NJBPU,
New Jersey’s Department of Transportation, New Jersey’s Department of Community
Affairs and other interested parties to evaluate policies and measures that will
enable New Jersey to achieve the greenhouse gas emissions reduction levels set
forth in the Executive Order. In July 2007, New Jersey enacted
legislation requiring NJDEP to promulgate regulations by July 1, 2009 that
establish a greenhouse gas emissions monitoring and reporting program to
evaluate progress toward the 2020 and 2050 greenhouse gas limits. In
January 2008, New Jersey enacted legislation requiring the NJDEP to develop
regulations for a trading program for CO2 allowances
to be created under RGGI. Regulatory actions in Delaware and Maryland
implementing CO2
regulations are expected in 2008.
Water
Quality Regulation
Provisions of the federal Water
Pollution Control Act, also known as the Clean Water Act (CWA), 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 CWA 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. All of
the steam generating facilities operated by PHI’s subsidiaries have NPDES
permits authorizing their pollutant discharges which are subject to periodic
renewal.
In July 2004, EPA issued final
regulations under Section 316(b) of the CWA that are intended to minimize
potential adverse environmental impacts from power plant cooling water intake
structures on aquatic resources by establishing performance-based standards for
the
operation
of these structures at large existing electric generating plants, including
Conectiv Energy’s Deepwater and Edge Moor generating
facilities. These regulations may require changes to cooling water
intake structures as part of the NPDES permit renewal process. In
January 2007, the U.S. Court of Appeals for the Second Circuit issued a decision
in Riverkeeper, Inc. v. United
States Environmental Protection Agency (commonly known as the Riverkeeper II decision),
that remanded to EPA for additional rulemaking substantial portions of these
regulations for large existing electric generating plants. EPA has
not yet initiated the additional rulemaking. Petitions for review of
the Riverkeeper II
decision have been filed with the U.S. Supreme Court by various interested
parties. The Supreme Court has not yet determined whether it will
hear the appeal. The capital expenditures, if any, that may be needed
as a consequence of these regulations will not be known until these proceedings
are concluded and until each affected facility completes additional studies and
addresses related permit requirements.
EPA has delegated authority to
administer the NPDES program to a number of state agencies including
DNREC. The NPDES permit for Conectiv Energy’s Edge Moor generating
facility expired on October 30, 2003, but has been administratively extended
until DNREC issues a renewal permit. Conectiv Energy submitted a
renewal application to the DNREC in April 2003. Studies required
under the existing permit to determine the impact on aquatic organisms of the
plant’s cooling water intake structures were completed in
2002. Site-specific alternative technologies and operational measures
have been evaluated and discussed with DNREC. DNREC, however, has not
announced how it intends to address Section 316(b) requirements in the renewal
NPDES permit in light of Riverkeeper II and the remand
of substantial portions of the federal regulations
Under the New Jersey Water Pollution
Control Act, NJDEP implements regulations, administers the New Jersey Pollutant
Discharge Elimination System (NJPDES) program with EPA oversight, and issues and
enforces NJPDES permits. In June 2007, Conectiv Energy filed a timely
application for renewal of the NJPDES permit for the Deepwater generating
facility. Timely filing of the application for renewal
administratively extended the existing permit. The previous NJPDES
permit for Deepwater required that Conectiv Energy perform several studies to
determine whether or not Deepwater’s cooling water intake structures satisfy
applicable requirements for protection of the environment. While
those study requirements were consistent with requirements under EPA’s
regulations implementing CWA Section 316(b), the result of the Riverkeeper II decision may
require reevaluation of the design and operational measures that Conectiv Energy
anticipated using for future compliance with Section 316(b) at
Deepwater. In view of the uncertainty associated with Riverkeeper II, Conectiv
Energy asked NJDEP to modify or stay a cooling water intake structure design
upgrade requirement in Deepwater’s NJPDES permit, and NJDEP agreed to stay that
permit requirement.
Pepco and a subsidiary of Pepco Energy
Services discharge water from a steam generating plant and service center
located in the District of Columbia under a NPDES permit issued by EPA in
November 2000. Pepco filed a petition with EPA’s Environmental
Appeals Board seeking review and reconsideration of certain provisions of EPA’s
permit determination. In May 2001, Pepco and EPA reached a settlement
on Pepco’s petition, under which EPA withdrew certain contested provisions and
agreed to issue a revised draft permit for public comment. EPA has
not yet issued the revised draft permit. A timely renewal application
was filed in May 2005 and the companies are operating under the November 2000
permit, excluding the withdrawn conditions, in accordance with the settlement
agreement.
On November 5, 2007, NJDEP adopted
amendments to its regulations under the Flood Hazard Area Control Act
(FHACA) to minimize
damage to life and property from flooding caused by development in flood
plains. The amended regulations impose a new regulatory program to
mitigate flooding and related environmental impacts from a broad range of
construction and development activities, including electric utility transmission
and distribution construction that was previously unregulated under the FHACA
and that is otherwise regulated under a number of other state and federal
programs. ACE is evaluating whether to appeal the adoption of these
regulations to the Appellate Division of the Superior Court of New
Jersey. PHI cannot predict at this time the costs of complying with
the FHACA regulations due, among other things, to the possibility that NJDEP
will issue exemptions from the new regulations.
In September 2007, NJDEP proposed
amendments to the agency’s regulations under the Freshwater Wetlands Protection
Act (FWPA). PHI believes that these proposed amendments may hinder
development of electric transmission and distribution systems by increasing the
regulatory obstacles necessary to site public service
infrastructure. On December 31, 2007, ACE filed comments concerning
the proposed amendments, urging NJDEP not to change the manner in which the FWPA
regulations presently apply to utility lines, poles, and other utility
property. An accurate estimate of PHI’s compliance costs is not
feasible until the regulations are adopted.
In 2002, EPA amended its oil pollution
prevention regulations to require facilities, that because of their location
could reasonably be expected to discharge oil in quantities that may be harmful
to the environment, to amend and implement Spill Prevention, Control, and
Countermeasure (SPCC) Plans and Facility Response Plans (FRPs) by February
2003. Since 2002, EPA has provided a number of extensions to the
compliance deadline. As a result of those extensions, PHI facilities
subject to the regulations must now comply with these regulatory requirements by
July 1, 2009. PHI has undertaken an analysis of its facilities to
identify equipment/sites for which physical modifications are necessary to
reduce the risk of a release of oil and comply with EPA’s SPCC and FRP
regulations. Physical modification of facilities through the
construction of containment structures or replacement of oil-filled equipment
with non-oil-filled equipment is scheduled from 2008 through 2010 with an
anticipated cost of approximately $56 million.
Hazardous
Substance Regulation
The Comprehensive Environmental
Response, Compensation, and Liability Act of 1980 (CERCLA), authorizes EPA, and
comparable state laws authorize state environmental authorities, to issue orders
and bring enforcement actions to compel responsible parties to investigate and
take remedial actions at any site that is determined to present an actual or
potential threat to human health or the environment because of an actual or
threatened release of one or more hazardous substances. Parties that
generated or transported hazardous substances to such sites, as well as the
owners and operators of such sites, may be deemed liable under CERCLA or
comparable state laws. Pepco, DPL and ACE each has been named by EPA
or a state environmental agency as a potentially responsible party at certain
contaminated sites. See Note (12), Commitments and Contingencies --
Legal Proceedings -- Environmental Litigation” to the consolidated financial
statements of PHI included in Item 8. In addition, DPL and ACE
have undertaken efforts to remediate currently or formerly owned facilities
found to be contaminated, including two former manufactured gas plant sites and
other owned property. See Note (12), Commitments and Contingencies --
Legal Proceedings -- Environmental Litigation” to the consolidated financial
statements of PHI included in Item 8 and Item 7 “Management’s
Discussion
and Analysis of Financial Condition and Results of Operations -- Capital
Resources and Liquidity -- Capital Requirements -- Environmental Remediation
Obligations.”
Item
1A. RISK
FACTORS
The businesses of PHI, Pepco, DPL and
ACE 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 companies, including, depending on the circumstances, its financial
condition, results of operations and cash flows. Unless otherwise
noted, each risk factor set forth below applies to each of PHI, Pepco, DPL and
ACE.
PHI
and its subsidiaries are subject to substantial governmental regulation, and
unfavorable regulatory treatment could have a negative effect.
PHI’s Power Delivery businesses are
subject to regulation by various federal, state and local regulatory agencies
that significantly affects their operations. Each of Pepco, DPL and
ACE is regulated by state regulatory agencies in its service territories, with
respect to, among other things, the rates it can charge retail customers for the
supply and distribution of electricity (and additionally for DPL the supply and
distribution of natural gas). In addition, the rates that the
companies can charge for electricity transmission are regulated by FERC, and
DPL’s natural gas transportation is regulated by FERC. The companies
cannot change supply, distribution, or transmission rates without approval by
the applicable regulatory authority. While the approved distribution
and transmission rates are intended to permit the companies to recover their
costs of service and earn a reasonable rate of return, the profitability of the
companies is affected by the rates they are able to charge. In
addition, if the costs incurred by any of the companies in operating its
transmission and distribution facilities exceed the allowed amounts for costs
included in the approved rates, the financial results of that company, and
correspondingly, PHI, will be adversely affected.
PHI’s subsidiaries also are required to
have numerous permits, approvals and certificates from governmental agencies
that regulate their businesses. 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; however, none of the companies is able to predict the impact of future
regulatory activities of any of these agencies 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.
Pepco
may be required to make additional divestiture proceeds gain-sharing payments to
customers in the District of Columbia and Maryland. (PHI and Pepco
only)
Pepco currently is involved in
regulatory proceedings in Maryland and the District of Columbia related to the
sharing of the net proceeds from the sale of its generation-related
assets. The principal issue in the proceedings is whether Pepco
should be required to share with customers the excess deferred income taxes and
accumulated deferred investment tax credits associated with the sold assets and,
if so, whether such sharing would violate the normalization provisions of the
Internal Revenue Code and its implementing regulations. Depending on
the
outcome
of the proceedings, Pepco could be required to make additional gain-sharing
payments to customers and payments to the Internal Revenue Service (IRS) in the
amount of the associated accumulated deferred investment tax credits, and Pepco
might be unable to use accelerated depreciation on District of Columbia and
Maryland allocated or assigned property. See Item 7 “PHI --
Management’s Discussion and Analysis of Financial Condition and Results of
Operations -- Regulatory and Other Matters -- Divestiture Cases” for additional
information.
The
operating results of the Power Delivery business and the Competitive Energy
businesses fluctuate on a seasonal basis and can be adversely affected by
changes in weather.
The Power Delivery business is seasonal
and weather patterns can have a material impact on their 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
has generated less revenue and income when temperatures are warmer than normal
in the winter and cooler than normal in the summer. In Maryland,
however, the decoupling of distribution revenue for a given reporting period,
from the amount of power delivered during the period as the result of the
adoption by the MPSC of a bill stabilization adjustment mechanism for retail
customers, has had the effect of eliminating changes in customer usage due to
weather conditions or for other reasons as a factor having an impact on reported
revenue and income.
Historically, the competitive energy
operations of Conectiv Energy and Pepco Energy Services also have produced less
revenue when weather conditions are milder than normal, which can negatively
impact PHI’s income from these operations. The Competitive Energy
businesses’ energy management services generally are not seasonal.
Facilities
may not operate as planned or may require significant maintenance expenditures,
which could decrease revenues or increase expenses.
Operation of the Pepco, DPL and ACE
transmission and distribution facilities and the Competitive Energy businesses’
generation facilities involves many risks, including the breakdown or failure of
equipment, accidents, labor disputes 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 keep them operating at peak
efficiency, to comply with changing environmental requirements, or to provide
reliable operations. Natural disasters and weather-related incidents,
including tornadoes, hurricanes and snow and ice storms, also can disrupt
generation, transmission and distribution delivery systems. Operation
of generation, transmission and distribution facilities below expected capacity
levels can reduce revenues and result in the incurrence of additional expenses
that may not be recoverable from customers or through insurance, including
deficiency charges imposed by PJM on generation facilities at a rate up to two
times the capacity payment price which the generation facility
receives. Furthermore, if the company owning the facilities is unable
to perform its contractual obligations for any of these reasons, that company,
and correspondingly PHI, may incur penalties or damages.
The
transmission facilities of the Power Delivery business are interconnected with
the facilities of other transmission facility owners whose actions could have a
negative impact on operations.
The electricity transmission facilities
of Pepco, DPL and ACE are directly interconnected with the transmission
facilities of contiguous utilities and, as such, are part of an interstate power
transmission grid. FERC has designated a number of regional
transmission organizations to coordinate the operation of portions of the
interstate transmission grid. Pepco, DPL and ACE are members of the
PJM RTO. In 1997, FERC approved PJM as the sole provider of
transmission service in the PJM RTO region, which today consists 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. Pepco, DPL and ACE operate their transmission
facilities under the direction and control of PJM. PJM RTO and the
other regional transmission organizations have established sophisticated systems
that are designed to ensure the reliability of the operation of transmission
facilities and prevent the operations of one utility from having an adverse
impact on the operations of the other utilities. However, the systems
put in place by PJM RTO and the other regional transmission organizations may
not always be adequate to prevent problems at other utilities from causing
service interruptions in the transmission facilities of Pepco, DPL or
ACE. If any of Pepco, DPL or ACE were to suffer such a service
interruption, it could have a negative impact on it and on PHI.
The
cost of compliance with environmental laws, including laws relating to emissions
of greenhouse gases, is significant and new environmental laws may increase
expenses.
The operations of PHI’s subsidiaries,
including Pepco, DPL and ACE, are subject to extensive federal, state and local
environmental statutes, rules and regulations relating to air quality, water
quality, spill prevention, waste management, natural resources, site
remediation, and health and safety. These laws and regulations can
require significant capital and other expenditures to, among other things, meet
emissions standards, conduct site remediation 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 come into
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.
There is growing concern at the federal
and state levels about CO2 and other
greenhouse gas emissions. As a result, it is possible that state and
federal regulations will be developed that will impose more stringent
limitations on emissions than are currently in effect. Any of these factors
could result in increased capital expenditures and/or operating costs for one or
more generating plants operated by PHI’s Conectiv Energy and Pepco Energy
Services businesses. Until specific regulations are promulgated, the
impact that any new environmental regulations, voluntary compliance guidelines,
enforcement initiatives, or legislation may have on the results of operations,
financial position or liquidity of PHI and its subsidiaries is not
determinable.
PHI, Pepco, DPL and ACE each continues
to monitor federal and state activity related to environmental matters in order
to analyze their potential operational and cost implications.
New environmental laws and regulations,
or new interpretations of existing laws and regulations, could impose more
stringent limitations on the operations of PHI’s subsidiaries or require them to
incur significant additional costs. Current compliance strategies may
not successfully address the relevant standards and interpretations of the
future.
Failure
to retain and attract key skilled professional and technical employees could
have an adverse effect on the operations.
The ability of each of PHI and its
subsidiaries, including Pepco, DPL and ACE, to implement its business strategy
is dependent on its ability to recruit, retain and motivate employees.
Competition for skilled employees in some areas is high and the inability
to retain and attract these employees could adversely affect the company’s
business, operations and financial condition.
PHI’s
Competitive Energy businesses are highly competitive. (PHI
only)
The unregulated energy generation,
supply and marketing businesses primarily in the mid-Atlantic region are
characterized by intense competition at both the wholesale and retail
levels. PHI’s Competitive Energy businesses compete with numerous
non-utility generators, independent power producers, wholesale and retail energy
marketers, and traditional utilities. This competition generally has
the effect of reducing margins and requires a continual focus on controlling
costs.
PHI’s
Competitive Energy businesses rely on some generation, transmission, storage,
and distribution assets that they do not own or control to deliver wholesale and
retail electricity and natural gas and to obtain fuel for their generation
facilities. (PHI only)
PHI’s Competitive Energy businesses
depend upon electric generation and transmission facilities, natural gas
pipelines, and natural gas storage facilities owned and operated by
others. The operation of their generation facilities also depends
upon coal, natural gas or diesel fuel supplied by others. If electric
generation or transmission, natural gas pipelines, or natural gas storage are
disrupted or capacity is inadequate or unavailable, the Competitive Energy
businesses’ ability to buy and receive and/or sell and deliver wholesale and
retail power and natural gas, and therefore to fulfill their contractual
obligations, could be adversely affected. Similarly, if the fuel
supply to one or more of their generation plants is disrupted and storage or
other alternative sources of supply are not available, the Competitive Energy
businesses’ ability to operate their generating facilities could be adversely
affected.
Changes
in technology may adversely affect the Power Delivery business and PHI’s
Competitive Energy businesses.
Research and development activities are
ongoing to improve alternative technologies to produce electricity, including
fuel cells, micro turbines and photovoltaic (solar) cells. It is
possible that advances in these or other alternative technologies will reduce
the costs of electricity production from these technologies, thereby making the
generating facilities of PHI’s Competitive Energy businesses less
competitive. In addition, increased conservation efforts and advances
in technology could reduce demand for electricity supply and distribution, which
could
adversely
affect the Power Delivery businesses of Pepco, DPL and ACE and PHI’s Competitive
Energy businesses. Changes in technology also could alter the channels through
which retail electric customers buy electricity, which could adversely affect
the Power Delivery businesses of Pepco, DPL and ACE.
PHI’s
risk management procedures may not prevent losses in the operation of its
Competitive Energy businesses. (PHI only)
The operations of PHI’s Competitive
Energy businesses are conducted in accordance with sophisticated risk management
systems that are designed to quantify risk. However, actual results
sometimes deviate from modeled expectations. In particular, risks in
PHI’s energy activities are measured and monitored utilizing value-at-risk
models to determine the effects of potential one-day favorable or unfavorable
price movements. These estimates are based on historical price
volatility and assume a normal distribution of price changes and a 95%
probability of occurrence. Consequently, if prices significantly
deviate from historical prices, PHI’s risk management systems, including
assumptions supporting risk limits, may not protect PHI from significant
losses. In addition, adverse changes in energy prices may result in
economic losses in PHI’s earnings and cash flows and reductions in the value of
assets on its balance sheet under applicable accounting rules.
The
commodity hedging procedures used by PHI’s Competitive Energy businesses may not
protect them from significant losses caused by volatile commodity
prices. (PHI only)
To lower the financial exposure related
to commodity price fluctuations, PHI’s Competitive Energy businesses routinely
enter into contracts to hedge the value of their assets and operations. As part
of this strategy, PHI’s Competitive Energy businesses utilize fixed-price,
forward, physical purchase and sales contracts, tolling agreements, futures,
financial swaps and option contracts traded in the over-the-counter markets or
on exchanges. Each of these various hedge instruments can present a
unique set of risks in its application to PHI’s energy assets. PHI
must apply judgment in determining the application and effectiveness of each
hedge instrument. Changes in accounting rules, or revised
interpretations to existing rules, may cause hedges to be deemed ineffective as
an accounting matter. This could have material earnings implications
for the period or periods in question. Conectiv Energy’s objective is
to hedge a portion of the expected power output of its generation facilities and
the costs of fuel used to operate those facilities so it is not completely
exposed to energy price movements. Hedge targets are approved by
PHI’s Corporate Risk Management Committee and may change from time to time based
on market conditions. Conectiv Energy generally establishes hedge
targets annually for the next three succeeding 12-month
periods. Within a given 12-month horizon, the actual hedged
positioning in any month may be outside of the targeted range, even if the
average for a 12-month period falls within the stated
range. Management exercises judgment in determining which months
present the most significant risk, or opportunity, and hedge levels are adjusted
accordingly. Since energy markets can move significantly in a short
period of time, hedge levels may also be adjusted to reflect revised
assumptions. Such factors may include, but are not limited to,
changes in projected plant output, revisions to fuel requirements, transmission
constraints, prices of alternate fuels, and improving or deteriorating supply
and demand conditions. In addition, short-term occurrences, such as
abnormal weather, operational events, or intra-month commodity price volatility
may also cause the actual level of hedging coverage to vary from the established
hedge targets. These events can cause fluctuations in PHI’s earnings
from period to period. Due to the high heat rate of the Pepco Energy
Services generating
facilities,
Pepco Energy Services generally does not enter into wholesale contracts to lock
in the forward value of its plants. To the extent that PHI’s
Competitive Energy businesses have unhedged positions or their hedging
procedures do not work as planned, fluctuating commodity prices could result in
significant losses. Conversely, by engaging in hedging activities,
PHI may not realize gains that otherwise could result from fluctuating commodity
prices.
Business
operations could be adversely affected by terrorism.
The threat of, or actual acts of,
terrorism may affect the operations of PHI or any of its subsidiaries in
unpredictable ways and may cause changes in the insurance markets, force an
increase in security measures and cause disruptions of fuel supplies and
markets. If any of its infrastructure facilities, such as its
electric generation, fuel storage, 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. Corresponding instability in the financial markets as a
result of terrorism also could adversely affect the ability to raise needed
capital.
Insurance
coverage may not be sufficient to cover all casualty 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. 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, if any,
received will be sufficient to cover the entire cost of replacement or
repair.
Revenues,
profits and cash flows may be adversely affected by economic
conditions.
Periods of slowed economic activity
generally result in decreased demand for power, particularly by industrial and
large commercial customers. As a consequence, recessions or other
downturns in the economy may result in decreased revenues and cash flows for the
Power Delivery businesses of Pepco, DPL and ACE and PHI’s Competitive Energy
businesses.
The
IRS challenge to cross-border energy sale and lease-back transactions entered
into by a PHI subsidiary could result in loss of prior and future tax
benefits. (PHI only)
PCI maintains a portfolio of
cross-border energy sale-leaseback transactions, which as of December 31, 2007,
had a book value of approximately $1.4 billion and from which PHI currently
derives approximately $60 million per year in tax benefits in the form of
interest and depreciation deductions. On February 11, 2005, the
Treasury Department and IRS issued a notice informing taxpayers that the IRS
intends to challenge the tax benefits claimed by taxpayers with respect to
certain of these transactions.
As part of the normal PHI tax audit for
2001 and 2002, the IRS disallowed the tax benefits claimed by PHI with respect
to these leases for those years. The tax benefits claimed by PHI with
respect to these leases from 2001 through December 31, 2007 were approximately
$347 million. PHI has filed a protest against the IRS adjustments and the
unresolved audit has been forwarded to the IRS Appeals Office. If the
IRS prevails, PHI would be subject to
additional
taxes, along with interest and possibly penalties on the additional taxes, which
could have a material adverse effect on PHI’s results of operations and cash
flows. See Item 7 “Management’s Discussion and Analysis of Financial
Condition and Results of Operations -- Regulatory and Other Matters -- Federal
Tax Treatment of Cross-Border Leases” for additional information.
Changes
in tax law could have a material adverse effect on the tax benefits that PHI
realizes from the portfolio of cross-border energy sale-leaseback transactions
entered into by one of its subsidiaries.
In recent years, efforts have been made
by members of the U.S. Senate to pass legislation that would have the effect of
deferring the deduction of losses associated with leveraged lease transactions
involving tax-indifferent parties for taxable years beginning after the year of
enactment regardless of when the transaction was entered into. These
proposals, which would affect transactions such as those included in PCI’s
portfolio of cross-border energy leases, would effectively defer the deduction
of losses associated with such leveraged lease transactions until the taxable
year in which the taxpayer recognized taxable income from the lease, which is
typically toward the end of the lease term. To date, no such
legislation has been enacted; however, there are continuing efforts by members
of the U.S. Senate to add legislation to various Senate bills directed to the
deferral or other curtailment of the tax benefits realized from such
transactions. Enactment of legislation of this nature could result in
a material delay of the income tax benefits that PHI would receive in connection
with PCI’s portfolio of cross-border energy leases. Furthermore, if legislation
of this type were enacted, under the Financial Accounting Standards Board Staff
Position on Financial Accounting Standard 13-2, PHI would be required to adjust
the book value of the leases and record a charge to earnings equal to the
repricing impact of the deferred deductions which could result in a material
adverse effect on PHI’s financial condition, results of operations and cash
flows.
IRS
Revenue Ruling 2005-53 on Mixed Service Costs could require PHI to incur
additional tax and interest payments in connection with the IRS audit of this
issue for the tax years 2001 through 2004 (IRS Revenue Ruling
2005-53).
During 2001, Pepco, DPL and ACE changed
their methods of accounting with respect to capitalizable construction costs for
income tax purposes. The change allowed the companies to accelerate
the deduction of certain expenses that were previously capitalized and
depreciated. Through December 31, 2005, these accelerated deductions
generated incremental tax cash flow benefits of approximately $205 million
(consisting of $94 million for Pepco, $62 million for DPL and $49 million for
ACE) for the companies, primarily attributable to their 2001 tax
returns.
In 2005, the Treasury Department issued
proposed regulations that, if adopted in their current form, would require
Pepco, DPL and ACE to change their method of accounting with respect to
capitalizable construction costs for income tax purposes for future tax periods
beginning in 2005. Based on the proposed regulations, PHI in its 2005
federal tax return adopted an alternative method of accounting for capitalizable
construction costs that management believes will be acceptable to the
IRS.
At the same time as the proposed
regulations were released, the IRS issued Revenue Ruling 2005-53, which is
intended to limit the ability of certain taxpayers to utilize the method of
accounting for income tax purposes they utilized on their tax returns for 2004
and prior years
with
respect to capitalizable construction costs. In line with this
Revenue Ruling, the IRS revenue agent’s report for the 2001 and 2002 tax returns
disallowed substantially all of the incremental tax benefits that Pepco, DPL and
ACE had claimed on those returns by requiring the companies to capitalize and
depreciate certain expenses rather than treat such expenses as current
deductions. PHI has filed a protest against the IRS adjustments and
the issue is among the unresolved audit matters relating to the 2001 and 2002
audits pending before the Appeals Office.
In February 2006, PHI paid
approximately $121 million of taxes to cover the amount of additional taxes and
interest that management estimated to be payable for the years 2001 through 2004
based on the method of tax accounting that PHI, pursuant to the proposed
regulations, adopted on its 2005 tax return. However, if the IRS is
successful in requiring Pepco, DPL and ACE to capitalize and depreciate
construction costs that result in a tax and interest assessment greater than
management’s estimate of $121 million, PHI will be required to pay additional
taxes and interest only to the extent these adjustments exceed the $121 million
payment made in February 2006.
PHI
and its subsidiaries are dependent on their ability to successfully access
capital markets. An inability to access capital may adversely affect
their businesses.
PHI, Pepco, DPL and ACE each rely on
access to both short-term money markets and longer-term capital markets as a
source of liquidity and to satisfy their capital requirements not satisfied by
the cash flow from their operations. Capital market disruptions, or a downgrade
in credit ratings, would increase the cost of borrowing or could adversely
affect the ability to access one or more financial markets. In addition, a
reduction in PHI’s credit ratings could require PHI or its subsidiaries to post
additional collateral in connection with some of the Competitive Energy
businesses’ wholesale marketing and financing activities. Disruptions
to the capital markets could include, but are not limited to:
|
|
·
|
recession
or an economic slowdown;
|
|
|
·
|
the
bankruptcy of one or more energy
companies;
|
|
|
·
|
significant
increases in the prices for oil or other
fuel;
|
|
|
·
|
a
terrorist attack or threatened attacks;
or
|
|
|
·
|
a
significant transmission failure.
|
In accordance with the requirements of
the Sarbanes-Oxley Act of 2002 and the SEC rules thereunder, PHI’s management is
responsible for establishing and maintaining internal control over financial
reporting and is required to assess annually the effectiveness of these
controls. The inability to certify the effectiveness of these
controls due to the identification of one or more material weaknesses in these
controls also could increase financing costs or could adversely affect the
ability to access one or more financial markets.
Future
defined benefit plan funding obligations are affected by assumptions regarding
the valuation of PHI’s benefit obligations and the performance of plan assets;
actual experience which varies from the assumptions could result in an
obligation of PHI, Pepco, DPL or ACE to make significant unplanned cash
contributions to the Retirement Plan.
PHI follows the guidance of SFAS No.
87, “Employers’ Accounting for Pensions” in accounting for pension benefits
under its non-contributory defined benefit plan (the PHI Retirement
Plan). In addition, on December 31, 2006, PHI implemented SFAS No.
158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement
Plans, an amendment of FASB Statements No. 87, 88, 106 and 132(R)” (SFAS No.
158) which requires that companies recognize a net liability or asset to report
the funded status of their defined benefit pension and other postretirement
benefit plans on the balance sheet. In accordance with these
accounting standards, PHI makes assumptions regarding the valuation of benefit
obligations and the performance of plan assets. Changes in
assumptions, such as the use of a different discount rate or expected return on
plan assets, affect the calculation of projected benefit obligations (PBO),
accumulated benefit obligation (ABO), reported pension liability, regulated
assets, or accumulated other comprehensive income on PHI’s consolidated balance
sheet and on the balance sheets of Pepco, DPL and ACE, and reported annual net
periodic pension benefit cost on PHI’s consolidated statement of earnings and on
the statements of earnings of Pepco, DPL and ACE.
Use of alternative assumptions could
also impact the expected future cash funding requirements of PHI, Pepco, DPL and
ACE for the PHI Retirement Plan if the plan did not meet the minimum funding
requirements of the Employment Retirement Income Security Act of 1974
(ERISA).
PHI’s
cash flow, ability to pay dividends and ability to satisfy debt obligations
depend on the performance of its operating subsidiaries. PHI’s
unsecured obligations are effectively subordinated to the liabilities and the
outstanding preferred stock of its subsidiaries. (PHI
only)
PHI is a holding company that conducts
its operations entirely through its 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 the
subsidiaries and the distribution of such earnings to PHI in the form of
dividends. The subsidiaries are separate and distinct 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. Because the claims of the creditors of PHI’s subsidiaries
and the preferred stockholders of ACE 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 and to
the rights of the holders of ACE’s preferred stock to receive dividend
payments.
Energy
companies are subject to adverse publicity which makes them vulnerable to
negative regulatory and litigation outcomes.
The energy sector has been among the
sectors of the economy that have been the subject of highly publicized
allegations of misconduct in recent years. In addition, many utility
companies have been publicly criticized for their performance during natural
disasters and
weather
related incidents. Adverse publicity of this nature may render
legislatures, regulatory authorities, and other 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 adverse outcomes
with respect to decisions by such bodies.
Provisions
of the Delaware General Corporation Law may discourage an acquisition of
PHI. (PHI only)
As a Delaware corporation, PHI is
subject to the business combination law set forth in Section 203 of the Delaware
General Corporation Law, which could have the effect of delaying, discouraging
or preventing an acquisition of PHI.
Because
Pepco is a wholly owned subsidiary of PHI, and each of DPL and ACE are indirect
wholly owned subsidiaries of PHI, PHI can exercise substantial control over
their dividend policies and businesses and operations. (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 Pepco’s, DPL’s and ACE’s
executive officers, are officers of PHI or an affiliate of PHI. Among
other decisions, each of Pepco’s, DPL’s and ACE’s board 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 the company’s respective
earnings, cash flow and capital structure, but may also take into account the
business plans and financial requirements of PHI and its other
subsidiaries.
Item
1B. UNRESOLVED STAFF
COMMENTS
Pepco
Holdings
Pepco
DPL
ACE
Item
2. PROPERTIES
Generation
Facilities
The following table identifies the
electric generating facilities owned by PHI’s subsidiaries at December 31,
2007.
|
Electric Generating
Facilities
|
Location
|
Owner
|
Generating
Capacity
|
|
Coal-Fired
Units
|
|
|
(kilowatts)
|
|
|
Edge
Moor Units 3 and 4
|
Wilmington,
DE
|
Conectiv
Energya
|
260,000
|
|
|
Deepwater
Unit 6
|
Pennsville,
NJ
|
Conectiv
Energya
|
80,000
|
|
|
|
|
|
340,000
|
|
Oil Fired
Units
|
|
|
|
|
|
Benning
Road
|
Washington,
DC
|
Pepco
Energy Servicesb
|
550,000
|
|
|
Edge
Moor Unit 5
|
Wilmington,
DE
|
Conectiv
Energya
|
450,000
|
|
|
Deepwater
Unit 1
|
Pennsville,
NJ
|
Conectiv
Energya
|
86,000
|
|
|
|
1,086,000
|
|
Combustion
Turbines/Combined Cycle Units
|
|
|
|
|
Hay
Road Units 1-4
|
Wilmington,
DE
|
Conectiv
Energya
|
552,000
|
|
|
Hay
Road Units 5-8
|
Wilmington,
DE
|
Conectiv
Energya
|
545,000
|
|
|
Bethlehem
Units 1-8
|
Bethlehem,
PA
|
Conectiv
Energya
|
1,092,000
|
|
|
Buzzard
Point
|
Washington,
DC
|
Pepco
Energy Servicesb
|
240,000
|
|
|
Cumberland
|
Millville,
NJ
|
Conectiv
Energya
|
84,000
|
|
|
Sherman
Avenue
|
Vineland,
NJ
|
Conectiv
Energya
|
81,000
|
|
|
Middle
|
Rio
Grande, NJ
|
Conectiv
Energya
|
77,000
|
|
|
Carll’s
Corner
|
Upper
Deerfield Twp., NJ
|
Conectiv
Energya
|
73,000
|
|
|
Cedar
|
Cedar
Run, NJ
|
Conectiv
Energya
|
68,000
|
|
|
Missouri
Avenue
|
Atlantic
City, NJ
|
Conectiv
Energya
|
60,000
|
|
|
Mickleton
|
Mickleton,
NJ
|
Conectiv
Energya
|
59,000
|
|
|
Christiana
|
Wilmington,
DE
|
Conectiv
Energya
|
45,000
|
|
|
Edge
Moor Unit 10
|
Wilmington,
DE
|
Conectiv
Energya
|
13,000
|
|
|
West
|
Marshallton,
DE
|
Conectiv
Energya
|
15,000
|
|
|
Delaware
City
|
Delaware
City, DE
|
Conectiv
Energya
|
16,000
|
|
|
Tasley
|
Tasley,
VA
|
Conectiv
Energya
|
26,000
|
|
|
|
|
|
3,046,000
|
|
Landfill Gas-Fired
Units
|
|
|
|
|
|
Fauquier
Landfill Project
|
Fauquier
County, VA
|
Pepco
Energy Servicesc
|
2,000
|
|
|
Eastern
Landfill Project
|
Baltimore
County, MD
|
Pepco
Energy Servicesd
|
3,000
|
|
|
|
|
|
5,000
|
|
Diesel
Units
|
|
|
|
|
|
Crisfield
|
Crisfield,
MD
|
Conectiv
Energya
|
10,000
|
|
|
Bayview
|
Bayview,
VA
|
Conectiv
Energya
|
12,000
|
|
|
|
|
|
22,000
|
|
Total
Electric Generating Capacity
|
4,499,000
|
| |
|
|
a
|
All
holdings of Conectiv Energy are owned by its various
subsidiaries.
|
|
b
|
These
facilities are owned by a subsidiary of Pepco Energy
Services. In 2007, a 16 MW combustion turbine at Buzzard Point
was deactivated.
|
|
c
|
This
facility is owned by Fauquier Landfill Gas, LLC, of which Pepco Energy
Services holds a 75% membership
interest.
|
|
d
|
This
facility is owned by Eastern Landfill Gas, LLC, of which Pepco Energy
Services holds a 75% membership
interest.
|
The preceding table sets forth the
summer electric generating capacity of the electric generating plants owned by
Pepco Holdings’ subsidiaries. Although the generating capacity of
these facilities may be higher during the winter months, the plants operated by
PHI’s subsidiaries 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 plants.
Transmission and
Distribution Systems
On a combined basis, the electric
transmission and distribution systems owned by Pepco, DPL and ACE at December
31, 2007 consisted of approximately 3,600 transmission circuit miles of overhead
lines, 160 transmission circuit miles of underground cables, 22,740 distribution
circuit miles of overhead lines, and 19,030 distribution circuit miles of
underground cables, primarily in their respective service
territories. On January 2, 2008, DPL completed the sale of
substantially all of its electric business in Virginia, which included
approximately 94.5 transmission circuit miles of overhead lines, .3 transmission
circuit miles of underground cables, 534 distribution circuit miles of overhead
lines and 291 distribution circuit miles of underground cables. See
“Business - Power Delivery - DPL” in Item 1 of this Form 10-K. 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 Maryland. The
computer equipment and systems contained in Pepco’s control center are financed
through a sale and leaseback transaction.
DPL has a liquefied natural gas plant
located in Wilmington, Delaware, with a storage capacity of 3.045 million
gallons and an emergency sendout capability of 48,210 Mcf per
day. DPL owns eight natural gas city gate stations at various
locations in New Castle County, Delaware. These stations have a total
sendout capacity of 225,000 Mcf per day. DPL also owns approximately
111 pipeline miles of natural gas transmission mains, 1,777 pipeline miles of
natural gas distribution mains, and 1,292 natural gas pipeline miles of service
lines. The natural gas transmission mains include 7.2 miles of
pipeline of which DPL owns 10%, which is used for natural gas operations, and of
which Conectiv Energy owns 90%, which is used for delivery of natural gas to
electric generation 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 (7) “Debt” to the
consolidated financial statements of PHI included in Item 8.
Item
3. LEGAL
PROCEEDINGS
Pepco
Holdings
Other than ordinary routine litigation
incidental to its and its subsidiaries’ business, PHI is not a party to, and its
and its subsidiaries’ property is not subject to, any material pending legal
proceedings except as described in Note (12), “Commitments and
Contingencies--Legal Proceedings,” to the consolidated financial statements of
PHI included in Item 8.
Pepco
Other than ordinary routine 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
(10), “Commitments and Contingencies--Legal Proceedings,” to the financial
statements of Pepco included in Item 8.
DPL
Other than ordinary routine 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
(11),
“Commitments and Contingencies--Legal Proceedings,” to the financial statements
of DPL included in Item 8.
ACE
Other than ordinary routine 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 (11), “Commitments and Contingencies--Legal Proceedings,” to the
financial statements of ACE included in Item 8.
Item
4. SUBMISSION OF MATTERS TO A
VOTE OF SECURITY HOLDERS
Pepco
Holdings
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.
Part II
|
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 fiscal years.
|
Period
|
|
Dividends
Per
Share
|
|
|
Price
Range
|
|
| |
|
|
|
|
High
|
|
|
Low
|
|
|
2007:
|
|
|
|
|
|
|
|
|
|
|
First
Quarter
|
|
$ |
.26 |
|
|
$ |
29.28 |
|
|
$ |
24.89 |
|
|
Second
Quarter
|
|
|
.26 |
|
|
|
30.71 |
|
|
|
26.89 |
|
|
Third
Quarter
|
|
|
.26 |
|
|
|
29.28 |
|
|
|
24.20 |
|
|
Fourth
Quarter
|
|
|
.26 |
|
|
|
30.10 |
|
|
|
25.73 |
|
|
|
|
$ |
1.04 |
|
|
|
|
|
|
|
|
|
|
2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First
Quarter
|
|
$ |
.26 |
|
|
$ |
24.28 |
|
|
$ |
22.15 |
|
|
Second
Quarter
|
|
|
.26 |
|
|
|
23.92 |
|
|
|
21.79 |
|
|
Third
Quarter
|
|
|
.26 |
|
|
|
25.50 |
|
|
|
22.64 |
|
|
Fourth
Quarter
|
|
|
.26 |
|
|
|
26.99 |
|
|
|
24.25 |
|
|
|
|
$ |
1.04 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See Item 7. “Management’s Discussion
and Analysis of Financial Condition and Results of Operations -- Capital
Resources and Liquidity -- Capital Requirements -- Dividends” for information
regarding restrictions on the ability of PHI and its subsidiaries to pay
dividends.
At December 31, 2007, there were
approximately 64,126 holders of record of Pepco Holdings common
stock.
Dividends
PHI Subsidiaries
All of the common equity of Pepco, DPL
and ACE is owned directly or indirectly by PHI. Pepco, DPL and ACE
each customarily pays dividends on its common stock on a quarterly basis based
on its earnings, cash flow and capital structure, and after taking into account
the business plans and financial requirements of PHI and its other
subsidiaries.
All of Pepco’s common stock is held by
Pepco Holdings. The table below presents the aggregate amount of
common stock dividends paid by Pepco to PHI during each quarter in the last two
fiscal years.
|
|
|
Aggregate
Dividends
|
|
2007:
|
|
|
|
First
Quarter
|
$
|
15,000,000
|
|
Second
Quarter
|
|
14,000,000
|
|
Third
Quarter
|
|
45,000,000
|
|
Fourth
Quarter
|
|
12,000,000
|
|
|
$
|
86,000,000
|
|
2006:
|
|
|
|
First
Quarter
|
$
|
15,000,000
|
|
Second
Quarter
|
|
49,000,000
|
|
Third
Quarter
|
|
-
|
|
Fourth
Quarter
|
|
35,000,000
|
|
|
$
|
99,000,000
|
|
|
|
|
All of DPL’s common stock is held by
Conectiv. The table below presents the aggregate amount of common
stock dividends paid by DPL to Conectiv during each quarter in the last two
fiscal years.
|
Period
|
|
Aggregate
Dividends
|
|
2007:
|
|
|
|
First
Quarter
|
$
|
8,000,000
|
|
Second
Quarter
|
|
19,000,000
|
|
Third
Quarter
|
|
-
|
|
Fourth
Quarter
|
|
12,000,000
|
|
|
$
|
39,000,000
|
|
2006:
|
|
|
|
First
Quarter
|
$
|
15,000,000
|
|
Second
Quarter
|
|
-
|
|
Third
Quarter
|
|
-
|
|
Fourth
Quarter
|
|
-
|
|
|
$
|
15,000,000
|
|
|
|
|
All of ACE’s common stock is held by
Conectiv. The table below presents the aggregate amount of common
stock dividends paid by ACE to Conectiv during each quarter in the last two
fiscal years.
|
Period
|
|
Aggregate
Dividends
|
|
2007:
|
|
|
|
First
Quarter
|
$
|
20,000,000
|
|
Second
Quarter
|
|
10,000,000
|
|
Third
Quarter
|
|
20,000,000
|
|
Fourth
Quarter
|
|
-
|
|
|
$
|
50,000,000
|
|
2006:
|
|
|
|
First
Quarter
|
$
|
19,000,000
|
|
Second
Quarter
|
|
-
|
|
Third
Quarter
|
|
75,000,000
|
|
Fourth
Quarter
|
|
15,000,000
|
|
|
$
|
109,000,000
|
|
|
|
|
Recent
Sales of Unregistered Equity Securities
Pepco
Holdings
Pepco
DPL
ACE
Purchases
of Equity Securities by the Issuer and Affiliated Purchasers.
Pepco
Holdings
Pepco
DPL
ACE
Item
6. SELECTED FINANCIAL
DATA
PEPCO
HOLDINGS CONSOLIDATED FINANCIAL HIGHLIGHTS
|
|
|
2007
|
|
|
|
2006
|
|
|
|
2005
|
|
|
|
2004
|
|
|
|
2003
|
|
|
|
|
|
(in
millions, except per share data)
|
|
Consolidated Operating
Results
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Operating Revenue
|
|
$ |
9,366.4 |
|
|
|
$ |
8,362.9 |
|
|
|
$ |
8,065.5 |
|
|
|
$ |
7,223.1 |
|
|
|
$ |
7,268.7 |
|
|
|
Total
Operating Expenses
|
|
|
8,559.8
|
|
(a)
|
|
|
7,669.6 |
|
(c)
|
|
|
7,160.1 |
|
(e)
(f) (g)
|
|
|
6,451.0 |
|
|
|
|
6,658.0 |
|
(j)
(k)
|
|
Operating
Income
|
|
|
806.6
|
|
|
|
|
693.3 |
|
|
|
|
905.4 |
|
|
|
|
772.1 |
|
|
|
|
610.7 |
|
|
|
Other
Expenses
|
|
|
284.2
|
|
|
|
|
282.4 |
|
(d)
|
|
|
285.5 |
|
|
|
|
341.4 |
|
|
|
|
433.3 |
|
(l)
|
|
Preferred
Stock Dividend
Requirements
of Subsidiaries
|
|
|
.3
|
|
|
|
|
1.2 |
|
|
|
|
2.5 |
|
|
|
|
2.8 |
|
|
|
|
13.9 |
|
|
|
Income
Before Income
Tax
Expense and
Extraordinary Item
|
|
|
522.1
|
|
|
|
|
409.7 |
|
|
|
|
617.4 |
|
|
|
|
427.9 |
|
|
|
|
163.5 |
|
|
|
Income
Tax Expense
|
|
|
187.9
|
|
(b)
|
|
|
161.4 |
|
|
|
|
255.2 |
|
(h)
|
|
|
167.3 |
|
(i)
|
|
|
62.1 |
|
|
|
Income
Before
Extraordinary Item
|
|
|
334.2
|
|
|
|
|
248.3 |
|
|
|
|
362.2 |
|
|
|
|
260.6 |
|
|
|
|
101.4 |
|
|
|
Extraordinary
Item
|
|
|
-
|
|
|
|
|
- |
|
|
|
|
9.0 |
|
|
|
|
- |
|
|
|
|
5.9 |
|
|
|
Net
Income
|
|
|
334.2
|
|
|
|
|
248.3 |
|
|
|
|
371.2 |
|
|
|
|
260.6 |
|
|
|
|
107.3 |
|
|
|
Redemption
Premium on Preferred
Stock
|
|
|
(.6 |
) |
|
|
|
(.8 |
) |
|
|
|
(.1 |
) |
|
|
|
.5 |
|
|
|
|
- |
|
|
|
Earnings
Available for
Common
Stock
|
|
|
333.6
|
|
|
|
|
247.5 |
|
|
|
|
371.1 |
|
|
|
|
261.1 |
|
|
|
|
107.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common Stock Information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
Earnings Per Share of Common
Stock
Before Extraordinary Item
|
|
$ |
1.72 |
|
|
|
$ |
1.30 |
|
|
|
$ |
1.91 |
|
|
|
$ |
1.48 |
|
|
|
$ |
.60 |
|
|
|
Basic
- Extraordinary Item Per
Share
of Common Stock
|
|
|
- |
|
|
|
|
- |
|
|
|
|
.05 |
|
|
|
|
- |
|
|
|
|
.03 |
|
|
|
Basic
Earnings Per Share of
Common Stock
|
|
|
1.72
|
|
|
|
|
1.30 |
|
|
|
|
1.96 |
|
|
|
|
1.48 |
|
|
|
|
.63 |
|
|
|
Diluted
Earnings Per Share of
Common Stock Before
Extraordinary
Item
|
|
|
1.72
|
|
|
|
|
1.30 |
|
|
|
|
1.91 |
|
|
|
|
1.48 |
|
|
|
|
.60 |
|
|
|
Diluted
- Extraordinary Item Per
Share
of Common Stock
|
|
|
-
|
|
|
|
|
- |
|
|
|
|
.05 |
|
|
|
|
- |
|
|
|
|
.03 |
|
|
|
Diluted
Earnings Per Share
of
Common Stock
|
|
|
1.72
|
|
|
|
|
1.30 |
|
|
|
|
1.96 |
|
|
|
|
1.48 |
|
|
|
|
.63 |
|
|
|
Cash
Dividends Per Share
of
Common Stock
|
|
|
1.04
|
|
|
|
|
1.04 |
|
|
|
|
1.00 |
|
|
|
|
1.00 |
|
|
|
|
1.00 |
|
|
|
Year-End
Stock Price
|
|
|
29.33
|
|
|
|
|
26.01 |
|
|
|
|
22.37 |
|
|
|
|
21.32 |
|
|
|
|
19.54 |
|
|
|
Net
Book Value per Common Share
|
|
|
20.04
|
|
|
|
|
18.82 |
|
|
|
|
18.88 |
|
|
|
|
17.74 |
|
|
|
|
17.31 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
Average Shares Outstanding
|
|
|
194.1
|
|
|
|
|
190.7 |
|
|
|
|
189.0 |
|
|
|
|
176.8 |
|
|
|
|
170.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
in Property, Plant
and
Equipment
|
|
$ |
12,306.5 |
|
|
|
$ |
11,819.7 |
|
|
|
$ |
11,441.0 |
|
|
|
$ |
11,109.4 |
|
|
|
$ |
10,815.2 |
|
|
|
Net
Investment in Property, Plant
and
Equipment
|
|
|
7,876.7
|
|
|
|
|
7,576.6 |
|
|
|
|
7,368.8 |
|
|
|
|
7,152.2 |
|
|
|
|
7,032.9 |
|
|
|
Total
Assets
|
|
|
15,111.0
|
|
|
|
|
14,243.5 |
|
|
|
|
14,038.9 |
|
|
|
|
13,374.6 |
|
|
|
|
13,390.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capitalization
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term
Debt
|
|
$ |
288.8 |
|
|
|
$ |
349.6 |
|
|
|
$ |
156.4 |
|
|
|
$ |
319.7 |
|
|
|
$ |
518.4 |
|
|
|
Long-term
Debt
|
|
|
4,174.8
|
|
|
|
|
3,768.6 |
|
|
|
|
4,202.9 |
|
|
|
|
4,362.1 |
|
|
|
|
4,588.9 |
|
|
|
Current
Maturities of Long-Term
Debt
and Project Funding
|
|
|
332.2
|
|
|
|
|
857.5 |
|
|
|
|
469.5 |
|
|
|
|
516.3 |
|
|
|
|
384.9 |
|
|
|
Transition
Bonds issued by ACE
Funding
|
|
|
433.5
|
|
|
|
|
464.4 |
|
|
|
|
494.3 |
|
|
|
|
523.3 |
|
|
|
|
551.3 |
|
|
|
Capital
Lease Obligations due
within one
year
|
|
|
6.0
|
|
|
|
|
5.5 |
|
|
|
|
5.3 |
|
|
|
|
4.9 |
|
|
|
|
4.4 |
|
|
|
Capital
Lease Obligations
|
|
|
105.4
|
|
|
|
|
111.1 |
|
|
|
|
116.6 |
|
|
|
|
122.1 |
|
|
|
|
126.8 |
|
|
|
Long-Term
Project Funding
|
|
|
20.9
|
|
|
|
|
23.3 |
|
|
|
|
25.5 |
|
|
|
|
65.3 |
|
|
|
|
68.6 |
|
|
|
Debentures
issued to Financing Trust
|
|
|
-
|
|
|
|
|
- |
|
|
|
|
- |
|
|
|
|
- |
|
|
|
|
98.0 |
|
|
|
Minority
Interest
|
|
|
6.2
|
|
|
|
|
24.4 |
|
|
|
|
45.9 |
|
|
|
|
54.9 |
|
|
|
|
108.2 |
|
|
|
Common
Shareholders’ Equity
|
|
|
4,018.4
|
|
|
|
|
3,612.2 |
|
|
|
|
3,584.1 |
|
|
|
|
3,339.0 |
|
|
|
|
2,974.1 |
|
|
|
Total
Capitalization
|
|
$ |
9,386.2 |
|
|
|
$ |
9,216.6 |
|
|
|
$ |
9,100.5 |
|
|
|
$ |
9,307.6 |
|
|
|
$ |
9,423.6 |
|
|
|
(a)
|
Includes
$33.4 million ($20.0 million after-tax) from settlement of Mirant
bankruptcy claims. See “Management’s Discussion and Analysis --
Financial Condition and Results of Operations -- Capital Resources and
Liquidity -- Cash Flow Activity -- Proceeds from Settlement of Mirant
Bankruptcy Claims.”
|
|
(b)
|
Includes
$19.5 million ($17.7 million net of fees) benefit related to Maryland
income tax settlement.
|
|
(c)
|
Includes
$18.9 million of impairment losses ($13.7 million after-tax) related to
certain energy services business assets.
|
|
(d)
|
Includes
$12.3 million gain ($7.9 million after-tax) on the sale of Conectiv
Energy’s equity interest in a joint venture which owns a wood burning
cogeneration facility.
|
|
(e)
|
Includes
$68.1 million ($40.7 million after-tax) gain from sale of non-utility land
owned by Pepco at Buzzard Point.
|
|
(f)
|
Includes
$70.5 million ($42.2 million after-tax) gain (net of customer sharing)
from settlement of Mirant bankruptcy claims. See “Management’s
Discussion and Analysis -- Financial Condition and Results of Operations
-- Capital Resources and Liquidity -- Cash Flow Activity -- Proceeds from
Settlement of Mirant Bankruptcy Claims.”
|
|
(g)
|
Includes
$13.3 million ($8.9 million after-tax) related to PCI’s liquidation of a
financial investment that was written off in 2001.
|
|
(h)
|
Includes
$10.9 million in income tax expense related to the mixed service cost
issue under IRS Revenue Ruling 2005-53.
|
|
(i)
|
Includes
a $19.7 million charge related to an IRS settlement. Also
includes $13.2 million tax benefit related to issuance of a local
jurisdiction’s final consolidated tax return
regulations.
|
|
(j)
|
Includes
a charge of $50.1 million ($29.5 million after-tax) related to a CT
contract cancellation. Also includes a gain of $68.8 million
($44.7 million after-tax) on the sale of the Edison Place office
building.
|
|
(k)
|
Includes
the unfavorable impact of $44.3 million ($26.6 million after-tax)
resulting from trading losses prior to the cessation of proprietary
trading.
|
|
(l)
|
Includes
an impairment charge of $102.6 million ($66.7 million after-tax) related
to prior investment in Starpower Communications,
L.L.C.
|
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. MANAGEMENT’S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF
OPERATIONS
The information required by this item
is contained herein, as follows:
|
Registrants
|
Page
No.
|
|
Pepco
Holdings
|
40
|
|
Pepco
|
107
|
|
DPL
|
117
|
|
ACE
|
127
|
THIS
PAGE LEFT INTENTIONALLY BLANK.
MANAGEMENT’S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF
OPERATIONS
PEPCO
HOLDINGS, INC.
GENERAL
OVERVIEW
In 2007, 2006 and 2005, respectively,
PHI’s Power Delivery operations produced 56%, 61%, and 58% of PHI’s consolidated
operating revenues (including revenues from intercompany transactions) and 66%,
67%, and 74% of PHI’s consolidated operating income (including income from
intercompany transactions).
The Power Delivery business consists
primarily of the transmission, distribution and default supply of electric
power, which for 2007, 2006, and 2005, was responsible for 94%, 95%, and 94%,
respectively, of Power Delivery’s operating revenues. The
distribution of natural gas contributed 6%, 5% and 6% of Power Delivery’s
operating revenues in 2007, 2006 and 2005, respectively. Power
Delivery represents one operating segment for financial reporting
purposes.
The Power Delivery business is
conducted by PHI’s three utility subsidiaries: Pepco, DPL and
ACE. Each of these companies is a regulated public utility in the
jurisdictions that comprise its service territory. Each company is
responsible for the delivery of electricity and, in the case of DPL, natural gas
in its service territory, for which it is paid tariff rates established by the
local public service commission. Each company 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 varies by
jurisdiction as follows:
|
|
Delaware
|
Provider
of Last Resort service (POLR) – before May 1, 2006
|
| |
|
Standard
Offer Service (SOS) – on and after May 1, 2006
|
| |
District
of Columbia |
SOS
|
| |
Maryland |
SOS
|
| |
New
Jersey |
Basic
Generation Service (BGS)
|
| |
Virginia |
Default
Service |
In this Form 10-K, these supply service
obligations are referred to generally as Default Electricity
Supply.
Pepco, DPL and ACE are also responsible
for the transmission of wholesale electricity into and across their service
territories. The rates each company is permitted to charge for the
wholesale transmission of electricity are regulated by the Federal Energy
Regulatory Commission (FERC). Transmission rates are updated annually
based on a FERC-approved formula methodology.
The profitability of the Power Delivery
business depends on its ability to recover costs and earn a reasonable return on
its capital investments through the rates it is permitted to
charge.
Power
Delivery’s operating results are seasonal, generally producing higher revenue
and income in the warmest and coldest periods of the year. Operating
results also can be affected by economic conditions, energy prices and the
impact of energy efficiency measures on customer usage of
electricity.
Effective June 16, 2007, the Maryland
Public Service Commission (MPSC) approved new electric service distribution base
rates for Pepco and DPL (the 2007 Maryland Rate Order). The MPSC also
approved a bill stabilization adjustment mechanism (BSA) for retail
customers. See “Regulatory and Other Matters – Rate
Proceedings.” For customers to which the BSA applies, Pepco and DPL
recognize distribution revenue based on an approved distribution charge per
customer. From a revenue recognition standpoint, the BSA thus
decouples the distribution revenue recognized in a reporting period from the
amount of power delivered during the period. This change in the
reporting of distribution revenue has the effect of eliminating changes in
customer usage (whether due to weather conditions, energy prices, energy
efficiency programs or other reasons) as a factor having an impact on reported
revenue. As a consequence, the only factors that will cause
distribution revenue to fluctuate from period to period are changes in the
number of customers and changes in the approved distribution charge per
customer.
The Competitive Energy business
provides competitive generation, marketing and supply of electricity and gas,
and related energy management services primarily in the mid-Atlantic region.
These operations are conducted through subsidiaries of Conectiv Energy Holding
Company (collectively, Conectiv Energy) and Pepco Energy Services, Inc. and its
subsidiaries (collectively, Pepco Energy Services), each of which is treated as
a separate operating segment for financial reporting purposes. For
the years ended December 31, 2007, 2006 and 2005, the operating revenues of
the Competitive Energy business (including revenue from intercompany
transactions) were equal to 48%, 43%, and 48%, respectively, of PHI’s
consolidated operating revenues, and the operating income of the Competitive
Energy business (including operating income from intercompany transactions) was
26%, 20%, and 16% of PHI’s consolidated operating income for the years ended
December 31, 2007, 2006 and 2005, respectively. For the years
ended December 31, 2007, 2006 and 2005, amounts equal to 10%, 13%, and 15%
respectively, of the operating revenues of the Competitive Energy business were
attributable to electric energy and capacity, and natural gas sold to the Power
Delivery segment.
|
|
·
|
Conectiv Energy provides
wholesale electric power, capacity and ancillary services in the wholesale
markets and also supplies electricity to other wholesale market
participants under long- and short-term bilateral
contracts. Conectiv Energy supplies electric power to Pepco,
DPL and ACE to satisfy a portion of their Default Electricity Supply load,
as well as default electricity supply load shares of other utilities
within PJM RTO and ISONE wholesale markets. PHI refers to these
activities as Merchant Generation & Load Service. Conectiv
Energy obtains the electricity required to meet its Merchant Generation
& Load Service power supply obligations from its own generation
plants, bilateral contract purchases from other wholesale market
participants, and purchases in the wholesale market. Conectiv
Energy also sells natural gas and fuel oil to very large end-users and to
wholesale market participants under bilateral agreements. PHI
refers to these sales operations as Energy
Marketing.
|
|
|
·
|
Pepco Energy Services
provides retail energy supply and energy services primarily to commercial,
industrial, and governmental customers. Pepco
Energy
|
|
|
Services
sells electricity and natural gas to customers primarily in the
mid-Atlantic region. Pepco Energy Services provides
energy-savings performance contracting services, owns and operates two
district energy systems, and designs, constructs and operates combined
heat and power and central energy plants. Pepco Energy Services
provides high voltage construction and maintenance services to customers
throughout the U.S. and low voltage electric construction and maintenance
services and streetlight asset management services in the Washington, D.C.
area and owns and operates electric generating plants in Washington,
D.C.
|
Conectiv Energy’s primary objective is
to maximize the value of its generation fleet by leveraging its operational and
fuel flexibilities. Pepco Energy Services’ primary objective is to
capture retail energy supply and service opportunities predominantly in the
mid-Atlantic region. The financial results of the Competitive Energy
business can be significantly affected by wholesale and retail energy prices,
the cost of fuel and gas to operate the Conectiv Energy plants, and the cost of
purchased energy necessary to meet its power and gas supply
obligations.
The Competitive Energy business, like
the Power Delivery business, is seasonal, and therefore weather patterns can
have a material impact on operating results.
Through its subsidiary Potomac Capital
Investment Corporation (PCI), PHI maintains a portfolio of cross-border energy
sale-leaseback transactions with a book value at December 31, 2007 of
approximately $1.4 billion. This activity constitutes a fourth
operating segment, which is designated as “Other Non-Regulated,” for financial
reporting purposes. For a discussion of PHI’s cross-border leasing
transactions, see “Regulatory and Other Matters -- Federal Income Tax Treatment
of Cross-Border Leases” in this Management’s Discussion and
Analysis.
BUSINESS
STRATEGY
PHI’s business strategy is to remain a
regional diversified energy delivery utility and competitive energy services
company focused on value creation and operational excellence. The
components of this strategy include:
|
|
·
|
Achieving
earnings growth in the Power Delivery business by focusing on
infrastructure investments and constructive regulatory outcomes, while
maintaining a high level of operational
excellence.
|
|
|
·
|
Supplementing
PHI’s utility earnings through competitive energy businesses that focus on
serving the competitive wholesale and retail markets primarily in PJM
RTO.
|
|
|
·
|
Pursuing
technologies and practices that promote energy efficiency, energy
conservation and the reduction of green house gas
emissions.
|
In furtherance of this business
strategy, PHI may from time to time examine a variety of transactions involving
its existing businesses, including the entry into joint ventures or the
disposition of one or more businesses, as well as possible
acquisitions. PHI also may reassess or refine the components of its
business strategy as it deems necessary or appropriate in response
to
a wide
variety of factors, including the requirements of its businesses, competitive
conditions and regulatory requirements.
EARNINGS
OVERVIEW
PHI’s net income for the year ended
December 31, 2007 was $334.2 million, or $1.72 per share, compared to $248.3
million, or $1.30 per share, for the year ended December 31, 2006.
Net income for the year ended December
31, 2007, included the credits set forth below, which are presented net of
federal and state income taxes and are in millions of dollars. The
operating segment that recognized the credits is also indicated.
|
·
|
Power
Delivery
|
|
|
|
Mirant
bankruptcy damage claims settlement
|
$ 20.0
|
|
|
Maryland
income tax settlement, net of fees
|
$ 17.7
|
Net income for year ended December 31,
2006, included the credits (charges) set forth below, which are presented net of
federal and state income taxes and are in millions of dollars. The
operating segment that recognized the credits (charges) is also
indicated.
|
·
|
Conectiv
Energy
|
|
|
|
|
Gain
on the disposition of assets associated with a
cogeneration
facility
|
$ 7.9
|
|
·
|
Pepco Energy
Services
|
|
|
|
|
Impairment
losses related to certain energy
services
business assets
|
$(13.7)
|
Excluding the items listed above for
the years ended December 31, net income would have been $296.5 million, or $1.53
per share, in 2007 and $254.1 million, or $1.33 per share, in 2006.
PHI’s net income for the years ended
December 31, 2007 and 2006, by operating segment, is set forth in the table
below (in millions of dollars):
|
|
|
2007
|
|
|
2006
|
|
|
Change
|
|
|
Power
Delivery
|
$
|
231.8
|
|
$
|
191.3
|
|
$
|
40.5
|
|
|
Conectiv
Energy
|
|
73.0
|
|
|
47.1
|
|
|
25.9
|
|
|
Pepco
Energy Services
|
|
38.4
|
|
|
20.6
|
|
|
17.8
|
|
|
Other
Non-Regulated
|
|
45.8
|
|
|
50.2
|
|
|
(4.4)
|
|
|
Corp.
& Other
|
|
(54.8)
|
|
|
(60.9)
|
|
|
6.1
|
|
|
Total
PHI Net Income
|
$
|
334.2
|
|
$
|
248.3
|
|
$
|
85.9
|
|
|
|
|
|
|
|
|
|
|
|
|
Discussion
of Operating Segment Net Income Variances:
Power Delivery’s $40.5 million increase
in earnings is primarily due to the following:
|
|
·
|
$20.0
million increase due to the recovery of operating expenses and certain
other costs associated with the Mirant Corporation (Mirant) bankruptcy
damage claims settlement.
|
|
|
·
|
$17.7
million increase due to the settlement of a Maryland income tax refund
claim relating to the divestiture of Pepco generation assets in 2000, net
of $1.8 million (after-tax) in professional
fees.
|
|
|
·
|
$24.2
million increase due to the impact of the Maryland distribution base rate
increases that became effective June 16, 2007 for Pepco and
DPL.
|
|
|
·
|
$27.5
million increase primarily due to higher distribution sales (favorable
impact of weather compared to
2006).
|
|
|
·
|
$28.4
million decrease due to higher operating and maintenance costs (primarily
electric system maintenance, various construction project write-offs
related to customer requested work, employee-related costs, regulatory
costs and increased bad debts expense). This variance does not include the
$1.8 million (after-tax) in professional fees associated with the Maryland
income tax refund settlement.
|
|
|
·
|
$13.7
million decrease primarily due to favorable income tax audit adjustments
in 2006.
|
|
|
·
|
$5.8
million decrease due to lower Default Electricity Supply margins primarily
as a result of customers electing to purchase electricity from competitive
suppliers and the impact of the Virginia Default Electricity Supply rate
cap.
|
Conectiv Energy’s $25.9 million
increase in earnings is primarily due to the following:
|
|
·
|
$40.8
million increase in Merchant Generation & Load Service primarily due
to: (i) an increase of approximately $45.3 million due to higher
generation output resulting from the favorable impact of weather and
improved availability at the Hay Road and Deepwater generating stations
and improved spark spreads, and (ii) an increase of approximately $15.3
million due to higher capacity prices due to the implementation of the PJM
Reliability Pricing Model; partially offset by (iii) a decrease of
approximately $19.8 million due to less favorable natural gas fuel hedges
and the expiration in 2006 of an agreement with an international
investment banking firm to hedge approximately 50% of the commodity price
risk of Conectiv Energy’s generation and Default Electricity Supply
commitment to DPL (see discussion under Conectiv Energy Gross Margin
below).
|
|
|
·
|
$7.9
million decrease due to the gain on disposition of assets associated with
a co-generation facility in 2006.
|
|
|
·
|
$6.4
million decrease due to higher plant maintenance
costs.
|
Pepco Energy Services’ $17.8 million
increase in earnings is primarily due to the following:
|
|
·
|
$12.4
million increase due to higher impairment losses on certain energy
services business assets in 2006.
|
|
|
·
|
$2.1
million increase from its retail energy supply businesses resulting from
$11.6 million increase from its retail electric business due to higher
installed capacity prices, higher volumes and more favorable congestion
costs in 2007; partially offset by higher gains of $8.4 million on sale of
excess electricity supply in 2006, and a $1.1 million decrease from its
retail natural gas business due to higher cost of supply in 2007 (see
discussion under Pepco Energy Services
below).
|
Other Non-Regulated’s $4.4 million
decrease in earnings is primarily due to tax adjustments in 2006 that related to
periods prior to the acquisition of Conectiv by Pepco and Financial Accounting
Standards Board (FASB) Interpretation No. (FIN) 48 (FIN 48) impact in 2007;
partially offset by lower interest expense in 2007.
Corporate and Other’s $6.1 million
increase in earnings is primarily due to prior year tax audit adjustments (tax
benefits recorded by other segments and eliminated in consolidation through
Corporate and Other); partially offset by higher interest expense in
2007.
CONSOLIDATED
RESULTS OF OPERATIONS
The following results of operations
discussion compares the year ended December 31, 2007, to the year ended
December 31, 2006. All amounts in the tables (except sales and
customers) are in millions.
Operating
Revenue
A detail of the components of PHI’s
consolidated operating revenue is as follows:
|
|
|
|
|
|
|
2007
|
2006
|
Change
|
|
|
Power
Delivery
|
$ $
|
5,244.2
|
|
$
|
5,118.8
|
|
$
|
125.4
|
|
|
|
Conectiv
Energy
|
|
2,205.6
|
|
|
1,964.2
|
|
|
241.4
|
|
|
|
Pepco
Energy Services
|
|
2,309.1
|
|
|
1,668.9
|
|
|
640.2
|
|
|
|
Other
Non-Regulated
|
|
76.2
|
|
|
90.6
|
|
|
(14.4)
|
|
|
|
Corp.
& Other
|
|
(468.7)
|
|
|
(479.6)
|
|
|
10.9
|
|
|
|
Total
Operating Revenue
|
$ $
|
9,366.4
|
|
$
|
8,362.9
|
|
$
|
1,003.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table categorizes Power
Delivery’s operating revenue by type of revenue.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
2006
|
Change
|
|
|
Regulated
T&D Electric Revenue
|
$
$
|
1,631.8
|
|
$
$
|
1,533.2
|
|
$
$
|
98.6
|
|
|
|
Default
Supply Revenue
|
|
3,256.9
|
|
|
3,271.9
|
|
|
(15.0)
|
|
|
|
Other
Electric Revenue
|
|
64.2
|
|
|
58.3
|
|
|
5.9
|
|
|
|
Total
Electric Operating Revenue
|
|
4,952.9
|
|
|
4,863.4
|
|
|
89.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulated
Gas Revenue
|
|
211.3
|
|
|
204.8
|
|
|
6.5
|
|
|
|
Other
Gas Revenue
|
|
80.0
|
|
|
50.6
|
|
|
29.4
|
|
|
|
Total
Gas Operating Revenue
|
|
291.3
|
|
|
255.4
|
|
|
35.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Power Delivery Operating Revenue
|
$
$
|
5,244.2
|
|
$
$
|
5,118.8
|
|
$
$
|
125.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulated Transmission and Distribution
(T&D) Electric Revenue includes revenue from the transmission and the
delivery of electricity, including the delivery of Default Electricity Supply,
by PHI’s utility subsidiaries to customers within their service territories at
regulated rates.
Default Supply Revenue is the revenue
received for Default Electricity Supply. The costs related to Default
Electricity Supply are included in Fuel and Purchased Energy and Other Services
Cost of Sales. Default Supply Revenue also includes revenue from
transition bond charges and other restructuring related revenues.
Other Electric Revenue includes work
and services performed on behalf of customers, including other utilities, which
is 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 Gas Revenue consists of
revenues for on-system natural gas sales and the transportation of natural gas
for customers by DPL within its service territories at regulated
rates.
Other Gas Revenue consists of DPL’s
off-system natural gas sales and the release of excess system
capacity.
Electric Operating Revenue
|
Regulated
T&D Electric Revenue
|
|
|
|
|
|
2007
|
2006
|
Change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
$
$
|
606.0
|
|
$
$
|
575.7
|
|
$
$
|
30.3
|
|
|
|
Commercial
|
|
731.2
|
|
|
699.0
|
|
|
32.2
|
|
|
|
Industrial
|
|
27.4
|
|
|
28.6
|
|
|
(1.2)
|
|
|
|
Other
|
|
267.2
|
|
|
229.9
|
|
|
37.3
|
|
|
|
Total
Regulated T&D Electric Revenue
|
$
$
|
1,631.8
|
|
$
$
|
1,533.2
|
|
$
$
|
98.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Regulated T&D Electric
Revenue consists primarily of (i) transmission service revenue received by PHI’s
utility subsidiaries from PJM as transmission owners, (ii) revenue from the
resale of energy and capacity under power purchase agreements between Pepco
and
unaffiliated
third parties in the PJM RTO market, and (iii) either (a) a positive adjustment
equal to the amount by which revenue from Maryland retail distribution sales
falls short of the revenue that Pepco and DPL are entitled to earn based on the
distribution charge per customer approved in the 2007 Maryland Rate Order or (b)
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).
|
Regulated
T&D Electric Sales (GWh)
|
|
|
|
|
2007
|
2006
|
Change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
17,946
|
|
|
17,139
|
|
|
807
|
|
|
|
Commercial
|
|
29,398
|
|
|
28,638
|
|
|
760
|
|
|
|
Industrial
|
|
3,974
|
|
|
4,119
|
|
|
(145)
|
|
|
|
Total
Regulated T&D Electric Sales
|
|
51,318
|
|
|
49,896
|
|
|
1,422
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulated
T&D Electric Customers (in thousands)
|
|
|
|
|
2007
|
2006
|
Change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
1,622
|
|
|
1,605
|
|
|
17
|
|
|
|
Commercial
|
|
199
|
|
|
198
|
|
|
1
|
|
|
|
Industrial
|
|
2
|
|
|
2
|
|
|
-
|
|
|
|
Total
Regulated T&D Electric Customers
|
|
1,823
|
|
|
1,805
|
|
|
18
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The Pepco, DPL and ACE service
territories are located within a corridor extending from Washington, D.C. to
southern New Jersey. These service territories are economically
diverse and include key industries that contribute to the regional economic
base.
|
|
·
|
Commercial
activity in the region includes banking and other professional services,
government, insurance, real estate, strip malls, casinos, stand alone
construction, and tourism.
|
|
|
·
|
Industrial
activity in the region includes automotive, chemical, glass,
pharmaceutical, steel manufacturing, food processing, and oil
refining.
|
Regulated T&D Electric Revenue
increased by $98.6 million primarily due to the following: (i) $43.0 million
increase in sales due to higher weather-related sales (a 17% increase in Cooling
Degree Days and a 12% increase in Heating Degree Days), (ii) $28.8 million
increase in Other Regulated T&D Electric Revenue from the resale of energy
and capacity purchased under the power purchase agreement between
Panda-Brandywine, L.P. (Panda) and Pepco (the Panda PPA), (offset in Fuel and
Purchased Energy and Other Services Cost of Sales), (iii) $20.3 million increase
due to a 2007 Maryland Rate Order that became effective in June 2007, which
includes a positive $4.9 million Revenue Decoupling Adjustment, (iv) $12.1
million increase due to higher pass-through revenue primarily resulting from tax
rate increases in the District of Columbia (offset primarily in Other Taxes),
(v) $5.2 million increase due to customer growth of 1% in 2007, partially offset
by (vi) $10.0 million decrease due to a change in Delaware rate structure
effective May 1, 2006, which shifted revenue from Regulated T&D Electric
Revenue to Default Supply Revenue, and (vii) $4.0 million decrease due to a
Delaware base rate reduction effective May 1, 2006.
Default Electricity Supply
|
Default
Supply Revenue
|
|
|
|
|
|
2007
|
2006
|
Change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
$
$
|
1,816.4
|
|
$
$
|
1,482.9
|
|
$
$
|
333.5
|
|
|
|
Commercial
|
|
1,061.8
|
|
|
1,352.6
|
|
|
(290.8)
|
|
|
|
Industrial
|
|
92.1
|
|
|
108.2
|
|
|
(16.1)
|
|
|
|
Other
|
|
286.6
|
|
|
328.2
|
|
|
(41.6)
|
|
|
|
Total
Default Supply Revenue
|
$
$
|
3,256.9
|
|
$
$
|
3,271.9
|
|
$
$
|
(15.0)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Default Supply Revenue consists
primarily of revenue from the resale of energy and capacity under non-utility
generating contracts between ACE and unaffiliated third parties (NUGs) in the
PJM RTO market.
|
Default
Electricity Supply Sales (GWh)
|
|
|
|
|
|
2007
|
2006
|
Change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
17,469
|
|
|
16,698
|
|
|
771
|
|
|
|
Commercial
|
|
9,910
|
|
|
14,799
|
|
|
(4,889)
|
|
|
|
Industrial
|
|
914
|
|
|
1,379
|
|
|
(465)
|
|
|
|
Other
|
|
131
|
|
|
129
|
|
|
2
|
|
|
|
Total
Default Electricity Supply Sales
|
|
28,424
|
|
|
33,005
|
|
|
(4,581)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Default
Electricity Supply Customers (in thousands)
|
|
|
|
|
2007
|
2006
|
Change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
1,585
|
|
|
1,575
|
|
|
10
|
|
|
|
Commercial
|
|
166
|
|
|
170
|
|
|
(4)
|
|
|
|
Industrial
|
|
1
|
|
|
1
|
|
|
-
|
|
|
|
Other
|
|
2
|
|
|
2
|
|
|
-
|
|
|
|
Total
Default Electricity Supply Customers
|
|
1,754
|
|
|
1,748
|
|
|
6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Default Supply Revenue, which is
partially offset in Fuel and Purchased Energy and Other Services Cost of Sales,
decreased by $15.0 million primarily due to the following: (i) $345.5
million decrease primarily due to commercial and industrial customers electing
to purchase an increased amount of electricity from competitive suppliers, (ii)
$94.8 million decrease due to differences in consumption among the various
customer rate classes, (iii) $46.3 million decrease in wholesale energy revenue
primarily the result of the sales by ACE of its Keystone and Conemaugh interests
and the B.L. England generating facilities, (iv) $4.1 million decrease due to a
DPL adjustment to reclassify market-priced supply revenue from Regulated T&D
Electric Revenue in 2006, partially offset by (v) $379.1 million increase due to
annual increases in market-based Default Electricity Supply rates, (vi) $86.6
million increase due to higher weather-related sales (a 17% increase in Cooling
Degree Days and a 12% increase in Heating Degree Days), and (vii) $10.0 million
increase due to a change in Delaware rate structure effective May 1, 2006
that shifted revenue from Regulated T&D Electric Revenue to Default Supply
Revenue.
Other Electric Revenue increased $5.9
million to $64.2 million in 2007 from $58.3 million in 2006 primarily due to
increases in revenue related to pole rentals and late payment fees.
|
Regulated
Gas Revenue
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
Change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
$ |
124.0 |
|
|
$ |
116.2 |
|
|
$ |
7.8 |
|
|
Commercial
|
|
|
72.7 |
|
|
|
73.0 |
|
|
|
(.3 |
) |
|
Industrial
|
|
|
8.2 |
|
|
|
10.3 |
|
|
|
(2.1 |
) |
|
Transportation
and Other
|
|
|
6.4 |
|
|
|
5.3 |
|
|
|
1.1 |
|
|
Total
Regulated Gas Revenue
|
|
$ |
211.3 |
|
|
$ |
204.8 |
|
|
$ |
6.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulated
Gas Sales (Bcf)
|
|
|
|
|
|
2007
|
2006
|
Change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
7.9
|
|
|
6.6
|
|
|
1.3
|
|
|
|
Commercial
|
|
5.2
|
|
|
4.6
|
|
|
.6
|
|
|
|
Industrial
|
|
.8
|
|
|
.8
|
|
|
-
|
|
|
|
Transportation
and Other
|
|
6.8
|
|
|
6.3
|
|
|
.5
|
|
|
|
Total
Regulated Gas Sales
|
|
20.7
|
|
|
18.3
|
|
|
2.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulated
Gas Customers (in thousands)
|
|
|
|
|
|
2007
|
2006
|
Change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
112
|
|
|
112
|
|
|
-
|
|
|
|
Commercial
|
|
10
|
|
|
9
|
|
|
1
|
|
|
|
Industrial
|
|
-
|
|
|
-
|
|
|
-
|
|
|
|
Transportation
and Other
|
|
-
|
|
|
-
|
|
|
-
|
|
|
|
Total
Regulated Gas Customers
|
|
122
|
|
|
121
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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.
|
|
·
|
Commercial
activity in the region includes banking and other professional services,
government, insurance, real estate, strip malls, stand alone construction
and tourism.
|
|
|
·
|
Industrial
activity in the region includes automotive, chemical and
pharmaceutical.
|
Regulated Gas Revenue increased by $6.5
million primarily due to (i) $11.7 million increase due to colder weather (a 15%
increase in Heating Degree Days), (ii) $5.7 million increase due to base rate
increases effective in November 2006 and April 2007, (iii) $4.8
million
increase
due to differences in consumption among the various customer rate classes, (iv)
$2.7 million increase due to customer growth of 1% in 2007, partially offset by
(v) $18.4 million decrease due to Gas Cost Rate (GCR) decreases effective
November 2006, April 2007 and November 2007 resulting from lower natural gas
commodity costs (offset in Fuel and Purchased Energy and Other Services Cost of
Sales).
Other Gas Revenue increased by $29.4
million to $80.0 million in 2007 from $50.6 million in 2006 primarily due to
higher off-system sales (partially offset in Fuel and Purchased Energy and Other
Services Cost of Sales). The gas sold off-system resulted from
increased demand from unaffiliated third party electric generators during
periods of low customer demand for natural gas.
The impact of Operating Revenue changes
and Fuel and Purchased Energy and Other Services Cost of Sales changes with
respect to the Conectiv Energy component of the Competitive Energy business are
encompassed within the discussion that follows.
Operating Revenues of the Conectiv
Energy segment are derived primarily from the sale of
electricity. The primary components of its costs of sales are fuel
and purchased power. Because fuel and electricity prices tend to move
in tandem, price changes in these commodities from period to period can have a
significant impact on Operating Revenue and costs of sales without signifying
any change in the performance of the Conectiv Energy segment. For
this reason, PHI from a managerial standpoint focuses on gross margin as a
measure of performance.
Conectiv Energy Gross
Margin
Merchant Generation & Load Service
consists primarily of electric power, capacity and ancillary services sales from
Conectiv Energy’s generating plants; tolling arrangements entered into to sell
energy and other products from Conectiv Energy’s generating plants and to
purchase energy and other products from generating plants of other companies;
hedges of power, capacity, fuel and load; the sale of excess fuel (primarily
natural gas) and emission allowances; electric power, capacity, and ancillary
services sales pursuant to competitively bid contracts entered into with
affiliated and non-affiliated companies to fulfill their default electricity
supply obligations; and fuel switching activities made possible by the
multi-fuel capabilities of some of Conectiv Energy’s power plants.
Energy Marketing activities consist
primarily of wholesale natural gas and fuel oil marketing; the activities of the
short-term power desk, which generates margin by capturing price differences
between power pools and locational and timing differences within a power pool;
and prior to October 31, 2006, operating services under an agreement with
an unaffiliated generating plant. Beginning in 2007, power
origination activities, which primarily represent the fixed margin component of
structured power transactions such as default electricity supply contracts, have
been classified into Energy Marketing from Merchant Generation & Load
Service. The 2006 activity has been reclassified for comparative
purposes accordingly. Power origination contributed $18.8 million and
$18.7 million of gross margin for the years ended December 31, 2007 and
2006, respectively.
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
Operating Revenue ($
millions):
|
|
|
|
|
|
|
|
Merchant
Generation & Load Service
|
|
$ |
1,086.8 |
|
|
$ |
1,073.2 |
|
|
Energy
Marketing
|
|
|
1,118.8 |
|
|
|
891.0 |
|
|
Total
Operating Revenue1
|
|
$ |
2,205.6 |
|
|
$ |
1,964.2 |
|
|
|
|
|
|
|
|
|
|
|
|
Cost of Sales ($
millions):
|
|
|
|
|
|
|
|
|
|
Merchant
Generation & Load Service
|
|
$ |
805.8 |
|
|
$ |
861.3 |
|
|
Energy
Marketing
|
|
|
1,081.0 |
|
|
|
847.7 |
|
|
Total
Cost of Sales2
|
|
$ |
1,886.8 |
|
|
$ |
1,709.0 |
|
|
|
|
|
|
|
|
|
|
|
|
Gross Margin ($
millions):
|
|
|
|
|
|
|
|
|
|
Merchant
Generation & Load Service
|
|
$ |
281.0 |
|
|
$ |
211.9 |
|
|
Energy
Marketing
|
|
|
37.8 |
|
|
|
43.3 |
|
|
Total
Gross Margin
|
|
$ |
318.8 |
|
|
$ |
255.2 |
|
|
|
|
|
|
|
|
|
|
|
|
Generation Fuel and Purchased
Power Expenses ($ millions) 3:
|
|
|
|
|
|
|
|
|
|
Generation
Fuel Expenses 4,5
|
|
|
|
|
|
|
|
|
|
Natural
Gas6
|
|
$ |
267.8 |
|
|
$ |
174.5 |
|
|
Coal
|
|
|
62.4 |
|
|
|
53.4 |
|
|
Oil
|
|
|
33.8 |
|
|
|
26.6 |
|
|
Other7
|
|
|
2.2 |
|
|
|
4.1 |
|
|
Total
Generation Fuel Expenses
|
|
$ |
366.2 |
|
|
$ |
258.6 |
|
|
Purchased
Power Expenses 5
|
|
|
479.7 |
|
|
|
431.3 |
|
|
|
|
|
|
|
|
|
|
|
|
Statistics:
|
|
2007
|
|
|
2006
|
|
|
Generation
Output (MWh):
|
|
|
|
|
|
|
|
|
|
Base-Load
8
|
|
|
2,232,499 |
|
|
|
1,814,517 |
|
|
Mid-Merit
(Combined Cycle) 9
|
|
|
3,341,716 |
|
|
|
2,081,873 |
|
|
Mid-Merit
(Oil Fired) 10
|
|
|
190,253 |
|
|
|
115,120 |
|
|
Peaking
|
|
|
146,486 |
|
|
|
131,930 |
|
|
Tolled
Generation
|
|
|
160,755 |
|
|
|
94,064 |
|
|
Total
|
|
|
6,071,709 |
|
|
|
4,237,504 |
|
|
|
|
|
|
|
|
|
|
|
|
Load
Service Volume (MWh) 11
|
|
|
7,075,743 |
|
|
|
8,514,719 |
|
|
|
|
|
|
|
|
|
|
|
|
Average
Power Sales Price
12($/MWh):
|
|
|
|
|
|
|
|
|
|
Generation
Sales 4
|
|
$ |
82.19 |
|
|
$ |
77.69 |
|
|
Non-Generation
Sales 13
|
|
$ |
70.43 |
|
|
$ |
58.49 |
|
|
Total
|
|
$ |
74.34 |
|
|
$ |
62.54 |
|
|
|
|
|
|
|
|
|
|
|
|
Average
on-peak spot power price at PJM East Hub ($/MWh) 14
|
|
$ |
77.85 |
|
|
$ |
65.29 |
|
|
Average
around-the-clock spot power price at PJM East Hub ($/MWh) 14
|
|
$ |
63.92 |
|
|
$ |
53.07 |
|
|
Average
spot natural gas price at market area M3 ($/MMBtu)15
|
|
$ |
7.76 |
|
|
$ |
7.31 |
|
|
|
|
|
|
|
|
|
|
|
|
Weather
(degree days at Philadelphia Airport): 16
|
|
|
|
|
|
|
|
|
|
Heating
degree days
|
|
|
4,560 |
|
|
|
4,205 |
|
|
Cooling
degree days
|
|
|
1,513 |
|
|
|
1,136 |
|
|
1
|
Includes
$441.5 million and $471.1 million of affiliate transactions for 2007 and
2006, respectively. The 2006 amount has been reclassified to
exclude $193.1 million of intra-affiliate transactions that were reported
gross in 2006 at the segment level.
|
|
2
|
Includes
$6.7 million and $4.6 million of affiliate transactions for 2007 and 2006,
respectively. The 2006 amount has been reclassified to exclude
$193.1 million of intra-affiliate transactions that were reported gross in
2006 at the segment level. Also, excludes depreciation and
amortization expense of $37.7 million and $36.3 million,
respectively.
|
|
3
|
Consists
solely of Merchant Generation & Load Service expenses; does not
include the cost of fuel not consumed by the power plants and intercompany
tolling expenses.
|
|
4
|
Includes
tolled generation.
|
|
5
|
Includes
associated hedging gains and
losses.
|
|
6
|
Includes
adjusted 2006 amount related to change in natural gas hedge allocation
methodology.
|
|
7
|
Includes
emissions expenses, fuel additives, and other fuel-related
costs.
|
|
8
|
Edge
Moor Units 3 and 4 and Deepwater Unit
6.
|
|
9
|
Hay
Road and Bethlehem, all units.
|
|
10
|
Edge
Moor Unit 5 and Deepwater Unit 1. Generation output for these
units was negative for the first and fourth quarters of 2006 because of
station service consumption.
|
|
11
|
Consists
of all default electricity supply sales; does not include standard product
hedge volumes.
|
|
12
|
Calculated
from data reported in Conectiv Energy’s Electric Quarterly Report (EQR)
filed with the FERC; does not include capacity or ancillary services
revenue.
|
|
13
|
Consists
of default electricity supply sales, standard product power sales, and
spot power sales other than merchant generation as reported in Conectiv
Energy’s EQR.
|
|
15
|
Source: Average
delivered natural gas price at Tetco Zone M3 as published in Gas
Daily.
|
|
16
|
Source:
National Oceanic and Atmospheric Administration National Weather Service
data.
|
Merchant Generation & Load Service
gross margin increased $69.1 million primarily due to:
|
|
·
|
An
increase of approximately $76.5 million primarily due to 43% higher
generation output attributable to more favorable weather and improved
availability at the Hay Road and Deepwater generating plants and improved
spark spreads.
|
|
|
·
|
An
increase of approximately $25.9 million due to higher capacity prices due
to the implementation of the PJM Reliability Pricing
Model.
|
|
|
·
|
A
decrease of $33.4 million due to less favorable natural gas fuel hedges,
and the expiration, in 2006, of an agreement with an international
investment banking firm to hedge approximately 50% of the commodity price
risk of Conectiv Energy’s generation and Default Electricity Supply
commitment to DPL.
|
Energy Marketing gross margin decreased
$5.5 million primarily due to:
|
|
·
|
A
decrease of $5.2 million due to lower margins in oil
marketing.
|
|
|
·
|
A
decrease of $4.0 million due to lower margins in natural gas
marketing.
|
|
|
·
|
An
increase of $2.7 million for adjustments related to an unaffiliated
generation operating services agreement that expired in
2006.
|
Pepco Energy Services’ operating
revenue increased $640.2 million, which corresponds with the increase in Fuel
and Purchased Energy and Other Services Costs of Sales, to $2,309.1 million in
2007 from $1,668.9 million in 2006 primarily due to (i) increase of $646.0
million due to higher volumes of retail electric load served at higher prices in
2007 driven by customer acquisitions , (ii) increase of $27.4 million due to
higher volumes of wholesale natural gas sales in 2007 that resulted from
increased natural gas supply transactions to deliver gas to retail customers,
partially offset by (iii) decrease of $32.3 million due primarily to lower
construction activity in 2007 and to the sale of five construction businesses in
2006.
Other Non-Regulated operating revenue
decreased $14.4 million to $76.2 million in 2007 from $90.6 million in
2006. The operating revenue of this segment primarily consists of
lease earnings recognized under Statement of Financial Accounting Standards No.
13, “Accounting for Leases.” The revenue decrease is primarily due to
a change in state income tax lease assumptions that resulted in increased
revenue in 2006 as compared to 2007.
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:
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
Change
|
|
|
Power
Delivery
|
|
$ |
3,359.7 |
|
|
$ |
3,303.6 |
|
|
$ |
56.1 |
|
|
Conectiv
Energy
|
|
|
1,886.8 |
|
|
|
1,709.0 |
|
|
|
177.8 |
|
|
Pepco
Energy Services
|
|
|
2,161.7 |
|
|
|
1,531.1 |
|
|
|
630.6 |
|
|
Corp.
& Other
|
|
|
(464.9 |
) |
|
|
(477.8 |
) |
|
|
12.9 |
|
|
Total
|
|
$ |
6,943.3 |
|
|
$ |
6,065.9 |
|
|
$ |
877.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Power Delivery's Fuel and Purchased
Energy and Other Services Cost of Sales, which is primarily associated with
Default Electricity Supply sales, increased by $56.1 million primarily due to:
(i) $445.2 million increase in average energy costs, the result of new annual
Default Electricity Supply contracts, (ii) $93.0 million increase due to an
increase in weather-related sales, (iii) $28.8 million increase for energy and
capacity purchased under the Panda PPA (offset in T&D Electric Revenue),
partially offset by (iv) $472.2 million decrease primarily due to commercial and
industrial customers electing to purchase an increased amount of electricity
from competitive suppliers, and (v) $36.4 million decrease in the Default
Electricity Supply deferral balance. Fuel and Purchased Energy
expense is primarily offset in Default Supply Revenue, Regulated Gas Revenue or
Other Gas Revenue.
The impact of Fuel and Purchased Energy
and Other Services Cost of Sales changes with respect to the Conectiv Energy
component of the Competitive Energy business are encompassed within the prior
discussion under the heading “Conectiv Energy Gross Margin.”
Pepco Energy Services’ Fuel and
Purchased Energy and Other Services Cost of Sales increased $630.6 million
primarily due to (i) an increase of $635.7 million due to higher volumes of
purchased electricity at higher prices in 2007 to serve increased retail
customer load (ii) an increase of $39.9 million due to higher volumes of
wholesale natural gas sales in 2007 that resulted from increased natural gas
supply transactions to deliver gas to retail customers, partially offset by
(iii) a decrease of $44.6 million due primarily to lower construction activity
in 2007 and to the sale of five construction businesses in 2006.
Other Operation and
Maintenance
A detail of PHI’s other operation and
maintenance expense is as follows:
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
Change
|
|
|
Power
Delivery
|
|
$ |
667.0 |
|
|
$ |
639.6 |
|
|
$ |
27.4 |
|
|
Conectiv
Energy
|
|
|
127.2 |
|
|
|
116.3 |
|
|
|
10.9 |
|
|
Pepco
Energy Services
|
|
|
73.6 |
|
|
|
67.6 |
|
|
|
6.0 |
|
|
Other
Non-Regulated
|
|
|
3.5 |
|
|
|
4.2 |
|
|
|
(.7 |
) |
|
Corp.
& Other
|
|
|
(13.8 |
) |
|
|
(20.4 |
) |
|
|
6.6 |
|
|
Total
|
|
$ |
857.5 |
|
|
$ |
807.3 |
|
|
$ |
50.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Operation and Maintenance expense
of the Power Delivery segment increased by $27.4 million; however, excluding the
favorable variance of $34.2 million primarily resulting from ACE's sale of the
B.L. England electric generating facility in February 2007, Other Operation and
Maintenance expenses increased by $61.6 million. The $61.6 million
increase was primarily due to (i) $15.7 million increase in employee-related
costs, (ii) $10.6 million increase in preventative maintenance and system
operation costs, (iii) $6.8 million increase in customer service operation
expenses, (iv) $4.4 million increase in costs associated with Default
Electricity Supply (primarily deferred and recoverable), (v) $3.5 million
increase in regulatory expenses, (vi) $3.5 million increase in accounting
service expenses, (vii) $3.4 million increase due to various construction
project write-offs related to customer requested work, (viii) $3.1 million
increase in Demand Side Management program costs (offset in Deferred Electric
Service Costs), and (ix) $2.8 million increase due to higher bad debt
expenses.
Other Operation and Maintenance expense
for Conectiv Energy increased by $10.9 million primarily due to higher
plant maintenance costs due to more scheduled outages in 2007 and higher costs
of materials and labor.
Other Operation and Maintenance expense
for Pepco Energy Services increased by $6.0 million due to higher retail
electric and gas operating costs to support the growth in the retail business in
2007.
Other Operation and Maintenance expense
for Corporate & Other increased by $6.6 million due to increased
employee-related costs.
Depreciation and
Amortization
Depreciation and Amortization
expenses decreased by $47.3 million to $365.9 million in 2007 from $413.2
million in 2006. The decrease is primarily due to (i) $31.1 million
decrease in ACE’s regulatory asset amortization resulting primarily from the
2006 sale of ACE’s interests in Keystone and Conemaugh, and (ii) $19.1 million
decrease in depreciation due to a change in depreciation rates in accordance
with the 2007 Maryland Rate Order.
Other Taxes increased by $14.1 million
to $357.1 million in 2007 from $343.0 million in 2006. The increase
was primarily due to increased pass-throughs resulting from tax rate increases
(partially offset in Regulated T&D Electric Revenue).
Deferred Electric Service
Costs
Deferred Electric Service Costs, which
relate only to ACE, increased by $46.0 million to $68.1 million in 2007 from
$22.1 million in 2006. The increase is primarily due to (i) $37.5
million net over-recovery associated with non-utility generation contracts
between ACE and unaffiliated third parties, (ii) $11.7 million net over-recovery
associated with BGS energy costs, partially offset by (iii) $3.2 million net
under-recovery associated with Demand Side Management program
costs.
During 2007, Pepco Holdings recorded
pre-tax impairment losses of $2.0 million ($1.3 million after-tax) related to
certain energy services business assets owned by Pepco Energy
Services. During 2006, Pepco Holdings recorded pre-tax impairment
losses of $18.9 million ($13.7 million after-tax) related to certain energy
services business assets owned by Pepco Energy Services.
Effect of Settlement of Mirant
Bankruptcy Claims
The Effect of Settlement of Mirant
Bankruptcy Claims reflects the recovery of $33.4 million in operating expenses
and certain other costs as damages in the Mirant bankruptcy
settlement. See “Capital Resources and Liquidity -- Cash Flow
Activity -- Proceeds from Settlement of Mirant Bankruptcy Claims.”
Income
Tax Expense
PHI’s effective tax rates for the years
ended December 31, 2007 and 2006 were 36.0% and 39.3%, respectively. The 3.3%
decrease in the effective tax rate in 2007 was primarily the result of a 2007
Maryland state income tax refund. The refund was due to an increase
in the tax basis of certain assets sold in 2000, and as a result, PHI’s 2007
income tax expense was reduced by $19.5 million with a corresponding decrease to
the effective tax rate of 3.7%.
The following results of operations
discussion compares the year ended December 31, 2006, to the year ended
December 31, 2005. All amounts in the tables (except sales and
customers) are in millions.
Operating
Revenue
A detail of the components of PHI’s
consolidated operating revenue is as follows:
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
Change
|
|
|
Power
Delivery
|
|
$ |
5,118.8 |
|
|
$ |
4,702.9 |
|
|
$ |
415.9 |
|
|
Conectiv
Energy
|
|
|
1,964.2 |
|
|
|
2,393.1 |
|
|
|
(428.9 |
) |
|
Pepco
Energy Services
|
|
|
1,668.9 |
|
|
|
1,487.5 |
|
|
|
181.4 |
|
|
Other
Non-Regulated
|
|
|
90.6 |
|
|
|
84.5 |
|
|
|
6.1 |
|
|
Corp.
& Other
|
|
|
(479.6 |
) |
|
|
(602.5 |
) |
|
|
122.9 |
|
|
Total
Operating Revenue
|
|
$ |
8,362.9 |
|
|
$ |
8,065.5 |
|
|
$ |
297.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table categorizes Power
Delivery’s operating revenue by type of revenue.
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
Change
|
|
|
Regulated
T&D Electric Revenue
|
|
$ |
1,533.2 |
|
|
$ |
1,623.2 |
|
|
$ |
(90.0 |
) |
|
Default
Supply Revenue
|
|
|
3,271.9 |
|
|
|
2,753.0 |
|
|
|
518.9 |
|
|
Other
Electric Revenue
|
|
|
58.3 |
|
|
|
65.2 |
|
|
|
(6.9 |
) |
|
Total
Electric Operating Revenue
|
|
|
4,863.4 |
|
|
|
4,441.4 |
|
|
|
422.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulated
Gas Revenue
|
|
|
204.8 |
|
|
|
198.7 |
|
|
|
6.1 |
|
|
Other
Gas Revenue
|
|
|
50.6 |
|
|
|
62.8 |
|
|
|
(12.2 |
) |
|
Total
Gas Operating Revenue
|
|
|
255.4 |
|
|
|
261.5 |
|
|
|
(6.1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Power Delivery Operating Revenue
|
|
$ |
5,118.8 |
|
|
$ |
4,702.9 |
|
|
$ |
415.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulated T&D Electric Revenue
includes revenue from the transmission and the delivery of electricity,
including the delivery of Default Electricity Supply, by PHI’s utility
subsidiaries to customers within their service territories at regulated
rates.
Default Supply Revenue is the revenue
received for Default Electricity Supply. The costs related to Default
Electricity Supply are included in Fuel and Purchased Energy and Other Services
Cost of Sales. Default Supply Revenue also includes revenue from
transition bond charges and other restructuring related revenues.
Other Electric Revenue includes work
and services performed on behalf of customers, including other utilities, which
is 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 Gas Revenue consists of
revenues for on-system natural gas sales and the transportation of natural gas
for customers by DPL within its service territories at regulated
rates.
Other Gas Revenue consists of DPL’s
off-system natural gas sales and the release of excess system
capacity.
Electric Operating Revenue
|
Regulated
T&D Electric Revenue
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
Change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
$ |
575.7 |
|
|
$ |
613.0 |
|
|
$ |
(37.3 |
) |
|
Commercial
|
|
|
699.0 |
|
|
|
726.8 |
|
|
|
(27.8 |
) |
|
Industrial
|
|
|
28.6 |
|
|
|
36.8 |
|
|
|
(8.2 |
) |
|
Other
|
|
|
229.9 |
|
|
|
246.6 |
|
|
|
(16.7 |
) |
|
Total
Regulated T&D Electric Revenue
|
|
$ |
1,533.2 |
|
|
$ |
1,623.2 |
|
|
$ |
(90.0 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Regulated T&D Electric
Revenue consists primarily of (i) transmission service revenue received by PHI’s
utility subsidiaries from PJM as transmission owners, and (ii) revenue from the
resale of energy and capacity under power purchase agreements between Pepco and
unaffiliated third parties in the PJM market.
|
Regulated
T&D Electric Sales (GWh)
|
|
|
|
|
2006
|
2005
|
Change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
17,139
|
|
|
18,045
|
|
|
(906)
|
|
|
|
Commercial
|
|
28,638
|
|
|
29,441
|
|
|
(803)
|
|
|
|
Industrial
|
|
4,119
|
|
|
4,288
|
|
|
(169)
|
|
|
|
Total
Regulated T&D Electric Sales
|
|
49,896
|
|
|
51,774
|
|
|
(1,878)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulated
T&D Electric Customers (in thousands)
|
|
|
|
|
2006
|
2005
|
Change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
1,605
|
|
|
1,591
|
|
|
14
|
|
|
|
Commercial
|
|
198
|
|
|
196
|
|
|
2
|
|
|
|
Industrial
|
|
2
|
|
|
2
|
|
|
-
|
|
|
|
Total
Regulated T&D Electric Customers
|
|
1,805
|
|
|
1,789
|
|
|
16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulated T&D Revenue decreased by
$90.0 million primarily due to the following: (i) $51.2 million decrease in
sales due to weather, the result of a 16% decrease in Heating Degree Days and
12% decrease in Cooling Degree Days in 2006, (ii) $18.5 million decrease due to
a change in Delaware rate structure effective May 1, 2006, which shifted revenue
from Regulated T&D Electric Revenue to Default Supply Revenue, (iii) $17.1
million decrease in network transmission revenues due to lower rates approved by
FERC in June 2006, (iv) $7.0 million decrease due to a Delaware base rate
reduction effective May 1, 2006, primarily offset by (v) $12.9 million increase
in sales due to a 0.9% increase in the number of customers.
Default Electricity Supply
|
Default
Supply Revenue
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
Change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
$ |
1,482.9 |
|
|
$ |
1,161.6 |
|
|
$ |
321.3 |
|
|
Commercial
|
|
|
1,352.6 |
|
|
|
995.4 |
|
|
|
357.2 |
|
|
Industrial
|
|
|
108.2 |
|
|
|
134.2 |
|
|
|
(26.0 |
) |
|
Other
|
|
|
328.2 |
|
|
|
461.8 |
|
|
|
(133.6 |
) |
|
Total
Default Supply Revenue
|
|
$ |
3,271.9 |
|
|
$ |
2,753.0 |
|
|
$ |
518.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Default Supply Revenue consists
primarily of revenue from the resale of energy and capacity under non-utility
generating contracts between ACE and unaffiliated third parties (NUGs) in the
PJM market.
|
Default
Electricity Supply Sales (GWh)
|
|
|
|
|
|
2006
|
2005
|
Change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
16,698
|
|
|
17,490
|
|
|
(792)
|
|
|
|
Commercial
|
|
14,799
|
|
|
15,020
|
|
|
(221)
|
|
|
|
Industrial
|
|
1,379
|
|
|
2,058
|
|
|
(679)
|
|
|
|
Other
|
|
129
|
|
|
157
|
|
|
(28)
|
|
|
|
Total
Default Electricity Supply Sales
|
|
33,005
|
|
|
34,725
|
|
|
(1,720)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Default
Electricity Supply Customers (in thousands)
|
|
|
|
|
2006
|
2005
|
Change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
1,575
|
|
|
1,557
|
|
|
18
|
|
|
|
Commercial
|
|
170
|
|
|
181
|
|
|
(11)
|
|
|
|
Industrial
|
|
1
|
|
|
2
|
|
|
(1)
|
|
|
|
Other
|
|
2
|
|
|
2
|
|
|
-
|
|
|
|
Total
Default Electricity Supply Customers
|
|
1,748
|
|
|
1,742
|
|
|
6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Default Supply Revenue, which is
partially offset in Fuel and Purchased Energy and Other Services Cost of Sales,
increased $518.9 million, representing an 18.8% increase despite a 5% decrease
in GWh sales. This increase was primarily due to the
following: (i) an increase of $709.3 million attributable to higher
retail electricity rates, primarily resulting from market based rates beginning
in Delaware on May 1, 2006 and annual increases in Default Electricity Supply
rates during the year in the District of Columbia, Maryland, New Jersey, and
Virginia, primarily offset by (ii) $142.1 million decrease in wholesale energy
revenues from sales of generated and purchased energy in PJM due to lower market
prices in the third quarter of 2006 and the sale by ACE of its interests in the
Keystone and Conemaugh generating plants, effective September 1, 2006, and (iii)
$93.1 million decrease in sales due to milder weather (a 16% decrease in Heating
Degree Days and a 12% decrease in Cooling Degree Days in 2006).
Other Electric Revenue decreased $6.9
million to $58.3 million in 2006 from $65.2 million in 2005 primarily due to a
decrease in customer requested work.
|
Regulated
Gas Revenue
|
|
|
|
|
|
2006
|
2005
|
Change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
$
$
|
116.2
|
|
$
$
|
115.0
|
|
$$
|
1.2
|
|
|
|
Commercial
|
|
73.0
|
|
|
68.5
|
|
|
4.5
|
|
|
|
Industrial
|
|
10.3
|
|
|
10.6
|
|
|
(.3)
|
|
|
|
Transportation
and Other
|
|
5.3
|
|
|
4.6
|
|
|
.7
|
|
|
|
Total
Regulated Gas Revenue
|
$
$
|
204.8
|
|
$
$
|
198.7
|
|
$$
|
6.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulated
Gas Sales (Bcf)
|
|
|
|
|
|
2006
|
2005
|
Change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
6.6
|
|
|
8.4
|
|
|
(1.8)
|
|
|
|
Commercial
|
|
4.6
|
|
|
5.6
|
|
|
(1.0)
|
|
|
|
Industrial
|
|
.8
|
|
|
1.1
|
|
|
(.3)
|
|
|
|
Transportation
and Other
|
|
6.3
|
|
|
5.6
|
|
|
.7
|
|
|
|
Total
Regulated Gas Sales
|
|
18.3
|
|
|
20.7
|
|
|
(2.4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulated
Gas Customers (in thousands)
|
|
|
|
|
|
2006
|
2005
|
Change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
112
|
|
|
111
|
|
|
1
|
|
|
|
Commercial
|
|
9
|
|
|
9
|
|
|
-
|
|
|
|
Industrial
|
|
-
|
|
|
-
|
|
|
-
|
|
|
|
Transportation
and Other
|
|
-
|
|
|
-
|
|
|
-
|
|
|
|
Total
Regulated Gas Customers
|
|
121
|
|
|
120
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulated Gas Revenue increased by $6.1
million primarily due to (i) $33.2 million increase primarily due to GCR
increase effective November 1, 2005, as a result of higher natural gas commodity
costs (primarily offset in Fuel and Purchased Energy and Other Services Costs of
Sales expense), offset by (ii) $22.3 million decrease in sales due to milder
weather (a 17% decrease in Heating Degree Days in 2006), and (iii) $4.8 million
decrease primarily due to differences in consumption among various customer rate
classes.
Other Gas Revenue decreased by $12.2
million to $50.6 million in 2006 from $62.8 million in 2005 primarily due to
lower off-system sales (partially offset in Gas Purchased expense).
The impact of Operating Revenue changes
and Fuel and Purchased Energy and Other Services Cost of Sales changes with
respect to the Conectiv Energy component of the Competitive Energy business are
encompassed within the following discussion of gross margin.
Operating Revenues of the Conectiv
Energy segment are derived primarily from the sale of
electricity. The primary components of its costs of sales are fuel
and purchased power. Because fuel and electricity prices tend to move
in tandem, price changes in these commodities from period to period can have a
significant impact on Operating Revenue and costs of sales without signifying
any change in the performance of the Conectiv Energy segment. For
this reason, PHI from a managerial standpoint focuses on gross margin as a
measure of performance.
Conectiv Energy Gross
Margin
Beginning in 2007, power origination
activities, which primarily represent the fixed margin component of structured
power transactions such as default electricity supply contracts, were classified
into Energy Marketing from Merchant Generation & Load
Service. Accordingly, the 2006 and 2005 activity has been
reclassified for comparative purposes. Power origination contributed
$18.7 million and $7.5 million of gross margin for 2006 and 2005,
respectively.
|
|
|
|
|
|
|
|
|
|
|
2005
|
|
|
Operating Revenue ($
millions):
|
|
|
|
|
|
|
|
Merchant
Generation & Load Service
|
|
$ |
1,073.2 |
|
|
$ |
1,193.6 |
|
|
Energy
Marketing
|
|
|
891.0 |
|
|
|
1,199.5 |
|
|
Total
Operating Revenue 1
|
|
$ |
1,964.2 |
|
|
$ |
2,393.1 |
|
|
|
|
|
|
|
|
|
|
|
|
Cost of Sales ($
millions):
|
|
|
|
|
|
|
|
|
|
Merchant
Generation & Load Service
|
|
$ |
861.3 |
|
|
$ |
952.5 |
|
|
Energy
Marketing
|
|
|
847.7 |
|
|
|
1,181.4 |
|
|
Total
Cost of Sales 2
|
|
$ |
1,709.0 |
|
|
$ |
2,133.9 |
|
|
|
|
|
|
|
|
|
|
|
|
Gross Margin ($
millions):
|
|
|
|
|
|
|
|
|
|
Merchant
Generation & Load Service
|
|
$ |
211.9 |
|
|
$ |
241.1 |
|
|
Energy
Marketing
|
|
|
43.3 |
|
|
|
18.1 |
|
|
Total
Gross Margin
|
|
$ |
255.2 |
|
|
$ |
259.2 |
|
|
|
|
|
|
|
|
|
|
|
|
Generation Fuel and Purchased
Power Expenses ($ millions) 3:
|
|
|
|
|
|
|
|
|
|
Generation
Fuel Expenses 4,5
|
|
|
|
|
|
|
|
|
|
Natural
Gas6
|
|
$ |
174.5 |
|
|
$ |
223.5 |
|
|
Coal
|
|
|
53.4 |
|
|
|
46.7 |
|
|
Oil
|
|
|
26.6 |
|
|
|
104.6 |
|
|
Other7
|
|
|
4.1 |
|
|
|
4.9 |
|
|
Total
Generation Fuel Expenses
|
|
$ |
258.6 |
|
|
$ |
379.7 |
|
|
Purchased
Power Expenses 5
|
|
|
431.3 |
|
|
|
539.0 |
|
|
|
|
|
|
|
|
|
|
|
|
Statistics:
|
|
2006
|
|
|
2005
|
|
|
Generation
Output (MWh):
|
|
|
|
|
|
|
|
|
|
Base-Load
8
|
|
|
1,814,517 |
|
|
|
1,738,280 |
|
|
Mid-Merit
(Combined Cycle) 9
|
|
|
2,081,873 |
|
|
|
2,971,294 |
|
|
Mid-Merit
(Oil Fired) 10
|
|
|
115,120 |
|
|
|
694,887 |
|
|
Peaking
|
|
|
131,930 |
|
|
|
190,688 |
|
|
Tolled
Generation
|
|
|
94,064 |
|
|
|
70,834 |
|
|
Total
|
|
|
4,237,504 |
|
|
|
5,665,983 |
|
|
|
|
|
|
|
|
|
|
|
|
Load
Service Volume (MWh) 11
|
|
|
8,514,719 |
|
|
|
14,230,888 |
|
|
|
|
|
|
|
|
|
|
|
|
Average
Power Sales Price 12
($/MWh):
|
|
|
|
|
|
|
|
|
|
Generation
Sales 4
|
|
$ |
77.69 |
|
|
$ |
87.62 |
|
|
Non-Generation
Sales 13
|
|
$ |
58.49 |
|
|
$ |
53.16 |
|
|
Total
|
|
$ |
62.54 |
|
|
$ |
60.12 |
|
|
|
|
|
|
|
|
|
|
|
|
Average
on-peak spot power price at PJM East Hub ($/MWh) 14
|
|
$ |
65.29 |
|
|
$ |
83.35 |
|
|
Average
around-the-clock spot power price at PJM East Hub ($/MWh) 14
|
|
$ |
53.07 |
|
|
$ |
66.05 |
|
|
Average
spot natural gas price at market area M3 ($/MMBtu)15
|
|
$ |
7.31 |
|
|
$ |
9.69 |
|
|
|
|
|
|
|
|
|
|
|
|
Weather
(degree days at Philadelphia Airport): 16
|
|
|
|
|
|
|
|
|
|
Heating
degree days
|
|
|
4,205 |
|
|
|
4,966 |
|
|
Cooling
degree days
|
|
|
1,136 |
|
|
|
1,306 |
|
|
1
|
Includes
$471.1 million and $591.3 million of affiliate transactions for 2006 and
2005, respectively. The 2006 and 2005 amounts have been
reclassified to exclude $193.1 million and $210.5 million, respectively,
of intra-affiliate transactions that were reported gross in 2006 and 2005
at the segment level.
|
|
2
|
Includes
$4.6 million and $7.2 million of affiliate transactions for 2006 and 2005,
respectively. The 2006 and 2005 amounts have been reclassified
to exclude $193.1 million and $210.5 million, respectively, of affiliate
transactions that were reported gross in 2006 and 2005 at the segment
level. Also, excludes depreciation and amortization expense of
$36.3 million and $40.4 million,
respectively.
|
|
3
|
Consists
solely of Merchant Generation & Load Service expenses; does not
include the cost of fuel not consumed by the power plants and intercompany
tolling expenses.
|
|
4
|
Includes
tolled generation.
|
|
5
|
Includes
associated hedging gains and
losses.
|
|
6
|
Includes
adjusted amounts in 2006 and 2005 for change in natural gas hedge
allocation methodology.
|
|
7
|
Includes
emissions expenses, fuel additives, and other fuel-related
costs.
|
|
8
|
Edge
Moor Units 3 and 4 and Deepwater Unit
6.
|
|
9
|
Hay
Road and Bethlehem, all units.
|
|
10
|
Edge
Moor Unit 5 and Deepwater Unit 1.
|
|
11
|
Consists
of all default electricity supply sales; does not include standard product
hedge volumes.
|
|
12
|
Calculated
from data reported in Conectiv Energy’s Electric Quarterly Report (EQR)
filed with the FERC; does not include capacity or ancillary services
revenue.
|
|
13
|
Consists
of default electricity supply sales, standard product power sales, and
spot power sales other than merchant generation as reported in Conectiv
Energy’s EQR.
|
|
15
|
Source: Average
delivered natural gas price at Tetco Zone M3 as published in Gas
Daily.
|
|
16
|
Source:
National Oceanic and Atmospheric Administration National Weather Service
data.
|
Merchant Generation & Load Service
gross margin decreased $29.2 million primarily due to:
|
·
|
A
decrease of $110.9 million due a 26% decline in output from Conectiv
Energy’s generating plants primarily because of milder weather in 2006,
coupled with lower spark spreads, lower contribution from sales of
ancillary services and fuel switching activities, and an unplanned summer
outage at the Hay Road generating
facility.
|
|
·
|
An
increase of $73.2 million on fuel and power hedge
contracts.
|
|
·
|
An
increase of $10.1 million due to a mark-to-market gain on a supply
contract.
|
Energy Marketing gross margin increased
$25.2 million primarily due to:
|
·
|
An
increase of $11.2 million in power origination due to new higher margin
contracts.
|
|
·
|
An
increase of $9.2 million due to improved inventory management in the oil
marketing business.
|
|
·
|
An
increase of $7.7 million in the gas marketing business from gains on
storage, transportation, and supply
contracts.
|
|
·
|
A
decrease of $3.3 million due to the expiration and associated termination
costs of a contract to provide operating services for an unaffiliated
generation station which expired on October 31,
2006.
|
Pepco Energy Services’ operating
revenue increased $181.4 million primarily due to (i) an increase of $265.6
million due to higher retail electricity customer load in 2006 and (ii) an
increase of $44.3 million due to higher energy services project revenue in 2006
resulting from increased construction activity partially offset by lower revenue
related to the sale of five businesses in 2006; partially offset by (iii) a
decrease of $93.8 million due to lower natural gas volumes in 2006 as a result
of fewer customers served and milder weather, (iv) a decrease of $29.0 million
due to reduced electricity generation by the Benning and Buzzard power plants in
2006 due to milder weather and higher fuel oil prices, and (v) a decrease of
$5.7 million in mass market products and services revenue, a business Pepco
Energy Services exited in 2005. As of December 31, 2006, Pepco Energy
Services had 3,544 megawatts of commercial and industrial load, as compared to
2,034 megawatts of commercial and industrial load at the end of
2005. In 2006, Pepco Energy Services’ power plants generated 89,578
megawatt hours of electricity as compared to 237,624 in 2005.
Other Non-Regulated revenue increased
$6.1 million to $90.6 million in 2006 from $84.5 million in
2005. Operating revenues consist of lease earnings recognized under
Statement of Financial Accounting Standards (SFAS) No. 13 and changes to the
carrying value of the other miscellaneous investments.
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:
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
Change
|
|
|
Power
Delivery
|
|
$ |
3,303.6 |
|
|
$ |
2,720.5 |
|
|
$ |
583.1 |
|
|
Conectiv
Energy
|
|
|
1,709.0 |
|
|
|
2,133.9 |
|
|
|
(424.9 |
) |
|
Pepco
Energy Services
|
|
|
1,531.1 |
|
|
|
1,357.5 |
|
|
|
173.6 |
|
|
Corp.
& Other
|
|
|
(477.8 |
) |
|
|
(599.9 |
) |
|
|
122.1 |
|
|
Total
|
|
$ |
6,065.9 |
|
|
$ |
5,612.0 |
|
|
$ |
453.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Power Delivery’s Fuel and Purchased
Energy and Other Services Cost of Sales, which is primarily associated with
Default Electricity Supply sales, increased by $583.1 million primarily due to:
(i) $736.8 million increase in average energy costs, resulting from higher costs
of Default Electricity Supply contracts that went into effect primarily in June
2006 and 2005, offset by (ii) $155.5 million decrease primarily due to
differences in consumption among the various customer rate classes (impact due
to such factors as weather, migration, etc). This expense is
primarily offset in Default Supply Revenue, Regulated Gas Revenue, and Other Gas
Revenue.
The impact of Fuel and Purchased
Energy and Other Services Cost of Sales changes with respect to the Conectiv
Energy component of the Competitive Energy business are encompassed within the
prior discussion under the heading “Conectiv Energy Gross Margin.”
Pepco Energy Services’ Fuel and
Purchased Energy and Other Services Cost of Sales increased $173.6 million due
to (i) a $246.5 million increase in purchases of electricity in 2006 to serve
higher retail customer load and (ii) an increase of $37.2 million in costs due
to higher energy services projects in 2006 as a result of increased construction
activity; partially offset by (iii) a decrease of $87.6 million for purchases of
natural gas due to lower volumes sold in 2006 as the result of fewer customers
served and milder weather, (iv) a $17.6 million decrease in electricity
generation costs in 2006 due to reduced electricity generation by the Benning
and Buzzard power plants as a result of milder weather and higher fuel oil
prices, (v) a $4.9 million decrease in mass market products and services costs,
a business Pepco Energy Services exited in 2005, and (vi) decreased costs due to
the sale of five companies in 2006.
Other Operation and
Maintenance
A detail of PHI’s other operation and
maintenance expense is as follows:
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
Change
|
|
|
Power
Delivery
|
|
$ |
639.6 |
|
|
$ |
643.1 |
|
|
$ |
(3.5 |
) |
|
Conectiv
Energy
|
|
|
116.3 |
|
|
|
107.7 |
|
|
|
8.6 |
|
|
Pepco
Energy Services
|
|
|
67.6 |
|
|
|
71.2 |
|
|
|
(3.6 |
) |
|
Other
Non-Regulated
|
|
|
4.2 |
|
|
|
5.2 |
|
|
|
(1.0 |
) |
|
Corp.
& Other
|
|
|
(20.4 |
) |
|
|
(11.5 |
) |
|
|
(8.9 |
) |
|
Total
|
|
$ |
807.3 |
|
|
$ |
815.7 |
|
|
$ |
(8.4 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The higher operation and maintenance
expenses of the Conectiv Energy segment were primarily due to planned and
unplanned facility outages. The impact of this increase was
substantially offset by lower corporate expenses related to the amortization of
non-compete agreements and other administrative and general
expenses.
Depreciation and
Amortization
Depreciation and amortization expenses
decreased by $14.1 million to $413.2 million in 2006, from $427.3 million in
2005. The decrease is primarily due to (i) $5.4 million change in
depreciation technique resulting from the ACE distribution base rate case
settlement in 2005 that depreciates assets over their whole life versus their
remaining life, (ii) $4.1 million reduction of ACE regulatory debits, and (iii)
$3 million reduction due to completion of amortization related to software,
offset by net increases to plant in-service (additions less retirements) of
about $5.4 million.
Deferred Electric Service
Costs
Deferred Electric Service Costs
decreased by $98.1 million to $22.1 million in 2006 from $120.2 million in
2005. The $98.1 million decrease was attributable to (i) $92.4
million net under-recovery associated with New Jersey BGS, NUGs, market
transition charges and other restructuring items and (ii) $5.7 million in
regulatory disallowances (net of amounts previously reserved) in connection with
the ACE distribution base rate case settlement in 2005.
For the year ended December 31, 2006,
Pepco Holdings recorded pre-tax impairment losses of $18.9 million ($13.7
million after-tax) related to certain energy services business assets owned by
Pepco Energy Services. The impairments were recorded as a result of
the execution of contracts to sell certain assets and due to the lower than
expected production and related estimated cash flows from other
assets. The fair value of the assets under contract for sale was
determined based on the sales contract price; while the fair value of the other
assets was determined by estimating future expected production and cash
flows.
Pepco Holdings recorded a Gain on Sale
of Assets of $.8 million for the year ended December 31, 2006, compared to $86.8
million for the year ended December 31, 2005. The $86.8 million gain
in 2005 primarily consisted of: (i) a $68.1 million gain from the sale of
non-utility land owned by Pepco located at Buzzard Point in the District of
Columbia, and (ii) a $13.3 million gain recorded by PCI from proceeds related to
the final liquidation of a financial investment that was written off in
2001.
Effect of Settlement of Mirant
Bankruptcy Claims
The Effect of Settlement of Mirant
Bankruptcy Claims of $70.5 million in 2005 represents a settlement (net of
customer sharing) with Mirant of the allowed, pre-petition general unsecured
claim related to a transition power agreement (TPA) by Pepco in the Mirant
bankruptcy in the amount of $105 million (the TPA Claim) ($70 million gain) and
a Pepco asbestos claim against the Mirant bankruptcy estate ($.5 million
gain). See “Capital Resources and Liquidity -- Cash Flow Activity --
Proceeds from Settlement of Mirant Bankruptcy Claims.”
Other
Income (Expenses)
Other Expenses (which are net of other
income) decreased by $3.1 million to $282.4 million for the year ended December
31, 2006 from $285.5 million for the same period in 2005. The
decrease primarily resulted from an increase in income from equity fund
valuations at PCI of $7.3 million and $2.3 in lower impairment charges during
2006 compared to 2005, partially offset by a $6.6 million gain in 2005 related
to the sale of an investment.
Income
Tax Expense
PHI’s effective tax rates for the years
ended December 31, 2006 and 2005 were 39.3% and 41.2%, respectively. The 1.9%
decrease in the effective tax rate in 2006 was primarily the result of changes
in estimates related to prior year tax liabilities, which reduced the effective
tax rate by 2.3%.
CAPITAL
RESOURCES AND LIQUIDITY
This section discusses Pepco Holdings’
working capital, cash flow activity, capital requirements and other uses and
sources of capital.
Working
Capital
At December 31, 2007, Pepco Holdings’
current assets on a consolidated basis totaled $2.0 billion and its current
liabilities totaled $2.0 billion. At December 31, 2006, Pepco
Holdings’ current assets on a consolidated basis totaled $2.0 billion and its
current liabilities totaled $2.5 billion. The working capital deficit
at the end of 2006 was primarily due to $500 million of current long-term debt
due to mature in August 2007. During 2007, PHI refinanced $450
million of the maturing debt with new long-term debt.
At December 31, 2007, Pepco Holdings’
cash and cash equivalents and its current restricted cash (cash that is
available to be used only for designated purposes) totaled $69.6
million. At December 31, 2006, Pepco Holdings’ cash and cash
equivalents and its current restricted cash, totaled $60.8
million. See “Capital Requirements -- Contractual Arrangements with
Credit Rating Triggers or Margining Rights” for additional
information.
A detail of PHI’s short-term debt
balance and its current maturities of long-term debt and project funding balance
follows.
|
|
(Millions
of dollars)
|
|
Type
|
PHI
Parent
|
Pepco
|
DPL
|
ACE
|
ACE
Funding
|
Conectiv
Energy
|
Pepco Energy Services
|
PCI
|
Conectiv
|
PHI
Consolidated
|
|
Variable
Rate
Demand
Bonds
|
$ -
|
$ -
|
$104.8
|
$22.6
|
$ -
|
$ -
|
$24.3
|
$ -
|
$ -
|
$151.7
|
|
|
Commercial
Paper
|
-
|
84.0
|
24.0
|
29.1
|
-
|
-
|
-
|
-
|
-
|
137.1
|
|
|
Total
Short-Term Debt
|
$ -
|
$ 84.0
|
$128.8
|
$51.7
|
$ -
|
$ -
|
$24.3
|
$ -
|
$ -
|
$288.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
Maturities
of
Long-Term Debt
and
Project Funding
|
$ -
|
$128.0
|
$ 22.6
|
$50.0
|
$31.0
|
$ -
|
$ 8.6
|
$92.0
|
$ -
|
$332.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Millions
of dollars)
|
|
Type
|
PHI
Parent
|
Pepco
|
DPL
|
ACE
|
ACE
Funding
|
Conectiv
Energy
|
Pepco Energy Services
|
PCI
|
Conectiv
|
PHI
Consolidated
|
|
Variable
Rate
Demand
Bonds
|
$ -
|
$ -
|
$104.8
|
$22.6
|
$ -
|
$ -
|
$26.8
|
$ -
|
$ -
|
$154.2
|
|
|
Commercial
Paper
|
36.0
|
67.1
|
91.1
|
1.2
|
-
|
-
|
-
|
-
|
-
|
195.4
|
|
|
Total
Short-Term Debt
|
$ 36.0
|
$ 67.1
|
$195.9
|
$23.8
|
$ -
|
$ -
|
$26.8
|
$ -
|
$ -
|
$349.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
Maturities
of
Long-Term Debt
and
Project Funding
|
$500.0
|
$210.0
|
$ 64.7
|
$16.0
|
$29.9
|
$ -
|
$ 2.6
|
$34.3
|
$ -
|
$857.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
Flow Activity
|
|
PHI’s
cash flows for 2007, 2006, and 2005 are summarized
below.
|
|
|
Cash
Source (Use)
|
|
|
|
2007
|
|
2006
|
|
2005
|
|
|
|
(Millions
of dollars)
|
|
|
Operating
Activities
|
$
|
795.0
|
|
$
|
202.6
|
|
$
|
986.9
|
|
|
Investing
Activities
|
|
(581.6)
|
|
|
(229.1)
|
|
|
(333.9)
|
|
|
Financing
Activities
|
|
(207.1)
|
|
|
(46.2)
|
|
|
(561.0)
|
|
|
Net
increase (decrease) in cash and cash equivalents
|
$
|
6.3
|
|
$
|
(72.7)
|
|
$
|
92.0
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from operating activities
are summarized below for 2007, 2006, and 2005.
|
|
Cash
Source (Use)
|
|
|
|
2007
|
|
2006
|
|
2005
|
|
|
|
(Millions
of dollars)
|
|
|
Net
Income
|
$
|
334.2
|
|
$
|
248.3
|
|
$
|
371.2
|
|
|
Non-cash
adjustments to net income
|
|
382.3
|
|
|
613.0
|
|
|
161.2
|
|
|
Changes
in working capital
|
|
78.5
|
|
|
(658.7)
|
|
|
454.5
|
|
|
Net
cash from operating activities
|
$
|
795.0
|
|
$
|
202.6
|
|
$
|
986.9
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash from operating activities in
2007 was $592.4 million higher than in 2006. In addition to net
income, the factors that primarily contributed to the increase
were: (i) a decrease of $202.9 million in taxes paid in 2007,
partially attributable to a tax payment of $121 million made in February 2006 in
connection with an unresolved tax matter (see “Regulatory and Other Matters –
IRS Mixed Service Cost Issue” below) and (ii) the change in cash collateral
requirements detailed below associated with Competitive Energy
activities.
Changes in cash collateral include the
following:
|
|
·
|
The
balance of cash collateral posted by PHI (net of cash collateral held by
PHI) decreased $61.7 million from December 31, 2006 to December 31, 2007
(an increase in cash).
|
|
|
·
|
The
balance of cash collateral posted by PHI (net of cash collateral held by
PHI) increased $259.9 million from December 31, 2005 to December 31, 2006
(a decrease in cash).
|
Cash flows from operating activities in
2007 also were affected by the Mirant bankruptcy settlement. See
“Proceeds from Settlement of Mirant Bankruptcy Claims” below. During
the third quarter of 2007, Pepco Holdings received $413.9 million in net
settlement proceeds, of which $398.9 million was designated as operating cash
flows and $15.0 million was designated as investing cash flows. See
“Investing Activities” below. These funds were used to purchase money
market funds, which are considered cash equivalents, and have been accounted for
as restricted cash based on management’s intent only to use such funds, and any
interest earned thereon, to pay for the future above-market capacity and energy
purchase costs under the Panda PPA. This restricted cash has been
classified as a non-current asset to be consistent with the classification of
the corresponding non-current regulatory liability, and any changes in the
balance of this restricted cash, including interest receipts, have been
considered operating cash flows.
Net cash from operating activities in
2006 was $784.3 million lower than in 2005. In addition to the
decrease in net income, the factors contributing to the decrease in cash flow
from operating activities included: (i) an increase of $194.5 million
in taxes paid in 2006, including a tax payment of $121 million made in February
2006 in connection with an unresolved tax matter (see “Regulatory and Other
Matters -- IRS Mixed Service Cost Issue” below), (ii) a decrease in the
change in regulatory assets and liabilities of $107.9 million due primarily to
the 2005 over-
recoveries
associated with New Jersey BGS, NUGs, market transition charges and other
restructuring items, and (iii) the change in collateral requirements associated
with the activities of Competitive Energy described above.
Cash flows used by investing activities
during 2007, 2006, and 2005 are summarized below.
|
|
Cash
(Use) Source
|
|
|
|
2007
|
|
2006
|
|
2005
|
|
|
|
(Millions
of dollars)
|
|
|
Construction
expenditures
|
$
|
(623.4)
|
|
$
|
(474.6)
|
|
$
|
(467.1)
|
|
|
Cash
proceeds from sale of properties
|
|
11.2
|
|
|
181.5
|
|
|
84.1
|
|
|
All
other investing cash flows, net
|
|
30.6
|
|
|
64.0
|
|
|
49.1
|
|
|
Net
cash used by investing activities
|
$
|
(581.6)
|
|
$
|
(229.1)
|
|
$
|
(333.9)
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used by investing activities
in 2007 was $352.5 million higher than in 2006 primarily due to: (i)
a $148.8 million increase in capital expenditures, $107.0 million of which
relates to Power Delivery, and (ii) a decrease of $170.3 million in cash
proceeds from the sale of property. The increase in Power Delivery
capital expenditures is primarily due to major transmission projects and new
substations for Pepco and ACE. The proceeds from the sale of property
in 2006 consisted primarily of $177.0 million from the sale of ACE’s interest in
the Keystone and Conemaugh generating facilities and $13.1 million from the sale
of Conectiv Energy’s equity interest in a joint venture which owns a wood
burning cogeneration facility. Proceeds from the sale of property in 2007
consisted primarily of $9.0 million received from the sale of the B.L. England
generating facility. Cash flows from investing activities in 2007
also include $15.0 million of the net settlement proceeds received by Pepco in
the Mirant bankruptcy settlement that were specifically designated as a
reimbursement of certain investments in property, plant and
equipment.
Net cash used by investing activities
in 2006 were $104.8 million lower than in 2005. The decrease is
primarily due to the net proceeds of $177.0 million received in 2006 from the
sale of ACE’s interest in the Keystone and Conemaugh generating facilities,
compared to the $73.7 million in proceeds received in 2005 from the sale of the
Buzzard Point land.
Cash flows used by financing activities
during 2007, 2006 and 2005 are summarized below.
|
|
Cash
(Use) Source
|
|
|
|
2007
|
|
2006
|
|
2005
|
|
|
|
(Millions
of dollars)
|
|
|
Dividends
paid on common and preferred stock
|
$
|
(202.9)
|
|
$
|
(199.5)
|
|
$
|
(191.4)
|
|
|
Common
stock issued through the Dividend
Reinvestment
Plan (DRP)
|
|
28.0
|
|
|
29.8
|
|
|
27.5
|
|
|
Issuance
of common stock
|
|
199.6
|
|
|
17.0
|
|
|
5.7
|
|
|
Redemption
of preferred stock of subsidiaries
|
|
(18.2)
|
|
|
(21.5)
|
|
|
(9.0)
|
|
|
Issuances
of long-term debt
|
|
703.9
|
|
|
514.5
|
|
|
532.0
|
|
|
Reacquisition
of long-term debt
|
|
(854.9)
|
|
|
(578.0)
|
|
|
(755.8)
|
|
|
(Repayments)
issuances of short-term debt, net
|
|
(58.3)
|
|
|
193.2
|
|
|
(161.3)
|
|
|
All
other financing cash flows, net
|
|
(4.3)
|
|
|
(1.7)
|
|
|
(8.7)
|
|
|
Net
cash used by financing activities
|
$
|
(207.1)
|
|
$
|
(46.2)
|
|
$
|
(561.0)
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used by financing activities
in 2007 was $160.9 million higher than in 2006. Net cash used by
financing activities in 2006 was $514.8 million lower than in 2005.
Changes
in Outstanding Common Stock
In November 2007, PHI sold 6.5 million
shares of common stock in a registered offering at a price per share of $27.00,
resulting in gross proceeds of $175.5 million. The net proceeds
are being used for general corporate purposes. The balance of the
change in 2007 common stock is primarily attributable to the issuance of
performance based shares under the long-term incentive plan.
Under the
DRP, PHI issued 979,155 shares of common stock in 2007, 1,232,569 shares of
common stock in 2006, and 1,228,505 shares of common stock in 2005.
Common
Stock Dividends
Common stock dividend payments were
$202.6 million in 2007, $198.3 million in 2006, and $188.9 million in
2005. The increase in common dividends paid in 2007 was due primarily
to an issuance of the additional shares under the DRP. The increase
in common dividends paid in 2006 was due to the issuance of the additional
shares under the DRP and a quarterly dividend increase from 25 cents per share
to 26 cents per share beginning in the first quarter of 2006.
Changes in Outstanding Preferred
Stock
Preferred stock redemptions in 2007
consisted of DPL’s redemption in January 2007, at prices ranging from 103% to
105% of par, of the following securities, representing all of DPL’s outstanding
preferred stock, at an aggregate cost of $18.9 million:
|
|
·
|
19,809
shares of 4.00% Series, 1943 Redeemable Serial Preferred
Stock,
|
|
|
·
|
39,866
shares of 3.70% Series, 1947 Redeemable Serial Preferred
Stock,
|
|
|
·
|
28,460
shares of 4.28% Series, 1949 Redeemable Serial Preferred
Stock,
|
|
|
·
|
19,571
shares of 4.56% Series, 1952 Redeemable Serial Preferred
Stock,
|
|
|
·
|
25,404
shares of 4.20% Series, 1955 Redeemable Serial Preferred Stock,
and
|
|
|
·
|
48,588
shares of 5.00% Series, 1956 Redeemable Serial Preferred
Stock.
|
Preferred
stock redemptions in 2006 consisted of Pepco’s redemption in March 2006 of the
following securities at an aggregate cost of $21.5 million:
|
|
·
|
216,846
shares of $2.44 Series, 1957 Serial Preferred
Stock,
|
|
|
·
|
99,789
shares of $2.46 Series, 1958 Serial Preferred Stock,
and
|
|
|
·
|
112,709
shares of $2.28 Series, 1965 Serial Preferred
Stock.
|
Preferred
stock redemptions in 2005 consisted of:
|
|
·
|
Pepco’s
redemption in October 2005 of the following securities at an aggregate
cost of $5.5 million:
|
|
|
o
|
22,795
shares of $2.44 Series 1957 Serial Preferred
Stock,
|
|
|
o
|
74,103
shares of $2.46 Series 1958 Serial Preferred Stock,
and
|
|
|
o
|
13,148
shares of $2.28 Series 1965 Serial Preferred
Stock.
|
|
|
·
|
ACE’s
redemption in August 2005 of 160 shares of 4.35% Serial Preferred Stock at
a cost of $.02 million, and
|
|
|
·
|
DPL’s
redemption in December 2005 of all of the 35,000 shares of 6.75% Serial
Preferred Stock outstanding at a cost of $3.5
million.
|
Changes
in Outstanding Long-Term Debt
Cash flows from the issuance and
redemption of long-term debt in 2007 were attributable primarily to the
following transactions, which encompass $700.0 million of the $703.9 million in
long-term debt issued in 2007 and all of the $854.9 million in long-term debt
redeemed in 2007:
|
|
·
|
In
January 2007, Pepco retired at maturity $35 million of 7.64% medium-term
notes and also retired at maturity $175 million of 6.25% first mortgage
bonds using the proceeds of commercial paper. In November 2007, Pepco
issued $250 million of 6.5% first mortgage
bonds.
|
|
|
·
|
In
February 2007, DPL retired at maturity $11.5 million of medium-term notes
with a weighted average interest rate of 7.08%. In the second
quarter of 2007, DPL retired at maturity $50 million of 8.125% medium-term
notes and $3.2 million of 6.95% first mortgage
bonds.
|
|
|
·
|
In
the second quarter of 2007, ACE retired at maturity $15 million of 7.52%
medium-term notes and $1 million of 7.15% medium-term
notes.
|
|
|
·
|
For
the year ended December 31, 2007, Atlantic City Electric Transition
Funding LLC (ACE Funding) made principal payments of $21.4 million on
Series 2002-1 Bonds, Class A-1 and $8.5 million on Series 2003-1, Class
A-1 with a weighted average interest rate of
2.89%.
|
|
|
·
|
In
February 2007, PCI retired at maturity $34.3 million of 7.62% medium-term
notes.
|
|
|
·
|
In
April 2007, PHI issued $200 million of 6.0% notes due 2019 in a private
placement. The proceeds were used to redeem $200 million of
5.5% notes due August 15, 2007 at a price of 100.0377% of
par. In June 2007, PHI issued $250 million of 6.125% notes due
2017 in a public offering and used the proceeds along with short-term debt
to redeem $300 million of its 5.5% notes in August
2007.
|
Cash flows from the issuance and
redemption of long-term debt in 2006 were attributable primarily to the
following transactions, which encompass all of the $514.5 million of long-term
debt issued in 2006 and $576.4 million of the $578.0 million of the long-term
debt redeemed in 2006:
|
|
·
|
In
May 2006, Pepco used the proceeds from a bond refinancing to redeem an
aggregate of $109.5 million of three series of first mortgage
bonds. The series were combined into one series of $109.5
million due 2022.
|
|
|
·
|
In
December 2006, Pepco retired at maturity $50 million of variable rate
notes.
|
|
|
·
|
In
June 2006, DPL redeemed $2.9 million of 6.95% first mortgage bonds due
2008.
|
|
|
·
|
In
October 2006, DPL retired at maturity $20 million of medium-term
notes.
|
|
|
·
|
In
December 2006, DPL issued $100 million of 5.22% unsecured notes due
2016. The proceeds were used to redeem DPL’s commercial paper
outstanding.
|
|
|
·
|
In
the first quarter of 2006, PHI retired at maturity $300 million of its
3.75% unsecured notes with proceeds from the issuance of commercial
paper.
|
|
|
·
|
In
December 2006, PHI issued $200 million of 5.9% unsecured notes due
2016. The net proceeds, plus additional funds, were used to
repay a $250 million bank loan entered into in August
2006.
|
|
|
·
|
In
January 2006, ACE retired at maturity $65 million of medium-term
notes.
|
|
|
·
|
In
March 2006, ACE issued $105 million of Senior Notes due
2036. The proceeds were used to pay down short-term debt
incurred earlier in the quarter to repay medium-term notes at
maturity.
|
|
|
·
|
For
the year ended December 31, 2006, ACE Funding made principal payments of
$20.7 million on Series 2002-1 Bonds, Class A-1 and $8.3 million on Series
2003-1, Class A-1 with a weighted average interest rate of
2.89%.
|
Cash flows from the issuance and
redemption of long-term debt in 2005 were attributable primarily to the
following transactions, which encompass $525 million of the $532 million of
long-term debt issued in 2005 and $727.7 million of the $755.8 million of
long-term debt redeemed in 2005:
|
|
·
|
In
2005, Pepco Holdings issued $250 million of floating rate unsecured notes
due 2010. The net proceeds, plus additional funds, were used to
repay commercial paper issued to fund the $300 million redemptions of
Conectiv debt.
|
|
|
·
|
In
September 2005, Pepco used the proceeds from the June 2005 issuance of
$175 million in senior secured notes to fund the retirement of $100
million in first mortgage bonds at maturity as well as the redemption of
$75 million in first mortgage bonds prior to
maturity.
|
|
|
·
|
In
2005, DPL issued $100 million of unsecured notes due 2015. The
net proceeds were used to redeem $102.7 million of higher rate
securities.
|
|
|
·
|
In
December 2005, Pepco paid down $50 million of its $100 million bank loan
due December 2006.
|
|
|
·
|
In
2005, ACE retired at maturity $40 million of medium-term
notes.
|
|
|
·
|
In
2005, PCI redeemed $60 million of medium-term
notes.
|
PHI’s long-term debt is subject to
certain covenants. PHI and its subsidiaries are in compliance with
all requirements.
Changes
in Short-Term Debt
In 2007, PHI redeemed a total of $36.0
million in short-term debt with cash from operations.
In 2006, Pepco and DPL issued
short-term debt of $67.1 million and $91.1 million, respectively, in order to
cover capital expenditures and tax obligations throughout the year.
In 2005, ACE and PHI redeemed a total
of $161.3 million in short-term debt with cash from operations.
Sales of ACE Generating
Facilities
On September 1, 2006, ACE completed the
sale of its interest in the Keystone and Conemaugh generating facilities for
$175.4 million (after giving effect to post-closing adjustments). On
February 8, 2007, ACE completed the sale of the B.L. England generating facility
for a price of $9.0 million. No gain or loss was realized on these
sales.
Sale of Interest in Cogeneration Joint
Venture
During the first quarter of 2006,
Conectiv Energy recognized a $12.3 million pre-tax gain ($7.9 million after-tax)
on the sale of its equity interest in a joint venture which owns a wood burning
cogeneration facility.
Proceeds from Settlement of Mirant
Bankruptcy Claims
In 2000, Pepco sold substantially all
of its electricity generating assets to Mirant. In 2003, Mirant
commenced a voluntary bankruptcy proceeding in which it sought to reject certain
obligations that it had undertaken in connection with the asset
sale. As part of the asset sale, Pepco entered into the
TPAs. Under a settlement to avoid the rejection by Mirant of its
obligations under the TPAs in the bankruptcy proceeding, the terms of the TPAs
were modified to increase the purchase price of the energy and capacity supplied
by Mirant and Pepco received the TPA Claim. In December 2005, Pepco
sold the TPA Claim, plus the right to receive accrued interest thereon, to an
unaffiliated third party for $112.5 million. In addition, Pepco
received proceeds of $.5 million in settlement of an asbestos claim against
the Mirant bankruptcy estate. After customer sharing, Pepco recorded
a pre-tax gain of $70.5 million from the settlement of these
claims.
In connection with the asset sale,
Pepco and Mirant also entered into a “back-to-back” arrangement, whereby Mirant
agreed to purchase from Pepco the 230 megawatts of electricity and capacity that
Pepco is obligated to purchase annually through 2021 from Panda under the Panda
PPA at the purchase price Pepco is obligated to pay to Panda. As part
of the further settlement of Pepco’s claims against Mirant arising from the
Mirant bankruptcy, Pepco agreed not to contest the rejection by Mirant of its
obligations under the “back-to-back” arrangement in exchange for the payment by
Mirant of damages corresponding to the estimated amount by which the purchase
price that Pepco is obligated to pay Panda for the energy and capacity exceeded
the market price. In 2007, Pepco received as damages
$413.9 million in net proceeds from the sale of shares of Mirant common
stock issued to it by Mirant. These funds are being accounted for as
restricted cash based on management’s intent to use such funds, and any interest
earned thereon, for the sole purpose of paying for the future above-market
capacity and energy purchase costs under the Panda
PPA. Correspondingly, a regulatory liability has been established in
the same amount to help offset the future above-market capacity and energy
purchase costs. This restricted cash has been classified as a
non-current asset to be consistent with the classification of the non-current
regulatory liability, and any changes in the balance of this restricted cash,
including interest on the invested funds, are being accounted for as operating
cash flows.
As of December 31, 2007, the balance of
the restricted cash account was $417.3 million. Based on a
reexamination of the costs of the Panda PPA in light of current and projected
wholesale market conditions conducted in the fourth quarter of 2007, Pepco
determined that, principally due to increases in wholesale capacity prices, the
present value above-market cost
of
the Panda
PPA over the term of the agreement are expected to be significantly less than
the current amount of the restricted cash account
balance. Accordingly, on February 22, 2008, Pepco filed applications
with the DCPSC and the MPSC requesting orders directing Pepco to maintain
$320 million in the restricted cash account and to use that cash, and any
future earnings on the cash, for the sole purpose of paying the future
above-market cost of the Panda PPA (or, in the alternative, to fund a transfer
or assignment of the remaining obligations under the Panda PPA to a third
party). Pepco also requested that the order provide that any cash
remaining in the account at the conclusion of the Panda PPA be refunded to
customers and that any shortfall be recovered from customers. Pepco
further proposed that the excess proceeds remaining from the settlement
(approximately $94.6 million, representing the amount by which the
regulatory liability of $414.6 million at December 31, 2007 exceeded
$320 million) be shared approximately equally with its customers in
accordance with the procedures previously approved by each commission for the
sharing of the proceeds received by Pepco from the sale to Mirant of its
generating assets. The regulatory liability of $414.6 million at
December 31, 2007 differs from the restricted cash amount of $417.3 million
on that date, in part, because the regulatory liability has been reduced for the
portion of the December 2007 Panda charges in excess of market that had not yet
been paid from the restricted cash account. The amount of the
restricted cash balance that Pepco is permitted to retain will be recorded as
earnings upon approval of the sharing arrangement by the respective
commissions. At this time, Pepco cannot predict the outcome of these
proceedings.
In settlement of other damages claims
against Mirant, Pepco in 2007 also received a settlement payment in the amount
of $70.0 million. Of this amount (i) $33.4 million was
recorded as a reduction in operating expenses, (ii) $21.0 million was
recorded as a reduction in a net pre-petition receivable claim from Mirant,
(iii) $15.0 million was recorded as a reduction in the capitalized costs of
certain property, plant and equipment and (iv) $.6 million was recorded as
a liability to reimburse a third party for certain legal costs associated with
the settlement.
Sale of Buzzard Point
Property
In August 2005, Pepco sold for $75
million excess non-utility land located at Buzzard Point in the District of
Columbia. The sale resulted in a pre-tax gain of $68.1 million which was
recorded as a reduction of Operating Expenses in the Consolidated Statements of
Earnings.
Financial Investment
Liquidation
In October 2005, PCI received $13.3
million in cash and recorded an after-tax gain of $8.9 million related to the
liquidation of a financial investment that was written-off in 2001.
Capital
Requirements
Pepco Holdings’ total capital
expenditures for the year ended December 31, 2007 totaled $623.4 million of
which $272.2 million related to Pepco (excluding $15 million of reimbursements
related to the settlement of the Mirant bankruptcy claims), $132.6 million
related to DPL and $149.4 million related to ACE. The remainder of
$69.2 million was primarily related to Conectiv Energy and Pepco Energy
Services. The Power Delivery expenditures were primarily related to
capital costs associated with new customer services, distribution reliability,
and transmission.
The table below shows the projected
capital expenditures for Pepco, DPL, ACE, Conectiv Energy and Pepco Energy
Services for the five-year period 2008 through 2012.
|
|
For
the Year
|
|
|
|
|
|
2008
|
|
2009
|
|
2010
|
|
2011
|
|
2012
|
|
Total
|
|
|
(Millions
of Dollars)
|
|
Pepco
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distribution
|
$
|
192
|
$
|
215
|
$
|
212
|
$
|
232
|
$
|
331
|
$
|
1,182
|
|
Distribution
- Blueprint for the Future
|
|
24
|
|
61
|
|
61
|
|
63
|
|
5
|
|
214
|
|
Transmission
|
|
45
|
|
64
|
|
167
|
|
168
|
|
62
|
|
506
|
|
MAPP
|
|
17
|
|
72
|
|
30
|
|
-
|
|
-
|
|
119
|
|
Other
|
|
15
|
|
17
|
|
12
|
|
12
|
|
11
|
|
67
|
|
DPL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distribution
|
|
101
|
|
118
|
|
124
|
|
124
|
|
138
|
|
605
|
|
Distribution
- Blueprint for the Future
|
|
22
|
|
58
|
|
59
|
|
30
|
|
9
|
|
178
|
|
Transmission
|
|
57
|
|
52
|
|
45
|
|
57
|
|
52
|
|
263
|
|
MAPP
|
|
11
|
|
107
|
|
210
|
|
271
|
|
185
|
|
784
|
|
Gas
Delivery
|
|
23
|
|
24
|
|
19
|
|
19
|
|
18
|
|
103
|
|
Other
|
|
10
|
|
10
|
|
9
|
|
7
|
|
7
|
|
43
|
|
ACE
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distribution
|
|
96
|
|
107
|
|
101
|
|
109
|
|
111
|
|
524
|
|
Distribution
- Blueprint for the Future
|
|
15
|
|
11
|
|
16
|
|
20
|
|
85
|
|
147
|
|
Transmission
|
|
78
|
|
17
|
|
25
|
|
45
|
|
47
|
|
212
|
|
MAPP
|
|
-
|
|
-
|
|
1
|
|
2
|
|
3
|
|
6
|
|
Other
|
|
10
|
|
10
|
|
8
|
|
7
|
|
5
|
|
40
|
|
Total
for Power Delivery Business
|
|
716
|
|
943
|
|
1,099
|
|
1,166
|
|
1,069
|
|
4,993
|
|
Conectiv
Energy
|
|
155
|
|
229
|
|
161
|
|
28
|
|
9
|
|
582
|
|
Pepco
Energy Services
|
|
21
|
|
13
|
|
13
|
|
14
|
|
15
|
|
76
|
|
Corporate
|
|
4
|
|
2
|
|
2
|
|
2
|
|
2
|
|
12
|
|
Total
PHI
|
$
|
896
|
$
|
1,187
|
$
|
1,275
|
$
|
1,210
|
$
|
1,095
|
$
|
5,663
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pepco Holdings expects to fund these
expenditures through internally generated cash and external
financing.
Distribution, Transmission and Gas
Delivery
The projected capital expenditures for
distribution (other than Blueprint for the Future), transmission (other than
MAPP) and gas delivery are primarily for facility replacements and upgrades to
accommodate customer growth and reliability.
During 2007, Pepco, DPL and ACE each
announced an initiative that it refers to as the “Blueprint for the
Future.” These initiatives combine traditional energy efficiency
programs with new technologies and systems to help customers manage their energy
use and reduce the total cost of energy. The programs include Demand
side management efforts, such as rebates or other financial incentives for
residential customers to replace inefficient appliances and for business
customers to use more energy efficient equipment, such as improved lighting and
HVAC systems. Under the programs, customers also could receive
credits on their bills for allowing the utility company to “cycle,” or
intermittently turn off, their central air conditioning or heat pumps when
wholesale electricity prices are high. The programs contemplate that
business customers would receive financial incentives for using energy efficient
equipment, and would be rewarded for reducing use during periods of peak
demand. Additionally, Pepco and DPL intend to install “smart meters”
for all customers in the District of Columbia, Maryland and
Delaware,
providing the utilities with the ability to remotely read the meters and
identify the location of a power outage. Pepco, DPL and ACE have made
filings with their respective regulatory commissions for approval of certain
aspects of these programs. The projected costs for PHI’s utility
subsidiaries for the years 2008 through 2012 are included in the table
above.
On October 17, 2007, PHI received the
approval of the PJM Board of Managers to build a new 230-mile, 500-kilovolt
interstate transmission line as part of PJM’s Regional Transmission Expansion
Plan to address the reliability objectives of the PJM RTO system. The
transmission line, which is referred to as the MAPP Project, will be located in
northern Virginia, Maryland, the Delmarva Peninsula, and New
Jersey. The preliminarily estimated cost of the MAPP Project is
approximately $1 billion. Construction is expected to occur in
sections over a six-year period with completion targeted by 2013. PHI
also plans to add significant 230-kilovolt support lines in Maryland and New
Jersey to connect with the new 500-kilovolt line at an approximate cost of $200
million. PJM continues to evaluate the 230-kilovolt support
lines. Only the projected construction costs associated with the
500-kilovolt transmission line for the years 2008 through 2012 are included in
the table above.
On December 14, 2007, Conectiv Energy
announced a decision to construct a 545 MW natural gas and oil-fired
combined-cycle electricity generation plant to be located in Peach Bottom
Township, Pennsylvania (“Delta Project”). The total construction
expenditures for the Delta Project are expected to be $470 million, with
projected expenditures of $62 million in 2008, $195 million in 2009, $136
million in 2010, and $14 million in 2011, and are included in Conectiv Energy’s
projected capital expenditures shown in the table above. The total
expenditures include $63 million in development costs and three combustion
turbines currently held in inventory by Conectiv Energy. The plant is
expected to become operational by June 2011.
In 2007, Conectiv Energy began
construction of a new combustion turbine power plant in Millville, New
Jersey. The total construction expenditures for this project are
expected to be $75 million (of which $24 million was expended in 2007), with
projected expenditures of $46 million in 2008 and $5 million in
2009. These future expenditures are included in Conectiv Energy’s
projected capital expenditures shown in the table above.
Compliance with Delaware Multipollutant
Regulations
As required by the Delaware
multipollutant emissions regulations adopted by the Delaware Department of
Natural Resources and Environmental Control, PHI, in June 2007, filed a
compliance plan for controlling nitrogen oxide (NOx), sulfur dioxide (SO2) and
mercury emissions from its Edge Moor power plant. The plan includes
installation of a sodium-based sorbent injection system and a Selective
Non-Catalytic Reduction (SNCR) system and carbon injection for Edge Moor Units 3
and 4, and use of an SNCR system and lower sulfur oil at Edge Moor Unit
5. Conectiv Energy currently believes that with these modifications,
it will be able to meet the requirements of the new regulations at an estimated
capital cost of $79 million. The compliance plan filed by Conectiv
Energy contemplates capital expenditures of $38 million of capital in 2008 and
$19 million of capital in 2009.
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 2007,
PHI’s Board of Directors declared quarterly dividends of 26 cents per share of
common stock payable on March 30, 2007, June 29, 2007, September 28, 2007
and December 31, 2007.
PHI 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 and regulatory laws, which impose limitations on the funds that
can be used to pay dividends and, in the case of regulatory laws, as applicable,
may require the prior approval of the relevant utility regulatory commissions
before dividends can be paid, (ii) the prior rights of holders of existing and
future preferred stock, 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 certificate of
incorporation which provides that, if any preferred stock is outstanding, no
dividends may be paid on the ACE common stock if, after payment, ACE’s common
stock capital plus surplus would be less than the involuntary liquidation value
of the outstanding preferred stock. Pepco and DPL have no shares of
preferred stock outstanding. Currently, the restriction in the ACE
charter does not limit its ability to pay dividends.
Pepco Holdings has a noncontributory
retirement plan (the PHI Retirement Plan) that covers substantially all
employees of Pepco, DPL and ACE and certain employees of other Pepco Holdings
subsidiaries.
As of the 2007 valuation, the PHI
Retirement Plan satisfied the minimum funding requirements of the Employment
Retirement Income Security Act of 1974 (ERISA) without requiring any additional
funding. PHI’s funding policy with regard to the PHI Retirement Plan
is to maintain a funding level in excess of 100% of its accumulated benefit
obligation (ABO). In 2007 and 2006, no contributions were made to the
PHI Retirement Plan.
In 2007, the ABO for the PHI Retirement
Plan decreased from 2006, due to an increase in the discount rate used to value
the ABO obligation, which more than offset the accrual of an additional year of
service for participants. The PHI Retirement Plan assets achieved
returns in 2007 above the 8.25% level assumed in the valuation. As a
result of the combination of these factors, no contribution was made to the PHI
Retirement Plan, because the funding level at year end 2007 was in excess of
100% of the ABO. In 2006, as a result of similar factors, PHI made no
contribution to the PHI Retirement Plan. Assuming no changes to the
current pension plan assumptions, PHI projects no funding will be required under
ERISA in 2008; however, PHI may elect to make a discretionary tax-deductible
contribution, if required to maintain its assets in excess of ABO for the PHI
Retirement Plan. Legislative changes, in the form of the Pension
Protection Act of 2006, impact the funding requirements for pension plans
beginning in 2008. The Pension Protection Act alters the manner in which
liabilities and asset values are determined
for the
purpose of calculating required pension contributions. Based on
preliminary actuarial projections and assuming no changes to current pension
plan assumptions, PHI believes it is unlikely that there will be a required
contribution in 2008.
Contractual Obligations and Commercial
Commitments
Summary information about Pepco
Holdings’ consolidated contractual obligations and commercial commitments at
December 31, 2007, is as follows:
|
|
Contractual
Maturity
|
|
|
Obligation (a)
|
|
Total
|
|
|
Less
than 1 Year
|
|
|
1-3
Years
|
|
|
3-5
Years
|
|
|
After
5 Years
|
|
|
|
|
(Millions
of dollars)
|
|
|
Variable
rate demand bonds
|
$
|
151.7
|
|
$
|
151.7
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
|
Commercial
paper
|
|
137.1
|
|
|
137.1
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
Long-term
debt
(b)
|
|
4,938.4
|
|
|
323.8
|
|
|
614.1
|
|
|
857.2
|
|
|
3,143.3
|
|
|
Long-term
project funding
|
|
29.3
|
|
|
8.4
|
|
|
4.1
|
|
|
3.3
|
|
|
13.5
|
|
|
Interest
payments on debt
|
|
3,254.4
|
|
|
282.8
|
|
|
521.5
|
|
|
462.7
|
|
|
1,987.4
|
|
|
Capital
leases
|
|
182.9
|
|
|
15.4
|
|
|
30.4
|
|
|
30.4
|
|
|
106.7
|
|
|
Liabilities
and accrued interest
related
to effectively settled
and
uncertain tax positions
|
|
140.8
|
|
|
71.0
|
|
|
-
|
|
|
13.0
|
|
|
56.8
|
|
|
Operating
leases
|
|
512.0
|
|
|
38.1
|
|
|
62.4
|
|
|
49.6
|
|
|
361.9
|
|
|
Non-derivative
fuel and
purchase
power contracts
(c)
|
|
9,806.1
|
|
|
3,176.7
|
|
|
2,756.8
|
|
|
752.7
|
|
|
3,119.9
|
|
|
Total
|
$
|
19,152.7
|
|
$
|
4,205.0
|
|
$
|
3,989.3
|
|
$
|
2,168.9
|
|
$
|
8,789.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
Estimates
relating to the future funding of PHI’s pension and other postretirement
benefit plans are not included in this table. For additional
information, see Item 8, Note (6) Pension and Other Postretirement
Benefits -- “Cash Flows.”
|
|
|
(b)
|
Includes
transition bonds issued by ACE
Funding.
|
|
|
(c)
|
Excludes
contractual obligations entered into by ACE to purchase electricity to
satisfy its BGS load.
|
Third Party Guarantees,
Indemnifications and Off-Balance Sheet Arrangements
Pepco Holdings and certain of its
subsidiaries have various financial and performance guarantees and
indemnification obligations which are entered into in the normal course of
business to facilitate commercial transactions with third parties as discussed
below.
As of December 31, 2007, Pepco Holdings
and its subsidiaries were parties to a variety of agreements pursuant to which
they were guarantors for standby letters of credit, performance residual value,
and other commitments and obligations. These commitments and
obligations, in millions of dollars, were as follows:
|
|
Guarantor
|
|
|
|
|
|
|
PHI
|
|
DPL
|
|
ACE
|
|
Other
|
|
Total
|
|
|
Energy
marketing obligations of
Conectiv
Energy
(a)
|
$
|
180.9
|
$
|
-
|
$
|
-
|
$
|
-
|
$
|
180.9
|
|
|
Energy
procurement obligations of
Pepco Energy
Services
(a)
|
|
141.7
|
|
-
|
|
-
|
|
-
|
|
141.7
|
|
|
Guaranteed
lease residual values
(b)
|
|
-
|
|
2.6
|
|
2.7
|
|
.4
|
|
5.7
|
|
|
Other (c)
|
|
2.3
|
|
-
|
|
-
|
|
1.4
|
|
3.7
|
|
|
Total
|
$
|
324.9
|
$
|
2.6
|
$
|
2.7
|
$
|
1.8
|
$
|
332.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
Pepco
Holdings has contractual commitments ensuring the performance and related
payments of Conectiv Energy and Pepco Energy Services to counterparties
under routine energy sales and procurement obligations, including retail
customer load obligations of Pepco Energy Services and requirements under
BGS contracts entered into by Conectiv Energy with
ACE.
|
|
|
(b)
|
Subsidiaries
of Pepco Holdings have guaranteed residual values in excess of fair value
of certain equipment and fleet vehicles held through lease
agreements. As of December 31, 2007, obligations under the
guarantees were approximately $5.7 million. Assets leased
under agreements subject to residual value guarantees are typically for
periods ranging from 2 years to 10 years. Historically,
payments under the guarantees have not been made by the guarantor as,
under normal conditions, the contract runs to full term at which time the
residual value is minimal. As such, Pepco Holdings believes the
likelihood of payment being required under the guarantee is
remote.
|
|
|
(c)
|
Other
guarantees consist of:
|
|
|
·
|
Pepco
Holdings has guaranteed a subsidiary building lease of $2.3 million. Pepco
Holdings does not expect to fund the full amount of the exposure under the
guarantee.
|
|
|
·
|
PCI
has guaranteed facility rental obligations related to contracts entered
into by Starpower Communications, LLC, a joint venture in which PCI prior
to December 2004 had a 50% interest. As of December 31, 2007,
the guarantees cover the remaining $1.4 million in rental
obligations.
|
Pepco Holdings 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.
Energy Contract Net Asset/Liability
Activity
The following table provides detail on
changes in the net asset or liability position of the Competitive Energy
businesses (consisting of the activities of the Conectiv Energy and Pepco Energy
Services segments) with respect to energy commodity contracts from one period to
the next:
|
Roll-forward
of Mark-to-Market Energy Contract Net Assets (Liabilities)
(Dollars
are pre-tax and in millions)
|
|
|
Proprietary
Trading (a)
|
Other
Energy Commodity (b)
|
Total
|
|
|
Total
Marked-to-Market (MTM) Energy Contract Net
|
$ -
|
$(64.3)
|
$(64.3)
|
|
|
Total
change in unrealized fair value
|
-
|
8.2
|
8.2
|
|
|
Reclassification
to realized at settlement of contracts
|
-
|
73.9
|
73.9
|
|
|
Effective
portion of changes in fair value - recorded
in
Other Comprehensive Income
|
-
|
2.8
|
2.8
|
|
|
Ineffective
portion of changes in fair value -
recorded
in earnings
|
-
|
(2.5)
|
(2.5)
|
|
|
Total
MTM Energy Contract Net Assets
|
$ -
|
$ 18.1
|
$ 18.1
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
Current
Assets (other current assets)
|
|
|
$ 44.2
|
|
|
Noncurrent
Assets (other assets)
|
|
|
24.6
|
|
|
Total
MTM Energy Contract Assets
|
|
|
68.8
|
|
|
Current
Liabilities (other current liabilities)
|
|
|
(23.0)
|
|
|
Noncurrent
Liabilities (other liabilities)
|
|
|
(27.7)
|
|
|
Total
MTM Energy Contract Liabilities
|
|
|
(50.7)
|
|
|
Total
MTM Energy Contract Net Assets
|
|
|
$ 18.1
|
|
|
|
|
|
|
|
|
(a)
|
PHI
does not engage in proprietary trading
activities.
|
|
(b)
|
Includes
all SFAS No. 133 hedge activity and non-proprietary trading activities
marked-to-market through earnings.
|
PHI uses its best estimates to
determine the fair value of the commodity and derivative contracts that its
Competitive Energy businesses hold and sell. The fair values in each
category presented below reflect forward prices and volatility factors as of
December 31, 2007 and are subject to change as a result of changes in these
factors:
|
Maturity
and Source of Fair Value of Mark-to-Market
Energy
Contract Net Assets (Liabilities)
(Dollars
are pre-tax and in millions)
|
|
|
|
|
|
|
Maturities (a)
|
|
|
|
Source of Fair
Value
|
2008
|
2009
|
2010
|
2011
and
Beyond
|
Total
Fair
Value
|
|
|
Proprietary
Trading
|
|
|
|
|
|
|
|
Actively
Quoted (i.e., exchange-traded) prices
|
$ -
|
$ -
|
$ -
|
$ -
|
$ -
|
|
|
Prices
provided by other external sources
|
-
|
-
|
-
|
-
|
-
|
|
|
Modeled
|
-
|
-
|
-
|
-
|
-
|
|
|
Total
|
$ -
|
$ -
|
$ -
|
$ -
|
$ -
|
|
|
Other Energy
Commodity, net (b)
|
|
|
|
|
|
|
|
Actively
Quoted (i.e., exchange-traded) prices
|
$(15.0)
|
$ 10.0
|
$ 3.2
|
$ .2
|
$ (1.6)
|
|
|
Prices
provided by other external sources (c)
|
23.7
|
(8.4)
|
4.4
|
-
|
19.7
|
|
|
Modeled
|
-
|
-
|
-
|
-
|
-
|
|
|
Total
|
$ 8.7
|
$ 1.6
|
$ 7.6
|
$ .2
|
$18.1
|
|
|
|
|
|
|
|
|
|
|
(a)
|
Indicated
maturity is based on contract settlement or delivery
date(s).
|
|
(b)
|
Includes
all SFAS No. 133 hedge activity and non-proprietary trading activities
marked-to-market through Accumulated Other Comprehensive Income or on the
Statements of earnings, as
required.
|
|
(c)
|
Prices
provided by other external sources reflect information obtained from
over-the-counter brokers, industry services, or multiple-party on-line
platforms.
|
Contractual Arrangements with Credit
Rating Triggers or Margining Rights
Under certain contractual arrangements
entered into by PHI’s subsidiaries in connection with Competitive Energy
business and other transactions, the subsidiary may be required to provide cash
collateral or letters of credit as security for its contractual obligations if
the credit ratings of 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,
2007, PHI estimates that if a one level downgrade in the credit rating of PHI
and each of its relevant subsidiaries were to occur, the additional aggregate
cash collateral or letters of credit amount required would be $339.0
million. PHI believes that it and its utility subsidiaries maintain
adequate short-term funding sources in the event the additional collateral or
letters of credit are required. See “Sources of Capital -- Short-Term
Funding Sources.”
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,
2007,
Pepco Holdings’ subsidiaries engaged in Competitive Energy activities and
Default Electricity Supply activities provided net cash collateral in the amount
of $91.2 million in connection with these activities.
Environmental Remediation
Obligations
PHI’s accrued liabilities as of
December 31, 2007 include approximately $18.4 million, of which
$5.7 million is expected to be incurred in 2008, for potential
environmental cleanup and other costs related to sites at which an operating
subsidiary is a potentially responsible party (PRP), is alleged to be a
third-party contributor, or has made a decision to clean up contamination on its
own property. For information regarding projected expenditures for
environmental control facilities, see Item 1 “Business -- Environmental
Matters.” The most significant environmental remediation obligations
as of December 31, 2007, were:
|
|
·
|
$4.7 million,
of which $1.2 million is expected to be incurred in 2008, 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 was
sold in June 2001.
|
|
·
|
$4.9 million
in environmental remediation costs, of which $1.3 million is expected
to be incurred in 2008, payable by Conectiv Energy associated with the
Deepwater generating facility.
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$3.8 million
for environmental remediation costs related to former manufactured gas
plant (MGP) operations at a Cambridge, Maryland site on DPL-owned
property, adjacent property and the adjacent Cambridge Creek, all of which
is expected to be incurred in 2008.
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$1.7 million
in connection with Pepco’s liability for a remedy at the Metal
Bank/Cottman Avenue site.
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$1.4 million,
of which approximately $260,000 is expected to be incurred in 2008,
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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$735,000,
of which approximately $65,000 is expected to be incurred in 2008, payable
by Pepco for long-term monitoring associated with a pipeline oil release
that occurred in 2000.
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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, securities issuances 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 efficient 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.
Internally Generated Cash
The primary source of Pepco Holdings’
internally generated funds is the cash flow generated by its regulated utility
subsidiaries in the Power Delivery business. Additional sources of
funds include cash flow generated from its non-regulated subsidiaries and the
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
lines of credit. Proceeds from short-term borrowings are used
primarily to meet working capital needs but may also be used to fund temporarily
long-term capital requirements.
Pepco Holdings maintains an ongoing
commercial paper program of up to $875 million. Pepco, DPL, and ACE
have ongoing commercial paper programs of up to $500 million, up to
$275 million, and up to $250 million, respectively. The
commercial paper can be issued with maturities of up to 270 days.
PHI, Pepco, DPL and ACE maintain a
credit facility which supports the issuance of commercial paper and is available
to provide for short-term liquidity needs.
The aggregate borrowing limit under the
facility is $1.5 billion, all or any portion of which may be used to obtain
loans or to issue letters of credit. PHI’s credit limit under the facility is
$875 million. The credit limit of each of Pepco, DPL and ACE is the lesser of
$500 million and the maximum amount of debt the company is permitted to have
outstanding by its regulatory authorities, except that the aggregate amount of
credit used by Pepco, DPL and ACE at any given time collectively may not exceed
$625 million. The interest rate payable by each company on utilized funds is
based on the prevailing prime rate or Eurodollar rate, plus a margin that varies
according to the credit rating of the borrower. 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 $150 million. Any swingline loan
must be repaid by the borrower within seven days of receipt thereof. All
indebtedness incurred under the facility is unsecured.
The facility commitment expiration date
is May 5, 2012, with each company having the right to elect to have 100% of the
principal balance of the loans outstanding on the expiration date continued as
non-revolving term loans for a period of one year from such expiration
date.
The facility is intended to serve
primarily as a source of liquidity to support the commercial paper programs of
the respective companies. The companies also are permitted to use the facility
to borrow funds for general corporate purposes and issue letters of credit. In
order for a borrower to use the facility, certain representations and warranties
made by the borrower at the time the credit agreement was entered into also must
be true at the time the facility is utilized, and the borrower must be in
compliance with specified covenants, including the financial covenant described
below. However, a material adverse change in the borrower’s
business,
property,
and results of operations or financial condition subsequent to the entry into
the credit agreement is not a condition to the availability of credit under the
facility. Among the covenants to which each of the companies is subject are (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 certain trust
preferred securities and deferrable interest subordinated debt from the
definition of total indebtedness (not to exceed 15% of total capitalization),
(ii) a restriction on sales or other dispositions of assets, other than sales
and dispositions permitted by the credit agreement, and (iii) a restriction on
the incurrence of liens on the assets of a borrower or any of its significant
subsidiaries other than liens permitted by the credit agreement. The credit
agreement does not include any rating triggers.
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 both debt and equity
securities by the principal subsidiaries of PHI requires 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 District of Columbia Public Service Commission (DCPSC) and
MPSC. DPL’s long-term financing activities are subject to
authorization by MPSC and the Delaware Public Service Commission
(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 New Jersey Board of Public Utilities
(NJBPU). Each utility, through periodic filings with the state public
service commission(s) having jurisdiction over its financing activities,
typically maintains standing authority sufficient to cover its projected
financing needs over a multi-year period.
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. Because Conectiv Energy
and Pepco Energy Services also qualify as public utilities under the FPA and are
not regulated by a state utility commission, FERC approval would be required for
the issuance of securities by those companies.
To the extent FERC approval is required
for the issuance of securities by PHI and its subsidiaries, the companies, in
accordance with regulations adopted by FERC, are relying on
authority
granted in a financing order issued by the Securities and Exchange Commission
prior to the repeal of Public Utility Holding Company Act 1935 (the Financing
Order), which extends through June 30, 2008. Prior to June 30, 2008,
PHI’s utility subsidiaries will file for new financing authority for the
issuance of securities for which FERC approval is required.
Under the Financing Order, Pepco
Holdings is authorized to operate a system money pool. 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. After expiration of the Financing
Order, PHI and its subsidiaries expect to engage in intra-system cash management
programs such as the money pool under a blanket authorization adopted by
FERC.
REGULATORY
AND OTHER MATTERS
Proceeds
from Settlement of Mirant Bankruptcy Claims
In 2000, Pepco sold substantially all
of its electricity generating assets to Mirant. In 2003, Mirant
commenced a voluntary bankruptcy proceeding in which it sought to reject certain
obligations that it had undertaken in connection with the asset
sale. As part of the asset sale, Pepco entered into the
TPAs. Under a settlement to avoid the rejection by Mirant of its
obligations under the TPAs in the bankruptcy proceeding, the terms of the TPAs
were modified to increase the purchase price of the energy and capacity supplied
by Mirant and Pepco received the TPA Claim. In December 2005, Pepco
sold the TPA Claim, plus the right to receive accrued interest thereon, to an
unaffiliated third party for $112.5 million. In addition, Pepco
received proceeds of $.5 million in settlement of an asbestos claim against
the Mirant bankruptcy estate. After customer sharing, Pepco recorded
a pre-tax gain of $70.5 million from the settlement of these
claims.
In connection with the asset sale,
Pepco and Mirant also entered into a “back-to-back” arrangement, whereby Mirant
agreed to purchase from Pepco the 230 megawatts of electricity and capacity that
Pepco is obligated to purchase annually through 2021 from Panda under the Panda
PPA at the purchase price Pepco is obligated to pay to Panda. As part
of the further settlement of Pepco’s claims against Mirant arising from the
Mirant bankruptcy, Pepco agreed not to contest the rejection by Mirant of its
obligations under the “back-to-back” arrangement in exchange for the payment by
Mirant of damages corresponding to the estimated amount by which the purchase
price that Pepco is obligated to pay Panda for the energy and capacity exceeded
the market price. In 2007, Pepco received as damages
$413.9 million in net proceeds from the sale of shares of Mirant common
stock issued to it by Mirant. These funds are being accounted for as
restricted cash based on management’s intent to use such funds, and any
interest
earned
thereon, for the sole purpose of paying for the future above-market capacity and
energy purchase costs under the Panda PPA. Correspondingly, a
regulatory liability has been established in the same amount to help offset the
future above-market capacity and energy purchase costs. This
restricted cash has been classified as a non-current asset to be consistent with
the classification of the non-current regulatory liability, and any changes in
the balance of this restricted cash, including interest on the invested funds,
are being accounted for as operating cash flows.
As of December 31, 2007, the balance of
the restricted cash account was $417.3 million. Based on a
reexamination of the costs of the Panda PPA in light of current and projected
wholesale market conditions conducted in the fourth quarter of 2007, Pepco
determined that, principally due to increases in wholesale capacity prices, the
present value above-market cost of the
Panda PPA over the term of the agreement is expected to be significantly less than
the current amount of the restricted cash account
balance. Accordingly, on February 22, 2008, Pepco filed applications
with the DCPSC and the MPSC requesting orders directing Pepco to maintain
$320 million in the restricted cash account and to use that cash, and any
future earnings on the cash, for the sole purpose of paying the future
above-market cost of the Panda PPA (or, in the alternative, to fund a transfer
or assignment of the remaining obligations under the Panda PPA to a third
party). Pepco also requested that the order provide that any cash
remaining in the account at the conclusion of the Panda PPA be refunded to
customers and that any shortfall be recovered from customers. Pepco
further proposed that the excess proceeds remaining from the settlement
(approximately $94.6 million, representing the amount by which the
regulatory liability of $414.6 million at December 31, 2007 exceeded
$320 million) be shared approximately equally with its customers in
accordance with the procedures previously approved by each commission for the
sharing of the proceeds received by Pepco from the sale to Mirant of its
generating assets. The regulatory liability of $414.6 million at
December 31, 2007 differs from the restricted cash amount of $417.3 million
on that date, in part, because the regulatory liability has been reduced for the
portion of the December 2007 Panda charges in excess of market that had not yet
been paid from the restricted cash account. The amount of the
restricted cash balance that Pepco is permitted to retain will be recorded as
earnings upon approval of the sharing arrangement by the respective
commissions. At this time, Pepco cannot predict the outcome of these
proceedings.
In settlement of other damages claims
against Mirant, Pepco in 2007 also received a settlement payment in the amount
of $70.0 million. Of this amount (i) $33.4 million was
recorded as a reduction in operating expenses, (ii) $21.0 million was
recorded as a reduction in a net pre-petition receivable claim from Mirant,
(iii) $15.0 million was recorded as a reduction in the capitalized costs of
certain property, plant and equipment and (iv) $.6 million was recorded as
a liability to reimburse a third party for certain legal costs associated with
the settlement.
Rate
Proceedings
In electric service distribution base
rate cases filed by Pepco in the District of Columbia and Maryland, and by DPL
in Maryland, and pending in 2007, Pepco and DPL proposed the adoption of a BSA
for retail customers. Under the BSA, customer delivery rates are
subject to adjustment (through a surcharge or credit mechanism), depending on
whether actual distribution revenue per customer exceeds or falls short of the
approved revenue-per-customer amount. The BSA will increase rates if
actual distribution revenues fall below the level approved by the applicable
commission and will decrease rates if actual distribution revenues are above the
approved level. The result will be that, over time, the utility would
collect its authorized
revenues
for distribution deliveries. As a consequence, a BSA “decouples”
revenue from unit sales consumption and ties the growth in revenues to the
growth in the number of customers. Some advantages of the BSA are
that it (i) eliminates revenue fluctuations due to weather and changes in
customer usage patterns and, therefore, provides for more predictable utility
distribution revenues that are better aligned with costs, (ii) provides for
more reliable fixed-cost recovery, (iii) tends to stabilize customers’
delivery bills, and (iv) removes any disincentives for the regulated
utilities to promote energy efficiency programs for their customers, because it
breaks the link between overall sales volumes and delivery
revenues. The status of the BSA proposals in each of the
jurisdictions is described below in discussion of the respective base rate
proceedings.
On September 4, 2007, DPL submitted its
2007 GCR filing to the DPSC. The GCR permits DPL to recover its gas
procurement costs through customer rates. On September 18, 2007, the
DPSC issued an initial order approving a 5.7% decrease in the level of the GCR,
which became effective November 1, 2007, subject to refund and pending final
DPSC approval after evidentiary hearings.
In December 2006, Pepco submitted an
application to the DCPSC to increase electric distribution base rates, including
a proposed BSA. The application to the DCPSC requested an annual
increase of approximately $46.2 million or an overall increase of 13.5%,
reflecting a proposed return on equity (ROE) of 10.75%. In the
alternative, the application requested an annual increase of $50.5 million
or an overall increase of 14.8%, reflecting an ROE of 11.00%, if the BSA were
not approved. Subsequently, Pepco reduced its annual revenue increase
request to $43.4 million (including a proposed BSA) and $47.9 million
(if the BSA were not approved).
On January 30, 2008, the DCPSC approved
a revenue requirement increase of approximately $28.3 million, based on an
authorized return on rate base of 7.96%, including a 10% ROE. The
rate increase is effective February 20, 2008. The DCPSC, while
finding the BSA to be an appropriate ratemaking concept, cited potential
statutory problems in the DCPSC’s ability to implement the BSA. The
DCPSC stated that it intends to issue an order to establish a Phase II
proceeding to consider these implementation issues.
On July 19, 2007, the MPSC issued
orders in the electric service distribution rate cases filed by DPL and Pepco,
each of which included approval of a BSA. The DPL order approved an
annual increase in distribution rates of approximately $14.9 million
(including a decrease in annual depreciation expense of approximately
$.9 million). The Pepco order approved an annual increase in
distribution rates of approximately $10.6 million (including a decrease in
annual depreciation expense of approximately $30.7 million). In
each case, the approved distribution rate reflects an ROE of
10.0%. The orders each provided that the rate increases are effective
as of June 16, 2007, and will remain in effect for an initial period of nine
months from the date of the order (or until April 19, 2008). These
rates are subject to a Phase II proceeding in which the MPSC will consider the
results of audits of each company’s cost allocation manual, as filed
with
the MPSC,
to determine whether a further adjustment to the rates is
required. Hearings for the Phase II proceeding are scheduled for
mid-March 2008.
On June 1, 2007, ACE filed with the
NJBPU an application for permission to decrease the Non Utility Generation
Charge (NGC) and increase components of its Societal Benefits Charge (SBC) to be
collected from customers for the period October 1, 2007 through
September 30, 2008. The proposed changes are designed to effect
a true-up of the actual and estimated costs and revenues collected through the
current NGC and SBC rates through September 30, 2007 and, in the case of the
SBC, forecasted costs and revenues for the period October 1, 2007 through
September 30, 2008.
As of December 31, 2007, the NGC, which
is intended primarily to recover the above-market component of payments made by
ACE under non-utility generation contracts and stranded costs associated with
those commitments, had an over-recovery balance of
$224.3 million. The filing proposed that the estimated NGC
balance as of September 30, 2007 in the amount of $216.2 million, including
interest, be amortized and returned to ACE customers over a four-year period,
beginning October 1, 2007.
As of December 31, 2007, the SBC, which
is intended to allow ACE to recover certain costs involved with various
NJBPU-mandated social programs, had an under-recovery of approximately
$20.9 million, primarily due to increased costs associated with funding the
New Jersey Clean Energy Program. In addition, ACE has requested an
increase to the SBC to reflect the funding levels approved by the NJBPU of $20.4
million for the period October 1, 2007 through September 30, 2008, bringing to
$40 million the total recovery requested for the period October 1,
2007 to September 30, 2008 (based upon actual data through August
2007).
The net impact of the proposed
adjustments to the NGC and the SBC, including associated changes in sales and
use tax, is an overall rate decrease of approximately $129.9 million for
the period October 1, 2007 through September 30, 2008 (based upon actual data
through August 2007). The proposed adjustments and the corresponding
changes in customer rates are subject to the approval of the
NJBPU. If approved and implemented, ACE anticipates that the revised
rates will remain in effect until September 30, 2008, subject to an annual
true-up and change each year thereafter. The proposed adjustments and
the corresponding changes in customer rates remain under review by the NJBPU and
have not yet been implemented.
ACE
Restructuring Deferral Proceeding
Pursuant to orders issued by the NJBPU
under the New Jersey Electric Discount and Energy Competition Act (EDECA),
beginning August 1, 1999, ACE was obligated to provide BGS to retail electricity
customers in its service territory who did not elect to purchase electricity
from a competitive supplier. For the period August 1, 1999 through
July 31, 2003, ACE’s aggregate costs that it was allowed to recover from
customers exceeded its aggregate revenues from supplying BGS. These
under-recovered costs were partially offset by a $59.3 million deferred
energy cost liability existing as of July 31, 1999 (LEAC Liability) related to
ACE’s Levelized Energy Adjustment Clause and ACE’s Demand Side Management
Programs. ACE established a regulatory asset in an amount equal to
the balance of under-recovered costs.
In August 2002, ACE filed a petition
with the NJBPU for the recovery of approximately $176.4 million in actual
and projected deferred costs relating to the provision of BGS and other
restructuring related costs incurred by ACE over the four-year period August 1,
1999 through July 31, 2003, net of the $59.3 million offset for the
LEAC Liability. The petition also requested that ACE’s rates be reset
as of August 1, 2003 so that there would be no under-recovery of costs embedded
in the rates on or after that date. The increase sought represented
an overall 8.4% annual increase in electric rates.
In July 2004, the NJBPU issued a final
order in the restructuring deferral proceeding confirming a July 2003 summary
order, which (i) permitted ACE to begin collecting a portion of the deferred
costs and reset rates to recover on-going costs incurred as a result of EDECA,
(ii) approved the recovery of $125 million of the deferred balance over a
ten-year amortization period beginning August 1, 2003, (iii) transferred to
ACE’s then pending base rate case for further consideration approximately
$25.4 million of the deferred balance (the base rate case ended in a
settlement approved by the NJBPU in May 2005, the result of which is that any
net rate impact from the deferral account recoveries and credits in future years
will depend in part on whether rates associated with other deferred accounts
considered in the case continue to generate over-collections relative to costs),
and (iv) estimated the overall deferral balance as of July 31, 2003 at
$195.0 million, of which $44.6 million was disallowed recovery by
ACE. Although ACE believes the record does not justify the level of
disallowance imposed by the NJBPU in the final order, the $44.6 million of
disallowed incurred costs were reserved during the years 1999 through 2003
(primarily 2003) through charges to earnings, primarily in the operating expense
line item “deferred electric service costs,” with a corresponding reduction in
the regulatory asset balance sheet account. In 2005, an additional
$1.2 million in interest on the disallowed amount was identified and
reserved by ACE. In August 2004, ACE filed a notice of appeal with
respect to the July 2004 final order with the Appellate Division of the Superior
Court of New Jersey (the Appellate Division), which hears appeals of the
decisions of New Jersey administrative agencies, including the
NJBPU. On August 9, 2007, the Appellate Division, citing deference to
the factual and policy findings of the NJBPU, affirmed the NJBPU’s decision in
its entirety, rejecting challenges from ACE and the Division of Rate
Counsel. On September 10, 2007, ACE filed an application for
certification to the New Jersey Supreme Court. On January 15, 2008,
the New Jersey Supreme Court denied ACE’s application for
certification. Because the full amount at issue in this proceeding
was previously reserved by ACE, there will be no further financial statement
impact to ACE.
Divestiture
Cases
Final briefs on Pepco’s District of
Columbia divestiture proceeds sharing application were filed with the DCPSC in
July 2002 following an evidentiary hearing in June 2002. That
application was filed to implement a provision of Pepco’s DCPSC-approved
divestiture settlement that provided for a sharing of any net proceeds from the
sale of Pepco’s generation-related assets. One of the principal
issues in the case is whether Pepco should be required to share with customers
the excess deferred income taxes (EDIT) and accumulated deferred investment tax
credits (ADITC) associated with the sold assets and, if so, whether such sharing
would violate the normalization provisions of the Internal Revenue Code (IRC)
and its implementing regulations. As of December 31, 2007, the
District of Columbia allocated portions
of EDIT
and ADITC associated with the divested generating assets were approximately
$6.5 million and $5.8 million, respectively.
Pepco believes that a sharing of EDIT
and ADITC would violate the Internal Revenue Service (IRS) normalization
rules. Under these rules, Pepco could not transfer the EDIT and the
ADITC benefit to customers more quickly than on a straight line basis over the
book life of the related assets. Since the assets are no longer owned by Pepco,
there is no book life over which the EDIT and ADITC can be
returned. If Pepco were required to share EDIT and ADITC and, as a
result, the normalization rules were violated, Pepco would be unable to use
accelerated depreciation on District of Columbia allocated or assigned
property. In addition to sharing with customers the
generation-related EDIT and ADITC balances, Pepco would have to pay to the IRS
an amount equal to Pepco’s District of Columbia jurisdictional
generation-related ADITC balance ($5.8 million as of December 31, 2007), as
well as its District of Columbia jurisdictional transmission and
distribution-related ADITC balance ($4.0 million as of December 31, 2007)
in each case as those balances exist as of the later of the date a DCPSC order
is issued and all rights to appeal have been exhausted or lapsed, or the date
the DCPSC order becomes operative.
In March 2003, the IRS issued a notice
of proposed rulemaking (NOPR), which would allow for the sharing of EDIT and
ADITC related to divested assets with utility customers on a prospective basis
and at the election of the taxpayer on a retroactive basis. In
December 2005 a revised NOPR was issued which, among other things, withdrew the
March 2003 NOPR and eliminated the taxpayer’s ability to elect to apply the
regulation retroactively. Comments on the revised NOPR were filed in
March 2006, and a public hearing was held in April 2006. Pepco filed
a letter with the DCPSC in January 2006, in which it has reiterated that the
DCPSC should continue to defer any decision on the ADITC and EDIT issues until
the IRS issues final regulations or states that its regulations project related
to this issue will be terminated without the issuance of any
regulations. Other issues in the divestiture proceeding deal with the
treatment of internal costs and cost allocations as deductions from the gross
proceeds of the divestiture.
Pepco believes that its calculation of
the District of Columbia customers’ share of divestiture proceeds is
correct. However, depending on the ultimate outcome of this
proceeding, Pepco could be required to make additional gain-sharing payments to
District of Columbia customers, including the payments described above related
to EDIT and ADITC. Such additional payments (which, other than the
EDIT and ADITC related payments, cannot be estimated) would be charged to
expense in the quarter and year in which a final decision is rendered and could
have a material adverse effect on Pepco’s and PHI’s results of operations for
those periods. However, neither PHI nor Pepco believes that
additional gain-sharing payments, if any, or the ADITC-related payments to the
IRS, if required, would have a material adverse impact on its financial position
or cash flows.
Pepco filed its divestiture proceeds
plan application with the MPSC in April 2001. The principal issue in
the Maryland case is the same EDIT and ADITC sharing issue that has been raised
in the District of Columbia case. See the discussion above under
“Divestiture Cases -- District of Columbia.” As of December 31, 2007,
the Maryland allocated portions of EDIT and ADITC associated with the divested
generating assets were approximately $9.1 million and $10.4 million,
respectively. Other issues deal with the treatment of certain costs
as deductions from the gross proceeds of the divestiture. In November
2003, the Hearing Examiner in the
Maryland
proceeding issued a proposed order with respect to the application that
concluded that Pepco’s Maryland divestiture settlement agreement provided for a
sharing between Pepco and customers of the EDIT and ADITC associated with the
sold assets. Pepco believes that such a sharing would violate the
normalization rules (discussed above) and would result in Pepco’s inability to
use accelerated depreciation on Maryland allocated or assigned
property. If the proposed order is affirmed, Pepco would have to
share with its Maryland customers, on an approximately 50/50 basis, the Maryland
allocated portion of the generation-related EDIT ($9.1 million as of
December 31, 2007), and the Maryland-allocated portion of generation-related
ADITC. Furthermore, Pepco would have to pay to the IRS an amount
equal to Pepco’s Maryland jurisdictional generation-related ADITC balance
($10.4 million as of December 31, 2007), as well as its Maryland retail
jurisdictional ADITC transmission and distribution-related balance
($7.2 million as of December 31, 2007), in each case as those balances
exist as of the later of the date a MPSC order is issued and all rights to
appeal have been exhausted or lapsed, or the date the MPSC order becomes
operative. The Hearing Examiner decided all other issues in favor of
Pepco, except for the determination that only one-half of the severance payments
that Pepco included in its calculation of corporate reorganization costs should
be deducted from the sales proceeds before sharing of the net gain between Pepco
and customers. Pepco filed a letter with the MPSC in January 2006, in
which it has reiterated that the MPSC should continue to defer any decision on
the ADITC and EDIT issues until the IRS issues final regulations or states that
its regulations project related to this issue will be terminated without the
issuance of any regulations.
In December 2003, Pepco appealed the
Hearing Examiner’s decision to the MPSC as it relates to the treatment of EDIT
and ADITC and corporate reorganization costs. The MPSC has not issued
any ruling on the appeal and Pepco does not believe that it will do so until
action is taken by the IRS as described above. However, depending on
the ultimate outcome of this proceeding, Pepco could be required to share with
its customers approximately 50 percent of the EDIT and ADITC balances described
above in addition to the additional gain-sharing payments relating to the
disallowed severance payments. Such additional payments would be
charged to expense in the quarter and year in which a final decision is rendered
and could have a material adverse effect on results of operations for those
periods. However, neither PHI nor Pepco believes that additional
gain-sharing payments, if any, or the ADITC-related payments to the IRS, if
required, would have a material adverse impact on its financial position or cash
flows.
In connection with the divestiture by
ACE of its nuclear generating assets, the NJBPU in July 2000 preliminarily
determined that the amount of stranded costs associated with the divested assets
that ACE could recover from ratepayers should be reduced by approximately
$94.8 million, consisting of $54.1 million of accumulated deferred
federal income taxes (ADFIT) associated with accelerated depreciation on the
divested nuclear assets, and $40.7 million of current tax loss from selling
the assets at a price below the tax basis.
The $54.1 million in deferred
taxes associated with the divested assets’ accelerated depreciation, however, is
subject to the normalization rules. Due to uncertainty under federal
tax law regarding whether the sharing of federal income tax benefits associated
with the divested assets, including ADFIT related to accelerated depreciation,
with ACE’s customers would violate the normalization rules, ACE submitted a
request to the IRS for a Private Letter Ruling
(PLR) to
clarify the applicable law. The NJBPU delayed its final determination
of the amount of recoverable stranded costs until after the receipt of the
PLR.
On May 25, 2006, the IRS issued the PLR
in which it stated that returning to ratepayers any of the unamortized ADFIT
attributable to accelerated depreciation on the divested assets after the sale
of the assets by means of a reduction of the amount of recoverable stranded
costs would violate the normalization rules.
On June 9, 2006, ACE submitted a letter
to the NJBPU, requesting that the NJBPU conduct proceedings to finalize the
determination of the stranded costs associated with the sale of ACE’s nuclear
assets in accordance with the PLR. In the absence of an NJBPU action
regarding ACE’s request, on June 22, 2007, ACE filed a motion requesting that
the NJBPU issue an order finalizing the determination of such stranded costs in
accordance with the PLR. On October 24, 2007, the NJBPU approved a
stipulation resolving the ADFIT issue and issued a clarifying order, which
concludes that the $94.8 million in stranded cost reduction, including the
$54.1 million in ADFIT, does not violate the IRS normalization
rules. In explaining this result, the NJBPU stated that (i) its
earlier orders determining ACE’s recoverable stranded costs “net of tax” did not
cause ADFIT associated with certain divested nuclear assets to reduce stranded
costs otherwise recoverable from ACE’s ratepayers, and (ii) because the
Market Transition Charge-Tax component of the stranded cost recovery was
intended by the NJBPU to gross-up “net of tax” stranded costs, thereby ensuring
and establishing that the ADFIT balance was not flowed through to ratepayers,
the normalization rules were not violated.
Default
Electricity Supply Proceedings
Virginia
In June 2007, the Virginia State
Corporation Commission (VSCC) denied DPL’s request for an increase in its rates
for Default Service for the period July 1, 2007 to May 31, 2008. DPL
appealed in both state and federal courts. Those appeals have been
dismissed in light of the closing of the sale of DPL's Virginia electric
operations as described below under the heading “DPL Sale of Virginia
Operations.”
ACE
Sale of B.L. England Generating Facility
On February 8, 2007, ACE completed the
sale of the B.L. England generating facility to RC Cape May Holdings, LLC (RC
Cape May), an affiliate of Rockland Capital Energy Investments, LLC, for which
it received proceeds of approximately $9 million. At the time of
the sale, RC Cape May and ACE agreed to submit to arbitration the issue of
whether RC Cape May, under the terms of the purchase agreement, must pay to ACE
an additional $3.1 million as part of the purchase price. On February
26, 2008, the arbitrators issued a decision awarding $3.1 million to ACE, plus
interest, attorneys’ fees and costs, for a total award of approximately $4.2
million.
On July 18, 2007, ACE received a claim
for indemnification from RC Cape May under the purchase agreement. RC
Cape May contends that one of the assets it purchased, a contract for terminal
services (TSA) between ACE and Citgo Asphalt Refining Co. (Citgo), has been
declared by Citgo to have been terminated due to a failure by ACE to renew the
contract in a timely manner. RC Cape May has commenced an arbitration
proceeding against Citgo seeking a determination that the TSA remains in effect
and has notified ACE of the proceeding. In
addition,
RC Cape May has asserted a claim for indemnification from ACE in the amount of
$25 million if the TSA is held not to be enforceable against
Citgo. While ACE believes that it has defenses to the indemnification
under the terms of the purchase agreement, should the arbitrator rule that the
TSA has terminated, the outcome of this matter is uncertain. ACE
notified RC Cape May of its intent to participate in the pending
arbitration.
The sale of B.L. England will not
affect the stranded costs associated with the plant that already have been
securitized. ACE anticipates that approximately $9 million to $10
million of additional regulatory assets related to B.L. England may, subject to
NJBPU approval, be eligible for recovery as stranded
costs. Approximately $47 million in emission allowance credits
associated with B. L. England were monetized for the benefit of ACE’s ratepayers
pursuant to the NJBPU order approving the sale. Net proceeds from the
sale of the plant and monetization of the emission allowance credits, estimated
to be $32.2 million as of December 31, 2007, will be credited to ACE’s
ratepayers in accordance with the requirements of EDECA and NJBPU
orders. The appropriate mechanism for crediting the net proceeds from
the sale of the plant and the monetized emission allowance credits to ratepayers
is being determined in a proceeding that is currently pending before the
NJBPU.
DPL
Sale of Virginia Operations
On January 2, 2008, DPL completed (i)
the sale of its retail electric distribution business on the Eastern Shore of
Virginia to A&N Electric Cooperative (A&N) for a purchase price of
approximately $45.2 million, after closing adjustments, and (ii) the
sale of its wholesale electric transmission business located on the Eastern
Shore of Virginia to Old Dominion Electric Cooperative (ODEC) for a purchase
price of approximately $5.4 million, after closing
adjustments. Each of A&N and ODEC assumed certain post-closing
liabilities and unknown pre-closing liabilities related to the respective assets
they are purchasing (including, in the A&N transaction, most environmental
liabilities), except that DPL remained liable for unknown pre-closing
liabilities if they become known within six months after the January 2, 2008
closing date. These sales are expected to result in an immaterial
financial gain to DPL that will be recorded in the first quarter of
2008.
Pepco
Energy Services Deactivation of Power Plants
Pepco Energy Services owns and operates
two oil-fired power plants. The power plants are located in
Washington, D.C. and have a generating capacity rating of approximately 790
MW. Pepco Energy Services sells the output of these plants into the
wholesale market administered by PJM. In February 2007, Pepco Energy
Services provided notice to PJM of its intention to deactivate these
plants. In May 2007, Pepco Energy Services deactivated one combustion
turbine at its Buzzard Point facility with a generating capacity of
approximately 16 MW. Pepco Energy Services currently plans to
deactivate the balance of both plants by May 2012. PJM has informed
Pepco Energy Services that these facilities are not expected to be needed for
reliability after that time, but that its evaluation is dependent on the
completion of transmission upgrades. Pepco Energy Services’ timing
for deactivation of these units, in whole or in part, may be accelerated or
delayed based on the operating condition of the units, economic conditions, and
reliability considerations. Prior to deactivation of the plants,
Pepco Energy Services may incur deficiency charges imposed by PJM at a rate up
to two times the capacity payment price that the plants
receive. Deactivation is not expected to have a material impact on
PHI’s financial condition, results of operations or cash flows.
General
Litigation
During 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 are
not entirely clear, it appears that each plaintiff sought $2 million in
compensatory damages and $4 million in punitive damages from each
defendant.
Since the initial filings in 1993,
additional individual suits have been filed against Pepco, and significant
numbers of cases have been dismissed. As a result of two motions to
dismiss, numerous hearings and meetings and one motion for summary judgment,
Pepco has had approximately 400 of these cases successfully dismissed with
prejudice, either voluntarily by the plaintiff or by the court. As of
December 31, 2007, there are approximately 180 cases still pending against Pepco
in the State Courts of Maryland, of which approximately 90 cases were filed
after December 19, 2000, and were tendered to Mirant for defense and
indemnification pursuant to the terms of the Asset Purchase and Sale Agreement
between Pepco and Mirant under which Pepco sold its generation assets to Mirant
in 2000.
While the aggregate amount of monetary
damages sought in the remaining suits (excluding those tendered to Mirant) is
approximately $360 million, PHI and Pepco believe the amounts claimed by
current plaintiffs are greatly exaggerated. The amount of total
liability, if any, and any related insurance recovery cannot be determined at
this time; however, based on information and relevant circumstances known at
this time, neither PHI nor Pepco believes these suits will have a material
adverse effect on its financial position, results of operations or cash
flows. However, if an unfavorable decision were rendered against
Pepco, it could have a material adverse effect on Pepco’s and PHI’s financial
position, results of operations or cash flows.
Cash
Balance Plan Litigation
In 1999, Conectiv established a cash
balance retirement plan to replace defined benefit retirement plans then
maintained by ACE and DPL. Following the acquisition by Pepco of
Conectiv, this plan became the Conectiv Cash Balance Sub-Plan within the PHI
Retirement Plan. In September 2005, three management employees of PHI
Service Company filed suit in the U.S. District Court for the District of
Delaware (the Delaware District Court) against the PHI Retirement Plan, PHI and
Conectiv (the PHI Parties), alleging violations of ERISA, on behalf of a class
of management employees who did not have enough age and service when the Cash
Balance Sub-Plan was implemented in 1999 to assure that their accrued benefits
would be calculated pursuant to the terms of the predecessor plans sponsored by
ACE and DPL. A fourth plaintiff was added to the case to represent
DPL-legacy employees who were not eligible for grandfathered
benefits.
The plaintiffs challenged the design of
the Cash Balance Sub-Plan and sought a declaratory judgment that the Cash
Balance Sub-Plan was invalid and that the accrued benefits of
each
member of the class should be calculated pursuant to the terms of the
predecessor plans. Specifically, the complaint alleged that the use
of a variable rate to compute the plaintiffs’ accrued benefit under the Cash
Balance Sub-Plan resulted in reductions in the accrued benefits that violated
ERISA. The complaint also alleged that the benefit accrual rates and
the minimal accrual requirements of the Cash Balance Sub-Plan violated ERISA as
did the notice that was given to plan participants upon implementation of the
Cash Balance Sub-Plan.
On September 19, 2007, the Delaware
District Court issued an order granting summary judgment in favor of the PHI
Parties. On October 12, 2007, the plaintiffs filed an appeal of
the decision to the U.S. Court of Appeals for the Third Circuit.
If the plaintiffs were to prevail in
this litigation, the ABO and projected benefit obligation (PBO) calculated in
accordance with SFAS No. 87 each would increase by approximately
$12 million, assuming no change in benefits for persons who have already
retired or whose employment has been terminated and using actuarial valuation
data as of the time the suit was filed. The ABO represents the
present value that participants have earned as of the date of
calculation. This means that only service already worked and
compensation already earned and paid is considered. The PBO is
similar to the ABO, except that the PBO includes recognition of the effect that
estimated future pay increases would have on the pension plan
obligation.
Environmental
Litigation
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. 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. Although penalties
assessed for violations of environmental laws and regulations are not
recoverable from customers of the operating utilities, environmental clean-up
costs incurred by Pepco, DPL and ACE would be included by each company in its
respective cost of service for ratemaking purposes.
Cambridge, Maryland
Site. In July 2004, DPL entered into an administrative consent order
(ACO) with the Maryland Department of the Environment (MDE) to perform a
Remedial Investigation/Feasibility Study (RI/FS) to further identify the extent
of soil, sediment and ground and surface water contamination related to former
MGP operations at a Cambridge, Maryland site on DPL-owned property and to
investigate the extent of MGP contamination on adjacent property. The
MDE has approved the RI and DPL submitted a final FS to MDE on February 15,
2007. No further MDE action is required with respect to the final
FS. The costs of cleanup (as determined by the RI/FS and subsequent
negotiations with MDE) are anticipated to be approximately $3.8 million. The
remedial action to be taken by DPL will include dredging activities within
Cambridge Creek, which are expected to commence in March 2008, and soil
excavation on DPL’s and adjacent property as early as August
2008. The final cleanup costs will include protective measures to
control contaminant migration during the dredging activities and improvements to
the existing shoreline.
Delilah Road Landfill
Site. In November 1991, the New Jersey Department of
Environmental Protection (NJDEP) identified ACE as a PRP at the Delilah Road
Landfill site in Egg Harbor Township, New Jersey. In 1993, ACE, along
with other PRPs, signed an ACO with NJDEP to remediate the site. The
soil cap remedy for the site has been implemented and in August 2006, NJDEP
issued a No Further Action Letter (NFA) and Covenant Not to Sue for the
site. Among other things, the NFA requires the PRPs to monitor the
effectiveness of institutional (deed restriction) and engineering (cap) controls
at the site every two years. In September 2007, NJDEP approved the
PRP group’s petition to conduct semi-annual, rather than quarterly, ground water
monitoring for two years and deferred until the end of the two-year period a
decision on the PRP group’s request for annual groundwater monitoring
thereafter. In August 2007, the PRP group agreed to reimburse the
U.S. Environmental Protection Agency’s (EPA’s) costs in the amount of $81,400 in
full satisfaction of EPA’s claims for all past and future response costs
relating to the site (of which ACE’s share is one-third) and in October 2007,
EPA and the PRP group entered into a tolling agreement to permit the parties
sufficient time to execute a final settlement agreement. This
settlement agreement will allow EPA to reopen the settlement in the event of new
information or unknown conditions at the site. Based on information
currently available, ACE anticipates that its share of additional cost
associated with this site for post-remedy operation and maintenance will be
approximately $555,000 to $600,000. ACE believes that its liability
for post-remedy operation and maintenance costs will not have a material adverse
effect on its financial position, results of operations or cash
flows.
Frontier Chemical
Site. On June 29, 2007, ACE received a letter from the New
York Department of Environmental Conservation (NYDEC) identifying ACE as a PRP
at the Frontier Chemical Waste Processing Company site in Niagara Falls, N.Y.
based on hazardous waste manifests indicating that ACE sent in excess of 7,500
gallons of manifested hazardous waste to the site. ACE has entered
into an agreement with the other parties identified as PRPs to form the PRP
group and has informed NYDEC that it has entered into good faith negotiations
with the PRP group to address ACE’s responsibility at the site. ACE
believes that its responsibility at the site will not have a material adverse
effect on its financial position, results of operations or cash
flows.
Carolina Transformer
Site. In August 2006, EPA notified each of DPL and Pepco that
they have been identified as entities that sent PCB-laden oil to be disposed at
the Carolina Transformer site in Fayetteville, North Carolina. The
EPA notification stated that, on this basis, DPL and Pepco may be
PRPs. In December 2007, DPL and Pepco agreed to enter into a
settlement agreement with EPA and the PRP group at the Carolina Transformer
site. Under the terms of the settlement, (i) Pepco and DPL each
will pay $162,000 to EPA to resolve any liability that it might have at the
site, (ii) EPA covenants not to sue or bring administrative action against
DPL and Pepco for response costs at the site, (iii) other PRP group members
release all rights for cost recovery or contribution claims they may have
against DPL and Pepco, and (iv) DPL and Pepco release all rights for cost
recovery or contribution claims that they may have against other parties
settling with EPA. The consent decree is expected to be filed with
the U.S. District Court in North Carolina in the second quarter of
2008.
Deepwater Generating
Station. On December 27, 2005, NJDEP issued a Title V
Operating Permit for Conectiv Energy’s Deepwater Generating
Station. The permit includes new limits on unit heat
input. In order to comply with these new operational limits, Conectiv
Energy restricted the output of the Deepwater Generating Station’s Unit 1 and
Unit 6. In 2006 and the first half of 2007, these restrictions
resulted in operating losses of approximately $10,000
per
operating day on Unit 6, primarily because of lost revenues due to reduced
output, and to a lesser degree because of lost revenues related to capacity
requirements of PJM. Since June 1, 2007, Deepwater Unit 6 can operate
within the heat input limits set forth in the Title V Operating Permit without
restricting output, because of technical improvements that partially corrected
the inherent bias in the continuous emissions monitoring system that had caused
recorded heat input to be higher than actual heat input. In order to
comply with the heat input limit at Deepwater Unit 1, Conectiv Energy continues
to restrict Unit 1 output, resulting in operating losses of approximately
$500,000 in the second half of 2007 and projected operating losses in 2008 of
approximately $500,000, due to penalties and lost revenues related to PJM
capacity requirements. Beyond 2008, while penalties due to PJM
capacity requirements are not expected, further operating losses due to lost
revenues related to PJM capacity requirements may continue to be
incurred. The operating losses due to reduced output on Unit 1 have
been, and are expected to continue to be, insignificant. Conectiv
Energy is challenging these heat input restrictions and other provisions of the
Title V Operating Permit for Deepwater Generating Station in the New Jersey
Office of Administrative Law (OAL). On October 2, 2007, the OAL
issued a decision granting summary decision in favor of Conectiv Energy, finding
that hourly heat input shall not be used as a condition or limit for Conectiv
Energy’s electric generating operations. On October 26, 2007, the
NJDEP Commissioner denied NJDEP’s request for interlocutory review of the OAL
order and determined that the Commissioner would review the October 2, 2007
order upon completion of the proceeding on Conectiv Energy’s other challenges to
the Deepwater Title V permit. A hearing on the remaining challenged
Title V permit provisions is scheduled for mid-April 2008.
On April 3, 2007, NJDEP issued an
Administrative Order and Notice of Civil Administrative Penalty Assessment (the
First Order) alleging that at Conectiv Energy's Deepwater Generating Station,
the maximum gross heat input to Unit 1 exceeded the maximum allowable heat input
in calendar year 2005 and the maximum gross heat input to Unit 6 exceeded the
maximum allowable heat input in calendar years 2005 and 2006. The
order required the cessation of operation of Units 1 and 6 above the alleged
permitted heat input levels, assessed a penalty of approximately
$1.1 million and requested that Conectiv Energy provide additional
information about heat input to Units 1 and 6. Conectiv Energy
provided NJDEP Units 1 and 6 calendar year 2004 heat input data on May 9, 2007,
and calendar years 1995 to 2003 heat input data on July 10, 2007. On
May 23, 2007, NJDEP issued a second Administrative Order and Notice of Civil
Administrative Penalty Assessment (the Second Order) alleging that the maximum
gross heat input to Units 1 and 6 exceeded the maximum allowable heat input in
calendar year 2004. The Second Order required the cessation of
operation of Units 1 and 6 above the alleged permitted heat input levels
and assessed a penalty of $811,600. Conectiv Energy has requested a
contested case hearing challenging the issuance of the First Order and the
Second Order and moved for a stay of the orders pending resolution of the Title
V Operating Permit contested case described above. On November 29,
2007, the OAL issued orders placing the First Order and the Second Order on the
inactive list for six months. Until the OAL decision discussed above
is final, it will not have an impact on these currently inactive enforcement
cases.
IRS
Examination of Like-Kind Exchange Transaction
In 2001, Conectiv and certain of its
subsidiaries (the Conectiv Group) were engaged in the implementation of a
strategy to divest non-strategic electric generating facilities and replace
these facilities with mid-merit electric generating capacity. As part
of this strategy, the Conectiv Group exchanged its interests in two older
coal-fired plants for the more efficient gas-fired Hay
Road II
generating facility, which was owned by an unaffiliated third
party. For tax purposes, Conectiv treated the transaction as a
“like-kind exchange” under IRC Section 1031. As a result,
approximately $88 million of taxable gain was deferred for federal income
tax purposes.
The transaction was examined by the IRS
as part of the normal Conectiv tax audit. In May 2006, the IRS issued
a revenue agent’s report (RAR) for the audit of Conectiv’s 2000, 2001 and 2002
income tax returns, in which the IRS disallowed the qualification of the
exchange under IRC Section 1031. In July 2006, Conectiv filed a
protest of this disallowance to the IRS Office of Appeals.
PHI believes that its tax position
related to this transaction is proper based on applicable statutes, regulations
and case law and is contesting the disallowance. However, there is no
absolute assurance that Conectiv’s position will prevail. If the IRS
prevails, Conectiv would be subject to additional income taxes, interest and
possible penalties. However, a portion of the denied benefit would be
offset by additional tax depreciation. PHI has accrued approximately
$4.9 million related to this matter.
As of December 31, 2007, if the IRS
were to fully prevail, the potential cash impact on PHI would be current income
tax and interest payments of approximately $31.2 million and the earnings
impact would be approximately $9.8 million in after-tax
interest.
Federal
Tax Treatment of Cross-Border Leases
PCI maintains a portfolio of
cross-border energy sale-leaseback transactions, which, as of December 31,
2007, had a book value of approximately $1.4 billion, and from which PHI
currently derives approximately $60 million per year in tax benefits in the form
of interest and depreciation deductions.
In 2005, the Treasury Department and
IRS issued Notice 2005-13 informing taxpayers that the IRS intends to challenge
on various grounds the purported tax benefits claimed by taxpayers entering into
certain sale-leaseback transactions with tax-indifferent parties (i.e.,
municipalities, tax-exempt and governmental entities), including those entered
into on or prior to March 12, 2004 (the Notice). All of PCI’s
cross-border energy leases are with tax indifferent parties and were entered
into prior to 2004. Also in 2005, the IRS published a Coordinated
Issue Paper concerning the resolution of audit issues related to such
transactions. PCI’s cross-border energy leases are similar to those
sale-leaseback transactions described in the Notice and the Coordinated Issue
Paper.
PCI’s leases have been under
examination by the IRS as part of the normal PHI tax audit. In 2006,
the IRS issued its final RAR for its audit of PHI’s 2001 and 2002 income tax
returns. In the RAR, the IRS disallowed the tax benefits claimed by
PHI with respect to these leases for those years. The tax benefits
claimed by PHI with respect to these leases from 2001 through December 31, 2007
were approximately $347 million. PHI has filed a protest against the
IRS adjustments and the unresolved audit has been forwarded to the U.S. Office
of Appeals. The ultimate outcome of this issue is uncertain; however,
if the IRS prevails, PHI would be subject to additional taxes, along with
interest and possibly penalties on the additional taxes, which could have a
material adverse effect on PHI’s financial condition, results of operations, and
cash flows. PHI believes that its tax position related to these
transactions was appropriate based on
applicable
statutes, regulations and case law, and intends to contest the adjustments
proposed by the IRS; however, there is no assurance that PHI’s position will
prevail.
In 2006, the FASB issued FASB Staff
Position (FSP) on Financial Accounting Standards (FAS) 13-2, which amends SFAS
No. 13 effective for fiscal years beginning after December 15,
2006. This amendment requires a lease to be repriced and the book
value adjusted when there is a change or probable change in the timing of tax
benefits of the lease, regardless of whether the change results in a deferral or
permanent loss of tax benefits. Accordingly, a material change in the
timing of cash flows under PHI’s cross-border leases as the result of a
settlement with the IRS would require an adjustment to the book value of the
leases and a charge to earnings equal to the repricing impact of the disallowed
deductions which could result in a material adverse effect on PHI’s financial
condition, results of operations, and cash flows. PHI believes its
tax position was appropriate and at this time does not believe there is a
probable change in the timing of its tax benefits that would require repricing
the leases and a charge to earnings.
On December 14, 2007 the U.S.
Senate passed its version of the Farm, Nutrition, and Bioenergy Act of 2007
(H.R. 2419), which contains a provision that would apply passive loss limitation
rules to leases with foreign tax indifferent parties effective for taxable years
beginning after December 31, 2006, even if the leases were entered into on
or prior to March 12, 2004. The U.S. House of Representatives
version of this proposed legislation which it passed on July 27, 2007 does
not contain any provision that would modify the current treatment of leases with
tax indifferent parties. Enactment into law of a bill that is similar
to that passed by the U.S. Senate in its current form could result in a material
delay of the income tax benefits that PHI would receive in connection with its
cross-border energy leases. Furthermore, if legislation of this type
were to be enacted, under FSP FAS 13-2, PHI would be required to adjust the book
value of the leases and record a charge to earnings equal to the repricing
impact of the deferred deductions which could result in a material adverse
effect on PHI’s financial condition, results of operations and
cash-flows. The U.S. House of Representatives and the U.S. Senate are
expected to hold a conference in the near future to reconcile the differences in
the two bills to determine the final legislation.
IRS
Mixed Service Cost Issue
During 2001, Pepco, DPL, and ACE
changed their methods of accounting with respect to capitalizable construction
costs for income tax purposes. The change allowed the companies to
accelerate the deduction of certain expenses that were previously capitalized
and depreciated. Through December 31, 2005, these accelerated
deductions generated incremental tax cash flow benefits of approximately $205
million (consisting of $94 million for Pepco, $62 million for DPL, and $49
million for ACE) for the companies, primarily attributable to their 2001 tax
returns.
In 2005, the Treasury Department
released proposed regulations that, if adopted in their current form, would
require Pepco, DPL, and ACE to change their method of accounting with respect to
capitalizable construction costs for income tax purposes for tax periods
beginning in 2005. Based on those proposed regulations, PHI in its
2005 federal tax return adopted an alternative method of accounting for
capitalizable construction costs that management believes will be acceptable to
the IRS.
At the same time as the new proposed
regulations were released, the IRS issued Revenue Ruling 2005-53, which is
intended to limit the ability of certain taxpayers to utilize the method of
accounting for income tax purposes for 2004 and prior years with respect to
capitalizable construction costs. In line with this Revenue Ruling,
the IRS RAR for the 2001 and 2002 tax returns disallowed substantially all of
the incremental tax benefits that Pepco, DPL and ACE had claimed on those
returns by requiring the companies to capitalize and depreciate certain expenses
rather than treat such expenses as current deductions. PHI’s protest
of the IRS adjustments is among the unresolved audit matters relating to the
2001 and 2002 audits pending before the Appeals Office.
In February 2006, PHI paid
approximately $121 million of taxes to cover the amount of additional taxes that
management estimated to be payable for the years 2001 through 2004 based on the
method of tax accounting that PHI, pursuant to the proposed regulations, has
adopted on its 2005 tax return. However, if the IRS is successful in
requiring Pepco, DPL and ACE to capitalize and depreciate construction costs
that result in a tax and interest assessment greater than management’s estimate
of $121 million, PHI will be required to pay additional taxes and interest only
to the extent these adjustments exceed the $121 million payment made in February
2006. It is reasonably possible that PHI’s unrecognized tax benefits
related to this issue will significantly decrease in the next 12 months as a
result of a settlement with the IRS.
CRITICAL
ACCOUNTING POLICIES
General
Pepco Holdings has identified the
following accounting policies, including 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
to its financial condition or results of operations under different conditions
or using different assumptions. Pepco Holdings has discussed the
development, selection and disclosure of each of these policies with the Audit
Committee of the Board of Directors.
Goodwill Impairment
Evaluation
Pepco Holdings believes that the
estimates involved in its goodwill impairment evaluation process represent
“Critical Accounting Estimates” because (i) they may be susceptible to change
from period to period because management is required to make assumptions and
judgments about the discounting of future cash flows, which are inherently
uncertain, (ii) actual results could vary from those used in Pepco Holdings’
estimates and the impact of such variations could be material, and (iii) the
impact that recognizing an impairment would have on Pepco Holdings’ assets and
the net loss related to an impairment charge could be material.
Pepco Holdings tests its goodwill for
impairment annually as of July 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 its carrying
amount. Substantially all of Pepco Holdings’ goodwill was generated
by Pepco’s acquisition of Conectiv in 2002 and was allocated to Pepco Holdings’
Power Delivery segment. In order to estimate the fair value of its
Power Delivery segment, Pepco Holdings discounts the estimated future cash flows
associated with the segment using a discounted cash flow model with a single
interest rate that is commensurate with the risk involved with such an
investment. The estimation of fair value is dependent on a number
of
factors,
including but not limited to interest rates, future growth assumptions,
operating and capital expenditure requirements and other factors, changes in
which could materially impact the results of impairment
testing. Pepco Holdings’ July 1, 2007 goodwill impairment
testing indicated that its goodwill balance was not impaired. A
hypothetical decrease in the Power Delivery segment’s forecasted cash flows of
10 percent would not have resulted in an impairment charge.
Long-Lived Assets Impairment
Evaluation
Pepco Holdings 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 undiscounted and discounted future cash
flows and fair values, which are inherently uncertain, (ii) actual results could
vary from those used in Pepco Holdings’ estimates and the impact of such
variations could be material, and (iii) the impact that recognizing an
impairment would have on Pepco Holdings’ assets as well as the net loss related
to an impairment charge could be material.
SFAS No. 144, “Accounting for the
Impairment or Disposal of Long-Lived Assets,” requires that certain long-lived
assets must be tested for recoverability whenever events or circumstances
indicate that the carrying amount may not be recoverable. 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,
Pepco Holdings considers historical cash flows. Pepco Holdings uses
its best 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 done consistent with the process described in assessing the fair value
of goodwill, which is discussed above.
For a discussion of PHI’s impairment
losses during 2007, refer to the “Impairment Losses” section in the accompanying
Consolidated Results of Operations discussion.
Accounting for Derivatives
Pepco Holdings believes that the
estimates involved in accounting for its derivative instruments represent
“Critical Accounting Estimates” because (i) the fair value of the instruments
are highly susceptible to changes in market value and/or interest rate
fluctuations, (ii) there are significant uncertainties in modeling techniques
used to measure fair value in certain circumstances, (iii) actual results could
vary from those used in Pepco Holdings’ estimates and the impact of such
variations could be material, and (iv) changes in fair values and market prices
could result in material impacts to Pepco Holdings’ assets, liabilities, other
comprehensive income (loss), and results of operations. See Note (2),
“Summary of Significant Accounting Policies - Accounting for Derivatives” to the
consolidated financial statements of PHI included in Item 8 for information on
PHI’s accounting for derivatives.
Pepco Holdings and its subsidiaries use
derivative instruments primarily to manage risk associated with commodity prices
and interest rates. SFAS No. 133, “Accounting for
Derivative
Instruments
and Hedging Activities,” as amended, governs
the accounting treatment for derivatives and requires that derivative
instruments be measured at fair value. 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, an
internal model is used to interpolate broker quality price
information. The same valuation methods are used to determine the
value of non-derivative, commodity exposure for risk management
purposes.
Pension and Other Postretirement
Benefit Plans
Pepco Holdings believes that the
estimates involved in reporting the costs of providing pension and other
postretirement 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 Pepco Holdings’ expected future cash
funding requirements for the plans and would have an impact on the projected
benefit obligations, the reported pension and other postretirement benefit
liability on the balance sheet, and the reported annual net periodic pension and
other postretirement benefit cost on the income statement. In terms
of quantifying the anticipated impact of a change in assumptions, Pepco Holdings
estimates that a .25% change in the discount rate used to value the benefit
obligations could result in a $5 million impact on its consolidated balance
sheets and statements of earnings. Additionally, Pepco Holdings
estimates that a .25% change in the expected return on plan assets could result
in a $4 million impact on the consolidated balance sheets and statements of
earnings and a .25% change in the assumed healthcare cost trend rate could
result in a $.5 million impact on its consolidated balance sheets and statements
of earnings. Pepco Holdings’ management consults with its actuaries
and investment consultants when selecting its plan assumptions.
Pepco Holdings follows the guidance of
SFAS No. 87, “Employers’ Accounting for Pensions,” SFAS No. 106, “Employers’
Accounting for Postretirement Benefits Other Than Pensions,” and SFAS
No. 158, “Employers’ Accounting for Defined Benefit Pension and Other
Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and
132(R)” (SFAS No. 158), when accounting for these benefits. Under these
accounting standards, assumptions are made regarding the valuation of benefit
obligations and the performance of plan assets. In accordance with these
standards, the impact of changes in these assumptions and the difference between
actual and expected or estimated results on pension and postretirement
obligations is generally recognized over the working lives of the employees who
benefit under the plans rather than immediately recognized in the statements of
earnings. Plan assets are stated at their market value as of the
measurement date, which is December 31.
Regulation of Power Delivery
Operations
The requirements of SFAS No. 71,
“Accounting for the Effects of Certain Types of Regulation,” apply to the Power
Delivery businesses of Pepco, DPL, and ACE. Pepco Holdings believes that the
judgment involved in accounting for its regulated activities represent “Critical
Accounting Estimates” because (i) a significant amount of judgment is required
(including but not limited to the interpretation of laws and regulatory
commission orders) to assess the probability of the recovery of regulatory
assets, (ii) actual results and interpretations could vary from those used in
Pepco Holdings’ estimates and the impact of
such
variations could be material, and (iii) the impact that writing off a regulatory
asset would have on Pepco Holdings’ assets and the net loss related to the
charge could be material.
Unbilled revenue represents an estimate
of revenue earned from services rendered by Pepco Holdings’ utility operations
that have not yet been billed. Pepco Holdings’ utility operations
calculate unbilled revenue using an output based methodology. This
methodology is based on the supply of electricity or gas distributed to
customers. Pepco Holdings believes that the estimates involved in its
unbilled revenue process represent “Critical Accounting Estimates” because
management is required to make assumptions and judgments about input factors
such as customer sales mix and estimated power line losses (estimates of
electricity expected to be lost in the process of its transmission and
distribution to customers), all of which are inherently uncertain and
susceptible to change from period to period, the impact of which could be
material.
Accounting for Income
Taxes
Pepco Holdings and the majority of its
subsidiaries file a consolidated federal income tax return. Pepco Holdings
accounts for income taxes in accordance with SFAS No. 109, “Accounting for
Income Taxes” and effective January 1, 2007, adopted FIN 48 “Accounting for
Uncertainty in Income Taxes”. FIN 48 clarifies the criteria for
recognition of tax benefits in accordance with SFAS No. 109, and prescribes a
financial statement recognition threshold and measurement attribute for a tax
position taken or expected to be taken in a tax return. Specifically,
it clarifies that an entity’s tax benefits must be “more likely than not” of
being sustained assuming that position will be examined by taxing authorities
with full knowledge of all relevant information prior to recording
the related tax benefit in the financial statements. If the position
drops below the “more likely than not” standard, the benefit can no longer be
recognized.
Assumptions, judgment and the use of
estimates are required in determining if the “more likely than not” standard has
been met when developing the provision for income taxes. Pepco
Holdings’ assumptions, judgments and estimates take into account current tax
laws, interpretation of current tax laws and the possible outcomes of current
and future investigations conducted by tax authorities. Pepco
Holdings has established reserves for income taxes to address potential
exposures involving tax positions that could be challenged by tax
authorities. Although Pepco Holdings believes that these assumptions,
judgments and estimates are reasonable, changes in tax laws or its
interpretation of tax laws and the resolutions of the current and any future
investigations could significantly impact the amounts provided for income taxes
in the consolidated financial statements.
Under SFAS No. 109, deferred income tax
assets and liabilities are recorded, representing future effects on income taxes
for temporary differences between the bases of assets and liabilities for
financial reporting and tax purposes. Pepco Holdings evaluates quarterly the
probability of realizing deferred tax assets by reviewing a forecast of future
taxable income and the availability of 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.
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 (2) “Summary of
Significant Accounting Policies -- Newly Adopted Accounting Standards and
Recently Issued Accounting Policies, Not Yet Adopted” to the consolidated
financial statements of PHI set forth in Item 8 of this Form 10-K.
FORWARD-LOOKING
STATEMENTS
Some of the statements contained in
this Annual Report on Form 10-K are forward-looking statements within the
meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and
are subject to the safe harbor created by the Private Securities Litigation
Reform Act of 1995. These statements include declarations regarding Pepco
Holdings’ intents, beliefs and current expectations. In some cases, you can
identify forward-looking statements by terminology such as “may,” “will,”
“should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,”
“predicts,” “potential” or “continue” or the negative of such terms or other
comparable terminology. Any forward-looking statements are not guarantees of
future performance, and actual results could differ materially from those
indicated by the forward-looking statements. Forward-looking statements involve
estimates, assumptions, known and unknown risks, uncertainties and other factors
that may cause PHI’s actual results, levels of activity, performance or
achievements to be materially different from any future results, levels of
activity, performance or achievements expressed or implied by such
forward-looking statements.
The forward-looking statements
contained herein are qualified in their entirety by reference to the following
important factors, which are difficult to predict, contain uncertainties, are
beyond Pepco Holdings’ control and may cause actual results to differ materially
from those contained in forward-looking statements:
|
|
·
|
Prevailing
governmental policies and regulatory actions affecting the energy
industry, including allowed rates of return, industry and rate structure,
acquisition and disposal of assets and facilities, operation and
construction of plant facilities, recovery of purchased power expenses,
and present or prospective wholesale and retail
competition;
|
|
|
·
|
Changes
in and compliance with environmental and safety laws and
policies;
|
|
|
·
|
Population
growth rates and demographic
patterns;
|
|
|
·
|
Competition
for retail and wholesale customers;
|
|
|
·
|
General
economic conditions, including potential negative impacts resulting from
an economic downturn;
|
|
|
·
|
Growth
in demand, sales and capacity to fulfill
demand;
|
|
|
·
|
Changes
in tax rates or policies or in rates of
inflation;
|
|
|
·
|
Changes
in accounting standards or
practices;
|
|
|
·
|
Changes
in project costs;
|
|
|
·
|
Unanticipated
changes in operating expenses and capital
expenditures;
|
|
|
·
|
The
ability to obtain funding in the capital markets on favorable
terms;
|
|
|
·
|
Rules
and regulations imposed by federal and/or state regulatory commissions,
PJM and other regional transmission organizations (New York Independent
System Operator, ISONE), the North American Electric Reliability Council
and other applicable electric reliability
organizations;
|
|
|
·
|
Legal
and administrative proceedings (whether civil or criminal) and settlements
that affect PHI’s business and
profitability;
|
|
|
·
|
Pace
of entry into new markets;
|
|
|
·
|
Volatility
in market demand and prices for energy, capacity and
fuel;
|
|
|
·
|
Interest
rate fluctuations and credit market concerns;
and
|
|
|
·
|
Effects
of geopolitical events, including the threat of domestic
terrorism.
|
Any forward-looking statements speak
only as to the date of this Annual Report and Pepco Holdings undertakes no
obligation to update any forward-looking statements to reflect events or
circumstances after the date on which such statements are made or to reflect the
occurrence of unanticipated events. New factors emerge from time to time, and it
is not possible for Pepco Holdings to predict all of such factors, nor can Pepco
Holdings assess the impact of any such factor on our business or the extent to
which any factor, or combination of factors, may cause results to differ
materially from those contained in any forward-looking statement.
The foregoing review of factors should
not be construed as exhaustive.
THIS
PAGE LEFT INTENTIONALLY BLANK.
MANAGEMENT’S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF
OPERATIONS
POTOMAC
ELECTRIC POWER COMPANY
GENERAL
OVERVIEW
Potomac Electric Power Company (Pepco)
is engaged in the transmission and distribution of electricity in Washington,
D.C. and major portions of Montgomery County and Prince George’s County in
suburban Maryland. Pepco provides Default Electricity Supply, which
is the supply of electricity at regulated rates to retail customers in its
territories who do not elect to purchase electricity from a competitive
supplier, in both the District of Columbia and Maryland. Default
Electricity Supply is known as Standard Offer Service in both the District of
Columbia and Maryland. Pepco’s service territory covers approximately
640 square miles and has a population of approximately 2.1
million. As of December 31, 2007, approximately 57% of delivered
electricity sales were to Maryland customers and approximately 43% were to
Washington, D.C. customers.
Effective June 16, 2007, the Maryland
Public Service Commission (MPSC) approved new electric service distribution base
rates for Pepco (the 2007 Maryland Rate Order). The MPSC also
approved a bill stabilization adjustment mechanism (BSA) for retail
customers. For customers to which the BSA applies, Pepco recognizes
distribution revenue based on an approved distribution charge per
customer. From a revenue recognition standpoint, the BSA thus
decouples the distribution revenue recognized in a reporting period from the
amount of power delivered during the period. This change in the
reporting of distribution revenue has the effect of eliminating changes in
customer usage (whether due to weather conditions, energy prices, energy
efficiency programs or other reasons) as a factor having an impact on reported
revenue. As a consequence, the only factors that will cause
distribution revenue to fluctuate from period to period are changes in the
number of customers and changes in the approved distribution charge per
customer.
Pepco is a wholly owned subsidiary of
Pepco Holdings, Inc. (PHI or Pepco Holdings). Because PHI is a public
utility holding company subject to the Public Utility Holding Company Act of
2005 (PUHCA 2005), the relationship between PHI and Pepco and certain activities
of Pepco are subject to the regulatory oversight of Federal Energy Regulatory
Commission under PUHCA 2005.
RESULTS
OF OPERATIONS
The following results of operations
discussion compares the year ended December 31, 2007 to the year ended
December 31, 2006. Other than this disclosure, information under this
item has been omitted in accordance with General Instruction I(2)(a) to the Form
10-K. All amounts in the tables (except sales and customers) are in
millions of dollars.
Operating
Revenue
|
|
|
2007
|
|
|
2006
|
|
|
Change
|
|
|
Regulated
T&D Electric Revenue
|
|
$ |
927.9 |
|
|
$ |
854.1 |
|
|
$ |
73.8 |
|
|
Default
Supply Revenue
|
|
|
1,241.4 |
|
|
|
1,331.7 |
|
|
|
(90.3 |
) |
|
Other
Electric Revenue
|
|
|
31.6 |
|
|
|
30.7 |
|
|
|
0.9 |
|
|
Total
Operating Revenue
|
|
$ |
2,200.9 |
|
|
$ |
2,216.5 |
|
|
$ |
(15.6 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The table above shows the amount of
Operating Revenue earned that is subject to price regulation (Regulated
Transmission and Distribution (T&D) Electric Revenue and Default Supply
Revenue) and that which is not subject to price regulation (Other Electric
Revenue).
Regulated T&D Electric Revenue
includes revenue from the transmission and the delivery of electricity,
including the delivery of Default Electricity Supply, to Pepco’s customers
within its service territory at regulated rates.
Default Supply Revenue is the revenue
received for Default Electricity Supply. The costs related to Default
Electricity Supply are included in Fuel and Purchased Energy
expense.
Other Electric Revenue includes work
and services performed on behalf of customers, including other utilities, which
is 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 Revenue
|
|
2007
|
|
|
2006
|
|
|
Change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
$ |
262.4 |
|
|
$ |
244.7 |
|
|
$ |
17.7 |
|
|
Commercial
|
|
|
529.4 |
|
|
|
501.8 |
|
|
|
27.6 |
|
|
Industrial
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Other
|
|
|
136.1 |
|
|
|
107.6 |
|
|
|
28.5 |
|
|
Total
Regulated T&D Electric Revenue
|
|
$ |
927.9 |
|
|
$ |
854.1 |
|
|
$ |
73.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Regulated T&D Electric
Revenue consists primarily of (i) transmission service revenue received by Pepco
from PJM Interconnection, LLC (PJM) as a transmission owner, (ii) revenue from
the resale of energy and capacity under power purchase agreements between Pepco
and unaffiliated third parties in the PJM Regional Transmission Organization
(PJM RTO) market, and (iii) either (a) a positive adjustment equal to the amount
by which revenue from Maryland retail distribution sales falls short of the
revenue that Pepco is entitled to earn based on the distribution charge per
customer approved in the 2007 Maryland Rate Order or (b) 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).
|
Regulated
T&D Electric Sales (GWh)
|
2007
|
2006
|
Change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
8,093
|
|
|
7,694
|
|
|
399
|
|
|
|
Commercial
|
|
19,197
|
|
|
18,632
|
|
|
565
|
|
|
|
Industrial
|
|
-
|
|
|
-
|
|
|
-
|
|
|
|
Other
|
|
161
|
|
|
162
|
|
|
(1)
|
|
|
|
Total
Regulated T&D Electric Sales
|
|
27,451
|
|
|
26,488
|
|
|
963
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulated
T&D Electric Customers (in thousands)
|
2007
|
2006
|
Change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
687
|
|
|
680
|
|
|
7
|
|
|
|
Commercial
|
|
73
|
|
|
73
|
|
|
-
|
|
|
|
Industrial
|
|
-
|
|
|
-
|
|
|
-
|
|
|
|
Other
|
|
-
|
|
|
-
|
|
|
-
|
|
|
|
Total
Regulated T&D Electric Customers
|
|
760
|
|
|
753
|
|
|
7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulated T&D Electric Revenue
increased by $73.8 million primarily due to the following: (i) $28.8
million increase in Other Regulated T&D Electric Revenue from the resale of
energy and capacity purchased under the power purchase agreement between
Panda-Brandywine, L.P. (Panda) and Pepco (the Panda PPA) (offset in Fuel and
Purchased Energy), (ii) $26.1 million increase due to higher weather-related
sales (a 21% increase in Cooling Degree Days and a 10% increase in Heating
Degree Days), (iii) $12.1 million increase due to higher pass-through revenue
primarily resulting from tax rate increases in the District of Columbia (offset
primarily in Other Taxes), (iv) $11.5 million increase due to a 2007 Maryland
Rate Order that became effective in June 2007, which includes a positive $3.3
million Revenue Decoupling Adjustment.
Default Electricity Supply
|
Default
Supply Revenue
|
|
2007
|
|
|
2006
|
|
|
Change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
$ |
774.5 |
|
|
$ |
612.5 |
|
|
$ |
162.0 |
|
|
|
Commercial
|
|
|
458.9 |
|
|
|
716.6 |
|
|
|
(257.7 |
) |
|
|
Industrial
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
Other
(includes PJM)
|
|
|
8.0 |
|
|
|
2.6 |
|
|
|
5.4 |
|
|
|
Total
Default Supply Revenue
|
|
$ |
1,241.4 |
|
|
$ |
1,331.7 |
|
|
$ |
(90.3 |
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Default
Electricity Supply Sales (GWh)
|
2007
|
2006
|
Change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
7,692
|
|
|
7,269
|
|
|
423
|
|
|
|
Commercial
|
|
4,384
|
|
|
8,160
|
|
|
(3,776)
|
|
|
|
Industrial
|
|
-
|
|
|
-
|
|
|
-
|
|
|
|
Other
|
|
37
|
|
|
33
|
|
|
4
|
|
|
|
Total
Default Electricity Supply Sales
|
|
12,113
|
|
|
15,462
|
|
|
(3,349)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Default
Electricity Supply Customers (in thousands)
|
2007
|
2006
|
Change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
659
|
|
|
652
|
|
|
7
|
|
|
|
Commercial
|
|
52
|
|
|
54
|
|
|
(2)
|
|
|
|
Industrial
|
|
-
|
|
|
-
|
|
|
-
|
|
|
|
Other
|
|
-
|
|
|
-
|
|
|
-
|
|
|
|
Total
Default Electricity Supply Customers
|
|
711
|
|
|
706
|
|
|
5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Default Supply Revenue, which is
partially offset in Fuel and Purchased Energy, decreased by $90.3 million
primarily due to the following: (i) $279.8 million decrease primarily due to
commercial customers electing to purchase an increased amount of electricity
from competitive suppliers, (ii) $54.4 million decrease due to differences in
consumption among the various customer rate classes, partially offset by (iii)
$194.9 million increase due to annual increases in market-based Default
Electricity Supply rates, and (iv) $48.0 million increase due to higher
weather-related sales, (a 21% increase in Cooling Degree Days and a 10 %
increase in Heating Degree Days).
The following table shows percentages
of Pepco’s total sales by jurisdiction that are derived from customers receiving
Default Electricity Supply in that jurisdiction from Pepco.
|
|
2007
|
2006
|
|
Sales
to District of Columbia customers
|
|
35%
|
|
|
57%
|
|
|
Sales
to Maryland customers
|
|
51%
|
|
|
60%
|
|
Operating
Expenses
Fuel and Purchased Energy
Fuel and Purchased Energy, which is
primarily associated with Default Electricity Supply sales, decreased by $53.9
million to $1,245.8 million in 2007 from $1,299.7 in 2006. The
decrease is primarily due to the following: (i) $316.1 million decrease
primarily due to commercial customers electing to purchase an increased amount
of electricity from competitive suppliers, (ii) $28.3 million decrease in the
Default Electricity Supply deferral balance, partially offset by (iii) $211.6
million increase in average energy costs, the result of new annual Default
Electricity Supply contracts, (iv) $49.1 million increase due to higher
weather-related sales, and (v) $28.8 million increase for energy and capacity
purchased under the Panda PPA (offset in Regulated T&D Electric
Revenue). Fuel and Purchased Energy expense is primarily offset in
Default Supply Revenue.
Other Operation and
Maintenance
Other Operation and Maintenance
increased by $22.7 million to $300.0 million in 2007 from $277.3 million in
2006. The increase was primarily due to the following: (i)
$7.0 million increase in preventative maintenance and system operation costs,
(ii) $6.9 million increase in employee-related costs, (iii) $3.9 million
increase in regulatory expenses, (iv) $3.4 million increase due to construction
project write-offs related to customer requested work, and (v) $2.0 million
increase due to higher bad debt expenses.
Depreciation and
Amortization
Depreciation and Amortization expenses
decreased by $14.8 million to $151.4 million in 2007 from $166.2 million in
2006, primarily due to a change in depreciation rates in accordance with the
2007 Maryland Rate Order.
Effect of Settlement of Mirant
Bankruptcy Claims
The Effect of Settlement of Mirant
Bankruptcy Claims reflects the recovery of $33.4 million in operating expenses
and certain other costs as damages in the Mirant bankruptcy
settlement.
Other Taxes increased $16.4 million to
$289.5 million in 2007 from $273.1 million in 2006 primarily due to increased
pass-throughs resulting from tax rate increases in the District of Columbia
(partially offset in Regulated T&D Electric Revenue).
Income
Tax Expense
Pepco’s effective tax rates for the
years ended December 31, 2007 and 2006 were 33.2% and 40.2%, respectively. The
7.0% decrease in the effective tax rate in 2007 was primarily the result of a
2007 Maryland state income tax refund. The refund was due to an
increase in the tax basis of certain assets sold in 2000, and as a result,
Pepco’s 2007 income tax expense was reduced by $19.5 million with a
corresponding decrease to the effective tax rate of 10.4%. This decrease in the
effective tax rate was partially offset by 2007 deferred tax basis adjustments
and reduced book versus tax depreciation and amortization differences, which
increased the year over year effective tax rate by 2.4% and 0.9%,
respectively.
Capital
Requirements
Capital
Expenditures
Pepco’s total capital expenditures for
the twelve months ended December 31, 2007, totaled $272.2
million. These expenditures were primarily related to capital costs
associated with new customer services, distribution reliability and
transmission.
The table below shows Pepco’s projected
capital expenditures for the five year period 2008 through 2012:
|
|
|
For
the Year
|
|
|
|
|
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
Total
|
|
|
|
|
(Millions
of Dollars)
|
|
|
Pepco
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distribution
|
|
$ |
192 |
|
|
$ |
215 |
|
|
$ |
212 |
|
|
$ |
232 |
|
|
$ |
331 |
|
|
$ |
1,182 |
|
|
Distribution
- Blueprint for the Future
|
|
|
24 |
|
|
|
61 |
|
|
|
61 |
|
|
|
63 |
|
|
|
5 |
|
|
|
214 |
|
|
Transmission
|
|
|
45 |
|
|
|
64 |
|
|
|
167 |
|
|
|
168 |
|
|
|
62 |
|
|
|
506 |
|
|
MAPP
|
|
|
17 |
|
|
|
72 |
|
|
|
30 |
|
|
|
- |
|
|
|
- |
|
|
|
119 |
|
|
Other
|
|
|
15 |
|
|
|
17 |
|
|
|
12 |
|
|
|
12 |
|
|
|
11 |
|
|
|
67 |
|
|
|
|
$ |
293 |
|
|
$ |
429 |
|
|
$ |
482 |
|
|
$ |
475 |
|
|
$ |
409 |
|
|
$ |
2,088 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pepco expects to fund these
expenditures through internally generated cash and from external financing and
capital contributions from PHI.
Distribution, Transmission and Gas
Delivery
The projected capital expenditures for
distribution (other than Blueprint for the Future), transmission (other than
MAPP) and gas delivery are primarily for facility replacements and upgrades to
accommodate customer growth and reliability.
During 2007, PHI announced an
initiative in Pepco’s service territory referred to as the “Blueprint for the
Future.” This initiative combines traditional energy efficiency programs with
new technologies and systems to help customers manage their energy use and
reduce the total cost of energy, and includes the installation of “smart meters”
for all customers in the District of Columbia and Maryland. Pepco has
made filings with the District of Columbia Public Service Commission and the
MPSC for approval of certain aspects of these programs.
On October 17, 2007, Pepco Holdings
received the approval of the PJM Board of Managers to build a new 230-mile,
500-kilovolt interstate transmission line as part of PJM’s Regional Transmission
Expansion Plan to address the reliability objectives of the PJM RTO
system. The transmission line, which is referred to as the MAPP
Project, will be located in northern Virginia, Maryland, the Delmarva Peninsula,
and New Jersey. The preliminarily estimated cost of the 500-kilovolt
MAPP Project is approximately $1 billion. Pepco’s portion of the
preliminary estimated cost of the 500-kilovolt transmission line is
approximately $119 million. Construction is expected to occur in
sections over a six-year period with completion targeted by 2013.
Proceeds from Settlement of Mirant
Bankruptcy Claims
In 2000, Pepco sold substantially all
of its electricity generating assets to Mirant Corporation
(Mirant). In 2003, Mirant commenced a voluntary bankruptcy proceeding
in which it sought to reject certain obligations that it had undertaken in
connection with the asset sale. As part of the asset sale, Pepco
entered into transition power agreements with Mirant pursuant to which Mirant
agreed to supply all of the energy and capacity needed by Pepco to fulfill its
SOS obligations in Maryland and in the District of Columbia (the
TPAs). Under a settlement to avoid the rejection by Mirant of its
obligations under the TPAs in the bankruptcy proceeding, the terms of the TPAs
were modified to increase the purchase price of the energy and capacity supplied
by Mirant and Pepco received an allowed, pre-petition general unsecured claim in
the bankruptcy in the amount of $105 million (the TPA Claim). In
December 2005, Pepco sold the TPA Claim, plus the right to receive accrued
interest thereon, to an unaffiliated third party for $112.5
million. In addition, Pepco received proceeds of $.5 million in
settlement of an asbestos claim against the Mirant bankruptcy
estate. After customer sharing, Pepco recorded a pre-tax gain of
$70.5 million from the settlement of these claims.
In connection with the asset sale,
Pepco and Mirant also entered into a “back-to-back” arrangement, whereby Mirant
agreed to purchase from Pepco the 230 megawatts of electricity and capacity that
Pepco is obligated to purchase annually through 2021 from Panda-Brandywine LLP
(Panda) under a power purchase agreement (the Panda PPA) at the purchase price
Pepco is
obligated
to pay to Panda. As part of the further settlement of Pepco’s claims
against Mirant arising from the Mirant bankruptcy, Pepco agreed not to contest
the rejection by Mirant of its obligations under the “back-to-back” arrangement
in exchange for the payment by Mirant of damages corresponding to the estimated
amount by which the purchase price that Pepco is obligated to pay Panda for the
energy and capacity exceeded the market price. In 2007, Pepco
received as damages $413.9 million in net proceeds from the sale of shares of
Mirant common stock issued to it by Mirant. These funds are being
accounted for as restricted cash based on management’s intent to use such funds,
and any interest earned thereon, for the sole purpose of paying for the future
above-market capacity and energy purchase costs under the Panda
PPA. Correspondingly, a regulatory liability has been established in
the same amount to help offset the future above-market capacity and energy
purchase costs. This restricted cash has been classified as a
non-current asset to be consistent with the classification of the non-current
regulatory liability, and any changes in the balance of this restricted cash,
including interest on the invested funds, are being accounted for as operating
cash flows.
As of December 31, 2007, the balance of
the restricted cash account was $417.3 million. Based on a
reexamination of the costs of the Panda PPA in light of current and projected
wholesale market conditions conducted in the fourth quarter of 2007, Pepco
determined that, principally due to increases in wholesale capacity prices, the
present value above-market cost of the Panda PPA over the term of the agreement
is expected to be significantly less than the current amount of the restricted
cash account balance. Accordingly, on February 22, 2008, Pepco filed
applications with the DCPSC and the MPSC requesting orders directing Pepco to
maintain $320 million in the restricted cash account and to use that cash, and
any future earnings on the cash, for the sole purpose of paying the future
above-market cost of the Panda PPA (or, in the alternative, to fund a transfer
or assignment of the remaining obligations under the Panda PPA to a third
party). Pepco also requested that the order provide that any cash
remaining in the account at the conclusion of the Panda PPA be refunded to
customers and that any shortfall be recovered from customers. Pepco
further proposed that the excess proceeds remaining from the settlement
(approximately $94.6 million, representing the amount by which the regulatory
liability of $414.6 million at December 31, 2007 exceeded $320 million) be
shared with its customers in accordance with the procedures previously approved
by each commission for the sharing of the proceeds received by Pepco from the
sale to Mirant of its generating assets. The regulatory liability of
$414.6 million at December 31, 2007 differs from the restricted cash amount of
$417.3 million on that date, in part, because the regulatory liability has been
reduced for the portion of the December 2007 Panda charges in excess of market
that had not yet been paid from the restricted cash account. The
amount of the restricted cash balance that Pepco is permitted to retain will be
recorded as earnings upon approval of the sharing arrangement by the respective
commissions. At this time, Pepco cannot predict the outcome of these
proceedings.
In settlement of other damages claims
against Mirant, Pepco in 2007 also received a settlement payment in the amount
of $70.0 million. Of this amount (i) $33.4 million was recorded as a
reduction in operating expenses, (ii) $21.0 million was recorded as a reduction
in a net pre-petition receivable claim from Mirant, (iii) $15.0 million was
recorded as a reduction in the capitalized costs of certain property, plant and
equipment and (iv) $.6 million was recorded as a liability to reimburse a third
party for certain legal costs associated with the settlement.
FORWARD-LOOKING
STATEMENTS
Some of the statements contained in
this Annual Report on Form 10-K are forward-looking statements within the
meaning of Section 21E of the Securities Exchange Act of 1934, as
amended,
and are subject to the safe harbor created by the Private Securities Litigation
Reform Act of 1995. These statements include declarations regarding Pepco’s
intents, beliefs and current expectations. In some cases, you can identify
forward-looking statements by terminology such as “may,” “will,” “should,”
“expects,” “plans,” “anticipates,” “believes,” “estimates,” “predicts,”
“potential” or “continue” or the negative of such terms or other comparable
terminology. Any forward-looking statements are not guarantees of future
performance, and actual results could differ materially from those indicated by
the forward-looking statements. Forward-looking statements involve estimates,
assumptions, known and unknown risks, uncertainties and other factors that may
cause Pepco’s or Pepco’s industry’s actual results, levels of activity,
performance or achievements to be materially different from any future results,
levels of activity, performance or achievements expressed or implied by such
forward-looking statements.
The forward-looking statements
contained herein are qualified in their entirety by reference to the following
important factors, which are difficult to predict, contain uncertainties, are
beyond Pepco’s control and may cause actual results to differ materially from
those contained in forward-looking statements:
|
|
·
|
Prevailing
governmental policies and regulatory actions affecting the energy
industry, including allowed rates of return, industry and rate structure,
acquisition and disposal of assets and facilities, operation and
construction of plant facilities, recovery of purchased power expenses,
and present or prospective wholesale and retail
competition;
|
|
|
·
|
Changes
in and compliance with environmental and safety laws and
policies;
|
|
|
·
|
Population
growth rates and demographic
patterns;
|
|
|
·
|
Competition
for retail and wholesale customers;
|
|
|
·
|
General
economic conditions, including potential negative impacts resulting from
an economic downturn;
|
|
|
·
|
Growth
in demand, sales and capacity to fulfill
demand;
|
|
|
·
|
Changes
in tax rates or policies or in rates of
inflation;
|
|
|
·
|
Changes
in project costs;
|
|
|
·
|
Unanticipated
changes in operating expenses and capital
expenditures;
|
|
|
·
|
The
ability to obtain funding in the capital markets on favorable
terms;
|
|
|
·
|
Restrictions
imposed by federal and/or state regulatory commissions, PJM, the North
American Electric Reliability Council and other applicable electric
reliability organizations;
|
|
|
·
|
Legal
and administrative proceedings (whether civil or criminal) and settlements
that affect Pepco’s business and
profitability;
|
|
|
·
|
Volatility
in market demand and prices for energy, capacity and
fuel;
|
|
|
·
|
Interest
rate fluctuations and credit market concerns;
and
|
|
|
·
|
Effects
of geopolitical events, including the threat of domestic
terrorism.
|
Any forward-looking statements speak
only as to the date of this Annual Report and Pepco undertakes no obligation to
update any forward-looking statements to reflect events or circumstances after
the date on which such statements are made or to reflect the occurrence of
unanticipated events. New factors emerge from time to time, and it is not
possible for Pepco to predict all of such factors, nor can Pepco assess the
impact of any such factor on Pepco’s business or the extent to which any factor,
or combination of factors, may cause results to differ materially from those
contained in any forward-looking statement.
The foregoing review of factors should
not be construed as exhaustive.
THIS
PAGE LEFT INTENTIONALLY BLANK.
MANAGEMENT’S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF
OPERATIONS
DELMARVA
POWER & LIGHT COMPANY
GENERAL
OVERVIEW
Delmarva Power & Light Company
(DPL) is engaged in the transmission and distribution of electricity in Delaware
and portions of Maryland and Virginia (until the sale of its Virginia operations
on January 2, 2008). DPL provides Default Electricity Supply, which
is the supply of electricity at regulated rates to retail customers in its
territories who do not elect to purchase electricity from a competitive
supplier. Default Electricity Supply is also known as Default Service
in Virginia (until the sale of its Virginia operations on January 2, 2008), as
Standard Offer Service in Maryland and in Delaware on and after May 1,
2006, and as Provider of Last Resort (POLR) service in Delaware before
May 1, 2006. DPL’s electricity distribution service territory
covers approximately 6,000 square miles and has a population of approximately
1.3 million. As of December 31, 2007, approximately 65% of delivered
electricity sales were to Delaware customers, approximately 32% were to Maryland
customers, and approximately 3% were to Virginia customers. DPL also
provides natural gas distribution service in northern Delaware. DPL’s
natural gas distribution service territory covers approximately 275 square miles
and has a population of approximately .5 million.
On
January 2, 2008, DPL completed (i) the sale of its retail electric distribution
business on the Eastern Shore of Virginia to A&N Electric Cooperative
(A&N) for a purchase price of approximately $45.2 million, after
closing adjustments, and (ii) the sale of its wholesale electric
transmission business located on the Eastern Shore of Virginia to Old Dominion
Electric Cooperative (ODEC) for a purchase price of approximately
$5.4 million, after closing adjustments. Each of A&N and
ODEC assumed certain post-closing liabilities and unknown pre-closing
liabilities related to the respective assets they are purchasing (including, in
the A&N transaction, most environmental liabilities), except that DPL
remained liable for unknown pre-closing liabilities if they become known within
six months after the January 2, 2008 closing date. These sales
resulted in an immaterial financial gain to DPL that will be recorded during the
first quarter of 2008.
Effective
June 16, 2007, the Maryland Public Service Commission (MPSC) approved new
electric service distribution base rates for DPL (the 2007 Maryland Rate
Order). The MPSC also approved a bill stabilization adjustment
mechanism (BSA) for retail customers. For customers to which the BSA
applies, DPL recognizes distribution revenue based on an approved distribution
charge per customer. From a revenue recognition standpoint, the BSA
thus decouples the distribution revenue recognized in a reporting period from
the amount of power delivered during the period. This change in the
reporting of distribution revenue has the effect of eliminating changes in
customer usage (whether due to weather conditions, energy prices, energy
efficiency programs or other reasons) as a factor having an impact on reported
revenue. As a consequence, the only factors that will cause
distribution revenue to fluctuate from period to period are changes in the
number of customers and changes in the approved distribution charge per
customer.
DPL is a wholly owned subsidiary of
Conectiv, which is wholly owned by Pepco Holdings, Inc.
(PHI). Because PHI is a public utility holding company subject to the
Public Utility Holding Company Act of 2005 (PUHCA 2005), the relationship
between PHI and DPL and certain activities of DPL are subject to the regulatory
oversight of Federal Energy Regulatory Commission under PUHCA 2005.
RESULTS
OF OPERATIONS
The following results of operations
discussion compares the year ended December 31, 2007 to the year ended
December 31, 2006. Other than this disclosure, information under
this item has been omitted in accordance with General Instruction I(2)(a) to the
Form 10-K. All amounts in the tables (except sales and customers) are
in millions of dollars.
Operating
Revenue
|
|
|
2007
|
|
|
2006
|
|
|
Change
|
|
|
Regulated
T&D Electric Revenue
|
|
$ |
337.4 |
|
|
$ |
333.4 |
|
|
$ |
4.0 |
|
|
Default
Supply Revenue
|
|
|
846.4 |
|
|
|
812.5 |
|
|
|
33.9 |
|
|
Other
Electric Revenue
|
|
|
20.9 |
|
|
|
22.1 |
|
|
|
(1.2 |
) |
|
Total
Electric Operating Revenue
|
|
$ |
1,204.7 |
|
|
$ |
1,168.0 |
|
|
$ |
36.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The table above shows the amount of
Electric Operating Revenue earned that is subject to price regulation (Regulated
Transmission and Distribution (T&D) Electric Revenue and Default Supply
Revenue) and that which is not subject to price regulation (Other Electric
Revenue).
Regulated T&D Electric Revenue
includes revenue from the transmission and the delivery of electricity,
including the delivery of Default Electricity Supply, to DPL’s customers within
its service territory at regulated rates.
Default Supply Revenue is the revenue
received for Default Electricity Supply. The costs related to Default
Electricity Supply are included in Fuel and Purchased Energy
expense.
Other Electric Revenue includes work
and services performed on behalf of customers, including other utilities, which
is 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 Revenue
|
|
2007
|
|
|
2006
|
|
|
Change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
$ |
166.6 |
|
|
$ |
162.5 |
|
|
$ |
4.1 |
|
|
Commercial
|
|
|
90.7 |
|
|
|
90.0 |
|
|
|
.7 |
|
|
Industrial
|
|
|
12.0 |
|
|
|
13.5 |
|
|
|
(1.5 |
) |
|
Other
|
|
|
68.1 |
|
|
|
67.4 |
|
|
|
.7 |
|
|
Total
Regulated T&D Electric Revenue
|
|
$ |
337.4 |
|
|
$ |
333.4 |
|
|
$ |
4.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Regulated T&D Electric
Revenue consists primarily of (i) transmission service revenue received by DPL
from PJM Interconnection, LLC (PJM) as a transmission owner,
and
(ii)
either (a) 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 distribution charge per customer approved in the
2007 Maryland Rate Order or (b) 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).
|
Regulated
T&D Electric Sales
(GWh)
|
2007
|
2006
|
Change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
5,333
|
|
|
5,170
|
|
|
163
|
|
|
|
Commercial
|
|
5,471
|
|
|
5,357
|
|
|
114
|
|
|
|
Industrial
|
|
2,825
|
|
|
2,899
|
|
|
(74)
|
|
|
|
Other
|
|
51
|
|
|
51
|
|
|
-
|
|
|
|
Total
Regulated T&D Electric Sales
|
|
13,680
|
|
|
13,477
|
|
|
203
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulated
T&D Electric Customers (in thousands)
|
2007
|
2006
|
Change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
456
|
|
|
451
|
|
|
5
|
|
|
|
Commercial
|
|
61
|
|
|
60
|
|
|
1
|
|
|
|
Industrial
|
|
1
|
|
|
1
|
|
|
-
|
|
|
|
Other
|
|
1
|
|
|
1
|
|
|
-
|
|
|
|
Total
Regulated T&D Electric Customers
|
|
519
|
|
|
513
|
|
|
6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulated T&D Electric Revenue
increased by $4.0 million primarily due to the following: (i) $11.0 million
increase due to higher weather-related sales (a 15% increase in Heating Degree
Days and a 13% increase in Cooling Degree Days), (ii) $8.8 million increase due
to a 2007 Maryland Rate Order that became effective in June 2007, which includes
a positive $1.6 million Revenue Decoupling Adjustment, partially offset by (iii)
$10.0 million decrease due to a change in Delaware rate structure effective May
1, 2006, which shifted revenue from Regulated T&D Electric Revenue to
Default Supply Revenue, and (iv) $4.0 million decrease due to a Delaware base
rate reduction in May 2006.
Default Electricity Supply
|
Default
Supply Revenue
|
|
2007
|
|
|
2006
|
|
|
Change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
$ |
556.2 |
|
|
$ |
449.9 |
|
|
$ |
106.3 |
|
|
|
Commercial
|
|
|
238.7 |
|
|
|
302.2 |
|
|
|
(63.5 |
)
|
|
|
Industrial
|
|
|
42.1 |
|
|
|
55.4 |
|
|
|
(13.3 |
)
|
|
|
Other
(includes PJM)
|
|
|
9.4 |
|
|
|
5.0 |
|
|
|
4.4 |
|
|
|
Total
Default Supply Revenue
|
|
$ |
846.4 |
|
|
$ |
812.5 |
|
|
$ |
33.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Default
Electricity Supply Sales (GWh)
|
2007
|
2006
|
Change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
$
|
5,257
|
|
$
|
5,154
|
|
$
|
103
|
|
|
|
Commercial
|
|
2,291
|
|
|
3,472
|
|
|
(1,181)
|
|
|
|
Industrial
|
|
551
|
|
|
983
|
|
|
(432)
|
|
|
|
Other
|
|
45
|
|
|
49
|
|
|
(4)
|
|
|
|
Total
Default Electricity Supply Sales
|
$
|
8,144
|
|
$
|
9,658
|
|
$
|
(1,514)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Default
Electricity Supply Customers (in thousands)
|
2007
|
2006
|
Change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
447
|
|
|
449
|
|
|
(2)
|
|
|
|
Commercial
|
|
51
|
|
|
53
|
|
|
(2)
|
|
|
|
Industrial
|
|
-
|
|
|
-
|
|
|
-
|
|
|
|
Other
|
|
1
|
|
|
1
|
|
|
-
|
|
|
|
Total
Default Electricity Supply Customers
|
|
499
|
|
|
503
|
|
|
(4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Default Supply Revenue, which is
partially offset in Fuel and Purchased Energy, increased by $33.9 million
primarily due to the following: (i) $116.0 million increase due to annual
increases in market-based Default Electricity Supply rates, (ii) $27.0 million
increase due to higher weather-related sales (a 15% increase in Heating Degree
Days and a 13% increase in Cooling Degree Days), (iii) $10.0 million increase
due to a change in Delaware rate structure effective May 1, 2006 that shifted
revenue from Regulated T&D Electric Revenue to Default Supply Revenue,
partially offset by (iv) $68.0 million decrease primarily due to commercial and
industrial customers electing to purchase an increased amount of electricity
from competitive suppliers, and (v) $50.0 million decrease due to differences in
consumption among the various customer rate classes.
The following table shows the
percentages of DPL’s total sales by jurisdiction that are derived from customers
receiving Default Electricity Supply in that jurisdiction from DPL.
|
|
2007
|
2006
|
|
Sales
to Delaware customers
|
|
54%
|
|
|
69%
|
|
|
Sales
to Maryland customers
|
|
67%
|
|
|
75%
|
|
|
Sales
to Virginia customers
|
|
94%
|
|
|
94%
|
|
Natural
Gas Operating Revenue
|
|
|
2007
|
|
|
2006
|
|
|
Change
|
|
|
Regulated
Gas Revenue
|
|
$ |
211.3 |
|
|
$ |
204.8 |
|
|
$ |
6.5 |
|
|
Other
Gas Revenue
|
|
|
80.0 |
|
|
|
50.6 |
|
|
|
29.4 |
|
|
Total
Natural Gas Operating Revenue
|
|
$ |
291.3 |
|
|
$ |
255.4 |
|
|
$ |
35.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 for on-system natural gas delivered sales and the
transportation of natural gas for customers. Other Gas Revenue
includes off-system natural gas sales and the release of excess system
capacity.
|
Regulated
Gas Revenue
|
|
2007
|
|
|
2006
|
|
|
Change
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
$ |
124.0 |
|
|
$ |
116.2 |
|
|
$ |
7.8 |
|
|
Commercial
|
|
|
72.7 |
|
|
|
73.0 |
|
|
|
(.3 |
) |
|
Industrial
|
|
|
8.2 |
|
|
|
10.3 |
|
|
|
(2.1 |
) |
|
Transportation
and Other
|
|
|
6.4 |
|
|
|
5.3 |
|
|
|
1.1 |
|
|
Total
Regulated Gas Revenue
|
|
$ |
211.3 |
|
|
$ |
204.8 |
|
|
$ |
6.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulated
Gas Sales (Bcf)
|
2007
|
2006
|
Change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
7.9
|
|
|
6.6
|
|
|
1.3
|
|
|
|
Commercial
|
|
5.2
|
|
|
4.6
|
|
|
.6
|
|
|
|
Industrial
|
|
.8
|
|
|
.8
|
|
|
-
|
|
|
|
Transportation
and Other
|
|
6.8
|
|
|
6.3
|
|
|
.5
|
|
|
|
Total
Regulated Gas Sales
|
|
20.7
|
|
|
18.3
|
|
|
2.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulated
Gas Customers (in thousands)
|
2007
|
2006
|
Change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
112
|
|
|
112
|
|
|
-
|
|
|
|
Commercial
|
|
10
|
|
|
9
|
|
|
1
|
|
|
|
Industrial
|
|
-
|
|
|
-
|
|
|
-
|
|
|
|
Transportation
and Other
|
|
-
|
|
|
-
|
|
|
-
|
|
|
|
Total
Regulated Gas Customers
|
|
122
|
|
|
121
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulated Gas Revenue increased by $6.5
million primarily due to (i) $11.7 million increase due to colder weather (a 15%
increase in Heating Degree Days), (ii) $5.7 million increase due to base rate
increases effective in November 2006 and April 2007, (iii) $4.8 million increase
due to differences in consumption among the various customer rate classes, (iv)
$2.7 million increase due to customer growth of 1% in 2007, partially offset by
(v) $18.4 million decrease due to Gas Cost Rate decreases effective November
2006, April 2007 and November 2007 resulting from lower natural gas commodity
costs (offset in Gas Purchased Expense).
Other Gas Revenue increased by $29.4
million to $80.0 million in 2007 from $50.6 million in 2006 primarily due to
higher off-system sales (partially offset in Gas Purchased
Expense). The gas sold off-system resulted from increased demand from
unaffiliated third party electric generators during periods of low customer
demand for natural gas.
Operating
Expenses
Fuel and Purchased Energy
Fuel and Purchased Energy, which is
primarily associated with Default Electricity Supply sales, increased by $21.8
million to $838.6 million in 2007 from $816.8 million in 2006. The
increase is primarily due to (i) $143.8 million increase in average energy
costs, the result of new annual Default Electricity Supply contracts, (ii) $27.1
million increase due to higher weather-related sales, partially offset by (iii)
$130.1 million decrease primarily due to commercial and
industrial
customers electing to purchase an increased amount of electricity from
competitive suppliers, (iv) $10.8 million decrease in network transmission
expenses primarily due to POLR service obligations ending April 1, 2006, and (v)
$8.1 million decrease in the Default Electricity Supply deferral
balance. Fuel and Purchased Energy expense is primarily offset by
Default Supply Revenue.
Total Gas Purchased, which is primarily
offset in Regulated Gas Revenue and Other Gas Revenue, increased by $21.9
million to $220.3 million in 2007 from $198.4 million in 2006. The
increase is primarily due to (i) $26.4 million increase in off-system sales,
partially offset by (ii) $4.6 million decrease from the settlement of financial
hedges (entered into as part of DPL’s regulated natural gas hedge
program).
Other Operation and
Maintenance
Other Operation and Maintenance
increased by $20.5 million to $205.4 million in 2007 from $184.9 million in
2006. The increase was primarily due to the following: (i) $4.3
million increase in costs associated with Default Electricity Supply (primarily
deferred and recoverable), (ii) $4.2 million increase in preventative
maintenance and system operation costs, (iii) $3.7 million increase in
employee-related costs, (iv) $2.5 million increase in customer service operation
expenses, (v) $1.2 million increase due to higher bad debt expenses, and (vi)
$1.1 million increase in accounting service expenses.
Depreciation and
Amortization
Depreciation and Amortization decreased
by $2.3 million to $74.4 million in 2007 from $76.7 million in
2006. The decrease is primarily due to fully amortized
software.
Other
Income (Expense)
Other Expenses (which are net of Other
Income) increased by $3.0 million to a net expense of $39.9 million in 2007 from
a net expense of $36.9 million in 2006. The increase is primarily due
to an increase in interest expense on inter-company borrowings.
Income
Tax Expense
DPL’s effective tax rates for the years
ended December 31, 2007 and 2006 were 45.3% and 43.0%,
respectively. The 2.3% increase in the effective tax rate in 2007 was
primarily the result of certain 2007 deferred tax basis adjustments which
increased the 2007 effective tax rate by 3.9 %. This increase in the
effective tax rate was partially offset by 2007 and 2006 changes in estimates
related to prior year tax liabilities, which reduced the year over year
effective tax rate by 2.0%.
Capital
Requirements
Capital
Expenditures
DPL’s total capital expenditures for
the twelve months ended December 31, 2007, totaled $132.6
million. These expenditures were primarily related to capital costs
associated with new customer services, distribution reliability and
transmission.
The table below shows DPL’s projected
capital expenditures for the five-year period 2008 through 2012:
|
|
For
the Year
|
|
|
|
|
|
2008
|
|
2009
|
|
2010
|
|
2011
|
|
2012
|
|
Total
|
|
|
(Millions
of Dollars)
|
|
DPL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distribution
|
$
|
101
|
$
|
118
|
$
|
124
|
$
|
124
|
$
|
138
|
$
|
605
|
|
Distribution
- Blueprint for the Future
|
|
22
|
|
58
|
|
59
|
|
30
|
|
9
|
|
178
|
|
Transmission
|
|
57
|
|
52
|
|
45
|
|
57
|
|
52
|
|
263
|
|
MAPP
|
|
11
|
|
107
|
|
210
|
|
271
|
|
185
|
|
784
|
|
Gas
Delivery
|
|
23
|
|
24
|
|
19
|
|
19
|
|
18
|
|
103
|
|
Other
|
|
10
|
|
10
|
|
9
|
|
7
|
|
7
|
|
43
|
|
|
$
|
224
|
$
|
369
|
$
|
466
|
$
|
508
|
$
|
409
|
$
|
1,976
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DPL expects to fund these expenditures
through internally generated cash and from external financing and capital
contributions from PHI.
Distribution, Transmission and Gas
Delivery
The projected capital expenditures for
distribution (other than Blueprint for the Future), transmission (other than
MAPP) and gas delivery are primarily for facility replacements and upgrades to
accommodate customer growth and reliability.
During 2007, PHI announced an
initiative in DPL’s service territory referred to as the “Blueprint for the
Future.” This initiative combines traditional energy efficiency programs with
new technologies and systems to help customers manage their energy use and
reduce the total cost of energy, and includes the installation of “smart meters”
for all customers in Delaware and Maryland. DPL has made filings with
the Delaware Public Service Commission and the MPSC for approval of certain
aspects of these programs. DPL’s preliminarily estimated cost to implement these
proposals, if approved by the applicable regulatory commissions, is summarized
in the chart above for the five-year period from 2008 to 2012.
On October 17, 2007, Pepco Holdings
received the approval of the PJM Board of Managers to build a new 230-mile,
500-kilovolt interstate transmission line as part of PJM’s Regional Transmission
Expansion Plan to address the reliability objectives of the PJM RTO
system. The transmission line, which is referred to as the MAPP
Project, will be located in northern Virginia, Maryland, the Delmarva Peninsula,
and New Jersey. The preliminarily estimated cost of the 500-kilovolt
MAPP Project is approximately $1 billion. DPL’s portion of the
preliminary cost of the 500-kilovolt transmission line is approximately $904
million. Construction is expected to occur in sections over a
six-year period with completion targeted by 2013.
PHI also plans to add significant
230-kilovolt support lines in Maryland and New Jersey to connect with the new
500-kilovolt line at an approximate cost of $200 million. PJM
continues to evaluate the 230-kilovolt support lines. Accordingly,
DPL’s projected construction costs associated with these support lines are not
included in the table above.
FORWARD-LOOKING
STATEMENTS
Some of the statements contained in
this Annual Report on Form 10-K are forward-looking statements within the
meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and
are subject to the safe harbor created by the Private Securities Litigation
Reform Act of 1995. These statements include declarations regarding DPL’s
intents, beliefs and current expectations. In some cases, you can identify
forward-looking statements by terminology such as “may,” “will,” “should,”
“expects,” “plans,” “anticipates,” “believes,” “estimates,” “predicts,”
“potential” or “continue” or the negative of such terms or other comparable
terminology. Any forward-looking statements are not guarantees of future
performance, and actual results could differ materially from those indicated by
the forward-looking statements. Forward-looking statements involve estimates,
assumptions, known and unknown risks, uncertainties and other factors that may
cause DPL or DPL’s industry’s actual results, levels of activity, performance or
achievements to be materially different from any future results, levels of
activity, performance or achievements expressed or implied by such
forward-looking statements.
The forward-looking statements
contained herein are qualified in their entirety by reference to the following
important factors, which are difficult to predict, contain uncertainties, are
beyond DPL’s control and may cause actual results to differ materially from
those contained in forward-looking statements:
|
|
·
|
Prevailing
governmental policies and regulatory actions affecting the energy
industry, including allowed rates of return, industry and rate structure,
acquisition and disposal of assets and facilities, operation and
construction of plant facilities, recovery of purchased power expenses,
and present or prospective wholesale and retail
competition;
|
|
|
·
|
Changes
in and compliance with environmental and safety laws and
policies;
|
|
|
·
|
Population
growth rates and demographic
patterns;
|
|
|
·
|
Competition
for retail and wholesale customers;
|
|
|
·
|
General
economic conditions, including potential negative impacts resulting from
an economic downturn;
|
|
|
·
|
Growth
in demand, sales and capacity to fulfill
demand;
|
|
|
·
|
Changes
in tax rates or policies or in rates of
inflation;
|
|
|
·
|
Changes
in project costs;
|
|
|
·
|
Unanticipated
changes in operating expenses and capital
expenditures;
|
|
|
·
|
The
ability to obtain funding in the capital markets on favorable
terms;
|
|
|
·
|
Restrictions
imposed by federal and/or state regulatory commissions, PJM, the North
American Electric Reliability Council and other applicable electric
reliability organizations
|
|
|
·
|
Legal
and administrative proceedings (whether civil or criminal) and settlements
that affect DPL’s business and
profitability;
|
|
|
·
|
Volatility
in market demand and prices for energy, capacity and
fuel;
|
|
|
·
|
Interest
rate fluctuations and credit market concerns;
and
|
|
|
·
|
Effects
of geopolitical events, including the threat of domestic
terrorism.
|
Any forward-looking statements speak
only as to the date of this Annual Report and DPL undertakes no obligation to
update any forward looking statements to reflect events or circumstances after
the date on which such statements are made or to reflect the occurrence of
anticipated events. New factors emerge from time to time, and it is
not possible for DPL to predict all of such factors, nor can DPL assess the
impact of any such factor on our business or the extent to which any factor, or
combination of factors, may cause results to differ materially from those
contained in any forward-looking statement.
The foregoing review of factors should
not be construed as exhaustive.
THIS
PAGE LEFT INTENTIONALLY BLANK.
|
|
MANAGEMENT’S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
|
ATLANTIC
CITY ELECTRIC COMPANY
GENERAL
OVERVIEW
Atlantic City Electric Company (ACE) is
engaged in the generation, transmission, and distribution of electricity in
southern New Jersey. ACE 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
supplier. Default Electricity Supply is also known as Basic
Generation Service (BGS) in New Jersey. ACE’s service territory
covers approximately 2,700 square miles and has a population of approximately
1.0 million.
ACE is a wholly owned subsidiary of
Conectiv, which is wholly owned by Pepco Holdings, Inc. (PHI or Pepco
Holdings). Because PHI is a public utility holding company subject to
the Public Utility Holding Company Act of 2005 (PUHCA 2005), the relationship
between PHI and ACE and certain activities of ACE are subject to the regulatory
oversight of Federal Energy Regulatory Commission under PUHCA 2005.
DISCONTINUED
OPERATIONS
On February 8, 2007, ACE completed the
sale of the B.L. England generating facility. B.L. England comprised
a significant component of ACE’s generation operations and its sale requires
discontinued operations presentation under Statement of Financial Accounting
Standards No. 144, “Accounting for the Impairment or Disposal of Long Lived
Assets,” on ACE’s Consolidated Statements of Earnings for the years ended
December 31, 2007, 2006 and 2005. In September 2006, ACE sold its
interests in the Keystone and Conemaugh generating facilities, which for the
years ended December 31, 2006 and 2005, are also reflected as discontinued
operations.
The following table summarizes
information related to the discontinued operations for the years presented
(millions of dollars):
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Operating
Revenue
|
$
|
9.7
|
|
$
|
113.7
|
|
$
|
170.3
|
|
|
Income
Before Income Tax Expense and Extraordinary Item
|
$
|
.2
|
|
$
|
4.4
|
|
$
|
5.2
|
|
|
Net
Income
|
$
|
.1
|
|
$
|
2.6
|
|
$
|
3.1
|
|
|
|
|
|
|
|
|
|
|
|
|
RESULTS
OF OPERATIONS
The following results of operations
discussion compares the year ended December 31, 2007 to the year ended
December 31, 2006. Other than this disclosure, information under
this item has been omitted in accordance with General Instruction I(2)(a) to the
Form 10-K. All amounts in the tables (except sales and customers) are
in millions of dollars.
Operating
Revenue
|
|
|
2007
|
|
|
2006
|
|
|
Change
|
|
|
Regulated
T&D Electric Revenue
|
|
$ |
366.5 |
|
|
$ |
345.6 |
|
|
$ |
20.9 |
|
|
Default
Supply Revenue
|
|
|
1,159.4 |
|
|
|
1,014.0 |
|
|
|
145.4 |
|
|
Other
Electric Revenue
|
|
|
16.6 |
|
|
|
13.7 |
|
|
|
2.9 |
|
|
Total
Operating Revenue
|
|
$ |
1,542.5 |
|
|
$ |
1,373.3 |
|
|
$ |
169.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The table above shows the amount of
Operating Revenue earned that is subject to price regulation (Regulated
Transmission and Distribution (T&D) Electric Revenue and Default Supply
Revenue) and that which is not subject to price regulation (Other Electric
Revenue).
Regulated T&D Electric Revenue
consists of revenue from the transmission and the delivery of electricity,
including the delivery of Default Electricity Supply, to ACE’s customers within
its service territory at regulated rates.
Default Supply Revenue is the revenue
received for Default Electricity Supply. The costs related to Default
Electricity Supply are included in Fuel and Purchased Energy
expense. Also included in Default Supply Revenue is revenue from
transition bond charges and other restructuring related revenues (see Deferred
Electric Service Costs).
Other Electric Revenue includes work
and services performed on behalf of customers, including other utilities, which
is 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 Revenue
|
|
2007
|
|
|
2006
|
|
|
Change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
$ |
177.0 |
|
|
$ |
168.5 |
|
|
$ |
8.5 |
|
|
Commercial
|
|
|
111.1 |
|
|
|
107.2 |
|
|
|
3.9 |
|
|
Industrial
|
|
|
15.4 |
|
|
|
15.1 |
|
|
|
0.3 |
|
|
Other
|
|
|
63.0 |
|
|
|
54.8 |
|
|
|
8.2 |
|
|
Total
Regulated T&D Electric Revenue
|
|
$ |
366.5 |
|
|
$ |
345.6 |
|
|
$ |
20.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Regulated T&D Electric
Revenue consists primarily of transmission service revenue received by ACE from
PJM Interconnection, LLC (PJM) as a transmission owner.
|
Regulated
T&D Electric Sales (GWh)
|
2007
|
2006
|
Change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
4,520
|
|
|
4,275
|
|
|
245
|
|
|
|
Commercial
|
|
4,469
|
|
|
4,389
|
|
|
80
|
|
|
|
Industrial
|
|
1,149
|
|
|
1,220
|
|
|
(71)
|
|
|
|
Other
|
|
49
|
|
|
47
|
|
|
2
|
|
|
|
Total
Regulated T&D Electric Sales
|
|
10,187
|
|
|
9,931
|
|
|
256
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulated
T&D Electric Customers (in thousands)
|
2007
|
2006
|
Change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
479
|
|
|
474
|
|
|
5
|
|
|
|
Commercial
|
|
63
|
|
|
63
|
|
|
-
|
|
|
|
Industrial
|
|
1
|
|
|
1
|
|
|
-
|
|
|
|
Other
|
|
1
|
|
|
1
|
|
|
-
|
|
|
|
Total
Regulated T&D Electric Customers
|
|
544
|
|
|
539
|
|
|
5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulated T&D Electric Revenue
increased by $20.9 million primarily due to the following: (i) $8.1 million
increase in transmission service revenue primarily due to an increase in the
Federal Energy Regulatory Commission formula rate in June 2007, (ii) $5.9
million increase due to higher weather-related sales (a 10% increase in Heating
Degree Days and an 8% increase in Cooling Degree Days), (iii) $4.5 million
increase due to differences in consumption among the various customer rate
classes, and (iv) $2.4 million increase due to customer growth of 1.0% in
2007.
Default Electricity
Supply
|
Default
Supply Revenue
|
|
2007
|
|
|
2006
|
|
|
Change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
$ |
485.7 |
|
|
$ |
420.5 |
|
|
$ |
65.2 |
|
|
Commercial
|
|
|
364.2 |
|
|
|
333.8 |
|
|
|
30.4 |
|
|
Industrial
|
|
|
50.0 |
|
|
|
52.8 |
|
|
|
(2.8 |
) |
|
Other
|
|
|
259.5 |
|
|
|
206.9 |
|
|
|
52.6 |
|
|
Total
Default Supply Revenue
|
|
$ |
1,159.4 |
|
|
$ |
1,014.0 |
|
|
$ |
145.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Default Supply Revenue consists
primarily of revenue from the resale of energy and capacity under non-utility
generating contracts between ACE and unaffiliated third parties (NUGs) in the
PJM Regional Transmission Organization (PJM RTO) market.
|
Default
Electricity Supply Sales (GWh)
|
2007
|
2006
|
Change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
4,520
|
|
|
4,275
|
|
|
245
|
|
|
|
Commercial
|
|
3,235
|
|
|
3,167
|
|
|
68
|
|
|
|
Industrial
|
|
363
|
|
|
396
|
|
|
(33)
|
|
|
|
Other
|
|
49
|
|
|
47
|
|
|
2
|
|
|
|
Total
Default Electricity Supply Sales
|
|
8,167
|
|
|
7,885
|
|
|
282
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Default
Electricity Supply Customers (in thousands)
|
2007
|
2006
|
Change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
479
|
|
|
474
|
|
|
5
|
|
|
|
Commercial
|
|
63
|
|
|
63
|
|
|
-
|
|
|
|
Industrial
|
|
1
|
|
|
1
|
|
|
-
|
|
|
|
Other
|
|
1
|
|
|
1
|
|
|
-
|
|
|
|
Total
Default Electricity Supply Customers
|
|
544
|
|
|
539
|
|
|
5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Default Supply Revenue, which is
partially offset in Fuel and Purchased Energy, increased by $145.4 million
primarily due to the following: (i) $68.2 million increase due to annual
increases in market-based Default Electricity Supply rates, (ii) $53.7 million
increase in wholesale energy revenues due to the sale in PJM at higher market
prices of electricity purchased from NUGs, and (iii) $11.6 million increase due
to higher weather-related sales (a 10% increase in Heating Degree Days and an 8%
increase in Cooling Degree Days).
For the years ended December 31, 2007
and 2006, ACE’s customers served energy by ACE represented 80% and 78%,
respectively, of ACE’s total sales.
Operating
Expenses
Fuel and Purchased Energy
Fuel and Purchased Energy, which is
primarily associated with Default Electricity Supply sales, increased by $126.8
million to $1,051.0 million in 2007 from $924.2 in 2006. The increase
is primarily due to the following: (i) $89.8 million increase due to new annual
BGS supply contracts, and (ii) $16.8 million increase due to higher
weather-related sales. Fuel and Purchased Energy expense is primarily
offset in Default Supply Revenue.
Other Operation and
Maintenance
Other Operation and Maintenance
increased by $17.1 million to $164.8 million in 2007 from $147.7 million in
2006. The increase was primarily due to the following: (i)
$5.2 million increase in employee-related costs, (ii) $3.1 million increase in
Demand Side Management program costs (offset in Deferred Electric Service
costs), (iii) $2.8 million increase in customer service operation expenses, (iv)
$1.5 million increase in accounting service expenses, and (v) $.7 million
increase in regulatory expenses.
Depreciation and
Amortization
Depreciation and Amortization expenses
decreased by $31.1 million to $80.2 million in 2007 from $111.3 million in
2006. The decrease is primarily due to lower amortization of
regulatory assets resulting from the 2006 sale of ACE’s interests in Keystone
and Conemaugh.
Deferred Electric Service
Costs
Deferred Electric Service Costs
increased by $51.0 million to an expense of $66.0 million in 2007 from an
expense of $15.0 million in 2006. The increase was primarily due to
(i) $37.5 million net over-recovery associated with non-utility generating
contracts between ACE and unaffiliated third parties, (ii) $11.7 million net
over-recovery associated with BGS energy costs,
partially
offset by (iii) $3.2 million net under-recovery associated with Demand Side
Management program costs.
Income
Tax Expense
ACE’s effective tax rates for the years
ended December 31, 2007 and 2006 were 40.5% and 35.4%,
respectively. The 5.1% increase in the effective tax rate in 2007 was
primarily the result of 2007 and 2006 changes in estimates related to prior year
tax liabilities, which increased the year over year effective tax rate by
4.8%.
Capital
Requirements
Capital
Expenditures
ACE’s total capital expenditures for
the twelve months ended December 31, 2007, totaled $149.4
million. These expenditures were primarily related to capital costs
associated with new customer services, distribution reliability and
transmission.
The table below shows ACE’s projected
capital expenditures for the five-year period 2008 through 2012:
|
|
For
the Year
|
|
|
|
|
|
2008
|
|
2009
|
|
2010
|
|
2011
|
|
2012
|
|
Total
|
|
|
(Millions
of Dollars)
|
|
ACE
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distribution
|
$
|
96
|
$
|
107
|
$
|
101
|
$
|
109
|
$
|
111
|
$
|
524
|
|
Distribution
- Blueprint for the Future
|
|
15
|
|
11
|
|
16
|
|
20
|
|
85
|
|
147
|
|
Transmission
|
|
78
|
|
17
|
|
25
|
|
45
|
|
47
|
|
212
|
|
MAPP
|
|
-
|
|
-
|
|
1
|
|
2
|
|
3
|
|
6
|
|
Other
|
|
10
|
|
10
|
|
8
|
|
7
|
|
5
|
|
40
|
|
|
$
|
199
|
$
|
145
|
$
|
151
|
$
|
183
|
$
|
251
|
$
|
929
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ACE expects to fund these expenditures
through internally generated cash and from external financing and capital
contributions from PHI.
Distribution, Transmission and Gas
Delivery
The projected capital expenditures for
distribution (other than Blueprint for the Future), transmission (other than
MAPP) and gas delivery are primarily for facility replacements and upgrades to
accommodate customer growth and reliability.
During 2007, PHI announced an
initiative in ACE’s service territory referred to as the “Blueprint for the
Future.” This initiative combines traditional energy efficiency programs with
new technologies and systems to help customers manage their energy use and
reduce the total cost of energy, and includes the installation of “smart meters”
for all customers in New Jersey. In November 2007, ACE filed its
“Blueprint for the Future” proposal with the New Jersey Board of Public
Utilities.
On October 17, 2007, Pepco Holdings
received the approval of the PJM Board of Managers to build a new 230-mile,
500-kilovolt interstate transmission line as part of PJM’s Regional Transmission
Expansion Plan to address the reliability objectives of the PJM RTO
system. The transmission line, which is referred to as the MAPP
Project, will be located in northern Virginia, Maryland, the Delmarva Peninsula,
and New Jersey. The preliminarily estimated cost of the 500-kilovolt
MAPP Project is approximately $1 billion. ACE’s portion of the
preliminary estimated cost of the 500-kilovolt transmission line is
approximately $27 million. Construction is expected to occur in
sections over a six-year period with completion targeted by 2013.
PHI also plans to add significant
230-kilovolt support lines in Maryland and New Jersey to connect with the new
500-kilovolt line at an approximate cost of $200 million. PJM
continues to evaluate the 230-kilovolt support lines. Accordingly,
ACE’s projected construction costs associated with these support lines are not
included in the table above.
FORWARD-LOOKING
STATEMENTS
Some of the statements contained in
this Annual Report on Form 10-K are forward-looking statements within the
meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and
are subject to the safe harbor created by the Private Securities Litigation
Reform Act of 1995. These statements include declarations regarding ACE’s
intents, beliefs and current expectations. In some cases, you can identify
forward-looking statements by terminology such as “may,” “will,” “should,”
“expects,” “plans,” “anticipates,” “believes,” “estimates,” “predicts,”
“potential” or “continue” or the negative of such terms or other comparable
terminology. Any forward-looking statements are not guarantees of future
performance, and actual results could differ materially from those indicated by
the forward-looking statements. Forward-looking statements involve estimates,
assumptions, known and unknown risks, uncertainties and other factors that may
cause ACE or ACE’s industry’s actual results, levels of activity, performance or
achievements to be materially different from any future results, levels of
activity, performance or achievements expressed or implied by such
forward-looking statements.
The forward-looking statements
contained herein are qualified in their entirety by reference to the following
important factors, which are difficult to predict, contain uncertainties, are
beyond ACE’s control and may cause actual results to differ materially from
those contained in forward-looking statements:
|
|
·
|
Prevailing
governmental policies and regulatory actions affecting the energy
industry, including allowed rates of return, industry and rate structure,
acquisition and disposal of assets and facilities, operation and
construction of plant facilities, recovery of purchased power expenses,
and present or prospective wholesale and retail
competition;
|
|
|
·
|
Changes
in and compliance with environmental and safety laws and
policies;
|
|
|
·
|
Population
growth rates and demographic
patterns;
|
|
|
·
|
Competition
for retail and wholesale customers;
|
|
|
·
|
General
economic conditions, including potential negative impacts resulting from
an economic downturn;
|
|
|
·
|
Growth
in demand, sales and capacity to fulfill
demand;
|
|
|
·
|
Changes
in tax rates or policies or in rates of
inflation;
|
|
|
·
|
Changes
in project costs;
|
|
|
·
|
Unanticipated
changes in operating expenses and capital
expenditures;
|
|
|
·
|
The
ability to obtain funding in the capital markets on favorable
terms;
|
|
|
·
|
Restrictions
imposed by federal and/or state regulatory commissions, PJM, the North
American Electric Reliability Council and other applicable electric
reliability organizations;
|
|
|
·
|
Legal
and administrative proceedings (whether civil or criminal) and settlements
that affect ACE’s business and
profitability;
|
|
|
·
|
Volatility
in market demand and prices for energy, capacity and
fuel;
|
|
|
·
|
Interest
rate fluctuations and credit market concerns;
and
|
|
|
·
|
Effects
of geopolitical events, including the threat of domestic
terrorism.
|
Any forward-looking statements speak
only as to the date of this Annual Report and ACE undertakes no obligation to
update any forward looking statements to reflect events or circumstances after
the date on which such statements are made or to reflect the occurrence of
anticipated events. New factors emerge from time to time, and it is
not possible for ACE to predict all of such factors, nor can ACE assess the
impact of any such factor on our business or the extent to which any factor, or
combination of factors, may cause results to differ materially from those
contained in any forward-looking statement.
The foregoing review of factors should
not be construed as exhaustive.
THIS
PAGE LEFT INTENTIONALLY BLANK.
|
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,
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 Corporate Risk Management Committee 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.
Pepco Holdings,
Inc.
Commodity Price
Risk
PHI’s Competitive Energy businesses use
derivative instruments primarily to reduce their financial exposure to changes
in the value of their assets and obligations due to commodity price
fluctuations. The derivative instruments used by the Competitive Energy
businesses include forward contracts, futures, swaps, and exchange-traded and
over-the-counter options. In addition, the Competitive Energy businesses also
manage commodity risk with contracts that are not classified as
derivatives. The two primary risk management objectives are (1) to
manage the spread between the cost of fuel used to operate electric generation
plants and the revenue received from the sale of the power produced by those
plants, and (2) to manage the spread between retail sales commitments and the
cost of supply used to service those commitments to ensure stable and known
minimum cash flows, and lock in favorable prices and margins when they become
available. To a lesser extent, Conectiv Energy also engages in energy
marketing activities. Energy marketing activities consist primarily
of wholesale natural gas and fuel oil marketing; the activities of the
short-term power desk, which generates margin by capturing price differences
between power pools, and locational and timing differences within a power pool;
and prior to October 31, 2006, provided operating services under an
agreement with an unaffiliated generating plant. PHI collectively
refers to these energy marketing activities, including its commodity risk
management activities, as “other energy commodity” activities and identifies
this activity separately from the discontinued proprietary trading activity that
was discontinued in 2003.
The Corporate Risk Management Committee
has the responsibility for establishing corporate compliance requirements for
the Competitive Energy businesses’ energy market participation. PHI
collectively refers to these energy market activities, including its commodity
risk management activities, as “other energy commodity”
activities. PHI does not engage in proprietary trading
activities. PHI uses a value-at-risk (VaR) model to assess the market
risk of its Competitive Energy businesses’ energy commodity
activities. 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
mark-to-market loss on energy contracts or portfolios due to changes in market
prices for a specified time period and confidence level. PHI
estimates VaR using a delta-normal variance / covariance model with a 95
percent, one-tailed confidence level and assuming a one-day holding
period. Since VaR is an estimate, it is not necessarily indicative of
actual results that may occur.
|
Value
at Risk Associated with Energy Contracts
(Millions
of dollars)
|
|
|
Proprietary
Trading
VaR
|
|
VaR
for
Competitive
Energy
Activity (a)
|
|
95%
confidence level, one-day
holding
period, one-tailed
|
|
|
|
|
|
|
Period
end
|
$
|
-
|
|
$
|
4.2
|
|
Average
for the period
|
$
|
-
|
|
$
|
5.8
|
|
High
|
$
|
-
|
|
$
|
12.0
|
|
Low
|
$
|
-
|
|
$
|
2.1
|
|
|
(a)
|
This
column represents all energy derivative contracts, normal purchase and
sales contracts, modeled generation output and fuel requirements and
modeled customer load obligations for PHI’s other energy commodity
activities.
|
For additional information about PHI’s
derivative activities refer to Note (2), “Accounting for Derivatives” and Note
13, “Use of Derivatives in Energy and Interest Rate Hedging Activities” of the
Consolidated Financial Statements of Pepco Holdings included in Item
8.
A significant portion of the Conectiv
Energy’s portfolio of electric generating plants consists of “mid-merit” assets
and peaking assets. Mid-merit electric generating plants are
typically combined cycle units that can quickly change their megawatt output
level on an economic basis. These plants are generally operated
during times when demand for electricity rises and power prices are
higher. Conectiv Energy economically hedges both the estimated plant
output and fuel requirements as the estimated levels of output and fuel needs
change. Economic hedge percentages include the estimated electricity
output of Conectiv Energy’s generation plants and any associated financial or
physical commodity contracts (including derivative contracts that are classified
as cash flow hedges under SFAS No. 133, other derivative instruments, wholesale
normal purchase and sales contracts, and load service obligations).
Conectiv Energy maintains a forward 36
month program with targeted ranges for economically hedging its projected
on-peak plant output combined with its on-peak energy purchase commitments
(based on the then current forward electricity price curve) as
follows:
|
Month
|
Target Range
|
|
|
50-100%
|
|
13-24
|
25-75%
|
|
25-36
|
0-50%
|
The primary purpose of the risk
management program is to improve the predictability and stability of margins by
selling forward a portion of its projected plant output, and buying forward a
portion of its projected fuel supply requirements. Within each
period, hedged percentages can vary significantly above or below the average
reported percentages.
As of December 31, 2007, the
electricity sold forward by Conectiv Energy as a percentage of projected on-peak
plant output combined with on-peak energy purchase commitments was 94%, 98%, and
39% for the 1-12 month, 13-24 month and 25-36 month forward periods,
respectively. Hedge percentages were above the target ranges for the
13-24 month period due to Conectiv Energy’s success in the default electricity
supply auctions and a decrease in projected on-peak plant output since the
forward sale commitments were entered into. The amount of forward
on-peak sales during the 1-12 month period represents 22% of Conectiv Energy’s
combined total on-peak generating capability and on-peak energy purchase
commitments. The volumetric percentages for the forward periods can
vary and may not represent the amount of expected value hedged.
Not all of the value associated with
Conectiv Energy’s generation activities can be hedged such as the portion
attributable to ancillary services and fuel switching due to the lack of market
products, market liquidity, and other factors. Also the hedging of
locational value can be limited.
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 delivery to customers. Pepco Energy Services accounts for its
futures and swap contracts as cash flow hedges of forecasted
transactions. Its options contracts are marked-to-market through
current earnings. Its forward contracts are accounted for using
standard accrual accounting since these contracts meet the requirements for
normal purchase and sale accounting under SFAS No. 133.
Credit and Nonperformance
Risk
Pepco Holdings’ subsidiaries attempt
to minimize credit risk exposure to wholesale energy counterparties through,
among other things, formal credit policies, regular assessment of counterparty
creditworthiness and the establishment of a credit limit for each counterparty,
monitoring procedures that include stress testing, the use of standard
agreements which allow for the netting of positive and negative exposures
associated with a single counterparty and collateral requirements under certain
circumstances, and have established reserves for credit losses. As of
December 31, 2007, credit exposure to wholesale energy counterparties was
weighted 74% with investment grade counterparties, 22% with counterparties
without external credit quality ratings, and 4% with non-investment grade
counterparties.
This table provides information on
the Competitive Energy businesses’ credit exposure, net of collateral, to
wholesale counterparties.
|
Schedule
of Credit Risk Exposure on Competitive Wholesale Energy
Contracts
(Millions
of dollars)
|
|
|
|
|
Rating (a)
|
Exposure
Before Credit Collateral
(b)
|
Credit
Collateral
(c)
|
Net
Exposure
|
Number
of Counterparties Greater Than 10% (d)
|
Net
Exposure of Counterparties Greater Than 10%
|
|
|
|
|
|
|
|
|
Investment
Grade
|
$116.5
|
$3.0
|
$113.5
|
1
|
$22.4
|
|
Non-Investment
Grade
|
7.1
|
.6
|
6.5
|
-
|
|
|
No
External Ratings
|
34.6
|
.7
|
33.9
|
-
|
|
|
Credit
reserves
|
|
|
$ 1.7
|
|
|
|
|
(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 (MTM) energy
contract net assets for open/unrealized transactions, the net
receivable/payable for realized transactions and net open positions for
contracts not subject to MTM. 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 gas reserves).
|
|
|
(d)
|
Using
a percentage of the total exposure.
|
Interest Rate
Risk
Pepco Holdings manages interest rates
through the use of fixed and, to a lesser extent, variable rate
debt. 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. The effect of a hypothetical 10% change in interest
rates on the annual interest costs for short-term and variable rate debt was
approximately $4.5 million as of December 31, 2007.
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 approximately $.9
million as of December 31, 2007.
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 gas commodity price volatility while limiting its
firm customers’ exposure to increases in the market price of 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 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 gas cost rate clause
included in DPL’s gas tariff rates approved by the Delaware Public Service
Commission and are deferred under SFAS No. 71 until recovered. At
December 31, 2007, DPL had a net deferred derivative payable of $13.1 million,
offset by a $13.1 million regulatory asset. At December 31,
2006, DPL had a net deferred derivative payable of $27.3 million, offset by a
$28.5 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 approximately $.9
million as of December 31, 2007.
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 approximately $.5
million as of December 31, 2007.
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.
|
|
Registrants
|
|
Item
|
Pepco
Holdings
|
Pepco *
|
DPL *
|
ACE
|
|
Management’s
Report on Internal Control
Over
Financial Reporting
|
142
|
226
|
264
|
297
|
|
Report
of Independent Registered
Public
Accounting Firm
|
143
|
227
|
265
|
298
|
|
Consolidated
Statements of Earnings
|
145
|
228
|
266
|
299
|
|
Consolidated
Statements
of
Comprehensive Earnings
|
146
|
229
|
N/A
|
N/A
|
|
Consolidated
Balance Sheets
|
147
|
230
|
267
|
300
|
|
Consolidated
Statements of Cash Flows
|
149
|
232
|
269
|
302
|
|
Consolidated
Statements
of
Shareholders’ Equity
|
150
|
233
|
270
|
303
|
|
Notes
to Consolidated
Financial
Statements
|
151
|
234
|
271
|
304
|
* Pepco
and DPL have no subsidiaries and therefore their financial statements are not
consolidated.
THIS
PAGE LEFT INTENTIONALLY BLANK.
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. Because of 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 assessed its internal
control over financial reporting as of December 31, 2007 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 its internal control over financial reporting
was effective as of December 31, 2007.
PricewaterhouseCoopers LLP, the
registered public accounting firm that audited the financial statements of Pepco
Holdings included in this Annual Report on Form 10-K, has issued its attestation
report on Pepco Holdings’ internal control over financial reporting, which is
included herein.
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
present fairly, in all material respects, the financial position of Pepco
Holdings, Inc. and its subsidiaries at December 31, 2007 and December 31, 2006,
and the results of their operations and their cash flows for each of the three
years in the period ended December 31, 2007 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 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, 2007, 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 Management’s Report on
Internal Control Over Financial Reporting appearing under Item 8. 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.
As
discussed in Note 8 to the consolidated financial statements, the Company
changed its manner of accounting and reporting for uncertain tax positions in
2007.
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.
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.
PricewaterhouseCoopers
LLP
Washington,
DC
|
PEPCO
HOLDINGS, INC. AND SUBSIDIARIES
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
(in
millions, except per share data)
|
|
|
|
|
|
|
|
|
|
|
Operating
Revenue
|
|
|
|
|
|
|
|
|
|
|
Power
Delivery
|
|
$ |
5,244.2 |
|
|
$ |
5,118.8 |
|
|
$ |
4,702.9 |
|
|
Competitive
Energy
|
|
|
4,054.0 |
|
|
|
3,160.8 |
|
|
|
3,288.2 |
|
|
Other
|
|
|
68.2 |
|
|
|
83.3 |
|
|
|
74.4 |
|
|
Total
Operating Revenue
|
|
|
9,366.4 |
|
|
|
8,362.9 |
|
|
|
8,065.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and purchased energy
|
|
|
6,336.4 |
|
|
|
5,416.5 |
|
|
|
4,899.7 |
|
|
Other
services cost of sales
|
|
|
606.9 |
|
|
|
649.4 |
|
|
|
712.3 |
|
|
Other
operation and maintenance
|
|
|
857.5 |
|
|
|
807.3 |
|
|
|
815.7 |
|
|
Depreciation
and amortization
|
|
|
365.9 |
|
|
|
413.2 |
|
|
|
427.3 |
|
|
Other
taxes
|
|
|
357.1 |
|
|
|
343.0 |
|
|
|
342.2 |
|
|
Deferred
electric service costs
|
|
|
68.1 |
|
|
|
22.1 |
|
|
|
120.2 |
|
|
Impairment
losses
|
|
|
2.0 |
|
|
|
18.9 |
|
|
|
- |
|
|
Effect
of settlement of Mirant bankruptcy claims
|
|
|
(33.4 |
) |
|
|
- |
|
|
|
(70.5 |
) |
|
Gain
on sale of assets
|
|
|
(.7 |
) |
|
|
(.8 |
) |
|
|
(86.8 |
) |
|
Total
Operating Expenses
|
|
|
8,559.8 |
|
|
|
7,669.6 |
|
|
|
7,160.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Income
|
|
|
806.6 |
|
|
|
693.3 |
|
|
|
905.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Income (Expenses)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
and dividend income
|
|
|
19.6 |
|
|
|
16.9 |
|
|
|
16.0 |
|
|
Interest
expense
|
|
|
(339.8 |
) |
|
|
(339.1 |
) |
|
|
(337.6 |
) |
|
Income
(loss) from equity investments
|
|
|
10.1 |
|
|
|
5.1 |
|
|
|
(2.2 |
) |
|
Impairment
loss on equity investments
|
|
|
- |
|
|
|
(1.8 |
) |
|
|
(4.1 |
) |
|
Other
income
|
|
|
27.7 |
|
|
|
48.3 |
|
|
|
50.8 |
|
|
Other
expenses
|
|
|
(1.8 |
) |
|
|
(11.8 |
) |
|
|
(8.4 |
) |
|
Total
Other Expenses
|
|
|
(284.2 |
) |
|
|
(282.4 |
) |
|
|
(285.5 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
Stock Dividend Requirements of Subsidiaries
|
|
|
.3 |
|
|
|
1.2 |
|
|
|
2.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Before Income Tax Expense and Extraordinary Item
|
|
|
522.1 |
|
|
|
409.7 |
|
|
|
617.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
|
187.9 |
|
|
|
161.4 |
|
|
|
255.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Before Extraordinary Item
|
|
|
334.2 |
|
|
|
248.3 |
|
|
|
362.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Extraordinary
Item (net of tax of $6.2 million)
|
|
|
- |
|
|
|
- |
|
|
|
9.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
Income
|
|
$ |
334.2 |
|
|
$ |
248.3 |
|
|
$ |
371.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
and Diluted Share Information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
average shares outstanding
|
|
|
194.1 |
|
|
|
190.7 |
|
|
|
189.0 |
|
|
Earnings
per share of common stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Before
extraordinary item
|
|
$ |
1.72 |
|
|
$ |
1.30 |
|
|
$ |
1.91 |
|
|
Extraordinary
item
|
|
|
- |
|
|
|
- |
|
|
|
.05 |
|
|
Total
|
|
$ |
1.72 |
|
|
$ |
1.30 |
|
|
$ |
1.96 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
accompanying Notes are an integral part of these Consolidated Financial
Statements.
|
|
|
PEPCO
HOLDINGS, INC. AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF COMPREHENSIVE EARNINGS
|
|
|
|
|
2006
|
2005
|
|
(Millions
of dollars)
|
|
|
Net
income
|
$334.2
|
$248.3
|
$371.2
|
|
|
|
|
|
|
Other
comprehensive earnings (losses)
|
|
|
|
|
|
|
|
|
|
Unrealized
gains (losses) on commodity
derivatives
designated as cash flow hedges:
|
|
|
|
|
Unrealized
holding (losses) gains
arising
during period
|
(.3)
|
(143.8)
|
117.1
|
|
Less: reclassification
adjustment for
(losses)
gains included in net earnings
|
(84.3)
|
(2.3)
|
76.1
|
|
Net
unrealized gains (losses) on
commodity
derivatives
|
84.0
|
(141.5)
|
41.0
|
|
|
|
|
|
|
Realized
gains on Treasury Lock transaction
|
9.4
|
11.7
|
11.7
|
|
|
|
|
|
|
Unrealized
gains on interest rate swap
agreements
designated as cash flow hedges:
|
|
|
|
|
Unrealized
holding gains arising
during
period
|
-
|
-
|
1.5
|
|
Less: reclassification
adjustment for gains
included
in net earnings
|
-
|
-
|
1.1
|
|
Net
unrealized gains on interest rate swaps
|
-
|
-
|
.4
|
|
|
|
|
|
|
Minimum
pension liability adjustment
|
-
|
(1.2)
|
(5.2)
|
|
|
|
|
|
|
Amortization
of gains and losses for prior service cost
|
1.6
|
-
|
-
|
|
|
|
|
|
|
Other
comprehensive earnings (losses), before income taxes
|
95.0
|
(131.0)
|
47.9
|
|
Income
tax expense (benefit)
|
37.1
|
(50.8)
|
18.7
|
|
|
|
|
|
|
Other
comprehensive earnings (losses), net of income taxes
|
57.9
|
(80.2)
|
29.2
|
|
|
|
|
|
|
Comprehensive
earnings
|
$392.1
|
$168.1
|
$400.4
|
|
|
|
|
|
|
The
accompanying Notes are an integral part of these Consolidated Financial
Statements.
|
|
|
PEPCO
HOLDINGS, INC. AND SUBSIDIARIES
CONSOLIDATED
BALANCE SHEETS
|
|
|
ASSETS
|
|
|
|
|
|
|
|
(Millions
of dollars)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CURRENT
ASSETS
|
|
|
|
|
|
|
|
Cash
and cash equivalents
|
|
$ |
55.1 |
|
|
$ |
48.8 |
|
|
Restricted
cash
|
|
|
14.5 |
|
|
|
12.0 |
|
|
Accounts
receivable, less allowance for
uncollectible
accounts of $30.6 million and
$35.8
million, respectively
|
|
|
1,278.3 |
|
|
|
1,253.5 |
|
|
Fuel,
materials and supplies - at average cost
|
|
|
287.9 |
|
|
|
288.8 |
|
|
Unrealized
gains - derivative contracts
|
|
|
26.7 |
|
|
|
72.7 |
|
|
Prepayments
of income taxes
|
|
|
249.8 |
|
|
|
228.4 |
|
|
Prepaid
expenses and other
|
|
|
84.8 |
|
|
|
77.2 |
|
|
Total
Current Assets
|
|
|
1,997.1 |
|
|
|
1,981.4 |
|
|
|
|
|
|
|
|
|
|
|
|
INVESTMENTS
AND OTHER ASSETS
|
|
|
|
|
|
|
|
|
|
Goodwill
|
|
|
1,409.6 |
|
|
|
1,409.2 |
|
|
Regulatory
assets
|
|
|
1,515.7 |
|
|
|
1,570.8 |
|
|
Investment
in finance leases held in Trust
|
|
|
1,384.4 |
|
|
|
1,321.8 |
|
|
Income
taxes receivable
|
|
|
196.1 |
|
|
|
- |
|
|
Restricted
cash and cash equivalents
|
|
|
424.1 |
|
|
|
17.5 |
|
|
Other
|
|
|
307.3 |
|
|
|
366.2 |
|
|
Total
Investments and Other Assets
|
|
|
5,237.2 |
|
|
|
4,685.5 |
|
|
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
|
|
Property,
plant and equipment
|
|
|
12,306.5 |
|
|
|
11,819.7 |
|
|
Accumulated
depreciation
|
|
|
(4,429.8 |
) |
|
|
(4,243.1 |
) |
|
Net
Property, Plant and Equipment
|
|
|
7,876.7 |
|
|
|
7,576.6 |
|
|
TOTAL
ASSETS
|
|
$ |
15,111.0 |
|
|
$ |
14,243.5 |
|
| |
|
|
The
accompanying Notes are an integral part of these Consolidated Financial
Statements.
|
|
|
PEPCO
HOLDINGS, INC. AND SUBSIDIARIES
CONSOLIDATED
BALANCE SHEETS
|
|
LIABILITIES
AND SHAREHOLDERS’ EQUITY
|
|
|
|
|
|
(Millions
of dollars, except shares)
|
|
|
|
|
|
|
CURRENT
LIABILITIES
|
|
|
|
|
Short-term
debt
|
|
$ |
288.8 |
|
|
$ |
349.6 |
|
|
Current
maturities of long-term debt and project funding
|
|
|
332.2 |
|
|
|
857.5 |
|
|
Accounts
payable and accrued liabilities
|
|
|
796.7 |
|
|
|
700.7 |
|
|
Capital
lease obligations due within one year
|
|
|
6.0 |
|
|
|
5.5 |
|
|
Taxes
accrued
|
|
|
133.5 |
|
|
|
99.9 |
|
|
Interest
accrued
|
|
|
70.1 |
|
|
|
80.1 |
|
|
Liabilities
and accrued interest related to uncertain tax positions
|
|
|
131.7 |
|
|
|
- |
|
|
Other
|
|
|
281.8 |
|
|
|
440.7 |
|
|
Total
Current Liabilities
|
|
|
2,040.8 |
|
|
|
2,534.0 |
|
|
|
|
|
|
|
|
|
|
|
|
DEFERRED
CREDITS
|
|
|
|
|
|
|
|
|
|
Regulatory
liabilities
|
|
|
1,248.9 |
|
|
|
842.7 |
|
|
Deferred
income taxes, net
|
|
|
2,105.1 |
|
|
|
2,084.0 |
|
|
Investment
tax credits
|
|
|
38.9 |
|
|
|
46.1 |
|
|
Pension
benefit obligation
|
|
|
65.5 |
|
|
|
78.3 |
|
|
Other
postretirement benefit obligations
|
|
|
385.5 |
|
|
|
405.0 |
|
|
Income
taxes payable
|
|
|
164.9 |
|
|
|
- |
|
|
Other
|
|
|
302.2 |
|
|
|
249.4 |
|
|
Total
Deferred Credits
|
|
|
4,311.0 |
|
|
|
3,705.5 |
|
|
|
|
|
|
|
|
|
|
|
|
LONG-TERM
LIABILITIES
|
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
4,174.8 |
|
|
|
3,768.6 |
|
|
Transition
Bonds issued by ACE Funding
|
|
|
433.5 |
|
|
|
464.4 |
|
|
Long-term
project funding
|
|
|
20.9 |
|
|
|
23.3 |
|
|
Capital
lease obligations
|
|
|
105.4 |
|
|
|
111.1 |
|
|
Total
Long-Term Liabilities
|
|
|
4,734.6 |
|
|
|
4,367.4 |
|
|
|
|
|
|
|
|
|
|
|
|
COMMITMENTS
AND CONTINGENCIES (NOTE 12)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MINORITY
INTEREST
|
|
|
6.2 |
|
|
|
24.4 |
|
|
|
|
|
|
|
|
|
|
|
|
SHAREHOLDERS’
EQUITY
|
|
|
|
|
|
|
|
|
|
Common
stock, $.01 par value - authorized 400,000,000 shares -
issued
200,512,890 shares and 191,932,445 shares, respectively
|
|
|
2.0 |
|
|
|
1.9 |
|
|
Premium
on stock and other capital contributions
|
|
|
2,869.2 |
|
|
|
2,645.0 |
|
|
Accumulated
other comprehensive loss
|
|
|
(45.5 |
) |
|
|
(103.4 |
) |
|
Retained
earnings
|
|
|
1,192.7 |
|
|
|
1,068.7 |
|
|
Total
Shareholders’ Equity
|
|
|
4,018.4 |
|
|
|
3,612.2 |
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
$ |
15,111.0 |
|
|
$ |
14,243.5 |
|
|
|
|
|
|
|
|
|
|
|
|
The
accompanying Notes are an integral part of these Consolidated Financial
Statements.
|
|
PEPCO
HOLDINGS, INC. AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
(Millions
of dollars)
|
|
|
|
|
|
|
|
|
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
$
|
334.2
|
|
|
$
|
248.3
|
|
|
$
|
371.2
|
|
|
Adjustments
to reconcile net income to net cash from operating
activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation
and amortization
|
|
|
365.9
|
|
|
|
413.2
|
|
|
|
427.3
|
|
|
Gain
on sale of assets
|
|
|
(.7)
|
|
|
|
(.8)
|
|
|
|
(86.8)
|
|
|
Effect
of settlement of Mirant bankruptcy claims
|
|
|
(33.4)
|
|
|
|
-
|
|
|
|
(70.5)
|
|
|
Gain
on sale of other investment
|
|
|
(.1)
|
|
|
|
(13.2)
|
|
|
|
(8.0)
|
|
|
Extraordinary
item
|
|
|
-
|
|
|
|
-
|
|
|
|
(15.2)
|
|
|
Rents
received from leveraged leases under income earned
|
|
|
(72.5)
|
|
|
|
(56.1)
|
|
|
|
(79.3)
|
|
|
Impairment
losses
|
|
|
2.0
|
|
|
|
20.7
|
|
|
|
4.1
|
|
|
Proceeds
from sale of claims with Mirant
|
|
|
-
|
|
|
|
-
|
|
|
|
112.9
|
|
|
Proceeds
from settlement of Mirant bankruptcy claims
|
|
|
507.2
|
|
|
|
70.0
|
|
|
|
-
|
|
|
Reimbursements
to Mirant
|
|
|
(108.3)
|
|
|
|
-
|
|
|
|
-
|
|
|
Changes
in restricted cash and cash equivalents related to Mirant
settlement
|
|
|
(417.3)
|
|
|
|
-
|
|
|
|
-
|
|
|
Deferred
income taxes
|
|
|
82.7
|
|
|
|
243.6
|
|
|
|
(51.6)
|
|
|
Investment
tax credit adjustments
|
|
|
(2.5)
|
|
|
|
(4.7)
|
|
|
|
(5.1)
|
|
|
Prepaid
pension expense
|
|
|
12.6
|
|
|
|
21.9
|
|
|
|
(43.2)
|
|
|
Energy
supply contracts
|
|
|
(2.6)
|
|
|
|
(5.1)
|
|
|
|
(11.3)
|
|
|
Other
deferred charges
|
|
|
71.2
|
|
|
|
(94.9)
|
|
|
|
17.0
|
|
|
Other
deferred credits
|
|
|
(21.9)
|
|
|
|
18.4
|
|
|
|
(29.1)
|
|
|
Changes
in:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts
receivable
|
|
|
(28.3)
|
|
|
|
225.1
|
|
|
|
(153.7)
|
|
|
Regulatory
assets and liabilities
|
|
|
3.5
|
|
|
|
(31.8)
|
|
|
|
76.1
|
|
|
Prepaid
expenses
|
|
|
(18.0)
|
|
|
|
4.5
|
|
|
|
10.3
|
|
|
Fuel,
materials and supplies
|
|
|
(3.8)
|
|
|
|
(8.3)
|
|
|
|
(76.4)
|
|
|
Accounts
payable and accrued liabilities
|
|
|
48.3
|
|
|
|
(375.3)
|
|
|
|
327.5
|
|
|
Interest
and taxes accrued
|
|
|
29.0
|
|
|
|
(472.9)
|
|
|
|
270.7
|
|
|
Sale
of emission allowances
|
|
|
47.8
|
|
|
|
-
|
|
|
|
-
|
|
|
Net
Cash From Operating Activities
|
|
|
795.0
|
|
|
|
202.6
|
|
|
|
986.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
investment in property, plant and equipment
|
|
|
(623.4)
|
|
|
|
(474.6)
|
|
|
|
(467.1)
|
|
|
Proceeds
from settlement of Mirant bankruptcy claims representing
reimbursement
for investment in property, plant and equipment
|
|
|
15.0
|
|
|
|
-
|
|
|
|
-
|
|
|
Proceeds
from/changes in:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sale
of other assets
|
|
|
11.2
|
|
|
|
181.5
|
|
|
|
84.1
|
|
|
Purchases
of other investments
|
|
|
(1.0)
|
|
|
|
(.6)
|
|
|
|
(2.1)
|
|
|
Sale
of other investments
|
|
|
1.2
|
|
|
|
24.2
|
|
|
|
33.8
|
|
|
Net
investment in receivables
|
|
|
2.4
|
|
|
|
2.2
|
|
|
|
(7.1)
|
|
|
Changes
in restricted cash
|
|
|
8.2
|
|
|
|
11.0
|
|
|
|
19.0
|
|
|
Net
other investing activities
|
|
|
4.8
|
|
|
|
27.2
|
|
|
|
5.5
|
|
|
Net
Cash Used By Investing Activities
|
|
|
(581.6)
|
|
|
|
(229.1)
|
|
|
|
(333.9)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends
paid on preferred stock of subsidiaries
|
|
|
(.3)
|
|
|
|
(1.2)
|
|
|
|
(2.5)
|
|
|
Dividends
paid on common stock
|
|
|
(202.6)
|
|
|
|
(198.3)
|
|
|
|
(188.9)
|
|
|
Common
stock issued to the Dividend Reinvestment Plan
|
|
|
28.0
|
|
|
|
29.8
|
|
|
|
27.5
|
|
|
Redemption
of preferred stock of subsidiaries
|
|
|
(18.2)
|
|
|
|
(21.5)
|
|
|
|
(9.0)
|
|
|
Redemption
of variable rate demand bonds
|
|
|
(2.5)
|
|
|
|
-
|
|
|
|
(2.0)
|
|
|
Issuance
of common stock
|
|
|
199.6
|
|
|
|
17.0
|
|
|
|
5.7
|
|
|
Issuances
of long-term debt
|
|
|
703.9
|
|
|
|
514.5
|
|
|
|
532.0
|
|
|
Reacquisition
of long-term debt
|
|
|
(854.9)
|
|
|
|
(578.0)
|
|
|
|
(755.8)
|
|
|
(Repayments)
issuances of short-term debt, net
|
|
|
(58.3)
|
|
|
|
193.2
|
|
|
|
(161.3)
|
|
|
Cost
of issuances
|
|
|
(6.7)
|
|
|
|
(5.6)
|
|
|
|
(9.0)
|
|
|
Net
other financing activities
|
|
|
4.9
|
|
|
|
3.9
|
|
|
|
2.3
|
|
|
Net
Cash Used By Financing Activities
|
|
|
(207.1)
|
|
|
|
(46.2)
|
|
|
|
(561.0)
|
|
|
Net
Increase (Decrease) In Cash and Cash Equivalents
|
|
|
6.3
|
|
|
|
(72.7)
|
|
|
|
92.0
|
|
|
Cash
and Cash Equivalents at Beginning of Year
|
|
|
48.8
|
|
|
|
121.5
|
|
|
|
29.5
|
|
|
CASH
AND CASH EQUIVALENTS AT END OF YEAR
|
|
$
|
55.1
|
|
|
$
|
48.8
|
|
|
$
|
121.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NON-CASH
ACTIVITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset
retirement obligations associated with removal costs
transferred
to
regulatory liabilities
|
|
$
|
9.7
|
|
|
$
|
78.0
|
|
|
$
|
(9.9)
|
|
|
Excess
accumulated depreciation transferred to regulatory
liabilities
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
131.0
|
|
|
Sale
of financed project account receivables
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
50.0
|
|
|
Recoverable
pension/OPEB costs included in regulatory assets
|
|
$
|
(31.4)
|
|
|
$
|
365.4
|
|
|
$
|
-
|
|
|
Transfer
of combustion turbines to construction work in progress
|
|
$
|
57.0
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTAL
DISCLOSURE OF CASH FLOW INFORMATION
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
paid for interest (net of capitalized interest of $8.7 million, $3.8
million
and
$3.8 million, respectively) and paid for income taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
|
|
$
|
338.2
|
|
|
$
|
331.8
|
|
|
$
|
328.4
|
|
|
Income
taxes
|
|
$
|
35.7
|
|
|
$
|
238.6
|
|
|
$
|
44.1
|
|
|
The
accompanying Notes are an integral part of these Consolidated Financial
Statements.
|
|
PEPCO
HOLDINGS, INC. AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF SHAREHOLDERS’ EQUITY
|
|
|
Common Stock
Shares Par
Value
|
|
Premium
on
Stock
|
Capital
Stock Expense
|
Accumulated
Other Comprehensive (Loss) Earnings
|
|
Retained
Earnings
|
|
(Millions
of dollars, except shares)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
188,327,510
|
|
$ |
1.9
|
|
$2,566.2
|
$(13.5)
|
$(52.0
|
)
|
$836.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
Income
|
-
|
|
|
-
|
|
-
|
-
|
-
|
|
371.2
|
|
Other
comprehensive income
|
-
|
|
|
-
|
|
-
|
-
|
29.2
|
|
-
|
|
Dividends
on common stock
($1.00/sh.)
|
-
|
|
|
-
|
|
-
|
-
|
-
|
|
(188.9)
|
|
Reacquisition
of subsidiary
preferred
stock
|
-
|
|
|
-
|
|
.1
|
-
|
-
|
|
-
|
|
Issuance
of common stock:
|
|
|
|
|
|
|
|
|
|
|
|
Original
issue shares
|
261,708
|
|
|
-
|
|
5.7
|
-
|
-
|
|
-
|
|
DRP
original shares
|
1,228,505
|
|
|
-
|
|
27.5
|
-
|
-
|
|
-
|
|
Reacquired
Conectiv and
Pepco
PARS
|
-
|
|
|
-
|
|
.3
|
-
|
-
|
|
-
|
|
|
189,817,723
|
|
|
1.9
|
|
2,599.8
|
(13.5)
|
(22.8)
|
|
1,018.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
Income
|
-
|
|
|
-
|
|
-
|
-
|
-
|
|
248.3
|
|
Other
comprehensive loss
|
-
|
|
|
-
|
|
-
|
-
|
(80.2)
|
|
-
|
|
Impact
of initially applying SFAS No. 158, net of tax
|
-
|
|
|
-
|
|
-
|
-
|
(.4)
|
|
-
|
|
Dividends
on common stock
($1.04/sh.)
|
-
|
|
|
-
|
|
-
|
-
|
-
|
|
(198.3)
|
|
Reacquisition
of subsidiary
preferred
stock
|
-
|
|
|
-
|
|
(.4)
|
-
|
-
|
|
-
|
|
Issuance
of common stock:
|
|
|
|
|
|
|
|
|
|
|
|
Original
issue shares
|
882,153
|
|
|
-
|
|
17.0
|
-
|
-
|
|
-
|
|
DRP
original shares
|
1,232,569
|
|
|
-
|
|
29.8
|
-
|
-
|
|
-
|
|
Compensation
expense on
share-based
awards
|
-
|
|
|
-
|
|
13.1
|
-
|
-
|
|
-
|
|
Treasury
stock
|
-
|
|
|
-
|
|
(.8)
|
-
|
-
|
|
-
|
|
|
191,932,445
|
|
|
1.9
|
|
2,658.5
|
(13.5)
|
(103.4)
|
|
1,068.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
Income
|
-
|
|
|
-
|
|
-
|
-
|
-
|
|
334.2
|
|
Other
comprehensive income
|
-
|
|
|
-
|
|
-
|
-
|
57.9
|
|
-
|
|
Dividends
on common stock
($1.04/sh.)
|
-
|
|
|
-
|
|
-
|
-
|
-
|
|
(202.6)
|
|
Reacquisition
of subsidiary
preferred
stock
|
-
|
|
|
-
|
|
(.6)
|
-
|
-
|
|
-
|
|
Issuance
of common stock:
|
|
|
|
|
|
|
|
|
|
|
|
Original
issue shares
|
7,601,290
|
|
|
.1
|
|
199.5
|
(.2)
|
-
|
|
-
|
|
DRP
original shares
|
979,155
|
|
|
-
|
|
28.0
|
-
|
-
|
|
-
|
|
Compensation
expense on
share-based
awards
|
-
|
|
|
-
|
|
(2.5)
|
-
|
-
|
|
-
|
|
Cumulative
effect adjustment
related
to the implementation
of
FIN 48
|
-
|
|
|
-
|
|
-
|
-
|
-
|
|
(7.4)
|
|
LTIP
dividend
|
-
|
|
|
-
|
|
-
|
-
|
-
|
|
(.3)
|
|
Treasury
stock
|
|
|
|
-
|
|
-
|
-
|
-
|
|
.1
|
|
|
200,512,890
|
|
$ |
2.0
|
|
$2,882.9
|
$(13.7)
|
$(45.5)
|
|
$1,192.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
accompanying Notes are an integral part of these Consolidated Financial
Statements.
|
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 diversified energy
company that, through its operating subsidiaries, is engaged primarily in two
principal business operations:
|
|
·
|
electricity
and natural gas delivery (Power Delivery), conducted through the following
regulated public utility companies, each of which is a reporting company
under the Securities Exchange Act of 1934, as amended (the Exchange
Act):
|
|
o
|
Potomac
Electric Power Company (Pepco), which was incorporated in Washington, D.C.
in 1896 and became a domestic Virginia corporation in
1949.
|
|
o
|
Delmarva
Power & Light Company (DPL), which was incorporated in Delaware in
1909 and became a domestic Virginia corporation in 1979,
and
|
|
o
|
Atlantic
City Electric Company (ACE), which was incorporated in New Jersey in
1924.
|
|
|
·
|
competitive
energy generation, marketing and supply (Competitive Energy) conducted
through subsidiaries of Conectiv Energy Holding Company (Conectiv Energy)
and Pepco Energy Services, Inc. (Pepco Energy
Services).
|
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 the service company are
charged to PHI and the participating operating subsidiaries in accordance with
costing methodologies set forth in the service agreement.
The following is a description of each
of PHI’s two principal business operations.
Power
Delivery
The largest component of PHI’s business
is Power Delivery, which consists of the transmission, distribution and default
supply of electricity and the delivery and supply of natural gas.
PHI’s Power Delivery business is
conducted by its three regulated utility subsidiaries: Pepco, DPL and
ACE. Each subsidiary is a regulated public utility in the
jurisdictions that comprise its service territory. Pepco, DPL and ACE
each owns and operates a network of wires, substations and other equipment that
are classified either as transmission or distribution facilities.
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. Together the three companies constitute a single
segment for financial reporting purposes.
Each company is responsible for the
delivery of electricity and, in the case of DPL, natural gas in its service
territory, for which it is paid tariff rates established by the local public
service commission. Each company 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 varies by jurisdiction as
follows:
|
|
Delaware
|
|
| |
|
Standard
Offer Service (SOS) – on and after May 1,
2006 |
|
|
New
Jersey
|
Basic
Generation Service (BGS)
|
In this Form 10-K, these supply
services are referred to generally as Default Electricity Supply.
Competitive
Energy
The Competitive Energy business
provides competitive generation, marketing and supply of electricity and gas,
and related energy management services, primarily in the mid-Atlantic
region. PHI’s Competitive Energy operations are conducted through
subsidiaries of Conectiv Energy Holding Company (collectively, Conectiv Energy)
and Pepco Energy Services, Inc. and its subsidiaries (collectively, Pepco Energy
Services). Conectiv Energy and Pepco Energy Services are separate
operating segments for financial reporting purposes.
Other Business
Operations
Through its subsidiary Potomac Capital
Investment Corporation (PCI), PHI maintains a portfolio of cross-border energy
sale-leaseback transactions, with a book value at December 31, 2007 of
approximately $1.4 billion. This activity constitutes a fourth
operating segment, which is designated as “Other Non-Regulated” for financial
reporting purposes. For a discussion of PHI’s cross-border leasing
transactions, see “Regulatory and Other Matters -- Federal Tax Treatment of
Cross-Border Leases,” in Note (12), “Commitments and
Contingencies.”
(2) SUMMARY OF 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 a
20% to 50% voting interest and cannot exercise control over the operations and
policies of the investment. Undivided interests in several jointly
owned electric plants previously held by PHI, and certain transmission and other
facilities currently held, are consolidated in proportion to PHI’s percentage
interest in the facility.
In accordance with the provisions of
Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 46R
entitled “Consolidation of Variable Interest Entities” (FIN 46R), Pepco Holdings
consolidates those variable interest entities where Pepco Holdings or a
subsidiary has been determined to be primary beneficiary. FIN 46R
addresses conditions under which an entity should be consolidated based upon
variable interests rather than voting interests. For additional
information, see the FIN 46R discussion later in this Note.
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 estimates used by Pepco
Holdings include the assessment of contingencies, the calculation of future cash
flows and fair value amounts for use in goodwill and asset impairment
evaluations, fair value calculations (based on estimated market pricing)
associated with derivative instruments, pension and other postretirement
benefits assumptions, unbilled revenue calculations, the assessment of the
probability of recovery of regulatory assets, 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 that are probable and reasonably estimable.
Changes in Accounting
Estimates
During 2007, as a result of
depreciation studies presented as part of Pepco's and DPL’s Maryland rate cases,
the MPSC approved new lower depreciation rates for Maryland distribution assets
owned by Pepco and DPL. This resulted in lower depreciation expense
of approximately $19.1 million for the last six months of 2007.
During 2005, Pepco recorded the impact
of an increase in estimated unbilled revenue (electricity and gas delivered to
the customer but not yet billed), primarily reflecting a change in Pepco’s
unbilled revenue estimation process. This modification in accounting
estimate increased net earnings for the year ended December 31, 2005 by
approximately $2.2 million.
During 2005, DPL and ACE each recorded
the impact of reductions in estimated unbilled revenue, primarily reflecting an
increase in the estimated amount of power line losses (electricity lost in the
process of its transmission and distribution to customers). These
changes in accounting estimates reduced net earnings for the year ended December
31, 2005 by approximately $7.4 million, of which $1.0 million was attributable
to DPL and $6.4 million was attributable to ACE.
During 2005, Conectiv Energy increased
the estimated useful lives of its generation assets which resulted in lower
depreciation expense of approximately $5.3 million.
Revenue
Recognition
Regulated
Revenue
The Power Delivery businesses recognize
revenue upon delivery of electricity and gas to their customers, including
amounts for services rendered but not yet billed (unbilled
revenue). Pepco Holdings recorded amounts for unbilled revenue of
$169.8 million and $172.2 million as of December 31, 2007 and 2006,
respectively. These amounts are included in “Accounts
receivable.” Pepco Holdings’ 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 power line losses (estimates of electricity expected
to be lost in the process of its transmission and distribution to customers),
all of which are inherently uncertain and susceptible to change from period to
period, the impact of which could be material.
The 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 subsidiaries
and, as such, are billed to customers and recorded in “Operating
Revenues.” Accruals for 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 de minimis.
Competitive
Revenue
The Competitive Energy businesses
recognize revenue upon delivery of electricity and gas to the customer,
including amounts for electricity and gas delivered, but not yet
billed. Unrealized derivative gains and losses are recognized in
current earnings as revenue if the derivative activity does not qualify for
hedge accounting or normal sales treatment under Statement of Financial
Accounting Standards (SFAS) No. 133. Revenue for Pepco Energy
Services’ energy efficiency construction business is recognized using the
percentage-of-completion method which recognizes revenue as work is completed on
the contract, and revenues from its operation and maintenance and other products
and services contracts are recognized when earned. Revenue from the
Other Non-Regulated business lines is principally recognized when services are
performed or products are delivered; however, revenues from utility industry
services contracts are recognized using the percentage-of-completion
method.
Regulation of Power Delivery
Operations
The Power Delivery operations of Pepco
are regulated by the District of Columbia Public Service Commission (DCPSC) and
the Maryland Public Service Commission (MPSC).
The Power Delivery operations of DPL
are regulated by the Delaware Public Service Commission (DPSC) and the MPSC and,
until the sale of its Virginia operations on January 2, 2008, was regulated
by the Virginia State Corporation Commission (VSCC). DPL’s interstate
transportation and wholesale sale of natural gas are regulated by the Federal
Energy Regulatory Commission (FERC).
The Power Delivery operations of ACE
are regulated by the New Jersey Board of Public Utilities (NJBPU).
The transmission and wholesale sale of
electricity by each of Pepco, DPL, and ACE are regulated by FERC.
The requirements of SFAS No. 71 apply
to the Power Delivery businesses of Pepco, DPL, and ACE. SFAS No. 71 allows
regulated entities, in appropriate circumstances, to establish regulatory assets
and liabilities and to defer the income statement impact of certain costs that
are expected to be recovered in future rates. 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 must be eliminated through a charge to
earnings.
As part of the new electric service
distribution base rates for Pepco and DPL approved by the MPSC, effective June
16, 2007, the MPSC approved for both companies a bill stabilization adjustment
mechanism (BSA) for retail customers. See Note 12 “Commitments and
Contingencies – Regulatory and Other Matters – Rate Proceedings.” For
customers to which the BSA applies, Pepco and DPL recognize distribution revenue
based on an approved distribution charge per customer. From a revenue
recognition standpoint, the BSA thus decouples the distribution revenue
recognized in a reporting period from the amount of power delivered during the
period. Pursuant to this mechanism, Pepco and DPL recognize either
(a) a positive adjustment equal to the amount by which revenue from Maryland
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 (b) 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 positive Revenue Decoupling Adjustment is recorded as
a regulatory asset and a negative Revenue Decoupling Adjustment is recorded as a
regulatory liability. The net Revenue Decoupling Adjustment at
December 31, 2007 is a regulatory asset and is included in the “Other” line item
on the table of regulatory asset balances listed below.
The components of Pepco Holdings’
regulatory asset balances at December 31, 2007 and 2006 are as
follows:
|
|
|
2007
|
|
|
2006
|
|
|
|
|
(Millions
of dollars)
|
|
|
Securitized
stranded costs
|
|
$ |
734.6 |
|
|
$ |
773.0 |
|
|
Recoverable
pension and OPEB costs
|
|
|
334.0 |
|
|
|
365.4 |
|
|
Deferred
energy supply costs
|
|
|
1.7 |
|
|
|
6.9 |
|
|
Deferred
recoverable income taxes
|
|
|
155.6 |
|
|
|
130.5 |
|
|
Deferred
debt extinguishment costs
|
|
|
71.5 |
|
|
|
76.9 |
|
|
Unrecovered
purchased power contract costs
|
|
|
10.0 |
|
|
|
13.5 |
|
|
Deferred
other postretirement benefit costs
|
|
|
12.5 |
|
|
|
15.0 |
|
|
Phase
in credits
|
|
|
38.9 |
|
|
|
31.0 |
|
|
Asset
retirement cost
|
|
|
- |
|
|
|
33.0 |
|
|
Other
|
|
|
156.9 |
|
|
|
125.6 |
|
|
Total
Regulatory Assets
|
|
$ |
1,515.7 |
|
|
$ |
1,570.8 |
|
|
|
|
|
|
|
|
|
|
|
The components of Pepco Holdings’
regulatory liability balances at December 31, 2007 and 2006 are as
follows:
|
|
|
2007
|
|
|
2006
|
|
|
|
|
(Millions
of dollars)
|
|
|
Deferred
income taxes due to customers
|
|
$ |
60.5 |
|
|
$ |
69.3 |
|
|
Deferred
energy supply costs
|
|
|
240.9 |
|
|
|
164.9 |
|
|
Federal
and New Jersey tax benefits,
related
to securitized stranded costs
|
|
|
31.5 |
|
|
|
34.6 |
|
|
Asset
removal costs
|
|
|
331.8 |
|
|
|
322.2 |
|
|
Excess
depreciation reserve
|
|
|
90.0 |
|
|
|
105.8 |
|
|
Asset
retirement obligation
|
|
|
- |
|
|
|
63.2 |
|
|
Gain
from sale of B.L. England
|
|
|
36.1 |
|
|
|
- |
|
|
Settlement
proceeds - Mirant bankruptcy claims
|
|
|
414.6 |
|
|
|
- |
|
|
Gain
from sale of Keystone and Conemaugh
|
|
|
30.7 |
|
|
|
48.4 |
|
|
Other
|
|
|
12.8 |
|
|
|
34.3 |
|
|
Total
Regulatory Liabilities
|
|
$ |
1,248.9 |
|
|
$ |
842.7 |
|
|
|
|
|
|
|
|
|
|
|
A description for each category of
regulatory assets and regulatory liabilities follows:
Securitized Stranded
Costs: Represents stranded costs associated with contract
termination payments associated with a contract between ACE and an unaffiliated
non-utility generator (NUG) and the discontinuation of the application of SFAS
No. 71 for ACE’s electricity generation business. The recovery of
these stranded costs has been securitized through the issuance by Atlantic City
Electric Transition Funding LLC (ACE Funding) of transition bonds (Transition
Bonds). A customer surcharge is collected by ACE to fund principal
and interest payments on the Transition Bonds. The stranded costs are
amortized over the life of the Transition Bonds, which mature between 2010 and
2023.
Recoverable Pension and OPEB
Costs: Represents the funded portion of Pepco Holdings’
defined benefit pension and other postretirement benefit plans that is probable
of recovery in rates under SFAS No. 71 by Pepco, DPL and ACE.
Deferred Energy Supply
Costs: The regulatory liability balances of $240.9 million and
$164.9 million for the years ended December 31, 2007 and 2006,
respectively, primarily represent deferred costs related to a net over-recovery
by ACE connected with the provision of BGS and other restructuring related costs
incurred by ACE. The regulatory asset balances of $1.7 million and
$6.9 million for the years ended December 31, 2007 and 2006, respectively,
represent deferred fuel costs for DPL’s gas business, which are recovered
annually.
Deferred Recoverable Income
Taxes: Represents a receivable
from Power Delivery’s customers for tax benefits applicable to utility
operations of Pepco, DPL, and ACE previously flowed through before the companies
were ordered to provide deferred income taxes. As the temporary
differences between the financial statement and tax basis of assets reverse, the
deferred recoverable balances are reversed. There is no return on
these deferrals.
Deferred Debt Extinguishment
Costs: Represents the costs of
debt extinguishment of Pepco, DPL and ACE for which recovery through regulated
utility rates is considered probable
and will
be amortized to interest expense during the authorized rate recovery
period. A return is received on these deferrals.
Unrecovered Purchased Power Contract
Costs: Represents deferred costs related to purchase power
contracts entered into by ACE and DPL. The ACE amortization period
began in July 1994 and will end in May 2014 and earns a return. The
DPL amortization period ended in October 2007 and earned a return.
Deferred Other Postretirement
Benefit Costs: Represents the non-cash
portion of other postretirement benefit costs deferred by ACE during 1993
through 1997. This cost is being recovered over a 15-year period that
began on January 1, 1998. There is no return on this
deferral.
Phase In
Credits: Represents phase-in credits for participating
Maryland and Delaware residential and small commercial customers to mitigate the
immediate impact of significant rate increases due to energy costs in
2006. The deferral period for Delaware was May 1, 2006 to
January 1, 2008 with recovery to occur over a 17-month period beginning
January 2008. The Delaware deferral will be recovered from
participating customers on a straight-line basis. The deferral period
for Maryland was June 1, 2006 to June 1, 2007, with the recovery to
occur over an 18-month period beginning June 2007. The Maryland
deferral will be recovered from participating customers at a rate per
kilowatt-hour based on energy usage during the recovery period.
Other: Represents
miscellaneous regulatory assets that generally are being amortized over 1 to 20
years and generally do not receive a return.
Deferred Income Taxes Due to
Customers:
Represents the portion of deferred income tax liabilities applicable to utility
operations of Pepco, DPL, and ACE that has not been reflected in current
customer rates for which future payment to customers is probable. As
temporary differences between the financial statement and tax basis of assets
reverse, deferred recoverable income taxes are amortized.
Federal and New Jersey Tax Benefits,
Related to Securitized Stranded Costs: Securitized stranded
costs include a portion of stranded costs attributable to the future tax benefit
expected to be realized when the higher tax basis of generating plants 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 regulated electricity delivery 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 issues its final regulations with respect to
normalization of these federal excess deferred taxes.
Asset Removal Costs: Represents Pepco’s
and DPL’s asset retirement obligations associated with removal costs accrued
using public service commission approved depreciation techniques for
transmission, distribution, and general utility property.
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 depreciable lives and a change in depreciation technique
from remaining life to whole life. The excess is being amortized over
an 8.25 year period, which began in June 2005.
Asset Retirement
Obligation: During the first quarter of 2006, ACE recorded an
asset retirement obligation of $60 million for B.L. England plant demolition and
environmental remediation costs; the obligation was to be amortized over a
two-year period. The cumulative amortization of $33.0 million at
December 31, 2006, was recorded as a regulatory asset -- “Asset Retirement
Cost.” As discussed in Note (12) “Commitments and Contingencies --
ACE Sale of Generating Assets,” in the first quarter of 2007, ACE completed the
sale of the B.L. England generating facility and the asset retirement obligation
and asset retirement cost were reversed.
Gain from Sale of B.L.
England: In the first quarter of 2007, ACE completed the sale
of the B.L. England generating facility. Net proceeds from the sale
of the plant and monetization of the emission allowance credits will be credited
to ACE’s ratepayers in accordance with the requirements of the New Jersey
Electric Discount and Energy Competition Act (EDECA) and NJBPU
orders.
Settlement Proceeds - Mirant
Bankruptcy Claims: Represents the $413.9 million of net
proceeds received by Pepco from settlement of a Mirant Corporation (Mirant)
claim, plus interest earned, which will be used to pay for future above-market
capacity and energy purchases under a power purchase agreement entered into with
Panda-Brandywine L.P. (Panda) over the remaining life of the agreement, which
extends through 2021 (the Panda PPA).
Gain from Sale of Keystone and
Conemaugh: In the third quarter of
2006, ACE completed the sale of its interests in the Keystone and Conemaugh
generating facilities for $175.4 million (after giving effect to post-closing
adjustments). The total gain recognized on this sale, net of
adjustments, came to $131.4 million. Approximately $81.3 million
of the net gain from the sale offset the remaining regulatory asset balance,
which ACE has been recovering in rates, and $49.8 million of the net gain
is being returned to ratepayers over a 33-month period as a credit on their
bills, which began during the October 2006 billing period. The
balance to be repaid to customers is $30.7 million as of December 31,
2007.
Other: Includes
miscellaneous regulatory liabilities such as the over-recovery of procurement,
transmission and administrative costs associated with Maryland, Delaware and
District of Columbia SOS.
Accounting for
Derivatives
Pepco Holdings 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 SFAS No. 133, “Accounting for Derivative
Instruments and Hedging Activities,” as amended. SFAS No. 133
requires derivative instruments to be measured at fair value. Derivatives are
recorded on the Consolidated Balance Sheets as other assets or other liabilities
unless designated as “normal purchases and sales.”
Mark-to-market gains and losses on
derivatives that are not designated as hedges are presented on the Consolidated
Statements of Earnings as operating revenue. PHI uses
mark-to-
market
accounting through earnings for derivatives that either do not qualify for hedge
accounting or that management does not designate as hedges.
The gain or loss on a derivative that
hedges exposure to variable cash flow of a forecasted transaction is initially
recorded in Other Comprehensive Income (a separate component of common
stockholders’ equity) 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 a forecasted transaction is no longer
probable, the deferred gain or loss in accumulated other comprehensive income is
immediately reclassified to earnings. Gains or losses related to any
ineffective portion of cash flow hedges are also recognized in earnings
immediately.
Changes in the fair value of
derivatives designated as fair value hedges result in a change in the value of
the asset, liability, or firm commitment being hedged. Changes in
fair value of the asset, liability, or firm commitment, and the hedging
instrument, are recorded in the Consolidated Statements of
Earnings.
Certain commodity forwards are not
required to be recorded on a mark-to-market basis of accounting under SFAS No.
133. These contracts are designated as “normal purchases and sales”
as permitted by SFAS No. 133. This type of contract is used in normal
operations, settles physically, and follows standard accrual
accounting. Unrealized gains and losses on these contracts do not
appear on the Consolidated Balance Sheets. Examples of these
transactions include purchases of fuel to be consumed in power plants and actual
receipts and deliveries of electric power. Normal purchases and sales
transactions are presented on a gross basis, normal sales as operating revenue,
and normal purchases as fuel and purchased energy expenses.
PHI uses option contracts to mitigate
certain risks. These options are normally marked-to-market through
current earnings because of the difficulty in qualifying options for hedge
accounting treatment. Market prices, when available, are used to
value options. If market prices are not available, the market value
of the options is estimated using Black-Scholes closed form
models. Option contracts typically make up only a small portion of
PHI’s total derivatives portfolio.
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 are used to interpolate broker quality price
information. Models are also used to estimate volumes for certain
transactions. The same valuation methods are used to determine the
value of non-derivative commodity exposure for risk management
purposes.
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
Earnings. When a hedging gain or loss is realized, it is presented on
a net basis in the same category as the underlying item being
hedged. Normal purchase and sale transactions are presented gross on
the Consolidated Statements of Earnings as they are realized. The
unrealized assets and liabilities that offset unrealized derivative gains and
losses are presented gross on the Consolidated Balance Sheets except where
contractual netting agreements are in place.
Emission
Allowances
Emission allowances for sulfur dioxide
and nitrous oxide are allocated to generation owners by the U.S. Environmental
Protection Agency (EPA) based on federal programs designed to regulate the
emissions from power plants. EPA allotments have no cost basis to the
generation owners. Depending on the run-time of a generating unit in
a given year, and other pollution controls it may have, the unit may need
additional allowances above its allocation or it may have excess
allowances. Allowances are traded among companies in an
over-the-counter market, which allows companies to purchase additional
allowances to avoid incurring penalties for noncompliance with applicable
emissions standards or to sell excess allowances.
Pepco Holdings accounts for emission
allowances as inventory in the balance sheet line item “Fuel, materials and
supplies - at average cost.” Allowances from EPA allocations are
added to current inventory each year at a zero basis. Additional
purchased allowances are recorded at cost. Allowances sold or
consumed at the power plants are expensed at a weighted-average
cost. This cost tends to be relatively low due to the inclusion of
the zero-basis allowances. At December 31, 2007 and 2006, the
book value of emission allowances was $8.4 million and $11.7 million,
respectively. Pepco Holdings has established a committee to monitor
compliance with emissions regulations and ensure its power plants have the
required number of allowances.
Goodwill and Goodwill
Impairment
Goodwill represents the excess of the
purchase price of an acquisition over the fair value of the net assets
acquired. Substantially all of Pepco Holdings’ goodwill was generated
by Pepco’s August 2002 acquisition of Conectiv and was recorded at the PHI
level. Pepco Holdings tests its goodwill for impairment annually as
of July 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 its carrying amount. The July 1, 2007 test indicated that
none of Pepco Holdings’ goodwill balance was impaired.
A roll forward of PHI’s goodwill
balance follows (millions of dollars):
|
|
$
|
1,431.3
|
|
Add: Changes
in estimates related to pre-merger tax liabilities
|
|
.6
|
|
Less: Adjustment
due to resolution of pre-merger tax contingencies
|
|
(9.1)
|
|
Pepco
Energy impairment related to completed dispositions
|
|
(13.6)
|
|
|
|
1,409.2
|
|
Less: Adjustment
due to resolution of pre-merger tax contingencies
and
correction of pre-merger deferred tax balances
|
|
.4
|
|
|
$
|
1,409.6
|
|
|
|
|
Long-Lived Assets
Impairment
Pepco Holdings evaluates certain
long-lived assets to be held and used (for example, generating property and
equipment and real estate) to determine if they are impaired whenever events or
changes in circumstances indicate that their carrying amount 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 sum of its expected future undiscounted cash flows is less
than its carrying amount.
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 amount exceeds their fair value
including costs to sell.
During 2007, Pepco Holdings recorded
pre-tax impairment losses of $2.0 million ($1.3 million after-tax) related to
certain energy services business assets owned by Pepco Energy
Services. During 2006, Pepco Holdings recorded pre-tax impairment
losses of $18.9 million ($13.7 million after-tax) related to certain energy
services business assets owned by Pepco Energy Services. The
impairments were recorded as a result of the execution of contracts to sell
certain assets, and due to the lower than expected production and related
estimated cash flows from other assets. The fair value of the assets
under contracts for sale was determined based on the sales contract price; while
the fair value of the other assets was determined by estimating future expected
production and cash flows.
Cash and cash equivalents include cash
on hand, money market funds, and commercial paper with original maturities of
three months or less.
Restricted Cash and Cash
Equivalents
The restricted cash included in Current
Assets and the restricted cash and cash equivalents included in Investments and
Other Assets represent (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 solely to fund the future above-market capacity and energy purchase
costs under the Panda PPA. The classification as current or
non-current conforms to the classification of the related
liabilities.
Prepaid Expenses and
Other
The prepaid expenses and other balance
primarily consists of prepayments and the current portion of deferred income tax
assets.
Accounts Receivable and
Allowance for Uncollectible Accounts
Pepco Holdings’ subsidiaries’ accounts
receivable balances primarily consist 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). PHI uses the allowance method to account for uncollectible
accounts receivable.
Capitalized Interest and
Allowance for Funds Used During Construction
In accordance with the provisions of
SFAS No. 71, PHI’s utility subsidiaries can capitalize as Allowance for Funds
Used During Construction (AFUDC) the capital costs of financing the construction
of plant and equipment. The debt portion of AFUDC is recorded as
a
reduction
of “interest expense” and the equity portion of AFUDC is credited to “other
income” in the accompanying Consolidated Statements of Earnings.
Pepco Holdings recorded AFUDC for
borrowed funds of $7.0 million, $2.8 million, and $3.3 million for the years
ended December 31, 2007, 2006 and 2005, respectively.
Pepco Holdings recorded amounts for the
equity component of AFUDC of $4.4 million, $3.8 million and $4.7 million for the
years ended December 31, 2007, 2006, and 2005, respectively.
Leasing
Activities
Income from investments in direct
financing leases and leveraged lease transactions, in which PCI 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. For
direct financing leases, unearned income is amortized to income over the lease
term at a constant rate of return on the net investment. Income, including
investment tax credits, on leveraged equipment leases is recognized over the
life of the lease at a constant rate of return on the positive net investment.
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. Each quarter, PHI reviews the
carrying value of each lease, which includes a review of the underlying lease
financial assumptions, the timing and collectibility of cash flows, and the
credit quality (including, if available, credit ratings) of the
lessee. Changes to the underlying assumptions, if any, would be
accounted for in accordance with SFAS No. 13 and reflected in the carrying value
of the lease effective for the quarter within which they occur.
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 issues. Costs associated with the redemption of
debt for PHI’s subsidiaries are also deferred and amortized over the lives of
the new issues.
Pension and Other
Postretirement Benefit Plans
Pepco Holdings sponsors a
non-contributory defined benefit retirement plan that covers substantially all
employees of Pepco, DPL, ACE and certain employees of other Pepco Holdings
subsidiaries (the PHI Retirement Plan). 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 and nonqualified retirement plans in accordance with
SFAS No. 87, “Employers’ Accounting for Pensions,” as amended by SFAS
No. 158, “Employers’ Accounting for Defined Benefit Pension and Other
Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132
(R)” (SFAS No. 158) and its postretirement health care and life insurance
benefits for eligible employees in accordance with SFAS No. 106,
“Employers’ Accounting for Postretirement Benefits Other Than Pensions,” as
amended by SFAS No. 158. PHI’s financial statement disclosures are
prepared in accordance
with
SFAS No. 132, “Employers’ Disclosures about Pensions and Other
Postretirement Benefits,” as amended by SFAS No. 158.
See Note (6), Pensions and Other
Postretirement Benefits, for additional information.
Severance
Costs
In 2004, the Power Delivery business
reduced its work force through a combination of retirements and targeted
reductions. This reduction plan met the criteria for the accounting
treatment provided under SFAS No. 88, “Employer’s Accounting for Settlements and
Curtailments of Defined Benefit Pension Plans and for Termination Benefits,” and
SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal
Activities,” as applicable. A roll forward of PHI’s severance accrual
balance is as follows (millions of dollars):
|
|
$
|
2.5
|
|
|
Accrued
during 2006
|
|
7.3
|
|
|
Payments
during 2006
|
|
(5.2)
|
|
|
|
|
4.6
|
|
|
Accrued
during 2007
|
|
1.9
|
|
|
Payments
during 2007
|
|
(6.4)
|
|
|
|
$
|
.1
|
|
|
|
|
|
|
Based on the employees that accepted
the severance packages, substantially all of the severance liability was paid by
December 31, 2007. Employees had the option of taking severance
payments in a lump sum or over a period of time.
Property, Plant and
Equipment
Property, plant and equipment are
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 under the provisions of SFAS No.
144. 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. Property, plant and equipment other than electric and gas
facilities is generally depreciated on a straight-line basis over the useful
lives of the assets. The table below provides system-wide composite
depreciation rates for the years ended December 31, 2007, 2006, and
2005.
|
|
Transmission
&
Distribution
|
|
Generation
|
|
|
2007
|
|
2006
|
|
2005
|
|
2007
|
|
2006
|
|
2005
|
|
Pepco
|
3.0%
|
|
3.5%
|
|
3.4%
|
|
-
|
|
-
|
|
-
|
|
DPL
|
2.9%
|
|
3.0%
|
|
3.1%
|
|
-
|
|
-
|
|
-
|
|
ACE
|
2.9%
|
|
2.9%
|
|
3.1%
|
|
-
|
|
.3%
|
(a)
|
2.4%
|
|
Conectiv
Energy
|
-
|
|
-
|
|
-
|
|
2.0%
|
|
2.0%
|
|
2.2%
|
|
Pepco
Energy Services
|
-
|
|
-
|
|
-
|
|
10.1%
|
|
9.6%
|
|
8.4%
|
|
|
(a)
|
Rate
reflects the Consolidated Balance Sheet classification of ACE’s generation
assets as “assets held for sale” in 2006 and therefore no depreciation
expense was recorded.
|
In accordance with FASB Staff Position
(FSP) American Institute of Certified Public Accountants Industry Audit Guide,
Audits of Airlines--”Accounting for Planned Major Maintenance Activities” (FSP
AUG AIR-1), costs associated with planned major maintenance activities related
to generation facilities are expensed as incurred.
Asset Retirement
Obligations
In accordance with SFAS No. 143,
“Accounting for Asset Retirement Obligations” and FIN 47, asset removal costs
are recorded as regulatory liabilities. At December 31, 2007, $331.8
million of accrued asset removal costs ($234.2 million for DPL and $97.6 million
for Pepco) and at December 31, 2006, $322.2 million of accrued asset removal
costs ($229.5 million for DPL and $92.7 million for Pepco) are reflected as
regulatory liabilities in the accompanying Consolidated Balance
Sheets. Public service commission-approved depreciation rates for ACE
do not contain components for the recovery of removal cost; therefore, the
recording of asset retirement obligations for ACE associated with accruals for
removal cost is not required. Additionally, in 2005 Pepco Holdings
recorded conditional asset retirement obligations of approximately $1.5
million. Accretion for 2007 and 2006, which relates to the regulated
Power Delivery segment, has been recorded as a regulatory asset.
Stock-Based
Compensation
Pepco Holdings adopted and implemented
SFAS No. 123R, on January 1, 2006, using the modified prospective
method. Under this method, Pepco Holdings recognizes compensation
expense for share-based awards, modifications or cancellations after the
effective date, based on the grant-date fair value. Compensation
expense is recognized over the requisite service period. In addition,
compensation cost recognized includes the cost for all share-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/release from restriction,
respectively. In applying the modified prospective transition method,
Pepco Holdings has not restated prior interim and annual financial results and
therefore these prior periods do not reflect the revised recognition of
share-based compensation cost as required by SFAS No. 123R.
In November 2005, the FASB issued FSP
123(R)-3, “Transition Election Related to Accounting for the Tax Effects of
Share-Based Payment Awards” (FSP 123R-3). FSP 123R-3 provides an
elective alternative transition method that includes a computation that
establishes the beginning balance of the additional paid-in capital (APIC pool)
related to the tax effects of employee and director stock-based compensation,
and a simplified method to determine the subsequent impact on the APIC pool of
employee and director stock-based awards that are
outstanding
upon adoption of SFAS No. 123R. Entities may make a one-time election
to apply the transition method discussed in FSP 123R-3. That one-time
election may be made within one year of an entity’s adoption of SFAS No. 123R,
or the FSP’s effective date (November 11, 2005), whichever is
later. Pepco Holdings adopted the alternative transition method at
December 31, 2006.
Prior to the adoption of SFAS No. 123R,
Pepco Holdings accounted for its share-based employee compensation under the
intrinsic value method of expense recognition and measurement prescribed by
Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued
to Employees, and related Interpretations” (APB No. 25). Under this
method, compensation expense was recognized for restricted stock awards but not
for stock options granted since the exercise price was equal to the grant-date
market price of the stock.
The issuance of SFAS No. 123,
“Accounting for Stock-Based Compensation,” in 1995 as amended by SFAS No. 148,
“Accounting for Stock-Based Compensation-Transition and Disclosure,” permitted
continued application of APB No. 25, but required tabular presentation of
pro-forma stock-based employee compensation cost, net income, and basic and
diluted earnings per share as if the fair-value based method of expense
recognition and measurement prescribed by SFAS No. 123 had been applied to all
options. This information for the year ended December 31, 2005
is as follows:
|
|
|
For
the Year Ended
|
|
|
|
|
(Millions
of dollars,
except per share data)
|
|
|
|
|
|
|
|
Net
Income
|
|
$
|
371.2 |
|
|
Add: Total
stock-based employee compensation expense
included
in net income as reported (net of related tax effect
of
$1.8 million)
|
|
|
2.6 |
|
|
Deduct:
Total stock-based employee compensation expense
determined
under fair value based methods for all awards (net
of
related tax effect of $2.0 million)
|
|
|
(2.8 |
) |
|
Pro
forma net income
|
|
$
|
371.0 |
|
|
|
|
|
|
|
|
Basic
earnings per share as reported
|
|
$
|
1.96 |
|
|
Pro
forma basic earnings per share
|
|
|
1.96 |
|
|
Diluted
earnings per share as reported
|
|
|
1.96 |
|
|
Pro
forma diluted earnings per share
|
|
|
1.96 |
|
|
|
|
|
|
|
Pepco Holdings estimates the fair value
of each stock option award on the date of grant using the Black-Scholes-Merton
option pricing model. This model uses assumptions related to expected
option term, expected volatility, expected dividend yield and risk-free interest
rate. Pepco Holdings uses historical data to estimate option exercise
and employee termination within the valuation model; separate groups of
employees that have similar historical exercise behavior are considered
separately for valuation purposes. The expected term of options
granted is derived from the output of the option valuation model and represents
the period of time that options granted are expected to be
outstanding.
No stock options were granted in 2005,
2006 or 2007.
No modifications were made to
outstanding stock options prior to the adoption of SFAS No. 123R, and no changes
in valuation methodology or assumptions in estimating the fair value of stock
options have occurred with its adoption.
There were no cumulative adjustments
recorded in the financial statements as a result of this new pronouncement; the
percentage of forfeitures of outstanding stock options issued prior to SFAS No.
123R’s adoption is estimated to be zero.
As of January 1, 2007, there are
no outstanding options that were not fully vested. Consequently, no
compensation cost related to the vesting of options was recorded in
2007.
Cash received from stock options
exercised under all share-based payment arrangements for the years ended
December 31, 2007, 2006 and 2005, was $13.4 million, $15.9 million, and $3.7
million, respectively. The actual tax benefit realized from these
option exercises totaled $1.2 million, $.9 million, and $.3 million,
respectively, for the years ended December 31, 2007, 2006 and 2005.
Pepco Holdings’ current policy is to
issue new shares to satisfy stock option exercises and the vesting of restricted
stock awards.
Accumulated Other
Comprehensive (Loss) Earnings
A detail of the components of Pepco
Holdings’ Accumulated Other Comprehensive (Loss) Earnings is as
follows. For additional information, see the Consolidated Statements
of Comprehensive Earnings.
|
|
Commodity
Derivatives
|
Treasury
Lock
|
Interest
Rate
Swaps
|
Other
|
Accumulated
Other Comprehensive (Loss) Earnings
|
|
|
|
(Millions
of dollars)
|
|
|
|
$ (.5)
|
$(47.1)
|
$ (.3)
|
$(4.1)
|
|
$ (52.0)
|
|
|
Current
year change
|
25.1
|
7.0
|
.3
|
(3.2)
|
(a)
|
29.2
|
|
|
|
24.6
|
(40.1)
|
-
|
(7.3)
|
|
(22.8)
|
|
|
Current
year change
|
(86.5)
|
7.0
|
-
|
(.7)
|
(a)
|
(80.2)
|
|
|
Impact
of initially applying
SFAS
No. 158, net of tax
|
-
|
-
|
-
|
(.4)
|
|
(.4)
|
|
|
|
(61.9)
|
(33.1)
|
-
|
(8.4)
|
|
(103.4)
|
|
|
Current
year change
|
52.7
|
4.3
|
-
|
.9
|
(b)
|
57.9
|
|
|
|
$ (9.2)
|
$(28.8)
|
$ -
|
$(7.5)
|
|
$ (45.5)
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
Represents
an adjustment for nonqualified pension plan minimum liability and the
impact of initially applying SFAS No.
158.
|
|
(b)
|
Represents
amortization of gains and losses for prior service
costs.
|
A detail of the income tax (benefit)
expense allocated to the components of Pepco Holdings’ Other Comprehensive
(Loss) Earnings for each year is as follows.
|
|
Commodity
Derivatives
|
Treasury
Lock
|
Interest
Rate
Swaps
|
Other
|
Accumulated
Other Comprehensive (Loss) Earnings
|
|
|
|
(Millions
of dollars)
|
|
|
|
$ 15.9
|
$ 4.7
|
$ .1
|
$(2.0)(a)
|
$ 18.7
|
|
|
|
$(55.0)
|
$ 4.7
|
$ -
|
$ (.5)(a)
|
$(50.8)
|
|
|
|
$ 31.3
|
$ 5.1
|
$ -
|
$ .7 (b)
|
$ 37.1
|
|
|
(a)
|
Represents
the income tax benefit on an adjustment for nonqualified pension plan
minimum liability.
|
|
(b)
|
Represents
income tax expense on amortization of gains and losses for prior service
costs.
|
Financial Investment
Liquidation
In October 2005, PCI received $13.3
million in cash related to the liquidation of a preferred stock investment that
was written-off in 2001 and recorded an after-tax gain of $8.9
million.
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 as part of Pepco’s acquisition of
Conectiv on August 1, 2002. 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.
In 2006, the FASB issued FIN 48,
“Accounting for Uncertainty in Income Taxes” (FIN 48). FIN 48
clarifies the criteria for recognition of tax benefits in accordance with SFAS
No. 109, “Accounting for Income Taxes,” and prescribes a financial statement
recognition threshold and measurement attribute for a tax position taken or
expected to be taken in a tax return. Specifically, it clarifies that
an entity’s tax benefits must be “more likely than not” of being sustained prior
to recording the related tax benefit in the financial statements. If
the position drops below the “more likely than not” standard, the benefit can no
longer be recognized. FIN 48 also provides guidance on derecognition,
classification, interest and penalties, accounting in interim periods,
disclosure, and transition.
On May 2, 2007, the FASB issued FSP FIN
48-1, “Definition of Settlement in FASB Interpretation No. 48” (FIN 48-1), which
provides guidance on how an enterprise should determine whether a tax position
is effectively settled for the purpose of recognizing previously unrecognized
tax benefits. PHI applied the guidance of FIN 48-1 with its adoption
of FIN 48 on January 1, 2007.
The consolidated financial statements
include current and deferred income taxes. Current income taxes
represent the amounts 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 and tax basis of existing assets and liabilities and are
measured using presently enacted tax rates. The portion of Pepco’s,
DPL’s, and 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. For additional information, see the
preceding discussion under “Regulation of Power Delivery
Operations.”
Deferred income tax expense generally
represents the net change during the reporting period in the net deferred tax
liability and deferred recoverable income taxes.
PHI recognizes interest on under/over
payments of income taxes, interest on unrecognized tax benefits, and tax-related
penalties in income tax expense.
Investment tax credits from utility
plants purchased in prior years are reported on the Consolidated Balance Sheets
as “Investment tax credits.” These investment tax credits are being
amortized to income over the useful lives of the related utility
plant.
FIN 46R, “Consolidation of
Variable Interest Entities”
Subsidiaries of Pepco Holdings have
power purchase agreements (PPAs) with a number of entities, including three NUGs
and ACE and the Panda PPA. Due to a variable element in the pricing
structure of the NUGs and the Panda PPA, Pepco and ACE, respectively,
potentially assume the variability in the operations of the plants related to
these PPAs and therefore have a variable interest in the counterparties to these
PPAs. In accordance with the provisions of FIN 46R, Pepco Holdings
continued, during 2007, to conduct exhaustive efforts to obtain information from
these four entities, but was unable to obtain sufficient information to conduct
the analysis required under FIN 46R to determine whether these four entities
were variable interest entities or if the Pepco Holdings subsidiaries were the
primary beneficiary. As a result, Pepco Holdings has applied the
scope exemption from the application of FIN 46R for enterprises that have
conducted exhaustive efforts to obtain the necessary information, but have not
been able to obtain such information.
Net purchase activities with the
counterparties to the NUGs and the Panda PPA for the years ended December 31,
2007, 2006, and 2005, were approximately $412 million, $403 million, and $419
million, respectively, of which approximately $378 million, $367 million, and
$381 million, respectively, related to power purchases under the NUGs and the
Panda PPA. Pepco Holdings does not have loss exposure under the NUGs
because cost recovery will be achieved from ACE’s customers through regulated
rates. In addition, there is no loss exposure on the Panda PPA as
recovery will be achieved through the PJM Interconnection LLC (PJM) and funds
received from the Mirant bankruptcy settlement.
Sale of Interest in
Cogeneration Joint Venture
During the first quarter of 2006,
Conectiv Energy recognized a $12.3 million pre-tax gain ($7.9 million after-tax)
on the sale of its equity interest in a joint venture which owns a wood burning
cogeneration facility.
Other Non-Current
Assets
The other assets balance principally
consists of real estate under development, equity and other investments,
unrealized derivative assets, and deferred compensation trust
assets.
Other Current
Liabilities
The other current liability balance
principally consists of customer deposits, accrued vacation liability, current
unrealized derivative liabilities, and other miscellaneous
liabilities. For 2006, this balance included $70 million paid to
Pepco by Mirant in settlement of claims resulting from the Mirant
bankruptcy.
Other Deferred
Credits
The other deferred credits balance
principally consists of non-current unrealized derivative liabilities and
miscellaneous deferred liabilities.
Preferred
Stock
As of December 31, 2007 and 2006, PHI
had 40 million shares of preferred stock authorized for issuance, with a par
value of $.01 per share. No shares of preferred stock were
outstanding at December 31, 2007 and 2006.
Reclassifications
Certain prior year amounts have been
reclassified in order to conform to current year presentation.
Newly
Adopted Accounting Standards
FSP FTB 85-4-1, “Accounting for Life
Settlement Contracts by Third-Party Investors”
In March 2006, the FASB issued FSP FASB
Technical Bulletin (FTB) 85-4-1, “Accounting for Life Settlement Contracts by
Third-Party Investors” (FSP FTB 85-4-1). This FSP provides initial
and subsequent measurement guidance and financial statement presentation and
disclosure guidance for investments by third-party investors in life settlement
contracts. FSP FTB 85-4-1 also amends certain provisions of FTB
No. 85-4, “Accounting for Purchases of Life Insurance,” and SFAS No. 133,
“Accounting for Derivative Instruments and Hedging Activities.” The
guidance in FSP FTB 85-4-1 applies prospectively for all new life settlement
contracts and is effective for fiscal years beginning after June 15, 2006 (year
ended December 31, 2007 for Pepco Holdings). Implementation of
FSP FTB 85-4-1 did not have a material impact on Pepco Holdings’ overall
financial condition, results of operations, or cash flows.
SFAS No. 155, “Accounting for Certain
Hybrid Financial Instruments - an amendment of FASB Statements No. 133 and
140”
In February 2006, the FASB issued SFAS
No. 155, “Accounting for Certain Hybrid Financial Instruments - an amendment of
FASB Statements No. 133 and 140” (SFAS No. 155). SFAS No. 155 amends
SFAS No. 133, “Accounting for Derivative Instruments and Hedging
Activities,”
and SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets
and Extinguishments of Liabilities.” SFAS No. 155 resolves issues
addressed in SFAS No. 133 Implementation Issue No. D1, “Application of Statement
133 to Beneficial Interests in Securitized Financial Assets.” SFAS
No. 155 is effective for all financial instruments acquired or issued after the
beginning of an entity’s first fiscal year that begins after September 15, 2006
(year ended December 31, 2007 for Pepco Holdings). Implementation of
SFAS No. 155 did not have a material impact on Pepco Holdings’ overall financial
condition, results of operations, or cash flows.
SFAS No. 156, “Accounting for Servicing
of Financial Assets, an amendment of FASB Statement No. 140”
In March 2006, the FASB issued SFAS No.
156, “Accounting for Servicing of Financial Assets” (SFAS No. 156), an amendment
of SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and
Extinguishments of Liabilities,” with respect to the accounting for separately
recognized servicing assets and servicing liabilities. SFAS No. 156
requires an entity to recognize a servicing asset or servicing liability upon
undertaking an obligation to service a financial asset via certain servicing
contracts, and for all separately recognized servicing assets and servicing
liabilities to be initially measured at fair value, if
practicable. Subsequent measurement is permitted using either the
amortization method or the fair value measurement method for each class of
separately recognized servicing assets and servicing liabilities.
SFAS No. 156 is effective as of the
beginning of an entity’s first fiscal year that begins after September 15, 2006
(year ended December 31, 2007 for Pepco Holdings). Application
is to be applied prospectively to all transactions following adoption of SFAS
No. 156. Implementation of SFAS No. 156 did not have a material
impact on Pepco Holdings’ overall financial condition, results of operations, or
cash flows.
EITF Issue No. 06-3, “Disclosure
Requirements for Taxes Assessed by a Governmental Authority on Revenue-producing
Transactions”
On
June 28, 2006, the FASB ratified Emerging Issues Task Force (EITF) Issue No.
06-3, “Disclosure Requirements for Taxes Assessed by a Governmental Authority on
Revenue-producing Transactions” (EITF 06-3). EITF 06-3 provides
guidance on an entity’s disclosure of its accounting policy regarding the gross
or net presentation of certain taxes and provides that if taxes included in
gross revenues are significant, a company should disclose the amount of such
taxes for each period for which an income statement is presented (i.e., both
interim and annual periods). Taxes within the scope of EITF 06-3 are those that
are imposed on and concurrent with a specific revenue-producing transaction.
Taxes assessed on an entity’s activities over a period of time are not within
the scope of EITF 06-3. Pepco Holdings implemented EITF 06-3 during
the first quarter of 2007. Taxes included in Pepco Holdings gross
revenues were $318.3 million, $259.9 million and $266.1 million for the years
ended December 31, 2007, 2006 and 2005, respectively.
FSP FAS 13-2, “Accounting for a Change
or Projected Change in the Timing of Cash Flows Relating to Income Taxes
Generated by a Leveraged Lease Transaction”
On July 13, 2006, the FASB
issued FSP Financial Accounting Standards (FAS) 13-2, “Accounting for a
Change or Projected Change in the Timing of Cash Flows Relating to Income Taxes
Generated by a Leveraged Lease Transaction” (FSP FAS 13-2). FSP FAS
13-2, which amends SFAS No. 13, “Accounting for Leases,” addresses how a change
or projected change in the timing of cash flows relating to income taxes
generated by a leveraged lease transaction affects the accounting by a lessor
for that lease.
FSP FAS 13-2 is effective for the first
fiscal year beginning after December 15, 2006 (year ended December 31, 2007
for Pepco Holdings). A material change in the timing of cash flows
under Pepco Holdings’ cross-border leases as the result of a settlement with the
Internal Revenue Service or a change in tax law would require an adjustment to
the book value of the leases and a charge to earnings equal to the repricing
impact of the disallowed deductions which could result in a material adverse
effect on Pepco Holdings’ overall financial condition, results of operations,
and cash flows. For a further discussion, see “Federal Tax Treatment
of Cross-Border Leases” in Note (12), “Commitments and
Contingencies.”
FSP AUG AIR-1, “Accounting for Planned
Major Maintenance Activities”
On September 8, 2006, the FASB issued
FSP AUG AIR-1, which prohibits the use of the accrue-in-advance method of
accounting for planned major maintenance activities in annual and interim
financial reporting periods for all industries. FSP AUG AIR-1 is
effective the first fiscal year beginning after December 15, 2006 (year
ended December 31, 2007 for Pepco Holdings). Implementation of
FSP AUG AIR-1 did not have a material impact on Pepco Holdings’ overall
financial condition, results of operations, or cash flows.
EITF Issue No. 06-5, “Accounting for
Purchases of Life Insurance -- Determining the Amount That Could Be Realized in
Accordance with FASB Technical Bulletin No. 85-4, Accounting for Purchases of
Life Insurance”
On September 20, 2006, the FASB
ratified EITF Issue No. 06-5, “Accounting for Purchases of Life Insurance --
Determining the Amount That Could Be Realized in Accordance with FASB Technical
Bulletin No. 85-4, Accounting for Purchases of Life Insurance” (EITF 06-5) which
provides guidance on whether an entity should consider the contractual ability
to surrender all of the individual-life policies (or certificates under a group
life policy) together when determining the amount that could be realized in
accordance with FTB 85-4, and whether a guarantee of the additional value
associated with the group life policy affects that
determination. EITF 06-5 provides that a policyholder should (i)
determine the amount that could be realized under the insurance contract
assuming the surrender of an individual-life by individual-life policy (or
certificate by certificate in a group policy) and (ii) not discount the cash
surrender value component of the amount that could be realized when contractual
restrictions on the ability to surrender a policy exist unless contractual
limitations prescribe that the cash surrender value component of the amount that
could be realized is a fixed amount, in which case the amount that could be
realized should be discounted in accordance with Accounting Principles Board of
the American Institute of Certified Public Accountants Opinion
21. EITF 06-5 is effective for fiscal years beginning after December
15, 2006 (year ended December 31, 2007 for Pepco Holdings).
Implementation
of EITF 06-5 did not have a material impact on Pepco Holdings’ overall financial
condition, results of operations, cash flows, or footnote disclosure
requirements.
FASB Staff Position No. EITF 00-19-2,
“Accounting for Registration Payment Arrangements”
On December 21, 2006, the FASB issued
FSP No. EITF 00-19-2, “Accounting for Registration Payment Arrangements” (FSP EITF 00-19-2),
which addresses an issuer’s accounting for registration payment arrangements and
specifies that the contingent obligation to make future payments or otherwise
transfer consideration under a registration payment arrangement, whether issued
as a separate agreement or included as a provision of a financial instrument or
other agreement, should be separately recognized and measured in accordance with
SFAS No. 5, “Accounting for Contingencies.” FSP EITF 00-19-2 is
effective immediately for registration payment arrangements and the financial
instruments subject to those arrangements that are entered into or modified
subsequent to the date of its issuance. For registration payment
arrangements and financial instruments subject to those arrangements that were
entered into prior to the issuance of FSP EITF 00-19-2, this guidance is
effective for financial statements issued for fiscal years beginning after
December 15, 2006, and interim periods within those fiscal years (year ended
December 31, 2007 for Pepco Holdings). Pepco Holdings
implemented FSP EITF 00-19-2 during the first quarter of 2007. The
implementation did not have a material impact on its overall financial
condition, results of operations, or cash flows.
Recently
Issued Accounting Standards, Not Yet Adopted
SFAS No. 157, "Fair Value
Measurements"
In September 2006, the FASB issued SFAS
No. 157, "Fair Value Measurements" (SFAS No. 157) which defines fair value,
establishes a framework for measuring fair value in GAAP, and expands
disclosures about fair value measurements. SFAS No. 157 applies under
other accounting pronouncements that require or permit fair value measurements
and does not require any new fair value measurements. However, it is
possible that the application of this Statement will change current practice
with respect to the definition of fair value, the methods used to measure fair
value, and the disclosures about fair value measurements.
The provisions of SFAS No. 157, as
issued, are effective for financial statements issued for fiscal years beginning
after November 15, 2007, and interim periods within those fiscal years (January
1, 2008 for Pepco Holdings). On February 6, 2008, the FASB decided to
issue final Staff Positions that will (i) defer the effective date of SFAS No.
157 for all non-financial assets and non-financial liabilities, except those
that are recognized or disclosed at fair value in the financial statements on a
recurring basis (that is, at least annually) and (ii) remove certain leasing
transactions from the scope of SFAS No. 157. The final Staff
Positions will defer the effective date of SFAS No. 157 to fiscal years
beginning after November 15, 2008, and interim periods within those fiscal years
for items within the scope of the final Staff Positions. Pepco
Holdings has evaluated the impact of SFAS No. 157 and does not anticipate its
adoption will have a material impact on its overall financial condition, results
of operations, cash flows, or footnote disclosure requirements.
SFAS No. 159, “The Fair Value Option for Financial
Assets and Financial Liabilities - Including an amendment of FASB Statement No.
115”
On February 15, 2007, the FASB issued
SFAS No. 159, “The Fair Value Option for Financial Assets and Financial
Liabilities - Including an amendment of FASB Statement No. 115” (SFAS No. 159)
which permits entities to elect to measure eligible financial instruments at
fair value. The objective of SFAS No. 159 is to improve financial
reporting by providing entities with the opportunity to mitigate volatility in
reported earnings caused by measuring related assets and liabilities differently
without having to apply complex hedge accounting provisions. SFAS No.
159 applies under other accounting pronouncements that require or permit fair
value measurements and does not require any new fair value
measurements. However, it is possible that the application of SFAS
No. 159 will change current practice with respect to the definition of fair
value, the methods used to measure fair value, and the disclosures about fair
value measurements.
SFAS No. 159 establishes presentation
and disclosure requirements designed to facilitate comparisons between companies
that choose different measurement attributes for similar types of assets and
liabilities. SFAS No. 159 requires companies to provide additional
information that will help investors and other users of financial statements to
more easily understand the effect of the company’s choice to use fair value on
its earnings. It also requires entities to display the fair value of
those assets and liabilities for which the company has chosen to use fair value
on the face of the balance sheet. SFAS No. 159 does not eliminate
disclosure requirements included in other accounting standards.
SFAS No. 159 applies to the beginning
of a reporting entity’s first fiscal year that begins after November 15, 2007
(January 1, 2008 for Pepco Holdings), with early adoption permitted for an
entity that has also elected to apply the provisions of SFAS No. 157, Fair Value
Measurements. An entity is
prohibited from retrospectively applying SFAS No. 159, unless it chooses early
adoption. SFAS No. 159 also applies to eligible items existing
at November 15, 2007 (or early adoption date). Pepco Holdings has
evaluated the impact of SFAS No. 159 and does not anticipate its adoption will
have a material impact on its overall financial condition, results of
operations, cash flows, or footnote disclosure requirements.
FSP FIN 39-1, “Amendment of FASB
Interpretation No. 39”
On April 30, 2007, the FASB issued FSP
FIN 39-1, “Amendment of FASB Interpretation No. 39” to amend certain portions of
Interpretation 39. The FSP replaces the terms “conditional contracts”
and “exchange contracts” in Interpretation 39 with the term “derivative
instruments” as defined in Statement 133. The FSP also amends
Interpretation 39 to allow for the offsetting of fair value amounts for the
right to reclaim cash collateral or receivable, or the obligation to return cash
collateral or payable, arising from the same master netting arrangement as the
derivative instruments. FSP FIN 39-1 applies to fiscal years beginning
after November 15, 2007 (year ending December 31, 2008 for Pepco Holdings), with
early adoption permitted. Pepco Holdings has evaluated the impact of
FSP FIN 39-1 and has determined that it does not have a material impact on its
overall financial condition, results of operations, cash flows, or footnote
disclosure requirements.
EITF Issue No. 06-11, “Accounting for
Income Tax Benefits of Dividends on Share-Based Payment Awards”
On June 27, 2007, the FASB ratified
EITF Issue No. 06-11, “Accounting for Income Tax Benefits of Dividends on
Share-Based Payment Awards” (EITF 06-11) which provides that a realized income
tax benefit from dividends or dividend equivalents that are charged to retained
earnings and paid to employees for equity classified nonvested equity shares,
nonvested equity share units, and outstanding equity share options should be
recognized as an increase to additional paid-in capital (APIC). The
amount recognized in APIC for the realized income tax benefit from dividends on
those awards should be included in the pool of excess tax benefits available to
absorb tax deficiencies on share-based payment awards (i.e. the “APIC
pool”).
EITF Issue No. 06-11 also provides
that, when the estimated amount of forfeitures increases or actual forfeitures
exceeds estimates, the amount of tax benefits previously recognized in APIC
should be reclassified into the income statement; however, the amount
reclassified is limited to the APIC pool balance on the reclassification
date.
EITF Issue No. 06-11 applies
prospectively to the income tax benefits of dividends on equity-classified
employee share-based payment awards that are declared in fiscal years beginning
after December 15, 2007, and interim periods within those fiscal years (year
ending December 31, 2008 for Pepco Holdings). Early application is
permitted as of the beginning of a fiscal year for which interim or annual
financial statements have not yet been issued. Retrospective
application to previously issued financial statements is
prohibited. Entities must disclose the nature of any change in their
accounting policy for income tax benefits of dividends on share-based payment
awards resulting from the adoption of this guidance. Pepco Holdings
has evaluated the impact of EITF Issue No. 06-11 and has determined that it does
not have a material impact on its overall financial condition, results of
operations, cash flows, or footnote disclosure requirements.
SFAS No. 141(R), “Business Combinations
– a replacement of FASB Statement No. 141”
On December 4, 2007, the FASB issued
SFAS No. 141(R), “Business Combinations – a replacement of FASB Statement No.
141” (SFAS No. 141(R)) which replaces FASB Statement No. 141, “Business
Combinations.” This Statement retains the fundamental requirements in
Statement 141 that the acquisition method of accounting (which Statement
141 called the purchase method) be used for all business combinations and for an
acquirer to be identified for each business combination.
SFAS No. 141(R) applies to all
transactions or other events in which an entity (the acquirer) obtains control
of one or more businesses (the acquiree). It does not apply to (i)
the formation of a joint venture, (ii) the acquisition of an asset or a group of
assets that does not constitute a business, (iii) a combination between entities
or businesses under common control and (iv) a combination between not-for-profit
organizations or the acquisition of a for-profit business by a not-for-profit
organization.
SFAS No. 141(R) applies prospectively
to business combinations for which the acquisition date is on or after the
beginning of the first annual reporting period beginning on or after December
15, 2008 (January 1, 2009 for Pepco Holdings). An entity may not
apply it before that date.
SFAS No. 160, “Noncontrolling Interests
in Consolidated Financial Statements – an amendment of ARB No. 51”
On December 4, 2007, the FASB issued
SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements –
an amendment of ARB No. 51” (SFAS No. 160) which amends ARB 51 to establish
accounting and reporting standards for the noncontrolling interest in a
subsidiary and for the deconsolidation of a subsidiary. It clarifies
that a noncontrolling interest in a subsidiary is an ownership interest in the
consolidated entity that should be reported as equity in the consolidated
financial statements.
A noncontrolling interest, sometimes
called a minority interest, is the portion of equity in a subsidiary not
attributable, directly or indirectly, to a parent. The objective of SFAS No. 160
is to improve the relevance, comparability, and transparency of the financial
information that a reporting entity provides in its consolidated financial
statements by establishing accounting and reporting standards that require (i)
the ownership interests in subsidiaries held by parties other than the parent be
clearly identified, labeled, and presented in the consolidated statement of
financial position within equity, but separate from the parent’s equity, (ii)
the amount of consolidated net income attributable to the parent and to the
noncontrolling interest be clearly identified and presented on the face of the
consolidated statement of income, (iii) changes in a parent’s ownership interest
while the parent retains its controlling financial interest in its subsidiary be
accounted for consistently. A parent’s ownership interest in a
subsidiary changes if the parent purchases additional ownership interests in its
subsidiary or if the parent sells some of its ownership interests in its
subsidiary. It also changes if the subsidiary reacquires some of its ownership
interests or the subsidiary issues additional ownership interests. All of those
transactions are economically similar, and this Statement requires that they be
accounted for similarly, as equity transactions, (iv) when a subsidiary is
deconsolidated, any retained noncontrolling equity investment in the former
subsidiary be initially measured at fair value. The gain or loss on
the deconsolidation of the subsidiary is measured using the fair value of any
noncontrolling equity investment rather than the carrying amount of that
retained investment and (v) entities provide sufficient disclosures that clearly
identify and distinguish between the interests of the parent and the interests
of the noncontrolling owners.
SFAS No. 160 applies to all entities
that prepare consolidated financial statements, except not-for-profit
organizations, but will affect only those entities that have an outstanding
noncontrolling interest in one or more subsidiaries or that deconsolidate a
subsidiary.
SFAS No. 160 is effective for fiscal
years, and interim periods within those fiscal years, beginning on or after
December 15, 2008 (January 1, 2009, for Pepco Holdings). Earlier
adoption is prohibited. SFAS No. 160 shall be applied prospectively
as of the beginning of the fiscal year in which this Statement is initially
applied, except for the presentation and disclosure requirements. The
presentation and disclosure requirements shall be applied retrospectively for
all periods presented. Pepco Holdings is currently evaluating the
impact SFAS No. 160 may have on its overall financial condition, results of
operations, cash flows or footnote disclosure requirements.
(3) SEGMENT
INFORMATION
Based on the provisions of SFAS No.
131, “Disclosures about Segments of an Enterprise and Related Information,”
Pepco Holdings’ management has identified its operating segments at
December 31, 2007 as Power Delivery, Conectiv Energy, Pepco Energy
Services, and Other Non-Regulated. Prior to 2007, intrasegment
revenues and expenses were not eliminated at the segment level for purposes of
presenting segment financial results but rather were eliminated for PHI’s
consolidated results through the “Corp. & Other”
column. Beginning in 2007, intrasegment revenues and expenses are
eliminated at the segment level. Segment results for the years ended
December 31, 2006 and 2005 have been reclassified to conform to the current
presentation. Segment financial information for the years ended
December 31, 2007, 2006, and 2005, is as follows.
|
Year
Ended December 31,
2007 |
(Millions
of dollars)
|
|
|
|
Competitive
Energy
Segments
|
|
|
|
|
|
|
Power
Delivery
|
Conectiv
Energy
|
Pepco
Energy
Services
|
Other
Non-
Regulated
|
Corp.
&
Other(a)
|
PHI
Cons.
|
|
|
Operating
Revenue
|
$5,244.2
|
|
$2,205.6
|
(b)
|
$2,309.1
|
(b)
|
$ 76.2
|
|
$(468.7)
|
|
$9,366.4
|
|
|
Operating
Expense (c)
|
4,713.6
|
(b)(d)
|
2,057.1
|
|
2,250.9
|
|
5.0
|
|
(466.8)
|
|
8,559.8
|
|
|
Operating
Income
|
530.6
|
|
148.5
|
|
58.2
|
|
71.2
|
|
(1.9)
|
|
806.6
|
|
|
Interest
Income
|
13.0
|
|
5.5
|
|
3.2
|
|
10.4
|
|
(12.5)
|
|
19.6
|
|
|
Interest
Expense
|
189.3
|
|
32.7
|
|
3.6
|
|
33.8
|
|
80.4
|
|
339.8
|
|
|
Other
Income
|
19.5
|
|
.5
|
|
5.0
|
|
9.8
|
|
1.2
|
|
36.0
|
|
|
Preferred
Stock
Dividends
|
.3
|
|
-
|
|
-
|
|
2.5
|
|
(2.5)
|
|
.3
|
|
|
Income
Taxes
|
141.7
|
(e)
|
48.8
|
|
24.4
|
|
9.3
|
|
(36.3)
|
|
187.9
|
|
|
Net
Income (Loss)
|
231.8
|
|
73.0
|
|
38.4
|
|
45.8
|
|
(54.8)
|
|
334.2
|
|
|
Total
Assets
|
9,799.9
|
|
1,785.3
|
|
682.7
|
|
1,533.0
|
|
1,310.1
|
|
15,111.0
|
|
|
Construction
Expenditures
|
$ 554.2
|
|
$ 42.0
|
|
$ 15.2
|
|
$ -
|
|
$ 12.0
|
|
$ 623.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
Includes
unallocated Pepco Holdings’ (parent company) capital costs, such as
acquisition financing costs, and the depreciation and amortization related
to purchase accounting adjustments for the fair value of Conectiv assets
and liabilities as of the August 1, 2002 acquisition
date. Additionally, the Total Assets line item in this column
includes Pepco Holdings’ goodwill balance. Included in Corp.
& Other are intercompany amounts of $(469.0) million for Operating
Revenue, $(464.2) million for Operating Expense, $(92.8) million for
Interest Income, $(90.4) million for Interest Expense, and $(2.5) million
for Preferred Stock Dividends.
|
|
(b)
|
Power
Delivery purchased electric energy and capacity and natural gas from
Conectiv Energy and Pepco Energy Services in the amount of $431.4 million
for the year ended December 31,
2007.
|
|
(c)
|
Includes
depreciation and amortization of $365.9 million, consisting of $306.0
million for Power Delivery, $37.7 million for Conectiv Energy, $12.1
million for Pepco Energy Services, $1.8 million for Other Non-Regulated
and $8.3 million for Corp. &
Other.
|
|
(d)
|
Includes
$33.4 million ($20.0 million, after-tax) from settlement of Mirant
bankruptcy claims.
|
|
(e)
|
Includes
$19.5 million benefit ($17.7 million net of fees) related to Maryland
income tax settlement.
|
|
|
|
(Millions
of dollars)
|
|
|
|
Competitive
Energy
Segments
|
|
|
|
|
|
|
Power
Delivery
|
Conectiv
Energy
|
Pepco
Energy
Services
|
Other
Non-
Regulated
|
Corp.
&
Other(a)
|
PHI
Cons.
|
|
|
Operating
Revenue
|
$5,118.8
|
|
$1,964.2
|
(b)(g)
|
$1,668.9
|
|
$ 90.6
|
|
$(479.6)
|
(g)
|
$ 8,362.9
|
|
|
Operating
Expense (c)
|
4,651.0
|
(b)
|
1,866.6
|
(g)
|
1,631.2
|
(e)
|
6.5
|
|
(485.7)
|
(g)
|
7,669.6
|
|
|
Operating
Income
|
467.8
|
|
97.6
|
|
37.7
|
|
84.1
|
|
6.1
|
|
693.3
|
|
|
Interest
Income
|
12.0
|
|
7.7
|
(g)
|
2.9
|
|
7.3
|
(h)
|
(13.0)
|
(g)(h)
|
16.9
|
|
|
Interest
Expense
|
180.5
|
|
36.1
|
(g)
|
4.9
|
|
38.2
|
(h)
|
79.4
|
(g)(h)
|
339.1
|
|
|
Other
Income
|
18.6
|
|
10.4
|
(d)
|
1.6
|
|
7.9
|
|
1.3
|
|
39.8
|
|
|
Preferred
Stock
Dividends
|
2.1
|
|
-
|
|
-
|
|
2.5
|
|
(3.4)
|
|
1.2
|
|
|
Income
Taxes
|
124.5
|
(f)
|
32.5
|
|
16.7
|
|
8.4
|
(f)
|
(20.7)
|
(f)
|
161.4
|
|
|
Net
Income (Loss)
|
191.3
|
|
47.1
|
|
20.6
|
|
50.2
|
|
(60.9)
|
|
248.3
|
|
|
Total
Assets
|
8,933.3
|
|
1,841.5
|
|
617.6
|
|
1,595.6
|
|
1,255.5
|
|
14,243.5
|
|
|
Construction
Expenditures
|
$ 447.2
|
|
$ 11.8
|
|
$ 6.3
|
|
$ -
|
|
$ 9.3
|
|
$ 474.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
Includes
unallocated Pepco Holdings’ (parent company) capital costs, such as
acquisition financing costs, and the depreciation and amortization related
to purchase accounting adjustments for the fair value of Conectiv assets
and liabilities as of the August 1, 2002 acquisition
date. Additionally, the Total Assets line item in this column
includes Pepco Holdings’ goodwill balance. Included in Corp.
& Other are intercompany amounts of $(481.3) million for Operating
Revenue, $(475.1) million for Operating Expense, $(90.0) million for
Interest Income, $(87.6) million for Interest Expense, and $(2.5) million
for Preferred Stock Dividends.
|
|
(b)
|
Power
Delivery purchased electric energy and capacity and natural gas from
Conectiv Energy in the amount of $460.5 million for the year ended
December 31, 2006.
|
|
(c)
|
Includes
depreciation and amortization of $413.2 million, consisting of $354.3
million for Power Delivery, $36.3 million for Conectiv Energy, $11.8
million for Pepco Energy Services, $1.8 million for Other Non-Regulated
and $9.0 million for Corp. &
Other.
|
|
(d)
|
Includes
$12.3 million gain ($7.9 million after-tax) on the sale of its equity
interest in a joint venture which owns a wood burning cogeneration
facility in California.
|
|
(e)
|
Includes
$18.9 million of impairment losses ($13.7 million after-tax) related to
certain energy services business
assets.
|
|
(f)
|
In
2006, PHI resolved certain, but not all, tax matters that were raised in
Internal Revenue Service audits related to the 2001 and 2002 tax
years. Adjustments recorded related to these resolved tax
matters resulted in a $6.3 million increase in net income ($2.5 million
for Power Delivery and $5.4 million for Other Non-Regulated, partially
offset by an unfavorable $1.6 million impact in Corp. &
Other). To the extent that the matters resolved related to tax
contingencies from the Conectiv legacy companies that existed at the
August 2002 acquisition date, in accordance with accounting rules, an
additional adjustment of $9.1 million ($3.1 million related to Power
Delivery and $6.0 million related to Other Non-Regulated) was recorded in
Corp. & Other to eliminate the tax benefits recorded by Power Delivery
and Other Non-Regulated against the goodwill balance that resulted from
the acquisition. Also during 2006, the total favorable impact
of $2.6 million was recorded that resulted from changes in estimates
related to prior year tax liabilities subject to audit ($4.1 million for
Power Delivery, partially offset by an unfavorable $1.5 million for Corp.
& Other).
|
|
(g)
|
Due
to the reclassification referred to in the introductory paragraph, the
Conectiv Energy segment does not include $193.1 million of intrasegment
operating revenue and operating expense and $27.7 million of intrasegment
interest income and interest expense. Accordingly, the Corp.
& Other column does not include an elimination for these
amounts.
|
|
(h)
|
Due
to the reclassification referred to in the introductory paragraph, the
Other Non-Regulated segment does not include $163.1 million of
intrasegment interest income and interest expense. Accordingly,
the Corp. & Other column does not include an elimination for these
amounts.
|
|
|
(Millions
of dollars)
|
|
|
|
Competitive
Energy
Segments
|
|
|
|
|
|
|
Power
Delivery
|
Conectiv
Energy
|
Pepco
Energy
Services
|
Other
Non-
Regulated
|
Corp.
&
Other(a)
|
PHI
Cons.
|
|
|
Operating
Revenue
|
$4,702.9
|
|
$2,393.1
|
(b)(h)
|
$1,487.5
|
$ 84.5
|
|
$(602.5)
|
(h)
|
$ 8,065.5
|
|
|
Operating
Expense (g)
|
4,032.1
|
(b)(e)
|
2,289.2
|
(h)
|
1,445.1
|
(3.8)
|
(f)
|
(602.5)
|
(h)
|
7,160.1
|
|
|
Operating
Income
|
670.8
|
|
103.9
|
|
42.4
|
88.3
|
|
-
|
|
905.4
|
|
|
Interest
Income
|
8.3
|
|
3.0
|
(h)
|
2.5
|
7.8
|
(i)
|
(5.6)
|
(h)(i)
|
16.0
|
|
|
Interest
Expense
|
175.0
|
|
29.8
|
(h)
|
5.6
|
41.7
|
(i)
|
85.5
|
(h)(i)
|
337.6
|
|
|
Other
Income
|
20.2
|
|
3.6
|
|
1.7
|
4.6
|
|
6.0
|
|
36.1
|
|
|
Preferred
Stock
Dividends
|
2.6
|
|
-
|
|
-
|
2.5
|
|
(2.6)
|
|
2.5
|
|
|
Income
Taxes
|
228.6
|
(c)
|
32.6
|
|
15.3
|
12.8
|
|
(34.1)
|
|
255.2
|
|
|
Extraordinary
Item
(net
of tax of
$6.2
million)
|
9.0
|
(d)
|
-
|
|
-
|
-
|
|
-
|
|
9.0
|
|
|
Net
Income (Loss)
|
302.1
|
|
48.1
|
|
25.7
|
43.7
|
|
(48.4)
|
|
371.2
|
|
|
Total
Assets
|
8,738.6
|
|
2,227.6
|
|
514.4
|
1,476.9
|
|
1,081.4
|
|
14,038.9
|
|
|
Construction
Expenditures
|
$ 432.1
|
|
$ 15.4
|
|
$ 11.3
|
$ -
|
|
$ 8.3
|
|
$ 467.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
Includes
unallocated Pepco Holdings’ (parent company) capital costs, such as
acquisition financing costs, and the depreciation and amortization related
to purchase accounting adjustments for the fair value of Conectiv assets
and liabilities as of the August 1, 2002 acquisition
date. Additionally, the Total Assets line item in this column
includes Pepco Holdings’ goodwill balance. Included in Corp.
& Other are intercompany amounts of $(605.2) million for Operating
Revenue, $(599.7) million for Operating Expense, $(81.3) million for
Interest Income, $(79.1) million for Interest Expense, and $(2.5) million
for Preferred Stock Dividends.
|
|
(b)
|
Power
Delivery purchased electric energy and capacity and natural gas from
Conectiv Energy in the amount of $565.3 million for the year ended
December 31, 2005.
|
|
(c)
|
Includes
$10.9 million in income tax expense related to Internal Revenue Service
(IRS) Revenue Ruling 2005-53. Also refer to Note (12)
Commitments and Contingencies for a discussion of the IRS mixed service
cost issue.
|
|
(d)
|
Relates
to ACE’s electric distribution rate case settlement that was accounted for
in the first quarter of 2005. This resulted in ACE’s reversal
of $9.0 million in after-tax accruals related to certain deferred costs
that are now deemed recoverable. This amount is classified as
extraordinary since the original accrual was part of an extraordinary
charge in conjunction with the accounting for competitive restructuring in
1999.
|
|
(e)
|
Includes
$70.5 million ($42.2 million after-tax) gain (net of customer sharing)
from the settlement of the Pepco TPA Claim and the Pepco asbestos claims
against the Mirant bankruptcy estate. Also includes $68.1
million gain ($40.7 million after-tax) from the sale of non-utility land
owned by Pepco at Buzzard Point.
|
|
(f)
|
Includes
$13.3 million gain ($8.9 million after-tax) related to PCI’s liquidation
of a financial investment that was written off in
2001.
|
|
(g)
|
Includes
depreciation and amortization of $427.3 million, consisting of $361.4
million for Power Delivery, $40.4 million for Conectiv Energy, $14.5
million for Pepco Energy Services, $1.7 million for Other Non-Regulated
and $9.3 million for Corp. &
Other.
|
|
(h)
|
Due
to the reclassification referred to in the introductory paragraph, the
Conectiv Energy segment does not include $210.5 million of intrasegment
operating revenue and operating expense and $28.9 million of intrasegment
interest income and interest expense. Accordingly, the Corp.
& Other column does not include an elimination for these
amounts.
|
|
(i)
|
Due
to the reclassification referred to in the introductory paragraph, the
Other Non-Regulated segment does not include $107.4 million of
intrasegment interest income and interest expense. Accordingly,
the Corp. & Other column does not include an elimination for these
amounts.
|
(4) LEASING
ACTIVITIES
Finance
Leases
As of December 31, 2007 and 2006, Pepco
Holdings had equity investments in energy leveraged leases of $1,384.4 million
and $1,321.8 million, respectively, consisting of electric power plants and
natural gas transmission and distribution networks located outside of
the
United
States. As of December 31, 2007, $708.4 million of equity is
attributable to facilities located in Austria, $490.5 million in The Netherlands
and $185.5 million in Australia.
The components of the net investment in
finance leases at December 31, 2007 and 2006 are summarized below (millions of
dollars):
|
|
|
|
|
|
Scheduled
lease payments, net of non-recourse debt
|
$
|
2,281.2
|
|
|
Less: Unearned
and deferred income
|
|
(896.8)
|
|
|
Investment
in finance leases held in trust
|
|
1,384.4
|
|
|
Less: Deferred
taxes
|
|
(772.8)
|
|
|
Net
Investment in Finance Leases Held in Trust
|
$
|
611.6
|
|
|
|
|
|
|
|
|
|
|
|
|
Scheduled
lease payments, net of non-recourse debt
|
$
|
2,284.6
|
|
|
Less: Unearned
and deferred income
|
|
(962.8)
|
|
|
Investment
in finance leases held in trust
|
|
1,321.8
|
|
|
Less: Deferred
taxes
|
|
(682.2)
|
|
|
Net
Investment in Finance Leases Held in Trust
|
$
|
639.6
|
|
|
|
|
|
|
Income recognized from leveraged leases
(included in “Other Operating Revenue”) was comprised of the following for the
years ended December 31:
|
|
|
2007
|
|
2006
|
|
2005
|
|
|
|
|
(Millions
of dollars)
|
|
|
Pre-tax
earnings from leveraged leases
|
|
$76.0
|
|
$88.2
|
|
$81.5
|
|
|
Income
tax expense
|
|
15.8
|
|
25.8
|
|
20.6
|
|
|
Net
Income from Leveraged Leases Held in Trust
|
|
$60.2
|
|
$62.4
|
|
$60.9
|
|
|
|
|
|
|
|
|
|
|
Scheduled lease payments from leveraged
leases are net of non-recourse debt. Minimum lease payments
receivable from PCI’s finance leases for each of the years 2008 through 2012 and
thereafter are zero for 2008 and 2009, $16.0 million for 2010, zero for 2011 and
2012, and $1,368.4 million thereafter. For a discussion of the
federal tax treatment of cross-border leases, see Note (12) “Commitments and
Contingencies.”
Lease
Commitments
Pepco leases its consolidated control
center, 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 $7.6 million
over a 25-year period beginning in December 1994 and provides for transfer of
ownership of the system to Pepco for $1 at the end of the lease
term. Under SFAS No. 71, the amortization of leased assets is
modified so that the total interest on the obligation and amortization of the
leased asset is equal to the rental expense allowed for rate-making
purposes. This lease has been treated as an operating lease for
rate-making purposes.
Capital lease assets recorded within
Property, Plant and Equipment at December 31, 2007 and 2006, in millions of
dollars, are comprised of the following:
|
|
Original
Cost
|
Accumulated
Amortization
|
Net
Book
Value
|
|
|
Transmission
|
$ 76.0
|
$ 20.5
|
$ 55.5
|
|
|
Distribution
|
76.0
|
20.5
|
55.5
|
|
|
General
|
2.6
|
2.4
|
.2
|
|
|
Total
|
$154.6
|
$ 43.4
|
$111.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transmission
|
$ 76.0
|
$ 18.0
|
$ 58.0
|
|
|
Distribution
|
76.0
|
18.0
|
58.0
|
|
|
General
|
2.6
|
2.0
|
.6
|
|
|
Total
|
$154.6
|
$ 38.0
|
$116.6
|
|
|
|
|
|
|
|
The approximate annual commitments
under all capital leases are $15.4 million for 2008, $15.2 million for 2009,
2010, 2011 and 2012, and $106.7 million thereafter.
Rental expense for operating leases was
$50.6 million, $50.8 million, and $53.3 million for the years ended
December 31, 2007, 2006, and 2005, respectively.
Total future minimum operating lease
payments for Pepco Holdings as of December 31, 2007 include $38.1 million in
2008, $33.7 million in 2009, $28.7 million in 2010, $25.6 million in 2011, $24.0
million in 2012 and $361.9 million after 2012.
(5) PROPERTY, PLANT AND
EQUIPMENT
Property, plant and equipment is
comprised of the following:
|
|
|
Original
Cost
|
|
Accumulated
Depreciation
|
|
Net
Book
Value
|
|
|
|
|
(Millions
of dollars)
|
|
|
Generation
|
|
$ 1,758.2
|
|
$ 607.9
|
|
$1,150.3
|
|
|
Distribution
|
|
6,494.2
|
|
2,426.6
|
|
4,067.6
|
|
|
Transmission
|
|
1,961.7
|
|
712.2
|
|
1,249.5
|
|
|
Gas
|
|
363.7
|
|
104.8
|
|
258.9
|
|
|
Construction
work in progress
|
|
561.1
|
|
-
|
|
561.1
|
|
|
Non-operating
and other property
|
|
1,167.6
|
|
578.3
|
|
589.3
|
|
|
Total
|
|
$12,306.5
|
|
$4,429.8
|
|
$7,876.7
|
|
|
|
|
|
|
|
|
|
|
|
Generation
|
|
$ 1,811.6
|
|
$ 608.9
|
|
$1,202.7
|
|
|
Distribution
|
|
6,285.6
|
|
2,302.3
|
|
3,983.3
|
|
|
Transmission
|
|
1,850.3
|
|
679.1
|
|
1,171.2
|
|
|
Gas
|
|
349.8
|
|
97.6
|
|
252.2
|
|
|
Construction
work in progress
|
|
343.5
|
|
-
|
|
343.5
|
|
|
Non-operating
and other property
|
|
1,178.9
|
|
555.2
|
|
623.7
|
|
|
Total
|
|
$11,819.7
|
|
$4,243.1
|
|
$7,576.6
|
|
|
|
|
|
|
|
|
|
|
The non-operating and other property
amounts include balances for general plant, distribution and transmission plant
held for future use as well as other property held by non-utility
subsidiaries.
Pepco Holdings’ utility subsidiaries
use separate depreciation rates for each electric plant account. The rates vary
from jurisdiction to jurisdiction.
Asset
Sales
As discussed in Note (2), Summary of
Significant Accounting Policies, in the third quarter of 2006, ACE completed the
sale of its interest in the Keystone and Conemaugh generating facilities for
approximately $175.4 million (after giving effect to post-closing adjustments)
and in the first quarter of 2007, ACE completed the sale of the B.L. England
generating facility for a price of $9.0 million.
In the third quarter of 2005, Pepco
sold for $75 million in cash 384,051 square feet of excess non-utility land
located at Buzzard Point in the District of Columbia. The sale resulted in a
pre-tax gain of $68.1 million, which was recorded as a reduction of Operating
Expenses in the Consolidated Statements of Earnings.
Jointly Owned
Plant
PHI’s Consolidated Balance Sheet
includes its proportionate share of assets and liabilities related to jointly
owned plant. PHI’s subsidiaries have ownership interests in
transmission facilities and other facilities in which various parties have
ownership interests. PHI’s proportionate share of operating and
maintenance expenses of the jointly owned plant is included in the corresponding
expenses in PHI’s Consolidated Statements of Earnings. PHI is
responsible for providing its share of financing for the jointly owned
facilities. Information with respect to PHI’s share of jointly owned
plant as of December 31, 2007 is shown below.
|
Jointly
Owned Plant
|
Ownership
Share
|
Plant
in
Service
|
Accumulated
Depreciation
|
Construction
Work
in
Progress
|
|
|
|
|
(Millions
of dollars)
|
|
|
Transmission
Facilities
|
Various
|
$35.8
|
$23.1
|
$ -
|
|
|
Other
Facilities
|
Various
|
5.1
|
2.1
|
-
|
|
|
Total
|
|
$40.9
|
$25.2
|
$ -
|
|
|
|
|
|
|
|
|
(6) PENSIONS 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. Certain 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.
Pepco Holdings accounts for the PHI
Retirement Plan and nonqualified retirement plans in accordance with
SFAS No. 87, “Employers’ Accounting for Pensions,” and its
postretirement
health
care and life insurance benefits for eligible employees in accordance with
SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other
Than Pensions.” In addition, on December 31, 2006, Pepco Holdings
implemented SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and
Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and
132 (R)” (SFAS No. 158) which requires that companies recognize a net liability
or asset to report the funded status of their defined benefit pension and other
postretirement benefit plans on the balance sheet with an offset to accumulated
other comprehensive income in shareholders’ equity or a deferral in a regulatory
asset or liability if probable of recovery in rates under SFAS No. 71
“Accounting For the Effects of Certain Types of Legislation.” SFAS
No.158 does not change how pension and other postretirement benefits are
accounted for and reported in the consolidated statements of
earnings. PHI’s financial statement disclosures are prepared in
accordance with SFAS No. 132, “Employers’ Disclosures about Pensions
and Other Postretirement Benefits,” as revised and amended by SFAS No.
158. Refer to Note (2) “Summary of Significant Accounting Policies --
Pension and Other Postretirement Benefit Plans” for additional
information.
All amounts in the following tables are
in millions of dollars.
|
At
December 31,
|
Pension
Benefits
|
|
Other
Postretirement
Benefits
|
|
|
Change
in Benefit Obligation
|
2007
|
|
2006
|
|
2007
|
|
2006
|
|
|
Benefit
obligation at beginning of year
|
$1,715.3
|
|
$1,746.0
|
|
$611.2
|
|
$610.2
|
|
|
Service
cost
|
36.3
|
|
40.5
|
|
7.1
|
|
8.4
|
|
|
Interest
cost
|
101.6
|
|
96.9
|
|
36.7
|
|
34.6
|
|
|
Amendments
|
3.6
|
|
-
|
|
-
|
|
-
|
|
|
Actuarial
(gain) loss
|
(7.0)
|
|
(42.4)
|
|
3.2
|
|
(3.6)
|
|
|
Benefits
paid
|
(149.0)
|
|
(125.7)
|
|
(38.4)
|
|
(38.4)
|
|
|
Benefit
obligation at end of year
|
$1,700.8
|
|
$1,715.3
|
|
$619.8
|
|
$611.2
|
|
|
Change
in Plan Assets
|
|
|
|
|
|
|
|
|
|
Fair
value of plan assets at beginning of year
|
$1,633.7
|
|
$1,578.4
|
|
$206.2
|
|
$ 173.7
|
|
|
Actual
return on plan assets
|
138.7
|
|
177.8
|
|
12.0
|
|
23.2
|
|
|
Company
contributions
|
8.0
|
|
3.2
|
|
54.5
|
|
47.7
|
|
|
Benefits
paid
|
(149.0)
|
|
(125.7)
|
|
(38.4)
|
|
(38.4)
|
|
|
Fair
value of plan assets at end of year
|
$1,631.4
|
|
$1,633.7
|
|
$234.3
|
|
$ 206.2
|
|
|
|
|
|
|
|
|
|
|
|
|
Funded
Status at end of year
(plan
assets less plan obligations)
|
$(69.4)
|
|
$ (81.6)
|
|
$(385.5)
|
|
$(405.0)
|
|
The following table provides the
amounts recognized in PHI’s Consolidated Balance Sheets as of December 31, 2007
in compliance with SFAS No. 158:
|
|
Pension
Benefits
|
|
Other
Postretirement
Benefits
|
|
|
2007
|
|
2006
|
|
2007
|
|
2006
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulatory
asset
|
$202.6
|
|
$229.9
|
|
$131.4
|
|
$135.5
|
|
|
Current
liabilities
|
(3.9)
|
|
(3.3)
|
|
-
|
|
-
|
|
|
Pension
benefit obligation
|
(65.5)
|
|
(78.3)
|
|
-
|
|
-
|
|
|
Other
postretirement benefit obligations
|
-
|
|
-
|
|
(385.5)
|
|
(405.0)
|
|
|
Deferred
income tax
|
5.0
|
|
5.6
|
|
-
|
|
-
|
|
|
Accumulated
other comprehensive income, net of tax
|
7.5
|
|
8.4
|
|
-
|
|
-
|
|
|
Net
amount recognized
|
$145.7
|
|
$162.3
|
|
$(254.1)
|
|
$(269.5)
|
|
|
|
|
|
|
|
|
|
|
|
Amounts included in accumulated other
comprehensive income (pre-tax) and regulatory assets at December 31, 2007 in
compliance with SFAS No. 158 consist of:
|
|
Pension
Benefits
|
|
Other
Postretirement
Benefits
|
|
|
2007
|
|
2006
|
|
2007
|
|
2006
|
|
|
|
|
|
|
|
|
|
|
Unrecognized
net actuarial loss
|
$214.7
|
|
$242.8
|
|
$158.9
|
|
$167.6
|
|
Unamortized
prior service cost (credit)
|
.3
|
|
1.1
|
|
(31.2)
|
|
(36.6)
|
|
Unamortized
transition liability
|
-
|
|
-
|
|
3.7
|
|
4.5
|
|
|
215.0
|
|
243.9
|
|
131.4
|
|
135.5
|
|
Accumulated
other comprehensive income
($7.5
million, and $8.4 million net of tax)
|
12.4
|
|
14.0
|
|
-
|
|
-
|
|
Regulatory
assets
|
202.6
|
|
229.9
|
|
131.4
|
|
135.5
|
|
|
$215.0
|
|
$243.9
|
|
$131.4
|
|
$135.5
|
|
|
|
|
|
|
|
|
|
The table below provides the components
of net periodic benefit costs recognized for the years ended December
31.
|
|
|
|
|
|
Pension
Benefits
|
|
Other
Postretirement
Benefits
|
|
|
2007
|
|
2006
|
|
2005
|
|
2007
|
|
2006
|
|
2005
|
|
|
Service
cost
|
$ 36.3
|
|
$ 40.5
|
|
$ 37.9
|
|
$ 7.1
|
|
$ 8.4
|
|
$ 8.5
|
|
|
Interest
cost
|
101.6
|
|
96.9
|
|
96.1
|
|
36.7
|
|
34.6
|
|
33.6
|
|
|
Expected
return on plan assets
|
(130.2)
|
|
(130.0)
|
|
(125.5)
|
|
(13.3)
|
|
(11.5)
|
|
(10.9)
|
|
|
Amortization
of prior service cost
|
.8
|
|
.8
|
|
1.1
|
|
(4.2)
|
|
(4.0)
|
|
(3.3)
|
|
|
Amortization
of net loss
|
9.3
|
|
17.5
|
|
10.9
|
|
11.2
|
|
14.3
|
|
11.3
|
|
|
Recognition
of Benefit Contract
|
3.6
|
|
-
|
|
-
|
|
2.0
|
|
-
|
|
-
|
|
|
Curtailment/Settlement
(Gain)/Loss
|
3.3
|
|
-
|
|
-
|
|
(.4)
|
|
-
|
|
-
|
|
|
Net
periodic benefit cost
|
$ 24.7
|
|
$ 25.7
|
|
$ 20.5
|
|
$39.1
|
|
$ 41.8
|
|
$39.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The 2007 combined pension and other
postretirement net periodic benefit cost of $63.8 million includes $22.3 million
for Pepco, $4.3 million for DPL and $11.0 million for ACE. The
remaining net periodic benefit cost includes amounts for other PHI
subsidiaries.
The 2006 combined pension and other
postretirement net periodic benefit cost of $67.5 million includes $32.1 million
for Pepco, $.7 million for DPL and $14.3 million for ACE. The
remaining net periodic benefit cost includes amounts for other PHI
subsidiaries.
The 2005 combined pension and other
postretirement net periodic benefit cost of $59.7 million includes $28.9 million
for Pepco, $(2.0) million for DPL and $16.9 million for ACE. The
remaining net periodic benefit cost includes amounts for other PHI
subsidiaries.
The following weighted average
assumptions were used to determine the benefit obligations at December
31:
|
|
|
|
|
|
|
|
|
|
|
Pension
Benefits
|
|
Other
Postretirement
Benefits
|
|
|
2007
|
|
2006
|
|
2007
|
|
2006
|
|
Discount
rate
|
6.25%
|
|
6.00%
|
|
6.25%
|
|
6.00%
|
|
Rate
of compensation increase
|
4.50%
|
|
4.50%
|
|
4.50%
|
|
4.50%
|
|
Health
care cost trend rate assumed for current year
|
-
|
|
-
|
|
8.00%
|
|
9.00%
|
|
Rate
to which the cost trend rate is assumed to decline
(the
ultimate trend rate)
|
-
|
|
-
|
|
5.00%
|
|
5.00%
|
|
Year
that the rate reaches the ultimate trend rate
|
-
|
|
-
|
|
2010
|
|
2010
|
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 (millions of dollars):
|
|
1-Percentage-
Point
Increase
|
1-Percentage-
Point
Decrease
|
|
Increase
(decrease) on total service and interest cost
|
$ 2.1
|
$ (2.1)
|
|
Increase
(decrease) on postretirement benefit obligation
|
$31.8
|
$(31.6)
|
The following weighted average
assumptions were used to determine the net periodic benefit cost for the years
ended December 31:
|
|
|
|
Pension
Benefits
|
|
Other
Postretirement
Benefits
|
|
|
2007
|
|
2006
|
|
2007
|
|
2006
|
|
Discount
rate
|
6.000%
|
|
5.625%
|
|
6.000%
|
|
5.625%
|
|
Expected
long-term return on plan assets
|
8.250%
|
|
8.500%
|
|
8.250%
|
|
8.500%
|
|
Rate
of compensation increase
|
4.500%
|
|
4.500%
|
|
4.500%
|
|
4.500%
|
A cash flow matched bond portfolio
approach to developing a discount rate is used to value SFAS No. 87 and SFAS No.
106 liabilities. The hypothetical portfolio includes high quality instruments
with maturities that mirror the benefit obligations.
In selecting an expected rate of return
on plan assets, PHI considers actual historical returns, economic forecasts and
the judgment of its investment consultants on expected long-term performance for
the types of investments held by the plan. The plan assets consist of equity and
fixed income investments, and when viewed over a long-term horizon, are expected
to yield a return on assets of 8.250%.
Plan
Assets
The PHI Retirement Plan weighted
average asset allocations at December 31, 2007, and 2006, by asset category
are as follows:
|
Asset
Category
|
Plan
Assets
at
December 31,
|
|
Target
Plan
Asset
Allocation
|
|
Minimum/
Maximum
|
|
2007
|
|
2006
|
|
|
|
Equity
securities
|
58%
|
|
58%
|
|
60%
|
|
55%
- 65%
|
|
|
Debt
securities
|
33%
|
|
34%
|
|
30%
|
|
30%
- 50%
|
|
|
Other
|
9%
|
|
8%
|
|
10%
|
|
0%
- 10%
|
|
|
Total
|
100%
|
|
100%
|
|
100%
|
|
|
|
|
|
|
|
|
|
|
|
|
Pepco Holdings’ Other Postretirement
plan weighted average asset allocations at December 31, 2007, and 2006, by
asset category are as follows:
|
Asset
Category
|
Plan
Assets
at
December 31,
|
|
Target
Plan
Asset
Allocation
|
|
Minimum/
Maximum
|
|
2007
|
|
2006
|
|
|
|
Equity
securities
|
62%
|
|
64%
|
|
60%
|
|
55%
- 65%
|
|
|
Debt
securities
|
34%
|
|
33%
|
|
35%
|
|
20%
- 50%
|
|
|
Cash
|
4%
|
|
3%
|
|
5%
|
|
0%
- 10%
|
|
|
Total
|
100%
|
|
100%
|
|
100%
|
|
|
|
|
|
|
|
|
|
|
|
|
In developing an asset allocation
policy for the PHI Retirement Plan and other postretirement plan, PHI examined
projections of asset returns and volatility over a long-term
horizon. In connection with this analysis, PHI examined the
risk/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 and provide sufficient
liquidity for projected benefit payments. By incorporating the
results of these analyses with an assessment of its risk posture, and taking
into account industry practices, PHI developed its asset mix
guidelines. Under these guidelines, PHI diversifies assets in order
to protect against large investment losses and to reduce the probability of
excessive performance volatility while maximizing return at an acceptable risk
level. Diversification of assets is implemented by allocating monies to various
asset classes and investment styles within asset classes, and by retaining
investment management firm(s) with complementary investment philosophies, styles
and approaches. Based on the assessment of demographics,
actuarial/funding, and business and financial characteristics, PHI believes that
its risk posture is slightly below average relative to other pension
plans. Consequently, Pepco Holdings believes that a slightly below
average equity exposure (i.e. a target equity asset allocation of 60%) is
appropriate for the PHI Retirement Plan and the other postretirement
plan.
On a periodic basis, Pepco Holdings
reviews its asset mix and rebalances assets back to the target allocation over a
reasonable period of time.
No Pepco Holdings common stock is
included in pension or postretirement program assets.
Cash
Flows
Contributions
- PHI Retirement Plan
Pepco Holdings’ funding policy with
regard to the PHI Retirement Plan is to maintain a funding level in excess of
100% with respect to its accumulated benefit obligation (ABO). The
PHI Retirement Plan currently meets the minimum funding requirements of the
Employment Retirement Income Security Act of 1974 (ERISA) without any additional
funding. In 2007 and 2006, PHI made no contributions to the
plan. At December 31, 2007, PHI’s Plan assets were $1,631.4 and
the ABO was $1,538.0 million. At December 31, 2006, PHI’s Plan assets were
$1,633.7 million and the ABO was $1,575.2 million. Assuming no
changes to the current pension plan assumptions, PHI projects no funding will be
required under ERISA in 2008; however, PHI may elect to make a discretionary
tax-deductible contribution, to maintain its plan assets in excess of its
ABO.
Contributions
- Other Postretirement Benefits
In 2007 and 2006, Pepco contributed
$10.3 million and $6.0 million, respectively, DPL contributed $8.0 million and
$6.8 million, respectively, and ACE contributed $6.8 million and $6.6 million,
respectively, to the plans. In 2007 and 2006, contributions of $13.2
million and $13.5 million, respectively, were made by other PHI
subsidiaries. Assuming no changes to the other postretirement benefit
pension plan assumptions, PHI expects similar amounts to be contributed in
2008.
Expected
Benefit Payments
Estimated future benefit payments to
participants in PHI’s pension and postretirement welfare benefit plans, which
reflect expected future service as appropriate, as of December 31, 2007 are as
follows (millions of dollars):
|
Years
|
|
Pension
Benefits
|
Other Postretirement
Benefits
|
|
|
|
|
|
|
|
|
2008
|
|
$106.5
|
|
$ 40.3
|
|
|
2009
|
|
110.2
|
|
42.3
|
|
|
2010
|
|
112.4
|
|
44.1
|
|
|
2011
|
|
119.5
|
|
45.5
|
|
|
2012
|
|
121.8
|
|
46.5
|
|
|
2013
through 2017
|
|
656.3
|
|
246.1
|
|
Medicare Prescription Drug
Improvement and Modernization Act of 2003
On December 8, 2003, the Medicare
Prescription Drug Improvement and Modernization Act of 2003 (the Medicare Act)
became effective. The Medicare Act introduced a prescription drug
benefit under Medicare (Medicare Part D), as well as a federal subsidy to
sponsors of retiree health care benefits plans that provide a benefit that is at
least actuarially equivalent to Medicare Part D. Pepco Holdings
sponsors post-retirement health care plans that provide prescription drug
benefits that PHI plan actuaries have determined are actuarially equivalent to
Medicare Part D. At December 31, 2007, the estimated reduction
in accumulated postretirement
benefit
obligation is $30.4 million. In 2007 and 2006, Pepco Holdings received $1.9
million and $1.6 million, respectively, in Federal Medicare prescription drug
subsidies.
Pepco Holdings Retirement
Savings Plan
Pepco Holdings has a defined
contribution employee benefit plan (the 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 $11.0 million,
$11.0 million, and $10.4 million for the years ended December 31, 2007, 2006,
and 2005, respectively.
(7) DEBT
LONG-TERM
DEBT
The
components of long-term debt are shown below.
|
|
|
|
|
|
At December
31,
|
|
Interest
Rate
|
|
Maturity
|
|
|
2007
|
|
|
2006
|
|
|
|
|
|
|
(Millions
of dollars)
|
|
First
Mortgage Bonds
|
|
|
|
|
|
|
|
|
|
Pepco:
|
|
|
|
|
|
|
|
|
|
6.25%
|
|
2007
|
|
$
|
-
|
|
$
|
175.0
|
|
6.50%
|
|
2008
|
|
|
78.0
|
|
|
78.0
|
|
5.875%
|
|
2008
|
|
|
50.0
|
|
|
50.0
|
|
5.75% (a)
|
|
2010
|
|
|
16.0
|
|
|
16.0
|
|
4.95% (a)(b)
|
|
2013
|
|
|
200.0
|
|
|
200.0
|
|
4.65% (a)(b)
|
|
2014
|
|
|
175.0
|
|
|
175.0
|
|
Variable
(a)(b)
|
|
2022
|
|
|
109.5
|
|
|
109.5
|
|
5.375%
(a)
|
|
2024
|
|
|
38.3
|
|
|
38.3
|
|
5.75% (a)(b)
|
|
2034
|
|
|
100.0
|
|
|
100.0
|
|
5.40%
(a)(b)
|
|
2035
|
|
|
175.0
|
|
|
175.0
|
|
6.50%
(a)(b)
|
|
2037
|
|
|
250.0
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
ACE:
|
|
|
|
|
|
|
|
|
|
6.71%
- 7.15%
|
|
2007 - 2008
|
|
|
50.0
|
|
|
51.0
|
|
7.25%
- 7.63%
|
|
2010 - 2014
|
|
|
8.0
|
|
|
8.0
|
|
6.63%
|
|
2013
|
|
|
68.6
|
|
|
68.6
|
|
7.68%
|
|
2015 - 2016
|
|
|
17.0
|
|
|
17.0
|
|
6.80% (a)
|
|
2021
|
|
|
38.9
|
|
|
38.9
|
|
5.60% (a)
|
|
2025
|
|
|
4.0
|
|
|
4.0
|
|
Variable
(a)(b)
|
|
2029
|
|
|
54.7
|
|
|
54.7
|
|
5.80% (a)(b)
|
|
2034
|
|
|
120.0
|
|
|
120.0
|
|
5.80% (a)(b)
|
|
2036
|
|
|
105.0
|
|
|
105.0
|
|
|
|
|
|
|
|
|
|
|
|
Amortizing
First Mortgage Bonds
|
|
|
|
|
|
|
|
|
|
DPL:
|
|
|
|
|
|
|
|
|
|
6.95%
|
|
2007 - 2008
|
|
|
4.4
|
|
|
7.6
|
|
Total
First Mortgage Bonds
|
|
|
|
$
|
1,662.4
|
|
$
|
1,591.6
|
|
|
|
|
|
|
|
|
|
|
|
Unsecured
Tax-Exempt Bonds
|
|
|
|
|
|
|
|
|
|
DPL:
|
|
|
|
|
|
|
|
|
|
5.20%
|
|
2019
|
|
$
|
31.0
|
|
$
|
31.0
|
|
3.15%
|
|
2023
(c)
|
|
|
18.2
|
|
|
18.2
|
|
5.50%
|
|
2025(d)
|
|
|
15.0
|
|
|
15.0
|
|
4.90%
|
|
2026(e)
|
|
|
34.5
|
|
|
34.5
|
|
5.65%
|
|
2028
|
|
|
16.2
|
|
|
16.2
|
|
Variable
|
|
2030 - 2038
|
|
|
93.4
|
|
|
93.4
|
|
Total
Unsecured Tax-Exempt Bonds
|
|
|
|
$
|
208.3
|
|
$
|
208.3
|
|
(a)
|
Represents
a series of First Mortgage Bonds issued by the indicated company as
collateral for an outstanding series of senior notes or tax-exempt bonds
issued by the same company. The maturity date, optional and
mandatory prepayment provisions, if any, interest rate, and interest
payment dates on each series of senior notes or tax-exempt bonds are
identical to the terms of the collateral First Mortgage Bonds by which it
is secured. Payments of principal and interest on a series of
senior notes or 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 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 First Mortgage Bonds issued by the indicated company as
collateral for an outstanding series of senior notes as described in
footnote (a) above that 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.
|
|
(d)
|
The
bonds are subject to mandatory tender on July 1,
2010.
|
|
(e)
|
The
bonds are subject to mandatory tender on May 1,
2011.
|
|
|
NOTE: Schedule
is continued on next page.
|
|
|
|
|
|
|
At December
31,
|
|
Interest
Rate
|
|
Maturity
|
|
|
2007
|
|
|
2006
|
|
|
|
|
|
|
(Millions
of dollars)
|
|
Medium-Term
Notes (unsecured)
|
|
|
|
|
|
|
|
|
|
Pepco:
|
|
|
|
|
|
|
|
|
|
7.64%
|
|
2007
|
|
$
|
-
|
|
$
|
35.0
|
|
6.25%
|
|
2009
|
|
|
50.0
|
|
|
50.0
|
|
|
|
|
|
|
|
|
|
|
|
DPL:
|
|
|
|
|
|
|
|
|
|
7.06%
- 8.13%
|
|
2007
|
|
|
-
|
|
|
61.5
|
|
7.56%
- 7.58%
|
|
2017
|
|
|
14.0
|
|
|
14.0
|
|
6.81%
|
|
2018
|
|
|
4.0
|
|
|
4.0
|
|
7.61%
|
|
2019
|
|
|
12.0
|
|
|
12.0
|
|
7.72%
|
|
2027
|
|
|
10.0
|
|
|
10.0
|
|
|
|
|
|
|
|
|
|
|
|
ACE:
|
|
|
|
|
|
|
|
|
|
7.52%
|
|
2007
|
|
|
-
|
|
|
15.0
|
|
Total
Medium-Term Notes (unsecured)
|
|
|
|
$
|
90.0
|
|
$
|
201.5
|
|
|
|
|
|
|
|
|
|
|
|
Recourse
Debt
|
|
|
|
|
|
|
|
|
|
PCI:
|
|
|
|
|
|
|
|
|
|
6.59% - 6.69%
|
|
2014
|
|
$
|
11.1
|
|
$
|
11.1
|
|
7.62%
|
|
2007
|
|
|
-
|
|
|
34.3
|
|
7.40%
(a)
|
|
2008
|
|
|
92.0
|
|
|
92.0
|
|
Total
Recourse Debt
|
|
|
|
$
|
103.1
|
|
$
|
137.4
|
|
|
|
|
|
|
|
|
|
|
|
Notes
(secured)
|
|
|
|
|
|
|
|
|
|
Pepco
Energy Services:
|
|
|
|
|
|
|
|
|
|
7.85%
|
|
2017
|
|
$
|
10.0
|
|
$
|
9.9
|
|
|
|
|
|
|
|
|
|
|
|
Notes
(unsecured)
|
|
|
|
|
|
|
|
|
|
PHI:
|
|
|
|
|
|
|
|
|
|
5.50%
|
|
2007
|
|
$
|
-
|
|
$
|
500.0
|
|
Variable
|
|
2010
|
|
|
250.0
|
|
|
250.0
|
|
4.00%
|
|
2010
|
|
|
200.0
|
|
|
200.0
|
|
6.45%
|
|
2012
|
|
|
750.0
|
|
|
750.0
|
|
5.90%
|
|
2016
|
|
|
200.0
|
|
|
200.0
|
|
6.00%
|
|
2017
|
|
|
250.0
|
|
|
-
|
|
6.00%
|
|
2019
|
|
|
200.0
|
|
|
-
|
|
7.45%
|
|
2032
|
|
|
250.0
|
|
|
250.0
|
|
|
|
|
|
|
|
|
|
|
|
DPL:
|
|
|
|
|
|
|
|
|
|
5.00%
|
|
2014
|
|
|
100.0
|
|
|
100.0
|
|
5.00%
|
|
2015
|
|
|
100.0
|
|
|
100.0
|
|
5.22%
|
|
2016
|
|
|
100.0
|
|
|
100.0
|
|
Total
Notes (unsecured)
|
|
|
|
$
|
2,400.0
|
|
$
|
2,450.0
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
Debt
issued at a fixed rate of 8.24%. The debt was swapped into
variable rate debt at the time of
issuance.
|
NOTE: Schedule
is continued on next page.
|
|
|
|
|
|
At December
31,
|
|
Interest
Rate
|
|
Maturity
|
|
|
2007
|
|
|
2006
|
|
|
|
|
|
|
(Millions
of dollars)
|
|
|
|
|
|
|
|
|
|
|
|
Total
Long-Term Debt
|
|
|
|
$
|
4,473.8
|
|
$
|
4,598.7
|
|
Net
unamortized discount
|
|
|
|
|
(6.2)
|
|
|
(4.9)
|
|
Current
maturities of long-term debt
|
|
|
|
|
(292.8)
|
|
|
(825.2)
|
|
Total
Net Long-Term Debt
|
|
|
|
$
|
4,174.8
|
|
$
|
3,768.6
|
|
|
|
|
|
|
|
|
|
|
|
Transition
Bonds Issued by ACE Funding
|
|
|
|
|
|
|
|
|
|
2.89%
|
|
2010
|
|
$
|
13.2
|
|
$
|
34.5
|
|
2.89%
|
|
2011
|
|
|
14.4
|
|
|
23.0
|
|
4.21%
|
|
2013
|
|
|
66.0
|
|
|
66.0
|
|
4.46%
|
|
2016
|
|
|
52.0
|
|
|
52.0
|
|
4.91%
|
|
2017
|
|
|
118.0
|
|
|
118.0
|
|
5.05%
|
|
2020
|
|
|
54.0
|
|
|
54.0
|
|
5.55%
|
|
2023
|
|
|
147.0
|
|
|
147.0
|
|
Total
|
|
|
|
$
|
464.6
|
|
$
|
494.5
|
|
Net
unamortized discount
|
|
|
|
|
(.1)
|
|
|
(.2)
|
|
Current
maturities of long-term debt
|
|
|
|
|
(31.0)
|
|
|
(29.9)
|
|
Total
Transition Bonds issued by ACE Funding
|
|
|
|
$
|
433.5
|
|
$
|
464.4
|
The outstanding First Mortgage Bonds
issued by each of Pepco, DPL and ACE are secured by a lien on substantially all
of the issuing company’s property, plant and equipment.
ACE Funding was established in 2001
solely for the purpose of securitizing authorized portions of ACE’s recoverable
stranded costs through the issuance and sale of Transition Bonds. The
proceeds of the sale of each series of Transition Bonds have been transferred to
ACE in exchange for the transfer by ACE to ACE Funding of the right to collect a
non-bypassable transition bond charge from ACE customers pursuant to bondable
stranded costs rate orders issued by the NJBPU in an amount sufficient to fund
the principal and interest payments on the Transition Bonds and related taxes,
expenses and fees (Bondable Transition Property). The assets of ACE
Funding, including the Bondable Transition Property, and the Transition Bond
charges 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.
The aggregate amounts of maturities for
long-term debt and Transition Bonds outstanding at December 31, 2007, are $323.8
million in 2008, $82.2 million in 2009, $531.9 million in 2010, $69.9 million in
2011, $787.3 million in 2012, and $3,143.3 million thereafter.
PHI’s long-term debt is subject to
certain covenants. PHI and its subsidiaries are in compliance with
all requirements.
LONG-TERM
PROJECT FUNDING
As of December 31, 2007 and 2006, Pepco
Energy Services had outstanding total long-term project funding (including
current maturities) of $29.3 million and $25.7 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, 2007, are $8.4 million in 2008, $2.1 million in 2009, $2.0 million
in 2010, $1.7 million in 2011, $1.6 million in 2012, and $13.5 million
thereafter.
SHORT-TERM
DEBT
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
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 Holdings’ short-term debt at December 31, 2007 and 2006 is as
follows.
|
|
2007
|
2006
|
|
|
|
(Millions
of dollars)
|
|
|
Commercial
paper
|
$137.1
|
$195.4
|
|
|
Variable
rate demand bonds
|
151.7
|
154.2
|
|
|
Total
|
$288.8
|
$349.6
|
|
|
|
|
|
|
Commercial
Paper
Pepco Holdings maintains an ongoing
commercial paper program of up to $875 million. Pepco, DPL, and ACE
have ongoing commercial paper programs of up to $500 million, $275 million,
and $250 million, respectively. The commercial paper programs of
PHI, Pepco, DPL and ACE are backed by a $1.5 billion credit facility, which is
described under the heading “Credit Facility” below.
Pepco Holdings, Pepco, DPL and ACE had
zero, $84.0 million, $24.0 million and $29.1 million of commercial paper
outstanding at December 31, 2007, respectively. The weighted
average interest rate for Pepco Holdings, Pepco, DPL and ACE commercial paper
issued during 2007 was 5.58%, 5.27%, 5.35% and 5.45%
respectively. The weighted average maturity for Pepco Holdings,
Pepco, DPL and ACE was two, four, four, and three days respectively for all
commercial paper issued during 2007.
Variable Rate Demand
Bonds
Variable Rate Demand Bonds (“VRDB”) 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 the bonds submitted for purchase will
continue to be remarketed successfully due to the credit worthiness of the
issuing company and because the remarketing resets the interest rate to the
then-current market rate. The issuing company also may utilize one of
the fixed rate/fixed term conversion options of the bonds 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. The VRDBs outstanding at December 31, 2007 mature in
2008 to 2009 ($5.8 million), 2014 to 2017 ($48.6 million), 2024 ($33.3 million)
and 2028 to 2031 ($64 million). The weighted average interest rate
for VRDB was 3.79% during 2007 and 3.55% during 2006.
Credit
Facility
PHI, Pepco, DPL and ACE maintain a
credit facility to provide for their respective short-term liquidity
needs.
The aggregate borrowing limit under the
facility is $1.5 billion, all or any portion of which may be used to obtain
loans or to issue letters of credit. PHI’s credit limit under the facility is
$875 million. The credit limit of each of Pepco, DPL and ACE is the
lesser of $500 million and the maximum amount of debt the company is permitted
to have outstanding by its regulatory authorities, except that the aggregate
amount of credit used by Pepco, DPL and ACE at any given time collectively may
not exceed $625 million. The interest rate payable by each company on
utilized funds is based on the prevailing prime rate or Eurodollar rate, plus a
margin that varies according to the credit rating of the
borrower. 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 $150 million. Any swingline loan must be repaid
by the borrower within seven days of receipt thereof. All
indebtedness incurred under the facility is unsecured.
The facility commitment expiration date
is May 5, 2012, with each company having the right to elect to have 100% of the
principal balance of the loans outstanding on the expiration date continued as
non-revolving term loans for a period of one year from such expiration
date.
The facility is intended to serve
primarily as a source of liquidity to support the commercial paper programs of
the respective companies. The companies also are permitted to use the
facility to borrow funds for general corporate purposes and issue letters of
credit. In order for a borrower to use the facility, certain
representations and warranties made by the borrower at the time the credit
agreement was entered into also must be true at the time the facility is
utilized, and the borrower must be in compliance with specified covenants,
including the financial covenant described below. However, a material
adverse change in the borrower’s business, property, and results of operations
or financial condition subsequent to the entry into the credit agreement is not
a condition to the availability of credit under the facility. Among
the covenants to which each of the companies is subject are (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 certain trust preferred
securities and deferrable interest subordinated debt from the definition of
total indebtedness (not to exceed 15% of total capitalization), (ii) a
restriction on sales or other dispositions of assets, other than sales and
dispositions permitted by the credit agreement, and (iii) a restriction on the
incurrence of liens on the assets of a borrower or any of its significant
subsidiaries other than liens permitted by the credit agreement. The
agreement does not include any rating triggers.
(8) 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 as
part of Pepco’s acquisition of Conectiv on August 1, 2002. Under
this tax sharing agreement, PHI’s consolidated federal income tax liability is
allocated based upon PHI’s and its subsidiaries’ separate taxable income or
loss.
The provision for consolidated income
taxes, reconciliation of consolidated income tax expense, and components of
consolidated deferred tax liabilities (assets) are shown below.
Provision for Consolidated
Income Taxes
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
Operations
|
|
(Millions
of dollars)
|
|
|
Current
Tax Expense (Benefit)
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$ |
103.4 |
|
|
$ |
(77.5 |
) |
|
$ |
236.2 |
|
|
State
and local
|
|
|
5.0 |
|
|
|
- |
|
|
|
81.9 |
|
|
Total
Current Tax Expense (Benefit)
|
|
|
108.4 |
|
|
|
(77.5 |
) |
|
|
318.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred
Tax Expense (Benefit)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
82.2 |
|
|
|
202.8 |
|
|
|
(24.4 |
) |
|
State
and local
|
|
|
.5 |
|
|
|
40.8 |
|
|
|
(33.4 |
) |
|
Investment
tax credits
|
|
|
(3.2 |
) |
|
|
(4.7 |
) |
|
|
(5.1 |
) |
|
Total
Deferred Tax Expense (Benefit)
|
|
|
79.5 |
|
|
|
238.9 |
|
|
|
(62.9 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Income Tax Expense from Operations
|
|
|
187.9 |
|
|
|
161.4 |
|
|
|
255.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Extraordinary
Item
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred
Tax Expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
- |
|
|
|
- |
|
|
|
4.8 |
|
|
State
and local
|
|
|
- |
|
|
|
- |
|
|
|
1.4 |
|
|
Total
Deferred Tax on Extraordinary Item
|
|
|
- |
|
|
|
- |
|
|
|
6.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Consolidated Income Tax Expense
|
|
$ |
187.9 |
|
|
$ |
161.4 |
|
|
$ |
261.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of
Consolidated Income Tax Expense
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
|
|
Amount
|
|
|
Rate
|
|
|
Amount
|
|
|
Rate
|
|
|
Amount
|
|
|
Rate
|
|
|
|
|
(Millions
of dollars)
|
|
|
Income
Before Income Taxes and
Extraordinary
Item
|
|
$ |
522.1 |
|
|
|
|
|
$ |
409.7 |
|
|
|
|
|
$ |
617.4 |
|
|
|
|
|
Preferred
Dividends
|
|
|
.3 |
|
|
|
|
|
|
1.2 |
|
|
|
|
|
|
2.5 |
|
|
|
|
|
Income
Before Preferred Dividends,
Income
Taxes and Extraordinary Item
|
|
$ |
522.4 |
|
|
|
|
|
$ |
410.9 |
|
|
|
|
|
$ |
619.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
tax at federal statutory rate
|
|
$ |
182.8 |
|
|
|
35
|
% |
|
$ |
143.8 |
|
|
|
35 |
% |
|
$ |
217.1 |
|
|
|
35 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increases
(decreases) resulting from
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation
method and plant basis differences
|
|
|
9.5 |
|
|
|
2 |
|
|
|
7.9 |
|
|
|
2 |
|
|
|
9.7 |
|
|
|
1 |
|
|
State
income taxes, net of federal effect
|
|
|
22.6 |
|
|
|
4 |
|
|
|
25.6 |
|
|
|
6 |
|
|
|
30.8 |
|
|
|
5 |
|
|
Tax
credits
|
|
|
(2.8 |
) |
|
|
(1 |
) |
|
|
(4.7 |
) |
|
|
(1 |
) |
|
|
(4.7
|
) |
|
|
(1 |
) |
|
Maryland
State refund, net of federal effect
|
|
|
(19.5 |
) |
|
|
(4 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Leveraged
leases
|
|
|
(7.4 |
) |
|
|
(1 |
) |
|
|
(9.3 |
) |
|
|
(2 |
) |
|
|
(7.8
|
) |
|
|
(1 |
) |
|
Change
in estimates related to
prior
year tax liabilities
|
|
|
4.8 |
|
|
|
1 |
|
|
|
2.6 |
|
|
|
- |
|
|
|
17.9 |
|
|
|
3 |
|
|
Deferred
tax basis adjustment
|
|
|
4.1 |
|
|
|
1 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Other,
net
|
|
|
(6.2 |
) |
|
|
(1 |
) |
|
|
(4.5 |
) |
|
|
(1 |
) |
|
|
(7.8
|
) |
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Consolidated Income Tax Expense from Operations
|
|
$ |
187.9 |
|
|
|
36 |
% |
|
$ |
161.4 |
|
|
|
39 |
% |
|
$ |
255.2 |
|
|
|
41 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FIN 48, “Accounting for
Uncertainty in Income Taxes”
As disclosed in Note 2, “Summary of
Significant Accounting Policies”, PHI adopted FIN 48 effective January 1,
2007. Upon adoption, PHI recorded the cumulative effect
of
the
change in accounting principle of $7.4 million as a decrease in retained
earnings. Also upon adoption, PHI had $186.9 million
of unrecognized tax benefits and $24.3 million of related accrued
interest.
Reconciliation of Beginning and Ending
Balances of Unrecognized Tax Benefits
|
|
$
|
186.9
|
|
Tax
positions related to current year:
|
|
|
|
Additions
|
|
37.5
|
|
Reductions
|
|
(1.1)
|
|
Tax
positions related to prior years:
|
|
|
|
Additions
|
|
112.5
|
|
Reductions
|
|
(13.3)
|
|
Settlements
|
|
(47.1)
|
|
|
$
|
275.4
|
|
|
|
|
As of December 31, 2007, PHI had $26.4
million of accrued interest related to unrecognized tax benefits.
Unrecognized Benefits That If
Recognized Would Affect the Effective Tax Rate
Unrecognized tax benefits represent
those tax benefits 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, in accordance with FIN 48, 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, 2007, included $11.2 million that, if recognized, would
lower the effective tax rate.
PHI recognizes interest and penalties
relating to its unrecognized tax benefits as an element of tax
expense. For the year ended December 31, 2007, PHI recognized $2.1
million of interest expense and penalties, net, as a component of tax
expense.
Possible Changes to Unrecognized
Benefits
Total unrecognized tax benefits that
may change over the next twelve months include the matter of Mixed Service
Costs. See discussion in Note 12, “Commitments and Contingencies --
IRS Mixed Service Cost Issue.”
Tax Years Open to
Examination
PHI and the majority of its
subsidiaries file a consolidated federal income tax return. PHI’s
federal income tax liabilities for Pepco legacy companies for all years through
2000, and for Conectiv legacy companies for all years through 1999, 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. 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 noted above.
Components of Consolidated
Deferred Tax Liabilities (Assets)
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
|
(Millions
of dollars)
|
|
Deferred
Tax Liabilities (Assets)
|
|
|
|
|
|
|
|
|
|
Depreciation
and other book-to-tax basis differences
|
|
$
|
1,732.3
|
|
|
$
|
1,774.6
|
|
|
Deferred
taxes on amounts to be collected through future rates
|
|
|
53.1
|
|
|
|
43.0
|
|
|
Deferred
investment tax credits
|
|
|
(17.2
|
)
|
|
|
(23.4
|
)
|
|
Contributions
in aid of construction
|
|
|
(52.6
|
)
|
|
|
(60.5
|
)
|
|
Goodwill
and fair value adjustments
|
|
|
(107.0
|
)
|
|
|
(187.1
|
)
|
|
Deferred
electric service and electric restructuring liabilities
|
|
|
(74.2
|
)
|
|
|
(58.6
|
)
|
|
Finance
and operating leases
|
|
|
699.1
|
|
|
|
607.6
|
|
|
Contracts
with NUGs
|
|
|
67.8
|
|
|
|
72.6
|
|
|
Fuel
and purchased energy
|
|
|
(94.8
|
)
|
|
|
(38.6
|
)
|
|
Property
taxes
|
|
|
(45.0
|
)
|
|
|
(63.3
|
)
|
|
State
net operating loss
|
|
|
(55.7
|
)
|
|
|
(45.5
|
)
|
|
Valuation
allowance on state net operating loss
|
|
|
36.4
|
|
|
|
29.5
|
|
|
Pension
and other postretirement benefits
|
|
|
55.7
|
|
|
|
64.1
|
|
|
Unrealized
losses on fair value declines
|
|
|
(13.0
|
)
|
|
|
(1.7
|
)
|
|
Other
|
|
|
(103.6
|
)
|
|
|
(53.1
|
)
|
|
Total
Deferred Tax Liabilities, Net
|
|
|
2,081.3
|
|
|
|
2,059.6
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred
tax assets included in Other Current Assets
|
|
|
25.3
|
|
|
|
25.3
|
|
|
Deferred
tax liabilities included in Other Current Liabilities
|
|
|
(1.5
|
)
|
|
|
(.9
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Total
Consolidated Deferred Tax Liabilities, Net Non-Current
|
|
$
|
2,105.1
|
|
|
$
|
2,084.0
|
|
|
|
|
|
|
|
|
|
|
|
The net deferred tax liability
represents the tax effect, at presently enacted tax rates, of temporary
differences between the financial statement and tax basis of assets and
liabilities. The portion of the net deferred tax liability applicable to PHI’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.
The Tax Reform Act of 1986 repealed the
Investment Tax Credit (ITC) for property placed in service after December 31,
1985, except for certain transition property. ITC previously earned on Pepco’s,
DPL’s and ACE’s property continues to be normalized over the remaining service
lives of the related assets.
Resolution of Certain
Internal Revenue Service Audit Matters
In 2006, PHI resolved certain, but not
all, tax matters that were raised in Internal Revenue Service audits related to
the 2001 and 2002 tax years. Adjustments recorded related to these
resolved tax matters resulted in a $6.3 million increase in net income ($2.5
million for Power Delivery and $5.4 million for Other Non-Regulated, partially
offset by an unfavorable $1.6 million impact in Corp. &
Other). To the extent that the matters resolved related to tax
contingencies from the Conectiv legacy companies that existed at the August 2002
merger date, in accordance with accounting rules, an additional adjustment of
$9.1 million ($3.1 million
related
to Power Delivery and $6.0 million related to Other Non-Regulated) was recorded
in Corp. & Other to eliminate the tax benefits recorded by Power Delivery
and Other Non-Regulated against the goodwill balance that resulted from the
merger. Also during 2006, the total favorable impact of $2.6 million
was recorded that resulted from changes in estimates related to prior year tax
liabilities subject to audit ($4.1 million for Power Delivery, partially offset
by an unfavorable $1.5 million for Corp. & Other).
Non Financial Lease
Asset
The IRS, as part of its normal audit of
PCI’s income tax returns, questioned whether PCI is entitled to certain ongoing
tax deductions being taken by PCI as a result of the adoption by PCI of a
carry-over tax basis for a non-lease financial asset acquired in 1998 by a
subsidiary of PCI. On December 14, 2004, PCI and the IRS agreed to a
Notice of Proposed Adjustment settling this and certain other tax
matters. This settlement resulted in a cash payment in February 2006
for additional taxes and interest of approximately $22.8 million associated with
the examination of PCI’s 2001-2002 tax returns and an anticipated refund of
taxes and interest of approximately $7.1 million when the examination of PCI’s
2003 return is completed. In addition, in the fourth quarter of 2004,
PCI took a tax charge to earnings of approximately $19.7 million for financial
reporting purposes related to this matter. The charge consisted of
approximately $16.3 million to reflect the reversal of tax benefits recognized
by PCI prior to September 30, 2004, and approximately $3.4 million of interest
on the additional taxes. During 2006 and 2005, PCI recorded tax
charges to earnings of approximately $.1 million and $.9 million, respectively,
for interest on the additional taxes.
Taxes Other Than Income
Taxes
Taxes other than income taxes for each
year are shown below. The total amounts below include $348.2 million,
$332.9 million, and $333.4 million, for the years ended December 31, 2007,
2006, and 2005, respectively, related to the Power Delivery Business, which are
recoverable through rates.
|
|
2007
|
2006
|
2005
|
|
|
(Millions
of dollars)
|
|
Gross
Receipts/Delivery
|
$146.5
|
$149.1
|
$148.3
|
|
Property
|
63.5
|
62.7
|
60.4
|
|
County
Fuel and Energy
|
88.4
|
84.3
|
89.0
|
|
Environmental,
Use and Other
|
58.7
|
46.9
|
44.5
|
|
Total
|
$357.1
|
$343.0
|
$342.2
|
|
|
|
|
|
(9) MINORITY
INTEREST
The outstanding preferred stock issued
by subsidiaries of PHI as of December 31, 2007 and 2006 consisted of the
following. The shares of each of these series are redeemable solely
at the option of the issuer.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Redemption
|
|
Shares
Outstanding
|
|
December
31,
|
| Serial Preferred
Stock |
|
Price
|
|
2007
|
|
2006
|
|
2007
|
2006
|
|
|
|
|
|
|
|
|
|
|
|
(Millions
of dollars)
|
|
DPL (a)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4.0%
Series of 1943, $100 per share par value
|
|
$105.00
|
|
-
|
|
19,809
|
|
$
|
-
|
|
$
|
2.0
|
|
|
|
|
3.7%
Series of 1947, $100 per share par value
|
|
$104.00
|
|
-
|
|
39,866
|
|
|
-
|
|
|
4.0
|
|
|
|
|
4.28%
Series of 1949, $100 per share par value
|
|
$104.00
|
|
-
|
|
28,460
|
|
|
-
|
|
|
2.8
|
|
|
|
|
4.56%
Series of 1952, $100 per share par value
|
|
$105.00
|
|
-
|
|
19,571
|
|
|
-
|
|
|
2.0
|
|
|
|
|
4.20%
Series of 1955, $100 per share par value
|
|
$103.00
|
|
-
|
|
25,404
|
|
|
-
|
|
|
2.5
|
|
|
|
|
5.0%
Series of 1956, $100 per share par value
|
|
$104.00
|
|
-
|
|
48,588
|
|
|
-
|
|
|
4.9
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
-
|
|
$
|
18.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ACE
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4.0%
Series of 1944, $100 per share par value
|
|
$105.50
|
|
24,268
|
|
24,268
|
|
$
|
2.4
|
|
$
|
2.4
|
|
|
|
|
4.35%
Series of 1949, $100 per share par value
|
|
$101.00
|
|
2,942
|
|
2,942
|
|
|
.3
|
|
|
.3
|
|
|
|
|
4.35%
Series of 1953, $100 per share par value
|
|
$101.00
|
|
1,680
|
|
1,680
|
|
|
.2
|
|
|
.2
|
|
|
|
|
4.10%
Series of 1954, $100 per share par value
|
|
$101.00
|
|
20,504
|
|
20,504
|
|
|
2.0
|
|
|
2.0
|
|
|
|
|
4.75%
Series of 1958, $100 per share par value
|
|
$101.00
|
|
8,631
|
|
8,631
|
|
|
.9
|
|
|
.9
|
|
|
|
|
5.0%
Series of 1960, $100 per share par value
|
|
$100.00
|
|
4,120
|
|
4,120
|
|
|
.4
|
|
|
.4
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
6.2
|
|
$
|
6.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Preferred Stock of Subsidiaries
|
|
|
|
|
|
|
|
$
|
6.2
|
|
$
|
24.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
On
January 18, 2007, DPL redeemed all of the outstanding shares of its
preferred stock, with an aggregate par value of $18.9 million, at prices
ranging from 103% to 105% of par.
|
|
(10)
|
STOCK-BASED
COMPENSATION, DIVIDEND RESTRICTIONS, AND CALCULATIONS OF EARNINGS PER
SHARE OF COMMON STOCK
|
Stock-Based
Compensation
PHI maintains a Long-Term Incentive
Plan (LTIP), the objective of which is to increase shareholder value by
providing a long-term incentive to reward officers, key employees, and directors
of Pepco Holdings and its subsidiaries and to increase the ownership of Pepco
Holdings’ common stock by such individuals. Any officer or key employee of Pepco
Holdings or its subsidiaries may be designated by the Board as a participant in
the LTIP. Under the LTIP, awards to officers and key employees may be in the
form of restricted stock, options, performance units, stock appreciation rights,
and dividend equivalents. Up to 10,100,000 shares of common stock initially were
available for issuance under the LTIP over a period of 10 years commencing
August 1, 2002.
Total stock-based compensation expense
recorded in the Consolidated Statements of Earnings for the years ended December
31, 2007, 2006, and 2005 is $4.3 million, $5.8 million, and $4.4 million,
respectively. For the years ended December 31, 2007, 2006, and 2005,
$1.9 million, $.1 million, and zero, respectively, in tax benefits were
recognized in relation to stock-based compensation costs of stock
awards. No compensation costs related to restricted stock grants were
capitalized for the years ended December 31, 2007, 2006 and 2005.
PHI recognizes compensation expense
related to Performance Restricted Stock Awards based on the fair value of the
awards at date of grant. PHI estimates the fair value of market
condition awards using a Monte Carlo simulation model, in a risk-neutral
framework, based on the following assumptions:
|
|
Performance
Period
|
|
|
|
2004-2006
|
2005-2007
|
|
|
Risk-free
interest rate (%)
|
2.11
|
3.37
|
|
|
Peer
volatilities (%)
|
16.3
- 62.5
|
15.5
- 60.1
|
|
|
Peer
correlations
|
0.13
- 0.69
|
0.15
- 0.72
|
|
|
Fair
value of restricted share
|
$24.06
|
$26.92
|
|
Prior to acquisition of Conectiv by
Pepco, each company had a long-term incentive plan under which stock options
were granted. At the time of the acquisition, certain Conectiv options vested
and were canceled in exchange for a cash payment. Certain other Conectiv options
were exchanged on a 1 for 1.28205 basis for Pepco Holdings stock options under
the LTIP: 590,198 Conectiv stock options were converted into 756,660 Pepco
Holdings stock options. The Conectiv stock options were originally granted on
January 1, 1998, January 1, 1999, July 1, 1999, October 18, 2000, and
January 1, 2002, in each case with an exercise price equal to the market price
(fair value) of the Conectiv stock on the date of the grant. The
exercise prices of these options, after adjustment to give effect to the
conversion ratio of Conectiv stock for Pepco Holdings stock, are $17.81, $18.91,
$19.30, $13.08 and $19.03, respectively. All of the Pepco Holdings
options received in exchange for the Conectiv options are
exercisable.
At the time of the acquisition of
Conectiv by Pepco, outstanding Pepco options were exchanged on a one-for-one
basis for Pepco Holdings stock options granted under the LTIP. The
options were originally granted under Pepco’s long-term incentive plan in May
1998, May 1999, January 2000, May 2000, January 2001, May 2001, January 2002,
and May 2002. The exercise prices of the options are $24.3125, $29.78125,
$22.4375, $23.15625, $24.59, $21.825, $22.57 and $22.685, respectively, which
represent the market prices (fair values) of the Pepco common stock on its
original grant dates. All the options granted are exercisable.
Stock option activity for the three
years ended December 31 is summarized below. The information
presented in the table is for Pepco Holdings, including converted Pepco and
Conectiv options.
|
|
|
2007
|
|
2006
|
|
2005
|
|
|
|
|
Number
of
Options
|
|
|
Weighted
Average Price
|
|
Number
of
Options
|
|
|
Weighted
Average Price
|
|
Number
of
Options
|
|
|
Weighted
Average
Price
|
|
|
Beginning-of-year
balance
|
|
1,130,724
|
|
$
|
22.5099
|
|
1,864,250
|
|
$
|
22.1944
|
|
2,063,754
|
|
$
|
21.8841
|
|
|
Options
exercised
|
|
591,089
|
|
$
|
22.6139
|
|
733,526
|
|
$
|
21.7081
|
|
196,299
|
|
$
|
18.9834
|
|
|
Options
forfeited
|
|
-
|
|
$
|
-
|
|
-
|
|
$
|
-
|
|
3,205
|
|
$
|
19.0300
|
|
|
Options
lapsed
|
|
7,000
|
|
$
|
26.3259
|
|
-
|
|
$
|
-
|
|
-
|
|
$
|
-
|
|
|
End-of-year
balance
|
|
532,635
|
|
$
|
22.3443
|
|
1,130,724
|
|
$
|
22.5099
|
|
1,864,250
|
|
$
|
22.1944
|
|
|
Exercisable
at end of year
|
|
532,635
|
|
$
|
22.3443
|
|
1,130,724
|
|
$
|
22.5099
|
|
1,814,350
|
|
$
|
22.1840
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
All stock options have an expiration
date of ten years from the date of grant.
The aggregate intrinsic value of stock
options outstanding and exercisable at December 31, 2007, 2006, and 2005
was $3.8 million, $4.1 million, and $.1 million, respectively.
The total intrinsic value of stock
options exercised during the years ended December 31, 2007, 2006, and 2005
was $3.0 million, $2.2 million, and $.8 million, respectively. For
the years ended December 31, 2007, 2006, and 2005, $1.2 million, $.9 million,
and $.3 million, respectively, in tax benefits were recognized in relation to
stock-based compensation costs of stock options.
As of December 31, 2007, an analysis of
options outstanding by exercise prices is as follows:
|
Range
of
Exercise
Prices
|
Number
Outstanding
and
Exercisable at
|
Weighted
Average
Exercise
Price
|
Weighted
Average
Remaining
Contractual
Life (in Years)
|
|
$13.08
to $19.30
|
161,147
|
$18.4856
|
4.4
|
|
$21.83
to $29.78
|
371,488
|
$24.0181
|
2.4
|
|
$13.08
to $29.78
|
532,635
|
$22.3443
|
3.0
|
|
|
|
|
|
Prior to the adoption of SFAS No. 123R
on January 1, 2006, Pepco Holdings recognized compensation costs for the
LTIP based on the accounting prescribed by APB No. 25, “Accounting for Stock
Issued to Employees.” There were no stock-based employee compensation
costs charged to expense in 2007, 2006 and 2005 with respect to stock options
granted under the LTIP.
There were no options granted in 2007,
2006, or 2005.
The Performance Restricted Stock
Program and the Merger Integration Success Program have been established under
the LTIP. Under the Performance Restricted Stock Program, performance
criteria are selected and measured over a three-year period. The
target number of share award opportunities established in 2007, 2006 and 2005
under Pepco Holdings’ Performance Restricted Stock Program for performance
periods 2007-2009, 2006-2008, and 2005-2007 were 190,657, 218,108, and 247,400,
respectively. Additionally, beginning in 2006, time-restricted share
award opportunities with a requisite service period of three years were
established under the LTIP. The target number of share award
opportunities for these awards was 95,314 for the 2007-2009 time period and
109,057 for the 2006-2008 time period. The fair value per share on
award date for the performance restricted stock was $25.54 for the 2007-2009
award, $23.28 for the 2006-2008 award, and $26.92 for the 2005-2007
award. Depending on the extent to which the performance criteria are
satisfied, the executives are eligible to earn shares of common stock and
dividends accrued thereon over the vesting period, under the Performance
Restricted Stock Program ranging from 0% to 200% of the target share award
opportunities, inclusive of dividends accrued. There were 418,426
awards earned with respect to the 2004-2006 share award
opportunity.
The maximum number of share award
opportunities granted under the Merger Integration Success Program during 2002
was 241,075. The fair value per share on grant date was $19.735. Of those
shares, 96,427 were restricted and vested over three years: 20% vested in 2003,
30% vested in 2004, and 50% vested in 2005. The remaining 144,648 shares were
performance-based award opportunities that could have been earned based on the
extent to which operating
efficiencies
and expense reduction goals were attained through December 31, 2003 and 2004,
respectively. Although the goals were met in 2003, it was determined
that 63,943 shares, including shares reallocated from participants who did not
meet performance goals as well as shares reflecting accrued dividends for the
period August 1, 2002 to December 31, 2003, granted to certain
executives, would not vest until 2005, and then only if the cost reduction goals
were maintained and Pepco Holdings’ financial performance were
satisfactory. A total of 9,277 shares of common stock vested under
this program on December 31, 2003 for other eligible employees. On
March 11, 2005, 70,315 shares, including reinvested dividends, vested for the
performance period ending on December 31, 2004. A total of
44,644 shares, including reinvested dividends, vested on March 7, 2006, for the
original performance period ended December 31, 2003, that was extended to
December 31, 2005.
Under the LTIP, non-employee directors
are entitled 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 has determined that these grants will not be made.
On August 1, 2002, the date of the
acquisition of Conectiv by Pepco, in accordance with the terms of the merger
agreement, 80,602 shares of Conectiv performance accelerated restricted stock
(PARS) were converted to 103,336 shares of Pepco Holdings restricted
stock. The PARS were originally granted on January 1, 2002 at a fair
market price of $24.40. All of the converted restricted stock has
time-based vesting over periods ranging from 5 to 7 years from the original
grant date. As of December 31, 2007, 96,026 converted shares
have vested and 7,310 shares remain unvested.
In June 2003, the President and Chief
Executive Officer of PHI received a retention award in the form of 14,822 shares
of restricted stock. The shares vested on June 1, 2006.
In September 2007, retention awards in
the form of 9,015 shares of restricted stock were granted to certain PHI
executives, with vesting periods of two to three years.
The 2007 activity for non-vested share
opportunities is summarized below. The information presented in the
table is for Pepco Holdings, including Conectiv PARS converted to Pepco Holdings
restricted stock.
|
|
|
|
Number
of
Shares
|
|
Weighted
Average
Grant Date Fair Value
|
|
|
|
|
|
728,769
|
|
|
$24.588
|
|
|
Granted
|
|
|
300,099
|
|
|
25.642
|
|
|
Additional
performance shares granted
|
|
|
169,654
|
|
|
24.060
|
|
|
Vested
|
|
|
(418,689)
|
|
|
(24.057)
|
|
|
Forfeited
|
|
|
(18,851)
|
|
|
(24.323)
|
|
|
|
|
|
760,982
|
|
|
25.185
|
|
|
|
|
|
|
|
|
|
|
The total fair value of restricted
stock awards vested during the years ended December 31, 2007, 2006, and
2005 was $10.1 million, $2.0 million, and $2.7 million,
respectively.
As of December 31, 2007, there was
approximately $5.4 million of unrecognized compensation cost (net of estimated
forfeitures) related to non-vested stock granted under the
plans. That
cost is expected to be recognized over a weighted-average period of
approximately two years.
Dividend
Restrictions
PHI 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 and regulatory laws, which impose limitations on the funds that can be
used to pay dividends and, in the case of regulatory laws, as applicable, may
require the prior approval of the relevant utility regulatory commissions before
dividends can be paid; (ii) the prior rights of holders of existing and future
preferred stock, 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 and DPL have no shares of preferred
stock outstanding. Currently, the restriction in the ACE charter does
not limit its ability to pay dividends. Restricted net assets related
to PHI’s consolidated subsidiaries amounted to approximately $1.8 billion at
December 31, 2007 and $1.9 billion at December 31, 2006. PHI had
no restricted retained earnings or restricted net income at December 31, 2007
and 2006.
For the years ended December 31,
2007, 2006, and 2005, Pepco Holdings recorded dividends from its subsidiaries as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
Subsidiary
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
|
(Millions
of dollars)
|
|
|
Pepco
|
|
$ |
86.0 |
|
|
$ |
99.0 |
|
|
$ |
62.9 |
|
|
DPL
|
|
|
39.0 |
|
|
|
15.0 |
|
|
|
36.4 |
|
|
ACE
|
|
|
50.0 |
|
|
|
109.0 |
|
|
|
95.9 |
|
|
Conectiv
Energy
|
|
|
- |
|
|
|
- |
|
|
|
50.0 |
|
|
|
|
$ |
175.0 |
|
|
$ |
223.0 |
|
|
$ |
245.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Directors’ Deferred
Compensation
Under the Pepco Holdings’ Executive and
Director Deferred Compensation Plan, Pepco Holdings directors may elect to defer
all or part of their retainer or meeting fees that constitute normal
compensation. Deferred retainer or meeting fees can be invested in
phantom Pepco Holdings shares and earn dividends as well as appreciation equal
to the amount of increase in fair value of the phantom shares. The
ultimate payout is in cash. The amount deferred and invested in
phantom Pepco Holdings shares in the years ended December 31, 2007, 2006
and 2005 was $.2 million, $.1 million and $.1 million,
respectively.
Compensation recognized in respect of
dividends and increase in fair value in the years ended December 31, 2007,
2006 and 2005 was $.3 million, $.3 million and $.1 million,
respectively. The balance of deferred compensation invested in
phantom Pepco Holdings’ shares at December 31, 2007 and 2006 was $2.2
million and $1.8 million.
Calculations of Earnings per
Share of Common Stock
Reconciliations of the numerator and
denominator for basic and diluted earnings per share of common stock
calculations are shown below.
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
|
|
|
(Millions
of dollars, except share data)
|
|
|
Income
(Numerator):
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
Income
|
|
$
|
334.2
|
|
|
$
|
248.3
|
|
$
|
371.2
|
|
|
Add: Loss
on redemption of subsidiary’s preferred stock
|
|
|
(.6)
|
|
|
|
(.8)
|
|
|
(.1)
|
|
|
Earnings
Applicable to Common Stock
|
|
$
|
333.6
|
|
|
$
|
247.5
|
|
$
|
371.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares
(Denominator):
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
average shares outstanding for basic computation:
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
shares outstanding
|
|
|
194.1
|
|
|
|
190.7
|
|
|
189.0
|
|
|
Adjustment
to shares outstanding
|
|
|
(.2)
|
|
|
|
(.1)
|
|
|
(.1)
|
|
|
Weighted
Average Shares Outstanding for Computation of
Basic
Earnings Per Share of Common Stock
|
|
|
193.9
|
|
|
|
190.6
|
|
|
188.9
|
|
|
Weighted
average shares outstanding for diluted computation: (a)
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
shares outstanding
|
|
|
194.1
|
|
|
|
190.7
|
|
|
189.0
|
|
|
Adjustment
to shares outstanding
|
|
|
.4
|
|
|
|
.4
|
|
|
.2
|
|
|
Weighted
Average Shares Outstanding for Computation of
Diluted
Earnings Per Share of Common Stock
|
|
|
194.5
|
|
|
|
191.1
|
|
|
189.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
earnings per share of common stock
|
|
$
|
1.72
|
|
|
$
|
1.30
|
|
$
|
1.96
|
|
|
Diluted
earnings per share of common stock
|
|
$
|
1.72
|
|
|
$
|
1.30
|
|
$
|
1.96
|
|
|
(a)
|
Approximately zero, .6 million,
and 1.4 million for the years ended December 31, 2007, 2006 and 2005,
respectively, related to options to purchase common stock with exercise
prices between $22.44 and $29.78 per share, have been excluded from the
calculation of diluted EPS as they are considered to be
anti-dilutive.
|
Shareholder Dividend
Reinvestment Plan
PHI maintains a Shareholder Dividend
Reinvestment Plan (DRP) through which shareholders may reinvest cash dividends
and both existing shareholders and new investors 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 original issue shares or, at the election of PHI, shares
purchased in the open market. There were 979,155, 1,232,569, and
1,228,505 original issue shares sold under the DRP in 2007, 2006 and 2005,
respectively.
Pepco Holdings Common Stock
Reserved and Unissued
The following table presents Pepco
Holdings’ common stock reserved and unissued at December 31, 2007:
|
Name
of Plan
|
|
Number
of
Shares
|
|
|
DRP
|
|
2,734,400
|
|
|
Conectiv
Incentive Compensation Plan
(a)
|
|
1,231,900
|
|
|
Potomac
Electric Power Company Long-Term Incentive Plan (a)
|
|
412,547
|
|
|
Pepco
Holdings, Inc. Long-Term Incentive Plan
|
|
9,117,365
|
|
|
Pepco
Holdings, Inc. Non-Management Directors Compensation Plan
|
|
495,731
|
|
|
Pepco
Holdings, Inc. Savings Plan (b)
|
|
5,045,000
|
|
|
Total
|
|
19,036,943
|
|
|
|
|
|
|
|
|
(a)
|
No
further awards will be made under this
plan.
|
|
|
(b)
|
Effective
January 30, 2006, Pepco Holdings established the Pepco Holdings, Inc.
Retirement Savings Plan which is an amalgam of, and a successor to, (i)
the Potomac Electric Power Company Savings Plan for Bargaining Unit
Employees, (ii) the Potomac Electric Power Company Retirement Savings Plan
for Management Employees (which resulted from the merger, effective
January 1, 2005, of the Potomac Electric Power Company Savings Plan
for Non-Bargaining Unit, Non-Exempt Employees and the Potomac Electric
Power Company Savings Plan for Exempt Employees), (iii) the Conectiv
Savings and Investment Plan, and (iv) the Atlantic City Electric 401(k)
Savings and Investment Plan - B.
|
(11) FAIR VALUES OF FINANCIAL
INSTRUMENTS
The estimated fair values of Pepco
Holdings’ financial instruments at December 31, 2007 and 2006 are shown
below.
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
|
|
(Millions
of dollars)
|
|
|
|
|
Carrying
Amount
|
|
Fair
Value
|
|
|
Carrying
Amount
|
|
Fair
Value
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
Derivative
Instruments
|
|
$
|
81.9
|
$
|
81.9
|
|
$
|
123.7
|
$
|
123.7
|
|
Liabilities
and Capitalization
|
|
|
|
|
|
|
|
|
|
|
|
Long-Term
Debt
|
|
$
|
4,467.6
|
$
|
4,450.6
|
|
$
|
4,593.8
|
$
|
4,629.6
|
|
Transition
Bonds issued by ACE Funding
|
|
$
|
464.5
|
$
|
462.0
|
|
$
|
494.3
|
$
|
491.4
|
|
Derivative
Instruments
|
|
$
|
63.8
|
$
|
63.8
|
|
$
|
186.8
|
$
|
186.8
|
|
Long-Term
Project Funding
|
|
$
|
29.3
|
$
|
29.3
|
|
$
|
25.7
|
$
|
25.7
|
|
Redeemable
Serial Preferred Stock
|
|
$
|
6.2
|
$
|
4.4
|
|
$
|
24.4
|
$
|
21.7
|
The methods and assumptions described
below were used to estimate, at December 31, 2007 and 2006, the fair value of
each class of financial instruments shown above for which it is practicable to
estimate a value.
The fair values of derivative
instruments were derived based on quoted market prices where available or, for
instruments that are not traded on an exchange, based on information obtained
from over-the-counter brokers, industry services, or multiple-party on-line
platforms. For some custom and complex instruments, an internal model is used to
interpolate available price information.
Long-Term Debt includes recourse and
non-recourse debt issued by PCI. The fair values of this PCI debt,
including amounts due within one year, were based on current rates offered to
similar companies for debt with similar remaining maturities. The
fair values of all other Long-Term Debt and Transition Bonds issued by ACE
Funding, including amounts due within one year, were derived based on current
market prices, or for issues with no market price available, were based on
discounted cash flows using current rates for similar issues with similar terms
and remaining maturities.
The fair value of the Redeemable Serial
Preferred Stock, excluding amounts due within one year, was derived based on
quoted market prices or discounted cash flows using current rates of preferred
stock with similar terms.
The carrying amounts of all other
financial instruments in Pepco Holdings’ accompanying financial statements
approximate fair value.
(12) COMMITMENTS AND
CONTINGENCIES
REGULATORY
AND OTHER MATTERS
Proceeds
from Settlement of Mirant Bankruptcy Claims
In 2000, Pepco sold substantially all
of its electricity generating assets to Mirant. In 2003, Mirant
commenced a voluntary bankruptcy proceeding in which it sought to reject certain
obligations that it had undertaken in connection with the asset
sale. As part of the asset sale, Pepco entered into transition power
agreements with Mirant pursuant to which Mirant agreed to supply all of the
energy and capacity needed by Pepco to fulfill its SOS obligations in Maryland
and in the District of Columbia (the TPAs). Under a settlement to
avoid the rejection by Mirant of its obligations under the TPAs in the
bankruptcy proceeding, the terms of the TPAs were modified to increase the
purchase price of the energy and capacity supplied by Mirant and Pepco received
an allowed, pre-petition general unsecured claim in the bankruptcy in the amount
of $105 million (the TPA Claim). In December 2005, Pepco sold
the TPA Claim, plus the right to receive accrued interest thereon, to an
unaffiliated third party for $112.5 million. In addition, Pepco
received proceeds of $.5 million in settlement of an asbestos claim against
the Mirant bankruptcy estate. After customer sharing, Pepco recorded
a pre-tax gain of $70.5 million from the settlement of these
claims.
In connection with the asset sale,
Pepco and Mirant also entered into a “back-to-back” arrangement, whereby Mirant
agreed to purchase from Pepco the 230 megawatts of electricity and capacity that
Pepco is obligated to purchase annually through 2021 from Panda under the Panda
PPA at the purchase price Pepco is obligated to pay to Panda. As part
of the further settlement of Pepco’s claims against Mirant arising from the
Mirant bankruptcy, Pepco agreed not to contest the rejection by Mirant of its
obligations under the “back-to-back” arrangement in exchange for the payment by
Mirant of damages corresponding to the estimated amount by which the purchase
price that Pepco is obligated to pay Panda for the energy and capacity exceeded
the market price. In 2007, Pepco received as damages
$413.9 million in net proceeds from the sale of shares of Mirant common
stock issued to it by Mirant. These funds are being accounted for as
restricted cash based on management’s intent to use such funds, and any interest
earned thereon, for the sole purpose of paying for the future above-market
capacity and energy purchase costs under the Panda
PPA. Correspondingly, a regulatory liability has been established in
the same amount to help offset the future above-market capacity and
energy
purchase
costs. This restricted cash has been classified as a non-current
asset to be consistent with the classification of the non-current regulatory
liability, and any changes in the balance of this restricted cash, including
interest on the invested funds, are being accounted for as operating cash
flows.
As of December 31, 2007, the balance of
the restricted cash account was $417.3 million. Based on a
reexamination of the costs of the Panda PPA in light of current and projected
wholesale market conditions conducted in the fourth quarter of 2007, Pepco
determined that, principally due to increases in wholesale capacity prices, the
present value above-market cost of the
Panda PPA over the term of the agreement is expected to be significantly less than
the current amount of the restricted cash account
balance. Accordingly, on February 22, 2008, Pepco filed applications
with the DCPSC and the MPSC requesting orders directing Pepco to maintain
$320 million in the restricted cash account and to use that cash, and any
future earnings on the cash, for the sole purpose of paying the future
above-market cost of the Panda PPA (or, in the alternative, to fund a transfer
or assignment of the remaining obligations under the Panda PPA to a third
party). Pepco also requested that the order provide that any cash
remaining in the account at the conclusion of the Panda PPA be refunded to
customers and that any shortfall be recovered from customers. Pepco
further proposed that the excess proceeds remaining from the settlement
(approximately $94.6 million, representing the amount by which the
regulatory liability of $414.6 million at December 31, 2007 exceeded
$320 million) be shared approximately equally with its customers in
accordance with the procedures previously approved by each commission for the
sharing of the proceeds received by Pepco from the sale to Mirant of its
generating assets. The regulatory liability of $414.6 million at
December 31, 2007 differs from the restricted cash amount of $417.3 million
on that date, in part, because the regulatory liability has been reduced for the
portion of the December 2007 Panda charges in excess of market that had not yet
been paid from the restricted cash account. The amount of the
restricted cash balance that Pepco is permitted to retain will be recorded as
earnings upon approval of the sharing arrangement by the respective
commissions. At this time, Pepco cannot predict the outcome of these
proceedings.
In settlement of other damages claims
against Mirant, Pepco in 2007 also received a settlement payment in the amount
of $70.0 million. Of this amount (i) $33.4 million was
recorded as a reduction in operating expenses, (ii) $21.0 million was
recorded as a reduction in a net pre-petition receivable claim from Mirant,
(iii) $15.0 million was recorded as a reduction in the capitalized costs of
certain property, plant and equipment and (iv) $.6 million was recorded as
a liability to reimburse a third party for certain legal costs associated with
the settlement.
Rate
Proceedings
In electric service distribution base
rate cases filed by Pepco in the District of Columbia and Maryland, and by DPL
in Maryland, and pending in 2007, Pepco and DPL proposed the adoption of a BSA
for retail customers. Under the BSA, customer delivery rates are
subject to adjustment (through a surcharge or credit mechanism), depending on
whether actual distribution revenue per customer exceeds or falls short of the
approved revenue-per-customer amount. The BSA will increase rates if
actual distribution revenues fall below the level approved by the applicable
commission and will decrease rates if actual distribution revenues are above the
approved level. The result will be that, over time, the utility would
collect its authorized revenues for distribution deliveries. As a
consequence, a BSA “decouples” revenue from unit sales consumption and ties the
growth in revenues to the growth in the number of customers. Some
advantages of the BSA are that it (i) eliminates revenue fluctuations due
to weather and
changes
in customer usage patterns and, therefore, provides for more predictable utility
distribution revenues that are better aligned with costs, (ii) provides for
more reliable fixed-cost recovery, (iii) tends to stabilize customers’
delivery bills, and (iv) removes any disincentives for the regulated
utilities to promote energy efficiency programs for their customers, because it
breaks the link between overall sales volumes and delivery
revenues. The status of the BSA proposals in each of the
jurisdictions is described below in discussion of the respective base rate
proceedings.
On September 4, 2007, DPL submitted its
2007 Gas Cost Rate (GCR) filing to the DPSC. The GCR permits DPL to
recover its gas procurement costs through customer rates. On
September 18, 2007, the DPSC issued an initial order approving a 5.7% decrease
in the level of the GCR, which became effective November 1, 2007, subject to
refund and pending final DPSC approval after evidentiary hearings.
In December 2006, Pepco submitted an
application to the DCPSC to increase electric distribution base rates, including
a proposed BSA. The application to the DCPSC requested an annual
increase of approximately $46.2 million or an overall increase of 13.5%,
reflecting a proposed return on equity (ROE) of 10.75%. In the
alternative, the application requested an annual increase of $50.5 million
or an overall increase of 14.8%, reflecting an ROE of 11.00%, if the BSA were
not approved. Subsequently, Pepco reduced its annual revenue increase
request to $43.4 million (including a proposed BSA) and $47.9 million
(if the BSA were not approved).
On January 30, 2008, the DCPSC approved
a revenue requirement increase of approximately $28.3 million, based on an
authorized return on rate base of 7.96%, including a 10% ROE. The
rate increase is effective February 20, 2008. The DCPSC, while
finding the BSA to be an appropriate ratemaking concept, cited potential
statutory problems in the DCPSC’s ability to implement the BSA. The
DCPSC stated that it intends to issue an order to establish a Phase II
proceeding to consider these implementation issues.
On July 19, 2007, the MPSC issued
orders in the electric service distribution rate cases filed by DPL and Pepco,
each of which included approval of a BSA. The DPL order approved an
annual increase in distribution rates of approximately $14.9 million
(including a decrease in annual depreciation expense of approximately
$.9 million). The Pepco order approved an annual increase in
distribution rates of approximately $10.6 million (including a decrease in
annual depreciation expense of approximately $30.7 million). In
each case, the approved distribution rate reflects an ROE of
10.0%. The orders each provided that the rate increases are effective
as of June 16, 2007, and will remain in effect for an initial period of nine
months from the date of the order (or until April 19, 2008). These
rates are subject to a Phase II proceeding in which the MPSC will consider the
results of audits of each company’s cost allocation manual, as filed with the
MPSC, to determine whether a further adjustment to the rates is
required. Hearings for the Phase II proceeding are scheduled for
mid-March 2008.
On June 1, 2007, ACE filed with the
NJBPU an application for permission to decrease the Non Utility Generation
Charge (NGC) and increase components of its Societal Benefits Charge (SBC) to be
collected from customers for the period October 1, 2007 through September
30, 2008. The proposed changes are designed to effect a true-up of
the actual and estimated costs and revenues collected through the current NGC
and SBC rates through September 30, 2007 and, in the case of the SBC, forecasted
costs and revenues for the period October 1, 2007 through September 30,
2008.
As of December 31, 2007, the NGC, which
is intended primarily to recover the above-market component of payments made by
ACE under non-utility generation contracts and stranded costs associated with
those commitments, had an over-recovery balance of
$224.3 million. The filing proposed that the estimated NGC
balance as of September 30, 2007 in the amount of $216.2 million, including
interest, be amortized and returned to ACE customers over a four-year period,
beginning October 1, 2007.
As of December 31, 2007, the SBC, which
is intended to allow ACE to recover certain costs involved with various
NJBPU-mandated social programs, had an under-recovery of approximately
$20.9 million, primarily due to increased costs associated with funding the
New Jersey Clean Energy Program. In addition, ACE has requested an
increase to the SBC to reflect the funding levels approved by the NJBPU of $20.4
million for the period October 1, 2007 through September 30, 2008, bringing to
$40 million the total recovery requested for the period October 1,
2007 to September 30, 2008 (based upon actual data through August
2007).
The net impact of the proposed
adjustments to the NGC and the SBC, including associated changes in sales and
use tax, is an overall rate decrease of approximately $129.9 million for
the period October 1, 2007 through September 30, 2008 (based upon actual data
through August 2007). The proposed adjustments and the corresponding
changes in customer rates are subject to the approval of the
NJBPU. If approved and implemented, ACE anticipates that the revised
rates will remain in effect until September 30, 2008, subject to an annual
true-up and change each year thereafter. The proposed adjustments and
the corresponding changes in customer rates remain under review by the NJBPU and
have not yet been implemented.
ACE
Restructuring Deferral Proceeding
Pursuant to orders issued by the NJBPU
under EDECA, beginning August 1, 1999, ACE was obligated to provide BGS to
retail electricity customers in its service territory who did not elect to
purchase electricity from a competitive supplier. For the period
August 1, 1999 through July 31, 2003, ACE’s aggregate costs that it was
allowed to recover from customers exceeded its aggregate revenues from supplying
BGS. These under-recovered costs were partially offset by a
$59.3 million deferred energy cost liability existing as of July 31, 1999
(LEAC Liability) related to ACE’s Levelized Energy Adjustment Clause and ACE’s
Demand Side Management Programs. ACE established a regulatory asset
in an amount equal to the balance of under-recovered costs.
In August 2002, ACE filed a petition
with the NJBPU for the recovery of approximately $176.4 million in actual
and projected deferred costs relating to the provision of BGS and
other
restructuring
related costs incurred by ACE over the four-year period August 1, 1999 through
July 31, 2003, net of the $59.3 million offset for the LEAC
Liability. The petition also requested that ACE’s rates be reset as
of August 1, 2003 so that there would be no under-recovery of costs embedded in
the rates on or after that date. The increase sought represented an
overall 8.4% annual increase in electric rates.
In July 2004, the NJBPU issued a final
order in the restructuring deferral proceeding confirming a July 2003 summary
order, which (i) permitted ACE to begin collecting a portion of the deferred
costs and reset rates to recover on-going costs incurred as a result of EDECA,
(ii) approved the recovery of $125 million of the deferred balance over a
ten-year amortization period beginning August 1, 2003, (iii) transferred to
ACE’s then pending base rate case for further consideration approximately
$25.4 million of the deferred balance (the base rate case ended in a
settlement approved by the NJBPU in May 2005, the result of which is that any
net rate impact from the deferral account recoveries and credits in future years
will depend in part on whether rates associated with other deferred accounts
considered in the case continue to generate over-collections relative to costs),
and (iv) estimated the overall deferral balance as of July 31, 2003 at
$195.0 million, of which $44.6 million was disallowed recovery by
ACE. Although ACE believes the record does not justify the level of
disallowance imposed by the NJBPU in the final order, the $44.6 million of
disallowed incurred costs were reserved during the years 1999 through 2003
(primarily 2003) through charges to earnings, primarily in the operating expense
line item “deferred electric service costs,” with a corresponding reduction in
the regulatory asset balance sheet account. In 2005, an additional
$1.2 million in interest on the disallowed amount was identified and
reserved by ACE. In August 2004, ACE filed a notice of appeal with
respect to the July 2004 final order with the Appellate Division of the Superior
Court of New Jersey (the Appellate Division), which hears appeals of the
decisions of New Jersey administrative agencies, including the
NJBPU. On August 9, 2007, the Appellate Division, citing deference to
the factual and policy findings of the NJBPU, affirmed the NJBPU’s decision in
its entirety, rejecting challenges from ACE and the Division of Rate
Counsel. On September 10, 2007, ACE filed an application for
certification to the New Jersey Supreme Court. On January 15, 2008,
the New Jersey Supreme Court denied ACE’s application for
certification. Because the full amount at issue in this proceeding
was previously reserved by ACE, there will be no further financial statement
impact to ACE.
Divestiture
Cases
Final briefs on Pepco’s District of
Columbia divestiture proceeds sharing application were filed with the DCPSC in
July 2002 following an evidentiary hearing in June 2002. That
application was filed to implement a provision of Pepco’s DCPSC-approved
divestiture settlement that provided for a sharing of any net proceeds from the
sale of Pepco’s generation-related assets. One of the principal
issues in the case is whether Pepco should be required to share with customers
the excess deferred income taxes (EDIT) and accumulated deferred investment tax
credits (ADITC) associated with the sold assets and, if so, whether such sharing
would violate the normalization provisions of the Internal Revenue Code (IRC)
and its implementing regulations. As of December 31, 2007, the
District of Columbia allocated portions of EDIT and ADITC associated with the
divested generating assets were approximately $6.5 million and
$5.8 million, respectively.
Pepco believes that a sharing of EDIT
and ADITC would violate the IRS normalization rules. Under these
rules, Pepco could not transfer the EDIT and the ADITC benefit to customers more
quickly than on a straight line basis over the book life of the related assets.
Since the assets are no longer owned by Pepco, there is no book life over which
the EDIT and ADITC can be returned. If Pepco were required to share
EDIT and ADITC and, as a result, the normalization rules were violated, Pepco
would be unable to use accelerated depreciation on District of Columbia
allocated or assigned property. In addition to sharing with customers
the generation-related EDIT and ADITC balances, Pepco would have to pay to the
IRS an amount equal to Pepco’s District of Columbia jurisdictional
generation-related ADITC balance ($5.8 million as of December 31, 2007), as
well as its District of Columbia jurisdictional transmission and
distribution-related ADITC balance $4.0 million as of December 31, 2007) in
each case as those balances exist as of the later of the date a DCPSC order is
issued and all rights to appeal have been exhausted or lapsed, or the date the
DCPSC order becomes operative.
In March 2003, the IRS issued a notice
of proposed rulemaking (NOPR), which would allow for the sharing of EDIT and
ADITC related to divested assets with utility customers on a prospective basis
and at the election of the taxpayer on a retroactive basis. In
December 2005 a revised NOPR was issued which, among other things, withdrew the
March 2003 NOPR and eliminated the taxpayer’s ability to elect to apply the
regulation retroactively. Comments on the revised NOPR were filed in
March 2006, and a public hearing was held in April 2006. Pepco filed
a letter with the DCPSC in January 2006, in which it has reiterated that the
DCPSC should continue to defer any decision on the ADITC and EDIT issues until
the IRS issues final regulations or states that its regulations project related
to this issue will be terminated without the issuance of any
regulations. Other issues in the divestiture proceeding deal with the
treatment of internal costs and cost allocations as deductions from the gross
proceeds of the divestiture.
Pepco believes that its calculation of
the District of Columbia customers’ share of divestiture proceeds is
correct. However, depending on the ultimate outcome of this
proceeding, Pepco could be required to make additional gain-sharing payments to
District of Columbia customers, including the payments described above related
to EDIT and ADITC. Such additional payments (which, other than the
EDIT and ADITC related payments, cannot be estimated) would be charged to
expense in the quarter and year in which a final decision is rendered and could
have a material adverse effect on Pepco’s and PHI’s results of operations for
those periods. However, neither PHI nor Pepco believes that
additional gain-sharing payments, if any, or the ADITC-related payments to the
IRS, if required, would have a material adverse impact on its financial position
or cash flows.
Pepco filed its divestiture proceeds
plan application with the MPSC in April 2001. The principal issue in
the Maryland case is the same EDIT and ADITC sharing issue that has been raised
in the District of Columbia case. See the discussion above under
“Divestiture Cases -- District of Columbia.” As of December 31, 2007,
the Maryland allocated portions of EDIT and ADITC associated with the divested
generating assets were approximately $9.1 million and $10.4 million,
respectively. Other issues deal with the treatment of certain costs
as deductions from the gross proceeds of the divestiture. In November
2003, the Hearing Examiner in the Maryland proceeding issued a proposed order
with respect to the application that concluded that Pepco’s Maryland divestiture
settlement agreement provided for a sharing between Pepco and customers of the
EDIT and ADITC associated with the sold assets. Pepco believes that
such a
sharing
would violate the normalization rules (discussed above) and would result in
Pepco’s inability to use accelerated depreciation on Maryland allocated or
assigned property. If the proposed order is affirmed, Pepco would
have to share with its Maryland customers, on an approximately 50/50 basis, the
Maryland allocated portion of the generation-related EDIT ($9.1 million as
of December 31, 2007), and the Maryland-allocated portion of generation-related
ADITC. Furthermore, Pepco would have to pay to the IRS an amount
equal to Pepco’s Maryland jurisdictional generation-related ADITC balance
($10.4 million as of December 31, 2007), as well as its Maryland retail
jurisdictional ADITC transmission and distribution-related balance
($7.2 million as of December 31, 2007), in each case as those balances
exist as of the later of the date a MPSC order is issued and all rights to
appeal have been exhausted or lapsed, or the date the MPSC order becomes
operative. The Hearing Examiner decided all other issues in favor of
Pepco, except for the determination that only one-half of the severance payments
that Pepco included in its calculation of corporate reorganization costs should
be deducted from the sales proceeds before sharing of the net gain between Pepco
and customers. Pepco filed a letter with the MPSC in January 2006, in
which it has reiterated that the MPSC should continue to defer any decision on
the ADITC and EDIT issues until the IRS issues final regulations or states that
its regulations project related to this issue will be terminated without the
issuance of any regulations.
In December 2003, Pepco appealed the
Hearing Examiner’s decision to the MPSC as it relates to the treatment of EDIT
and ADITC and corporate reorganization costs. The MPSC has not issued
any ruling on the appeal and Pepco does not believe that it will do so until
action is taken by the IRS as described above. However, depending on
the ultimate outcome of this proceeding, Pepco could be required to share with
its customers approximately 50 percent of the EDIT and ADITC balances described
above in addition to the additional gain-sharing payments relating to the
disallowed severance payments. Such additional payments would be
charged to expense in the quarter and year in which a final decision is rendered
and could have a material adverse effect on results of operations for those
periods. However, neither PHI nor Pepco believes that additional
gain-sharing payments, if any, or the ADITC-related payments to the IRS, if
required, would have a material adverse impact on its financial position or cash
flows.
In connection with the divestiture by
ACE of its nuclear generating assets, the NJBPU in July 2000 preliminarily
determined that the amount of stranded costs associated with the divested assets
that ACE could recover from ratepayers should be reduced by approximately
$94.8 million, consisting of $54.1 million of accumulated deferred
federal income taxes (ADFIT) associated with accelerated depreciation on the
divested nuclear assets, and $40.7 million of current tax loss from selling
the assets at a price below the tax basis.
The $54.1 million in deferred
taxes associated with the divested assets’ accelerated depreciation, however, is
subject to the normalization rules. Due to uncertainty under federal
tax law regarding whether the sharing of federal income tax benefits associated
with the divested assets, including ADFIT related to accelerated depreciation,
with ACE’s customers would violate the normalization rules, ACE submitted a
request to the IRS for a Private Letter Ruling (PLR) to clarify the applicable
law. The NJBPU delayed its final determination of the amount of
recoverable stranded costs until after the receipt of the PLR.
On May 25, 2006, the IRS issued the PLR
in which it stated that returning to ratepayers any of the unamortized ADFIT
attributable to accelerated depreciation on the divested assets after the sale
of the assets by means of a reduction of the amount of recoverable stranded
costs would violate the normalization rules.
On June 9, 2006, ACE submitted a letter
to the NJBPU, requesting that the NJBPU conduct proceedings to finalize the
determination of the stranded costs associated with the sale of ACE’s nuclear
assets in accordance with the PLR. In the absence of an NJBPU action
regarding ACE’s request, on June 22, 2007, ACE filed a motion requesting that
the NJBPU issue an order finalizing the determination of such stranded costs in
accordance with the PLR. On October 24, 2007, the NJBPU approved a
stipulation resolving the ADFIT issue and issued a clarifying order, which
concludes that the $94.8 million in stranded cost reduction, including the
$54.1 million in ADFIT, does not violate the IRS normalization
rules. In explaining this result, the NJBPU stated that (i) its
earlier orders determining ACE’s recoverable stranded costs “net of tax” did not
cause ADFIT associated with certain divested nuclear assets to reduce stranded
costs otherwise recoverable from ACE’s ratepayers, and (ii) because the
Market Transition Charge-Tax component of the stranded cost recovery was
intended by the NJBPU to gross-up “net of tax” stranded costs, thereby ensuring
and establishing that the ADFIT balance was not flowed through to ratepayers,
the normalization rules were not violated.
Default
Electricity Supply Proceedings
Virginia
In June 2007, the Virginia State
Corporation Commission (VSCC) denied DPL’s request for an increase in its rates
for Default Service for the period July 1, 2007 to May 31, 2008. DPL
appealed in both state and federal courts. Those appeals have been
dismissed in light of the closing of the sale of DPL's Virginia electric
operations as described below under the heading “DPL Sale of Virginia
Operations.”
ACE
Sale of B.L. England Generating Facility
On February 8, 2007, ACE completed the
sale of the B.L. England generating facility to RC Cape May Holdings, LLC (RC
Cape May), an affiliate of Rockland Capital Energy Investments, LLC, for which
it received proceeds of approximately $9 million. At the time of
the sale, RC Cape May and ACE agreed to submit to arbitration the issue of
whether RC Cape May, under the terms of the purchase agreement, must pay to ACE
an additional $3.1 million as part of the purchase price. On
February 26, 2008, the arbitrators issued a decision awarding $3.1 million to
ACE, plus interest, attorneys’ fees and costs, for a total award of
approximately $4.2 million.
On July 18, 2007, ACE received a claim
for indemnification from RC Cape May under the purchase agreement. RC
Cape May contends that one of the assets it purchased, a contract for terminal
services (TSA) between ACE and Citgo Asphalt Refining Co. (Citgo), has been
declared by Citgo to have been terminated due to a failure by ACE to renew the
contract in a timely manner. RC Cape May has commenced an arbitration
proceeding against Citgo seeking a determination that the TSA remains in effect
and has notified ACE of the proceeding. In addition, RC Cape May has
asserted a claim for indemnification from ACE in the amount of $25 million
if the TSA is held not to be enforceable against Citgo. While ACE
believes that it
has
defenses to the indemnification under the terms of the purchase agreement,
should the arbitrator rule that the TSA has terminated, the outcome of this
matter is uncertain. ACE notified RC Cape May of its intent to
participate in the pending arbitration.
The sale of B.L. England will not
affect the stranded costs associated with the plant that already have been
securitized. ACE anticipates that approximately $9 million to $10
million of additional regulatory assets related to B.L. England may, subject to
NJBPU approval, be eligible for recovery as stranded
costs. Approximately $47 million in emission allowance credits
associated with B. L. England were monetized for the benefit of ACE’s ratepayers
pursuant to the NJBPU order approving the sale. Net proceeds from the
sale of the plant and monetization of the emission allowance credits, estimated
to be $36.1 million as of December 31, 2007, will be credited to ACE’s
ratepayers in accordance with the requirements of EDECA and NJBPU
orders. The appropriate mechanism for crediting the net proceeds from
the sale of the plant and the monetized emission allowance credits to ratepayers
is being determined in a proceeding that is currently pending before the
NJBPU.
DPL
Sale of Virginia Operations
On January 2, 2008, DPL completed (i)
the sale of its retail electric distribution business on the Eastern Shore of
Virginia to A&N Electric Cooperative (A&N) for a purchase price of
approximately $45.2 million, after closing adjustments, and (ii) the
sale of its wholesale electric transmission business located on the Eastern
Shore of Virginia to Old Dominion Electric Cooperative (ODEC) for a purchase
price of approximately $5.4 million, after closing
adjustments. Each of A&N and ODEC assumed certain post-closing
liabilities and unknown pre-closing liabilities related to the respective assets
they are purchasing (including, in the A&N transaction, most environmental
liabilities), except that DPL remained liable for unknown pre-closing
liabilities if they become known within six months after the January 2,
2008 closing date. These sales are expected to result in an
immaterial financial gain to DPL that will be recorded in the first quarter of
2008.
Pepco
Energy Services Deactivation of Power Plants
Pepco Energy Services owns and operates
two oil-fired power plants. The power plants are located in
Washington, D.C. and have a generating capacity rating of approximately 790
MW. Pepco Energy Services sells the output of these plants into the
wholesale market administered by PJM. In February 2007, Pepco Energy
Services provided notice to PJM of its intention to deactivate these
plants. In May 2007, Pepco Energy Services deactivated one combustion
turbine at its Buzzard Point facility with a generating capacity of
approximately 16 MW. Pepco Energy Services currently plans to
deactivate the balance of both plants by May 2012. PJM has informed
Pepco Energy Services that these facilities are not expected to be needed for
reliability after that time, but that its evaluation is dependent on the
completion of transmission upgrades. Pepco Energy Services’ timing
for deactivation of these units, in whole or in part, may be accelerated or
delayed based on the operating condition of the units, economic conditions, and
reliability considerations. Prior to deactivation of the plants,
Pepco Energy Services may incur deficiency charges imposed by PJM at a rate up
to two times the capacity payment price that the plants
receive. Deactivation is not expected to have a material impact on
PHI’s financial condition, results of operations or cash flows.
General
Litigation
During 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 are
not entirely clear, it appears that each plaintiff sought $2 million in
compensatory damages and $4 million in punitive damages from each
defendant.
Since the initial filings in 1993,
additional individual suits have been filed against Pepco, and significant
numbers of cases have been dismissed. As a result of two motions to
dismiss, numerous hearings and meetings and one motion for summary judgment,
Pepco has had approximately 400 of these cases successfully dismissed with
prejudice, either voluntarily by the plaintiff or by the court. As of
December 31, 2007, there are approximately 180 cases still pending against Pepco
in the State Courts of Maryland, of which approximately 90 cases were filed
after December 19, 2000, and were tendered to Mirant Corporation for defense and
indemnification pursuant to the terms of the Asset Purchase and Sale Agreement
between Pepco and Mirant under which Pepco sold its generation assets to Mirant
in 2000.
While the aggregate amount of monetary
damages sought in the remaining suits (excluding those tendered to Mirant) is
approximately $360 million, PHI and Pepco believe the amounts claimed by
current plaintiffs are greatly exaggerated. The amount of total
liability, if any, and any related insurance recovery cannot be determined at
this time; however, based on information and relevant circumstances known at
this time, neither PHI nor Pepco believes these suits will have a material
adverse effect on its financial position, results of operations or cash
flows. However, if an unfavorable decision were rendered against
Pepco, it could have a material adverse effect on Pepco’s and PHI’s financial
position, results of operations or cash flows.
Cash
Balance Plan Litigation
In 1999, Conectiv established a cash
balance retirement plan to replace defined benefit retirement plans then
maintained by ACE and DPL. Following the acquisition by Pepco of
Conectiv, this plan became the Conectiv Cash Balance Sub-Plan within the PHI
Retirement Plan. In September 2005, three management employees of PHI
Service Company filed suit in the U.S. District Court for the District of
Delaware (the Delaware District Court) against the PHI Retirement Plan, PHI and
Conectiv (the PHI Parties), alleging violations of ERISA, on behalf of a class
of management employees who did not have enough age and service when the Cash
Balance Sub-Plan was implemented in 1999 to assure that their accrued benefits
would be calculated pursuant to the terms of the predecessor plans sponsored by
ACE and DPL. A fourth plaintiff was added to the case to represent
DPL-legacy employees who were not eligible for grandfathered
benefits.
The plaintiffs challenged the design of
the Cash Balance Sub-Plan and sought a declaratory judgment that the Cash
Balance Sub-Plan was invalid and that the accrued benefits of
each
member of the class should be calculated pursuant to the terms of the
predecessor plans. Specifically, the complaint alleged that the use
of a variable rate to compute the plaintiffs’ accrued benefit under the Cash
Balance Sub-Plan resulted in reductions in the accrued benefits that violated
ERISA. The complaint also alleged that the benefit accrual rates and
the minimal accrual requirements of the Cash Balance Sub-Plan violated ERISA as
did the notice that was given to plan participants upon implementation of the
Cash Balance Sub-Plan.
On September 19, 2007, the Delaware
District Court issued an order granting summary judgment in favor of the PHI
Parties. On October 12, 2007, the plaintiffs filed an appeal of
the decision to the U.S. Court of Appeals for the Third Circuit.
If the plaintiffs were to prevail in
this litigation, the ABO and projected benefit obligation (PBO) calculated in
accordance with SFAS No. 87 each would increase by approximately
$12 million, assuming no change in benefits for persons who have already
retired or whose employment has been terminated and using actuarial valuation
data as of the time the suit was filed. The ABO represents the
present value that participants have earned as of the date of
calculation. This means that only service already worked and
compensation already earned and paid is considered. The PBO is
similar to the ABO, except that the PBO includes recognition of the effect that
estimated future pay increases would have on the pension plan
obligation.
Environmental
Litigation
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. 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. Although penalties
assessed for violations of environmental laws and regulations are not
recoverable from customers of the operating utilities, environmental clean-up
costs incurred by Pepco, DPL and ACE would be included by each company in its
respective cost of service for ratemaking purposes.
Cambridge, Maryland
Site. In July 2004, DPL entered into an administrative consent order
(ACO) with the Maryland Department of the Environment (MDE) to perform a
Remedial Investigation/Feasibility Study (RI/FS) to further identify the extent
of soil, sediment and ground and surface water contamination related to former
manufactured gas plant (MGP) operations at a Cambridge, Maryland site on
DPL-owned property and to investigate the extent of MGP contamination on
adjacent property. The MDE has approved the RI and DPL submitted a
final FS to MDE on February 15, 2007. No further MDE action is
required with respect to the final FS. The costs of cleanup (as
determined by the RI/FS and subsequent negotiations with MDE) are anticipated to
be approximately $3.8 million. The
remedial action to be taken by DPL will include dredging activities within
Cambridge Creek, which are expected to commence in March 2008, and soil
excavation on DPL’s and adjacent property as early as August
2008. The final cleanup costs will include protective measures to
control contaminant migration during the dredging activities and improvements to
the existing shoreline.
Delilah Road Landfill
Site. In November 1991, the New Jersey Department of
Environmental Protection (NJDEP) identified ACE as a potentially responsible
party (PRP) at the Delilah Road Landfill site in Egg Harbor Township, New
Jersey. In 1993, ACE, along with other PRPs, signed an ACO with NJDEP
to remediate the site. The soil cap remedy for the site has been
implemented and in August 2006, NJDEP issued a No Further Action Letter (NFA)
and Covenant Not to Sue for the site. Among other things, the NFA
requires the PRPs to monitor the effectiveness of institutional (deed
restriction) and engineering (cap) controls at the site every two
years. In September 2007, NJDEP approved the PRP group’s petition to
conduct semi-annual, rather than quarterly, ground water monitoring for two
years and deferred until the end of the two-year period a decision on the PRP
group’s request for annual groundwater monitoring thereafter. In
August 2007, the PRP group agreed to reimburse EPA’s costs in the amount of
$81,400 in full satisfaction of EPA’s claims for all past and future response
costs relating to the site (of which ACE’s share is one-third) and in October
2007, EPA and the PRP group entered into a tolling agreement to permit the
parties sufficient time to execute a final settlement agreement. This
settlement agreement will allow EPA to reopen the settlement in the event of new
information or unknown conditions at the site. Based on information
currently available, ACE anticipates that its share of additional cost
associated with this site for post-remedy operation and maintenance will be
approximately $555,000 to $600,000. ACE believes that its liability
for post-remedy operation and maintenance costs will not have a material adverse
effect on its financial position, results of operations or cash
flows.
Frontier Chemical
Site. On June 29, 2007, ACE received a letter from the New
York Department of Environmental Conservation (NYDEC) identifying ACE as a PRP
at the Frontier Chemical Waste Processing Company site in Niagara Falls, N.Y.
based on hazardous waste manifests indicating that ACE sent in excess of 7,500
gallons of manifested hazardous waste to the site. ACE has entered
into an agreement with the other parties identified as PRPs to form the PRP
group and has informed NYDEC that it has entered into good faith negotiations
with the PRP group to address ACE’s responsibility at the site. ACE
believes that its responsibility at the site will not have a material adverse
effect on its financial position, results of operations or cash
flows.
Carolina Transformer
Site. In August 2006, EPA notified each of DPL and Pepco that
they have been identified as entities that sent PCB-laden oil to be disposed at
the Carolina Transformer site in Fayetteville, North Carolina. The
EPA notification stated that, on this basis, DPL and Pepco may be
PRPs. In December 2007, DPL and Pepco agreed to enter into a
settlement agreement with EPA and the PRP group at the Carolina Transformer
site. Under the terms of the settlement, (i) Pepco and DPL each
will pay $162,000 to EPA to resolve any liability that it might have at the
site, (ii) EPA covenants not to sue or bring administrative action against
DPL and Pepco for response costs at the site, (iii) other PRP group members
release all rights for cost recovery or contribution claims they may have
against DPL and Pepco, and (iv) DPL and Pepco release all rights for cost
recovery or contribution claims that they may have against other parties
settling with EPA. The consent decree is expected to be filed with
the U.S. District Court in North Carolina in the second quarter of
2008.
Deepwater Generating
Station. On December 27, 2005, NJDEP issued a Title V
Operating Permit for Conectiv Energy’s Deepwater Generating
Station. The permit includes new limits on unit heat
input. In order to comply with these new operational limits, Conectiv
Energy restricted the output of the Deepwater Generating Station’s Unit 1 and
Unit 6. In 2006 and the first half of 2007, these restrictions
resulted in operating losses of approximately $10,000
per
operating day on Unit 6, primarily because of lost revenues due to reduced
output, and to a lesser degree because of lost revenues related to capacity
requirements of PJM. Since June 1, 2007, Deepwater Unit 6 can operate
within the heat input limits set forth in the Title V Operating Permit without
restricting output, because of technical improvements that partially corrected
the inherent bias in the continuous emissions monitoring system that had caused
recorded heat input to be higher than actual heat input. In order to
comply with the heat input limit at Deepwater Unit 1, Conectiv Energy continues
to restrict Unit 1 output, resulting in operating losses of approximately
$500,000 in the second half of 2007 and projected operating losses in 2008 of
approximately $500,000, due to penalties and lost revenues related to PJM
capacity requirements. Beyond 2008, while penalties due to PJM
capacity requirements are not expected, further operating losses due to lost
revenues related to PJM capacity requirements may continue to be
incurred. The operating losses due to reduced output on Unit 1 have
been, and are expected to continue to be, insignificant. Conectiv
Energy is challenging these heat input restrictions and other provisions of the
Title V Operating Permit for Deepwater Generating Station in the New Jersey
Office of Administrative Law (OAL). On October 2, 2007, the OAL
issued a decision granting summary decision in favor of Conectiv Energy, finding
that hourly heat input shall not be used as a condition or limit for Conectiv
Energy’s electric generating operations. On October 26, 2007, the
NJDEP Commissioner denied NJDEP’s request for interlocutory review of the OAL
order and determined that the Commissioner would review the October 2, 2007
order upon completion of the proceeding on Conectiv Energy’s other challenges to
the Deepwater Title V permit. A hearing on the remaining challenged
Title V permit provisions is scheduled for mid-April 2008.
On April 3, 2007, NJDEP issued an
Administrative Order and Notice of Civil Administrative Penalty Assessment (the
First Order) alleging that at Conectiv Energy's Deepwater Generating Station,
the maximum gross heat input to Unit 1 exceeded the maximum allowable heat input
in calendar year 2005 and the maximum gross heat input to Unit 6 exceeded the
maximum allowable heat input in calendar years 2005 and 2006. The
order required the cessation of operation of Units 1 and 6 above the alleged
permitted heat input levels, assessed a penalty of approximately
$1.1 million and requested that Conectiv Energy provide additional
information about heat input to Units 1 and 6. Conectiv Energy
provided NJDEP Units 1 and 6 calendar year 2004 heat input data on May 9, 2007,
and calendar years 1995 to 2003 heat input data on July 10, 2007. On
May 23, 2007, NJDEP issued a second Administrative Order and Notice of Civil
Administrative Penalty Assessment (the Second Order) alleging that the maximum
gross heat input to Units 1 and 6 exceeded the maximum allowable heat input in
calendar year 2004. The Second Order required the cessation of
operation of Units 1 and 6 above the alleged permitted heat input levels
and assessed a penalty of $811,600. Conectiv Energy has requested a
contested case hearing challenging the issuance of the First Order and the
Second Order and moved for a stay of the orders pending resolution of the Title
V Operating Permit contested case described above. On November 29,
2007, the OAL issued orders placing the First Order and the Second Order on the
inactive list for six months. Until the OAL decision discussed above
is final, it will not have an impact on these currently inactive enforcement
cases.
IRS
Examination of Like-Kind Exchange Transaction
In 2001, Conectiv and certain of its
subsidiaries (the Conectiv Group) were engaged in the implementation of a
strategy to divest non-strategic electric generating facilities and replace
these facilities with mid-merit electric generating capacity. As part
of this strategy, the Conectiv Group exchanged its interests in two older
coal-fired plants for the more efficient gas-fired Hay
Road II
generating facility, which was owned by an unaffiliated third
party. For tax purposes, Conectiv treated the transaction as a
“like-kind exchange” under IRC Section 1031. As a result,
approximately $88 million of taxable gain was deferred for federal income
tax purposes.
The transaction was examined by the IRS
as part of the normal Conectiv tax audit. In May 2006, the IRS issued
a revenue agent’s report (RAR) for the audit of Conectiv’s 2000, 2001 and 2002
income tax returns, in which the IRS disallowed the qualification of the
exchange under IRC Section 1031. In July 2006, Conectiv filed a
protest of this disallowance to the IRS Office of Appeals.
PHI believes that its tax position
related to this transaction is proper based on applicable statutes, regulations
and case law and is contesting the disallowance. However, there is no
absolute assurance that Conectiv’s position will prevail. If the IRS
prevails, Conectiv would be subject to additional income taxes, interest and
possible penalties. However, a portion of the denied benefit would be
offset by additional tax depreciation. PHI has accrued approximately
$4.9 million related to this matter.
As of December 31, 2007, if the IRS
were to fully prevail, the potential cash impact on PHI would be current income
tax and interest payments of approximately $31.2 million and the earnings
impact would be approximately $9.8 million in after-tax
interest.
Federal
Tax Treatment of Cross-Border Leases
PCI maintains a portfolio of
cross-border energy sale-leaseback transactions, which, as of December 31,
2007, had a book value of approximately $1.4 billion, and from which PHI
currently derives approximately $60 million per year in tax benefits in the form
of interest and depreciation deductions.
In 2005, the Treasury Department and
IRS issued Notice 2005-13 informing taxpayers that the IRS intends to challenge
on various grounds the purported tax benefits claimed by taxpayers entering into
certain sale-leaseback transactions with tax-indifferent parties (i.e.,
municipalities, tax-exempt and governmental entities), including those entered
into on or prior to March 12, 2004 (the Notice). All of PCI’s
cross-border energy leases are with tax indifferent parties and were entered
into prior to 2004. Also in 2005, the IRS published a Coordinated
Issue Paper concerning the resolution of audit issues related to such
transactions. PCI’s cross-border energy leases are similar to those
sale-leaseback transactions described in the Notice and the Coordinated Issue
Paper.
PCI’s leases have been under
examination by the IRS as part of the normal PHI tax audit. In June
2006, the IRS issued its final RAR for its audit of PHI’s 2001 and 2002 income
tax returns. In the RAR, the IRS disallowed the tax benefits claimed
by PHI with respect to these leases for those years. The tax benefits
claimed by PHI with respect to these leases from 2001 through December 31, 2007
were approximately $347 million. PHI has filed a protest against the
IRS adjustments and the unresolved audit has been forwarded to the U.S. Office
of Appeals. The ultimate outcome of this issue is uncertain; however,
if the IRS prevails, PHI would be subject to additional taxes, along with
interest and possibly penalties on the additional taxes, which could have a
material adverse effect on PHI’s financial condition, results of operations, and
cash flows. PHI believes that its tax position related to these
transactions was appropriate
based on
applicable statutes, regulations and case law, and intends to contest the
adjustments proposed by the IRS; however, there is no assurance that PHI’s
position will prevail.
In 2006, the FASB issued FSP FAS 13-2,
which amends SFAS No. 13 effective for fiscal years beginning after December 15,
2006. This amendment requires a lease to be repriced and the book
value adjusted when there is a change or probable change in the timing of tax
benefits of the lease regardless of whether the change results in a deferral or
permanent loss of tax benefits. Accordingly, a material change in the
timing of cash flows under PHI’s cross-border leases as the result of a
settlement with the IRS would require an adjustment to the book value of the
leases and a charge to earnings equal to the repricing impact of the disallowed
deductions which could result in a material adverse effect on PHI’s financial
condition, results of operations, and cash flows. PHI believes its
tax position was appropriate and at this time does not believe there is a
probable change in the timing of its tax benefits that would require repricing
the leases and a charge to earnings.
On December 14, 2007 the U.S.
Senate passed its version of the Farm, Nutrition, and Bioenergy Act of 2007
(H.R. 2419) which contains a provision that would apply passive loss limitation
rules to leases with foreign tax indifferent parties effective for taxable years
beginning after December 31, 2006, even if the leases were entered into on
or prior to March 12, 2004. The U.S. House of Representatives
version of this proposed legislation which it passed on July 27, 2007 does
not contain any provision that would modify the current treatment of leases with
tax indifferent parties. Enactment into law of a bill that is similar
to that passed by the U.S. Senate in its current form could result in a material
delay of the income tax benefits that PHI would receive in connection with its
cross-border energy leases. Furthermore, if legislation of this type
were to be enacted, under FSP FAS 13-2, PHI would be required to adjust the book
value of the leases and record a charge to earnings equal to the repricing
impact of the deferred deductions which could result in a material adverse
effect on PHI’s financial condition, results of operations and
cash-flows. The U.S. House of Representatives and the U.S. Senate are
expected to hold a conference in the near future to reconcile the differences in
the two bills to determine the final legislation.
IRS
Mixed Service Cost Issue
During 2001, Pepco, DPL, and ACE
changed their methods of accounting with respect to capitalizable construction
costs for income tax purposes. The change allowed the companies to
accelerate the deduction of certain expenses that were previously capitalized
and depreciated. Through December 31, 2005, these accelerated
deductions generated incremental tax cash flow benefits of approximately $205
million (consisting of $94 million for Pepco, $62 million for DPL, and $49
million for ACE) for the companies, primarily attributable to their 2001 tax
returns.
In 2005, the Treasury Department issued
proposed regulations that, if adopted in their current form, would require
Pepco, DPL, and ACE to change their method of accounting with respect to
capitalizable construction costs for income tax purposes for tax periods
beginning in 2005. Based on the proposed regulations, PHI in its 2005
federal tax return adopted an alternative method of accounting for capitalizable
construction costs that management believes will be acceptable to the
IRS.
At the same time as the proposed
regulations were released, the IRS issued Revenue Ruling 2005-53, which is
intended to limit the ability of certain taxpayers to utilize the method of
accounting for income tax purposes they utilized on their tax returns for 2004
and prior years with respect to capitalizable construction costs. In
line with this Revenue Ruling, the IRS RAR for the 2001 and 2002 tax returns
disallowed substantially all of the incremental tax benefits that Pepco, DPL and
ACE had claimed on those returns by requiring the companies to capitalize and
depreciate certain expenses rather than treat such expenses as current
deductions. PHI’s protest of the IRS adjustments is among the
unresolved audit matters relating to the 2001 and 2002 audits pending before the
Appeals Office.
In February 2006, PHI paid
approximately $121 million of taxes to cover the amount of additional taxes and
interest that management estimated to be payable for the years 2001 through 2004
based on the method of tax accounting that PHI, pursuant to the proposed
regulations, adopted on its 2005 tax return. However, if the IRS is
successful in requiring Pepco, DPL and ACE to capitalize and depreciate
construction costs that result in a tax and interest assessment greater than
management’s estimate of $121 million, PHI will be required to pay additional
taxes and interest only to the extent these adjustments exceed the $121 million
payment made in February 2006. It is reasonably possible that PHI’s
unrecognized tax benefits related to this issue will significantly decrease in
the next 12 months as a result of a settlement with the IRS.
Third
Party Guarantees, Indemnifications, and Off-Balance Sheet
Arrangements
Pepco Holdings and certain of its
subsidiaries have various financial and performance guarantees and
indemnification obligations which are entered into in the normal course of
business to facilitate commercial transactions with third parties as discussed
below.
As of December 31, 2007, Pepco Holdings
and its subsidiaries were parties to a variety of agreements pursuant to which
they were guarantors for standby letters of credit, performance residual value,
and other commitments and obligations. The commitments and
obligations, in millions of dollars, were as follows:
|
|
Guarantor
|
|
|
|
|
|
|
PHI
|
|
DPL
|
|
ACE
|
|
Other
|
|
Total
|
|
|
Energy
marketing obligations of Conectiv Energy (a)
|
$
|
180.9
|
$
|
-
|
$
|
-
|
$
|
-
|
$
|
180.9
|
|
|
Energy
procurement obligations of Pepco Energy
Services (a)
|
|
141.7
|
|
-
|
|
-
|
|
-
|
|
141.7
|
|
|
Guaranteed
lease residual values
(b)
|
|
-
|
|
2.6
|
|
2.7
|
|
.4
|
|
5.7
|
|
|
Other
(c)
|
|
2.3
|
|
-
|
|
-
|
|
1.4
|
|
3.7
|
|
|
Total
|
$
|
324.9
|
$
|
2.6
|
$
|
2.7
7
|
$
|
1.8
|
$
|
332.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
Pepco
Holdings has contractual commitments for ensuring the performance and
related payments of Conectiv Energy and Pepco Energy Services to
counterparties under routine energy sales and procurement obligations,
including retail customer load obligations of Pepco Energy Services and
requirements under BGS contracts entered into by Conectiv Energy with
ACE.
|
|
|
(b)
|
Subsidiaries
of Pepco Holdings have guaranteed residual values in excess of fair value
of certain equipment and fleet vehicles held through lease
agreements. As of December 31, 2007, obligations under the
guarantees were approximately $5.7 million. Assets leased
under agreements subject to residual value guarantees are typically for
periods ranging from 2 years to 10 years. Historically,
payments under the guarantees have not been made by the guarantor as,
under normal conditions, the contract runs to full term at which time the
residual value is minimal. As such, Pepco Holdings believes the
likelihood of payment being required under the guarantee is
remote.
|
|
|
(c)
|
Other
guarantees consist of:
|
|
|
·
|
Pepco
Holdings has guaranteed a subsidiary building lease of $2.3 million. Pepco
Holdings does not expect to fund the full amount of the exposure under the
guarantee.
|
|
|
·
|
PCI
has guaranteed facility rental obligations related to contracts entered
into by Starpower. As of December 31, 2007, the guarantees
cover the remaining $1.4 million in rental
obligations.
|
Pepco Holdings 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.
Dividends
Contractual
Obligations
As of December 31, 2007, Pepco
Holdings’ contractual obligations under non-derivative fuel and purchase power
contracts, excluding the BGS supplier load commitments, were $3,176.7 million in
2008, $2,756.8 million in 2009 to 2010, $752.7 million in 2011 to 2012, and
$3,119.9 million in 2013 and thereafter.
|
(13)
|
USE
OF DERIVATIVES IN ENERGY AND INTEREST RATE HEDGING
ACTIVITIES
|
PHI’s Competitive Energy businesses use
derivative instruments primarily to reduce their financial exposure to changes
in the value of their assets and obligations due to commodity price
fluctuations. The derivative instruments used by the Competitive Energy
businesses include forward contracts, futures, swaps, and exchange-traded and
over-the-counter options. In addition, the Competitive Energy businesses also
manage commodity risk with contracts that are not classified as
derivatives. The two primary risk management objectives are (1) to
manage the spread between the cost of fuel used to operate electric generation
plants and the revenue received from the sale of the power produced by those
plants, and (2) to manage the spread between retail sales commitments and the
cost of supply used to service those commitments to ensure stable and known
minimum cash flows, and lock in favorable prices and margins when they become
available. To a lesser extent, Conectiv Energy also engages in energy
marketing activities. Energy marketing activities consist primarily
of wholesale natural gas and fuel oil marketing; the activities of the
short-term power desk, which generates margin by capturing price differences
between power pools, and locational and timing differences within a power pool;
and prior to October 31, 2006, provided operating services under an
agreement with an unaffiliated generating plant. PHI collectively
refers to these energy marketing activities, including its commodity risk
management activities, as “other energy commodity” activities and identifies
this activity separately from the discontinued proprietary trading activity that
was discontinued in 2003.
Conectiv Energy assesses risk on a
total portfolio basis and by component (e.g. generation output, generation fuel,
load supply, etc.). Portfolio risk combines the
generation
fleet,
load obligations, miscellaneous commodity sales and
hedges. Derivatives designated as cash flow and fair value hedges
(Accounting Hedges) are matched against each component using the product or
products that most closely represent the underlying hedged item. The
total portfolio is risk managed based on its megawatt position by
month. If the total portfolio becomes too long or too short for a
period as determined in accordance with Conectiv Energy’s policies, steps are
taken to reduce or increase hedges. Portfolio-level hedging includes
the use of Accounting Hedges, derivatives that are being marked-to-market
through earnings, and other physical commodity purchases and sales.
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 delivery to customers. Pepco Energy Services accounts for its
futures and swap contracts as cash flow hedges of forecasted
transactions. Its options contracts are marked-to-market through
current earnings. Its forward contracts are accounted for using
standard accrual accounting since these contracts meet the requirements for
normal purchase and sale accounting under SFAS No. 133.
Policies and practices designed to
minimize credit risk exposure to wholesale energy counterparties include, among
other things, formal credit policies, regular assessment of counterparty
creditworthiness and the establishment of a credit limit for each counterparty,
monitoring procedures that include stress testing, the use of standard
agreements which allow for the netting of positive and negative exposures
associated with a single counterparty and collateral requirements under certain
circumstances, and the establishment of reserves for credit losses.
PHI and its subsidiaries also use
derivative instruments from time to time to mitigate the effects of fluctuating
interest rates on debt incurred in connection with the operation of their
businesses. In June 2002, PHI entered into several treasury lock
transactions in anticipation of the issuance of several series of fixed rate
debt commencing in July 2002. There remained a loss balance of $28.8
million in Accumulated Other Comprehensive Income (AOCI) at December 31,
2007 related to this transaction. The portion expected to be
reclassified to earnings during the next 12 months is $3.3
million. In addition, interest rate swaps have been executed in
support of PCI’s medium-term note program.
PCI has entered into interest rate swap
agreements for the purpose of managing its overall borrowing rate and managing
its interest rate exposure associated with debt it has issued. PCI’s
outstanding fixed rate debt issued under its Medium-Term Note program was
swapped into variable rate debt in a transaction entered into in December 2001,
which matures in December 2008. All of PCI’s hedges on variable rate
debt issued under its Medium-Term Note program matured during 2005.
The table below provides detail on
effective cash flow hedges under SFAS No. 133 included in PHI’s
Consolidated Balance Sheet as of December 31, 2007. Under SFAS
No. 133, cash flow hedges are marked-to-market on the balance sheet with
corresponding adjustments to AOCI. The data in the table indicates
the magnitude of the effective cash flow hedges by hedge type (i.e., other
energy commodity and interest rate hedges), maximum term, and portion expected
to be reclassified to earnings during the next 12 months.
|
Cash
Flow Hedges Included in Accumulated Other Comprehensive Loss
(Millions
of dollars)
|
|
Contracts
|
Accumulated
OCI
(Loss)
After-tax (a)
|
Portion
Expected
to
be Reclassified
to
Earnings during
the
Next 12 Months
|
Maximum
Term
|
|
Other
Energy Commodity
|
$ (9.2)
|
$ 7.1
|
48 months
|
|
Interest
Rate
|
(28.8)
|
(3.3)
|
296 months
|
|
Total
|
$(38.0)
|
$ 3.8
|
|
|
|
|
|
(a)
|
Accumulated
Other Comprehensive Loss as of December 31, 2007, includes a $(7.5)
million balance related to minimum pension liability. This
balance is not included in this table as there is not a cash flow hedge
associated with it.
|
The following table shows, in millions
of dollars, the pre-tax gain (loss) recognized in earnings for cash flow hedge
ineffectiveness for the years ended December 31, 2007, 2006, and 2005, and
where they were reported in the Consolidated Statements of Earnings during the
period.
|
|
2007
|
2006
|
2005
|
|
Operating
Revenue
|
$(2.3)
|
$ .4
|
$ 3.0
|
|
Fuel
and Purchased Energy Expenses
|
(.2)
|
(.3)
|
(2.7)
|
|
Total
|
$(2.5)
|
$ .1
|
$ .3
|
|
|
|
|
|
In connection with their other energy
commodity activities, the Competitive Energy businesses designate certain
derivatives as fair value hedges. The net pre-tax gains/(losses)
recognized during the twelve months ended December 31, 2007, 2006 and 2005
included in the Consolidated Statements of Earnings for fair value hedges and
the associated hedged items are shown in the following table (in millions of
dollars).
|
|
2007
|
2006
|
2005
|
|
(Loss)/Gain
on Derivative Instruments
|
$ (9.5)
|
$ .2
|
$-
|
|
Gain/(Loss)
on Hedged Items
|
$ 9.7
|
$(.2)
|
$-
|
For the years ended 2007 and 2006,
losses of $1.8 million and $.3 million, respectively, were reclassified from
other comprehensive income (OCI) to earnings because the forecasted hedged
transactions were deemed to be no longer probable.
In connection with their other energy
commodity activities, the Competitive Energy businesses hold certain derivatives
that do not qualify as hedges. Under SFAS No. 133, these derivatives
are marked-to-market through earnings with corresponding adjustments on the
balance sheet. The pre-tax gains (losses) on these derivatives are
included in “Competitive Energy Operating Revenues” and are summarized in the
following table, in millions of dollars, for the years ended December 31,
2007, 2006, and 2005.
|
|
2007
|
2006
|
2005
|
|
Proprietary
Trading
(a)
|
$ -
|
$ -
|
$ .1
|
|
Other
Energy Commodity (b)
|
8.7
|
64.7
|
37.8
|
|
Total
|
$ 8.7
|
$64.7
|
$37.9
|
|
|
|
|
|
|
(a)
|
PHI
discontinued its proprietary trading activity in
2003.
|
|
(b)
|
Includes
$.5 million, $.3 million and zero in effective fair value hedge gains for
the years ended December 31, 2007, 2006 and 2005,
respectively.
|
DPL uses derivative instruments
(forward contracts, futures, swaps, and exchange-traded and over-the-counter
options) primarily to reduce gas commodity price volatility while limiting its
firm customers’ exposure to increases in the market price of 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 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 gas cost
rate clause included in DPL’s gas tariff rates approved by the DPSC and are
deferred under SFAS No. 71 until recovered. At December 31, 2007, DPL
had a net deferred derivative payable of $13.1 million, offset by a $13.1
million regulatory asset. At December 31, 2006, DPL had a net
deferred derivative payable of $27.3 million, offset by a $28.5 million
regulatory asset.
(14) EXTRAORDINARY
ITEM
On April 19, 2005, ACE, the staff of
the NJBPU, the New Jersey Ratepayer Advocate, and active intervenor parties
agreed on a settlement in ACE’s electric distribution rate case. As a
result of this settlement, ACE reversed $15.2 million in accruals related to
certain deferred costs that are now deemed recoverable. The after-tax
credit to income of $9.0 million is classified as an extraordinary gain in the
2005 financial statements since the original accrual was part of an
extraordinary charge in conjunction with the accounting for competitive
restructuring in 1999.
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, differences between summer and
winter rates, and the scheduled downtime and maintenance of electric generating
units. The totals of the four quarterly basic and diluted earnings
per common share may not equal the basic and diluted earnings per common share
for the year due to changes in the number of common shares outstanding during
the year.
|
|
2007
|
|
|
First
Quarter
|
Second
Quarter
|
Third
Quarter
|
Fourth
Quarter
|
Total
|
|
|
(Millions,
except per share amounts)
|
|
Total
Operating Revenue
|
$2,178.8
|
|
$2,084.3
|
(a)
|
$2,770.3
|
(a)
|
$2,333.0
|
(a)
|
$9,366.4
|
|
|
Total
Operating Expenses
|
2,026.2
|
|
1,928.3
|
(b)
|
2,449.5
|
(b)
(c)
|
2,155.8
|
(b)
|
8,559.8
|
(c)
|
|
Operating
Income
|
152.6
|
|
156.0
|
|
320.8
|
|
177.2
|
|
806.6
|
|
|
Other
Expenses
|
(69.5)
|
|
(70.0)
|
|
(72.9)
|
|
(71.8)
|
|
(284.2)
|
|
|
Preferred
Stock Dividend
Requirements
of Subsidiaries
|
.1
|
|
.1
|
|
.1
|
|
-
|
|
.3
|
|
|
Income
Before Income Tax Expense
|
83.0
|
|
85.9
|
|
247.8
|
|
105.4
|
|
522.1
|
|
|
Income
Tax Expense
|
31.4
|
|
28.7
|
|
80.2
|
(d)
|
47.6
|
|
187.9
|
(d)
|
|
Net
Income
|
51.6
|
|
57.2
|
|
167.6
|
|
57.8
|
|
334.2
|
|
|
Basic
and Diluted Earnings
Per
Share of Common Stock
|
$ .27
|
|
$ .30
|
|
$ .87
|
|
$ .29
|
|
$ 1.72
|
|
|
Cash
Dividends Per Common Share
|
$ .26
|
|
$ .26
|
|
$ .26
|
|
$ .26
|
|
$ 1.04
|
|
|
|
2006
|
|
|
First
Quarter
|
Second
Quarter
|
Third
Quarter
|
Fourth
Quarter
|
Total
|
|
|
(Millions,
except per share amounts)
|
|
Total
Operating Revenue
|
$1,951.9
|
|
$1,916.6
|
|
$2,589.9
|
|
$1,904.5
|
|
$8,362.9
|
|
|
Total
Operating Expenses
|
1,798.0
|
|
1,753.4
|
|
2,347.1
|
|
1,771.1
|
|
7,669.6
|
(f)
|
|
Operating
Income
|
153.9
|
|
163.2
|
|
242.8
|
|
133.4
|
|
693.3
|
|
|
Other
Expenses
|
(61.5)
|
(e)
|
(72.5)
|
|
(76.2)
|
|
(72.2)
|
|
(282.4)
|
|
|
Preferred
Stock Dividend
Requirements
of Subsidiaries
|
.4
|
|
.3
|
|
.3
|
|
.2
|
|
1.2
|
|
|
Income
Before Income Tax Expense
|
92.0
|
|
90.4
|
|
166.3
|
|
61.0
|
|
409.7
|
|
|
Income
Tax Expense
|
35.2
|
|
39.2
|
|
62.3
|
|
24.7
|
|
161.4
|
|
|
Net
Income
|
56.8
|
|
51.2
|
|
104.0
|
|
36.3
|
|
248.3
|
|
|
Basic
and Diluted Earnings
Per
Share of Common Stock
|
$ .29
|
|
$ .27
|
|
$ .54
|
|
$ .19
|
|
$ 1.30
|
|
|
Cash
Dividends Per Common Share
|
$ .26
|
|
$ .26
|
|
$ .26
|
|
$ .26
|
|
$ 1.04
|
|
|
|
(a)
|
Includes
adjustment related to timing of recognition of certain operating revenues
which were overstated by $0.5 million and $1.9 million in the second and
third quarters, respectively, and understated by $2.4 million in the
fourth quarter.
|
|
|
(b)
|
Includes
adjustment related to timing of recognition of certain operating expenses
which were overstated by $4.8 million in the fourth quarter and
understated by $1.2 million and $3.6 million in the second and third
quarters, respectively.
|
|
|
(c)
|
Includes
$33.4 million benefit ($20.0 million after-tax) from settlement of Mirant
bankruptcy claims.
|
|
|
(d)
|
Includes
$19.5 million benefit ($17.7 million net of fees) related to Maryland
income tax refund.
|
|
|
(e)
|
Includes
$12.3 million gain ($7.9 million after-tax) on the sale of its equity
interest in a joint venture which owns a wood burning cogeneration
facility.
|
|
|
(f)
|
Includes
$18.9 million of impairment losses ($13.7 million after-tax) related to
certain energy services business
assets.
|
THIS
PAGE LEFT INTENTIONALLY BLANK.
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. Because of 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 assessed its internal
control over financial reporting as of December 31, 2007 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 its internal control over financial reporting was
effective as of December 31, 2007.
This Annual Report on Form 10-K does
not include an attestation report of Pepco’s registered public accounting firm,
PricewaterhouseCoopers LLP, regarding internal control over financial
reporting. Management’s report was not subject to attestation by
PricewaterhouseCoopers LLP pursuant to temporary rules of the Securities and
Exchange Commission that permit Pepco to provide only management’s report in
this Form 10-K.
To the
Shareholder and Board of Directors of
Potomac
Electric Power Company
In our
opinion, the financial statements listed in the accompanying index present
fairly, in all material respects, the financial position of Potomac Electric
Power Company (a wholly owned subsidiary of Pepco Holdings, Inc.) at December
31, 2007 and December 31, 2006, and the results of its operations and its cash
flows for each of the three years in the period ended December 31, 2007 in
conformity with accounting principles generally accepted in the United States of
America. In addition, in our opinion, the financial statement
schedule 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.
As
discussed in Note 8 to the financial statements, the Company changed its manner
of accounting and reporting for uncertain tax positions in 2007.
PricewaterhouseCoopers
LLP
Washington,
DC
|
POTOMAC
ELECTRIC POWER COMPANY
STATEMENTS
OF EARNINGS
|
|
|
|
|
|
|
2006
|
|
2005
|
|
|
(Millions
of dollars)
|
|
|
Operating
Revenue
|
$
|
2,200.9
|
$
|
2,216.5
|
$
|
1,845.3
|
|
|
Operating
Expenses
|
|
|
|
|
|
|
|
|
Fuel
and purchased energy
|
|
1,245.8
|
|
1,299.7
|
|
913.7
|
|
|
Other
operation and maintenance
|
|
300.0
|
|
277.3
|
|
280.3
|
|
|
Depreciation
and amortization
|
|
151.4
|
|
166.2
|
|
161.8
|
|
|
Other
taxes
|
|
289.5
|
|
273.1
|
|
276.1
|
|
|
Effect
of settlement of Mirant bankruptcy claims
|
|
(33.4)
|
|
-
|
|
(70.5)
|
|
|
Gain
on sale of assets
|
|
(.6)
|
|
-
|
|
(72.4)
|
|
|
Total
Operating Expenses
|
|
1,952.7
|
|
2,016.3
|
|
1,489.0
|
|
|
Operating
Income
|
|
248.2
|
|
200.2
|
|
356.3
|
|
|
Other
Income (Expenses)
|
|
|
|
|
|
|
|
|
Interest
and dividend income
|
|
9.4
|
|
5.7
|
|
4.8
|
|
|
Interest
expense
|
|
(81.7)
|
|
(75.5)
|
|
(81.0)
|
|
|
Other
income
|
|
12.1
|
|
13.1
|
|
13.8
|
|
|
Other
expenses
|
|
(.6)
|
|
(.7)
|
|
(1.3)
|
|
|
Total
Other Expenses
|
|
(60.8)
|
|
(57.4)
|
|
(63.7)
|
|
|
|
|
|
|
|
|
|
|
|
Income
Before Income Tax Expense
|
|
187.4
|
|
142.8
|
|
292.6
|
|
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
62.3
|
|
57.4
|
|
127.6
|
|
|
|
|
|
|
|
|
|
|
|
Net
Income
|
|
125.1
|
|
85.4
|
|
165.0
|
|
|
|
|
|
|
|
|
|
|
|
Dividends
on Serial Preferred Stock
|
|
-
|
|
1.0
|
|
1.3
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
Available for Common Stock
|
$
|
125.1
|
$
|
84.4
|
$
|
163.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
accompanying Notes are an integral part of these Financial
Statements.
|
|
POTOMAC
ELECTRIC POWER COMPANY
STATEMENTS
OF COMPREHENSIVE EARNINGS
|
|
|
|
|
2006
|
2005
|
|
(Millions
of dollars)
|
|
|
|
|
Net
income
|
$125.1
|
$85.4
|
$165.0
|
|
Minimum
pension liability adjustment, before income taxes
|
-
|
5.7
|
(4.5)
|
|
Income
tax expense (benefit)
|
-
|
2.3
|
(1.8)
|
|
Other
comprehensive earnings (losses), net of income taxes
|
-
|
3.4
|
(2.7)
|
|
Comprehensive
earnings
|
$125.1
|
$88.8
|
$162.3
|
|
|
|
|
|
|
The
accompanying Notes are an integral part of these Financial
Statements.
|
|
|
POTOMAC
ELECTRIC POWER COMPANY
BALANCE
SHEETS
|
|
|
ASSETS
|
|
|
|
|
|
(Millions
of dollars)
|
|
|
CURRENT
ASSETS
|
|
|
|
|
|
Cash
and cash equivalents
|
$ 19.0
|
|
$ 12.4
|
|
|
Restricted
cash
|
1.2
|
|
-
|
|
|
Accounts
receivable, less allowance for uncollectible
accounts
of $12.5 million and $17.4 million, respectively
|
343.5
|
|
318.3
|
|
|
Materials
and supplies - at average cost
|
45.4
|
|
42.8
|
|
|
Prepayments
of income taxes
|
93.4
|
|
66.5
|
|
|
Prepaid
expenses and other
|
15.1
|
|
25.5
|
|
|
Total
Current Assets
|
517.6
|
|
465.5
|
|
|
INVESTMENTS
AND OTHER ASSETS
|
|
|
|
|
|
Regulatory
assets
|
178.5
|
|
127.7
|
|
|
Prepaid
pension expense
|
152.0
|
|
160.1
|
|
|
Investment
in trust
|
26.5
|
|
29.0
|
|
|
Income
taxes receivable
|
171.2
|
|
-
|
|
|
Restricted
cash and cash equivalents
|
417.3
|
|
-
|
|
|
Other
|
75.4
|
|
99.6
|
|
|
Total
Investments and Other Assets
|
1,020.9
|
|
416.4
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
|
Property,
plant and equipment
|
5,368.9
|
|
5,157.6
|
|
|
Accumulated
depreciation
|
(2,274.4)
|
|
(2,162.5)
|
|
|
Net
Property, Plant and Equipment
|
3,094.5
|
|
2,995.1
|
|
|
TOTAL
ASSETS
|
$4,633.0
|
|
$3,877.0
|
|
|
|
|
|
|
The
accompanying Notes are an integral part of these Financial
Statements.
|
|
POTOMAC
ELECTRIC POWER COMPANY
BALANCE
SHEETS
|
|
LIABILITIES
AND SHAREHOLDER’S EQUITY
|
|
|
|
(Millions
of dollars, except shares)
|
|
|
|
|
|
CURRENT
LIABILITIES
|
|
|
|
Short-term
debt
|
$ 179.9
|
$ 67.1
|
|
Current
maturities of long-term debt
|
128.0
|
210.0
|
|
Accounts
payable and accrued liabilities
|
201.7
|
180.1
|
|
Accounts
payable to associated companies
|
75.8
|
46.0
|
|
Capital
lease obligations due within one year
|
6.0
|
5.5
|
|
Taxes
accrued
|
90.1
|
72.8
|
|
Interest
accrued
|
17.0
|
16.9
|
|
Liabilities
and accrued interest related to uncertain tax positions
|
67.8
|
-
|
|
Other
|
88.9
|
157.3
|
|
Total
Current Liabilities
|
855.2
|
755.7
|
|
DEFERRED
CREDITS
|
|
|
|
Regulatory
liabilities
|
542.4
|
146.8
|
|
Deferred
income taxes , net
|
619.2
|
636.3
|
|
Investment
tax credits
|
12.5
|
14.5
|
|
Other
postretirement benefit obligation
|
57.4
|
69.3
|
|
Income
taxes payable
|
129.0
|
-
|
|
Other
|
70.1
|
62.3
|
|
Total
Deferred Credits
|
1,430.6
|
929.2
|
|
|
|
|
|
LONG-TERM
LIABILITIES
|
|
|
|
Long-term
debt
|
1,111.7
|
990.0
|
|
Capital
lease obligations
|
105.2
|
110.9
|
|
Total
Long-Term Liabilities
|
1,216.9
|
1,100.9
|
|
|
|
|
|
COMMITMENTS
AND CONTINGENCIES (NOTE 10)
|
|
|
| |
|
|
|
SHAREHOLDER’S
EQUITY
|
|
|
|
Common
stock, $.01 par value, authorized 200,000,000 shares,
issued
100 shares
|
-
|
-
|
|
Premium
on stock and other capital contributions
|
533.4
|
531.5
|
|
Retained
earnings
|
596.9
|
559.7
|
|
Total
Shareholder’s Equity
|
1,130.3
|
1,091.2
|
|
|
|
|
|
TOTAL LIABILITIES AND
SHAREHOLDER’S EQUITY
|
$4,633.0
|
$3,877.0
|
|
|
|
|
|
The
accompanying Notes are an integral part of these Financial
Statements.
|
|
POTOMAC
ELECTRIC POWER COMPANY
STATEMENTS
OF CASH FLOWS
|
|
|
|
|
2006
|
|
2005
|
|
(Millions
of dollars)
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
|
Net
Income
|
$ 125.1
|
|
$ 85.4
|
|
$ 165.0
|
|
Adjustments
to reconcile net income to net cash from operating
activities:
|
|
|
|
|
|
|
Depreciation
and amortization
|
151.4
|
|
166.2
|
|
161.8
|
|
Gain
on sale of assets
|
(.6)
|
|
-
|
|
(72.4)
|
|
Effect
of settlement of Mirant bankruptcy claims
|
(33.4)
|
|
-
|
|
(70.5)
|
|
Proceeds
from settlement of Mirant bankruptcy claims
|
507.2
|
|
70.0
|
|
-
|
|
Proceeds
from sale of claims with Mirant
|
-
|
|
-
|
|
112.9
|
|
Reimbursements
to Mirant
|
(108.3)
|
|
-
|
|
-
|
|
Changes
in restricted cash and cash equivalents related to Mirant
settlement
|
(417.3)
|
|
-
|
|
-
|
|
Deferred
income taxes
|
(3.3)
|
|
38.0
|
|
(49.8)
|
|
Investment
tax credit adjustments, net
|
(2.0)
|
|
(2.0)
|
|
(2.0)
|
|
Prepaid
pension expense
|
8.1
|
|
12.2
|
|
9.8
|
|
Other
postretirement benefit obligation
|
(11.9)
|
|
(.7)
|
|
2.9
|
|
Other
deferred charges
|
2.3
|
|
(3.9)
|
|
17.0
|
|
Other
deferred credits
|
6.2
|
|
(3.0)
|
|
(3.6)
|
|
Changes
in:
|
|
|
|
|
|
|
Accounts
receivable
|
(46.2)
|
|
20.6
|
|
(26.3)
|
|
Regulatory
assets and liabilities, net
|
(32.9)
|
|
(18.5)
|
|
(45.1)
|
|
Prepaid
expenses
|
(2.6)
|
|
(1.2)
|
|
(.9)
|
|
Accounts
payable and accrued liabilities
|
52.3
|
|
(27.8)
|
|
59.8
|
|
Interest
and taxes accrued
|
11.5
|
|
(172.2)
|
|
100.6
|
|
Materials
and supplies
|
(2.6)
|
|
(6.0)
|
|
1.4
|
|
Net
Cash From Operating Activities
|
203.0
|
|
157.1
|
|
360.6
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
Investment
in property, plant and equipment
|
(272.2)
|
|
(204.9)
|
|
(177.7)
|
|
Proceeds
from settlement of Mirant bankruptcy claims representing
reimbursement
for investment in property, plant and equipment
|
15.0
|
|
-
|
|
-
|
|
Proceeds
from sale of other assets
|
-
|
|
-
|
|
78.0
|
|
Change
in restricted cash
|
(1.2)
|
|
-
|
|
-
|
|
Net
other investing activity
|
2.0
|
|
28.5
|
|
(.2)
|
|
Net
Cash Used By Investing Activities
|
(256.4)
|
|
(176.4)
|
|
(99.9)
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
Dividends
paid to Pepco Holdings
|
(86.0)
|
|
(99.0)
|
|
(62.9)
|
|
Dividends
paid on preferred stock
|
-
|
|
(1.0)
|
|
(1.3)
|
|
Issuances
of long-term debt
|
250.0
|
|
109.5
|
|
175.0
|
|
Reacquisition
of long-term debt
|
(210.0)
|
|
(159.5)
|
|
(225.0)
|
|
Issuances
(repayments) of short-term debt, net
|
112.8
|
|
67.1
|
|
(14.0)
|
|
Redemption
of preferred stock
|
-
|
|
(21.5)
|
|
(5.5)
|
|
Net
other financing activities
|
(6.8)
|
|
4.7
|
|
2.9
|
|
Net
Cash From (Used By) Financing Activities
|
60.0
|
|
(99.7)
|
|
(130.8)
|
|
|
|
|
|
|
|
|
Net
Increase (Decrease) in Cash and Cash Equivalents
|
6.6
|
|
(119.0)
|
|
129.9
|
|
Cash
and Cash Equivalents at Beginning of Year
|
12.4
|
|
131.4
|
|
1.5
|
|
CASH
AND CASH EQUIVALENTS AT END OF YEAR
|
$ 19.0
|
$
|
$ 12.4
|
|
$ 131.4
|
| |
|
|
|
|
|
|
NONCASH
ACTIVITIES
|
|
|
|
|
|
|
Asset
retirement obligations associated with removal
costs
transferred to regulatory liabilities
|
$ 5.0
|
|
$ 27.7
|
|
$ (12.3)
|
|
Capital
contribution in respect of certain intercompany
transactions
|
$ 1.9
|
|
$ 24.1
|
|
$ -
|
| |
|
|
|
|
|
|
SUPPLEMENTAL
DISCLOSURE OF CASH FLOW INFORMATION
|
|
|
|
|
|
|
Cash paid
for interest (net of capitalized interest of $4.7 million,
$1.5
million
and $1.6 million, respectively) and paid for income
taxes:
|
|
|
|
|
|
|
Interest
|
$ 77.5
|
|
$ 73.4
|
|
$ 77.8
|
|
Income
taxes
|
$ 61.0
|
|
$128.1
|
|
$ 80.3
|
|
The
accompanying Notes are an integral part of these Financial
Statements.
|
|
POTOMAC
ELECTRIC POWER COMPANY
STATEMENTS
OF SHAREHOLDER’S EQUITY
|
|
|
Common
Stock
Shares Par
Value
|
Premium
on
Stock
|
Capital
Stock
Expense
|
Accumulated
Other
Comprehensive
Earnings
(Loss)
|
Retained
Earnings
|
|
(Millions
of dollars, except shares)
|
|
|
|
|
|
|
|
|
100
|
$ -
|
$ 507.5
|
$ (.5)
|
$ (.7)
|
$473.5
|
|
Net
Income
|
-
|
-
|
-
|
-
|
-
|
165.0
|
|
Other
comprehensive loss
|
-
|
-
|
-
|
-
|
(2.7)
|
-
|
|
Dividends:
|
|
|
|
|
|
|
|
Preferred
stock
|
-
|
-
|
-
|
-
|
-
|
(1.3)
|
|
To
Pepco Holdings
|
-
|
-
|
-
|
-
|
-
|
(62.9)
|
|
Preferred
stock redemption
|
-
|
-
|
-
|
.1
|
-
|
-
|
|
|
100
|
-
|
507.5
|
(.4)
|
(3.4)
|
574.3
|
|
Net
Income
|
-
|
-
|
-
|
-
|
-
|
85.4
|
|
Other
comprehensive earnings
|
-
|
-
|
-
|
-
|
3.4
|
-
|
|
Dividends:
|
|
|
|
|
|
|
|
Preferred
stock
|
-
|
-
|
-
|
-
|
-
|
(1.0)
|
|
To
Pepco Holdings
|
-
|
-
|
-
|
-
|
-
|
(99.0)
|
|
Capital
contributions
|
-
|
-
|
24.1
|
-
|
-
|
-
|
|
Preferred
stock redemption
|
-
|
-
|
(.1)
|
.4
|
-
|
-
|
|
|
100
|
-
|
531.5
|
-
|
-
|
559.7
|
|
Net
Income
|
-
|
-
|
-
|
-
|
-
|
125.1
|
|
Other
comprehensive earnings
|
-
|
-
|
-
|
-
|
-
|
-
|
|
Dividends:
|
|
|
|
|
|
|
|
Preferred
stock
|
-
|
-
|
-
|
-
|
-
|
-
|
|
To
Pepco Holdings
|
-
|
-
|
-
|
-
|
-
|
(86.0)
|
|
Capital
contributions
|
-
|
-
|
1.9
|
-
|
-
|
-
|
|
Cumulative
Effect Adjustment Related
to
the Implementation of FIN 48
|
-
|
-
|
-
|
-
|
-
|
(1.9)
|
|
|
100
|
$ -
|
$ 533.4
|
$ -
|
$ -
|
$596.9
|
|
|
|
|
|
|
|
|
|
The
accompanying Notes are an integral part of these Financial
Statements.
|
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 Washington,
D.C. and major portions of Prince George’s and Montgomery Counties in suburban
Maryland. Pepco provides Default Electricity Supply, which is the
supply of electricity at regulated rates to retail customers in its territories
who do not elect to purchase electricity from a competitive supplier, in both
the District of Columbia and Maryland. Default Electricity Supply is
known as Standard Offer Service (SOS) in both the District of Columbia and
Maryland. Pepco is a wholly owned subsidiary of Pepco Holdings, Inc.
(Pepco Holdings or PHI).
(2) SUMMARY OF 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 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 estimates used by Pepco
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, unbilled revenue calculations, the
assessment of the probability of recovery of regulatory assets, 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 that are probable and reasonably estimable.
Adjustment to Pepco’s
Previously Recorded Delivery Taxes
In 2006, Pepco recorded an adjustment
to correct previously recorded District of Columbia delivery tax
amounts. This adjustment reduced Pepco’s earnings for the twelve
months ended December 31, 2006 by $2.9 million.
Change in Accounting
Estimates
During 2007, as a result of the
depreciation study presented as part of Pepco's Maryland rate case, the Maryland
Public Service Commission (MPSC) approved new lower depreciation rates for
Pepco’s Maryland distribution assets. This resulted in lower depreciation
expense of approximately $18.8 million for the last six months of
2007.
During 2005, Pepco recorded the impact
of an increase in estimated unbilled revenue (electricity delivered to the
customer but not yet billed), primarily reflecting a change in
Pepco’s
unbilled
revenue estimation process. This modification in accounting estimate
increased net earnings for the year ended December 31, 2005 by
approximately $2.2 million.
Revenue
Recognition
Pepco recognizes revenue upon delivery
of electricity to its customers, including amounts for services rendered, but
not yet billed (unbilled revenue). Pepco recorded amounts for
unbilled revenue of $81.9 million and $82.0 million as of December 31, 2007
and 2006, respectively. 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 power line losses (estimates
of electricity expected to be lost in the process of its transmission and
distribution to customers), all of which are inherently uncertain and
susceptible to change from period to period, the impact of which could be
material.
The 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 Revenues.” Accruals for 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 de minimis.
Regulation of Power Delivery
Operations
Pepco is regulated by the MPSC and the
District of Columbia Public Service Commission (DCPSC). The
transmission and wholesale sale 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 provisions of
Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the
Effects of Certain Types of Regulation.” SFAS No. 71 allows regulated entities,
in appropriate circumstances, to establish regulatory assets and to defer the
income statement impact of certain costs that are expected to be recovered in
future rates. Management’s assessment of the probability of recovery
of regulatory assets requires judgment and interpretation of laws, regulatory
commission orders, and other factors. Should existing facts or
circumstances change in the future to indicate that a regulatory asset is not
probable of recovery, the regulatory asset will be charged to
earnings.
As part of the new electric service
distribution base rates for Pepco approved by the MPSC, effective June 16, 2007,
the MPSC approved a bill stabilization adjustment mechanism (BSA) for retail
customers. See Note 10 “Commitments and Contingencies – Regulatory
and Other Matters – Rate Proceedings.” For customers to which the BSA
applies, Pepco recognizes distribution revenue based on an approved distribution
charge per customer. From a revenue recognition standpoint, the BSA
thus decouples the distribution revenue recognized in a reporting period from
the amount of power delivered during the period. Pursuant to this
mechanism, Pepco recognizes either (a) a positive adjustment equal to the amount
by which revenue from Maryland retail distribution sales falls short of the
revenue that Pepco is entitled to earn based on the approved distribution charge
per customer or (b) 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 positive Revenue Decoupling
Adjustment is recorded as a regulatory asset and a negative Revenue Decoupling
Adjustment is recorded as a regulatory liability. The net Revenue
Decoupling Adjustment at December 31, 2007 is a regulatory asset and is included
in the “Other” line item on the table of regulatory asset balances listed
below.
|
|
2007
|
2006
|
|
|
|
(Millions
of dollars)
|
|
|
Deferred
recoverable income taxes
|
$ 60.6
|
$ 34.9
|
|
|
Deferred
debt extinguishment costs
|
39.9
|
42.7
|
|
|
Phase
in credits
|
1.4
|
1.3
|
|
|
Other
|
76.6
|
48.8
|
|
|
Total
Regulatory Assets
|
$178.5
|
$127.7
|
|
|
|
|
|
|
|
|
2007
|
2006
|
|
|
|
(Millions
of dollars)
|
|
|
Deferred
income taxes due to customers
|
$ 21.4
|
$ 29.9
|
|
|
Asset
removal costs
|
97.6
|
92.7
|
|
|
Settlement
proceeds - Mirant bankruptcy claims
|
414.6
|
-
|
|
|
Other
|
8.8
|
24.2
|
|
|
Total
Regulatory Liabilities
|
$542.4
|
$146.8
|
|
|
|
|
|
|
A description of the regulatory assets
and regulatory liabilities is as follows:
Deferred Recoverable Income
Taxes: Represents a receivable
from our customers for tax benefits Pepco has previously flowed through before
the company was ordered to provide deferred income taxes. As the
temporary differences between the financial statement and tax basis of assets
reverse, the deferred recoverable balances are reversed. There is no
return on these deferrals.
Deferred Debt Extinguishment
Costs: Represents the costs of debt extinguishment for which
recovery through regulated utility rates is considered probable and will be
amortized to interest expense during the authorized rate recovery
period. A return is received on these deferrals.
Phase In
Credits: Represents phase-in credits for participating
Maryland residential and small commercial customers to mitigate the immediate
impact of significant rate increases due to energy costs in 2006. The
deferral period for Maryland was June 1, 2006 to June 1, 2007, with the recovery
to occur over an 18-month period beginning June 2007. The Maryland
deferral will be recovered from participating customers at a rate per
kilowatt-hour based on energy usage during the recovery period.
Other: Represents
miscellaneous regulatory assets that generally are being amortized over 1 to 20
years and generally do not receive a return.
Deferred Income Taxes Due to
Customers: Represents the portion of deferred income tax
liabilities applicable to Pepco’s utility operations that has not been reflected
in current customer rates for which future payment to customers is
probable. As temporary differences between the financial statement
and tax basis of assets reverse, deferred recoverable income taxes are
amortized.
Asset Removal
Costs: Represents Pepco’s asset retirement obligation
associated with removal costs accrued using public service commission approved
depreciation techniques for transmission, distribution, and general utility
property.
Settlement proceeds - Mirant
Bankruptcy Claims: Represents the $413.9 million of net
proceeds received by Pepco from settlement of a Mirant Corporation (Mirant)
claim, plus interest earned, which will be used to pay for future above-market
capacity and energy purchases under a power purchase agreement entered into with
Panda-Brandywine L.P. (Panda) over the remaining life of the agreement, which
extends through 2021 (the Panda PPA).
Other: Includes
miscellaneous regulatory liabilities such as the over-recovery of procurement,
transmission and administrative costs associated with Maryland and District of
Columbia SOS.
Asset Retirement
Obligations
In accordance with SFAS No. 143,
“Accounting for Asset Retirement Obligations” and Financial Accounting Standards
Board (FASB) Interpretation No. (FIN) 47, asset removal costs are recorded as
regulatory liabilities. At December 31, 2007 and 2006, $97.6 million and
$92.7 million, respectively, are reflected as regulatory liabilities in the
accompanying Balance Sheets. Additionally, in 2005, Pepco recorded
immaterial conditional asset retirement obligations for underground storage
tanks. Accretion for these asset retirement obligations has been
recorded as a regulatory asset.
Cash and Cash
Equivalents
Cash and cash equivalents include cash
on hand, money market funds, and commercial paper 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. Deposits in the money pool were zero and $.4 million at
December 31, 2007 and 2006, respectively.
Restricted Cash and Cash
Equivalents
The restricted cash that is included in
Current Assets and the restricted cash and cash equivalents that is included in
Investments and Other Assets represent (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 solely to
fund the
future above-market capacity and energy purchase costs under the Panda
PPA. The classification as current or non-current conforms to the
classification of the related liabilities.
Accounts Receivable and
Allowance for Uncollectible Accounts
Pepco’s accounts receivable balances
primarily consist 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
uses the allowance method to account for uncollectible accounts
receivable.
Investment in
Trust
Represents assets held in a trust for
the benefit of participants in the Pepco Owned Life Insurance plan.
Capitalized Interest and
Allowance for Funds Used During Construction
In accordance with the provisions of
SFAS No. 71, utilities can capitalize as Allowance for Funds Used During
Construction (AFUDC) the capital costs of financing the construction of plant
and equipment. The debt portion of AFUDC is recorded as a reduction
of “interest expense” and the equity portion of AFUDC is credited to “other
income” in the accompanying Statements of Earnings.
Pepco recorded AFUDC for borrowed funds
of $4.7 million, $1.5 million, and $1.6 million for the years ended
December 31, 2007, 2006, and 2005, respectively.
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 issues. Costs associated with the redemption of debt
are also deferred and amortized over the lives of the new issues.
Pension and Other
Postretirement Benefit Plans
Pepco Holdings sponsors a
non-contributory retirement plan that covers substantially all employees of
Pepco (the PHI Retirement Plan) 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 SFAS No. 87, “Employers’ Accounting for Pensions,”
as amended by SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension
and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106
and 132(R)” (SFAS No. 158), and its other postretirement benefits in accordance
with SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than
Pensions,” as amended by SFAS No. 158. Pepco Holdings’ financial
statement disclosures were prepared in
accordance
with SFAS No. 132, “Employers’ Disclosures about Pensions and Other
Postretirement Benefits,” as amended by SFAS No. 158.
Pepco participates in benefit plans
sponsored by Pepco Holdings and as such, the provisions of SFAS No. 158 do not
have an impact on its financial condition and cash flows.
Severance
Costs
In 2004, PHI’s Power Delivery business
reduced its work force through a combination of retirements and targeted
reductions. This plan met the criteria for the accounting treatment
provided under SFAS No. 88, “Employer’s Accounting for Settlements and
Curtailments of Defined Benefit Pension Plans and for Termination Benefits,” and
SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal
Activities,” as applicable. A roll forward of Pepco’s severance
accrual balance is as follows (Millions of dollars).
|
|
$
|
-
|
|
Accrued
during 2006
|
|
1.6
|
|
Payments/reversals
during 2006
|
|
(.1)
|
|
|
|
1.5
|
|
Accrued
during 2007
|
|
-
|
|
Payments
during 2007
|
|
(1.5)
|
|
|
$
|
-
|
|
|
|
|
All of the severance liability was paid
by December 31, 2007. Employees had the option of taking
severance payments in a lump sum or over a period of time.
Long-Lived Assets
Impairment
Pepco evaluates certain long-lived
assets to be held and used (for example, equipment and real estate) to determine
if they are impaired whenever events or changes in circumstances indicate that
their carrying amount 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 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 sum of its expected future undiscounted cash
flows is less than its carrying amount.
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 amount exceeds their fair value
including costs to sell.
Property, Plant and
Equipment
Property, plant and equipment are
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 under the provisions of SFAS No.
144. Upon retirement, the cost of regulated property, net of salvage,
is charged to accumulated depreciation. For additional information
regarding the treatment of removal obligations, see the “Asset Retirement
Obligations” section included in this Note.
The annual provision for depreciation
on electric property, plant and equipment is computed on the 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. Property, plant and equipment other
than electric facilities is generally depreciated on a straight-line basis over
the useful lives of the assets. The system-wide composite
depreciation rates for 2007, 2006, and 2005 for Pepco’s transmission and
distribution system property were approximately 3.0%, 3.5%, and 3.4%,
respectively.
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.
In 2006, the FASB issued FIN 48,
“Accounting for Uncertainty in Income Taxes” (FIN 48). FIN 48
clarifies the criteria for recognition of tax benefits in accordance with SFAS
No. 109, “Accounting for Income Taxes,” and prescribes a financial statement
recognition threshold and measurement attribute for a tax position taken or
expected to be taken in a tax return. Specifically, it clarifies that
an entity’s tax benefits must be “more likely than not” of being sustained prior
to recording the related tax benefit in the financial statements. If
the position drops below the “more likely than not” standard, the benefit can no
longer be recognized. FIN 48 also provides guidance on derecognition,
classification, interest and penalties, accounting in interim periods,
disclosure, and transition.
On May 2, 2007, the FASB issued FASB
Staff Position (FSP) FIN 48-1, “Definition of Settlement in FASB Interpretation
No. 48” (FIN 48-1), which provides guidance on how an enterprise should
determine whether a tax position is effectively settled for the purpose of
recognizing previously unrecognized tax benefits. Pepco applied the
guidance of FIN 48-1 with its adoption of FIN 48 on January 1,
2007.
The financial statements include
current and deferred income taxes. Current income taxes represent the amounts 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 and tax basis of existing assets and liabilities and 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. For additional
information, see the discussion under “Regulation of Power Delivery Operations”
above.
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 under/over
payments of income taxes, interest on unrecognized tax benefits, and tax-related
penalties in income tax expense.
Investment tax credits from utility
plants purchased in prior years are reported on the Balance Sheets as
“Investment tax credits.” These investment tax credits are being
amortized to income over the useful lives of the related utility
plant.
FIN 46R, “Consolidation of
Variable Interest Entities”
Due to a variable element in the
pricing structure of the Panda PPA, Pepco potentially assumes the variability in
the operations of the plants related to this PPA and therefore has a variable
interest in the entity. In accordance with the provisions of FIN 46R
(revised December 2003), entitled “Consolidation of Variable Interest Entities,”
(FIN 46R), Pepco continued, during the year ended December 31, 2007, to
conduct exhaustive efforts to obtain information from this entity, but was
unable to obtain sufficient information to conduct the analysis required under
FIN 46R to determine whether the entity was a variable interest entity or if
Pepco was the primary beneficiary. As a result, Pepco has applied the
scope exemption from the application of FIN 46R for enterprises that have
conducted exhaustive efforts to obtain the necessary information, but have not
been able to obtain such information.
Power purchases related to the Panda
PPA for the years ended December 31, 2007, 2006 and 2005, were approximately $85
million, $79 million and $91 million, respectively.
Other Non-Current
Assets
The other assets balance principally
consists of deferred compensation trust assets and unamortized debt
expense.
Other Current
Liabilities
The other current liability balance
principally consists of customer deposits, accrued vacation liability, and other
miscellaneous liabilities. For 2006, this balance included $70
million paid to Pepco by Mirant in settlement of claims resulting from the
Mirant bankruptcy.
Other Deferred
Credits
The other deferred credits balance
principally consists of miscellaneous deferred liabilities.
Dividend
Restrictions
In addition to its future financial
performance, the ability of Pepco to pay dividends is subject to limits imposed
by: (i) state corporate and regulatory laws, which impose limitations on the
funds that can be used to pay dividends and, in the case of regulatory laws, may
require the prior approval of Pepco’s utility regulatory commissions before
dividends can be paid 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 $75.0 million and $11.7 million
of restricted retained earnings at December 31, 2007 and 2006,
respectively.
Reclassifications
Certain prior year amounts have been
reclassified in order to conform to current year presentation.
Newly
Adopted Accounting Standards
FSP FTB 85-4-1, “Accounting for Life
Settlement Contracts by Third-Party Investors”
In March 2006, the FASB issued FSP FASB
Technical Bulletin (FTB) 85-4-1, “Accounting for Life Settlement Contracts by
Third-Party Investors” (FSP FTB 85-4-1). This FSP provides initial
and subsequent measurement guidance and financial statement presentation and
disclosure guidance for investments by third-party investors in life settlement
contracts. FSP FTB 85-4-1 also amends certain provisions of FTB
No. 85-4, “Accounting for Purchases of Life Insurance,” and SFAS No. 133,
“Accounting for Derivative Instruments and Hedging Activities.” The
guidance in FSP FTB 85-4-1 applies prospectively for all new life settlement
contracts and is effective for fiscal years beginning after June 15, 2006 (year
ended December 31, 2007 for Pepco). Implementation of FSP FTB
85-4-1 did not have a material impact on Pepco’s overall financial condition,
results of operations, or cash flows.
EITF Issue No. 06-3, “Disclosure
Requirements for Taxes Assessed by a Governmental Authority on Revenue-producing
Transactions”
On June 28, 2006, the FASB ratified
Emerging Issues Task Force (EITF) Issue No. 06-3, “Disclosure Requirements for
Taxes Assessed by a Governmental Authority on Revenue-producing Transactions”
(EITF 06-3). EITF 06-3 provides guidance on an entity’s
disclosure of its accounting policy regarding the gross or net presentation of
certain taxes and provides that if taxes included in gross revenues are
significant, a company should disclose the amount of such taxes for each period
for which an income statement is presented (i.e., both interim and annual
periods). Taxes within the scope of EITF 06-3 are those that are imposed on and
concurrent with a specific revenue-producing transaction. Taxes assessed on an
entity’s activities over a period of time are not within the scope of EITF
06-3. Pepco implemented EITF 06-3 during the first quarter of
2007. Taxes included in Pepco’s gross revenues were $243.1 million,
$223.4 million and $229.4 million for the twelve months ended December 31, 2007,
2006 and 2005, respectively.
FSP AUG AIR-1, “Accounting for Planned
Major Maintenance Activities”
On September 8, 2006, the FASB issued
FSP American Institute of Certified Public Accountants Industry Audit Guide,
Audits of Airlines--”Accounting for Planned Major Maintenance Activities” (FSP
AUG AIR-1), which prohibits the use of the accrue-in-advance method of
accounting for planned major maintenance activities in annual and interim
financial reporting periods for all industries. FSP AUG AIR-1 is
effective the first fiscal year beginning after December 15, 2006 (year
ended December 31, 2007 for Pepco). Implementation of FSP AUG
AIR-1 did not have a material impact on Pepco’s overall financial condition,
results of operations, or cash flows.
EITF Issue No. 06-5, “Accounting for
Purchases of Life Insurance -- Determining the Amount That Could Be Realized in
Accordance with FASB Technical Bulletin No. 85-4, Accounting for Purchases of
Life Insurance”
On September 20, 2006, the FASB
ratified EITF Issue No. 06-5, “Accounting for Purchases of Life Insurance --
Determining the Amount That Could Be Realized in Accordance with FASB Technical
Bulletin No. 85-4, Accounting for Purchases of Life Insurance” (EITF 06-5) which
provides guidance on whether an entity should consider the contractual ability
to surrender all of the individual-life policies (or certificates under a group
life policy) together when determining the amount that could be realized in
accordance with FTB 85-4, and whether a guarantee of the additional value
associated with the group life policy affects that
determination. EITF 06-5 provides that a policyholder should (i)
determine the amount that could be realized under the insurance contract
assuming the surrender of an individual-life by individual-life policy (or
certificate by certificate in a group policy) and (ii) not discount the cash
surrender value component of the amount that could be realized when contractual
restrictions on the ability to surrender a policy exist unless contractual
limitations prescribe that the cash surrender value component of the amount that
could be realized is a fixed amount, in which case the amount that could be
realized should be discounted in accordance with Accounting Principles Board of
the American Institute of Certified Public Accountants Opinion
21. EITF 06-5 is effective for fiscal years beginning after December
15, 2006 (year ended December 31, 2007 for
Pepco). Implementation of EITF 06-5 did not have a material impact on
Pepco’s overall financial condition, results of operations, cash flows, or
footnote disclosure requirements.
Recently
Issued Accounting Standards, Not Yet Adopted
SFAS No. 157, “Fair Value
Measurements”
In September 2006, the FASB issued SFAS
No. 157, "Fair Value Measurements" (SFAS No. 157) which defines fair value,
establishes a framework for measuring fair value in GAAP, and expands
disclosures about fair value measurements. SFAS No. 157 applies under
other accounting pronouncements that require or permit fair value measurements
and does not require any new fair value measurements. However, it is
possible that the application of this Statement will change current practice
with respect to the definition of fair value, the methods used to measure fair
value, and the disclosures about fair value measurements.
The provisions of SFAS No. 157, as
issued, are effective for financial statements issued for fiscal years beginning
after November 15, 2007, and interim periods within those fiscal years (January
1, 2008 for Pepco). On February 6, 2008, the FASB decided to issue
final Staff Positions that will (i) defer the effective date of SFAS No. 157 for
all non-financial assets and non-financial liabilities, except those that are
recognized or disclosed at fair value in the financial statements on a recurring
basis (that is, at least annually) and (ii) remove certain leasing transactions
from the scope of SFAS No. 157. The final Staff Positions will defer
the effective date of SFAS No. 157 to fiscal years beginning after November 15,
2008, and interim periods within those fiscal years for items within the scope
of the final Staff Positions. Pepco has evaluated the impact of SFAS
No. 157 and does not anticipate its adoption will have a material impact on its
overall financial condition, results of operations, cash flows, or footnote
disclosure requirements.
SFAS No. 159, “The Fair Value Option for Financial
Assets and Financial Liabilities - Including an amendment of FASB Statement No.
115”
On February 15, 2007, the FASB issued
SFAS No. 159, “The Fair Value Option for Financial Assets and Financial
Liabilities - Including an amendment of FASB Statement No. 115” (SFAS No. 159)
which permits entities to elect to measure eligible financial instruments at
fair value. The objective of SFAS No. 159 is to improve financial
reporting by providing entities with the opportunity to mitigate volatility in
reported earnings caused by measuring related assets and liabilities differently
without having to apply complex hedge accounting provisions. SFAS No.
159 applies under other accounting pronouncements that require or permit fair
value measurements and does not require any new fair value
measurements. However, it is possible that the application of SFAS
No. 159 will change current practice with respect to the definition of fair
value, the methods used to measure fair value, and the disclosures about fair
value measurements.
SFAS No. 159 establishes presentation
and disclosure requirements designed to facilitate comparisons between companies
that choose different measurement attributes for similar types of assets and
liabilities. SFAS No. 159 requires companies to provide additional
information that will help investors and other users of financial statements to
more easily understand the effect of the company’s choice to use fair value on
its earnings. It also requires entities to display the fair value of
those assets and liabilities for which the company has chosen to use fair value
on the face of the balance sheet. SFAS No. 159 does not eliminate
disclosure requirements included in other accounting standards.
SFAS No. 159 applies to the beginning
of a reporting entity’s first fiscal year that begins after November 15, 2007
(January 1, 2008 for Pepco), with early adoption permitted for an entity that
has also elected to apply the provisions of SFAS No. 157, Fair Value
Measurements. An entity is
prohibited from retrospectively applying SFAS No. 159, unless it chooses early
adoption. SFAS No. 159 also applies to eligible items existing at
November 15, 2007 (or early adoption date). Pepco has evaluated the
impact of SFAS No. 159 and does not anticipate its adoption will have a material
impact on its overall financial condition, results of operations, cash flows, or
footnote disclosure requirements.
SFAS No. 141(R), “Business Combinations
– a replacement of FASB Statement No. 141”
On December 4, 2007, the FASB issued
SFAS No. 141(R), “Business Combinations – a replacement of FASB Statement No.
141” (SFAS No. 141(R)) which replaces FASB Statement No. 141, “Business
Combinations.” This Statement retains the fundamental requirements in
Statement 141 that the acquisition method of accounting (which Statement
141 called the purchase method) be used for all business combinations and for an
acquirer to be identified for each business combination.
SFAS No. 141(R) applies to all
transactions or other events in which an entity (the acquirer) obtains control
of one or more businesses (the acquiree). It does not apply to (i)
the formation of a joint venture, (ii) the acquisition of an asset or a group of
assets that does not constitute a business, (iii) a combination between entities
or businesses under common control and (iv) a combination between not-for-profit
organizations or the acquisition of a for-profit business by a not-for-profit
organization.
SFAS No. 141(R) applies prospectively
to business combinations for which the acquisition date is on or after the
beginning of the first annual reporting period beginning on or after December
15, 2008 (January 1, 2009 for Pepco). An entity may not apply it
before that date.
SFAS No. 160, “Noncontrolling Interests
in Consolidated Financial Statements – an amendment of ARB No. 51”
On December 4, 2007, the FASB issued
SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements –
an amendment of ARB No. 51” (SFAS No. 160) which amends ARB 51 to establish
accounting and reporting standards for the noncontrolling interest in a
subsidiary and for the deconsolidation of a subsidiary. It clarifies
that a noncontrolling interest in a subsidiary is an ownership interest in the
consolidated entity that should be reported as equity in the consolidated
financial statements.
A noncontrolling interest, sometimes
called a minority interest, is the portion of equity in a subsidiary not
attributable, directly or indirectly, to a parent. The objective of SFAS No. 160
is to improve the relevance, comparability, and transparency of the financial
information that a reporting entity provides in its consolidated financial
statements by establishing accounting and reporting standards that require (i)
the ownership interests in subsidiaries held by parties other than the parent be
clearly identified, labeled, and presented in the consolidated statement of
financial position within equity, but separate from the parent’s equity, (ii)
the amount of consolidated net income attributable to the parent and to the
noncontrolling interest be clearly identified and presented on the face of the
consolidated statement of income, (iii) changes in a parent’s ownership interest
while the parent retains its controlling financial interest in its subsidiary be
accounted for consistently. A parent’s ownership interest in a
subsidiary changes if the parent purchases additional ownership interests in its
subsidiary or if the parent sells some of its ownership interests in its
subsidiary. It also changes if the subsidiary reacquires some of its ownership
interests or the subsidiary issues additional ownership interests. All of those
transactions are economically similar, and this Statement requires that they be
accounted for similarly, as equity transactions, (iv) when a subsidiary is
deconsolidated, any retained noncontrolling equity investment in the former
subsidiary be initially measured at fair value. The gain or loss on
the deconsolidation of the subsidiary is measured using the fair value of any
noncontrolling equity investment rather than the carrying amount of that
retained investment and (v) entities provide sufficient disclosures that clearly
identify and distinguish between the interests of the parent and the interests
of the noncontrolling owners.
SFAS No. 160 applies to all entities
that prepare consolidated financial statements, except not-for-profit
organizations, but will affect only those entities that have an outstanding
noncontrolling interest in one or more subsidiaries or that deconsolidate a
subsidiary.
SFAS No. 160 is effective for fiscal
years, and interim periods within those fiscal years, beginning on or after
December 15, 2008 (January 1, 2009, for Pepco). Earlier adoption is
prohibited. SFAS No. 160 shall be applied prospectively as of the
beginning of the fiscal year in which this Statement is initially applied,
except for the presentation and disclosure requirements. The
presentation and disclosure requirements shall be applied retrospectively for
all periods presented. Pepco is currently evaluating the impact SFAS
No. 160 may have on its overall financial condition, results of operations, cash
flows or footnote disclosure requirements.
In accordance with SFAS No. 131,
“Disclosures about Segments of an Enterprise and Related Information,” Pepco has
one segment, its regulated utility business.
(4) LEASING
ACTIVITIES
Lease
Commitments
Pepco leases its consolidated control
center, 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 $7.6 million
over a 25-year period beginning in December 1994 and provides for transfer of
ownership of the system to Pepco for $1 at the end of the lease
term. Under SFAS No. 71, 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. This lease has been treated as an operating
lease for rate-making purposes.
Capital lease assets recorded within
Property, Plant and Equipment at December 31, 2007 and 2006 are comprised
of the following:
|
|
Original
Cost
|
Accumulated
Amortization
|
Net
Book Value
|
|
|
|
(Millions
of dollars)
|
|
|
Transmission
|
$ 76.0
|
$20.5
|
$ 55.5
|
|
|
Distribution
|
76.0
|
20.5
|
55.5
|
|
|
Other
|
2.6
|
2.4
|
.2
|
|
|
Total
|
$154.6
|
$43.4
|
$111.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transmission
|
$ 76.0
|
$18.0
|
$ 58.0
|
|
|
Distribution
|
76.0
|
18.0
|
58.0
|
|
|
Other
|
2.6
|
2.2
|
.4
|
|
|
Total
|
$154.6
|
$38.2
|
$116.4
|
|
|
|
|
|
|
|
The approximate annual commitments
under capital leases are $15.4 million for 2008, $15.2 million for 2009, 2010,
2011 and 2012, and $106.7 million thereafter.
Rental expense for operating leases was
$3.7 million, $3.6 million and $2.5 million for the years ended December 31,
2007, 2006 and 2005, respectively.
Total future minimum operating lease
payments for Pepco as of December 31, 2007 include $3.1 million in 2008, $2.6
million in 2009, $1.9 million in 2010, $1.5 million in 2011, $1.3 million in
2012 and $7.9 million after 2012.
(5) PROPERTY, PLANT AND
EQUIPMENT
Property, plant and equipment is
comprised of the following:
|
|
Original
Cost
|
Accumulated
Depreciation
|
Net
Book
Value
|
|
|
|
(Millions
of dollars)
|
|
|
Distribution
|
$3,910.8
|
$1,669.5
|
$2,241.3
|
|
|
Transmission
|
785.7
|
327.5
|
458.2
|
|
|
Construction
work in progress
|
236.0
|
-
|
236.0
|
|
|
Non-operating
and other property
|
436.4
|
277.4
|
159.0
|
|
|
Total
|
$5,368.9
|
$2,274.4
|
$3,094.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distribution
|
$3,824.2
|
$1,587.4
|
$2,236.8
|
|
|
Transmission
|
722.7
|
312.1
|
410.6
|
|
|
Construction
work in progress
|
174.0
|
-
|
174.0
|
|
|
Non-operating
and other property
|
436.7
|
263.0
|
173.7
|
|
|
Total
|
$5,157.6
|
$2,162.5
|
$2,995.1
|
|
|
|
|
|
|
|
The non-operating and other property
amounts include balances for general plant, distribution and transmission plant
held for future use, intangible plant and non-utility property.
Asset
Sales
In August 2005, Pepco sold for $75
million in cash 384,051 square feet of excess non-utility land located at
Buzzard Point in the District of Columbia. The sale resulted in a pre-tax gain
of $68.1 million, which was recorded as a reduction of Operating Expenses in the
Statements of Earnings.
(6) PENSIONS AND OTHER
POSTRETIREMENT BENEFITS
Pepco accounts for its participation in
the Pepco Holdings benefit plans as participation in a multi-employer
plan. For 2007, 2006, and 2005, Pepco’s allocated share of the
pension and other postretirement net periodic benefit cost incurred by Pepco
Holdings was approximately $22.3 million, $32.1 million, and $28.9 million,
respectively. In 2007 and 2006, Pepco made no contributions to the
PHI Retirement Plan, and $10.3 million and $6.0 million, respectively to
other postretirement benefit plans. At December 31, 2007 and 2006, Pepco’s
prepaid pension expense of $152.0 million and $160.1 million, and
other postretirement benefit obligation of $57.4 million and
$69.3 million, effectively represent assets and benefit obligations
resulting from Pepco’s participation in the Pepco Holdings benefit
plan.
(7) DEBT
LONG-TERM
DEBT
The components of long-term debt are
shown below.
|
|
|
|
At
December 31,
|
|
|
Interest Rate
|
Maturity
|
|
2007
|
|
2006
|
|
|
|
|
|
(Millions
of dollars)
|
|
|
First
Mortgage Bonds
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6.25%
|
2007
|
$
|
-
|
$
|
175.0
|
|
|
6.50%
|
2008
|
|
78.0
|
|
78.0
|
|
|
5.875%
|
2008
|
|
50.0
|
|
50.0
|
|
|
5.75%
(a)
|
2010
|
|
16.0
|
|
16.0
|
|
|
4.95%
(a)(b)
|
2013
|
|
200.0
|
|
200.0
|
|
|
4.65%
(a)(b)
|
2014
|
|
175.0
|
|
175.0
|
|
|
Variable
(a)(b)
|
2022
|
|
109.5
|
|
109.5
|
|
|
5.375%
(a)
|
2024
|
|
38.3
|
|
38.3
|
|
|
5.75%
(a)(b)
|
2034
|
|
100.0
|
|
100.0
|
|
|
5.40%
(a)(b)
|
2035
|
|
175.0
|
|
175.0
|
|
|
6.50%
(a)(b)
|
2037
|
|
250.0
|
|
-
|
|
|
|
|
|
|
|
|
|
|
Total
First Mortgage Bonds
|
|
|
1,191.8
|
|
1,116.8
|
|
|
|
|
|
|
|
|
|
|
Medium-Term
Notes
|
|
|
|
|
|
|
|
7.64%
|
2007
|
|
-
|
|
35.0
|
|
|
6.25%
|
2009
|
|
50.0
|
|
50.0
|
|
|
|
|
|
|
|
|
|
|
Total
long-term debt
|
|
|
1,241.8
|
|
1,201.8
|
|
|
Net
unamortized discount
|
|
|
(2.1)
|
|
(1.8)
|
|
|
Current
maturities of long-term debt
|
|
|
(128.0)
|
|
(210.0)
|
|
|
Total
net long-term debt
|
|
$
|
1,111.7
|
$
|
990.0
|
|
|
|
|
|
|
|
|
|
|
(a)
|
Represents
a series of First Mortgage Bonds issued by Pepco as collateral for an
outstanding series of senior notes or tax-exempt bonds issued by or for
the benefit of Pepco. The maturity date, optional and mandatory
prepayment provisions, if any, interest rate, and interest payment dates
on each series of senior notes or tax-exempt bonds are identical to the
terms of the collateral First Mortgage Bonds by which it is
secured. Payments of principal and interest on a series of
senior notes or 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 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 First Mortgage Bonds issued by Pepco as collateral for an
outstanding series of senior notes as described in footnote (a) above that
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.
|
The outstanding First Mortgage Bonds
are secured by a lien on substantially all of Pepco’s property, plant and
equipment.
The aggregate principal amount of
long-term debt outstanding at December 31, 2007, that will mature in each
of 2008 through 2012 and thereafter is as follows: $128.0 million in
2008, $50.0 million in 2009, $16.0 million in 2010, zero in 2011 and 2012, and
$1,047.8 million thereafter.
Pepco’s long-term debt is subject to
certain covenants. Pepco is in compliance with all
requirements.
SHORT-TERM
DEBT
Pepco, a regulated utility, 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, 2007 and
2006 is as follows.
|
|
2007
|
2006
|
|
|
|
(Millions
of dollars)
|
|
|
Commercial
paper
|
$ 84.0
|
$ 67.1
|
|
|
Intercompany
borrowings
|
95.9
|
-
|
|
|
Total
|
$179.9
|
$ 67.1
|
|
|
|
|
|
|
Commercial
Paper
Pepco maintains an ongoing commercial
paper program of up to $500 million. The commercial paper notes can be issued
with maturities up to 270 days from the date of issue. The commercial paper
program is backed by a $500 million credit facility, described below under the
heading “Credit Facility,” shared with Delmarva Power & Light Company (DPL)
and Atlantic City Electric Company (ACE).
Pepco had $84.0 million of commercial
paper outstanding at December 31, 2007 and $67.1 million of commercial paper
outstanding at December 31, 2006. The weighted average interest rate for
commercial paper issued during 2007 was 5.27% and 5.25% in 2006. The
weighted average maturity for commercial paper issued during 2007 was four days
and during 2006 was five days.
Credit
Facility
PHI, Pepco, DPL and ACE maintain a
credit facility to provide for their respective short-term liquidity
needs.
The aggregate borrowing limit under the
facility is $1.5 billion, all or any portion of which may be used to obtain
loans or to issue letters of credit. PHI’s credit limit under the facility is
$875 million. The credit limit of each of Pepco, DPL and ACE is the
lesser of $500 million and the maximum amount of debt the company is permitted
to have outstanding by its regulatory authorities, except that the aggregate
amount of credit used by Pepco, DPL and ACE at any given time collectively may
not exceed $625 million. The interest rate payable by each company on
utilized funds is based on the prevailing prime rate or Eurodollar rate, plus a
margin that varies according to the credit rating of the
borrower. 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 $150 million. Any swingline loan must be repaid
by the borrower within seven days of receipt thereof. All
indebtedness incurred under the facility is unsecured.
The facility commitment expiration date
is May 5, 2012, with each company having the right to elect to have 100% of the
principal balance of the loans outstanding on the expiration date continued as
non-revolving term loans for a period of one year from such expiration
date.
The facility is intended to serve
primarily as a source of liquidity to support the commercial paper programs of
the respective companies. The companies also are permitted to use the
facility to borrow funds for general corporate purposes and issue letters of
credit. In order for a borrower to use the facility, certain
representations and warranties made by the borrower at the time the credit
agreement was entered into also must be true at the time the facility is
utilized, and the borrower must be in compliance with specified covenants,
including the financial covenant described below. However, a material
adverse change in the borrower’s business, property, and results of operations
or financial condition subsequent to the entry into the credit agreement is not
a condition to the availability of credit under the facility. Among
the covenants to which each of the companies is subject are (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 certain trust preferred
securities and deferrable interest subordinated debt from the definition of
total indebtedness (not to exceed 15% of total capitalization), (ii) a
restriction on sales or other dispositions of assets, other than sales and
dispositions permitted by the credit agreement, and (iii) a restriction on the
incurrence of liens on the assets of a borrower or any of its significant
subsidiaries other than liens permitted by the credit agreement. The
agreement does not include any rating triggers.
(8) 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 as
part of Pepco’s acquisition of Conectiv on August 1, 2002. Under
this tax sharing agreement, PHI’s consolidated federal income tax liability is
allocated based upon PHI’s and its subsidiaries’ separate taxable income or
loss.
The provision for income taxes,
reconciliation of income tax expense, and components of deferred income tax
liabilities (assets) are shown below.
Provision for Income
Taxes
| |
|
|
|
|
|
|
|
| |
|
|
|
| |
|
|
|
2006
|
|
2005
|
|
|
|
(Millions
of dollars)
|
|
| Current
Tax Expense |
|
|
|
|
|
|
|
|
Federal
|
$
|
81.3
|
$
|
13.0
|
$
|
142.1
|
|
|
State
and local
|
|
(13.7)
|
|
8.4
|
|
36.7
|
|
|
|
|
|
|
|
|
|
|
|
Total
Current Tax Expense
|
|
67.6
|
|
21.4
|
|
178.8
|
|
|
|
|
|
|
|
|
|
|
|
Deferred
Tax Expense (Benefit)
|
|
|
|
|
|
|
|
|
Federal
|
|
(3.8)
|
|
36.0
|
|
(36.4)
|
|
|
State
and local
|
|
.5
|
|
2.0
|
|
(12.8)
|
|
|
Investment
tax credits
|
|
(2.0)
|
|
(2.0)
|
|
(2.0)
|
|
|
|
|
|
|
|
|
|
|
|
Total
Deferred Tax Expense (Benefit)
|
|
(5.3)
|
|
36.0
|
|
(51.2)
|
|
|
|
|
|
|
|
|
|
|
|
Total
Income Tax Expense
|
$
|
62.3
|
$
|
57.4
|
$
|
127.6
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of Income Tax
Expense
|
|
|
|
|
|
|
|
|
|
2006
|
|
2005
|
|
|
|
|
(Millions
of dollars)
|
|
|
|
|
Amount
|
Rate
|
|
Amount
|
Rate
|
|
Amount
|
Rate
|
|
|
|
|
|
|
|
Income
Before Income Taxes
|
$
|
187.4
|
|
$
|
142.8
|
|
$
|
292.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
tax at federal statutory rate
|
$
|
65.6
|
35%
|
$
|
50.0
|
35%
|
$
|
102.4
|
35%
|
|
|
Increases
(decreases) resulting from
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation
|
|
5.2
|
3
|
|
5.9
|
4
|
|
5.3
|
2
|
|
|
Asset
removal costs
|
|
(2.0)
|
(1)
|
|
(3.1)
|
(2)
|
|
(3.3)
|
(1)
|
|
|
State
income taxes, net of
federal
effect
|
|
9.8
|
5
|
|
6.9
|
5
|
|
15.6
|
5
|
|
|
Software
amortization
|
|
3.3
|
2
|
|
3.0
|
2
|
|
5.2
|
2
|
|
|
Tax
credits
|
|
(1.8)
|
(1)
|
|
(2.1)
|
(2)
|
|
(2.3)
|
(1)
|
|
|
Change
in estimates related to
prior
year tax liabilities
|
|
.4
|
-
|
|
(1.5)
|
(1)
|
|
6.1
|
2
|
|
|
Maryland
State refund
net
of federal effect
|
|
(19.5)
|
(11)
|
|
-
|
-
|
|
-
|
-
|
|
|
Deferred
tax basis adjustment
|
|
3.6
|
2
|
|
-
|
-
|
|
-
|
-
|
|
|
Other,
net
|
|
(2.3)
|
(1)
|
|
(1.7)
|
(1)
|
|
(1.4)
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Income Tax Expense
|
$
|
62.3
|
33%
|
$
|
57.4
|
40%
|
$
|
127.6
|
44%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
During 2007, Pepco completed an
analysis of its deferred tax accounts as of December 31,
2006. As a result of this analysis, Pepco recorded a $3.2 million
charge to income tax expense which is included in "Deferred tax basis
adjustment" in the reconciliation provided above.
FIN 48, “Accounting for
Uncertainty in Income Taxes”
As disclosed in Note 2, “Summary of
Significant Accounting Policies”, Pepco adopted FIN 48 effective January 1,
2007. Upon adoption, Pepco recorded the cumulative effect of the
change in accounting principle of $1.9 million as a decrease in retained
earnings. Also upon adoption, Pepco had $95.1 million
of unrecognized tax benefits and $6.9 million of related accrued
interest.
Reconciliation of Beginning and Ending
Balances of Unrecognized Tax Benefits
|
|
|
$ |
95.1 |
|
|
Tax
positions related to current year:
|
|
|
|
|
|
Additions
|
|
|
1.7 |
|
|
Tax
positions related to prior years:
|
|
|
|
|
|
Additions
|
|
|
4.1 |
|
| Reductions |
|
|
(7.7 |
) |
|
Settlements
|
|
|
(33.5 |
) |
|
|
|
$ |
59.7 |
|
|
|
|
|
|
|
As of December 31, 2007, Pepco
had $7.4 million of accrued interest related to unrecognized tax
benefits.
Unrecognized Benefits That If
Recognized Would Affect the Effective Tax Rate
Unrecognized tax benefits represent
those tax benefits 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, in accordance with FIN 48, 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,
2007, Pepco had no unrecognized tax benefits that, if recognized, would lower
the effective tax rate.
Pepco recognizes interest and penalties
relating to its unrecognized tax benefits as an element of tax
expense. For the year ended December 31, 2007, Pepco recognized $.5
million of interest income and penalties, net, as a component of tax
expense.
Possible Changes to Unrecognized
Benefits
Total unrecognized tax benefits that
may change over the next twelve months include the matter of Mixed Service
Costs. See discussion in Note 10, “Commitments and Contingencies --
IRS Mixed Service Cost Issue.”
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 2000 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 noted above.
Components of Deferred
Income Tax Liabilities (Assets)
|
|
|
|
|
|
|
|
2006
|
|
|
|
(Millions
of dollars)
|
|
|
Deferred
Tax Liabilities (Assets)
|
|
|
|
|
|
|
Depreciation
and other book-to-tax basis differences
|
$
|
667.3
|
$
|
725.1
|
|
|
Pension
plan contribution
|
|
57.6
|
|
58.8
|
|
|
Other
post retirement benefits
|
|
(45.1)
|
|
(33.5)
|
|
|
Deferred
taxes on amounts to be collected through future rates
|
|
21.4
|
|
(2.7)
|
|
|
Deferred
investment tax credits
|
|
(8.4)
|
|
(12.6)
|
|
|
Contributions
in aid of construction
|
|
(52.6)
|
|
(60.5)
|
|
|
Customer
sharing
|
|
-
|
|
16.0
|
|
|
Transition
costs
|
|
1.3
|
|
(14.3)
|
|
|
Other
|
|
(25.1)
|
|
(42.8)
|
|
|
Total
Deferred Tax Liabilities, Net
|
|
616.4
|
|
633.5
|
|
|
Deferred
tax assets included in
Other
Current Assets
|
|
2.8
|
|
2.8
|
|
|
Total
Deferred Tax Liabilities, Net - Non-Current
|
$
|
619.2
|
$
|
636.3
|
|
|
|
|
|
|
|
|
The net deferred tax liability
represents the tax effect, at presently enacted tax rates, of temporary
differences between the financial statement 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, 2007
and 2006.
The Tax Reform Act of 1986 repealed the
Investment Tax Credit (ITC) for property placed in service after December 31,
1985, except for certain transition property. ITC previously earned
on Pepco’s property continues to be normalized over the remaining service lives
of the related assets.
Taxes Other Than Income
Taxes
Taxes other than income taxes for each
year are shown below. These amounts relate to the Power Delivery
business and are recoverable through rates.
|
|
2007
|
2006
|
2005
|
|
|
|
(Millions
of dollars)
|
|
Gross
Receipts/Delivery
|
$108.4
|
$108.7
|
$107.8
|
|
|
Property
|
35.9
|
35.2
|
36.4
|
|
|
County
Fuel and Energy
|
88.4
|
84.3
|
89.0
|
|
|
Environmental,
Use and Other
|
56.8
|
44.9
|
42.9
|
|
|
Total
|
$289.5
|
$273.1
|
$276.1
|
|
|
|
|
|
|
|
(9)
FAIR VALUES OF
FINANCIAL INSTRUMENTS
The estimated fair values of Pepco’s
financial instruments at December 31, 2007 and 2006 are shown
below.
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
|
|
(Millions
of dollars)
|
|
|
|
Carrying
Amount
|
Fair
Value
|
Carrying
Amount
|
Fair
Value
|
|
|
Liabilities
and Capitalization
|
|
|
|
|
|
|
|
|
Long-Term
Debt
|
|
$1,239.7
|
$1,183.0
|
|
$1,200.0
|
$1,170.4
|
|
|
|
|
|
|
|
|
|
|
The methods and assumptions described
below were used to estimate, at December 31, 2007 and 2006, the fair value
of each class of financial instrument shown above for which it is practicable to
estimate a value.
The fair values of the Long-Term Debt,
which include First Mortgage Bonds and Medium-Term Notes, including amounts due
within one year, were based on the current market prices, or for issues with no
market price available, were based on discounted cash flows using current rates
for similar issues with similar terms and remaining maturities.
The carrying amounts of all other
financial instruments in Pepco’s accompanying financial statements approximate
fair value.
(10) COMMITMENTS AND
CONTINGENCIES
REGULATORY
AND OTHER MATTERS
Proceeds
from Settlement of Mirant Bankruptcy Claims
In 2000, Pepco sold substantially all
of its electricity generating assets to Mirant. In 2003, Mirant
commenced a voluntary bankruptcy proceeding in which it sought to reject certain
obligations that it had undertaken in connection with the asset
sale. As part of the asset sale, Pepco entered into transition power
agreements with Mirant pursuant to which Mirant agreed to supply all of the
energy and capacity needed by Pepco to fulfill its SOS obligations in Maryland
and in the District of Columbia (the TPAs). Under a settlement to
avoid the rejection by Mirant of its obligations under the TPAs in the
bankruptcy proceeding, the terms of the TPAs were modified to increase the
purchase price of the energy and capacity supplied by Mirant and Pepco received
an allowed, pre-petition general unsecured claim in the bankruptcy in the amount
of $105 million (the TPA Claim). In December 2005, Pepco sold
the TPA Claim, plus the right to receive accrued interest thereon, to an
unaffiliated third party for $112.5 million. In addition, Pepco
received proceeds of $.5 million in settlement of an asbestos claim against
the Mirant bankruptcy estate. After customer sharing, Pepco recorded
a pre-tax gain of $70.5 million from the settlement of these
claims.
In connection with the asset sale,
Pepco and Mirant also entered into a “back-to-back” arrangement, whereby Mirant
agreed to purchase from Pepco the 230 megawatts of electricity and capacity that
Pepco is obligated to purchase annually through 2021 from Panda under
the
Panda PPA
at the purchase price Pepco is obligated to pay to Panda. As part of
the further settlement of Pepco’s claims against Mirant arising from the Mirant
bankruptcy, Pepco agreed not to contest the rejection by Mirant of its
obligations under the “back-to-back” arrangement in exchange for the payment by
Mirant of damages corresponding to the estimated amount by which the purchase
price that Pepco is obligated to pay Panda for the energy and capacity exceeded
the market price. In 2007, Pepco received as damages
$413.9 million in net proceeds from the sale of shares of Mirant common
stock issued to it by Mirant. These funds are being accounted for as
restricted cash based on management’s intent to use such funds, and any interest
earned thereon, for the sole purpose of paying for the future above-market
capacity and energy purchase costs under the Panda
PPA. Correspondingly, a regulatory liability has been established in
the same amount to help offset the future above-market capacity and energy
purchase costs. This restricted cash has been classified as a
non-current asset to be consistent with the classification of the non-current
regulatory liability, and any changes in the balance of this restricted cash,
including interest on the invested funds, are being accounted for as operating
cash flows.
As of December 31, 2007, the balance of
the restricted cash account was $417.3 million. Based on a
reexamination of the costs of the Panda PPA in light of current and projected
wholesale market conditions conducted in the fourth quarter of 2007, Pepco
determined that, principally due to increases in wholesale capacity prices, the
present value above-market cost of the Panda PPA over the term of the agreement
is expected to be significantly less than the current amount of the restricted
cash account balance. Accordingly, on February 22, 2008, Pepco filed
applications with the DCPSC and the MPSC requesting orders directing Pepco to
maintain $320 million in the restricted cash account and to use that cash,
and any future earnings on the cash, for the sole purpose of paying the future
above-market cost of the Panda PPA (or, in the alternative, to fund a transfer
or assignment of the remaining obligations under the Panda PPA to a third
party). Pepco also requested that the order provide that any cash
remaining in the account at the conclusion of the Panda PPA be refunded to
customers and that any shortfall be recovered from customers. Pepco
further proposed that the excess proceeds remaining from the settlement
(approximately $94.6 million, representing the amount by which the
regulatory liability of $414.6 million at December 31, 2007 exceeded
$320 million) be shared approximately equally with its customers in
accordance with the procedures previously approved by each commission for the
sharing of the proceeds received by Pepco from the sale to Mirant of its
generating assets. The regulatory liability of $414.6 million at
December 31, 2007 differs from the restricted cash amount of $417.3 million
on that date, in part, because the regulatory liability has been reduced for the
portion of the December 2007 Panda charges in excess of market that had not yet
been paid from the restricted cash account. The amount of the
restricted cash balance that Pepco is permitted to retain will be recorded as
earnings upon approval of the sharing arrangement by the respective
commissions. At this time, Pepco cannot predict the outcome of these
proceedings.
In settlement of other damages claims
against Mirant, Pepco in 2007 also received a settlement payment in the amount
of $70.0 million. Of this amount (i) $33.4 million was
recorded as a reduction in operating expenses, (ii) $21.0 million was
recorded as a reduction in a net pre-petition receivable claim from Mirant,
(iii) $15.0 million was recorded as a reduction in the capitalized costs of
certain property, plant and equipment and (iv) $.6 million was recorded as
a liability to reimburse a third party for certain legal costs associated with
the settlement.
Rate
Proceedings
In electric service distribution base
rate cases filed by Pepco in the District of Columbia and Maryland, and pending
in 2007, Pepco proposed the adoption of a BSA for retail
customers. Under the BSA, customer delivery rates are subject to
adjustment (through a surcharge or credit mechanism), depending on whether
actual distribution revenue per customer exceeds or falls short of the approved
revenue-per-customer amount. The BSA will increase rates if actual
distribution revenues fall below the level approved by the applicable commission
and will decrease rates if actual distribution revenues are above the approved
level. The result will be that, over time, Pepco would collect its
authorized revenues for distribution deliveries. As a consequence, a
BSA “decouples” revenue from unit sales consumption and ties the growth in
revenues to the growth in the number of customers. Some advantages of
the BSA are that it (i) eliminates revenue fluctuations due to weather and
changes in customer usage patterns and, therefore, provides for more predictable
utility distribution revenues that are better aligned with costs,
(ii) provides for more reliable fixed-cost recovery, (iii) tends to
stabilize customers’ delivery bills, and (iv) removes any disincentives for
Pepco to promote energy efficiency programs for its customers, because it breaks
the link between overall sales volumes and delivery revenues. The
status of the BSA proposals in each of the jurisdictions is described below in
discussion of the respective base rate proceedings.
In December 2006, Pepco submitted an
application to the DCPSC to increase electric distribution base rates, including
a proposed BSA. The application to the DCPSC requested an annual
increase of approximately $46.2 million or an overall increase of 13.5%,
reflecting a proposed return on equity (ROE) of 10.75%. In the
alternative, the application requested an annual increase of $50.5 million
or an overall increase of 14.8%, reflecting an ROE of 11.00%, if the BSA were
not approved. Subsequently, Pepco reduced its annual revenue increase
request to $43.4 million (including a proposed BSA) and $47.9 million
(if the BSA were not approved).
On January 30, 2008, the DCPSC approved
a revenue requirement increase of approximately $28.3 million, based on an
authorized return on rate base of 7.96%, including a 10% ROE. The
rate increase is effective February 20, 2008. The DCPSC, while
finding the BSA to be an appropriate ratemaking concept, cited potential
statutory problems in the DCPSC’s ability to implement the BSA. The
DCPSC stated that it intends to issue an order to establish a Phase II
proceeding to consider these implementation issues.
On July 19, 2007, the MPSC issued an
order in the electric service distribution rate case filed by Pepco, which
included approval of a BSA. The order approved an annual increase in
distribution rates of approximately $10.6 million (including a decrease in
annual depreciation expense of approximately $30.7 million). The
approved distribution rate reflects an ROE of 10.0%. The orders
provided that the rate increases are effective as of June 16, 2007, and will
remain in effect for an initial period of nine months from the date of the order
(or until April 19, 2008). These rates are subject to a Phase II
proceeding in which the MPSC will consider the results of an audit of Pepco’s
cost allocation manual, as filed with the MPSC, to determine whether a further
adjustment to the rates is required. Hearings for the Phase II
proceeding are scheduled for mid-March 2008.
Divestiture
Cases
Final briefs on Pepco’s District of
Columbia divestiture proceeds sharing application were filed with the DCPSC in
July 2002 following an evidentiary hearing in June 2002. That
application was filed to implement a provision of Pepco’s DCPSC-approved
divestiture settlement that provided for a sharing of any net proceeds from the
sale of Pepco’s generation-related assets. One of the principal
issues in the case is whether Pepco should be required to share with customers
the excess deferred income taxes (EDIT) and accumulated deferred investment tax
credits (ADITC) associated with the sold assets and, if so, whether such sharing
would violate the normalization provisions of the Internal Revenue Code (IRC)
and its implementing regulations. As of December 31, 2007, the
District of Columbia allocated portions of EDIT and ADITC associated with the
divested generating assets were approximately $6.5 million and
$5.8 million, respectively.
Pepco believes that a sharing of EDIT
and ADITC would violate the Internal Revenue Service (IRS) normalization
rules. Under these rules, Pepco could not transfer the EDIT and the
ADITC benefit to customers more quickly than on a straight line basis over the
book life of the related assets. Since the assets are no longer owned by Pepco,
there is no book life over which the EDIT and ADITC can be
returned. If Pepco were required to share EDIT and ADITC and, as a
result, the normalization rules were violated, Pepco would be unable to use
accelerated depreciation on District of Columbia allocated or assigned
property. In addition to sharing with customers the
generation-related EDIT and ADITC balances, Pepco would have to pay to the IRS
an amount equal to Pepco’s District of Columbia jurisdictional
generation-related ADITC balance ($5.8 million as of December 31, 2007), as
well as its District of Columbia jurisdictional transmission and
distribution-related ADITC balance ($4.0 million as of December 31, 2007)
in each case as those balances exist as of the later of the date a DCPSC order
is issued and all rights to appeal have been exhausted or lapsed, or the date
the DCPSC order becomes operative.
In March 2003, the IRS issued a notice
of proposed rulemaking (NOPR), which would allow for the sharing of EDIT and
ADITC related to divested assets with utility customers on a prospective basis
and at the election of the taxpayer on a retroactive basis. In
December 2005 a revised NOPR was issued which, among other things, withdrew the
March 2003 NOPR and eliminated the taxpayer’s ability to elect to apply the
regulation retroactively. Comments on the revised NOPR were filed in
March 2006, and a public hearing was held in April 2006. Pepco filed
a letter with the DCPSC in January 2006, in which it has reiterated that the
DCPSC should continue to defer any decision on the ADITC and EDIT issues until
the IRS issues final regulations or states that its regulations project related
to this issue will be terminated without the issuance of any
regulations. Other issues in the divestiture proceeding deal with the
treatment of internal costs and cost allocations as deductions from the gross
proceeds of the divestiture.
Pepco believes that its calculation of
the District of Columbia customers’ share of divestiture proceeds is
correct. However, depending on the ultimate outcome of this
proceeding, Pepco could be required to make additional gain-sharing payments to
District of Columbia customers, including the payments described above related
to EDIT and ADITC. Such additional payments (which, other than the
EDIT and ADITC related payments, cannot be estimated) would be charged to
expense in the quarter and year in which a final decision is rendered and could
have a material adverse effect on Pepco’s and PHI’s results of operations
for
those
periods. However, neither PHI nor Pepco believes that additional
gain-sharing payments, if any, or the ADITC-related payments to the IRS, if
required, would have a material adverse impact on its financial position or cash
flows.
Pepco filed its divestiture proceeds
plan application with the MPSC in April 2001. The principal issue in
the Maryland case is the same EDIT and ADITC sharing issue that has been raised
in the District of Columbia case. See the discussion above under
“Divestiture Cases -- District of Columbia.” As of December 31, 2007,
the Maryland allocated portions of EDIT and ADITC associated with the divested
generating assets were approximately $9.1 million and $10.4 million,
respectively. Other issues deal with the treatment of certain costs
as deductions from the gross proceeds of the divestiture. In November
2003, the Hearing Examiner in the Maryland proceeding issued a proposed order
with respect to the application that concluded that Pepco’s Maryland divestiture
settlement agreement provided for a sharing between Pepco and customers of the
EDIT and ADITC associated with the sold assets. Pepco believes that
such a sharing would violate the normalization rules (discussed above) and would
result in Pepco’s inability to use accelerated depreciation on Maryland
allocated or assigned property. If the proposed order is affirmed,
Pepco would have to share with its Maryland customers, on an approximately 50/50
basis, the Maryland allocated portion of the generation-related EDIT
($9.1 million as of December 31, 2007), and the Maryland-allocated portion
of generation-related ADITC. Furthermore, Pepco would have to pay to
the IRS an amount equal to Pepco’s Maryland jurisdictional generation-related
ADITC balance ($10.4 million as of December 31, 2007), as well as its
Maryland retail jurisdictional ADITC transmission and distribution-related
balance ($7.2 million as of December 31, 2007), in each case as those
balances exist as of the later of the date a MPSC order is issued and all rights
to appeal have been exhausted or lapsed, or the date the MPSC order becomes
operative. The Hearing Examiner decided all other issues in favor of
Pepco, except for the determination that only one-half of the severance payments
that Pepco included in its calculation of corporate reorganization costs should
be deducted from the sales proceeds before sharing of the net gain between Pepco
and customers. Pepco filed a letter with the MPSC in January 2006, in
which it has reiterated that the MPSC should continue to defer any decision on
the ADITC and EDIT issues until the IRS issues final regulations or states that
its regulations project related to this issue will be terminated without the
issuance of any regulations.
In December 2003, Pepco appealed the
Hearing Examiner’s decision to the MPSC as it relates to the treatment of EDIT
and ADITC and corporate reorganization costs. The MPSC has not issued
any ruling on the appeal and Pepco does not believe that it will do so until
action is taken by the IRS as described above. However, depending on
the ultimate outcome of this proceeding, Pepco could be required to share with
its customers approximately 50 percent of the EDIT and ADITC balances described
above in addition to the additional gain-sharing payments relating to the
disallowed severance payments. Such additional payments would be
charged to expense in the quarter and year in which a final decision is rendered
and could have a material adverse effect on results of operations for those
periods. However, neither PHI nor Pepco believes that additional
gain-sharing payments, if any, or the ADITC-related payments to the IRS, if
required, would have a material adverse impact on its financial position or cash
flows.
General
Litigation
During 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 are
not entirely clear, it appears that each plaintiff sought $2 million in
compensatory damages and $4 million in punitive damages from each
defendant.
Since the initial filings in 1993,
additional individual suits have been filed against Pepco, and significant
numbers of cases have been dismissed. As a result of two motions to
dismiss, numerous hearings and meetings and one motion for summary judgment,
Pepco has had approximately 400 of these cases successfully dismissed with
prejudice, either voluntarily by the plaintiff or by the court. As of
December 31, 2007, there are approximately 180 cases still pending against Pepco
in the State Courts of Maryland, of which approximately 90 cases were filed
after December 19, 2000, and were tendered to Mirant for defense and
indemnification pursuant to the terms of the Asset Purchase and Sale Agreement
between Pepco and Mirant under which Pepco sold its generation assets to Mirant
in 2000.
While the aggregate amount of monetary
damages sought in the remaining suits (excluding those tendered to Mirant) is
approximately $360 million, Pepco believes the amounts claimed by current
plaintiffs are greatly exaggerated. The amount of total liability, if
any, and any related insurance recovery cannot be determined at this time;
however, based on information and relevant circumstances known at this time,
Pepco does not believe these suits will have a material adverse effect on its
financial position, results of operations or cash flows. However, if
an unfavorable decision were rendered against Pepco, it could have a material
adverse effect on Pepco’s financial position, results of operations or cash
flows.
Environmental
Litigation
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. In addition, federal and state statutes authorize governmental
agencies to compel responsible parties to clean up certain abandoned or
unremediated hazardous waste sites. Pepco 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. Although penalties assessed for violations of
environmental laws and regulations are not recoverable from Pepco’s customers,
environmental clean-up costs incurred by Pepco would be included in its cost of
service for ratemaking purposes.
Carolina Transformer
Site. In August 2006, the U.S. Environmental Protection Agency
(EPA) notified Pepco that it had been identified as an entity that sent
PCB-laden oil to be disposed at the Carolina Transformer site in Fayetteville,
North Carolina. The EPA notification stated that, on this basis,
Pepco may be a potentially responsible party (PRP). In
December
2007,
Pepco agreed to enter into a settlement agreement with EPA and the PRP group at
the Carolina Transformer site. Under the terms of the settlement,
(i) Pepco will pay $162,000 to EPA to resolve any liability that it might
have at the site, (ii) EPA covenants not to sue or bring administrative
action Pepco for response costs at the site, (iii) other PRP group members
release all rights for cost recovery or contribution claims they may have
against Pepco, and (iv) Pepco releases all rights for cost recovery or
contribution claims that it may have against other parties settling with
EPA. The consent decree is expected to be filed with the U.S.
District Court in North Carolina in the second quarter of 2008.
IRS
Mixed Service Cost Issue
During 2001, Pepco changed its method
of accounting with respect to capitalizable construction costs for income tax
purposes. The change allowed Pepco to accelerate the deduction of
certain expenses that were previously capitalized and
depreciated. Through December 31, 2005, these accelerated deductions
generated incremental tax cash flow benefits of approximately $94 million,
primarily attributable to its 2001 tax returns.
In 2005, the Treasury Department issued
proposed regulations that, if adopted in their current form, would require Pepco
to change its method of accounting with respect to capitalizable construction
costs for income tax purposes for tax periods beginning in
2005. Based on the proposed regulations, PHI in its 2005 federal tax
return adopted an alternative method of accounting for capitalizable
construction costs that management believes will be acceptable to the
IRS.
At the same time as the proposed
regulations were released, the IRS issued Revenue Ruling 2005-53, which is
intended to limit the ability of certain taxpayers to utilize the method of
accounting for income tax purposes they utilized on their tax returns for 2004
and prior years with respect to capitalizable construction costs. In
line with this Revenue Ruling, the IRS revenue agent’s report for the 2001 and
2002 tax returns disallowed substantially all of the incremental tax benefits
that Pepco had claimed on those returns by requiring it to capitalize and
depreciate certain expenses rather than treat such expenses as current
deductions. PHI’s protest of the IRS adjustments is among the
unresolved audit matters relating to the 2001 and 2002 audits pending before the
Appeals Office.
In February 2006, PHI paid
approximately $121 million of taxes to cover the amount of additional taxes and
interest that management estimated to be payable for the years 2001 through 2004
based on the method of tax accounting that PHI, pursuant to the proposed
regulations, adopted on its 2005 tax return. However, if the IRS is
successful in requiring Pepco to capitalize and depreciate construction costs
that result in a tax and interest assessment greater than management’s estimate
of $121 million, PHI will be required to pay additional taxes and interest only
to the extent these adjustments exceed the $121 million payment made in February
2006. It is reasonably possible that PHI’s unrecognized tax benefits
related to this issue will significantly decrease in the next 12 months as a
result of a settlement with the IRS.
Contractual
Obligations
As of December 31, 2007, Pepco’s
contractual obligations under non-derivative fuel and power purchase contracts
were $973.3 million in 2008, $733.8 million in 2009 to 2010, $125.6 million in
2011 to 2012, and $430.4 in 2013 and thereafter.
(11) 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 causal
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, 2007, 2006 and 2005 were approximately $128.6
million, $114.4 million, and $114.6 million, respectively.
Certain subsidiaries of Pepco Energy
Services perform utility maintenance services, including services that are
treated as capital costs, for Pepco. Amounts charged to Pepco by
these companies for the years ended December 31, 2007, 2006 and 2005 were
approximately $25.7 million, $15.3 million and $11.6 million,
respectively.
In addition to the transactions
described above, Pepco’s financial statements include the following related
party transactions in its Statements of Earnings:
|
|
|
|
|
|
2006
|
2005
|
|
Income
(Expense)
|
(Millions
of dollars)
|
|
Intercompany
power purchases - Conectiv Energy Supply (a)
|
$(63.3)
|
$(35.6)
|
$ -
|
|
Intercompany
lease transactions
(b)
|
-
|
$ (2.4)
|
$ (4.4)
|
|
|
(a)
|
Included
in fuel and purchased energy.
|
|
|
(b)
|
Included
in other operation and maintenance.
|
As of December 31, 2007 and 2006, Pepco
had the following balances on its Balance Sheets due (to)/from related
parties:
|
|
2007
|
2006
|
|
Asset
(Liability)
|
(Millions
of dollars)
|
|
Payable
to Related Party (current)
|
|
|
|
PHI
Service Company
|
$(16.9)
|
$(.9)
|
|
PHI
Parent
|
-
|
(5.0)
|
|
Conectiv
Energy Supply
|
(5.8)
|
(4.8)
|
|
Pepco
Energy Services
(a)
|
(53.0)
|
(35.4)
|
|
The
items listed above are included in the “Accounts payable to
associated
companies”
balance on the Balance Sheet of $75.8 million and $46.0
|
|
|
|
Money
Pool Balance with Pepco Holdings (included in short-term debt
in
2007
and cash and cash equivalents in 2006 on the Balance
Sheet)
|
$(95.9)
|
$ .4
|
|
|
|
|
|
|
(a)
|
Pepco
bills customers on behalf of Pepco Energy Services where customers have
selected Pepco Energy Services as their alternative supplier or where
Pepco Energy Services has performed work for certain government agencies
under a General Services Administration area-wide
agreement.
|
(12)
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.
|
|
|
2007
|
|
|
|
|
|
First
Quarter
|
|
|
Second
Quarter
|
|
|
Third
Quarter
|
|
|
|
Fourth
Quarter
|
|
|
Total
|
|
|
|
|
|
(Millions
of dollars)
|
|
|
|
Total
Operating Revenue
|
|
$ |
506.6 |
|
|
$ |
495.0 |
|
|
$ |
693.6 |
|
|
|
$ |
505.7 |
|
|
$ |
2,200.9 |
|
|
|
Total
Operating Expenses
|
|
|
477.1 |
|
|
|
449.6 |
|
|
|
562.0 |
|
(a)
|
|
|
464.0 |
|
|
|
1,952.7 |
|
(a)
|
|
Operating
Income
|
|
|
29.5 |
|
|
|
45.4 |
|
|
|
131.6 |
|
|
|
|
41.7 |
|
|
|
248.2 |
|
|
|
Other
Expenses
|
|
|
(15.0 |
) |
|
|
(14.7 |
) |
|
|
(15.7 |
) |
|
|
|
(15.4 |
) |
|
|
(60.8 |
) |
|
|
Income
Before Income Tax Expense
|
|
|
14.5 |
|
|
|
30.7 |
|
|
|
115.9 |
|
|
|
|
26.3 |
|
|
|
187.4 |
|
|
|
Income
Tax Expense
|
|
|
5.8 |
|
|
|
12.7 |
|
|
|
31.3 |
|
(b)
|
|
|
12.5 |
|
|
|
62.3 |
|
(b)
|
|
Net
Income
|
|
|
8.7 |
|
|
|
18.0 |
|
|
|
84.6 |
|
|
|
|
13.8 |
|
|
|
125.1 |
|
|
|
Dividends
on Preferred Stock
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
|
- |
|
|
|
- |
|
|
|
Earnings
Available for Common Stock
|
|
$ |
8.7 |
|
|
$ |
18.0 |
|
|
$ |
84.6 |
|
|
|
$ |
13.8 |
|
|
$ |
125.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
|
|
|
First
Quarter
|
|
|
Second
Quarter
|
|
|
Third
Quarter
|
|
|
|
Fourth
Quarter
|
|
|
Total
|
|
|
|
|
|
(Millions
of dollars)
|
|
|
|
Total
Operating Revenue
|
|
$ |
475.2 |
|
|
$ |
520.5 |
|
|
$ |
742.3 |
|
|
|
$ |
478.5 |
|
|
$ |
2,216.5 |
|
|
|
Total
Operating Expenses
|
|
|
441.6 |
|
|
|
474.6 |
|
|
|
650.5 |
|
|
|
|
449.6 |
|
|
|
2,016.3 |
|
|
|
Operating
Income
|
|
|
33.6 |
|
|
|
45.9 |
|
|
|
91.8 |
|
|
|
|
28.9 |
|
|
|
200.2 |
|
|
|
Other
Expenses
|
|
|
(13.9 |
) |
|
|
(13.6 |
) |
|
|
(15.4 |
) |
|
|
|
(14.5 |
) |
|
|
(57.4 |
) |
|
|
Income
Before Income Tax Expense
|
|
|
19.7 |
|
|
|
32.3 |
|
|
|
76.4 |
|
|
|
|
14.4 |
|
|
|
142.8 |
|
|
|
Income
Tax Expense
|
|
|
9.1 |
|
|
|
13.4 |
|
|
|
27.5 |
|
|
|
|
7.4 |
|
|
|
57.4 |
|
|
|
Net
Income
|
|
|
10.6 |
|
|
|
18.9 |
|
|
|
48.9 |
|
|
|
|
7.0 |
|
|
|
85.4 |
|
|
|
Dividends
on Preferred Stock
|
|
|
1.0 |
|
|
|
- |
|
|
|
- |
|
|
|
|
- |
|
|
|
1.0 |
|
|
|
Earnings
Available for Common Stock
|
|
$ |
9.6 |
|
|
$ |
18.9 |
|
|
$ |
48.9 |
|
|
|
$ |
7.0 |
|
|
$ |
84.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
Includes
$33.4 million benefit ($20.0 million after-tax) from settlement of Mirant
bankruptcy claims.
|
|
|
(b)
|
Includes
$19.5 million benefit ($17.7 million net of fees) related to Maryland
income tax refund.
|
THIS
PAGE LEFT INTENTIONALLY BLANK.
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. Because of 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 assessed its internal
control over financial reporting as of December 31, 2007 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 its internal control over financial reporting was
effective as of December 31, 2007.
This Annual Report on Form 10-K does
not include an attestation report of DPL’s registered public accounting firm,
PricewaterhouseCoopers LLP, regarding internal control over financial
reporting. Management’s report was not subject to attestation by
PricewaterhouseCoopers LLP pursuant to temporary rules of the Securities and
Exchange Commission that permit DPL to provide only management’s report in this
Form 10-K.
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 listed in the accompanying index present
fairly, in all material respects, the financial position of Delmarva Power &
Light Company (a wholly owned subsidiary of Pepco Holdings, Inc.) at December
31, 2007 and December 31, 2006, and the results of its operations and its cash
flows for each of the three years in the period ended December 31, 2007 in
conformity with accounting principles generally accepted in the United States of
America. In addition, in our opinion, the financial statement
schedule 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.
As
discussed in Note 8 to the financial statements, the Company changed its manner
of accounting and reporting for uncertain tax positions in 2007.
PricewaterhouseCoopers
LLP
Washington,
DC
|
DELMARVA
POWER & LIGHT COMPANY
STATEMENTS
OF EARNINGS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
2005
|
|
|
|
(Millions
of dollars)
|
|
|
|
Operating
Revenue
|
|
|
|
|
|
|
|
|
Electric
|
|
$1,204.7
|
|
$1,168.0
|
|
$1,082.3
|
|
|
Natural
Gas
|
|
291.3
|
|
255.4
|
|
261.5
|
|
|
Total
Operating Revenue
|
|
1,496.0
|
|
1,423.4
|
|
1,343.8
|
|
|
Operating
Expenses
|
|
|
|
|
|
|
|
|
Fuel
and purchased energy
|
|
838.6
|
|
816.8
|
|
698.0
|
|
|
Gas
purchased
|
|
220.3
|
|
198.4
|
|
196.8
|
|
|
Other
operation and maintenance
|
|
205.4
|
|
184.9
|
|
180.1
|
|
|
Depreciation
and amortization
|
|
74.4
|
|
76.7
|
|
75.7
|
|
|
Other
taxes
|
|
36.3
|
|
36.6
|
|
34.4
|
|
|
Gain
on sale of assets
|
|
(1.0)
|
|
(1.5)
|
|
(3.6)
|
|
|
Total
Operating Expenses
|
|
1,374.0
|
|
1,311.9
|
|
1,181.4
|
|
|
Operating
Income
|
|
122.0
|
|
111.5
|
|
162.4
|
|
|
Other
Income (Expenses)
|
|
|
|
|
|
|
|
|
Interest
and dividend income
|
|
1.1
|
|
1.2
|
|
.9
|
|
|
Interest
expense
|
|
(43.3)
|
|
(41.1)
|
|
(34.7)
|
|
|
Other
income
|
|
2.3
|
|
7.3
|
|
8.3
|
|
|
Other
expenses
|
|
-
|
|
(4.3)
|
|
(4.6)
|
|
|
Total
Other Expenses
|
|
(39.9)
|
|
(36.9)
|
|
(30.1)
|
|
|
|
|
|
|
|
|
|
|
|
Income
Before Income Tax Expense
|
|
82.1
|
|
74.6
|
|
132.3
|
|
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
37.2
|
|
32.1
|
|
57.6
|
|
|
|
|
|
|
|
|
|
|
|
Net
Income
|
|
44.9
|
|
42.5
|
|
74.7
|
|
|
|
|
|
|
|
|
|
|
|
Dividends
on Redeemable Serial Preferred Stock
|
|
-
|
|
.8
|
|
1.0
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
Available for Common Stock
|
|
$ 44.9
|
|
$ 41.7
|
|
$ 73.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
accompanying Notes are an integral part of these Financial
Statements.
|
|
DELMARVA
POWER & LIGHT COMPANY
BALANCE
SHEETS
|
|
ASSETS
|
|
|
|
|
(Millions
of dollars)
|
|
CURRENT
ASSETS
|
|
|
|
|
Cash
and cash equivalents
|
$ 11.4
|
|
$ 8.2
|
|
Restricted
cash
|
3.8
|
|
-
|
|
Accounts
receivable, less allowance for uncollectible
accounts
of $8.0 million and $7.8 million, respectively
|
194.9
|
|
193.7
|
|
Fuel,
materials and supplies - at average cost
|
45.3
|
|
40.1
|
|
Prepayments
of income taxes
|
56.1
|
|
46.3
|
|
Prepaid
expenses and other
|
15.2
|
|
18.4
|
|
Total
Current Assets
|
326.7
|
|
306.7
|
|
INVESTMENTS
AND OTHER ASSETS
|
|
|
|
|
Goodwill
|
8.0
|
|
48.5
|
|
Regulatory
assets
|
224.6
|
|
187.2
|
|
Prepaid
pension expense
|
178.1
|
|
171.8
|
|
Other
|
35.3
|
|
18.4
|
|
Total
Investments and Other Assets
|
446.0
|
|
425.9
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
Property,
plant and equipment
|
2,615.8
|
|
2,512.8
|
|
Accumulated
depreciation
|
(828.8)
|
|
(794.2)
|
|
Net
Property, Plant and Equipment
|
1,787.0
|
|
1,718.6
|
|
TOTAL
ASSETS
|
$2,559.7
|
|
$2,451.2
|
|
|
|
The
accompanying Notes are an integral part of these Financial
Statements.
|
|
DELMARVA
POWER & LIGHT COMPANY
BALANCE
SHEETS
|
|
LIABILITIES
AND SHAREHOLDER’S EQUITY
|
|
|
|
(Millions
of dollars, except shares)
|
|
|
CURRENT
LIABILITIES
|
|
|
|
Short-term
debt
|
$ 286.2
|
$ 195.9
|
|
Current
maturities of long-term debt
|
22.6
|
64.7
|
|
Accounts
payable and accrued liabilities
|
104.7
|
95.0
|
|
Accounts
payable due to associated companies
|
54.0
|
9.6
|
|
Taxes
accrued
|
8.2
|
3.2
|
|
Interest
accrued
|
5.7
|
6.2
|
|
Liabilities
and accrued interest related to uncertain tax positions
|
34.1
|
-
|
|
Other
|
64.5
|
58.4
|
|
Total
Current Liabilities
|
580.0
|
433.0
|
|
DEFERRED
CREDITS
|
|
|
|
Regulatory
liabilities
|
275.5
|
272.4
|
|
Deferred
income taxes, net
|
410.1
|
424.1
|
|
Investment
tax credits
|
9.0
|
9.9
|
|
Above-market
purchased energy contracts and other
electric
restructuring liabilities
|
21.1
|
23.5
|
|
Other
|
61.2
|
49.2
|
|
Total
Deferred Credits
|
776.9
|
779.1
|
|
|
|
|
|
LONG-TERM
LIABILITIES
|
|
|
|
Long-term
debt
|
529.4
|
551.8
|
|
|
|
|
|
COMMITMENTS
AND CONTINGENCIES (NOTE 11)
|
|
|
|
|
|
|
|
REDEEMABLE
SERIAL PREFERRED STOCK
|
-
|
18.2
|
|
SHAREHOLDER’S
EQUITY
|
|
|
|
Common
stock, $2.25 par value, authorized 1,000,000
shares
- issued 1,000 shares
|
-
|
-
|
|
Premium
on stock and other capital contributions
|
241.6
|
242.7
|
|
Retained
earnings
|
431.8
|
426.4
|
|
Total
Shareholder’s Equity
|
673.4
|
669.1
|
|
|
|
|
|
TOTAL LIABILITIES AND
SHAREHOLDER’S EQUITY
|
$2,559.7
|
$2,451.2
|
|
|
|
|
|
The
accompanying Notes are an integral part of these Financial
Statements.
|
|
DELMARVA
POWER & LIGHT COMPANY
STATEMENTS
OF CASH FLOWS
|
|
| For
the Year Ended December 31, |
2007 |
|
2006
|
|
2005
|
| (Millions of
dollars) |
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
|
Net
income
|
$ 44.9
|
|
$ 42.5
|
|
$ 74.7
|
|
Adjustments
to reconcile net income to net cash from operating
activities:
|
|
|
|
|
|
|
Depreciation
and amortization
|
74.4
|
|
76.7
|
|
75.7
|
|
Gain
on sale of assets
|
(1.0)
|
|
(1.5)
|
|
(3.6)
|
|
Deferred
income taxes
|
27.3
|
|
38.8
|
|
(22.7)
|
|
Investment
tax credit adjustments, net
|
(.9)
|
|
(.9)
|
|
(.9)
|
|
Prepaid
pension expense
|
(6.3)
|
|
(6.6)
|
|
(8.6)
|
|
Energy
supply contracts
|
(1.8)
|
|
(4.3)
|
|
(8.2)
|
|
Other
deferred credits
|
1.9
|
|
(2.6)
|
|
1.1
|
|
Other
deferred charges
|
(2.6)
|
|
1.6
|
|
1.7
|
|
Changes
in:
|
|
|
|
|
|
|
Accounts
receivable
|
(1.4)
|
|
(10.3)
|
|
(7.8)
|
|
Regulatory
assets and liabilities
|
(18.3)
|
|
(31.4)
|
|
(1.1)
|
|
Fuel,
materials and supplies
|
(5.2)
|
|
1.7
|
|
(3.4)
|
|
Accounts
payable and accrued liabilities
|
61.6
|
|
10.2
|
|
28.3
|
|
Interest
and taxes accrued
|
(10.4)
|
|
(75.4)
|
|
21.1
|
|
Prepaid
expenses
|
7.0
|
|
3.1
|
|
(2.2)
|
|
Net
Cash From Operating Activities
|
169.2
|
|
41.6
|
|
144.1
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
Investment
in property, plant and equipment
|
(132.6)
|
|
(134.0)
|
|
(137.2)
|
|
Proceeds
from sale of other assets
|
.4
|
|
2.7
|
|
4.4
|
|
Changes
in restricted cash
|
(3.8)
|
|
-
|
|
4.8
|
|
Net
other investing activities
|
.9
|
|
(1.6)
|
|
-
|
|
Net
Cash Used By Investing Activities
|
(135.1)
|
|
(132.9)
|
|
(128.0)
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
Dividends
paid to Pepco Holdings
|
(39.0)
|
|
(15.0)
|
|
(36.4)
|
|
Dividends
paid on preferred stock
|
-
|
|
(.8)
|
|
(1.0)
|
|
Redemption
of preferred stock
|
(18.2)
|
|
-
|
|
(3.5)
|
|
Issuances
of long-term debt
|
-
|
|
100.0
|
|
100.0
|
|
Reacquisitions
of long-term debt
|
(64.7)
|
|
(22.9)
|
|
(102.7)
|
|
Issuances
of short-term debt, net
|
90.3
|
|
30.4
|
|
31.2
|
|
Net
other financing activities
|
.7
|
|
.4
|
|
.1
|
|
Net
Cash (Used By) From Financing Activities
|
(30.9)
|
|
92.1
|
|
(12.3)
|
|
|
|
|
|
|
|
|
Net
Increase In Cash and Cash Equivalents
|
3.2
|
|
.8
|
|
3.8
|
|
Cash
and Cash Equivalents at Beginning of Year
|
8.2
|
|
7.4
|
|
3.6
|
|
|
|
|
|
|
|
|
CASH
AND CASH EQUIVALENTS AT END OF YEAR
|
$ 11.4
|
|
$ 8.2
|
|
$ 7.4
|
|
|
|
|
|
|
|
|
NONCASH
ACTIVITIES
|
|
|
|
|
|
|
Asset
retirement obligations associated with removal costs
transferred
to regulatory liabilities
|
$ 4.7
|
|
$ 50.3
|
|
$ 2.4
|
|
Capital
(distribution) contribution in respect of
certain
intercompany transactions
|
$ (.9)
|
|
$ 7.3
|
|
$ -
|
|
|
|
|
|
|
|
|
SUPPLEMENTAL
DISCLOSURE OF CASH FLOW INFORMATION
|
|
|
|
|
|
|
Cash paid
for interest (net of capitalized interest of $.5 million,
$.6
million, and $.9 million, respectively), and paid for income
taxes:
|
|
|
|
|
|
|
Interest
|
$ 41.5
|
|
$ 38.7
|
|
$ 32.2
|
|
Income
taxes
|
$ 19.8
|
|
$ 32.6
|
|
$ 55.6
|
|
|
|
|
|
|
|
|
The
accompanying Notes are an integral part of these Financial
Statements.
|
|
DELMARVA
POWER & LIGHT COMPANY
STATEMENTS
OF SHAREHOLDER’S EQUITY
|
|
|
Common
Stock
|
Premium
on
Stock
|
Capital
Stock
Expense
|
Retained
Earnings
|
|
|
Shares
|
Par
Value
|
|
(Millions
of dollars, except shares)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,000
|
$-
|
$245.4
|
$(10.0)
|
$362.4
|
|
Net
Income
|
-
|
-
|
-
|
-
|
74.7
|
|
Dividends:
|
|
|
|
|
|
|
Preferred
stock
|
-
|
-
|
-
|
-
|
(1.0)
|
|
Common
stock
|
-
|
-
|
-
|
-
|
(36.4)
|
|
|
|
|
|
|
|
|
|
1,000
|
-
|
245.4
|
(10.0)
|
399.7
|
|
Net
Income
|
-
|
-
|
-
|
-
|
42.5
|
|
Capital
contributions
|
-
|
-
|
7.3
|
-
|
-
|
|
Dividends:
|
|
|
|
|
|
|
Preferred
stock
|
-
|
-
|
-
|
-
|
(.8)
|
|
Common
stock
|
-
|
-
|
-
|
-
|
(15.0)
|
|
|
|
|
|
|
|
|
|
1,000
|
-
|
252.7
|
(10.0)
|
426.4
|
|
Net
Income
|
-
|
-
|
-
|
-
|
44.9
|
|
Capital
distribution
|
-
|
-
|
(.9)
|
-
|
-
|
|
Cumulative
effect adjustment related to implementation of FIN 48
|
-
|
-
|
-
|
-
|
.1
|
|
Preferred
stock redemption
|
-
|
-
|
(.2)
|
-
|
(.6)
|
|
Dividends:
|
|
|
|
|
|
|
Common
stock
|
-
|
-
|
-
|
-
|
(39.0)
|
|
|
|
|
|
|
|
|
|
1,000
|
$-
|
$251.6
|
$(10.0)
|
$431.8
|
|
|
|
|
|
|
|
|
The
accompanying Notes are an integral part of these Financial
Statements.
|
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 Virginia (until the sale of its Virginia operations
on January 2, 2008), and provides gas distribution service in northern
Delaware. Additionally, DPL supplies electricity at regulated rates
to retail customers in its territories who do not elect to purchase electricity
from a competitive supplier. The regulatory term for this service
varies by jurisdiction as follows:
|
|
Delaware
|
|
| |
|
Standard
Offer Service (SOS) – on and after May 1,
2006 |
In this Form 10-K, DPL also refers to
these supply services generally as Default Electricity Supply.
DPL is a wholly owned subsidiary of
Conectiv, which is wholly owned by Pepco Holdings, Inc. (Pepco Holdings or
PHI). On January 2, 2008, DPL, in two separate transactions, sold its
Virginia electric distribution and default supply operations and substantially
all of its Virginia transmission assets, in each case located on the eastern
shore of Virginia, for an aggregate sale price of price of approximately $44.6
million, subject to closing adjustments. As a result of the
transaction, DPL no longer has any service territory in the state of Virginia
and has ceased to be regulated by the Virginia State Corporation
Commission.
(2) SUMMARY OF 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 estimates used by DPL
include the assessment of contingencies, the calculation of future cash flows
and fair value amounts for use in asset impairment evaluations, fair value
calculations (based on estimated market pricing) associated with derivative
instruments, pension and other postretirement benefits assumptions, unbilled
revenue calculations, the assessment of the probability of recovery of
regulatory assets, 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 that are probable and
reasonably estimable.
Change in Accounting
Estimates
During 2007, as a result of the
depreciation study presented as part of DPL’s Maryland rate case, the Maryland
Public Service Commission (MPSC) approved new lower depreciation rates for DPL’s
Maryland distribution assets. This resulted in lower depreciation expense of
approximately $.3 million for the last six months of 2007.
During 2005, DPL recorded the impact of
reductions in estimated unbilled revenue, primarily reflecting an increase in
the estimated amount of power line losses (electricity lost in the process of
its transmission and distribution to customers). This change in
accounting estimate reduced net earnings for the year ended December 31,
2005 by approximately $1.0 million.
Revenue
Recognition
DPL recognizes revenues upon delivery
of electricity and gas to its customers, including amounts for services
rendered, but not yet billed (unbilled revenue). DPL recorded amounts
for unbilled revenue of $49.8 million and $58.4 million as of December 31,
2007 and 2006, respectively. 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 power line losses
(estimates of electricity expected to be lost in the process of its transmission
and distribution to customers), all of which are inherently uncertain and
susceptible to change from period to period, the impact of which could be
material. Revenues from other services are recognized when services
are performed or products are delivered.
Revenues from non-regulated electricity
and gas sales are included in “Electric” revenues and “Natural Gas” revenues,
respectively. The 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 Revenues.” Accruals for 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 de minimis.
Regulation of Power Delivery
Operations
Certain aspects of DPL’s utility
businesses are subject to regulation by the Delaware Public Service Commission
(DPSC) and the MPSC, and, until the sale of its Virginia operations on January
2, 2008, was regulated by the Virginia State Corporation Commission
(VSCC). The transmission and wholesale sale 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, the provisions of
Statement of Financial Accounting Standards (SFAS) No. 71 (SFAS No.
71),
“Accounting
for the Effects of Certain Types of Regulation.” SFAS No. 71 allows regulated
entities, in appropriate circumstances, to establish regulatory assets and to
defer the income statement impact of certain costs that are expected to be
recovered in future rates. Management’s assessment of the probability
of recovery of regulatory assets requires judgment and interpretation of laws,
regulatory commission orders, and other factors. Should existing
facts or circumstances change in the future to indicate that a regulatory asset
is not probable of recovery, then the regulatory asset must be charged to
earnings.
As part of the new electric service
distribution base rates for DPL approved by the MPSC, effective June 16, 2007,
the MPSC approved a bill stabilization adjustment mechanism (BSA) for retail
customers. See Note 11 “Commitments and Contingencies – Regulatory
and Other Matters – Rate Proceedings.” For customers to which the BSA
applies, DPL recognizes distribution revenue based on an approved distribution
charge per customer. From a revenue recognition standpoint, the BSA
thus decouples the distribution revenue recognized in a reporting period from
the amount of power delivered during the period. Pursuant to this
mechanism, DPL recognizes either (a) 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 (b) 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 positive Revenue Decoupling Adjustment is recorded as
a regulatory asset and a negative Revenue Decoupling Adjustment is recorded as a
regulatory liability. The net Revenue Decoupling Adjustment at
December 31, 2007 is a regulatory asset and is included in the “Other” line item
on the table of regulatory asset balances listed below.
|
|
2007
|
2006
|
|
|
|
(Millions
of dollars)
|
|
|
Deferred
energy supply costs
|
$ 1.7
|
$ 6.9
|
|
|
Deferred
recoverable income taxes
|
73.3
|
77.5
|
|
|
Deferred
debt extinguishment costs
|
17.5
|
18.9
|
|
|
Unrecovered
purchased power contract costs
|
-
|
2.4
|
|
|
Phase
in credits
|
37.5
|
29.7
|
|
|
COPCO
acquisition adjustment
|
39.5
|
-
|
|
|
Other
|
55.1
|
51.8
|
|
|
Total
Regulatory Assets
|
$224.6
|
$187.2
|
|
|
|
|
|
|
|
|
2007
|
2006
|
|
| |
(Millions
of dollars) |
|
|
Deferred
income taxes due to customers
|
$ 39.1
|
$ 39.4
|
|
|
Asset
removal costs
|
234.2
|
229.5
|
|
|
Other
|
2.2
|
3.5
|
|
|
Total
Regulatory Liabilities
|
$275.5
|
$272.4
|
|
|
|
|
|
|
A description for each category of
regulatory assets and regulatory liabilities follows:
Deferred Energy Supply
Costs: Primarily represents deferred fuel costs for
DPL’s gas business. The gas deferred fuel costs are recovered over a
twelve month period and include a return component.
Deferred Recoverable Income
Taxes: Represents a receivable from our customers for tax
benefits DPL has previously flowed through before the company was ordered to
provide deferred income taxes. As the temporary differences between
the financial statement and tax basis of assets reverse, the deferred
recoverable balances are reversed. There is no return on these
deferrals.
Deferred Debt Extinguishment
Costs: Represents the costs of debt extinguishment for which
recovery through regulated utility rates is considered probable and will be
amortized to interest expense during the authorized rate recovery
period. A return is received on these deferrals.
Unrecovered Purchased Power Contract
Costs: Represents deferred costs related to purchase power
contracts at DPL, which were recovered from February 1996 through October 2007
and earned a return.
Phase In
Credits: Represents phase-in
credits for participating Maryland and Delaware residential and small commercial
customers to mitigate the immediate impact of significant rate increases due to
energy costs in 2006. The deferral period for Delaware was May 1,
2006 to January 1, 2008 with recovery to occur over a 17-month period beginning
January 2008. The Delaware deferral will be recovered from
participating customers on a straight-line basis. The deferral period
for Maryland was June 1, 2006 to June 1, 2007, with the recovery to occur over
an 18-month period beginning June 2007. The Maryland deferral will be
recovered from participating customers at a rate per kilowatt-hour based on
energy usage during the recovery period.
COPCO Acquisition
Adjustment: On July 19, 2007, the Maryland PSC issued an order
which provided for the recovery of a portion of DPL's goodwill. As a
result of this order, $40.5 million in DPL goodwill has been transferred to a
regulatory asset. It will earn a 12.95% return and will be amortized
from August 2007 through August, 2018.
Other: Includes
losses associated with DPL’s natural gas hedging activity and under-recovery of
procurement, transmission and administration costs associated with Maryland and
Delaware SOS.
Deferred Income Taxes Due to
Customers: Represents the portion of deferred income tax
liabilities applicable to DPL’s utility operations that has not been reflected
in current customer rates, for which future payment to customers is
probable. As temporary differences between the financial statement
and tax basis of assets reverse, deferred recoverable income taxes are
amortized.
Asset Removal
Costs: Represents DPL’s asset retirement obligation associated
with removal costs accrued using public service commission approved depreciation
techniques for transmission, distribution and general utility
property.
Other: Includes
over-recovery of procurement, transmission and administration costs associated
with Maryland and Delaware SOS.
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.
In 2006, the Financial Accounting
Standards Board (FASB) issued FASB Interpretation No. (FIN) 48, “Accounting for
Uncertainty in Income Taxes” (FIN 48). FIN 48 clarifies the criteria
for recognition of tax benefits in accordance with Statement of SFAS No. 109,
“Accounting for Income Taxes,” and prescribes a financial statement recognition
threshold and measurement attribute for a tax position taken or expected to be
taken in a tax return. Specifically, it clarifies that an entity’s
tax benefits must be “more likely than not” of being sustained prior to
recording the related tax benefit in the financial statements. If the
position drops below the “more likely than not” standard, the benefit can no
longer be recognized. FIN 48 also provides guidance on derecognition,
classification, interest and penalties, accounting in interim periods,
disclosure, and transition.
On May 2, 2007, the FASB issued FASB
Staff Position (FSP) FIN 48-1, “Definition of Settlement in FASB Interpretation
No. 48” (FIN 48-1), which provides guidance on how an enterprise should
determine whether a tax position is effectively settled for the purpose of
recognizing previously unrecognized tax benefits. DPL applied the
guidance of FIN 48-1 with its adoption of FIN 48 on January 1,
2007.
The financial statements include
current and deferred income taxes. Current income taxes represent the amounts 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 and tax basis of existing assets and liabilities and 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. For additional
information, see the discussion under “Regulation of Power Delivery Operations,”
above.
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 under/over
payments of income taxes, interest on unrecognized tax benefits, and tax-related
penalties in income tax expense.
Investment tax credits from utility
plant purchased in prior years are reported on the Balance Sheets as “Investment
tax credits.” These investment tax credits are being amortized to
income over the useful lives of the related utility plant.
Accounting for
Derivatives
DPL uses derivative instruments
(forward contracts, futures, swaps, and exchange-traded and over-the-counter
options) primarily to reduce gas commodity price volatility while limiting its
firm customers’ exposure to increases in the market price of gas. DPL
also manages commodity risk with physical natural gas and capacity contracts
that are not classified as derivatives. The primary goal of these
activities is to reduce the exposure of its regulated retail gas customers to
natural gas price fluctuations. 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 SFAS No. 71 until recovered. At December 31, 2007,
there was a net deferred derivative payable of $13.1 million, offset by a $13.1
million regulatory asset. At December 31, 2006, there was a net
deferred derivative payable of $27.3 million, offset by a $28.5 million
regulatory asset.
Accounts Receivable and
Allowance for Uncollectible Accounts
DPL’s accounts receivable balances
primarily consist 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 uses
the allowance method to account for uncollectible accounts
receivable.
Capitalized Interest and
Allowance for Funds Used During Construction
In accordance with the provisions of
SFAS No. 71, utilities can capitalize as Allowance for Funds Used During
Construction (AFUDC) the capital costs of financing the construction of plant
and equipment. The debt portion of AFUDC is recorded as a reduction
of “interest expense” and the equity portion of AFUDC is credited to “other
income” in the accompanying Statements of Earnings.
DPL recorded AFUDC for borrowed funds
of $.5 million, $.6 million, and $.9 million for the years ended
December 31, 2007, 2006, and 2005, respectively.
DPL recorded amounts for the equity
component of AFUDC of zero, $.6 million, and $.5 million for the years ended
December 31, 2007, 2006 and 2005, respectively.
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 issues. Costs associated with the redemption of debt are also
deferred and amortized over the lives of the new issues.
Goodwill and Goodwill
Impairment
Goodwill represents the excess of the
purchase price of an acquisition over the fair value of the net assets
acquired. DPL’s goodwill balances at December 31, 2007 and 2006 of
$8.0 million and $48.5 million, respectively, are primarily related to DPL’s
acquisition of Conowingo Power Company in 1995. In addition, on July
19, 2007, the Maryland PSC issued an order which provided for the recovery of a
portion of DPL’s goodwill through February 2018. As a
result of
this order, $40.5 million in DPL goodwill has been transferred to a regulatory
asset which will be amortized over that same period. DPL tests its
goodwill for impairment annually as of July 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 its carrying amount.
The July 1, 2007 test indicated
that none of DPL’s goodwill balance was impaired.
Long-Lived Asset Impairment
Evaluation
DPL evaluates certain long-lived assets
to be held and used (for example, equipment and real estate) to determine if
they are impaired whenever events or changes in circumstances indicate that
their carrying amount 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 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 sum of its expected future undiscounted cash
flows is less than its carrying amount.
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 amount exceeds their fair value
including costs to sell.
Pension and Other
Postretirement Benefit Plans
Pepco Holdings sponsors a
non-contributory retirement plan that covers substantially all employees of DPL
(the PHI Retirement Plan) 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 SFAS No. 87, “Employers’ Accounting for Pensions,”
as amended by SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension
and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106
and 132(R)” (SFAS No. 158), and its other postretirement benefits in accordance
with SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than
Pensions,” as amended by SFAS No. 158. Pepco Holdings’
financial statement disclosures were prepared in accordance with SFAS No. 132,
“Employers’ Disclosures about Pensions and Other Postretirement Benefits,” as
amended by SFAS No. 158.
DPL participates in benefit plans
sponsored by Pepco Holdings and as such, the provisions of SFAS No. 158 do not
have an impact on its financial condition and cash flows.
Property, Plant and
Equipment
Property, plant and equipment are
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
under the provisions of SFAS No. 144. Upon retirement, the cost of
regulated property, net of salvage, is charged to accumulated
depreciation. For additional information regarding the treatment of
retirement obligations, see the “Asset Retirement Obligations” section included
in this Note.
The annual provision for depreciation
on electric and gas property, plant and equipment is computed on the
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. Property, plant and equipment other than electric and gas
facilities is generally depreciated on a straight-line basis over the useful
lives of the assets. The system-wide composite depreciation rates for
2007, 2006 and 2005 for DPL’s transmission and distribution system property were
approximately 2.9%, 3.0%, and 3.1%, respectively.
Cash and Cash
Equivalents
Cash and cash equivalents include cash
on hand, money market funds, and commercial paper 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.
Restricted
Cash
Restricted cash represents cash either
held as collateral or pledged as collateral, and is restricted from use for
general corporate purposes.
Asset Retirement
Obligations
In accordance with SFAS No. 143,
“Accounting for Asset Retirement Obligations” and Financial Accounting Standards
Board Interpretation No. 47, asset removal costs are recorded as regulatory
liabilities. At December 31, 2007 and 2006, $234.2 million and
$229.5 million, respectively, are reflected as regulatory liabilities in the
accompanying Balance Sheets. Additionally, in 2005, DPL recorded
immaterial conditional asset retirement obligations for underground storage
tanks. Accretion for these asset retirement obligations has been
recorded as a regulatory asset.
Other Non-Current
Assets
The other assets balance principally
consists of deferred compensation trust assets and unamortized debt
expense.
Other Current
Liabilities
The other current liabilities balance
principally consists of customer deposits and accrued vacation
liability.
Other Deferred
Credits
The other deferred credits balance
principally consists of miscellaneous deferred liabilities.
Dividend
Restrictions
In addition to its future financial
performance, the ability of DPL to pay dividends is subject to limits imposed
by: (i) state corporate and regulatory laws, which impose limitations on the
funds that can be used to pay dividends and, in the case of regulatory
laws, may require the prior approval of DPL’s utility regulatory
commissions before dividends can be paid 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 $117.6 million and $113.3 million
of restricted retained earnings at December 31, 2007 and 2006,
respectively.
Newly
Adopted Accounting Standards
EITF Issue No. 06-3, “Disclosure
Requirements for Taxes Assessed by a Governmental Authority on Revenue-producing
Transactions”
On June 28, 2006, the FASB ratified
Emerging Issues Task Force (EITF) Issue No. 06-3, “Disclosure Requirements for
Taxes Assessed by a Governmental Authority on Revenue-producing Transactions”
(EITF 06-3). EITF 06-3 provides guidance on an entity’s
disclosure of its accounting policy regarding the gross or net presentation of
certain taxes and provides that if taxes included in gross revenues are
significant, a company should disclose the amount of such taxes for each period
for which an income statement is presented (i.e., both interim and annual
periods). Taxes within the scope of EITF 06-3 are those that are
imposed on and concurrent with a specific revenue-producing
transaction. Taxes assessed on an entity’s activities over a period
of time are not within the scope of EITF 06-3. DPL implemented EITF
06-3 during the first quarter of 2007. Taxes included in DPL’s gross
revenues were $13.3 million, $14.2 million and $14.1 million for the twelve
months ended December 31, 2007, 2006 and 2005, respectively.
FSP AUG AIR-1, “Accounting for Planned
Major Maintenance Activities”
On September 8, 2006, the FASB issued
FSP American Institute of Certified Public Accountants Industry Audit Guide,
Audits of Airlines--”Accounting for Planned Major Maintenance Activities” (FSP
AUG AIR-1), which prohibits the use of the accrue-in-advance method of
accounting for planned major maintenance activities in annual and interim
financial reporting periods for all industries. FSP AUG AIR-1 is
effective the first fiscal year beginning after December 15, 2006 (year
ended December 31, 2007 for DPL). Implementation of FSP AUG
AIR-1 did not have a material impact on DPL’s overall financial condition,
results of operations, or cash flows.
Recently
Issued Accounting Standards, Not Yet Adopted
SFAS No. 157, “Fair Value
Measurements”
In September 2006, the FASB issued SFAS
No. 157, "Fair Value Measurements" (SFAS No. 157) which defines fair value,
establishes a framework for measuring fair value in GAAP, and expands
disclosures about fair value measurements. SFAS No. 157 applies under
other accounting pronouncements that require or permit fair value measurements
and does not require any new fair value measurements. However, it is
possible that the application of this Statement
will
change current practice with respect to the definition of fair value, the
methods used to measure fair value, and the disclosures about fair value
measurements.
The provisions of SFAS No. 157, as
issued, are effective for financial statements issued for fiscal years beginning
after November 15, 2007, and interim periods within those fiscal years (January
1, 2008 for DPL). On February 6, 2008, the FASB decided to issue
final Staff Positions that will (i) defer the effective date of SFAS No. 157 for
all non-financial assets and non-financial liabilities, except those that are
recognized or disclosed at fair value in the financial statements on a recurring
basis (that is, at least annually) and (ii) remove certain leasing transactions
from the scope of SFAS No. 157. The final Staff Positions will defer
the effective date of SFAS No. 157 to fiscal years beginning after November 15,
2008, and interim periods within those fiscal years for items within the scope
of the final Staff Positions. DPL has evaluated the impact of SFAS
No. 157 and does not anticipate its adoption will have a material impact on its
overall financial condition, results of operations, cash flows, or footnote
disclosure requirements.
SFAS No. 159, “The Fair Value Option for Financial
Assets and Financial Liabilities - Including an amendment of FASB Statement No.
115”
On February 15, 2007, the FASB issued
SFAS No. 159, “The Fair Value Option for Financial Assets and Financial
Liabilities - Including an amendment of FASB Statement No. 115” (SFAS No. 159)
which permits entities to elect to measure eligible financial instruments at
fair value. The objective of SFAS No. 159 is to improve financial
reporting by providing entities with the opportunity to mitigate volatility in
reported earnings caused by measuring related assets and liabilities differently
without having to apply complex hedge accounting provisions. SFAS
No. 159 applies under other accounting pronouncements that require or
permit fair value measurements and does not require any new fair value
measurements. However, it is possible that the application of SFAS
No. 159 will change current practice with respect to the definition of fair
value, the methods used to measure fair value, and the disclosures about fair
value measurements.
SFAS No. 159 establishes presentation
and disclosure requirements designed to facilitate comparisons between companies
that choose different measurement attributes for similar types of assets and
liabilities. SFAS No. 159 requires companies to provide additional
information that will help investors and other users of financial statements to
more easily understand the effect of the company’s choice to use fair value on
its earnings. It also requires entities to display the fair value of
those assets and liabilities for which the company has chosen to use fair value
on the face of the balance sheet. SFAS No. 159 does not eliminate
disclosure requirements included in other accounting standards.
SFAS No. 159 applies to the beginning
of a reporting entity’s first fiscal year that begins after November 15, 2007
(January 1, 2008 for DPL), with early adoption permitted for an entity that has
also elected to apply the provisions of SFAS No. 157, Fair Value
Measurements. An entity is
prohibited from retrospectively applying SFAS No. 159, unless it chooses early
adoption. SFAS No. 159 also applies to eligible items existing at
November 15, 2007 (or early adoption date). DPL has evaluated the
impact of SFAS No. 159 and does not anticipate its adoption will have a material
impact on its overall financial condition, results of operations, cash flows, or
footnote disclosure requirements.
SFAS No. 141(R), “Business Combinations
– a replacement of FASB Statement No. 141”
On December 4, 2007, the FASB issued
SFAS No. 141(R), “Business Combinations – a replacement of FASB Statement No.
141” (SFAS No. 141(R)) which replaces FASB Statement No. 141, “Business
Combinations.” This Statement retains the fundamental requirements in
Statement 141 that the acquisition method of accounting (which Statement
141 called the purchase method) be used for all business combinations and for an
acquirer to be identified for each business combination.
SFAS No. 141(R) applies to all
transactions or other events in which an entity (the acquirer) obtains control
of one or more businesses (the acquiree). It does not apply to (i)
the formation of a joint venture, (ii) the acquisition of an asset or a group of
assets that does not constitute a business, (iii) a combination between entities
or businesses under common control and (iv) a combination between not-for-profit
organizations or the acquisition of a for-profit business by a not-for-profit
organization.
SFAS No. 141(R) applies prospectively
to business combinations for which the acquisition date is on or after the
beginning of the first annual reporting period beginning on or after December
15, 2008 (January 1, 2009 for DPL). An entity may not apply it
before that date.
SFAS No. 160, “Noncontrolling Interests
in Consolidated Financial Statements – an amendment of ARB No. 51”
On December 4, 2007, the FASB issued
SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements –
an amendment of ARB No. 51” (SFAS No. 160) which amends ARB 51 to establish
accounting and reporting standards for the noncontrolling interest in a
subsidiary and for the deconsolidation of a subsidiary. It clarifies
that a noncontrolling interest in a subsidiary is an ownership interest in the
consolidated entity that should be reported as equity in the consolidated
financial statements.
A noncontrolling interest, sometimes
called a minority interest, is the portion of equity in a subsidiary not
attributable, directly or indirectly, to a parent. The objective of SFAS No. 160
is to improve the relevance, comparability, and transparency of the financial
information that a reporting entity provides in its consolidated financial
statements by establishing accounting and reporting standards that require (i)
the ownership interests in subsidiaries held by parties other than the parent be
clearly identified, labeled, and presented in the consolidated statement of
financial position within equity, but separate from the parent’s equity, (ii)
the amount of consolidated net income attributable to the parent and to the
noncontrolling interest be clearly identified and presented on the face of the
consolidated statement of income, (iii) changes in a parent’s ownership interest
while the parent retains its controlling financial interest in its subsidiary be
accounted for consistently. A parent’s ownership interest in a
subsidiary changes if the parent purchases additional ownership interests in its
subsidiary or if the parent sells some of its ownership interests in its
subsidiary. It also changes if the subsidiary reacquires some of its ownership
interests or the subsidiary issues additional ownership interests. All of those
transactions are economically similar, and this Statement requires that they be
accounted for similarly, as equity transactions, (iv) when a subsidiary is
deconsolidated, any retained noncontrolling equity investment in the former
subsidiary be initially measured at fair value. The gain or loss on
the deconsolidation of the subsidiary is measured using the fair value of any
noncontrolling equity investment rather than the carrying amount of that
retained investment and
(v)
entities provide sufficient disclosures that clearly identify and distinguish
between the interests of the parent and the interests of the noncontrolling
owners.
SFAS No. 160 applies to all entities
that prepare consolidated financial statements, except not-for-profit
organizations, but will affect only those entities that have an outstanding
noncontrolling interest in one or more subsidiaries or that deconsolidate a
subsidiary.
SFAS No. 160 is effective for fiscal
years, and interim periods within those fiscal years, beginning on or after
December 15, 2008 (January 1, 2009, for DPL). Earlier adoption is
prohibited. SFAS No. 160 shall be applied prospectively as of the
beginning of the fiscal year in which this Statement is initially applied,
except for the presentation and disclosure requirements. The
presentation and disclosure requirements shall be applied retrospectively for
all periods presented. DPL is currently evaluating the impact SFAS
No. 160 may have on its overall financial condition, results of operations, cash
flows or footnote disclosure requirements.
(3) SEGMENT
INFORMATION
In accordance with SFAS No. 131,
“Disclosures about Segments of an Enterprise and Related Information,” DPL has
one segment, its regulated utility business.
(4) 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 $111.1 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, 2007
include $9.9 million in 2008, $9.4 million in 2009, $9.0 million in 2010, $8.4
million in 2011, $7.7 million in 2012 and $126.0 million after
2012.
Rental expense for operating leases,
including the Merrill Creek Reservoir lease, was $10.3 million, $11.1 million
and $11.7 million for the years ended December 31, 2007, 2006 and 2005,
respectively.
(5) PROPERTY, PLANT AND
EQUIPMENT
Property, plant and equipment is
comprised of the following:
|
|
|
Original
Cost
|
|
|
Accumulated
Depreciation
|
|
|
Net
Book Value
|
|
|
|
|
(Millions
of dollars)
|
|
|
Distribution
|
|
$ |
1,340.6 |
|
|
$ |
396.6 |
|
|
$ |
944.0 |
|
|
Transmission
|
|
|
632.2 |
|
|
|
204.6 |
|
|
|
427.6 |
|
|
Gas
|
|
|
363.7 |
|
|
|
104.8 |
|
|
|
258.9 |
|
|
Construction
work in progress
|
|
|
77.0 |
|
|
|
- |
|
|
|
77.0 |
|
|
Non-operating
and other property
|
|
|
202.3 |
|
|
|
122.8 |
|
|
|
79.5 |
|
|
Total
|
|
$ |
2,615.8 |
|
|
$ |
828.8 |
|
|
$ |
1,787.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distribution
|
|
$ |
1,273.3 |
|
|
$ |
374.4 |
|
|
$ |
898.9 |
|
|
Transmission
|
|
|
610.9 |
|
|
|
196.6 |
|
|
|
414.3 |
|
|
Gas
|
|
|
349.8 |
|
|
|
97.6 |
|
|
|
252.2 |
|
|
Construction
work in progress
|
|
|
67.2 |
|
|
|
- |
|
|
|
67.2 |
|
|
Non-operating
and other property
|
|
|
211.6 |
|
|
|
125.6 |
|
|
|
86.0 |
|
|
Total
|
|
$ |
2,512.8 |
|
|
$ |
794.2 |
|
|
$ |
1,718.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The balances of all property, plant and
equipment, which are primarily electric transmission and distribution property,
are stated at original cost. Utility plant is generally subject to a
first mortgage lien.
(6) PENSIONS AND OTHER
POSTRETIREMENT BENEFITS
DPL accounts for its participation in
the Pepco Holdings benefit plans as participation in a multi-employer
plan. For 2007, 2006, and 2005, DPL’s allocated share of the pension
and other postretirement net periodic benefit cost incurred by Pepco Holdings
was approximately $4.3 million, $.7 million, and $(2.0) million,
respectively. In 2007 and 2006, DPL made no contributions to the PHI
Retirement Plan, and $8.0 million and $6.8 million, respectively to other
postretirement benefit plans. At December 31, 2007 and 2006, DPL’s
prepaid pension expense of $178.1 million and $171.8 million, and
other postretirement benefit obligation of $4.5 million and $3.3 million,
included in Other Deferred Credits, effectively represent assets and benefit
obligations resulting from DPL’s participation in the Pepco Holdings benefit
plan.
(7) DEBT
LONG-TERM
DEBT
|
Type of Debt
|
Interest Rates
|
Maturity
|
2007
|
2006
|
|
|
|
|
|
(Millions
of dollars)
|
|
Amortizing
First Mortgage Bonds
|
6.95%
|
2007-2008
|
$ 4.4
|
$ 7.6
|
|
|
|
|
|
|
|
|
|
Unsecured
Tax-Exempt Bonds:
|
|
|
|
|
|
|
|
5.20%
|
2019
|
31.0
|
31.0
|
|
|
|
3.15%
|
2023 (c)
|
18.2
|
18.2
|
|
|
|
5.50%
|
2025 (a)
|
15.0
|
15.0
|
|
|
|
4.90%
|
2026 (b)
|
34.5
|
34.5
|
|
|
|
5.65%
|
2028
(a)
|
16.2
|
16.2
|
|
|
|
Variable
|
2030-2038
|
93.4
|
93.4
|
|
|
|
|
|
208.3
|
208.3
|
|
|
Medium-Term
Notes (unsecured):
|
|
|
|
|
|
|
|
7.06%-8.13%
|
2007
|
-
|
61.5
|
|
|
|
7.56%-7.58%
|
2017
|
14.0
|
14.0
|
|
|
|
6.81%
|
2018
|
4.0
|
4.0
|
|
|
|
7.61%
|
2019
|
12.0
|
12.0
|
|
|
|
7.72%
|
2027
|
10.0
|
10.0
|
|
|
|
|
|
40.0
|
101.5
|
|
|
|
|
|
|
|
|
|
Notes
(unsecured):
|
|
|
|
|
|
|
|
5.00%
|
2014
|
100.0
|
100.0
|
|
|
|
5.00%
|
2015
|
100.0
|
100.0
|
|
|
|
5.22%
|
2016
|
100.0
|
100.0
|
|
|
|
|
|
300.0
|
300.0
|
|
|
|
|
|
|
|
|
|
Total
long-term debt
|
|
|
552.7
|
617.4
|
|
|
Unamortized
premium and discount, net
|
|
|
(.7)
|
(.9)
|
|
|
Current
maturities of long-term debt
|
|
|
(22.6)
|
(64.7)
|
|
|
Total
net long-term debt
|
|
|
$529.4
|
$551.8
|
|
|
|
|
|
|
|
|
(a) The
bonds are subject to mandatory tender on July 1, 2010.
(b) The
bonds are subject to mandatory tender on May 1, 2011.
The outstanding First Mortgage Bonds
issued by DPL are secured by a lien on substantially all of DPL’s property,
plant and equipment.
Maturities of long-term debt and
sinking fund requirements during the next five years are as follows: $22.6
million in 2008, zero in 2009, $31.2 million in 2010, $34.5 million in 2011,
zero in 2012, and $464.4 million thereafter.
DPL’s long-term debt is subject to
certain covenants. DPL is in compliance with all
requirements.
SHORT-TERM
DEBT
DPL, a regulated utility, 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, 2007 and 2006 is as follows.
|
|
2007
|
2006
|
|
|
|
(Millions
of dollars)
|
|
|
Commercial
paper
|
$ 24.0
|
$ 91.1
|
|
|
Intercompany
borrowings
|
157.4
|
-
|
|
|
Variable
rate demand bonds
|
104.8
|
104.8
|
|
|
Total
|
$286.2
|
$195.9
|
|
|
|
|
|
|
Commercial
Paper
DPL maintains an ongoing commercial
paper program of up to $275 million. The commercial paper notes can be issued
with maturities up to 270 days from the date of issue. The commercial paper
program is backed by a $500 million credit facility, described below under the
heading “Credit Facility,” shared with Potomac Electric Power Company (Pepco)
and Atlantic City Electric Company (ACE).
DPL had $24.0 million of commercial
paper outstanding at December 31, 2007 and $91.1 million of commercial paper
outstanding at December 31, 2006. The weighted average interest rates
for commercial paper issued during 2007 and 2006 were 5.35% and 5.30%,
respectively. The weighted average maturity for commercial paper issued during
2007 and 2006 was four days and seven days, respectively.
Variable Rate Demand
Bonds
Variable Rate Demand Bonds (“VRDB”) 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 the bonds submitted for purchase will continue to be
remarketed successfully due to the credit worthiness of the company and because
the remarketing agent resets the interest rate to the then-current market rate.
The company also may utilize one of the fixed rate/fixed term conversion options
of the bonds to establish a maturity which corresponds to the date of final
maturity of the bonds. On this basis, DPL views VRDB as a source of long-term
financing. The VRDB outstanding in 2007 and 2006 mature as
follows: 2017 ($26.0 million), 2024 ($33.3 million), 2028 ($15.5
million), and 2029 ($30.0 million). The weighted average interest
rate for VRDB was 3.87% during 2007 and 3.64% during 2006. Of the
$104.8 in VRDB, $71.5 is collateralized with first mortgage bonds.
Credit
Facility
PHI, Pepco, DPL and ACE maintain a
credit facility to provide for their respective short-term liquidity
needs.
The aggregate borrowing limit under the
facility is $1.5 billion, all or any portion of which may be used to obtain
loans or to issue letters of credit. PHI’s credit limit under the facility is
$875 million. The credit limit of each of Pepco, DPL and ACE is the
lesser of $500 million and the maximum amount of debt the company is permitted
to have outstanding by its regulatory authorities, except that the aggregate
amount of credit used by Pepco, DPL and ACE at any given time collectively may
not exceed $625 million. The interest rate payable by each company on
utilized funds is based on the prevailing prime rate or Eurodollar rate, plus a
margin that varies according to the credit rating of the
borrower. 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 $150 million. Any swingline loan must be repaid
by the borrower within seven days of receipt thereof. All
indebtedness incurred under the facility is unsecured.
The facility commitment expiration date
is May 5, 2012, with each company having the right to elect to have 100% of the
principal balance of the loans outstanding on the expiration date continued as
non-revolving term loans for a period of one year from such expiration
date.
The facility is intended to serve
primarily as a source of liquidity to support the commercial paper programs of
the respective companies. The companies also are permitted to use the
facility to borrow funds for general corporate purposes and issue letters of
credit. In order for a borrower to use the facility, certain
representations and warranties made by the borrower at the time the credit
agreement was entered into also must be true at the time the facility is
utilized, and the borrower must be in compliance with specified covenants,
including the financial covenant described below. However, a material
adverse change in the borrower’s business, property, and results of operations
or financial condition subsequent to the entry into the credit agreement is not
a condition to the availability of credit under the facility. Among
the covenants to which each of the companies is subject are (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 certain trust preferred
securities and deferrable interest subordinated debt from the definition of
total indebtedness (not to exceed 15% of total capitalization), (ii) a
restriction on sales or other dispositions of assets, other than sales and
dispositions permitted by the credit agreement, and (iii) a restriction on the
incurrence of liens on the assets of a borrower or any of its significant
subsidiaries other than liens permitted by the credit agreement. The
agreement does not include any rating triggers.
(8) 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 as
part of Pepco’s acquisition of Conectiv on August 1, 2002. Under
this tax sharing agreement, PHI’s consolidated federal income tax liability is
allocated based upon PHI’s and its subsidiaries’ separate taxable income or
loss.
The provision for income taxes,
reconciliation of income tax expense, and components of deferred income tax
liabilities (assets) are shown below.
Provision for Income
Taxes
|
|
|
|
|
|
|
2006
|
2005
|
|
|
|
|
(Millions
of dollars)
|
|
|
Current
Tax Expense (Benefit)
|
|
|
|
|
|
Federal
|
$11.9
|
$(4.4)
|
$64.3
|
|
|
State
and local
|
(1.2)
|
(1.3)
|
16.4
|
|
|
Total
Current Tax Expense (Benefit)
|
10.7
|
(5.7)
|
80.7
|
|
|
Deferred
Tax Expense (Benefit)
|
|
|
|
|
|
Federal
|
21.0
|
30.0
|
(16.3)
|
|
|
State
and local
|
6.3
|
8.7
|
(5.9)
|
|
|
Investment
tax credit amortization
|
(.8)
|
(.9)
|
(.9)
|
|
|
Total
Deferred Tax Expense (Benefit)
|
26.5
|
37.8
|
(23.1)
|
|
|
Total
Income Tax Expense
|
$37.2
|
$32.1
|
$57.6
|
|
|
|
|
|
|
|
Reconciliation of Income Tax
Expense
|
|
|
|
|
|
|
|
|
|
2006
|
|
2005
|
|
|
|
|
(Millions
of dollars)
|
|
|
|
|
Amount
|
Rate
|
|
Amount
|
Rate
|
|
Amount
|
Rate
|
|
|
|
|
|
|
|
Income
Before Income Taxes
|
$
|
82.1
|
|
$
|
74.6
|
|
$
|
132.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
tax at federal statutory rate
|
$
|
28.7
|
35%
|
$
|
26.1
|
35%
|
$
|
46.3
|
35%
|
|
|
Increases
(decreases) resulting from
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation
|
|
2.4
|
3
|
|
1.8
|
2
|
|
2.0
|
1
|
|
|
State
income taxes, net of
federal
effect
|
|
4.3
|
5
|
|
4.8
|
6
|
|
6.0
|
5
|
|
|
Tax
credits
|
|
(.8)
|
(1)
|
|
(.9)
|
(1)
|
|
(.9)
|
(1)
|
|
|
Change
in estimates related to
prior
year tax liabilities
|
|
(1.0)
|
(1)
|
|
.6
|
1
|
|
4.3
|
3
|
|
|
Deferred
tax basis adjustments
|
|
3.2
|
4
|
|
-
|
-
|
|
-
|
-
|
|
|
Other,
net
|
|
.4
|
-
|
|
(.3)
|
-
|
|
(.1)
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Income Tax Expense
|
$
|
37.2
|
45%
|
$
|
32.1
|
43%
|
$
|
57.6
|
43%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FIN 48, “Accounting for
Uncertainty in Income Taxes”
As disclosed in Note 2, “Summary of
Significant Accounting Policies”, DPL adopted FIN 48 effective January 1,
2007. Upon adoption, DPL recorded the cumulative effect of the change
in accounting principle of $.1 million as an increase in retained
earnings. Also upon adoption, DPL had $43.2 million
of unrecognized tax benefits and $9.8 million of related accrued
interest.
Reconciliation of Beginning and Ending
Balances of Unrecognized Tax Benefits
|
|
$
|
43.2
|
|
Tax
positions related to current year:
|
|
|
|
Additions
|
|
1.5
|
|
Tax
positions related to prior years:
|
|
|
|
Additions
|
|
6.8
|
|
Settlements
|
|
(10.2)
|
|
|
$
|
41.3
|
|
|
|
|
As of December 31, 2007, DPL had $7.6
million of accrued interest related to unrecognized tax benefits.
Unrecognized Benefits That If
Recognized Would Affect the Effective Tax Rate
Unrecognized tax benefits represent
those tax benefits 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, in accordance with FIN 48, 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,
2007, DPL had no unrecognized tax benefits that, if recognized, would lower the
effective tax rate.
DPL recognizes interest and penalties
relating to its unrecognized tax benefits as an element of tax
expense. For the year ended December 31, 2007, DPL recognized $1.3
million of interest expense and no penalties, net, as a component of tax
expense.
Possible Changes to Unrecognized
Benefits
Total unrecognized tax benefits that
may change over the next twelve months include the matter of Mixed Service
Costs. See discussion in Note 11, “Commitments and Contingencies --
IRS Mixed Service Cost Issue.”
Tax Years Open to
Examination
DPL, as in indirect subsidiary of PHI,
is included on PHI’s consolidated federal tax return. DPL’s federal
income tax liabilities for all years through 1999 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, Delaware,
and Virginia), are the same as noted above.
Components of Deferred
Income Tax Liabilities (Assets)
|
|
|
As of December 31,
|
|
|
|
|
2007
|
|
|
2006
|
|
|
|
|
(Millions
of dollars)
|
|
|
Deferred
Tax Liabilities (Assets)
|
|
|
|
|
|
|
|
Depreciation
and other book-to-tax basis differences
|
|
$ |
302.0 |
|
|
$ |
323.7 |
|
|
Deferred
taxes on amounts to be collected through
future
rates
|
|
|
39.1 |
|
|
|
39.4 |
|
|
Prepaid
pension expense
|
|
|
68.9 |
|
|
|
67.4 |
|
|
Deferred
investment tax credits
|
|
|
(3.5 |
) |
|
|
(3.8 |
) |
|
Above-market
purchased energy contracts
and
other Electric restructuring liabilities
|
|
|
(9.5 |
) |
|
|
(10.7 |
) |
|
Other
|
|
|
8.5 |
|
|
|
2.6 |
|
|
Total
Deferred Tax Liabilities, net
|
|
|
405.5 |
|
|
|
418.6 |
|
|
Deferred
tax assets included in Other Current Assets
|
|
|
6.1 |
|
|
|
6.2 |
|
|
Deferred
tax liabilities included in Other Current Liabilities
|
|
|
(1.5 |
) |
|
|
(.7 |
) |
|
Total
Deferred Tax Liabilities, net - non-current
|
|
$ |
410.1 |
|
|
$ |
424.1 |
|
|
|
|
|
|
|
|
|
|
|
The net deferred tax liability
represents the tax effect, at presently enacted tax rates, of temporary
differences between the financial statement 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, 2007 and
2006.
The Tax Reform Act of 1986 repealed the
Investment Tax Credit (ITC) for property placed in service after
December 31, 1985, except for certain transition property. ITC
previously earned on DPL’s property continues to be normalized over the
remaining service lives of the related assets.
Taxes Other Than Income
Taxes
Taxes other than income taxes for each
year are shown below. These amounts relate to the Power Delivery
business and are recoverable through rates.
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
|
(Millions
of dollars)
|
|
|
Gross
Receipts/Delivery
|
|
$ |
17.2 |
|
|
$ |
18.9 |
|
|
$ |
18.9 |
|
|
Property
|
|
|
18.3 |
|
|
|
17.1 |
|
|
|
15.1 |
|
|
Environmental,
Use and Other
|
|
|
.8 |
|
|
|
.6 |
|
|
|
.4 |
|
|
Total
|
|
$ |
36.3 |
|
|
$ |
36.6 |
|
|
$ |
34.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(9) PREFERRED
STOCK
|
|
|
Shares Outstanding
|
December 31,
|
|
|
Series
|
Redemption Price
|
2007
|
2006
|
2007
|
2006
|
|
|
|
|
(Millions
of dollars)
|
|
Redeemable Serial
Preferred (a)
|
|
|
|
|
|
|
|
$100
per share par value:
3.70%-5.00%
|
$103-$105
|
-
|
181,698
|
$ -
|
$18.2
|
|
|
|
|
|
|
|
|
|
|
(a)
|
On
January 18, 2007, DPL redeemed all of the outstanding shares of its
Redeemable Serial Preferred Stock, at prices ranging from 103% to 105% of
par, in an aggregate amount of approximately $18.9
million.
|
(10)
FAIR VALUES OF
FINANCIAL INSTRUMENTS
|
|
2007
|
2006
|
|
|
Carrying
Amount
|
Fair
Value
|
Carrying
Amount
|
Fair
Value
|
|
|
(Millions
of dollars)
|
|
Assets
|
|
|
|
|
|
Derivative
instruments
|
$ 13.1
|
$ 13.1
|
$ 28.7
|
$ 28.7
|
|
Liabilities
and Capitalization
|
|
|
|
|
|
Long-term
debt
|
$552.0
|
$544.0
|
$616.5
|
$613.9
|
|
Redeemable
serial preferred stock
|
$ -
|
$ -
|
$ 18.2
|
$ 17.3
|
|
Derivative
instruments
|
$ 13.1
|
$ 13.1
|
$ 27.6
|
$ 27.6
|
The methods and assumptions below were
used to estimate, at December 31, 2007 and 2006, the fair value of each class of
financial instruments shown above for which it is practicable to estimate a
value.
The fair values of derivative
instruments were derived based on quoted market prices.
The fair values of the Long-term debt,
which includes First Mortgage Bonds, Amortizing First Mortgage Bonds, Unsecured
Tax-Exempt Bonds, Medium-Term Notes, and Unsecured Notes, including amounts due
within one year, were derived based on current market prices, or for issues with
no market price available, were based on discounted cash flows using current
rates for similar issues with similar terms and remaining
maturities.
The fair value of the Redeemable serial
preferred stock, excluding amounts due within one year, were derived based on
quoted market prices or discounted cash flows using current rates of preferred
stock with similar terms.
The carrying amounts of all other
financial instruments in DPL’s accompanying financial statements approximate
fair value.
(11) COMMITMENTS AND
CONTINGENCIES
Rate
Proceedings
On September 4, 2007, DPL submitted its
2007 Gas Cost Rate (GCR) filing to the DPSC. The GCR permits DPL to
recover its gas procurement costs through customer rates. On
September 18, 2007, the DPSC issued an initial order approving a 5.7% decrease
in the level of the GCR, which became effective November 1, 2007, subject to
refund and pending final DPSC approval after evidentiary hearings.
In electric service distribution base
rate cases it filed in Maryland, and pending in 2007, DPL proposed the adoption
of a BSA for retail customers. Under the BSA, customer delivery rates
are subject to adjustment (through a surcharge or credit mechanism), depending
on whether actual distribution revenue per customer exceeds or falls short of
the approved revenue-per-customer amount. The BSA will increase rates
if actual distribution revenues fall below the level approved by the MPSC and
will decrease rates if actual distribution revenues are above the approved
level. The result will be that, over time, DPL would collect its
authorized revenues for distribution deliveries. As a consequence, a
BSA “decouples” revenue from unit sales consumption and ties the growth in
revenues to the growth in the number of customers. Some advantages of
the BSA are that it (i) eliminates revenue fluctuations due to weather and
changes in customer usage patterns and, therefore, provides for more predictable
utility distribution revenues that are better aligned with costs,
(ii) provides for more reliable fixed-cost recovery, (iii) tends to
stabilize customers’ delivery bills, and (iv) removes any disincentives for
DPL to promote energy efficiency programs for its customers, because it breaks
the link between overall sales volumes and delivery revenues.
On July 19, 2007, the MPSC issued an
order in the electric service distribution rate case filed by DPL, which
included approval of a BSA. The order approved an annual increase in
distribution rates of approximately $14.9 million (including a decrease in
annual depreciation expense of approximately $.9 million). The
approved distribution rate reflects an ROE of 10.0%. The order
provided that the rate increases are effective as of June 16, 2007, and will
remain in effect for an initial period of nine months from the date of the order
(or until April 19, 2008). These rates are subject to a Phase II
proceeding in which the MPSC will consider the results of an audit of DPL’s cost
allocation manual, as filed with the MPSC, to determine whether a further
adjustment to the rates is required. Hearings for the Phase II
proceeding are scheduled for mid-March 2008.
Default
Electricity Supply Proceedings
Virginia
In June 2007, the Virginia State
Corporation Commission (VSCC) denied DPL’s request for an increase in its rates
for Default Service for the period July 1, 2007 to May 31, 2008. DPL
appealed in both state and federal courts. Those appeals have been
dismissed in light of the closing of the sale of DPL's Virginia electric
operations as described below under the heading “DPL Sale of Virginia
Operations.”
DPL
Sale of Virginia Operations
On January 2, 2008, DPL completed (i)
the sale of its retail electric distribution business on the Eastern Shore of
Virginia to A&N Electric Cooperative (A&N) for a purchase price of
approximately $45.2 million, after closing adjustments, and (ii) the
sale of its wholesale electric transmission business located on the Eastern
Shore of Virginia to Old Dominion Electric Cooperative (ODEC) for a purchase
price of approximately $5.4 million, after closing
adjustments. Each of A&N and ODEC assumed certain post-closing
liabilities and unknown pre-closing liabilities related to the respective assets
they are purchasing (including, in the A&N transaction, most environmental
liabilities), except that DPL remained liable for unknown pre-closing
liabilities if they become known within six months after the January 2, 2008
closing date. These sales are expected to result in an immaterial
financial gain to DPL that will be recorded in the first quarter of
2008.
Environmental
Litigation
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. In addition, federal and state statutes authorize governmental
agencies to compel responsible parties to clean up certain abandoned or
unremediated hazardous waste sites. DPL 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. Although penalties assessed for violations of
environmental laws and regulations are not recoverable from DPL’s customers,
environmental clean-up costs incurred by DPL would be included in its cost of
service for ratemaking purposes.
Cambridge, Maryland
Site. In July 2004, DPL entered into an administrative consent order with
the Maryland Department of the Environment (MDE) to perform a Remedial
Investigation/Feasibility Study (RI/FS) to further identify the extent of soil,
sediment and ground and surface water contamination related to former
manufactured gas plant (MGP) operations at a Cambridge, Maryland site on
DPL-owned property and to investigate the extent of MGP contamination on
adjacent property. The MDE has approved the RI and DPL submitted a
final FS to MDE on February 15, 2007. No further MDE action is
required with respect to the final FS. The costs of cleanup (as
determined by the RI/FS and subsequent negotiations with MDE) are anticipated to
be approximately $3.8 million. The
remedial action to be taken by DPL will include dredging activities within
Cambridge Creek, which are expected to commence in March 2008, and soil
excavation on DPL’s and adjacent property as early as August
2008. The final cleanup costs will include protective measures to
control contaminant migration during the dredging activities and improvements to
the existing shoreline.
Carolina Transformer
Site. In August 2006, the U.S. Environmental Protection Agency
(EPA) notified DPL that it had been identified as an entity that sent PCB-laden
oil to be disposed at the Carolina Transformer site in Fayetteville, North
Carolina. The EPA notification stated that, on this basis, DPL may be
a potentially responsible party (PRP). In December 2007, DPL agreed
to enter into a settlement agreement with EPA and the PRP group at the Carolina
Transformer site. Under the terms of the settlement, (i) DPL
will pay $162,000 to EPA to resolve any liability that it might have at the
site, (ii) EPA covenants not to sue or bring administrative action against
DPL for response costs at the site, (iii) other PRP group
members
release
all rights for cost recovery or contribution claims they may have against DPL,
and (iv) DPL releases all rights for cost recovery or contribution claims
that they may have against other parties settling with EPA. The
consent decree is expected to be filed with the U.S. District Court in North
Carolina in the second quarter of 2008.
IRS
Mixed Service Cost Issue
During 2001, DPL changed its method of
accounting with respect to capitalizable construction costs for income tax
purposes. The change allowed DPL to accelerate the deduction of
certain expenses that were previously capitalized and
depreciated. Through December 31, 2005, these accelerated deductions
generated incremental tax cash flow benefits of approximately $62 million,
primarily attributable to its 2001 tax returns.
In 2005, the Treasury Department issued
proposed regulations that, if adopted in their current form, would require DPL
to change its method of accounting with respect to capitalizable construction
costs for income tax purposes for tax periods beginning in
2005. Based on the proposed regulations, PHI in its 2005 federal tax
return adopted an alternative method of accounting for capitalizable
construction costs that management believes will be acceptable to the Internal
Revenue Service (IRS).
At the same time as the proposed
regulations were released, the IRS issued Revenue Ruling 2005-53, which is
intended to limit the ability of certain taxpayers to utilize the method of
accounting for income tax purposes they utilized on their tax returns for 2004
and prior years with respect to capitalizable construction costs. In
line with this Revenue Ruling, the IRS revenue agent’s report for the 2001 and
2002 tax returns disallowed substantially all of the incremental tax benefits
that DPL had claimed on those returns by requiring it to capitalize and
depreciate certain expenses rather than treat such expenses as current
deductions. PHI’s protest of the IRS adjustments is among the
unresolved audit matters relating to the 2001 and 2002 audits pending before the
Appeals Office.
In February 2006, PHI paid
approximately $121 million of taxes to cover the amount of additional taxes and
interest that management estimated to be payable for the years 2001 through
2004 based on the method of tax accounting that PHI, pursuant to the
proposed regulations, adopted on its 2005 tax return. However, if the
IRS is successful in requiring DPL to capitalize and depreciate construction
costs that result in a tax and interest assessment greater than management’s
estimate of $121 million, PHI will be required to pay additional taxes and
interest only to the extent these adjustments exceed the $121 million
payment made in February 2006. It is reasonably possible that PHI’s
unrecognized tax benefits related to this issue will significantly decrease in
the next 12 months as a result of a settlement with the IRS.
Contractual
Obligations
As of December 31, 2007, DPL’s
contractual obligations under non-derivative fuel and power purchase contracts
were $628.4 million in 2008, $478.5 million in 2009 to 2010, $43.9 million in
2011 to 2012, and zero in 2013 and thereafter.
(12) 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 causal
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, 2007, 2006 and 2005 were $107.6 million, $100.5
million, and $98.4 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 Earnings:
|
|
|
|
|
|
2006
|
2005
|
|
(Expense)
Income
|
(Millions
of dollars)
|
|
Full
Requirements Contract with Conectiv
Energy
Supply for power, capacity and
ancillary
services to service Provider
of
Last Resort Load (a)
|
$ -
|
$(122.2)
|
$(426.1)
|
|
SOS
with Conectiv Energy Supply
(a)
|
(262.9)
|
(213.7)
|
(53.4)
|
|
SOS
with Pepco Energy Services (a)
|
(6.2)
|
-
|
-
|
|
Intercompany
lease transactions (b)
|
7.6
|
8.9
|
8.3
|
|
Transcompany
pipeline gas sales with Conectiv Energy Supply (c)
|
2.5
|
2.8
|
7.5
|
|
Transcompany
pipeline gas purchase with Conectiv Energy Supply (d)
|
$ (1.9)
|
$ (2.9)
|
$ (5.4)
|
(a) Included
in fuel and purchased energy.
(b) Included
in electric revenue.
(c) Included
in gas revenue.
(d) Included
in gas purchased.
As of December 31, 2007 and 2006, DPL
had the following balances on its balance sheets due (to)/from related
parties:
|
|
2007
|
2006
|
|
Asset
(Liability)
|
(Millions
of dollars)
|
|
Receivable from Related Party
(current)
PHI Service
Company
|
$ -
|
$ 46.4
|
|
Payable
to Related Party (current)
|
|
|
|
PHI
Parent
|
$ -
|
$(24.7)
|
|
PHI
Service Company
|
(24.7)
|
-
|
|
Conectiv
Energy Supply
|
(23.0)
|
(24.6)
|
|
Pepco
Energy Services
|
(6.6)
|
(7.7)
|
|
The
items listed above are included in the “Accounts payable to
associated
companies” balance on the Balance Sheet of $54.0
respectively.
|
|
|
|
Money
Pool Balance with Pepco Holdings
(included
in short-term debt)
|
$(157.4)
|
$ -
|
|
Money
Pool Interest Accrued (included in interest accrued)
|
$ (.6)
|
$ -
|
|
|
|
|
(13) 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.
|
|
2007
|
|
|
First
Quarter
|
Second
Quarter
|
Third
Quarter
|
Fourth
Quarter
|
Total
|
|
|
(Millions
of dollars)
|
|
Total
Operating Revenue
|
$421.5
|
$330.1
|
$399.4
|
|
$345.0
|
|
$1,496.0
|
|
Total
Operating Expenses
|
384.3
|
310.0
|
367.3
|
|
312.4
|
|
1,374.0
|
|
Operating
Income
|
37.2
|
20.1
|
32.1
|
|
32.6
|
|
122.0
|
|
Other
Expenses
|
(9.9)
|
(9.7)
|
(10.2)
|
|
(10.1)
|
|
(39.9)
|
|
Income
Before Income Tax Expense
|
27.3
|
10.4
|
21.9
|
|
22.5
|
|
82.1
|
|
Income
Tax Expense
|
11.3
|
1.8
|
10.8
|
(a)
|
13.3
|
(a)
|
37.2
|
|
Net
Income
|
16.0
|
8.6
|
11.1
|
|
9.2
|
|
44.9
|
|
Dividends
on Preferred Stock
|
-
|
-
|
-
|
|
-
|
|
-
|
|
Earnings
Available for Common Stock
|
$ 16.0
|
$ 8.6
|
$ 11.1
|
|
$ 9.2
|
|
$ 44.9
|
|
|
2006
|
|
|
First
Quarter
|
Second
Quarter
|
Third
Quarter
|
Fourth
Quarter
|
Total
|
|
|
(Millions
of dollars)
|
|
Total
Operating Revenue
|
$368.5
|
$339.3
|
$394.9
|
|
$320.7
|
|
$1,423.4
|
|
Total
Operating Expenses
|
324.0
|
317.4
|
374.8
|
|
295.7
|
|
1,311.9
|
|
Operating
Income
|
44.5
|
21.9
|
20.1
|
|
25.0
|
|
111.5
|
|
Other
Expenses
|
(8.5)
|
(8.8)
|
(9.7)
|
|
(9.9)
|
|
(36.9)
|
|
Income
Before Income Tax Expense
|
36.0
|
13.1
|
10.4
|
|
15.1
|
|
74.6
|
|
Income
Tax Expense
|
15.2
|
6.2
|
5.1
|
|
5.6
|
|
32.1
|
|
Net
Income
|
20.8
|
6.9
|
5.3
|
|
9.5
|
|
42.5
|
|
Dividends
on Preferred Stock
|
.2
|
.2
|
.2
|
|
.2
|
|
.8
|
|
Earnings
Available for Common Stock
|
$ 20.6
|
$ 6.7
|
$ 5.1
|
|
$ 9.3
|
|
$ 41.7
|
|
(a)
|
Includes
charge to income tax expense of $1.2 million and $2.0 million,
respectively, related to analysis of deferred tax
accounts.
|
THIS
PAGE LEFT INTENTIONALLY BLANK.
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. Because of 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 assessed its internal
control over financial reporting as of December 31, 2007 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 its internal control over financial reporting was
effective as of December 31, 2007.
This Annual Report on Form 10-K does
not include an attestation report of ACE’s registered public accounting firm,
PricewaterhouseCoopers LLP, regarding internal control over financial
reporting. Management’s report was not subject to attestation by
PricewaterhouseCoopers LLP pursuant to temporary rules of the Securities and
Exchange Commission that permit ACE to provide only management’s report in this
Form 10-K.
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 listed in the accompanying index
present fairly, in all material respects, the financial position of Atlantic
City Electric Company (a wholly owned subsidiary of Pepco Holdings, Inc.) and
its subsidiaries at December 31, 2007 and December 31, 2006, and the results of
their operations and their cash flows for each of the three years in the period
ended December 31, 2007 in conformity with accounting principles generally
accepted in the United States of America. In addition, in our
opinion, the financial statement schedule 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.
As
discussed in Note 8 to the consolidated financial statements, the Company
changed its manner of accounting and reporting for uncertain tax positions in
2007.
PricewaterhouseCoopers
LLP
Washington,
DC
|
ATLANTIC
CITY ELECTRIC COMPANY
CONSOLIDATED
STATEMENTS OF EARNINGS
|
|
|
|
|
|
|
|
2006
|
|
2005
|
|
|
|
(Millions
of dollars)
|
|
|
|
Operating
Revenue
|
|
$1,542.5
|
|
$1,373.3
|
|
$1,350.1
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Expenses
|
|
|
|
|
|
|
|
|
Fuel
and purchased energy
|
|
1,051.0
|
|
924.2
|
|
850.9
|
|
|
Other
operation and maintenance
|
|
164.8
|
|
147.7
|
|
154.5
|
|
|
Depreciation
and amortization
|
|
80.2
|
|
111.3
|
|
122.2
|
|
|
Other
taxes
|
|
22.4
|
|
22.9
|
|
22.6
|
|
|
Deferred
electric service costs
|
|
66.0
|
|
15.0
|
|
56.6
|
|
|
Gain
on sale of assets
|
|
(.4)
|
|
-
|
|
-
|
|
|
Total
Operating Expenses
|
|
1,384.0
|
|
1,221.1
|
|
1,206.8
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Income
|
|
158.5
|
|
152.2
|
|
143.3
|
|
|
|
|
|
|
|
|
|
|
|
Other
Income (Expenses)
|
|
|
|
|
|
|
|
|
Interest
and dividend income
|
|
1.5
|
|
2.3
|
|
1.9
|
|
|
Interest
expense
|
|
(64.2)
|
|
(63.7)
|
|
(58.9)
|
|
|
Other
income
|
|
5.1
|
|
5.4
|
|
6.0
|
|
|
Other
expenses
|
|
-
|
|
(3.1)
|
|
-
|
|
|
Total
Other Expenses
|
|
(57.6)
|
|
(59.1)
|
|
(51.0)
|
|
|
|
|
|
|
|
|
|
|
|
Income
Before Income Tax Expense and
Extraordinary
Item
|
|
100.9
|
|
93.1
|
|
92.3
|
|
|
|
|
|
|
|
|
|
|
|
Income
Tax Expense
|
|
40.9
|
|
33.0
|
|
41.2
|
|
|
|
|
|
|
|
|
|
|
|
Income
from Continuing Operations
|
|
60.0
|
|
60.1
|
|
51.1
|
|
|
|
|
|
|
|
|
|
|
|
Discontinued
Operations (Note 13)
|
|
|
|
|
|
|
|
|
Income
from operations (net of tax of $.1
million,
$1.8 million, and $2.1 million,
respectively)
|
|
.1
|
|
2.6
|
|
3.1
|
|
|
|
|
|
|
|
|
|
|
|
Income
Before Extraordinary Item
|
|
60.1
|
|
62.7
|
|
54.2
|
|
|
|
|
|
|
|
|
|
|
|
Extraordinary
Item (net of tax of $6.2 million)
|
|
-
|
|
-
|
|
9.0
|
|
|
|
|
|
|
|
|
|
|
|
Net
Income
|
|
60.1
|
|
62.7
|
|
63.2
|
|
|
|
|
|
|
|
|
|
|
|
Dividends
on Redeemable Serial Preferred Stock
|
|
.3
|
|
.3
|
|
.3
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
Available for Common Stock
|
|
$ 59.8
|
|
$ 62.4
|
|
$ 62.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
accompanying Notes are an integral part of these Consolidated Financial
Statements.
|
|
ATLANTIC
CITY ELECTRIC COMPANY
CONSOLIDATED
BALANCE SHEETS
|
|
ASSETS
|
|
|
|
|
(Millions
of dollars)
|
|
CURRENT
ASSETS
|
|
|
|
|
Cash
and cash equivalents
|
$ 7.0
|
|
$ 5.5
|
|
Restricted
cash
|
9.5
|
|
9.0
|
|
Accounts
receivable, less allowance for uncollectible
accounts
of $4.9 million and $5.5 million, respectively
|
198.1
|
|
163.0
|
|
Fuel,
materials and supplies - at average cost
|
14.1
|
|
12.6
|
|
Prepayments
of income taxes
|
47.0
|
|
54.5
|
|
Prepaid
expenses and other
|
16.8
|
|
16.9
|
|
B.L.
England assets held for sale
|
-
|
|
14.4
|
|
Total
Current Assets
|
292.5
|
|
275.9
|
|
INVESTMENTS
AND OTHER ASSETS
|
|
|
|
|
Regulatory
assets
|
818.0
|
|
857.5
|
|
Restricted
funds held by trustee
|
6.8
|
|
17.5
|
|
Prepaid
pension expense
|
8.5
|
|
11.7
|
|
Other
|
36.9
|
|
19.5
|
|
B.L.
England assets held for sale
|
-
|
|
79.2
|
|
Total
Investments and Other Assets
|
870.2
|
|
985.4
|
|
|
|
|
|
|
|
|
|
|
|
PROPERTY,
PLANT AND EQUIPMENT
|
|
|
|
|
Property,
plant and equipment
|
2,078.0
|
|
1,942.9
|
|
Accumulated
depreciation
|
(633.5)
|
|
(599.1)
|
|
Net
Property, Plant and Equipment
|
1,444.5
|
|
1,343.8
|
|
|
|
|
|
|
TOTAL
ASSETS
|
$2,607.2
|
|
$2,605.1
|
|
|
|
|
|
|
|
|
|
|
|
The
accompanying Notes are an integral part of these Consolidated Financial
Statements.
|
|
ATLANTIC
CITY ELECTRIC COMPANY
CONSOLIDATED
BALANCE SHEETS
|
|
LIABILITIES
AND SHAREHOLDER’S EQUITY
|
|
|
|
(Millions
of dollars, except shares)
|
|
|
CURRENT
LIABILITIES
|
|
|
|
Short-term
debt
|
$ 51.7
|
$ 23.8
|
|
Current
maturities of long-term debt
|
81.0
|
45.9
|
|
Accounts
payable and accrued liabilities
|
128.9
|
110.3
|
|
Accounts
payable to associated companies
|
18.3
|
27.3
|
|
Taxes
accrued
|
30.2
|
8.5
|
|
Interest
accrued
|
13.3
|
13.7
|
|
Liabilities
and accrued interest related to uncertain tax positions
|
26.6
|
-
|
|
Other
|
37.0
|
38.1
|
|
Liabilities
associated with B.L. England assets held for sale
|
-
|
.9
|
|
Total
Current Liabilities
|
387.0
|
268.5
|
|
DEFERRED
CREDITS
|
|
|
|
Regulatory
liabilities
|
430.9
|
360.2
|
|
Deferred
income taxes , net
|
386.3
|
441.0
|
|
Investment
tax credits
|
11.1
|
14.9
|
|
Other
postretirement benefit obligation
|
38.0
|
27.1
|
|
Other
|
21.2
|
14.0
|
|
Liabilities
associated with B.L. England assets held for sale
|
-
|
78.6
|
|
Total
Deferred Credits
|
887.5
|
935.8
|
|
|
|
|
|
LONG-TERM
LIABILITIES
|
|
|
|
Long-term
debt
|
415.7
|
465.7
|
|
Transition
Bonds issued by ACE Funding
|
433.5
|
464.4
|
|
Total
Long-Term Liabilities
|
849.2
|
930.1
|
|
|
|
|
|
COMMITMENTS
AND CONTINGENCIES (NOTE 11)
|
|
|
|
|
|
|
|
REDEEMABLE
SERIAL PREFERRED STOCK
|
6.2
|
6.2
|
|
|
|
|
|
SHAREHOLDER’S
EQUITY
|
|
|
|
Common
stock, $3.00 par value, authorized 25,000,000
shares,
8,546,017 shares outstanding
|
25.6
|
25.6
|
|
Premium
on stock and other capital contributions
|
309.9
|
306.9
|
|
Retained
earnings
|
141.8
|
132.0
|
|
Total
Shareholder’s Equity
|
477.3
|
464.5
|
|
|
|
|
|
TOTAL LIABILITIES AND
SHAREHOLDER’S EQUITY
|
$2,607.2
|
$2,605.1
|
|
|
|
|
|
The
accompanying Notes are an integral part of these Consolidated Financial
Statements.
|
|
ATLANTIC
CITY ELECTRIC COMPANY
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
|
|
|
2006
|
|
2005
|
|
(Millions
of dollars)
|
|
|
|
|
|
|
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
|
Net
income
|
$ 60.1
|
|
$ 62.7
|
|
$ 63.2
|
|
Adjustments
to reconcile net income to net cash from operating
activities:
|
|
|
|
|
|
|
Extraordinary
item
|
-
|
|
-
|
|
(15.2)
|
|
Gain
on sale of assets
|
(.4)
|
|
-
|
|
-
|
|
Depreciation
and amortization
|
80.2
|
|
111.3
|
|
122.2
|
|
Investment
tax credit adjustments
|
.8
|
|
(1.4)
|
|
(3.2)
|
|
Deferred
income taxes
|
(30.5)
|
|
3.6
|
|
(77.4)
|
|
Other
deferred charges
|
(7.2)
|
|
(9.0)
|
|
1.7
|
|
Other
deferred credits
|
(1.0)
|
|
(.3)
|
|
.7
|
|
Other
postretirement benefit obligations
|
1.2
|
|
2.7
|
|
1.7
|
|
Prepaid
pension expense
|
3.2
|
|
4.8
|
|
(52.0)
|
|
Changes
in:
|
|
|
|
|
|
|
Accounts
receivable
|
(34.6)
|
|
41.6
|
|
(29.6)
|
|
Regulatory
assets and liabilities
|
54.8
|
|
17.9
|
|
122.5
|
|
Fuel,
material and supplies
|
(1.1)
|
|
9.8
|
|
(1.5)
|
|
Prepaid
expenses
|
(1.4)
|
|
1.7
|
|
1.6
|
|
Accounts
payable and accrued liabilities
|
(.4)
|
|
(105.5)
|
|
129.4
|
|
Interest
and taxes accrued
|
24.4
|
|
(119.2)
|
|
55.0
|
|
Proceeds
from sale of emission allowances
|
47.8
|
|
-
|
|
-
|
|
Net
Cash From Operating Activities
|
195.9
|
|
20.7
|
|
319.1
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
Investment
in property, plant and equipment
|
(149.4)
|
|
(108.3)
|
|
(117.2)
|
|
Proceeds
from sale of other assets
|
9.0
|
|
177.0
|
|
-
|
|
Change
in restricted cash
|
(.5)
|
|
2.4
|
|
2.2
|
|
Net
other investing activities
|
10.0
|
|
-
|
|
(.5)
|
|
Net
Cash (Used By) From Investing Activities
|
(130.9)
|
|
71.1
|
|
(115.5)
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
Dividends
paid to Pepco Holdings
|
(50.0)
|
|
(109.0)
|
|
(95.9)
|
|
Dividends
paid on preferred stock
|
(.3)
|
|
(.3)
|
|
(.3)
|
|
Issuances
of long-term debt
|
-
|
|
105.0
|
|
-
|
|
Reacquisitions
of long-term debt
|
(45.9)
|
|
(94.0)
|
|
(68.1)
|
|
Issuances
(repayments) of short-term debt, net
|
27.9
|
|
1.2
|
|
(32.7)
|
|
Net
other financing activities
|
4.8
|
|
2.6
|
|
(2.7)
|
|
Net
Cash Used By Financing Activities
|
(63.5)
|
|
(94.5)
|
|
(199.7)
|
|
Net
Increase (Decrease) In Cash and Cash Equivalents
|
1.5
|
|
(2.7)
|
|
3.9
|
|
Cash
and Cash Equivalents at Beginning of Year
|
5.5
|
|
8.2
|
|
4.3
|
|
|
|
|
|
|
|
|
CASH
AND CASH EQUIVALENTS AT END OF YEAR
|
$ 7.0
|
|
$ 5.5
|
|
$ 8.2
|
|
|
|
|
|
|
|
|
NON-CASH
ACTIVITIES
|
|
|
|
|
|
|
Excess
accumulated depreciation transferred to regulatory
liabilities
|
$ -
|
|
$ -
|
|
$ 131.0
|
|
Capital
contribution in respect of certain intercompany
transactions
|
$ 3.0
|
|
$ 13.5
|
|
$ -
|
|
|
|
|
|
|
|
|
SUPPLEMENTAL
DISCLOSURE OF CASH FLOW INFORMATION
|
|
|
|
|
|
|
Cash
paid for interest (net of capitalized interest of $1.8 million, $.8
million,
and
$.8 million, respectively) and paid for income taxes:
|
|
|
|
|
|
|
Interest
|
$ 61.9
|
|
$ 60.2
|
|
$ 57.5
|
|
Income
taxes
|
$ 37.8
|
|
$129.2
|
|
$ 73.6
|
|
|
|
The
accompanying Notes are an integral part of these Consolidated Financial
Statements.
|
|
ATLANTIC
CITY ELECTRIC COMPANY
CONSOLIDATED
STATEMENTS OF SHAREHOLDER’S EQUITY
|
|
|
|
Premium
on
Stock
|
Capital
Stock
Expense
|
Retained
Earnings
|
|
|
Common
Stock
Shares Par
Value
|
|
(Millions
of dollars, except shares)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,546,017
|
$25.6
|
$294.0
|
$ (.6)
|
$211.6
|
|
|
|
|
|
|
|
|
Net
Income
|
-
|
-
|
-
|
-
|
63.2
|
|
Dividends:
|
|
|
|
|
|
|
Preferred
stock
|
-
|
-
|
-
|
-
|
(.3)
|
|
Common
stock
|
-
|
-
|
-
|
-
|
(95.9)
|
|
|
8,546,017
|
25.6
|
294.0
|
(.6)
|
178.6
|
|
|
|
|
|
|
|
|
Net
Income
|
-
|
-
|
-
|
-
|
62.7
|
|
Dividends:
|
|
|
|
|
|
|
Preferred
stock
|
-
|
-
|
-
|
-
|
(.3)
|
|
Common
stock
|
-
|
-
|
-
|
-
|
(109.0)
|
|
Capital
contribution
|
-
|
-
|
13.5
|
-
|
-
|
|
|
8,546,017
|
25.6
|
307.5
|
(.6)
|
132.0
|
|
|
|
|
|
|
|
|
Net
Income
|
-
|
-
|
-
|
-
|
60.1
|
|
Dividends:
|
|
|
|
|
|
|
Preferred
stock
|
-
|
-
|
-
|
-
|
(.3)
|
|
Common
stock
|
-
|
-
|
-
|
-
|
(50.0)
|
|
Capital
contribution
|
-
|
-
|
3.0
|
-
|
-
|
|
|
|
|
|
|
|
|
|
8,546,017
|
$25.6
|
$310.5
|
$ (.6)
|
$141.8
|
|
|
|
|
|
|
|
|
The
accompanying Notes are an integral part of these Consolidated Financial
Statements.
|
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. Additionally, ACE 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
supplier. Default Electricity Supply is also known as Basic
Generation Service (BGS). ACE is a wholly owned subsidiary of
Conectiv, which is wholly owned by Pepco Holdings, Inc. (Pepco Holdings or
PHI).
In addition to its electricity
transmission and distribution operations, during 2006 ACE owned a 2.47%
undivided interest in the Keystone electric generating facility, a 3.83%
undivided interest in the Conemaugh electric generating facility (with a
combined generating capacity of 108 megawatts), and also owned the B.L. England
electric generating facility (with a generating capacity of 447
megawatts). On September 1, 2006, ACE sold its interests in the
Keystone and Conemaugh generating facilities and on February 8, 2007, ACE
completed the sale of the B.L. England generating facility.
(2) SUMMARY OF SIGNIFICANT
ACCOUNTING POLICIES
Consolidation
Policy
The accompanying consolidated financial
statements include the accounts of ACE and its wholly owned subsidiaries. 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
a 20% to 50% voting interest and cannot exercise control over the operations and
policies of the investee. Individual interests in several jointly
owned electric plants previously held by ACE, and certain transmission and other
facilities currently held are consolidated in proportion to ACE’s percentage
interest in the facility.
In accordance with the provisions of
Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 46R,
entitled “Consolidation of Variable Interest Entities” (FIN 46R), ACE
consolidates those variable interest entities where ACE has been determined to
be primary beneficiary. FIN 46R addresses conditions when an entity
should be consolidated based upon variable interests rather than voting
interests. For additional information, see the FIN 46R discussion
later in this Note.
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 estimates used by ACE
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, unbilled revenue calculations, the
assessment of the probability of recovery of regulatory assets, 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 that are probable and reasonably estimable.
Change in Accounting
Estimates
During 2005, ACE recorded the impact of
a reduction in estimated unbilled revenue, primarily reflecting an increase in
the estimated amount of power line losses (electricity lost in the process of
its transmission and distribution to customers). This change in
accounting estimate reduced net earnings for the year ended December 31,
2005 by approximately $6.4 million.
Revenue
Recognition
ACE recognizes revenue upon delivery of
electricity to its customers, including amounts for electricity delivered but
not yet billed (unbilled revenue). ACE recorded amounts for unbilled
revenue of $38.1 million and $31.8 million as of December 31, 2007 and
December 31, 2006, respectively. 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 power line
losses (estimates of electricity expected to be lost in the process of its
transmission and distribution to customers), all of which are inherently
uncertain and susceptible to change from period to period, the impact of which
could be material. Revenues from other services are recognized when
services are performed or products are delivered.
The taxes related to the delivery of
electricity to its customers are a component of ACE’s tariffs and, as such, are
billed to customers and recorded in “Operating Revenues.” Accruals
for 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 de
minimis.
Regulation of Power Delivery
Operations
Certain aspects of ACE’s utility
businesses are subject to regulation by the New Jersey Board of Public Utilities
(NJBPU). The transmission and wholesale sale 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, the provisions of
Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the
Effects of Certain Types of Regulation.” SFAS No. 71 allows regulated entities,
in appropriate circumstances, to establish regulatory assets and to defer the
income statement impact of certain costs that are expected to be recovered in
future rates. Management’s assessment of the probability of recovery
of regulatory assets requires judgment and interpretation of laws,
regulatory
commission orders, and other factors. Should existing facts or
circumstances change in the future to indicate that a regulatory asset is not
probable of recovery, then the regulatory asset must be charged to
earnings.
|
|
|
2007
|
|
|
2006
|
|
|
|
|
(Millions
of dollars)
|
|
|
Securitized
stranded costs
|
|
$ |
734.6 |
|
|
$ |
773.0 |
|
|
Deferred
recoverable income taxes
|
|
|
21.8 |
|
|
|
18.1 |
|
|
Deferred
debt extinguishment costs
|
|
|
14.1 |
|
|
|
15.3 |
|
|
Deferred
other postretirement benefit costs
|
|
|
12.5 |
|
|
|
15.0 |
|
|
Unrecovered
purchased power contract costs
|
|
|
10.0 |
|
|
|
11.1 |
|
|
Asset
retirement cost
|
|
|
- |
|
|
|
33.0 |
|
|
Other
|
|
|
25.0 |
|
|
|
25.0 |
|
|
Total
Regulatory Assets
|
|
|
818.0 |
|
|
|
890.5 |
|
|
|
|
|
|
|
|
|
|
|
|
Less: B.L.
England regulatory assets held for sale
|
|
|
- |
|
|
|
33.0 |
|
|
Total
Regulatory Assets per Balance Sheet
|
|
$ |
818.0 |
|
|
$ |
857.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
|
|
(Millions
of dollars)
|
|
|
Excess
depreciation reserve
|
|
$ |
90.0 |
|
|
$ |
105.8 |
|
|
Deferred
energy supply costs
|
|
|
240.9 |
|
|
|
164.9 |
|
|
Asset
retirement obligation
|
|
|
- |
|
|
|
63.2 |
|
|
Federal
and New Jersey tax benefits,
related
to securitized stranded costs
|
|
|
33.2 |
|
|
|
41.1 |
|
|
Gain
from sale of Keystone and Conemaugh
|
|
|
30.7 |
|
|
|
48.4 |
|
|
Gain
from sale of B.L. England
|
|
|
36.1 |
|
|
|
- |
|
|
Total
Regulatory Liabilities
|
|
|
430.9 |
|
|
|
423.4 |
|
|
|
|
|
|
|
|
|
|
|
|
Less: B.L. England
regulatory liabilities associated with
B.L.
England regulatory assets held for sale
|
|
|
- |
|
|
|
63.2 |
|
|
Total
Regulatory Liabilities per Balance Sheet
|
|
$ |
430.9 |
|
|
$ |
360.2 |
|
|
|
|
|
|
|
|
|
|
|
A description for each category of
regulatory assets and regulatory liabilities follows:
Securitized Stranded
Costs: Represents stranded costs associated with a non-utility
generator contract termination payment and the discontinuance of the application
of SFAS No. 71 for ACE’s electricity generation business. The
recovery of these stranded costs has been securitized through the issuance by
Atlantic City Electric Transition Funding LLC (ACE Funding) of transition bonds
(Transition Bonds). A customer surcharge is collected by ACE to fund
principal and interest payments on the Transition Bonds. The stranded
costs are amortized over the life of the Transition Bonds, which mature between
2010 and 2023.
Deferred Recoverable Income
Taxes: Represents a receivable from our customers for tax benefits
ACE has previously flowed through before the company was ordered to provide
deferred income taxes. As the temporary differences between the
financial statement and tax basis of assets reverse, the deferred recoverable
balances are reversed. There is no return on these
deferrals.
Deferred Debt Extinguishment
Costs: Represents the costs of debt extinguishment for which
recovery through regulated utility rates is considered probable and will be
amortized to interest expense during the authorized rate recovery
period. A return is received on these deferrals.
Deferred Other Postretirement
Benefit Costs: Represents the non-cash portion of other
postretirement benefit costs deferred by ACE during 1993 through
1997. This cost is being recovered over a 15-year period that began
on January 1, 1998. There is no return on this deferral.
Unrecovered Purchased Power Contract
Costs: Represents deferred costs related to purchase power
contracts at ACE, which are being recovered from July 1994 through May 2014 and
which earn a return.
Asset Retirement
Cost: During the first quarter of 2006, ACE recorded an asset
retirement obligation of $60 million for B.L. England plant demolition and
environmental remediation costs; the amortization was to be amortized over a
two-year period. The cumulative amortization of $33.0 million at
December 31, 2006, was recorded as a regulatory asset -- “Asset Retirement
Cost.” As discussed in Note (11) Commitments and Contingencies, in
the first quarter of 2007, ACE completed the sale of the B.L. England generating
facility, and the asset retirement obligation and asset retirement cost were
reversed.
Other: Represents
miscellaneous regulatory assets that generally are being amortized over 1 to 20
years and generally do not receive a return.
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. The excess is being
amortized over an 8.25 year period, which began in June 2005.
Deferred Energy Supply
Costs: The regulatory liability balances of $240.9 million and
$164.9 million for the years ended December 31, 2007 and 2006, respectively,
primarily represent deferred costs relating to a net over-recovery by ACE
connected with the provision of BGS and other restructuring related costs
incurred by ACE.
Federal and New Jersey Tax Benefits,
Related to Securitized Stranded Costs: Securitized stranded
costs include a portion of stranded costs attributable to the future tax benefit
expected to be realized when the higher tax basis of the generating plants 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 regulated electricity delivery customers through lower rates in
the future, ACE established a regulatory liability. The regulatory
liability related to federal excess deferred taxes will remain on ACE’s
Consolidated Balance Sheets until such time as the Internal Revenue
Service
issues its final regulations with respect to normalization of these federal
excess deferred taxes.
Gain from Sale of Keystone and
Conemaugh: In the third quarter of 2006, ACE completed the
sale of its interests in the Keystone and Conemaugh generating facilities for
$175.4 million (after giving effect to post-closing adjustments). The
total gain recognized on this sale, net of adjustments, came to $131.4
million. Approximately $81.3 million of the net gain from the
sale offset the remaining regulatory asset balance, which ACE has been
recovering in rates, and $49.8 million of the net gain is being returned to
ratepayers over a 33-month period as a credit on their bills, which began during
the October 2006 billing period. The balance to be repaid to
customers is $30.7 million as of December 31, 2007.
Gain from Sale of B.L.
England: In the first quarter of 2007, ACE completed the sale
of the B.L. England generating facility. Net proceeds from the sale
of the plant and monetization of the emission allowance credits will be credited
to ACE’s ratepayers in accordance with the requirements of the New Jersey
Electric Discount and Energy Competition Act (EDECA) and NJBPU
orders.
Cash and Cash
Equivalents
Cash and cash equivalents include cash
on hand, money market funds, and commercial paper 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
Restricted cash represents cash either
held as collateral or pledged as collateral, and is restricted from use for
general corporate purposes.
Capitalized Interest and
Allowance for Funds Used During Construction
In accordance with the provisions of
SFAS No. 71, utilities can capitalize as Allowance for Funds Used During
Construction (AFUDC) the capital costs of financing the construction of plant
and equipment. The debt portion of AFUDC is recorded as a reduction
of “interest expense” and the equity portion of AFUDC is credited to “other
income” in the accompanying Consolidated Statements of Earnings.
ACE recorded AFUDC for borrowed funds
of $1.8 million, $.8 million and $.8 million for the years ended
December 31, 2007, 2006 and 2005, respectively.
ACE recorded amounts for the equity
component of AFUDC of $1.1 million, $.7 million and $1.6 million for the years
ended December 31, 2007, 2006 and 2005, respectively.
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 issues. Costs associated with the redemption of debt are also
deferred and amortized over the lives of the new issues.
Emission
Allowances
Emission allowances for sulfur dioxide
(SO2)
and nitrous oxide (NOx) are
allocated to generation owners by the U.S. Environmental Protection Agency (EPA)
based on federal programs designed to regulate the emissions from power
plants. EPA allotments have no cost basis to the generation
owners. Depending on the run-time of a generator in a given year, and
other pollution controls it may have, the unit may need additional allowances
above its allocation, or it may have excess allowances that it does not
need. Allowances are traded among companies in an over-the-counter
market, which allows companies to purchase additional allowances to avoid
incurring penalties for noncompliance with applicable emissions standards or to
sell excess allowances.
ACE accounts for emission allowances as
inventory in the balance sheet line item “Fuel, materials and supplies - at
average cost.” Allowances from EPA allocation are added to current
inventory each year at a zero basis. Additional purchased allowances
are recorded at cost. Allowances sold or consumed at the power plants
are expensed at a weighted-average cost. This cost tends to be
relatively low due to the inclusion of the zero-basis allowances. At
December 31, 2007 and 2006, the book value of emission allowances was $.1
million and $.4 million, respectively. ACE has established a committee to ensure
its plants are in compliance with emissions regulations and that its power
plants have the required number of allowances on hand.
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.
In 2006, the FASB issued FIN 48,
“Accounting for Uncertainty in Income Taxes” (FIN 48). FIN 48
clarifies the criteria for recognition of tax benefits in accordance with SFAS
No. 109, “Accounting for Income Taxes,” and prescribes a financial statement
recognition threshold and measurement attribute for a tax position taken or
expected to be taken in a tax return. Specifically, it clarifies that
an entity’s tax benefits must be “more likely than not” of being sustained prior
to recording the related tax benefit in the financial statements. If
the position drops below the “more likely than not” standard, the benefit can no
longer be recognized. FIN 48 also provides guidance on derecognition,
classification, interest and penalties, accounting in interim periods,
disclosure, and transition.
On May 2, 2007, the FASB issued FASB
Staff Position (FSP) FIN 48-1, “Definition of Settlement in FASB Interpretation
No. 48” (FIN 48-1), which provides guidance on how an enterprise should
determine whether a tax position is effectively settled for the purpose of
recognizing previously unrecognized tax benefits. ACE applied the
guidance of FIN 48-1 with its adoption of FIN 48 on January 1,
2007.
The consolidated financial statements
include current and deferred income taxes. Current income taxes represent the
amounts of tax expected to be reported on ACE’s state income tax returns and the
amount of federal income tax allocated from PHI.
Deferred income tax assets and
liabilities represent the tax effects of temporary differences between the
financial statement and tax basis of existing assets and liabilities, and 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. For additional information, see the discussion under
“Regulation of Power Delivery Operations” above.
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 under/over
payments of income taxes, interest on unrecognized tax benefits, and tax-related
penalties in income tax expense.
Investment tax credits from utility
plant purchased in prior years are reported on the Consolidated Balance Sheets
as “Investment tax credits.” These investment tax credits are being
amortized to income over the useful lives of the related utility
plant.
Pension and Other
Postretirement Benefit Plans
Pepco Holdings sponsors a
non-contributory retirement plan that covers substantially all employees of ACE
(the PHI Retirement Plan) 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 SFAS No. 87, “Employers’ Accounting for Pensions,”
as amended by SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension
and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106
and 132(R)” (SFAS No. 158), and its other postretirement benefits in accordance
with SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than
Pensions,” as amended by SFAS No. 158. Pepco Holdings’ financial
statement disclosures were prepared in accordance with SFAS No. 132, “Employers’
Disclosures about Pensions and Other Postretirement Benefits,” as amended by
SFAS No. 158.
ACE participates in benefit plans
sponsored by Pepco Holdings and as such, the provisions of SFAS No. 158 do not
have an impact on its financial condition and cash flows.
Long-Lived Asset Impairment
Evaluation
ACE evaluates certain long-lived assets
to be held and used (for example, generating property and equipment and real
estate) to determine if they are impaired whenever events or changes in
circumstances indicate that their carrying amount 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 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 sum of its
expected future undiscounted cash flows is less than its carrying
amount.
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 amount exceeds their fair value
including costs to sell.
Property, Plant and
Equipment
Property, plant and equipment are
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 under the provisions of SFAS No. 144. 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 the 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. Property, plant and equipment other
than electric facilities is generally depreciated on a straight-line basis over
the useful lives of the assets. The system-wide composite
depreciation rates for 2007, 2006 and 2005 for ACE’s transmission and
distribution system property were 2.9%, 2.9% and 3.1%, respectively, and for its
generation system property were zero, .3%, and 2.4%, respectively.
In accordance with FSP American
Institute of Certified Public Accountants Industry Audit Guide, Audits of
Airlines--”Accounting for Planned Major Maintenance Activities” (FSP AUG AIR-1),
the costs associated with planned major maintenance activities related to
generation facilities are accounted for on an as incurred basis.
Accounts Receivable and
Allowance for Uncollectible Accounts
ACE’s accounts receivable balances
primarily consist 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 uses
the allowance method to account for uncollectible accounts
receivable.
FIN 46R, “Consolidation of
Variable Interest Entities”
ACE has power purchase agreements
(PPAs) with a number of entities, including three contracts between ACE and
unaffiliated non-utility generators (NUGs). Due to a variable element
in the pricing structure of the NUGs, ACE potentially assumes the variability in
the operations of the plants related to these PPAs and, therefore, has a
variable interest in the entities. In accordance with the provisions
of FIN 46R, ACE continued, during 2007, to conduct exhaustive efforts to obtain
information from these entities, but was unable to obtain sufficient information
to conduct the analysis required under FIN 46R to determine whether these three
entities were variable interest entities or if ACE was the primary
beneficiary. As a result, ACE has applied the scope exemption from
the application of FIN 46R for enterprises that have
conducted
exhaustive efforts to obtain the necessary information, but have not been able
to obtain such information.
Net power purchase activities with the
counterparties to the NUGs for the years ended December 31, 2007, 2006 and 2005,
were approximately $327 million, $324 million and $327 million, respectively, of
which $292 million, $288 million and $289 million, respectively, related to
power purchases under the NUGs. ACE does not have exposure to loss
under the PPA agreements since cost recovery will be achieved from its customers
through regulated rates.
Prepaid Expenses and
Other
The prepaid expenses and other balance
primarily consists of prepayments and the current portion of deferred income tax
assets.
Other Non-Current
Assets
The other assets balance principally
consists of deferred compensation trust assets and unamortized debt
expense.
Other Current
Liabilities
The other current liability balance
principally consists of customer deposits, accrued vacation liability and other
miscellaneous liabilities.
Other Deferred
Credits
The other deferred credits balance
principally consists of miscellaneous deferred liabilities.
Dividend
Restrictions
In addition to its future financial
performance, the ability of ACE to pay dividends is subject to limits imposed
by: (i) state corporate and regulatory laws, which impose limitations on the
funds that can be used to pay dividends and, in the case of regulatory laws, may
require the prior approval of ACE’s utility regulatory commission before
dividends can be paid; (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 dividends. ACE had approximately $87.9
million and $97.9 million of restricted retained earnings at December 31,
2007 and 2006, respectively.
Discontinued
Operations
Discontinued operations are identified
and accounted for in accordance with the provisions of SFAS No. 144, “Accounting
for the Impairment or Disposal of Long-Lived Assets.” For information
regarding ACE’s discontinued operations refer to Note (13), “Discontinued
Operations,” herein.
Newly
Adopted Accounting Standards
EITF Issue No. 06-3, “Disclosure
Requirements for Taxes Assessed by a Governmental Authority on Revenue-producing
Transactions”
On
June 28, 2006, the FASB ratified Emerging Issues Task Force (EITF) Issue No.
06-3, “Disclosure Requirements for Taxes Assessed by a Governmental Authority on
Revenue-producing Transactions” (EITF 06-3). EITF 06-3 provides
guidance on an entity’s disclosure of its accounting policy regarding the gross
or net presentation of certain taxes and provides that if taxes included in
gross revenues are significant, a company should disclose the amount of such
taxes for each period for which an income statement is presented (i.e., both
interim and annual periods). Taxes within the scope of EITF 06-3 are
those that are imposed on and concurrent with a specific revenue-producing
transaction. Taxes assessed on an entity’s activities over a period of time are
not within the scope of EITF 06-3. ACE implemented EITF 06-3 during
the first quarter of 2007. Taxes included in ACE’s gross revenues
were $22.9 million, $22.3 million and $22.6 million for the twelve months ended
December 31, 2007, 2006 and 2005, respectively.
FSP AUG AIR-1, “Accounting for Planned
Major Maintenance Activities”
On September 8, 2006, the FASB issued
FSP AUG AIR-1 which prohibits the use of the accrue-in-advance method of
accounting for planned major maintenance activities in annual and interim
financial reporting periods for all industries. FSP AUG AIR-1 is
effective the first fiscal year beginning after December 15, 2006 (year
ended December 31, 2007 for ACE). Implementation of FSP AUG
AIR-1 did not have a material impact on ACE’s overall financial condition,
results of operations, or cash flows.
Recently
Issued Accounting Standards, Not Yet Adopted
SFAS No. 157, “Fair Value
Measurements”
In September 2006, the FASB issued SFAS
No. 157, "Fair Value Measurements" (SFAS No. 157) which defines fair value,
establishes a framework for measuring fair value in GAAP, and expands
disclosures about fair value measurements. SFAS No. 157 applies under
other accounting pronouncements that require or permit fair value measurements
and does not require any new fair value measurements. However, it is
possible that the application of this Statement will change current practice
with respect to the definition of fair value, the methods used to measure fair
value, and the disclosures about fair value measurements.
The provisions of SFAS No. 157, as
issued, are effective for financial statements issued for fiscal years beginning
after November 15, 2007, and interim periods within those fiscal years (January
1, 2008 for ACE). On February 6, 2008, the FASB decided to issue
final Staff Positions that will (i) defer the effective date of SFAS No. 157 for
all non-financial assets and non-financial liabilities, except those that are
recognized or disclosed at fair value in the financial statements on a recurring
basis (that is, at least annually) and (ii) remove certain leasing transactions
from the scope of SFAS No. 157. The final Staff Positions will defer
the effective date of SFAS No. 157 to fiscal years beginning after November 15,
2008, and interim periods within those fiscal years for items within the scope
of the final Staff Positions. ACE has evaluated the impact of SFAS
No. 157 and does not anticipate its adoption will have a material impact on its
overall financial condition, results of operations, cash flows, or footnote
disclosure requirements.
SFAS No. 159, “The Fair Value Option for Financial
Assets and Financial Liabilities - Including an amendment of FASB Statement No.
115”
On February 15, 2007, the FASB issued
SFAS No. 159, “The Fair Value Option for Financial Assets and Financial
Liabilities - Including an amendment of FASB Statement No. 115” (SFAS No. 159)
which permits entities to elect to measure eligible financial instruments at
fair value. The objective of SFAS No. 159 is to improve financial
reporting by providing entities with the opportunity to mitigate volatility in
reported earnings caused by measuring related assets and liabilities differently
without having to apply complex hedge accounting provisions. SFAS No.
159 applies under other accounting pronouncements that require or permit fair
value measurements and does not require any new fair value
measurements. However, it is possible that the application of SFAS
No. 159 will change current practice with respect to the definition of fair
value, the methods used to measure fair value, and the disclosures about fair
value measurements.
SFAS No. 159 establishes presentation
and disclosure requirements designed to facilitate comparisons between companies
that choose different measurement attributes for similar types of assets and
liabilities. SFAS No. 159 requires companies to provide additional
information that will help investors and other users of financial statements to
more easily understand the effect of the company’s choice to use fair value on
its earnings. It also requires entities to display the fair value of
those assets and liabilities for which the company has chosen to use fair value
on the face of the balance sheet. SFAS No. 159 does not eliminate
disclosure requirements included in other accounting standards.
SFAS No. 159 applies to the beginning
of a reporting entity’s first fiscal year that begins after November 15, 2007
(January 1, 2008 for ACE), with early adoption permitted for an entity that has
also elected to apply the provisions of SFAS No. 157, Fair Value
Measurements. An entity is
prohibited from retrospectively applying SFAS No. 159, unless it chooses early
adoption. SFAS No. 159 also applies to eligible items existing at
November 15, 2007 (or early adoption date). ACE has evaluated the
impact of SFAS No. 159 and does not anticipate its adoption will have a material
impact on its overall financial condition, results of operations, cash flows, or
footnote disclosure requirements.
SFAS No. 141(R), “Business Combinations
– a replacement of FASB Statement No. 141”
On December 4, 2007, the FASB issued
SFAS No. 141(R), “Business Combinations – a replacement of FASB Statement No.
141” (SFAS No. 141(R)) which replaces FASB Statement No. 141, “Business
Combinations.” This Statement retains the fundamental requirements in
Statement 141 that the acquisition method of accounting (which Statement
141 called the purchase method) be used for all business combinations and for an
acquirer to be identified for each business combination.
SFAS No. 141(R) applies to all
transactions or other events in which an entity (the acquirer) obtains control
of one or more businesses (the acquiree). It does not apply to (i)
the formation of a joint venture, (ii) the acquisition of an asset or a group of
assets that does not constitute a business, (iii) a combination between entities
or businesses under common control and (iv) a combination between not-for-profit
organizations or the acquisition of a for-profit business by a not-for-profit
organization.
SFAS No. 141(R) applies prospectively
to business combinations for which the acquisition date is on or after the
beginning of the first annual reporting period beginning on or after December
15, 2008 (January 1, 2009 for ACE). An entity may not apply it
before that date.
SFAS No. 160, “Noncontrolling Interests
in Consolidated Financial Statements – an amendment of ARB No. 51”
On December 4, 2007, the FASB issued
SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements –
an amendment of ARB No. 51” (SFAS No. 160) which amends ARB 51 to establish
accounting and reporting standards for the noncontrolling interest in a
subsidiary and for the deconsolidation of a subsidiary. It clarifies
that a noncontrolling interest in a subsidiary is an ownership interest in the
consolidated entity that should be reported as equity in the consolidated
financial statements.
A noncontrolling interest, sometimes
called a minority interest, is the portion of equity in a subsidiary not
attributable, directly or indirectly, to a parent. The objective of SFAS No. 160
is to improve the relevance, comparability, and transparency of the financial
information that a reporting entity provides in its consolidated financial
statements by establishing accounting and reporting standards that require (i)
the ownership interests in subsidiaries held by parties other than the parent be
clearly identified, labeled, and presented in the consolidated statement of
financial position within equity, but separate from the parent’s equity, (ii)
the amount of consolidated net income attributable to the parent and to the
noncontrolling interest be clearly identified and presented on the face of the
consolidated statement of income, (iii) changes in a parent’s ownership interest
while the parent retains its controlling financial interest in its subsidiary be
accounted for consistently. A parent’s ownership interest in a
subsidiary changes if the parent purchases additional ownership interests in its
subsidiary or if the parent sells some of its ownership interests in its
subsidiary. It also changes if the subsidiary reacquires some of its ownership
interests or the subsidiary issues additional ownership interests. All of those
transactions are economically similar, and this Statement requires that they be
accounted for similarly, as equity transactions, (iv) when a subsidiary is
deconsolidated, any retained noncontrolling equity investment in the former
subsidiary be initially measured at fair value. The gain or loss on
the deconsolidation of the subsidiary is measured using the fair value of any
noncontrolling equity investment rather than the carrying amount of that
retained investment and (v) entities provide sufficient disclosures that clearly
identify and distinguish between the interests of the parent and the interests
of the noncontrolling owners.
SFAS No. 160 applies to all entities
that prepare consolidated financial statements, except not-for-profit
organizations, but will affect only those entities that have an outstanding
noncontrolling interest in one or more subsidiaries or that deconsolidate a
subsidiary.
SFAS No. 160 is effective for fiscal
years, and interim periods within those fiscal years, beginning on or after
December 15, 2008 (January 1, 2009, for ACE). Earlier adoption is
prohibited. SFAS No. 160 shall be applied prospectively as of the
beginning of the fiscal year in which this Statement is initially applied,
except for the presentation and disclosure requirements. The
presentation and disclosure requirements shall be applied retrospectively for
all periods presented. ACE is currently evaluating the impact SFAS
No. 160 may have on its overall financial condition, results of operations, cash
flows or footnote disclosure requirements.
(3) SEGMENT
INFORMATION
In accordance with SFAS No. 131,
“Disclosures about Segments of an Enterprise and Related Information,” ACE has
one segment, its regulated utility business.
(4) LEASING
ACTIVITIES
ACE leases certain types of property
and equipment for use in its operations. Rental expense for operating
leases was $9.9 million, $9.6 million and $11.0 million for the years ended
December 31, 2007, 2006 and 2005, respectively.
Total future minimum operating lease
payments for ACE as of December 31, 2007 include $3.0 million in 2008, $2.7
million in 2009, $2.2 million in 2010, $1.7 million in 2011, $1.1 million in
2012 and $6.2 million after 2012.
(5) PROPERTY, PLANT AND
EQUIPMENT
Property, plant and equipment is
comprised of the following:
|
|
|
Original
Cost
|
|
|
Accumulated
Depreciation
|
|
|
Net
Book Value
|
|
|
|
|
|
(Millions
of dollars)
|
|
|
|
Generation
|
|
$ |
10.1 |
|
|
$ |
8.8 |
|
|
$ |
1.3 |
|
|
Distribution
|
|
|
1,242.8 |
|
|
|
360.5 |
|
|
|
882.3 |
|
|
Transmission
|
|
|
543.8 |
|
|
|
180.0 |
|
|
|
363.8 |
|
|
Construction
work in progress
|
|
|
121.5 |
|
|
|
- |
|
|
|
121.5 |
|
|
Non-operating
and other property
|
|
|
159.8 |
|
|
|
84.2 |
|
|
|
75.6 |
|
|
Total
|
|
$ |
2,078.0 |
|
|
$ |
633.5 |
|
|
$ |
1,444.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Generation
|
|
$ |
80.5 |
|
|
$ |
39.5 |
|
|
$ |
41.0 |
|
|
Distribution
|
|
|
1,188.1 |
|
|
|
340.5 |
|
|
|
847.6 |
|
|
Transmission
|
|
|
516.7 |
|
|
|
170.3 |
|
|
|
346.4 |
|
|
Construction
work in progress
|
|
|
71.4 |
|
|
|
- |
|
|
|
71.4 |
|
|
Non-operating
and other property
|
|
|
156.6 |
|
|
|
79.5 |
|
|
|
77.1 |
|
|
Total
|
|
|
2,013.3 |
|
|
|
629.8 |
|
|
|
1,383.5 |
|
|
Less: B.L.
England assets held for sale
|
|
|
70.4 |
|
|
|
30.7 |
|
|
|
39.7 |
|
|
Total
|
|
$ |
1,942.9 |
|
|
$ |
599.1 |
|
|
$ |
1,343.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The balances of all property, plant and
equipment, which are primarily electric transmission and distribution property,
are stated at original cost. Utility plant is generally subject to a
first mortgage lien.
Jointly Owned
Plant
ACE’s Consolidated Balance Sheet
includes its proportionate share of assets and liabilities related to jointly
owned plant. ACE has ownership interests in transmission facilities, and other
facilities in which various parties have ownership interests. ACE’s
proportionate share of operating and maintenance expenses of the jointly owned
plant is included in the
corresponding
expenses in ACE’s Consolidated Statements of Earnings. ACE is responsible for
providing its share of financing for the jointly owned
facilities. Information with respect to ACE’s share of jointly owned
plant as of December 31, 2007 is shown below.
|
Jointly Owned Plant
|
Ownership
Share
|
Plant
in
Service
|
Accumulated
Depreciation
|
|
|
|
|
(Millions
of dollars)
|
|
|
Transmission
Facilities
|
Various
|
$24.9
|
$15.1
|
|
|
Other
Facilities
|
Various
|
1.1
|
.4
|
|
|
Total
|
|
$26.0
|
$15.5
|
|
|
|
|
|
|
|
Asset
Sales
As discussed in Note (2), Summary of
Significant Accounting Policies, in the third quarter of 2006, ACE completed the
sale of its interests in the Keystone and Conemaugh generating facilities for
approximately $175.4 million (after giving effect to post-closing adjustments)
and in the first quarter of 2007, ACE completed the sale of the B.L. England
generating facility for a price of $9.0 million.
(6) PENSIONS AND OTHER
POSTRETIREMENT BENEFITS
ACE accounts for its participation in
the Pepco Holdings benefit plans as participation in a multi-employer
plan. For 2007, 2006, and 2005, ACE’s allocated share of the pension
and other postretirement net periodic benefit cost incurred by Pepco Holdings
was approximately $11.0 million, $14.3 million, and $16.9 million,
respectively. In 2007 and 2006, ACE made no contributions to the PHI Retirement
Plan, and $6.8 million and $6.6 million, respectively to other postretirement
benefit plans. At December 31, 2007 and 2006, ACE’s prepaid pension
expense of $8.5 million and $11.7 million, and other postretirement
benefit obligation of $38.0 million and $27.1 million, effectively
represent assets and benefit obligations resulting from ACE’s participation in
the Pepco Holdings benefit plan.
(7) DEBT
LONG-TERM
DEBT
|
Type of Debt
|
Interest Rates
|
Maturity
|
2007
|
2006
|
|
|
|
|
|
|
(Millions
of dollars)
|
|
|
First
Mortgage Bonds:
|
|
|
|
|
|
|
|
|
6.71%-7.15%
|
2007-2008
|
$ 50.0
|
$ 51.0
|
|
|
|
|
7.25%-7.63%
|
2010-2014
|
8.0
|
8.0
|
|
|
|
|
6.63%
|
2013
|
68.6
|
68.6
|
|
|
|
|
7.68%
|
2015-2016
|
17.0
|
17.0
|
|
|
|
|
6.80% (a)
|
2021
|
38.9
|
38.9
|
|
|
|
|
5.60% (a)
|
2025
|
4.0
|
4.0
|
|
|
|
|
Variable (a)(b)
|
2029
|
54.7
|
54.7
|
|
|
|
|
5.80% (a)(b)
|
2034
|
120.0
|
120.0
|
|
|
|
|
5.80% (a)(b)
|
2036
|
105.0
|
105.0
|
|
|
|
|
|
|
466.2
|
467.2
|
|
|
|
|
|
|
|
|
|
|
|
Medium-Term
Notes (unsecured)
|
7.52%
|
2007
|
-
|
15.0
|
|
|
|
|
|
|
|
|
|
|
|
Total
long-term debt
|
|
|
466.2
|
482.2
|
|
|
|
Net
unamortized discount
|
|
|
(.5)
|
(.5)
|
|
|
|
Current
maturities of long-term debt
|
|
|
(50.0)
|
(16.0)
|
|
|
|
Total
net long-term debt
|
|
|
$415.7
|
$465.7
|
|
|
|
|
|
|
|
|
|
|
|
Transition
Bonds
ACE
Funding:
|
|
|
|
|
|
|
|
|
2.89%
|
2010
|
$ 13.2
|
$ 34.5
|
|
|
|
|
2.89%
|
2011
|
14.4
|
23.0
|
|
|
|
|
4.21%
|
2013
|
66.0
|
66.0
|
|
|
|
|
4.46%
|
2016
|
52.0
|
52.0
|
|
|
|
|
4.91%
|
2017
|
118.0
|
118.0
|
|
|
|
|
5.05%
|
2020
|
54.0
|
54.0
|
|
|
|
|
5.55%
|
2023
|
147.0
|
147.0
|
|
|
|
|
|
|
464.6
|
494.5
|
|
|
|
|
|
|
|
|
|
|
|
Net
unamortized discount
|
|
|
(.1)
|
(.2)
|
|
|
|
Current
maturities of long-term debt
|
|
|
(31.0)
|
(29.9)
|
|
|
|
Total
net long-term Transition Bonds
issued
by ACE Funding
|
|
|
$433.5
|
$464.4
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
Represents
a series of First Mortgage Bonds issued by ACE as collateral for an
outstanding series of senior notes 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 tax-exempt bonds are identical to the
terms of the collateral First Mortgage Bonds by which it is
secured. Payments of principal and interest on a series of
senior notes or 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 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 First Mortgage Bonds issued by ACE as collateral for an
outstanding series of senior notes as described in footnote (a) above 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.
|
The outstanding First Mortgage Bonds
issued by ACE are secured by a lien on substantially all of ACE’s property,
plant and equipment.
ACE Funding was established in 2001
solely for the purpose of securitizing authorized portions of ACE’s recoverable
stranded costs through the issuance and sale of Transition Bonds. The
proceeds of the sale of each series of Transition Bonds have been transferred to
ACE in exchange for the transfer by ACE to ACE Funding of the right to collect a
non-bypassable transition bond charge from ACE customers pursuant to bondable
stranded costs rate orders issued by the NJBPU in an amount sufficient to fund
the principal and interest payments on the Transition Bonds and related taxes,
expenses and fees (Bondable Transition Property). The assets of ACE
Funding, including the Bondable Transition Property, and the Transition Bond
charges collected from ACE’s customers are not available to creditors of ACE.
The Transition Bonds are obligations of ACE Funding and are non-recourse to
ACE.
The aggregate principal amount of
long-term debt including Transition Bonds outstanding at December 31, 2007,
that will mature in each of 2008 through 2012 and thereafter is as follows: $81
million in 2008, $32.2 million in 2009, $34.7 million in 2010, $35.4 million in
2011, $37.3 million in 2012, and $710.2 million thereafter.
ACE’s long-term debt is subject to
certain covenants. ACE is in compliance with all
requirements.
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, 2007 and 2006 is as
follows.
|
|
2007
|
2006
|
|
|
|
(Millions
of dollars)
|
|
|
Commercial
paper
|
$29.1
|
$ 1.2
|
|
|
Variable
rate demand bonds
|
22.6
|
22.6
|
|
|
Total
|
$51.7
|
$23.8
|
|
|
|
|
|
|
Commercial
Paper
ACE maintains an ongoing commercial
paper program of up to $250 million. The commercial paper notes can be issued
with maturities up to 270 days from the date of issue. The commercial paper
program is backed by a $500 million credit facility, described below under the
heading “Credit Facility,” shared with Potomac Electric Power Company (Pepco)
and Delmarva Power & Light Company (DPL).
ACE had $29.1 million of commercial
paper outstanding at December 31, 2007 and $1.2 million of commercial paper
outstanding at December 31, 2006. The weighted average interest rates
for commercial paper issued during 2007 and 2006 were 5.45% and 4.79%,
respectively.
The
weighted average maturity for commercial paper issued during 2007 and 2006 was
three days and four days.
Variable Rate Demand
Bonds
Variable Rate Demand Bonds (“VRDB”) 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 the bonds submitted for purchase will continue to be
remarketed successfully due to the credit worthiness of the company and because
the remarketing resets the interest rate to the then-current market
rate. The company also may utilize one of the fixed rate/fixed term
conversion options of the bonds 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 VRDB outstanding in 2007 and 2006 mature as
follows: 2014 ($18.2 million) and 2017 ($4.4 million). The weighted
average interest rate for VRDB was 3.59% and 3.39% during 2007 and 2006,
respectively.
Credit
Facility
PHI, Pepco, DPL and ACE maintain a
credit facility to provide for their respective short-term liquidity
needs.
The aggregate borrowing limit under the
facility is $1.5 billion, all or any portion of which may be used to obtain
loans or to issue letters of credit. PHI’s credit limit under the facility is
$875 million. The credit limit of each of Pepco, DPL and ACE is the
lesser of $500 million and the maximum amount of debt the company is permitted
to have outstanding by its regulatory authorities, except that the aggregate
amount of credit used by Pepco, DPL and ACE at any given time collectively may
not exceed $625 million. The interest rate payable by each company on
utilized funds is based on the prevailing prime rate or Eurodollar rate, plus a
margin that varies according to the credit rating of the
borrower. 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 $150 million. Any swingline loan must be repaid
by the borrower within seven days of receipt thereof. All
indebtedness incurred under the facility is unsecured.
The facility commitment expiration date
is May 5, 2012, with each company having the right to elect to have 100% of the
principal balance of the loans outstanding on the expiration date continued as
non-revolving term loans for a period of one year from such expiration
date.
The facility is intended to serve
primarily as a source of liquidity to support the commercial paper programs of
the respective companies. The companies also are permitted to use the
facility to borrow funds for general corporate purposes and issue letters of
credit. In order for a borrower to use the facility, certain
representations and warranties made by the borrower at the time the credit
agreement was entered into also must be true at the time the facility is
utilized, and the borrower must be in compliance with specified covenants,
including the financial covenant described below. However, a material
adverse change in the borrower’s business, property, and results of operations
or financial condition subsequent to the entry into the credit agreement is not
a condition to the availability of credit under the facility. Among
the covenants to which each of the companies is subject are (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 certain trust preferred securities and deferrable interest subordinated
debt from the definition of total indebtedness (not to exceed 15% of total
capitalization), (ii) a restriction on sales or other dispositions of assets,
other than sales and dispositions permitted by the credit agreement, and (iii) a
restriction on the incurrence of liens on the assets of a borrower or any of its
significant subsidiaries other than liens permitted by the credit
agreement. The agreement does not include any rating
triggers.
(8) 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 as
part of Pepco’s acquisition of Conectiv on August 1, 2002. 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
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
|
|
(Millions
of dollars)
|
|
|
Operations
|
|
|
|
|
|
|
|
|
|
|
Current
Tax Expense
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$ |
56.7 |
|
|
$ |
20.9 |
|
|
$ |
104.7 |
|
|
State
and local
|
|
|
14.7 |
|
|
|
11.7 |
|
|
|
22.7 |
|
|
Total
Current Tax Expense
|
|
|
71.4 |
|
|
|
32.6 |
|
|
|
127.4 |
|
|
Deferred
Tax Expense (Benefit)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
(27.0 |
) |
|
|
3.0 |
|
|
|
(73.1 |
) |
|
State
|
|
|
(3.6 |
) |
|
|
(1.2 |
) |
|
|
(12.1 |
) |
|
Investment
tax credits
|
|
|
.1 |
|
|
|
(1.4 |
) |
|
|
(1.0 |
) |
|
Total
Deferred Tax Expense (Benefit)
|
|
|
(30.5 |
) |
|
|
.4 |
|
|
|
(86.2 |
) |
|
Total
Income Tax Expense from Operations
|
|
|
40.9 |
|
|
|
33.0 |
|
|
|
41.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discontinued
Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred
Tax Expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
.1 |
|
|
|
1.4 |
|
|
|
1.6 |
|
|
State
|
|
|
- |
|
|
|
.4 |
|
|
|
.5 |
|
|
Total
Current Tax on Discontinued Operations
|
|
|
.1 |
|
|
|
1.8 |
|
|
|
2.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Extraordinary
Item
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred
Tax Expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
- |
|
|
|
- |
|
|
|
4.8 |
|
|
State
and local
|
|
|
- |
|
|
|
- |
|
|
|
1.4 |
|
|
Total
Deferred Tax on Extraordinary Item
|
|
|
- |
|
|
|
- |
|
|
|
6.2 |
|
|
Total
Consolidated Income Tax Expense
|
|
$ |
41.0 |
|
|
$ |
34.8 |
|
|
$ |
49.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of
Consolidated Income Tax Expense
|
|
|
|
|
|
|
|
|
|
2006
|
|
2005
|
|
|
|
|
(Millions
of dollars)
|
|
|
|
|
Amount
|
Rate
|
|
Amount
|
Rate
|
|
Amount
|
Rate
|
|
|
|
|
|
|
|
Income
Before Income Taxes, Discontinued
Operations
and Extraordinary Item
|
$
|
100.9
|
|
$
|
93.1
|
|
$
|
92.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
tax at federal statutory rate
|
$
|
35.3
|
35%
|
$
|
32.6
|
35%
|
$
|
32.3
|
35%
|
|
|
Increases
(decreases) resulting from
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation
|
|
.4
|
-
|
|
.4
|
-
|
|
.5
|
1
|
|
|
State
income taxes, net of
federal
effect
|
|
6.5
|
7
|
|
6.8
|
7
|
|
6.8
|
7
|
|
|
Tax
credits
|
|
.1
|
-
|
|
(1.4)
|
(1)
|
|
(1.0)
|
(1)
|
|
|
Change
in estimates related to
prior
year tax liabilities
|
|
1.0
|
1
|
|
(3.5)
|
(4)
|
|
2.9
|
3
|
|
|
Other,
net
|
|
(2.4)
|
(2)
|
|
(1.9)
|
(2)
|
|
(.3)
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Consolidated Income Tax Expense
from
Operations
|
$
|
40.9
|
41%
|
$
|
33.0
|
35%
|
$
|
41.2
|
45%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FIN 48, “Accounting for
Uncertainty in Income Taxes”
As disclosed in Note 2, “Summary of
Significant Accounting Policies”, ACE adopted FIN 48 effective January 1,
2007. Upon adoption, ACE recorded an immaterial adjustment to
retained earnings representing the cumulative effect of the change in accounting
principle. Also upon adoption, ACE had $28.4 million
of unrecognized tax benefits and $3.4 million of related accrued
interest.
Reconciliation of Beginning and Ending
Balances of Unrecognized Tax Benefits
|
|
$
|
28.4
|
|
Tax
positions related to current year:
|
|
|
|
Additions
|
|
34.2
|
|
Tax
positions related to prior years:
|
|
|
|
Additions
|
|
93.7
|
|
Reductions
|
|
(4.5)
|
|
Settlements
|
|
.1
|
|
|
$
|
151.9
|
|
|
|
|
As of December 31, 2007, ACE had $2.5
million of accrued interest related to unrecognized tax benefits.
Unrecognized Benefits That If
Recognized Would Affect the Effective Tax Rate
Unrecognized tax benefits represent
those tax benefits 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, in accordance with FIN 48, 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, 2007, included $3.6 million that, if recognized, would
lower the effective tax rate.
ACE recognizes interest and penalties
relating to its unrecognized tax benefits as an element of tax
expense. For the year ended December 31, 2007, ACE recognized $.9
million of interest income and penalties, net, as a component of tax
expense.
Possible Changes to Unrecognized
Benefits
Total unrecognized tax benefits that
may change over the next twelve months include the matter of Mixed Service
Costs. See discussion in Note 11, “Commitments and Contingencies --
IRS Mixed Service Cost Issue.”
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 1999 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 PHI files state income tax returns (New Jersey and
Pennsylvania), are the same as noted above.
Components of Consolidated
Deferred Income Tax Liabilities (Assets)
|
|
|
As of December 31,
|
|
|
|
|
2007
|
|
|
2006
|
|
|
|
|
(Millions
of dollars)
|
|
|
Deferred
Tax Liabilities (Assets)
|
|
|
|
|
|
|
|
Depreciation
and other book-to-tax basis differences
|
|
$ |
495.3 |
|
|
$ |
482.2 |
|
|
Deferred
taxes on amounts to be collected through future rates
|
|
|
7.6 |
|
|
|
6.3 |
|
|
Payment
for termination of purchased power contracts with NUGs
|
|
|
67.8 |
|
|
|
72.6 |
|
|
Electric
restructuring liabilities
|
|
|
(74.2 |
) |
|
|
(58.6 |
) |
|
Fuel
and purchased energy
|
|
|
(95.5 |
) |
|
|
(41.4 |
) |
|
Deferred
investment tax credits
|
|
|
(6.0 |
) |
|
|
(7.5 |
) |
|
Other
|
|
|
(21.3 |
) |
|
|
(25.2 |
) |
|
Total
Deferred Tax Liabilities, net
|
|
|
373.7 |
|
|
|
428.4 |
|
|
Deferred
tax asset included in Other Current Assets
|
|
|
12.6 |
|
|
|
12.6 |
|
|
Total
Consolidated Deferred Tax Liabilities, net - non-current
|
|
$ |
386.3 |
|
|
$ |
441.0 |
|
|
|
|
|
|
|
|
|
|
|
The net deferred tax liability
represents the tax effect, at presently enacted tax rates, of temporary
differences between the financial statement 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, 2007 and 2006.
The Tax Reform Act of 1986 repealed the
Investment Tax Credit (ITC) for property placed in service after
December 31, 1985, except for certain transition property. ITC
previously earned on ACE’s property continues to be normalized over the
remaining service lives of the related assets.
Taxes Other Than Income
Taxes
Taxes other than income taxes for each
year are shown below. These amounts relate to the Power Delivery
business and are recoverable through rates.
|
|
2007
|
2006
|
2005
|
|
|
|
(Millions
of dollars)
|
|
|
Gross
Receipts/Delivery
|
$20.0
|
$21.1
|
$20.9
|
|
|
Property
|
2.5
|
2.1
|
1.5
|
|
|
Environmental,
Use and Other
|
(.1)
|
(.3)
|
.2
|
|
|
Total
|
$22.4
|
$22.9
|
$22.6
|
|
|
|
|
|
|
|
(9) PREFERRED
STOCK
|
|
|
Shares Outstanding
|
December 31,
|
|
Series
|
Redemption Price
|
2007
|
2006
|
2007
|
2006
|
|
|
|
|
|
(Millions
of dollars)
|
|
Redeemable Serial
Preferred Stock
|
|
|
|
|
|
$100
per share par value
|
|
|
|
|
|
4.00%-5.00%
|
$100.00-$105.50
|
62,145
|
62,145
|
$6.2
|
$6.2
|
|
|
|
|
|
|
|
(10) FAIR VALUES OF FINANCIAL
INSTRUMENTS
|
|
2007
|
2006
|
|
|
Carrying
Amount
|
Fair
Value
|
Carrying
Amount
|
Fair
Value
|
|
|
(Millions
of dollars)
|
|
Long-term
debt
|
$465.7
|
$464.1
|
$481.7
|
$496.3
|
|
Redeemable
Serial Preferred Stock
|
$ 6.2
|
$ 4.4
|
$ 6.2
|
$ 4.4
|
|
Transition
Bonds issued by ACE Funding
|
$464.5
|
$462.0
|
$494.3
|
$491.4
|
|
|
|
|
|
|
The methods and assumptions below were
used to estimate, at December 31, 2007 and 2006, the fair value of each class of
financial instruments shown above for which it is practicable to estimate a
value.
The fair values of the Long-term Debt,
which includes First Mortgage Bonds, Medium-Term Notes, and Transition Bonds
issued by ACE Funding, including amounts due within one year, were derived based
on current market prices, or for issues with no market price available, were
based on discounted cash flows using current rates for similar issues with
similar terms and remaining maturities.
The fair value of the Redeemable Serial
Preferred Stock, excluding amounts due within one year, were derived based on
quoted market prices or discounted cash flows using current rates of preferred
stock with similar terms.
The carrying amounts of all other
financial instruments in ACE’s accompanying consolidated financial statements
approximate fair value.
(11) COMMITMENTS AND
CONTINGENCIES
Rate
Proceedings
On June 1, 2007, ACE filed with the
NJBPU an application for permission to decrease the Non Utility Generation
Charge (NGC) and increase components of its Societal Benefits Charge (SBC) to be
collected from customers for the period October 1, 2007 through September
30, 2008. The proposed changes are designed to effect a true-up of
the actual and estimated costs and revenues collected through the current NGC
and SBC rates through September 30, 2007 and, in the case of the SBC, forecasted
costs and revenues for the period October 1, 2007 through September 30,
2008.
As of December 31, 2007, the NGC, which
is intended primarily to recover the above-market component of payments made by
ACE under non-utility generation contracts and stranded costs associated with
those commitments, had an over-recovery balance of
$224.3 million. The filing proposed that the estimated NGC
balance as of September 30, 2007 in the amount of $216.2 million, including
interest, be amortized and returned to ACE customers over a four-year period,
beginning October 1, 2007.
As of December 31, 2007, the SBC, which
is intended to allow ACE to recover certain costs involved with various
NJBPU-mandated social programs, had an under-recovery of approximately
$20.9 million, primarily due to increased costs associated with funding the
New Jersey Clean Energy Program. In addition, ACE has requested an
increase to the SBC to reflect the funding levels approved by the NJBPU of $20.4
million for the period October 1, 2007 through September 30, 2008, bringing to
$40 million the total recovery requested for the period October 1,
2007 to September 30, 2008 (based upon actual data through August
2007).
The net impact of the proposed
adjustments to the NGC and the SBC, including associated changes in sales and
use tax, is an overall rate decrease of approximately $129.9 million for
the period October 1, 2007 through September 30, 2008 (based upon actual data
through August 2007). The proposed adjustments and the corresponding
changes in customer rates are subject to the approval of the
NJBPU. If approved and implemented, ACE anticipates that the revised
rates will remain in effect until September 30, 2008, subject to an annual
true-up and change each year thereafter. The proposed adjustments and
the corresponding changes in customer rates remain under review by the NJBPU and
have not yet been implemented.
ACE
Restructuring Deferral Proceeding
Pursuant to orders issued by the NJBPU
under EDECA, beginning August 1, 1999, ACE was obligated to provide BGS to
retail electricity customers in its service territory who did not elect to
purchase electricity from a competitive supplier. For the period
August 1, 1999 through July 31, 2003, ACE’s aggregate costs that it was
allowed to recover from customers exceeded its aggregate revenues from supplying
BGS. These under-recovered costs were partially offset by a
$59.3 million deferred energy cost liability existing as of July 31, 1999
(LEAC Liability) related to ACE’s Levelized Energy Adjustment Clause and ACE’s
Demand Side Management Programs. ACE established a regulatory asset
in an amount equal to the balance of under-recovered costs.
In August 2002, ACE filed a petition
with the NJBPU for the recovery of approximately $176.4 million in actual
and projected deferred costs relating to the provision of BGS and other
restructuring related costs incurred by ACE over the four-year period August 1,
1999 through July 31, 2003, net of the $59.3 million offset for the
LEAC Liability. The petition also requested that ACE’s rates be reset
as of August 1, 2003 so that there would be no under-recovery of costs embedded
in the rates on or after that date. The increase sought represented
an overall 8.4% annual increase in electric rates.
In July 2004, the NJBPU issued a final
order in the restructuring deferral proceeding confirming a July 2003 summary
order, which (i) permitted ACE to begin collecting a portion of the deferred
costs and reset rates to recover on-going costs incurred as a result of EDECA,
(ii) approved the recovery of $125 million of the deferred balance over a
ten-year amortization period beginning August 1, 2003, (iii) transferred to
ACE’s then pending base rate case for further consideration approximately
$25.4 million of the deferred balance (the base rate case ended in a
settlement approved by the NJBPU in May 2005, the result of which is that any
net rate impact from the deferral account recoveries and credits in future years
will depend in part on whether rates associated with other deferred accounts
considered in the case continue to generate over-collections relative to costs),
and (iv) estimated the overall deferral balance as of July 31, 2003 at
$195.0 million, of which $44.6 million was disallowed recovery by
ACE. Although ACE believes the record does not justify the level of
disallowance imposed by the NJBPU in the final order, the $44.6 million of
disallowed incurred costs were reserved during the years 1999 through 2003
(primarily 2003) through charges to earnings, primarily in the operating expense
line item “deferred electric service costs,” with a corresponding reduction in
the regulatory asset balance sheet account. In 2005, an additional
$1.2 million in interest on the disallowed amount was identified and
reserved by ACE. In August 2004, ACE filed a notice of appeal with
respect to the July 2004 final order with the Appellate Division of the Superior
Court of New Jersey (the Appellate Division), which hears appeals of the
decisions of New Jersey administrative agencies, including the
NJBPU. On August 9, 2007, the Appellate Division, citing deference to
the factual and policy findings of the NJBPU, affirmed the NJBPU’s decision in
its entirety, rejecting challenges from ACE and the Division of Rate
Counsel. On September 10, 2007, ACE filed an application for
certification to the New Jersey Supreme Court. On January 15, 2008,
the New Jersey Supreme Court denied ACE’s application for
certification. Because the full amount at issue in this proceeding
was previously reserved by ACE, there will be no further financial statement
impact to ACE.
Divestiture
Case
In connection with the divestiture by
ACE of its nuclear generating assets, the NJBPU in July 2000 preliminarily
determined that the amount of stranded costs associated with the divested assets
that ACE could recover from ratepayers should be reduced by approximately
$94.8 million, consisting of $54.1 million of accumulated deferred
federal income taxes (ADFIT) associated with accelerated depreciation on the
divested nuclear assets, and $40.7 million of current tax loss from selling
the assets at a price below the tax basis.
The $54.1 million in deferred
taxes associated with the divested assets’ accelerated depreciation, however, is
subject to the normalization rules. Due to uncertainty under federal
tax law regarding whether the sharing of federal income tax benefits associated
with the divested assets, including ADFIT related to accelerated depreciation,
with ACE’s customers would violate the normalization rules, ACE submitted a
request to the Internal Revenue Service (IRS) for a Private Letter Ruling (PLR)
to clarify the applicable law. The NJBPU delayed its final
determination of the amount of recoverable stranded costs until after the
receipt of the PLR.
On May 25, 2006, the IRS issued the PLR
in which it stated that returning to ratepayers any of the unamortized ADFIT
attributable to accelerated depreciation on the divested assets after the sale
of the assets by means of a reduction of the amount of recoverable stranded
costs would violate the normalization rules.
On June 9, 2006, ACE submitted a letter
to the NJBPU, requesting that the NJBPU conduct proceedings to finalize the
determination of the stranded costs associated with the sale of ACE’s nuclear
assets in accordance with the PLR. In the absence of an NJBPU action
regarding ACE’s request, on June 22, 2007, ACE filed a motion requesting that
the NJBPU issue an order finalizing the determination of such stranded costs in
accordance with the PLR. On October 24, 2007, the NJBPU approved a
stipulation resolving the ADFIT issue and issued a clarifying order, which
concludes that the $94.8 million in stranded cost reduction, including the
$54.1 million in ADFIT, does not violate the IRS normalization
rules. In explaining this result, the NJBPU stated that (i) its
earlier orders determining ACE’s recoverable stranded costs “net of tax” did not
cause ADFIT associated with certain divested nuclear assets to reduce stranded
costs otherwise recoverable from ACE’s ratepayers, and (ii) because the
Market Transition Charge-Tax component of the stranded cost recovery was
intended by the NJBPU to gross-up “net of tax” stranded costs, thereby ensuring
and establishing that the ADFIT balance was not flowed through to ratepayers,
the normalization rules were not violated.
ACE
Sale of B.L. England Generating Facility
On February 8, 2007, ACE completed the
sale of the B.L. England generating facility to RC Cape May Holdings, LLC (RC
Cape May), an affiliate of Rockland Capital Energy Investments, LLC, for which
it received proceeds of approximately $9 million. At the time of
the sale, RC Cape May and ACE agreed to submit to arbitration the issue of
whether RC Cape May, under the terms of the purchase agreement, must pay to ACE
an additional $3.1 million as part of the purchase price. On
February 26, 2008, the arbitrators issued a decision awarding $3.1 million to
ACE, plus interest, attorneys’ fees and costs, for a total award of
approximately $4.2 million.
On July 18, 2007, ACE received a claim
for indemnification from RC Cape May under the purchase agreement. RC
Cape May contends that one of the assets it purchased, a contract
for
terminal services (TSA) between ACE and Citgo Asphalt Refining Co. (Citgo), has
been declared by Citgo to have been terminated due to a failure by ACE to renew
the contract in a timely manner. RC Cape May has commenced an
arbitration proceeding against Citgo seeking a determination that the TSA
remains in effect and has notified ACE of the proceeding. In
addition, RC Cape May has asserted a claim for indemnification from ACE in the
amount of $25 million if the TSA is held not to be enforceable against
Citgo. While ACE believes that it has defenses to the indemnification
under the terms of the purchase agreement, should the arbitrator rule that the
TSA has terminated, the outcome of this matter is uncertain. ACE
notified RC Cape May of its intent to participate in the pending
arbitration.
The sale of B.L. England will not
affect the stranded costs associated with the plant that already have been
securitized. ACE anticipates that approximately $9 million to $10
million of additional regulatory assets related to B.L. England may, subject to
NJBPU approval, be eligible for recovery as stranded
costs. Approximately $47 million in emission allowance credits
associated with B. L. England were monetized for the benefit of ACE’s ratepayers
pursuant to the NJBPU order approving the sale. Net proceeds from the
sale of the plant and monetization of the emission allowance credits, estimated
to be $36.1 million as of December 31, 2007, will be credited to ACE’s
ratepayers in accordance with the requirements of EDECA and NJBPU
orders. The appropriate mechanism for crediting the net proceeds from
the sale of the plant and the monetized emission allowance credits to ratepayers
is being determined in a proceeding that is currently pending before the
NJBPU.
Environmental
Litigation
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. In addition, federal and state statutes authorize governmental
agencies to compel responsible parties to clean up certain abandoned or
unremediated hazardous waste sites. ACE 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. Although penalties assessed for violations of
environmental laws and regulations are not recoverable from ACE’s customers,
environmental clean-up costs incurred by ACE would be included in its cost of
service for ratemaking purposes.
Delilah Road Landfill
Site. In November 1991, the New Jersey Department of
Environmental Protection (NJDEP) identified ACE as a potentially responsible
party (PRP) at the Delilah Road Landfill site in Egg Harbor Township, New
Jersey. In 1993, ACE, along with other PRPs, signed an administrative
consent order with NJDEP to remediate the site. The soil cap remedy
for the site has been implemented and in August 2006, NJDEP issued a No Further
Action Letter (NFA) and Covenant Not to Sue for the site. Among other
things, the NFA requires the PRPs to monitor the effectiveness of institutional
(deed restriction) and engineering (cap) controls at the site every two
years. In September 2007, NJDEP approved the PRP group’s petition to
conduct semi-annual, rather than quarterly, ground water monitoring for two
years and deferred until the end of the two-year period a decision on the PRP
group’s request for annual groundwater monitoring thereafter. In
August 2007, the PRP group agreed to reimburse EPA’s costs in the amount of
$81,400 in full satisfaction of EPA’s claims for all past and future response
costs relating to the site (of which ACE’s share is one-third) and in October
2007, EPA and the PRP group entered into a tolling agreement to permit the
parties sufficient time to execute a final settlement agreement. This
settlement agreement will allow EPA to reopen the
settlement
in the event of new information or unknown conditions at the
site. Based on information currently available, ACE anticipates that
its share of additional cost associated with this site for post-remedy operation
and maintenance will be approximately $555,000 to $600,000. ACE
believes that its liability for post-remedy operation and maintenance costs will
not have a material adverse effect on its financial position, results of
operations or cash flows.
Frontier Chemical
Site. On June 29, 2007, ACE received a letter from the New
York Department of Environmental Conservation (NYDEC) identifying ACE as a PRP
at the Frontier Chemical Waste Processing Company site in Niagara Falls, N.Y.
based on hazardous waste manifests indicating that ACE sent in excess of 7,500
gallons of manifested hazardous waste to the site. ACE has entered
into an agreement with the other parties identified as PRPs to form the PRP
group and has informed NYDEC that it has entered into good faith negotiations
with the PRP group to address ACE’s responsibility at the site. ACE
believes that its responsibility at the site will not have a material adverse
effect on its financial position, results of operations or cash
flows.
IRS
Mixed Service Cost Issue
During 2001, ACE changed its method of
accounting with respect to capitalizable construction costs for income tax
purposes. The change allowed ACE to accelerate the deduction of
certain expenses that were previously capitalized and
depreciated. Through December 31, 2005, these accelerated deductions
generated incremental tax cash flow benefits of approximately $49 million,
primarily attributable to its 2001 tax returns.
In 2005, the Treasury Department issued
proposed regulations that, if adopted in their current form, would require ACE
to change its method of accounting with respect to capitalizable construction
costs for income tax purposes for tax periods beginning in
2005. Based on the proposed regulations, PHI in its 2005 federal tax
return adopted an alternative method of accounting for capitalizable
construction costs that management believes will be acceptable to the
IRS.
At the same time as the proposed
regulations were released, the IRS issued Revenue Ruling 2005-53, which is
intended to limit the ability of certain taxpayers to utilize the method of
accounting for income tax purposes they utilized on their tax returns for 2004
and prior years with respect to capitalizable construction costs. In
line with this Revenue Ruling, the IRS revenue agent’s report for the 2001 and
2002 tax returns disallowed substantially all of the incremental tax benefits
that ACE had claimed on those returns by requiring it to capitalize and
depreciate certain expenses rather than treat such expenses as current
deductions. PHI’s protest of the IRS adjustments is among the
unresolved audit matters relating to the 2001 and 2002 audits pending before the
Appeals Office.
In February 2006, PHI paid
approximately $121 million of taxes to cover the amount of additional taxes and
interest that management estimated to be payable for the years 2001 through 2004
based on the method of tax accounting that PHI, pursuant to the proposed
regulations, adopted on its 2005 tax return. However, if the IRS is
successful in requiring ACE to capitalize and depreciate construction costs that
result in a tax and interest assessment greater than management’s estimate of
$121 million, PHI will be required to pay additional taxes and interest only to
the extent these adjustments exceed the $121 million payment made in February
2006. It is reasonably possible that PHI’s unrecognized tax benefits
related to this issue will significantly decrease in the next 12 months as a
result of a settlement with the IRS.
Contractual
Obligations
As of December 31, 2007, ACE’s
contractual obligations under non-derivative fuel and power purchase contracts
(excluding BGS supplier load commitments) were $281.7 million in 2008, $548.0
million in 2009 to 2010, $455.4 million in 2011 to 2012, and $2,656.6 million in
2013 and thereafter.
(12) 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 causal
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, 2007, 2006 and 2005 were $81.2 million, $79.3
million and $82.2 million, respectively.
In addition to the PHI Service Company
charges described above, ACE’s financial statements include the following
related party transactions in its Consolidated Statements of
Earnings:
|
|
|
|
|
|
2006
|
2005
|
|
(Expense)
Income
|
(Millions
of dollars)
|
|
Purchased
power from Conectiv Energy Supply (a)
|
$(99.0)
|
$(89.0)
|
$(85.8)
|
|
Meter
reading services provided by
Millennium
Account Services LLC
(b)
|
(3.9)
|
(3.8)
|
(3.7)
|
|
|
(a)
|
Included
in fuel and purchased energy.
|
|
|
(b)
|
Included
in other operation and maintenance.
|
|
|
|
2007
|
|
|
2006
|
|
|
Asset
(Liability)
|
|
(Millions
of dollars)
|
|
|
Receivable
from Related Party (current)
PHI
Parent
|
|
$ |
- |
|
|
$ |
8.4 |
|
|
Payable
to Related Party (current)
|
|
|
|
|
|
|
|
|
|
PHI
Service Company
|
|
|
(10.4 |
) |
|
|
(28.7 |
) |
|
Conectiv
Energy Supply
|
|
|
(7.8 |
) |
|
|
(6.3 |
) |
The
items listed above are included in the “Accounts payable to associated
companies” balance on the Consolidated Balance Sheet of $18.3 million and
$27.3 million at December 31, 2007 and 2006,
respectively.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(13) DISCONTINUED
OPERATIONS
As discussed in Note (11), “Commitments
and Contingencies,” herein, on February 8, 2007, ACE completed the sale of the
B.L. England generating facility. B.L. England comprised a
significant component of ACE’s generation operations and its sale required
“discontinued operations” presentation under SFAS No. 144, “Accounting for the
Impairment or Disposal of Long Lived Assets,” on ACE’s Consolidated Statements
of Earnings for the years ended December 31, 2007, 2006 and
2005. In September 2006, ACE sold its interests in the Keystone and
Conemaugh generating facilities, which for the years ended December 31,
2006 and 2005, are also reflected as “discontinued operations.”
The following table summarizes
information related to the discontinued operations presentation (millions of
dollars):
|
|
|
2007
|
2006
|
|
2005
|
|
|
Operating
Revenue
|
|
$9.7
|
$113.7
|
|
$170.3
|
|
|
Income
Before Income Tax Expense and Extraordinary Item
|
|
$ .2
|
$ 4.4
|
|
$ 5.2
|
|
|
Net
Income
|
|
$ .1
|
$ 2.6
|
|
$ 3.1
|
|
(14) EXTRAORDINARY
ITEMS
On April 19, 2005, ACE, the staff of
the NJBPU, the New Jersey Ratepayer Advocate, and active intervenor parties
agreed on a settlement in ACE’s electric distribution rate case. As a
result of this settlement, ACE reversed $15.2 million in accruals related to
certain deferred costs that are now deemed recoverable. The after-tax
credit to income of $9.0 million is classified as an extraordinary gain in the
2005 financial statements since the original accrual was part of an
extraordinary charge in conjunction with the accounting for competitive
restructuring in 1999.
(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, differences between summer and
winter rates, and the scheduled downtime and maintenance of electric generating
units. Therefore, comparisons by quarter within a year are not
meaningful.
|
|
2007
|
|
|
|
First
Quarter
|
Second
Quarter
|
Third
Quarter
|
Fourth
Quarter
|
Total
|
|
|
|
(Millions
of dollars)
|
|
|
Total
Operating Revenue
|
$338.2
|
|
$338.3
|
|
$504.7
|
|
$361.3
|
|
$1,542.5
|
|
|
Total
Operating Expenses
|
311.9
|
|
291.6
|
(a)
|
448.7
|
(a)
|
331.8
|
(a)
|
1,384.0
|
|
|
Operating
Income
|
26.3
|
|
46.7
|
|
56.0
|
|
29.5
|
|
158.5
|
|
|
Other
Expenses
|
(14.3)
|
|
(14.6)
|
|
(14.5)
|
|
(14.2)
|
|
(57.6)
|
|
|
Income
Before Income Taxes
|
12.0
|
|
32.1
|
|
41.5
|
|
15.3
|
|
100.9
|
|
|
Income
Tax Expense
|
4.3
|
|
12.9
|
|
15.0
|
|
8.7
|
|
40.9
|
|
|
Income
From Continuing Operations
|
7.7
|
|
19.2
|
|
26.5
|
|
6.6
|
|
60.0
|
|
|
Discontinued
Operations, net of tax
|
.1
|
|
-
|
|
-
|
|
-
|
|
.1
|
|
|
Net
Income
|
7.8
|
|
19.2
|
|
26.5
|
|
6.6
|
|
60.1
|
|
|
Dividends
on Preferred Stock
|
.1
|
|
.1
|
|
.1
|
|
-
|
|
.3
|
|
|
Earnings
Available for Common Stock
|
$ 7.7
|
|
$ 19.1
|
|
$ 26.4
|
|
$ 6.6
|
|
$ 59.8
|
|
|
|
2006
|
|
|
|
First
Quarter
|
Second
Quarter
|
Third
Quarter
|
Fourth
Quarter
|
Total
|
|
|
|
(Millions
of dollars)
|
|
|
Total
Operating Revenue
|
$301.5
|
|
$299.0
|
|
$479.7
|
|
$293.1
|
|
$1,373.3
|
|
|
Total
Operating Expenses
|
277.7
|
|
256.9
|
|
417.8
|
|
268.7
|
|
1,221.1
|
|
|
Operating
Income
|
23.8
|
|
42.1
|
|
61.9
|
|
24.4
|
|
152.2
|
|
|
Other
Expenses
|
(16.6)
|
|
(14.6)
|
|
(14.2)
|
|
(13.7)
|
|
(59.1)
|
|
|
Income
Before Income Taxes
|
7.2
|
|
27.5
|
|
47.7
|
|
10.7
|
|
93.1
|
|
|
Income
Tax Expense
|
1.7
|
|
7.8
|
|
18.5
|
|
5.0
|
|
33.0
|
|
|
Income
From Continuing Operations
|
5.5
|
|
19.7
|
|
29.2
|
|
5.7
|
|
60.1
|
|
|
Discontinued
Operations, net of tax
|
.8
|
|
.8
|
|
.7
|
|
.3
|
|
2.6
|
|
|
Net
Income
|
6.3
|
|
20.5
|
|
29.9
|
|
6.0
|
|
62.7
|
|
|
Dividends
on Preferred Stock
|
.1
|
|
.1
|
|
.1
|
|
-
|
|
.3
|
|
|
Earnings
Available for Common Stock
|
$ 6.2
|
|
$ 20.4
|
|
$ 29.8
|
|
$ 6.0
|
|
$ 62.4
|
|
|
(a)
|
Includes
adjustment related to timing of recognition of certain operating expenses
which were overstated by $4.8 million in the fourth quarter and
understated by $1.2 million and $3.6 million in the second and third
quarters, respectively.
|
THIS
PAGE LEFT INTENTIONALLY BLANK.
|
Item
9.
|
CHANGES IN AND
DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE
|
None for all registrants.
Item
9A. CONTROLS AND
PROCEDURES
Pepco Holdings,
Inc.
Conclusion
Regarding the Effectiveness of Disclosure Controls and Procedures
Under the supervision, and with the
participation of management, including the chief executive officer and the chief
financial officer, Pepco Holdings has evaluated the effectiveness of the design
and operation of its disclosure controls and procedures as of December 31, 2007,
and, based upon this evaluation, the chief executive officer and the chief
financial officer of Pepco Holdings have concluded that these controls and
procedures are effective to provide reasonable assurance that material
information relating to Pepco Holdings and its subsidiaries that is required to
be disclosed in reports filed with, or submitted to, the Securities and Exchange
Commission (SEC) under the Securities Exchange Act of 1934, as amended (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 chief executive officer and chief
financial officer, as appropriate to allow timely decisions regarding required
disclosure.
Management’s
Annual Report on Internal Control over Financial Reporting
See “Management’s Annual Report on
Internal Control over Financial Reporting” in Part II, Item 8 of this Form
10-K.
Attestation
Report of the Registered Public Accounting Firm
See “Report of Independent Registered
Public Accounting Firm” in Part II, Item 8 of this Form 10-K.
Changes
in Internal Control over Financial Reporting
During the quarter ended December 31,
2007, there was no change in Pepco Holdings’ internal control over financial
reporting that has materially affected, or is reasonably likely to materially
affect, Pepco Holdings’ internal controls over financial reporting.
Item
9A(T). CONTROLS AND
PROCEDURES
Potomac Electric Power
Company
Conclusion
Regarding the Effectiveness of Disclosure Controls and Procedures
Under the supervision, and with the
participation of management, including the chief executive officer and the chief
financial officer, Pepco has evaluated the effectiveness of the design and
operation of its disclosure controls and procedures as of December 31, 2007,
and, based upon this evaluation, the chief executive officer and the chief
financial officer of Pepco have concluded that these controls and procedures are
effective to provide reasonable assurance
that
material information relating to Pepco 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 chief executive officer and chief financial officer,
as appropriate to allow timely decisions regarding required
disclosure.
Management’s
Annual Report on Internal Control over Financial Reporting
See “Management’s Annual Report on
Internal Control over Financial Reporting” in Part II, Item 8 of this Form
10-K.
Changes
in Internal Control over Financial Reporting
During the quarter ended December 31,
2007, there was no change in Pepco’s internal control over financial reporting
that has materially affected, or is reasonably likely to materially affect,
Pepco’s internal controls over financial reporting.
Delmarva Power and Light
Company
Conclusion
Regarding the Effectiveness of Disclosure Controls and Procedures
Under the supervision, and with the
participation of management, including the chief executive officer and the chief
financial officer, DPL has evaluated the effectiveness of the design and
operation of its disclosure controls and procedures as of December 31, 2007,
and, based upon this evaluation, the chief executive officer and the chief
financial officer of DPL have concluded that these controls and procedures are
effective to provide reasonable assurance that material information relating to
DPL 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 chief executive
officer and chief financial officer, as appropriate to allow timely decisions
regarding required disclosure.
Management’s
Annual Report on Internal Control over Financial Reporting
See “Management’s Annual Report on
Internal Control over Financial Reporting” in Part II, Item 8 of this Form
10-K.
Changes
in Internal Control over Financial Reporting
During the quarter ended December 31,
2007, there was no change in DPL’s internal control over financial reporting
that has materially affected, or is reasonably likely to materially affect,
DPL’s internal controls over financial reporting.
Atlantic City Electric
Company
Conclusion
Regarding the Effectiveness of Disclosure Controls and Procedures
Under the supervision, and with the
participation of management, including the chief executive officer and the chief
financial officer, ACE has evaluated the effectiveness of the design and
operation of its disclosure controls and procedures as of December 31, 2007,
and,
based
upon this evaluation, the chief executive officer and the chief financial
officer of ACE have concluded that these controls and procedures are effective
to provide reasonable assurance that material information relating to ACE 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
chief executive officer and chief financial officer, as appropriate to allow
timely decisions regarding required disclosure.
Management’s
Annual Report on Internal Control over Financial Reporting
See “Management’s Annual Report on
Internal Control over Financial Reporting” in Part II, Item 8 of this Form
10-K.
Changes
in Internal Control over Financial Reporting
During the quarter ended December 31,
2007, there was no change in ACE’s internal control over financial reporting
that has materially affected, or is reasonably likely to materially affect,
ACE’s internal controls over financial reporting.
Item
9B. OTHER
INFORMATION
Pepco Holdings,
Inc.
Potomac Electric Power
Company
Delmarva Power & Light
Company
Atlantic City Electric
Company
Part III
Item
10. DIRECTORS, EXECUTIVE
OFFICERS AND CORPORATE GOVERNANCE
Pepco Holdings,
Inc.
Other than as set forth below, the
information required by this Item 10 with regard to PHI is incorporated herein
by reference to PHI’s definitive proxy statement for the 2008 Annual Meeting of
Shareholders to be filed with the SEC on or about March 27, 2008 (excluding the
information under the caption “Audit Committee Report”).
Executive Officers of
PHI
The names of the executive officers of
PHI and their ages and the positions they held as of February 22, 2008 are
set forth in the following table. Their business experience during
the past five years is set forth in the footnotes to the following
table.
|
PEPCO HOLDINGS
|
|
|
|
Name
|
Age
|
Office and
Length of Service
|
|
Dennis
R. Wraase
|
63
|
Chairman
of the Board, President and Chief Executive Officer
5/04
- Present (1)
|
|
William
T. Torgerson
|
63
|
Vice
Chairman and General Counsel
6/03
- Present (2)
|
|
Joseph
M. Rigby
|
51
|
Executive
Vice President and Chief Operating Officer
9/07
- Present (3)
|
|
Paul
H. Barry
|
50
|
Senior
Vice President and Chief Financial Officer
9/07
- Present (4)
|
|
Beverly
L. Perry
|
60
|
Senior
Vice President
10/02
- Present
|
|
Ronald
K. Clark
|
52
|
Vice
President and Controller
8/05
- Present (5)
|
|
John
U. Huffman
|
48
|
President - 6/06 - Present
and Chief Operating
Officer, Pepco Energy Services, Inc. - 4/06 - Present
(6)
|
|
David
M. Velazquez
|
48
|
President - 6/06 -
Present
and Chief
Executive Officer, Conectiv Energy Holding Company - 1/07 - Present
(7)
|
|
(1)
|
Mr.
Wraase was President and Chief Operating Officer of PHI from August 2002
until June 2003. Mr. Wraase has been Chairman of Pepco
since May 2004 and was Chief Executive Officer from August 2002 until
October 2005. Since May 2004, he has also been Chairman of DPL
and ACE.
|
|
(2)
|
Mr.
Torgerson was Executive Vice President and General Counsel of PHI from
August 2002 until June 2003.
|
|
(3)
|
Mr.
Rigby was Senior Vice President of PHI from August 2002 until September
2007 and was Chief Financial Officer of PHI from May 2004 until September
2007. Mr. Rigby was President of ACE from July 2001 until
May 2004 and Chief Executive Officer of ACE from August 2002 until May
2004. He served as President of DPL from August 2002 until May
2004.
|
|
(4)
|
Mr.
Barry was Senior Vice President and Chief Development Officer of Duke
Energy Corporation from September 2006 to August 2007. From
November 2005 to September 2006, he was Group Executive and President of
Duke Energy Americas, a division of Duke Energy
Corporation. From June 2002 to November 2005, he was a Vice
President of Duke Energy Corporation. Duke Energy is an energy
company not affiliated with PHI.
|
|
(5)
|
Mr.
Clark has been employed by PHI since June 2005 and has also served as Vice
President and Controller of Pepco and DPL and Controller of ACE since
August 2005. From July 2004 until June 2005, he was Vice
President, Financial Reporting and Policy for MCI, Inc., a
telecommunications company not affiliated with PHI. From June
2002 until December 2003, Mr. Clark served as Vice President, Controller
and Chief Accounting Officer of Allegheny Energy, Inc., an energy company
not affiliated with PHI.
|
|
(6)
|
Since
June 2003, Mr. Huffman has been employed by Pepco Energy Services in the
following capacities: (a) Chief Operating Officer from April
2006 to June 2006, (b) Senior Vice President, February 2005 to March 2006
and (c) Vice President from June 2003 to February 2005. From
June 2000 to May 2003, Mr. Huffman was President and Chief Executive
Officer of ACN Energy, Inc, a retail electricity and natural gas provider
which is not affiliated with PHI.
|
|
(7)
|
Mr.
Velazquez served as Chief Operating Officer of Conectiv Energy Holding
Company from June 2006 to December 2006. He served as a Vice
President of PHI from February 2005 to June 2006 and as Chief Risk Officer
of PHI from August 2005 to June 2006. From July 2001 to
February 2005, he served as a Vice President of Conectiv Energy Supply,
Inc., an affiliate of PHI.
|
The PHI executive officers are elected
annually and serve until their respective successors have been elected and
qualified or their earlier resignation or removal.
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. EXECUTIVE
COMPENSATION
Pepco Holdings,
Inc.
The information required by this Item
11 with regard to PHI is incorporated herein by reference to PHI’s definitive
proxy statement for the 2008 Annual Meeting of Shareholders to be filed with the
SEC on or about March 27, 2008 (excluding the information under the caption
“Compensation Committee Report”).
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.
|
SECURITY OWNERSHIP OF
CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER
MATTERS
|
Pepco Holdings,
Inc.
Other than as set forth below, the
information required by this Item 12 with regard to PHI is incorporated herein
by reference to PHI’s definitive proxy statement for the 2008 Annual Meeting of
Shareholders to be filed with the SEC on or about March 27, 2008.
The following table provides
information as of December 31, 2007, with respect to the shares of PHI’s common
stock that may be issued under PHI’s existing equity compensation
plans.
|
Equity
Compensation Plans Information
|
|
Plan
Category
|
|
Number
of Securities to be Issued Upon Exercise of Outstanding
Options
|
|
Weighted-Average
Exercise Price of Outstanding Options
|
|
Number
of Securities Remaining Available for Future Issuance Under Equity
Compensation Plans (Excluding Outstanding Options)
|
|
|
|
|
|
|
|
|
|
Equity
Compensation Plans Approved by Shareholders (a)
|
|
(b)
|
|
(b)
|
|
9,117,365
|
|
|
|
|
|
|
|
|
|
Equity
Compensation Plans Not Approved by Shareholders (c)
|
|
-
|
|
-
|
|
495,731
|
|
|
|
|
|
|
|
|
|
Total
|
|
-
|
|
-
|
|
9,613,096
|
|
(a)
|
Consists
solely of the Pepco Holdings, Inc. Long-Term Incentive
Plan.
|
|
(b)
|
In
connection with the acquisition by Pepco of Conectiv (i) outstanding
options granted under the Potomac Electric Power Company Long-Term
Incentive Plan were converted into options to purchase shares of PHI
common stock and (ii) options granted under the Conectiv Incentive
Compensation Plan were converted into options to purchase shares of PHI
common stock. As of December 31, 2007, options to purchase
an aggregate of 532,635 shares of PHI common stock, having a weighted
average exercise price of $22.3443, were
outstanding.
|
|
(c)
|
On
January 1, 2005, the PHI Non-Management Directors Compensation Plan (the
Directors Compensation Plan) became effective, pursuant to which 500,000
shares of PHI common stock became available for future
issuance. Under the Directors Compensation Plan, each director
who is not an employee of PHI or any of its subsidiaries (“non-management
director”) is entitled to elect to receive his or her annual retainer,
retainer for service as a committee chairman, if any, and meeting fees
in: (i) cash, (ii) shares of PHI’s common stock, (iii) a credit
to an account for the director established under PHI’s Executive and
Director Deferred Compensation Plan or (iv) any combination
thereof. The Directors Compensation Plan expires on
December 31, 2014 unless terminated earlier by the Board of
Directors.
|
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.
|
CERTAIN RELATIONSHIPS
AND RELATED TRANSACTIONS, AND DIRECTOR
INDEPENDENCE
|
Pepco Holdings,
Inc.
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. PRINCIPAL ACCOUNTING FEES
AND SERVICES
Pepco Holdings, Inc., 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 the Company and its
subsidiary reporting companies for the 2007 and 2006 fiscal years, reviews of
the financial statements included in the 2007 and 2006 Forms 10-Q of the Company
and its subsidiary reporting companies, reviews of public filings, comfort
letters and other attest services were $6,074,408 and $5,589,719,
respectively. The amount for 2006 includes $74,592 for the 2006 audit
that was billed after the 2006 amount was disclosed in Pepco Holdings’ proxy
statement for the 2007 Annual Meeting.
Audit-Related
Fees
The aggregate fees billed by
PricewaterhouseCoopers LLP for audit-related services rendered for the 2007 and
2006 fiscal years were zero and $25,853, respectively. These services consisted
of employee benefit plan audits. The amount for 2006 includes $6,117
for 2006 audit-related services that was billed after the 2006 amount was
disclosed in Pepco Holdings’ proxy statement for the 2007 Annual
Meeting.
Tax
Fees
The aggregate fees billed by
PricewaterhouseCoopers LLP for tax services rendered for the 2007 and 2006
fiscal years were $126,810 and $121,951 respectively. These services consisted
of tax compliance, tax advice and tax planning. The amount for 2006
includes $35,791 for the 2006 tax-related services that was billed after the
2006 amount was disclosed in Pepco Holdings’ proxy statement for the 2007 Annual
Meeting.
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 2007 and
2006
fiscal years were $41,740 and $20,419, respectively, which represents 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 is attached
as Annex A. to Pepco Holdings’ definitive proxy statement for the 2008 Annual
Meeting of Shareholders to be filed with the SEC on or about March 27,
2008.
Part IV
Item
15. EXHIBITS, FINANCIAL
STATEMENT SCHEDULES
(a) Documents
List
1. FINANCIAL
STATEMENTS
The financial statements filed as part
of this report consist of the financial statements of each registrant set forth
in Item 8. “Financial Statements and Supplementary Data.”
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 Item 8. “Financial Statements and Supplementary
Data,” herein.
|
|
Registrants
|
|
Item
|
Pepco
Holdings
|
Pepco
|
DPL
|
ACE
|
|
Schedule
I, Condensed Financial
Information
of Parent Company
|
342
|
N/A
|
N/A
|
N/A
|
|
Schedule
II, Valuation and
Qualifying
Accounts
|
345
|
345
|
346
|
346
|
Schedule I, Condensed Financial
Information of Parent Company is submitted below.
|
PEPCO
HOLDINGS, INC. (Parent Company)
|
|
STATEMENTS
OF EARNINGS
|
|
|
|
|
|
|
|
2006
|
|
2005
|
|
|
(Millions
of dollars, except share data)
|
|
|
|
|
|
|
|
|
OPERATING
REVENUE
|
$ -
|
|
$ -
|
|
$ -
|
|
OPERATING
EXPENSES
|
|
|
|
|
|
|
Depreciation
and amortization
|
-
|
|
-
|
|
2.1
|
|
Other
operation and maintenance
|
3.4
|
|
2.8
|
|
5.4
|
|
Total
operating expenses
|
3.4
|
|
2.8
|
|
7.5
|
|
OPERATING
LOSS
|
(3.4)
|
|
(2.8)
|
|
(7.5)
|
|
OTHER
INCOME (EXPENSES)
|
|
|
|
|
|
|
Interest
and dividend income
|
1.3
|
|
.1
|
|
.1
|
|
Interest
expense
|
(91.0)
|
|
(83.3)
|
|
(77.1)
|
|
Income
from equity investments
|
390.6
|
|
298.9
|
|
406.5
|
|
Total
other income
|
300.9
|
|
215.7
|
|
329.5
|
|
|
|
|
|
|
|
|
INCOME
BEFORE INCOME TAXES AND EXTRAORDINARY ITEM
|
297.5
|
|
212.9
|
|
322.0
|
|
INCOME
TAX BENEFIT
|
(36.7)
|
|
(35.4)
|
|
(40.2)
|
|
INCOME
BEFORE EXTRAORDINARY ITEM
|
334.2
|
|
248.3
|
|
362.2
|
|
EXTRAORDINARY
ITEM (net of income taxes of
$6.2
million)
|
-
|
|
-
|
|
9.0
|
|
NET
INCOME
|
$334.2
|
|
$248.3
|
|
$371.2
|
|
EARNINGS
PER SHARE
|
|
|
|
|
|
|
Basic
and diluted before extraordinary item
|
$ 1.72
|
|
$ 1.30
|
|
$ 1.91
|
|
Basic
and diluted extraordinary item
|
-
|
|
-
|
|
.05
|
|
Basic
and diluted earnings
per
share of common stock
|
$ 1.72
|
|
$ 1.30
|
|
$ 1.96
|
The
accompanying Notes are an integral part of these financial
statements.
|
PEPCO
HOLDINGS, INC. (Parent Company)
|
|
BALANCE
SHEETS
|
|
|
|
|
|
|
|
2006
|
|
|
(Millions
of dollars, except share data)
|
|
ASSETS
|
|
|
|
|
Current
Assets
|
|
|
|
|
Cash
and cash equivalents
|
$ 386.6
|
|
$ 96.4
|
|
Accounts
receivable and other
|
58.9
|
|
16.4
|
|
|
445.5
|
|
112.8
|
|
|
|
|
|
|
Investments
and Other Assets
|
|
|
|
|
Notes
receivable from subsidiary companies
|
707.3
|
|
934.3
|
|
Investment
in consolidated companies
|
5,029.6
|
|
4,763.5
|
|
Other
|
25.2
|
|
31.3
|
|
|
5,762.1
|
|
5,729.1
|
|
Total
Assets
|
$6,207.6
|
|
$5,841.9
|
|
|
|
|
|
|
CAPITALIZATION
AND LIABILITIES
|
|
|
|
|
|
|
|
|
|
Current
Liabilities
|
|
|
|
|
Short-term
debt
|
$ -
|
|
$ 536.0
|
|
Accounts
payable
|
2.8
|
|
3.4
|
|
Interest
and taxes accrued
|
89.3
|
|
41.9
|
|
|
92.1
|
|
581.3
|
|
|
|
|
|
|
Long-Term
Debt
|
2,097.1
|
|
1,648.4
|
|
|
|
|
|
|
Commitments
and Contingencies
|
|
|
|
|
|
|
|
|
|
Capitalization
|
|
|
|
|
Common
stock, $.01 par value;
authorized
400,000,000 shares; issued
200,512,890
and 191,932,445 shares, respectively
|
2.0
|
|
1.9
|
|
Premium
on stock and other capital
contributions
|
2,869.2
|
|
2,645.0
|
|
Accumulated
other comprehensive loss
|
(45.5)
|
|
(103.4)
|
|
Retained
earnings
|
1,192.7
|
|
1,068.7
|
|
Total
common stockholders’ equity
|
4,018.4
|
|
3,612.2
|
|
Total
Capitalization and Liabilities
|
$6,207.6
|
|
$5,841.9
|
|
|
|
|
|
The
accompanying Notes are an integral part of these financial
statements.
|
PEPCO
HOLDINGS, INC. (Parent Company)
|
|
STATEMENTS
OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
2005
|
|
|
(Millions
of dollars)
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES
|
|
|
|
|
|
|
Net
income
|
$ 334.2
|
|
$ 248.3
|
|
$ 371.2
|
|
Adjustments
to reconcile net income to net
cash
provided by operating activities:
|
|
|
|
|
|
|
Depreciation
and amortization
|
2.6
|
|
2.7
|
|
6.6
|
|
Distributions
from related parties
(less
than) in excess of earnings
|
(215.1)
|
|
(200.7)
|
|
(344.1)
|
|
Extraordinary
item
|
-
|
|
-
|
|
(15.2)
|
|
Deferred
income taxes, net
|
1.6
|
|
34.6
|
|
3.8
|
|
Net
change in:
|
|
|
|
|
|
|
Prepaid
and other
|
(.2)
|
|
6.0
|
|
(1.0)
|
|
Accounts
payable
|
10.3
|
|
(.1)
|
|
.7
|
|
Interest
and taxes
|
(5.2)
|
|
(33.5)
|
|
.5
|
|
Other,
net
|
(1.1)
|
|
11.0
|
|
12.1
|
|
Net
cash provided by operating activities
|
127.1
|
|
68.3
|
|
34.6
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES
|
|
|
|
|
|
|
Net
investment in property, plant and equipment
|
-
|
|
-
|
|
-
|
|
Net
cash used by investing activities
|
-
|
|
-
|
|
-
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES
|
|
|
|
|
|
|
Dividends
paid on common stock
|
(202.6)
|
|
(198.3)
|
|
(188.9)
|
|
Common
stock issued to the Dividend Reinvestment Plan
|
28.0
|
|
29.8
|
|
27.5
|
|
Issuance
of common stock
|
199.6
|
|
17.0
|
|
5.7
|
|
Issuance
of long-term debt
|
450.0
|
|
200.0
|
|
250.0
|
|
Reacquisition
of long-term debt
|
(500.0)
|
|
(300.0)
|
|
-
|
|
Decrease
(increase) in notes receivable from
associated companies
|
227.0
|
|
202.9
|
|
(49.1)
|
|
(Repayments)
issuances of short-term debt, net
|
(36.0)
|
|
36.0
|
|
(128.6)
|
|
Costs
of issuances and refinancings
|
(2.9)
|
|
(2.1)
|
|
(3.2)
|
|
Other
financing activities
|
-
|
|
(.4)
|
|
(.3)
|
|
Net
cash from (used by) financing activities
|
163.1
|
|
(15.1)
|
|
(86.9)
|
|
Net
change in cash and cash equivalents
|
290.2
|
|
53.2
|
|
(52.3)
|
|
Beginning
of year cash and cash equivalents
|
96.4
|
|
43.2
|
|
95.5
|
|
End
of year cash and cash equivalents
|
$386.6
|
|
$ 96.4
|
|
$ 43.2
|
The
accompanying Notes are an integral part of these financial
statements.
NOTES
TO FINANCIAL INFORMATION
These
condensed financial statements represent the financial information for Pepco
Holdings, Inc. (Parent Company).
For
information concerning PHI’s long-term debt obligations, see Note (7) “Debt” to
the consolidated financial statements of Pepco Holdings included in Item 8 of
Part II.
For
information concerning PHI’s material contingencies and guarantees, see Note
(12) “Commitments and Contingencies” to the consolidated financial statements of
Pepco Holdings included in Item 8.
The
Parent Company’s majority owned subsidiaries are recorded using the equity
method of accounting.
Schedule II (Valuation and Qualifying
Accounts) for each registrant is submitted below:
|
Pepco Holdings,
Inc.
|
|
|
Col. A
|
Col. B
|
Col. C
|
Col. D
|
Col. E
|
|
|
|
Additions
|
|
|
|
Description
|
Balance
at
Beginning
of Period
|
Charged
to
Costs
and
Expenses
|
Charged
to
Other
Accounts (a)
|
Deductions(b)
|
Balance
at
End
of Period
|
|
|
(Millions
of dollars)
|
|
Allowance
for uncollectible
accounts
- customer and
other
accounts receivable
|
$35.8
|
$33.1
|
$1.3
|
$(39.6)
|
$30.6
|
|
Allowance
for uncollectible
accounts
- customer and
other
accounts receivable
|
$40.6
|
$19.9
|
$1.4
|
$(26.1)
|
$35.8
|
|
Allowance
for uncollectible
accounts
- customer and
other
accounts receivable
|
$43.7
|
$21.4
|
$2.0
|
$(26.5)
|
$40.6
|
(a) Collection
of accounts previously written off.
(b) Uncollectible
accounts written off.
|
Potomac Electric Power
Company
|
|
Col. A
|
Col. B
|
Col. C
|
Col. D
|
Col. E
|
|
|
|
Additions
|
|
|
|
Description
|
Balance
at
Beginning
of Period
|
Charged
to
Costs
and
Expenses
|
Charged
to
Other
Accounts (a)
|
Deductions(b)
|
Balance
at
End
of Period
|
|
|
(Millions
of dollars)
|
|
Allowance
for uncollectible
accounts
- customer and
other
accounts receivable
|
$17.4
|
$15.2
|
$1.3
|
$(21.4)
|
$12.5
|
|
Allowance
for uncollectible
accounts
- customer and
other
accounts receivable
|
$14.1
|
$11.0
|
$1.4
|
$(9.1)
|
$17.4
|
|
Allowance
for uncollectible
accounts
- customer and
other
accounts receivable
|
$20.1
|
$ .9
|
$2.0
|
$(8.9)
|
$14.1
|
(a) Collection
of accounts previously written off.
(b) Uncollectible
accounts written off.
|
Delmarva Power &
Light Company
|
|
Col. A
|
Col. B
|
Col. C
|
Col. D
|
Col. E
|
|
|
|
Additions
|
|
|
|
Description
|
Balance
at
Beginning
of Period
|
Charged
to
Costs
and
Expenses
|
Charged
to
Other
Accounts (a)
|
Deductions(b)
|
Balance
at
End
of Period
|
|
|
(Millions
of dollars)
|
|
Allowance
for uncollectible
accounts
- customer and
other
accounts receivable
|
$ 7.8
|
$12.0
|
$-
|
$(11.8)
|
$ 8.0
|
|
Allowance
for uncollectible
accounts
- customer and
other
accounts receivable
|
$ 9.2
|
$ 4.3
|
$-
|
$ (5.7)
|
$ 7.8
|
|
Allowance
for uncollectible
accounts
- customer and
other
accounts receivable
|
$ 8.7
|
$ 6.8
|
$-
|
$ (6.3)
|
$ 9.2
|
(a) Collection
of accounts previously written off.
(b) Uncollectible
accounts written off.
|
Atlantic City Electric
Company
|
|
|
Col. A
|
Col. B
|
Col. C
|
Col. D
|
Col. E
|
|
|
|
Additions
|
|
|
|
Description
|
Balance
at
Beginning
of Period
|
Charged
to
Costs
and
Expenses
|
Charged
to
Other
Accounts (a)
|
Deductions(b)
|
Balance
at
End
of Period
|
|
|
(Millions
of dollars)
|
|
Allowance
for uncollectible
accounts
- customer and
other
accounts receivable
|
$5.5
|
$4.9
|
$-
|
$(5.5)
|
$4.9
|
|
Allowance
for uncollectible
accounts
- customer and
other
accounts receivable
|
$5.2
|
$5.0
|
$-
|
$(4.7)
|
$5.5
|
|
Allowance
for uncollectible
accounts
- customer and
other
accounts receivable
|
$4.5
|
$5.5
|
$-
|
$(4.8)
|
$5.2
|
(a) Collection
of accounts previously written off.
(b) Uncollectible
accounts written off.
3. EXHIBITS
The documents listed below are being
filed herewith or have previously been filed and are incorporated herein by
reference from the documents indicated and made a part hereof.
|
Exhibit
No.
|
Registrant(s)
|
Description of Exhibit
|
Reference
|
|
3.1
|
PHI
|
Restated
Certificate of Incorporation (filed in Delaware 6/2/2005)
|
Exh.
3.1 to PHI’s Form 10-K, 3/13/06.
|
|
3.2
|
Pepco
|
Restated
Articles of Incorporation and Articles of Restatement (as filed in the
District of Columbia)
|
Exh.
3.1 to Pepco’s Form 10-Q, 5/5/06.
|
|
3.3
|
DPL
|
Articles
of Restatement of Certificate and Articles of Incorporation (filed in
Delaware and Virginia 02/22/07)
|
Exh.
3.3 to DPL’s Form 10-K, 3/1/07.
|
|
3.4
|
ACE
|
Restated
Certificate of Incorporation (filed in New Jersey 8/09/02)
|
Exh.
B.8.1 to PHI’s Amendment No. 1 to Form U5B, 2/13/03.
|
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3.5
|
PHI
|
Bylaws
|
Exh.
3 to PHI’s Form 8-K, 5/3/07.
|
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3.6
|
Pepco
|
By-Laws
|
Exh.
3.1 to Pepco’s Form 10-Q, 5/5/06.
|
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3.7
|
DPL
|
Bylaws
|
Exh.
3.2.1 to DPL’s Form 10-Q 5/9/05.
|
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3.8
|
ACE
|
Bylaws
|
Exh.
3.2.2 to ACE’s Form 10-Q 5/9/05.
|
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4.1
|
PHI
Pepco
|
Mortgage
and Deed of Trust dated July 1, 1936, of Pepco to The Bank of New
York as Successor Trustee, securing First Mortgage Bonds of Pepco, and
Supplemental Indenture dated July 1, 1936
|
Exh.
B-4 to First Amendment, 6/19/36, to Pepco’s Registration Statement No.
2-2232.
|
|
|
|
Supplemental
Indentures, to the aforesaid Mortgage and Deed of Trust, dated
-
December
10, 1939
|
Exh.
B to Pepco’s Form 8-K, 1/3/40.
|
|
|
|
July
15, 1942
|
Exh.
B-1 to Amendment No. 2, 8/24/42, and B-3 to Post-Effective Amendment,
8/31/42, to Pepco’s Registration Statement No.
2-5032.
|
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|
|
October
15, 1947
|
Exh.
A to Pepco’s Form 8-K, 12/8/47.
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December
31, 1948
|
Exh.
A-2 to Pepco’s Form 10-K, 4/13/49.
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December
31, 1949
|
Exh.
(a)-1 to Pepco’s Form 8-K, 2/8/50.
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February
15, 1951
|
Exh.
(a) to Pepco’s Form 8-K, 3/9/51.
|
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February
16, 1953
|
Exh.
(a)-1 to Pepco’s Form 8-K, 3/5/53.
|
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|
March
15, 1954 and March 15, 1955
|
Exh.
4-B to Pepco’s Registration Statement No. 2-11627,
5/2/55.
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March
15, 1956
|
Exh.
C to Pepco’s Form 10-K, 4/4/56.
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April
1, 1957
|
Exh.
4-B to Pepco’s Registration Statement No. 2-13884,
2/5/58.
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May
1, 1958
|
Exh.
2-B to Pepco’s Registration Statement No. 2-14518,
11/10/58.
|
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May
1, 1959
|
Exh.
4-B to Amendment No. 1, 5/13/59, to Pepco’s Registration Statement No.
2-15027.
|
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|
May
2, 1960
|
Exh.
2-B to Pepco’s Registration Statement No. 2-17286,
11/9/60.
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April
3, 1961
|
Exh.
A-1 to Pepco’s Form 10-K, 4/24/61.
|
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May
1, 1962
|
Exh.
2-B to Pepco’s Registration Statement No. 2-21037,
1/25/63.
|
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May
1, 1963
|
Exh.
4-B to Pepco’s Registration Statement No. 2-21961,
12/19/63.
|
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April
23, 1964
|
Exh.
2-B to Pepco’s Registration Statement No. 2-22344,
4/24/64.
|
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May
3, 1965
|
Exh.
2-B to Pepco’s Registration Statement No. 2-24655,
3/16/66.
|
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June
1, 1966
|
Exh.
1 to Pepco’s Form 10-K, 4/11/67.
|
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April
28, 1967
|
Exh.
2-B to Post-Effective Amendment No. 1 to Pepco’s Registration Statement
No. 2-26356, 5/3/67.
|
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July
3, 1967
|
Exh.
2-B to Pepco’s Registration Statement No. 2-28080,
1/25/68.
|
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May
1, 1968
|
Exh.
2-B to Pepco’s Registration Statement No. 2-31896,
2/28/69.
|
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June
16, 1969
|
Exh.
2-B to Pepco’s Registration Statement No. 2-36094,
1/27/70.
|
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May
15, 1970
|
Exh.
2-B to Pepco’s Registration Statement No. 2-38038,
7/27/70.
|
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September
1, 1971
|
Exh.
2-C to Pepco’s Registration Statement No. 2-45591,
9/1/72.
|
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June
17, 1981
|
Exh.
2 to Amendment No. 1 to Form 8-A, 6/18/81.
|
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November
1, 1985
|
Exh.
2B to Form 8-A, 11/1/85.
|
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September
16, 1987
|
Exh.
4-B to Registration Statement No. 33-18229, 10/30/87.
|
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May
1, 1989
|
Exh.
4-C to Registration Statement No. 33-29382, 6/16/89.
|
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May
21, 1991
|
Exh.
4 to Form 10-K, 3/27/92,
|
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|
Exh.
4 to Pepco’s Form 10-K, 3/26/93.
|
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|
Exh.
4 to Pepco’s Form 10-K, 3/26/93.
|
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|
Exh.
4 to Pepco’s Form 10-K, 3/26/93.
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|
Exh.
4 to Pepco’s Form 10-K, 3/26/93.
|
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|
Exh.
4.4 to Pepco’s Registration Statement No. 33-49973,
8/11/93.
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|
Exh.
4 to Pepco’s Form 10-K, 3/25/94.
|
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|
Exh.
4 to Pepco’s Form 10-K, 3/25/94.
|
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|
Exh.
4 to Pepco’s Form 10-K, 3/25/94.
|
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|
Exh.
4.3 to Registration Statement No. 33-61379, 7/28/95.
|
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|
Exh.
4 to Pepco’s Form 10-K, 3/26/98.
|
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|
Exhibit
4.1 to Pepco’s Form 10-K, 3/11/04.
|
|
|
|
|
Exh.
4.3 to Pepco’s Form 8-K, 3/23/04.
|
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|
Exh.
4.2 to Pepco’s Form 8-K, 5/26/05.
|
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|
Exh.
4.1 to Pepco’s Form 8-K, 4/17/06.
|
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|
|
Exh.
4.2 to Pepco’s Form 8-K, 11/15/07.
|
|
4.2
|
PHI
Pepco
|
Indenture,
dated as of July 28, 1989, between Pepco and The Bank of New York,
Trustee, with respect to Pepco’s Medium-Term Note Program
|
Exh.
4 to Pepco’s Form 8-K, 6/21/90.
|
|
4.3
|
PHI
Pepco
|
|
Exh.
4.2 to Pepco’s Form 8-K, 11/21/03.
|
|
4.4
|
PHI
DPL
|
Mortgage
and Deed of Trust of Delaware Power & Light Company to The Bank of New
York Trust Company, N.A. Trustee, (ultimate successor to the New York
Trust Company) dated as of October 1, 1943 and copies of the First
through Sixty-Eighth Supplemental Indentures thereto
|
Exh.
4-A to DPL’s Registration Statement No. 33-1763,
11/27/85.
|
|
|
|
Sixty-Ninth
Supplemental Indenture
|
Exh.
4-B to DPL’s Registration Statement No. 33-39756,
4/03/91.
|
|
|
|
Seventieth
through Seventy-Fourth Supplemental Indentures
|
Exhs.
4-B to DPL’s Registration Statement No. 33-24955,
10/13/88.
|
|
|
|
Seventy-Fifth
through Seventy-Seventh Supplemental Indentures
|
Exhs.
4-D, 4-E & 4-F to DPL’s Registration Statement No. 33-39756,
4/03/91.
|
|
|
|
Seventy-Eighth
and Seventy-Ninth Supplemental Indentures
|
Exhs.
4-E & 4-F to DPL’s Registration Statement No. 33-46892,
4/1/92.
|
|
|
|
Eightieth
Supplemental Indenture
|
Exh.
4 to DPL’s Registration Statement No. 33-49750,
7/17/92.
|
|
|
|
Eighty-First
Supplemental Indenture
|
Exh.
4-G to DPL’s Registration Statement No. 33-57652,
1/29/93.
|
|
|
|
Eighty-Second
Supplemental Indenture
|
Exh.
4-H to DPL’s Registration Statement No. 33-63582,
5/28/93.
|
|
|
|
Eighty-Third
Supplemental Indenture
|
Exh.
99 to DPL’s Registration Statement No. 33-50453,
10/1/93.
|
|
|
|
Eighty-Fourth
through Eighty-Eighth Supplemental Indentures
|
Exhs.
4-J, 4-K, 4-L, 4-M & 4-N to DPL’s Registration Statement No. 33-53855,
1/30/95.
|
|
|
|
Eighty-Ninth
and Ninetieth Supplemental Indentures
|
Exhs.
4-K & 4-L to DPL’s Registration Statement No. 333-00505,
1/29/96.
|
|
4.5
|
PHI
DPL
|
Indenture
between DPL and The Bank of New York Trust Company, N.A. (ultimate
successor to Manufacturers Hanover Trust Company), as Trustee, dated as of
November 1, 1988
|
Exh.
No. 4-G to DPL’s Registration Statement No. 33-46892,
4/1/92.
|
|
4.6
|
PHI
ACE
|
Mortgage
and Deed of Trust, dated January 15, 1937, between Atlantic City Electric
Company and The Bank of New York (formerly Irving Trust
Company)
|
Exh.
2(a) to ACE’s Registration Statement No. 2-66280,
12/21/79.
|
|
|
|
Supplemental
Indentures, to the aforesaid Mortgage and Deed of Trust, dated as of
-
|
|
|
|
|
June
1, 1949
|
Exh.
2(b) to ACE’s Registration Statement No. 2-66280,
12/21/79.
|
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|
|
July
1, 1950
|
Exh.
2(b) to ACE’s Registration Statement No. 2-66280,
12/21/79.
|
|
|
|
November
1, 1950
|
Exh.
2(b) to ACE’s Registration Statement No. 2-66280,
12/21/79.
|
|
|
|
March
1, 1952
|
Exh.
2(b) to ACE’s Registration Statement No. 2-66280,
12/21/79.
|
|
|
|
January
1, 1953
|
Exh.
2(b) to ACE’s Registration Statement No. 2-66280,
12/21/79.
|
|
|
|
March
1, 1954
|
Exh.
2(b) to ACE’s Registration Statement No. 2-66280,
12/21/79.
|
|
|
|
March
1, 1955
|
Exh.
2(b) to ACE’s Registration Statement No. 2-66280,
12/21/79.
|
|
|
|
January
1, 1957
|
Exh.
2(b) to ACE’s Registration Statement No. 2-66280,
12/21/79.
|
|
|
|
April
1, 1958
|
Exh.
2(b) to ACE’s Registration Statement No. 2-66280,
12/21/79.
|
|
|
|
April
1, 1959
|
Exh.
2(b) to ACE’s Registration Statement No. 2-66280,
12/21/79.
|
|
|
|
March
1, 1961
|
Exh.
2(b) to ACE’s Registration Statement No. 2-66280,
12/21/79.
|
|
|
|
July
1, 1962
|
Exh.
2(b) to ACE’s Registration Statement No. 2-66280,
12/21/79.
|
|
|
|
March
1, 1963
|
Exh.
2(b) to ACE’s Registration Statement No. 2-66280,
12/21/79.
|
|
|
|
February
1, 1966
|
Exh.
2(b) to ACE’s Registration Statement No. 2-66280,
12/21/79.
|
|
|
|
April
1, 1970
|
Exh.
2(b) to ACE’s Registration Statement No. 2-66280,
12/21/79.
|
|
|
|
September
1, 1970
|
Exh.
2(b) to ACE’s Registration Statement No. 2-66280,
12/21/79.
|
|
|
|
May
1, 1971
|
Exh.
2(b) to ACE’s Registration Statement No. 2-66280,
12/21/79.
|
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|
|
April
1, 1972
|
Exh.
2(b) to ACE’s Registration Statement No. 2-66280,
12/21/79.
|
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|
June
1, 1973
|
Exh.
2(b) to ACE’s Registration Statement No. 2-66280,
12/21/79.
|
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|
|
January
1, 1975
|
Exh.
2(b) to ACE’s Registration Statement No. 2-66280,
12/21/79.
|
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|
May
1, 1975
|
Exh.
2(b) to ACE’s Registration Statement No. 2-66280,
12/21/79.
|
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|
|
December
1, 1976
|
Exh.
2(b) to ACE’s Registration Statement No. 2-66280,
12/21/79.
|
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|
|
January
1, 1980
|
Exh.
4(e) to ACE’s Form 10-K, 3/25/81.
|
|
|
|
May
1, 1981
|
Exh.
4(a) to ACE’s Form 10-Q, 8/10/81.
|
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|
November
1, 1983
|
Exh.
4(d) to ACE’s Form 10-K, 3/30/84.
|
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|
|
April
15, 1984
|
Exh.
4(a) to ACE’s Form 10-Q, 5/14/84.
|
|
|
|
July
15, 1984
|
Exh.
4(a) to ACE’s Form 10-Q, 8/13/84.
|
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|
October
1, 1985
|
Exh.
4 to ACE’s Form 10-Q, 11/12/85.
|
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|
May
1, 1986
|
Exh.
4 to ACE’s Form 10-Q, 5/12/86.
|
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|
July
15, 1987
|
Exh.
4(d) to ACE’s Form 10-K, 3/28/88.
|
|
|
|
October
1, 1989
|
Exh.
4(a) to ACE’s Form 10-Q for quarter ended 9/30/89.
|
|
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|
March
1, 1991
|
Exh.
4(d)(1) to ACE’s Form 10-K, 3/28/91.
|
|
|
|
|
Exh.
4(b) to ACE’s Registration Statement 33-49279, 1/6/93.
|
|
|
|
|
Exh.
4.05(hh) to ACE’s Registration Statement 333-108861,
9/17/03
|
|
|
|
|
Exh.
4(a) to ACE’s Form 10-Q, 11/12/93.
|
|
|
|
|
Exh.
4(b) to ACE’s Form 10-Q, 11/12/93.
|
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|
|
Exh.
4(c)(1) to ACE’s Form 10-K, 3/29/94.
|
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|
|
|
Exh.
4(a) to ACE’s Form 10-Q, 8/14/94.
|
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|
|
Exh.
4(a) to ACE’s Form 10-Q, 11/14/94.
|
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|
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|
Exh.
4(c)(1) to ACE’s Form 10-K, 3/21/95.
|
|
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|
Exh.
4(b) to ACE’s Form 8-K, 3/24/97.
|
|
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|
|
Exh.
4.3 to ACE’s Form 8-K, 4/6/04.
|
|
|
|
|
Exh.
4 to PHI’s Form 10-Q, 11/8/04.
|
|
|
|
|
Exh.
4 to ACE’s Form 8-K, 3/17/06.
|
|
4.7
|
PHI
ACE
|
Indenture
dated as of March 1, 1997 between Atlantic City Electric Company and The
Bank of New York
|
Exh.
4(e) to ACE’s Form 8-K, 3/24/97.
|
|
4.8
|
PHI
ACE
|
Senior
Note Indenture, dated as of April 1, 2004, with The Bank of New York, as
trustee
|
Exh.
4.2 to ACE’s Form 8-K, 4/6/04.
|
|
4.9
|
PHI
ACE
|
Indenture
dated as of December 19, 2002 between Atlantic City Electric
Transition Funding LLC (ACE Funding) and The Bank of New
York
|
Exh.
4.1 to ACE Funding’s Form 8-K, 12/23/02.
|
|
4.10
|
PHI
ACE
|
2002-1
Series Supplement dated as of December 19, 2002 between ACE Funding
and The Bank of New York
|
Exh.
4.2 to ACE Funding’s Form 8-K, 12/23/02.
|
|
4.11
|
PHI
ACE
|
2003-1
Series Supplement dated as of December 23, 2003 between ACE Funding
and The Bank of New York
|
Exh.
4.2 to ACE Funding’s Form 8-K, 12/23/03.
|
|
4.12
|
PHI
|
Indenture
between PHI and The Bank of New York, as Trustee dated September 6,
2002
|
Exh.
4.03 to PHI’s Registration Statement No. 333-100478,
10/10/02.
|
|
10.1
|
PHI
|
Employment
Agreement of Dennis R. Wraase*
|
Exh.
10.3 to PHI’s Form 10-Q, 8/6/07.
|
|
10.2
|
PHI
|
Employment
Agreement of William T. Torgerson*
|
Exh.
10.3 to PHI’s Form 10-Q, 8/9/02.
|
|
10.3
|
PHI
|
Employment
Agreement of Thomas S. Shaw*
|
Exh.
10.5 to PHI’s Form 10-Q, 8/9/02.
|
|
10.4
|
PHI
|
Employment
Agreement of Paul H. Barry*
|
Exh.
10 to PHI’s Form 8-K, 8/13/07.
|
|
10.5
|
PHI
|
Employment
Agreement of Joseph M. Rigby*
|
Exh.
10.8 to PHI’s Form 10-Q, 8/9/02.
|
|
10.6
|
PHI
|
Pepco
Holdings, Inc. Long-Term Incentive Plan*
|
Exh.
10.9 to PHI’s Form 10-K, 3/13/06.
|
|
10.7
|
PHI
|
Pepco
Holdings, Inc. Executive and Director Deferred Compensation
Plan*
|
Exh.
10.13 to PHI’s Form 10-K, 3/13/06.
|
|
10.8
|
PHI
Pepco
|
Potomac
Electric Power Company Director and Executive Deferred Compensation
Plan*
|
Exh.
10.22 to PHI’s Form 10-K, 3/28/03.
|
|
10.9
|
PHI
Pepco
|
Potomac
Electric Power Company Long-Term Incentive Plan*
|
Exh.
4 to Pepco’s Form S-8, 6/12/98.
|
|
10.10
|
PHI
|
Conectiv
Incentive Compensation Plan*
|
Exh.
99(e) to Conectiv’s Registration Statement No. 333-18843,
12/26/96.
|
|
10.11
|
PHI
|
Conectiv
Supplemental Executive Retirement Plan*
|
Exh.
10.26 to PHI’s Form 10-K, 3/28/03.
|
|
10.12
|
ACE
|
Bondable
Transition Property Sale Agreement between ACE Funding and ACE dated as of
December 19, 2002
|
Exh.
10.1 to ACE Funding’s Form 8-K, 12/23/02.
|
|
10.13
|
ACE
|
Bondable
Transition Property Servicing Agreement between ACE Funding and ACE dated
as of December 19, 2002
|
Exh.
10.2 to ACE Funding’s Form 8-K, 12/23/02.
|
|
10.14
|
PHI
|
Conectiv
Deferred Compensation Plan*
|
Exh.
10.1 to PHI’s Form 10-Q, 8/6/04.
|
|
10.15
|
PHI
|
Form
of Employee Nonqualified Stock Option Agreement*
|
Exh.
10.2 to PHI’s Form 10-Q, 11/8/04.
|
|
10.16
|
PHI
|
Form
of Director Nonqualified Stock Option Agreement*
|
Exh.
10.3 to PHI’s Form 10-Q, 11/8/04.
|
|
10.17
|
PHI
|
Form
of Election Regarding Payment of Director Retainer/Fees*
|
Exh.
10.4 to PHI’s Form 10-Q, 11/8/04.
|
|
10.18
|
PHI
|
Form
of Executive and Director Deferred Compensation Plan Executive Deferral
Agreement*
|
Exh.
10.5 to PHI’s Form 10-Q, 11/8/04.
|
|
10.19
|
PHI
|
Form
of Executive Incentive Compensation Plan Participation
Agreement*
|
Exh.
10.6 to PHI’s Form 10-Q, 11/8/04.
|
|
10.20
|
PHI
|
Form
of Restricted Stock Agreement*
|
Exh.
10.7 to PHI’s Form 10-Q, 11/8/04.
|
|
10.21
|
PHI
|
Form
of Election with Respect to Stock Tax Withholding*
|
Exh.
10.8 to PHI’s Form 10-Q, 11/8/04.
|
|
10.22
|
PHI
|
Non-Management
Directors Compensation Plan*
|
Exh.
10.2 to PHI’s Form 8-K, 12/17/04.
|
|
10.23
|
PHI
|
|
Exh.
10.3 to PHI’s Form 8-K, 12/17/04.
|
|
10.24
|
PHI
|
Non-Management
Director Compensation Arrangements*
|
Filed
herewith.
|
|
10.25
|
PHI
|
Form
of Election regarding Non-Management Directors Compensation
Plan*
|
Exh.
10.57 to PHI’s Form 10-K, 3/16/05.
|
|
10.26
|
PHI
Pepco
|
Change-in-Control
Severance Plan for Certain Executive Employees*
|
Exh.
10 to PHI’s Form 8-K, 1/30/06.
|
|
10.27
|
PHI
Pepco
|
PHI
Named Executive Officer 2006 Compensation Determinations*
|
Exh.
10.50 to PHI’s Form 10-K, 3/13/06.
|
|
10.28
|
PHI
Pepco
DPL
ACE
|
Amended
and Restated Credit Agreement, dated as of May 2, 2007, between PHI,
Pepco, DPL and ACE, the lenders party thereto, Wachovia Bank, National
Association, as administrative agent and swingline lender, Citicorp USA,
Inc., as syndication agent, The Royal Bank of Scotland, plc, The Bank of
Nova Scotia and JPMorgan Chase Bank, N.A., as documentation agents, and
Wachovia Capital Markets, LLC and Citigroup Global Markets Inc., as joint
lead arrangers and joint book runners
|
Exh.
10 to PHI’s Form 10-Q, 5/7/07.
|
|
10.29
|
PHI
|
Agreement
and General Release of Claims between PHI and Eddie R.
Mayberry*
|
Exh.
10.43 to PHI’s Form 10-K, 3/1/07.
|
|
10.30
|
PHI
|
Agreement
and General Release of Claims between PHI and William J.
Sim*
|
Exh.
10.45 to PHI’s Form 10-K, 3/1/07.
|
|
10.31
|
PHI
|
Pepco
Holdings, Inc. Combined Executive Retirement Plan*
|
Exh.
10.46 to PHI’s Form 10-K, 3/1/07.
|
|
10.32
|
PHI
|
PHI
Named Executive Officer 2007 Compensation Determinations*
|
Exh.
10.47 to PHI’s Form 10-K, 3/1/07.
|
|
10.33
|
PHI
|
PHI
Named Executive Officer 2008 Compensation Determinations*
|
Filed
herewith.
|
|
10.34
|
DPL
|
Transmission
Purchase and Sale Agreement By and Between Delmarva Power & Light
Company and Old Dominion Electric Cooperative dated as of June 13,
2007
|
Exh.
10.1 to DPL’s Form 10-Q, 8/6/07.
|
|
10.35
|
DPL
|
Purchase
And Sale Agreement By and Between Delmarva Power & Light Company and
A&N Electric Cooperative dated as of June 13, 2007
|
Exh.
10.2 to DPL’s Form 10-Q, 8/6/07.
|
|
11
|
PHI
|
Statements
Re: Computation of Earnings Per Common Share
|
**
|
|
12.1
|
PHI
|
Statements
Re: Computation of Ratios
|
Filed
herewith.
|
|
12.2
|
Pepco
|
Statements
Re: Computation of Ratios
|
Filed
herewith.
|
|
12.3
|
DPL
|
Statements
Re: Computation of Ratios
|
Filed
herewith.
|
|
12.4
|
ACE
|
Statements
Re: Computation of Ratios
|
Filed
herewith.
|
|
21
|
PHI
|
Subsidiaries
of the Registrant
|
Filed
herewith.
|
|
23.1
|
PHI
|
Consent
of Independent Registered Public Accounting Firm
|
Filed
herewith.
|
|
23.2
|
Pepco
|
Consent
of Independent Registered Public Accounting Firm
|
Filed
herewith.
|
|
23.3
|
DPL
|
Consent
of Independent Registered Public Accounting Firm
|
Filed
herewith.
|
|
23.4
|
ACE
|
Consent
of Independent Registered Public Accounting Firm
|
Filed
herewith.
|
|
31.1
|
PHI
|
Rule
13a-14(a)/15d-14(a) Certificate of Chief Executive Officer
|
Filed
herewith.
|
|
31.2
|
PHI
|
Rule
13a-14(a)/15d-14(a) Certificate of Chief Financial Officer
|
Filed
herewith.
|
|
31.3
|
Pepco
|
Rule
13a-14(a)/15d-14(a) Certificate of Chief Executive Officer
|
Filed
herewith.
|
|
31.4
|
Pepco
|
Rule
13a-14(a)/15d-14(a) Certificate of Chief Financial Officer
|
Filed
herewith.
|
|
31.5
|
DPL
|
Rule
13a-14(a)/15d-14(a) Certificate of Chief Executive Officer
|
Filed
herewith.
|
|
31.6
|
DPL
|
Rule
13a-14(a)/15d-14(a) Certificate of Chief Financial Officer
|
Filed
herewith.
|
|
31.7
|
ACE
|
Rule
13a-14(a)/15d-14(a) Certificate of Chief Executive Officer
|
Filed
herewith.
|
|
31.8
|
ACE
|
Rule
13a-14(a)/15d-14(a) Certificate of Chief Financial Officer
|
Filed
herewith.
|
* Management
contract or compensatory plan or arrangement.
** The
information required by this Exhibit is set forth in Note (10) of
the ”Notes to Consolidated Financial Statements” of the Financial
Statements of Pepco Holdings included in Item 8 “Financial Statements and
Supplementary Data.”
Regulation S-K Item 10(d) requires
Registrants to identify the physical location, by SEC file number reference of
all documents that are incorporated by reference and have been on file with the
SEC for more than five years. The SEC file number references for
Pepco Holdings, Inc., those of its subsidiaries that are registrants, Conectiv
and ACE Funding are provided below:
Pepco Holdings, Inc. in file number
001-31403
Potomac Electric Power Company in file
number 001-1072
Delmarva Power & Light Company in
file number 001-1405
Atlantic City Electric Company in file
number 001-3559
Atlantic City Electric Transition
Funding LLC in file number 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:
|
Exhibit No.
|
Registrant(s)
|
Description of Exhibit
|
|
32.1
|
PHI
|
Certificate
of Chief Executive Officer and Chief Financial Officer pursuant to 18
U.S.C. Section 1350
|
|
32.2
|
Pepco
|
Certificate
of Chief Executive Officer and Chief Financial Officer pursuant to 18
U.S.C. Section 1350
|
|
32.3
|
DPL
|
Certificate
of Chief Executive Officer and Chief Financial Officer pursuant to 18
U.S.C. Section 1350
|
|
32.4
|
ACE
|
Certificate
of Chief Executive Officer and Chief Financial Officer pursuant to 18
U.S.C. Section 1350
|
(b) Exhibits
PEPCO HOLDINGS,
INC.
|
|
|
|
|
|
2006
|
2005
|
2004
|
2003
|
|
|
(Millions
of dollars)
|
|
Income
before extraordinary item (a)
|
$324.1
|
$245.0
|
$368.5
|
$257.4
|
$204.9
|
|
|
|
|
|
|
|
|
Income
tax expense (b)
|
187.9
|
161.4
|
255.2
|
167.3
|
62.1
|
|
|
|
|
|
|
|
|
Fixed
charges:
|
|
|
|
|
|
|
Interest
on long-term debt,
amortization of
discount,
premium
and expense
|
348.4
|
342.8
|
341.4
|
376.2
|
385.9
|
|
Other
interest
|
25.4
|
18.8
|
20.3
|
20.6
|
21.7
|
|
Preferred
dividend requirements
of
subsidiaries
|
.3
|
1.2
|
2.5
|
2.8
|
13.9
|
|
Total
fixed charges
|
374.1
|
362.8
|
364.2
|
399.6
|
421.5
|
|
|
|
|
|
|
|
|
Nonutility
capitalized interest
|
(1.6)
|
(1.0)
|
(.5)
|
(.1)
|
(10.2)
|
|
|
|
|
|
|
|
|
Income
before extraordinary
item,
income tax expense, fixed
charges
and capitalized interest
|
$884.5
|
$768.2
|
$987.4
|
$824.2
|
$678.3
|
|
|
|
|
|
|
|
|
Total
fixed charges, shown above
|
374.1
|
362.8
|
364.2
|
399.6
|
421.5
|
|
Increase
preferred stock dividend
requirements
of subsidiaries to
a
pre-tax amount
|
.2
|
.8
|
1.7
|
1.8
|
4.2
|
|
|
|
|
|
|
|
|
Fixed
charges for ratio
computation
|
$374.3
|
$363.6
|
$365.9
|
$401.4
|
$425.7
|
|
|
|
|
|
|
|
|
Ratio
of earnings to fixed charges
and
preferred dividends
|
2.36
|
2.11
|
2.70
|
2.05
|
1.59
|
|
|
(a)
|
Excludes
income/losses on equity
investments.
|
|
|
(b)
|
Concurrent
with the adoption of FIN 48 in 2007, amount includes interest on uncertain
tax positions.
|
POTOMAC ELECTRIC POWER
COMPANY
|
|
|
|
|
|
2006
|
2005
|
2004
|
2003
|
|
|
(Millions
of dollars)
|
|
Net
income
|
$125.1
|
$ 85.4
|
$165.0
|
$ 96.5
|
$103.2
|
|
|
|
|
|
|
|
|
Income
tax expense (a)
|
62.3
|
57.4
|
127.6
|
55.7
|
67.3
|
|
|
|
|
|
|
|
|
Fixed
charges:
|
|
|
|
|
|
|
Interest
on long-term debt,
amortization
of discount,
premium
and expense
|
86.5
|
77.1
|
82.8
|
82.5
|
83.8
|
|
Other
interest
|
11.6
|
12.9
|
13.6
|
14.3
|
16.2
|
|
Preferred
dividend requirements
of
a subsidiary trust
|
-
|
-
|
-
|
-
|
4.6
|
|
Total
fixed charges
|
98.1
|
90.0
|
96.4
|
96.8
|
104.6
|
|
|
|
|
|
|
|
|
Income
before income tax expense
and
fixed charges
|
$285.5
|
$232.8
|
$389.0
|
$249.0
|
$275.1
|
|
|
|
|
|
|
|
|
Ratio
of earnings to fixed charges
|
2.91
|
2.59
|
4.04
|
2.57
|
2.63
|
|
|
|
|
|
|
|
|
Total
fixed charges, shown above
|
98.1
|
90.0
|
96.4
|
96.8
|
104.6
|
|
|
|
|
|
|
|
|
Preferred
dividend requirements,
excluding
mandatorily redeemable
preferred
securities subsequent
to
SFAS No. 150 implementation,
adjusted
to a pre-tax amount
|
-
|
1.7
|
2.3
|
1.6
|
5.5
|
|
|
|
|
|
|
|
|
Total
Fixed Charges and
Preferred
Dividends
|
$ 98.1
|
$ 91.7
|
$ 98.7
|
$ 98.4
|
$110.1
|
|
|
|
|
|
|
|
|
Ratio
of earnings to fixed charges
and
preferred dividends
|
2.91
|
2.54
|
3.94
|
2.53
|
2.50
|
|
|
(a)
|
Concurrent
with the adoption of FIN 48 in 2007, amount includes interest on uncertain
tax positions.
|
DELMARVA POWER & LIGHT
COMPANY
|
|
|
|
|
|
2006
|
2005
|
2004
|
2003
|
|
|
(Millions
of dollars)
|
|
Net
income
|
$ 44.9
|
$ 42.5
|
$74.7
|
$ 63.0
|
$ 52.4
|
|
|
|
|
|
|
|
|
Income
tax expense (a)
|
37.2
|
32.1
|
57.6
|
48.1
|
37.0
|
|
|
|
|
|
|
|
|
Fixed
charges:
|
|
|
|
|
|
|
Interest
on long-term debt,
amortization
of discount,
premium
and expense
|
43.8
|
41.3
|
35.3
|
33.0
|
37.2
|
|
Other
interest
|
2.3
|
2.5
|
2.7
|
2.2
|
2.7
|
|
Preferred
dividend requirements
of
a subsidiary trust
|
-
|
-
|
-
|
-
|
2.8
|
|
Total
fixed charges
|
46.1
|
43.8
|
38.0
|
35.2
|
42.7
|
|
|
|
|
|
|
|
|
Income
before income tax expense
and
fixed charges
|
$128.2
|
$118.4
|
$170.3
|
$146.3
|
$132.1
|
|
|
|
|
|
|
|
|
Ratio
of earnings to fixed charges
|
2.78
|
2.70
|
4.48
|
4.16
|
3.09
|
|
|
|
|
|
|
|
|
Total
fixed charges, shown above
|
46.1
|
43.8
|
38.0
|
35.2
|
42.7
|
|
|
|
|
|
|
|
|
Preferred
dividend requirements,
adjusted
to a pre-tax amount
|
-
|
1.4
|
1.8
|
1.7
|
1.7
|
|
|
|
|
|
|
|
|
Total
fixed charges and
preferred
dividends
|
$ 46.1
|
$ 45.2
|
$ 39.8
|
$ 36.9
|
$ 44.4
|
|
|
|
|
|
|
|
|
Ratio
of earnings to fixed charges
and
preferred dividends
|
2.78
|
2.62
|
4.28
|
3.96
|
2.98
|
|
|
(a)
|
Concurrent
with the adoption of FIN 48 in 2007, amount includes interest on uncertain
tax positions.
|
ATLANTIC CITY ELECTRIC
COMPANY
|
|
|
|
|
|
2006
|
2005
|
2004
|
2003
|
|
|
(Millions
of dollars)
|
|
Income
from continuing operations
|
$ 60.0
|
$ 60.1
|
$ 51.1
|
$ 58.8
|
$ 31.6
|
|
|
|
|
|
|
|
|
Income
tax expense (a)
|
40.9
|
33.0
|
41.2
|
40.7
|
20.7
|
|
|
|
|
|
|
|
|
Fixed
charges:
|
|
|
|
|
|
|
Interest
on long-term debt,
amortization
of discount,
premium
and expense
|
66.0
|
64.9
|
60.1
|
62.2
|
63.7
|
|
Other
interest
|
3.3
|
3.2
|
3.7
|
3.4
|
2.6
|
|
Preferred
dividend requirements
of
subsidiary trusts
|
-
|
-
|
-
|
-
|
1.8
|
|
Total
fixed charges
|
69.3
|
68.1
|
63.8
|
65.6
|
68.1
|
|
|
|
|
|
|
|
|
Income
before extraordinary
item,
income tax expense and
fixed
charges
|
$170.2
|
$161.2
|
$156.1
|
$165.1
|
$120.4
|
|
|
|
|
|
|
|
|
Ratio
of earnings to fixed charges
|
2.46
|
2.37
|
2.45
|
2.52
|
1.77
|
|
|
|
|
|
|
|
|
Total
fixed charges, shown above
|
69.3
|
68.1
|
63.8
|
65.6
|
68.1
|
|
|
|
|
|
|
|
|
Preferred
dividend requirements
adjusted
to a pre-tax amount
|
.5
|
.5
|
.5
|
.5
|
.5
|
|
|
|
|
|
|
|
|
Total
fixed charges and
preferred
dividends
|
$ 69.8
|
$ 68.6
|
$ 64.3
|
$ 66.1
|
$ 68.6
|
|
|
|
|
|
|
|
|
Ratio
of earnings to fixed charges
and
preferred dividends
|
2.44
|
2.35
|
2.43
|
2.50
|
1.76
|
|
|
(a)
|
Concurrent
with the adoption of FIN 48 in 2007, amount includes interest on uncertain
tax positions.
|
Exhibit
21 Subsidiaries of the
Registrants
|
Name
of Company
|
Jurisdiction
of
Incorporation
or
Organization
|
|
Pepco
Holdings, Inc.
|
DE
|
|
Potomac
Electric Power Company
|
D.C.
& VA
|
|
Gridco
International LLC
|
DE
|
|
POM
Holdings, Inc.
|
DE
|
|
Microcell
Corporation
|
NC
|
|
Pepco
Energy Services, Inc.
|
DE
|
|
Pepco
Building Services Inc.
|
DE
|
|
W.A.
Chester, L.L.C.
|
DE
|
|
W.A.
Chester Corporation
|
DE
|
|
Chester
Transmission Construction Canada, Inc.
|
Canada
|
|
Severn
Construction Services, LLC
|
DE
|
|
Chesapeake
HVAC, Inc. (f/k/a Unitemp, Inc.)
|
DE
|
|
Conectiv
Thermal Systems, Inc.
|
DE
|
|
ATS
Operating Services, Inc.
|
DE
|
|
Atlantic
Jersey Thermal Systems, Inc.
|
DE
|
|
Thermal
Energy Limited Partnership I
|
DE
|
|
Eastern
Landfill Gas, LLC
|
DE
|
|
Blue
Ridge Renewable Energy, LLC
|
DE
|
|
Distributed
Generation Partners, LLC
|
DE
|
|
Rolling
Hills Landfill Gas, LLC
|
DE
|
|
Potomac
Power Resources, LLC
|
DE
|
|
Fauquier
Landfill Gas, L.L.C.
|
DE
|
|
Pepco
Energy Services - Suez Thermal, LLC (f/k/a Trigen-Pepco Energy Services,
LLC)
|
DC
|
|
Pepco
Government Services LLC
|
DE
|
|
Pepco
Enterprises, Inc.
|
DE
|
|
Electro
Ecology, Inc.
|
NY
|
|
Pepco
Energy Cogeneration LLC
|
DE
|
|
Bethlehem
Renewable Energy, LLC
|
DE
|
|
Potomac
Capital Investment Corporation
|
DE
|
|
PCI
Netherlands Corporation
|
NV
|
|
PCI
Queensland LLC (f/k/a PCI Queensland Corporation)
|
NV
|
|
AMP
Funding, LLC
|
DE
|
|
RAMP
Investments, LLC
|
DE
|
|
PCI
Air Management Partners, LLC
|
DE
|
|
PCI
Ever, Inc.
|
DE
|
|
Friendly
Skies, Inc.
|
Virgin
Islands
|
|
PCI
Air Management Corporation
|
NV
|
|
American
Energy Corporation
|
DE
|
|
PCI-BT
Investing, LLC
|
DE
|
|
Linpro
Harmans Land LTD Partnership
|
MD
|
|
Potomac
Nevada Corporation
|
NV
|
|
Potomac
Delaware Leasing Corporation
|
DE
|
|
Potomac
Equipment Leasing Corporation
|
NV
|
|
Potomac
Leasing Associates, LP
|
DE
|
|
Potomac
Nevada Leasing Corporation
|
NV
|
|
PCI
Engine Trading, Ltd.
|
Bermuda
|
|
Potomac
Capital Joint Leasing Corporation
|
DE
|
|
PCI
Nevada Investments
|
DE
|
|
PCI
Holdings, Inc.
|
DE
|
|
Aircraft
International Management Company
|
DE
|
|
PCI-DB
Ventures
|
DE
|
|
Potomac
Nevada Investment, Inc.
|
NV
|
|
PCI
Energy Corporation
|
DE
|
|
PHI
Service Company
|
DE
|
|
Conectiv
|
DE
|
|
Delmarva
Power & Light Company
|
DE
& VA
|
|
Atlantic
City Electric Company
|
NJ
|
|
Atlantic
City Electric Transition Funding LLC
|
DE
|
|
Conectiv
Properties and Investments, Inc.
|
DE
|
|
DCTC-Burney,
Inc.
|
DE
|
|
Conectiv
Solutions LLC
|
DE
|
|
ATE
Investment, Inc.
|
DE
|
|
King
Street Assurance Ltd.
|
Bermuda
|
|
Enertech
Capital Partners, LP
|
DE
|
|
Enertech
Capital Partners II, LP
|
DE
|
|
Black
Light Power, Inc.
|
DE
|
|
Millennium
Account Services, LLC
|
DE
|
|
Conectiv
Services, Inc.
|
DE
|
|
Atlantic
Generation, Inc.
|
NJ
|
|
Vineland
Limited, Inc.
|
DE
|
|
Vineland
Cogeneration Limited Partnership
|
DE
|
|
Vineland
General, Inc.
|
DE
|
|
Pedrick
Gen., Inc.
|
NJ
|
|
Project
Finance Fund III, LP
|
DE
|
|
Conectiv
Communications, Inc.
|
DE
|
|
Atlantic
Southern Properties, Inc.
|
NJ
|
|
Conectiv
Energy Holding Company
|
DE
|
|
ACE
REIT, Inc.
|
DE
|
|
Conectiv
Atlantic Generation, LLC
|
DE
|
|
Conectiv
Bethlehem LLC
|
DE
|
|
Conectiv
Delmarva Generation, LLC
|
DE
|
|
Conectiv
Pennsylvania Generation, LLC
|
DE
|
|
Conectiv
Energy Supply, Inc.
|
DE
|
|
Conectiv
North East, LLC
|
DE
|
|
Energy
Systems North East, LLC
|
DE
|
|
Delta,
LLC
|
DE
|
|
Conectiv
Mid Merit, LLC
|
DE
|
|
Delaware
Operating Services Company
|
DE
|
|
PHI
Operating Services Company
|
DE
|
|
Tech
Leaders II, LP
|
DE
|
Exhibit
23.1
CONSENT OF INDEPENDENT
REGISTERED PUBLIC ACCOUNTING FIRM
We hereby
consent to the incorporation by reference in the Registration Statements on Form
S-3 (Nos. 333-145691 and 333-129429) and the Registration Statements on Form S-8
(Nos. 333-96675, 333-121823 and 333-131371) of Pepco Holdings, Inc. of our
report dated February 29, 2008 for Pepco Holdings, Inc. relating to the
financial statements, financial statement schedules, and the effectiveness of
internal control over financial reporting, which appears in this Form
10-K.
Exhibit
23.2
CONSENT OF INDEPENDENT
REGISTERED PUBLIC ACCOUNTING FIRM
We hereby
consent to the incorporation by reference in the Registration Statement on Form
S-3 (No. 333-145691-03) of Potomac Electric Power Company of our report dated
February 29, 2008 relating to the financial statements and financial
statement schedule of Potomac Electric Power Company, which appears in this Form
10-K.
Exhibit
23.3
CONSENT OF INDEPENDENT
REGISTERED PUBLIC ACCOUNTING FIRM
We hereby
consent to the incorporation by reference in the Registration Statement on Form
S-3 (No. 333-145691-02) of Delmarva Power & Light Company of our report
dated February 29, 2008 relating to the financial statements and financial
statement schedule of Delmarva Power & Light Company, which appears in this
Form 10-K.
Exhibit
23.4
CONSENT OF INDEPENDENT
REGISTERED PUBLIC ACCOUNTING FIRM
We hereby
consent to the incorporation by reference in the Registration Statement on Form
S-3 (No. 333-145691-01) of Atlantic City Electric Company of our report dated
February 29, 2008 relating to the financial statements and financial statement
schedule of Atlantic City Electric Company, which appears in this Form
10-K.
|
|
|
|
|
I,
Dennis R. Wraase, certify that:
|
|
1.
|
I
have reviewed
this report on Form 10-K of Pepco Holdings, Inc.
|
|
2.
|
Based
on my knowledge, this report does not contain any untrue statement of a
material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this
report;
|
|
3.
|
Based
on my knowledge, the financial statements, and other financial information
included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this
report;
|
|
4.
|
The
registrant’s other certifying officer(s) and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchanges Act Rules 13a-15(e) and 15d-15(e)) and internal
control over financial reporting (as defined in Exchange Act Rules
13a-15(f) and 15d-15(f)) for the registrant and
have:
|
|
|
a)
|
Designed
such disclosure controls and procedures, or caused such disclosure
controls and procedures to be designed under our supervision, to ensure
that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being
prepared;
|
|
|
b)
|
Designed
such internal controls over financial reporting, or caused such internal
controls over financial reporting to be designed under our supervision, 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;
|
|
|
c)
|
Evaluated
the effectiveness of the registrant’s disclosure controls and procedures
and presented in this report our conclusions about the effectiveness of
the disclosure controls and procedures, as of the end of the period
covered by this report based on such evaluation; and
|
|
|
d)
|
Disclosed
in this report any change in the registrant’s internal control over
financial reporting that occurred during the registrant’s most recent
fiscal quarter (the registrant’s fourth fiscal quarter in the case of an
annual report) that has materially affected, or is reasonably likely to
materially affect, the registrant’s internal control over financial
reporting; and
|
|
5.
|
The
registrant’s other certifying officer(s) and I have disclosed, based on
our most recent evaluation of internal control over financial reporting,
to the registrant’s auditors and the audit committee of registrant’s board
of directors (or persons performing the equivalent
functions):
|
|
|
a)
|
All
significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrant’s ability to record,
process, summarize and report financial information; and
|
|
|
b)
|
Any
fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant’s internal control
over financial reporting.
|
|
|
/s/ D. R.
WRAASE
Dennis
R. Wraase
Chairman
of the Board, President
and
Chief Executive Officer
|
|
|
|
CERTIFICATION
|
|
I,
Paul H. Barry, certify that:
|
|
1.
|
I
have reviewed this report on Form 10-K of Pepco Holdings,
Inc.
|
|
2.
|
Based
on my knowledge, this report does not contain any untrue statement of a
material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this
report;
|
|
3.
|
Based
on my knowledge, the financial statements, and other financial information
included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this
report;
|
|
4.
|
The
registrant’s other certifying officer(s) and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchanges Act Rules 13a-15(e) and 15d-15(e)) and internal
control over financial reporting (as defined in Exchange Act Rules
13a-15(f) and 15d-15(f)) for the registrant and
have:
|
|
|
a)
|
Designed
such disclosure controls and procedures, or caused such disclosure
controls and procedures to be designed under our supervision, to ensure
that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being
prepared;
|
|
|
b)
|
Designed
such internal controls over financial reporting, or caused such internal
controls over financial reporting to be designed under our supervision, 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;
|
|
|
c)
|
Evaluated
the effectiveness of the registrant’s disclosure controls and procedures
and presented in this report our conclusions about the effectiveness of
the disclosure controls and procedures, as of the end of the period
covered by this report based on such evaluation; and
|
|
|
d)
|
Disclosed
in this report any change in the registrant’s internal control over
financial reporting that occurred during the registrant’s most recent
fiscal quarter (the registrant’s fourth fiscal quarter in the case of an
annual report) that has materially affected, or is reasonably likely to
materially affect, the registrant’s internal control over financial
reporting; and
|
|
5.
|
The
registrant’s other certifying officer(s) and I have disclosed, based on
our most recent evaluation of internal control over financial reporting,
to the registrant’s auditors and the audit committee of registrant’s board
of directors (or persons performing the equivalent
functions):
|
|
|
a)
|
All
significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrant’s ability to record,
process, summarize and report financial information; and
|
|
|
b)
|
Any
fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant’s internal control
over financial reporting.
|
|
|
/s/ P. H.
BARRY
Paul
H. Barry
Senior
Vice President and
Chief
Financial Officer
|
|
|
|
CERTIFICATION
|
|
I,
Joseph M. Rigby, certify that:
|
|
1.
|
I
have reviewed this report on Form 10-K of Potomac Electric Power
Company.
|
|
2.
|
Based
on my knowledge, this report does not contain any untrue statement of a
material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this
report;
|
|
3.
|
Based
on my knowledge, the financial statements, and other financial information
included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this
report;
|
|
4.
|
The
registrant’s other certifying officer(s) and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchanges Act Rules 13a-15(e) and 15d-15(e)) and internal
control over financial reporting (as defined in Exchange Act Rules
13a-15(f) and 15d-15(f)) for the registrant and
have:
|
|
|
a)
|
Designed
such disclosure controls and procedures, or caused such disclosure
controls and procedures to be designed under our supervision, to ensure
that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being
prepared;
|
|
|
b)
|
Designed
such internal controls over financial reporting, or caused such internal
controls over financial reporting to be designed under our supervision, 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;
|
|
|
c)
|
Evaluated
the effectiveness of the registrant’s disclosure controls and procedures
and presented in this report our conclusions about the effectiveness of
the disclosure controls and procedures, as of the end of the period
covered by this report based on such evaluation; and
|
|
|
d)
|
Disclosed
in this report any change in the registrant’s internal control over
financial reporting that occurred during the registrant’s most recent
fiscal quarter (the registrant’s fourth fiscal quarter in the case of an
annual report) that has materially affected, or is reasonably likely to
materially affect, the registrant’s internal control over financial
reporting; and
|
|
5.
|
The
registrant’s other certifying officer(s) and I have disclosed, based on
our most recent evaluation of internal control over financial reporting,
to the registrant’s auditors and the audit committee of registrant’s board
of directors (or persons performing the equivalent
functions):
|
|
|
a)
|
All
significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrant’s ability to record,
process, summarize and report financial information; and
|
|
|
b)
|
Any
fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant’s internal control
over financial reporting.
|
|
|
/s/
JOSEPH M.
RIGBY
Joseph
M. Rigby
President
and Chief Executive Officer
|
|
|
|
CERTIFICATION
|
|
I,
Paul H. Barry, certify that:
|
|
1.
|
I
have reviewed this report on Form 10-K of Potomac Electric Power
Company.
|
|
2.
|
Based
on my knowledge, this report does not contain any untrue statement of a
material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this
report;
|
|
3.
|
Based
on my knowledge, the financial statements, and other financial information
included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this
report;
|
|
4.
|
The
registrant’s other certifying officer(s) and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchanges Act Rules 13a-15(e) and 15d-15(e)) and internal
control over financial reporting (as defined in Exchange Act Rules
13a-15(f) and 15d-15(f)) for the registrant and
have:
|
|
|
a)
|
Designed
such disclosure controls and procedures, or caused such disclosure
controls and procedures to be designed under our supervision, to ensure
that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being
prepared;
|
|
|
b)
|
Designed
such internal controls over financial reporting, or caused such internal
controls over financial reporting to be designed under our supervision, 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;
|
|
|
c)
|
Evaluated
the effectiveness of the registrant’s disclosure controls and procedures
and presented in this report our conclusions about the effectiveness of
the disclosure controls and procedures, as of the end of the period
covered by this report based on such evaluation; and
|
|
|
d)
|
Disclosed
in this report any change in the registrant’s internal control over
financial reporting that occurred during the registrant’s most recent
fiscal quarter (the registrant’s fourth fiscal quarter in the case of an
annual report) that has materially affected, or is reasonably likely to
materially affect, the registrant’s internal control over financial
reporting; and
|
|
5.
|
The
registrant’s other certifying officer(s) and I have disclosed, based on
our most recent evaluation of internal control over financial reporting,
to the registrant’s auditors and the audit committee of registrant’s board
of directors (or persons performing the equivalent
functions):
|
|
|
a)
|
All
significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrant’s ability to record,
process, summarize and report financial information; and
|
|
|
b)
|
Any
fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant’s internal control
over financial reporting.
|
|
|
/s/ P. H.
BARRY
Paul
H. Barry
Senior
Vice President and
Chief
Financial Officer
|
|
|
|
CERTIFICATION
|
|
I,
Joseph M. Rigby, certify that:
|
|
1.
|
I
have reviewed this report on Form 10-K of Delmarva Power & Light
Company.
|
|
2.
|
Based
on my knowledge, this report does not contain any untrue statement of a
material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this
report;
|
|
3.
|
Based
on my knowledge, the financial statements, and other financial information
included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this
report;
|
|
4.
|
The
registrant’s other certifying officer(s) and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchanges Act Rules 13a-15(e) and 15d-15(e)) and internal
control over financial reporting (as defined in Exchange Act Rules
13a-15(f) and 15d-15(f)) for the registrant and
have:
|
|
|
a)
|
Designed
such disclosure controls and procedures, or caused such disclosure
controls and procedures to be designed under our supervision, to ensure
that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being
prepared;
|
|
|
b)
|
Designed
such internal controls over financial reporting, or caused such internal
controls over financial reporting to be designed under our supervision, 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;
|
|
|
c)
|
Evaluated
the effectiveness of the registrant’s disclosure controls and procedures
and presented in this report our conclusions about the effectiveness of
the disclosure controls and procedures, as of the end of the period
covered by this report based on such evaluation; and
|
|
|
d)
|
Disclosed
in this report any change in the registrant’s internal control over
financial reporting that occurred during the registrant’s most recent
fiscal quarter (the registrant’s fourth fiscal quarter in the case of an
annual report) that has materially affected, or is reasonably likely to
materially affect, the registrant’s internal control over financial
reporting; and
|
|
5.
|
The
registrant’s other certifying officer(s) and I have disclosed, based on
our most recent evaluation of internal control over financial reporting,
to the registrant’s auditors and the audit committee of registrant’s board
of directors (or persons performing the equivalent
functions):
|
|
|
a)
|
All
significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrant’s ability to record,
process, summarize and report financial information; and
|
|
|
b)
|
Any
fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant’s internal control
over financial reporting.
|
|
|
/s/
JOSEPH M.
RIGBY
Joseph
M. Rigby
President
and Chief Executive Officer
|
|
|
|
CERTIFICATION
|
|
I,
Paul H. Barry, certify that:
|
|
1.
|
I
have reviewed this report on Form 10-K of Delmarva Power & Light
Company.
|
|
2.
|
Based
on my knowledge, this report does not contain any untrue statement of a
material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this
report;
|
|
3.
|
Based
on my knowledge, the financial statements, and other financial information
included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this
report;
|
|
4.
|
The
registrant’s other certifying officer(s) and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchanges Act Rules 13a-15(e) and 15d-15(e)) and internal
control over financial reporting (as defined in Exchange Act Rules
13a-15(f) and 15d-15(f)) for the registrant and
have:
|
|
|
a)
|
Designed
such disclosure controls and procedures, or caused such disclosure
controls and procedures to be designed under our supervision, to ensure
that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being
prepared;
|
|
|
b)
|
Designed
such internal controls over financial reporting, or caused such internal
controls over financial reporting to be designed under our supervision, 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;
|
|
|
c)
|
Evaluated
the effectiveness of the registrant’s disclosure controls and procedures
and presented in this report our conclusions about the effectiveness of
the disclosure controls and procedures, as of the end of the period
covered by this report based on such evaluation; and
|
|
|
d)
|
Disclosed
in this report any change in the registrant’s internal control over
financial reporting that occurred during the registrant’s most recent
fiscal quarter (the registrant’s fourth fiscal quarter in the case of an
annual report) that has materially affected, or is reasonably likely to
materially affect, the registrant’s internal control over financial
reporting; and
|
|
5.
|
The
registrant’s other certifying officer(s) and I have disclosed, based on
our most recent evaluation of internal control over financial reporting,
to the registrant’s auditors and the audit committee of registrant’s board
of directors (or persons performing the equivalent
functions):
|
|
|
a)
|
All
significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrant’s ability to record,
process, summarize and report financial information; and
|
|
|
b)
|
Any
fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant’s internal control
over financial reporting.
|
|
|
/s/ P. H.
BARRY
Paul
H. Barry
Senior
Vice President and
Chief
Financial Officer
|
|
|
|
CERTIFICATION
|
|
I,
Joseph M. Rigby, certify that:
|
|
1.
|
I
have reviewed this report on Form 10-K of Atlantic City Electric
Company.
|
|
2.
|
Based
on my knowledge, this report does not contain any untrue statement of a
material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this
report;
|
|
3.
|
Based
on my knowledge, the financial statements, and other financial information
included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this
report;
|
|
4.
|
The
registrant’s other certifying officer(s) and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchanges Act Rules 13a-15(e) and 15d-15(e)) and internal
control over financial reporting (as defined in Exchange Act Rules
13a-15(f) and 15d-15(f)) for the registrant and
have:
|
|
|
a)
|
Designed
such disclosure controls and procedures, or caused such disclosure
controls and procedures to be designed under our supervision, to ensure
that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being
prepared;
|
|
|
b)
|
Designed
such internal controls over financial reporting, or caused such internal
controls over financial reporting to be designed under our supervision, 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;
|
|
|
c)
|
Evaluated
the effectiveness of the registrant’s disclosure controls and procedures
and presented in this report our conclusions about the effectiveness of
the disclosure controls and procedures, as of the end of the period
covered by this report based on such evaluation; and
|
|
|
d)
|
Disclosed
in this report any change in the registrant’s internal control over
financial reporting that occurred during the registrant’s most recent
fiscal quarter (the registrant’s fourth fiscal quarter in the case of an
annual report) that has materially affected, or is reasonably likely to
materially affect, the registrant’s internal control over financial
reporting; and
|
|
5.
|
The
registrant’s other certifying officer(s) and I have disclosed, based on
our most recent evaluation of internal control over financial reporting,
to the registrant’s auditors and the audit committee of registrant’s board
of directors (or persons performing the equivalent
functions):
|
|
|
a)
|
All
significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrant’s ability to record,
process, summarize and report financial information; and
|
|
|
b)
|
Any
fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant’s internal control
over financial reporting.
|
|
|
/s/
JOSEPH M.
RIGBY
Joseph
M. Rigby
President
and Chief Executive Officer
|
|
|
|
CERTIFICATION
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I,
Paul H. Barry, certify that:
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1.
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I
have reviewed this report on Form 10-K of Atlantic City Electric
Company.
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2.
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Based
on my knowledge, this report does not contain any untrue statement of a
material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this
report;
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3.
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Based
on my knowledge, the financial statements, and other financial information
included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this
report;
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4.
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The
registrant’s other certifying officer(s) and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchanges Act Rules 13a-15(e) and 15d-15(e)) and internal
control over financial reporting (as defined in Exchange Act Rules
13a-15(f) and 15d-15(f)) for the registrant and
have:
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a)
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Designed
such disclosure controls and procedures, or caused such disclosure
controls and procedures to be designed under our supervision, to ensure
that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being
prepared;
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b)
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Designed
such internal controls over financial reporting, or caused such internal
controls over financial reporting to be designed under our supervision, 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;
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c)
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Evaluated
the effectiveness of the registrant’s disclosure controls and procedures
and presented in this report our conclusions about the effectiveness of
the disclosure controls and procedures, as of the end of the period
covered by this report based on such evaluation; and
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d)
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Disclosed
in this report any change in the registrant’s internal control over
financial reporting that occurred during the registrant’s most recent
fiscal quarter (the registrant’s fourth fiscal quarter in the case of an
annual report) that has materially affected, or is reasonably likely to
materially affect, the registrant’s internal control over financial
reporting; and
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5.
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The
registrant’s other certifying officer(s) and I have disclosed, based on
our most recent evaluation of internal control over financial reporting,
to the registrant’s auditors and the audit committee of registrant’s board
of directors (or persons performing the equivalent
functions):
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a)
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All
significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrant’s ability to record,
process, summarize and report financial information; and
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b)
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Any
fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant’s internal control
over financial reporting.
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/s/ P. H.
BARRY
Paul
H. Barry
Chief
Financial Officer
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Certificate
of Chief Executive Officer and Chief Financial Officer
of
Pepco
Holdings, Inc.
(pursuant
to 18 U.S.C. Section 1350)
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I, Dennis R. Wraase, and I, Paul
H. Barry, certify that, to the best of my knowledge, (i) the Report on
Form 10-K of Pepco Holdings, Inc. for the year ended December 31, 2007,
filed with the Securities and Exchange Commission on the date hereof fully
complies with the requirements of section 13(a) or 15(d) of the Securities
Exchange Act of 1934, as amended, and (ii) the information contained
therein fairly presents, in all material respects, the financial condition
and results of operations of Pepco Holdings, Inc.
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/s/
D. R.
WRAASE
Dennis
R. Wraase
President
and Chief Executive Officer
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/s/ P. H.
BARRY
Paul
H. Barry
Senior
Vice President and
Chief
Financial Officer
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A signed original of this written
statement required by Section 906 has been provided to Pepco Holdings,
Inc. and will be retained by Pepco Holdings, Inc. and furnished to the
Securities and Exchange Commission or its staff upon
request.
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Certificate
of Chief Executive Officer and Chief Financial Officer
of
Potomac
Electric Power Company
(pursuant
to 18 U.S.C. Section 1350)
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I, Joseph M. Rigby, and I, Paul
H. Barry, certify that, to the best of my knowledge, (i) the Report on
Form 10-K of Potomac Electric Power Company for the year ended December
31, 2007, filed with the Securities and Exchange Commission on the date
hereof fully complies with the requirements of section 13(a) or
15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the
information contained therein fairly presents, in all material respects,
the financial condition and results of operations of Potomac Electric
Power Company.
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/s/
JOSEPH M.
RIGBY
Joseph
M. Rigby
President
and Chief Executive Officer
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/s/ P. H.
BARRY
Paul
H. Barry
Senior
Vice President and
Chief
Financial Officer
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A signed original of this written
statement required by Section 906 has been provided to Potomac Electric
Power Company and will be retained by Potomac Electric Power Company and
furnished to the Securities and Exchange Commission or its staff upon
request.
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Certificate
of Chief Executive Officer and Chief Financial Officer
of
Delmarva
Power & Light Company
(pursuant
to 18 U.S.C. Section 1350)
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I, Joseph M. Rigby, and I, Paul
H. Barry, certify that, to the best of my knowledge, (i) the Report on
Form 10-K of Delmarva Power & Light Company for the year ended
December 31, 2007, filed with the Securities and Exchange Commission
on the date hereof fully complies with the requirements of
section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended,
and (ii) the information contained therein fairly presents, in all
material respects, the financial condition and results of operations of
Delmarva Power & Light Company.
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/s/
JOSEPH M.
RIGBY
Joseph
M. Rigby
President
and Chief Executive Officer
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/s/ P. H.
BARRY
Paul
H. Barry
Senior
Vice President and
Chief
Financial Officer
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A signed original of this written
statement required by Section 906 has been provided to Delmarva Power
& Light Company and will be retained by Delmarva Power & Light
Company and furnished to the Securities and Exchange Commission or its
staff upon request.
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Certificate
of Chief Executive Officer and Chief Financial Officer
of
Atlantic
City Electric Company
(pursuant
to 18 U.S.C. Section 1350)
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I, Joseph M. Rigby, and I, Paul
H. Barry, certify that, to the best of my knowledge, (i) the Report on
Form 10-K of Atlantic City Electric Company for the year ended December
31, 2007, filed with the Securities and Exchange Commission on the date
hereof fully complies with the requirements of section 13(a) or
15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the
information contained therein fairly presents, in all material respects,
the financial condition and results of operations of Atlantic City
Electric Company.
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/s/
JOSEPH M.
RIGBY
Joseph
M. Rigby
President
and Chief Executive Officer
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/s/ P. H.
BARRY
Paul
H. Barry
Chief
Financial Officer
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A signed original of this written
statement required by Section 906 has been provided to Atlantic City
Electric Company and will be retained by Atlantic City Electric Company
and furnished to the Securities and Exchange Commission or its staff upon
request.
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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.
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PEPCO
HOLDINGS, INC.
(Registrant)
By /s/ D. R.
WRAASE
Dennis
R. Wraase
Chairman
of the Board,
President
and Chief
Executive
Officer
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POTOMAC
ELECTRIC POWER COMPANY (Pepco)
(Registrant)
By /s/ JOSEPH M.
RIGBY
Joseph
M. Rigby,
President
and Chief
Executive
Officer
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DELMARVA
POWER & LIGHT COMPANY (DPL)
(Registrant)
By /s/ JOSEPH M.
RIGBY
Joseph
M. Rigby,
President
and Chief
Executive
Officer
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ATLANTIC
CITY ELECTRIC COMPANY (ACE)
(Registrant)
By /s/ JOSEPH M.
RIGBY
Joseph
M. Rigby,
President
and Chief
Executive
Officer
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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:
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/s/
D. R.
WRAASE
Dennis
R. Wraase
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Chairman
of the Board, President and Chief Executive Officer of Pepco Holdings,
Chairman of the Board of Pepco and Director of Pepco Holdings, Pepco, DPL
and ACE
(Principal
Executive Officer of Pepco Holdings)
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/s/
JOSEPH M.
RIGBY
Joseph
M. Rigby
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Director,
President and Chief Executive Officer of Pepco and DPL and President and
Chief Executive Officer of ACE
(Principal
Executive Officer of Pepco, DPL and ACE)
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/s/ P. H.
BARRY
Paul
H. Barry
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Senior
Vice President and Chief Financial Officer of Pepco Holdings, Pepco, and
DPL, Chief Financial Officer of ACE and Director of Pepco and
DPL
(Principal
Financial Officer of Pepco Holdings, Pepco, DPL and ACE)
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/s/
R. K.
CLARK
Ronald
K. Clark
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Vice
President and Controller of Pepco Holdings, Pepco and DPL and Controller
of ACE
(Principal
Accounting Officer of Pepco Holdings, Pepco, DPL and ACE)
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Signature
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Title
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Date
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/s/ J. B.
DUNN
Jack
B. Dunn, IV
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Director,
Pepco Holdings
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/s/ T. C.
GOLDEN
Terence
C. Golden
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Director,
Pepco Holdings
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/s/
FRANK O.
HEINTZ
Frank
O. Heintz
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Director,
Pepco Holdings
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/s/
BARBARA J. KRUMSIEK
Barbara
J. Krumsiek
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Director,
Pepco Holdings
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/s/
GEORGE F.
MacCORMACK
George
F. MacCormack
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Director,
Pepco Holdings
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/s/
RICHARD B.
McGLYNN
Richard
B. McGlynn
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Director,
Pepco Holdings
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/s/ LAWRENCE C.
NUSSDORF
Lawrence
C. Nussdorf
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Director,
Pepco Holdings
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/s/
FRANK
ROSS
Frank
K. Ross
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Director,
Pepco Holdings
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/s/
PAULINE A. SCHNEIDER
Pauline
A. Schneider
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Director,
Pepco Holdings
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/s/
LESTER P. SILVERMAN
Lester
P. Silverman
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Director,
Pepco Holdings
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/s/
WILLIAM T.
TORGERSON
William
T. Torgerson
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Director
of Pepco Holdings, Pepco and DPL
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/s/ WILLIAM M.
GAUSMAN
William M.
Gausman
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Director
of Pepco
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/s/ MICHAEL J.
SULLIVAN
Michael J.
Sullivan
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Director
of Pepco
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/s/
S. A.
WISNIEWSKI
Stanley
A. Wisniewski
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Director
of Pepco
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Exhibit No.
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Registrant(s)
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Description of Exhibit
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10.24
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PHI
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Non-Management
Director Compensation Arrangements*
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10.33
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PHI
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PHI
Named Executive Officer 2008 Compensation
Determinations*
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12.1
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PHI
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Statements
Re: Computation of Ratios
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12.2
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Pepco
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Statements
Re: Computation of Ratios
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12.3
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DPL
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Statements
Re: Computation of Ratios
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12.4
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ACE
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Statements
Re: Computation of Ratios
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21
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PHI
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Subsidiaries
of the Registrant
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23.1
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PHI
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Consent
of Independent Registered Public Accounting Firm
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23.2
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Pepco
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Consent
of Independent Registered Public Accounting Firm
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23.3
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DPL
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Consent
of Independent Registered Public Accounting Firm
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23.4
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ACE
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Consent
of Independent Registered Public Accounting Firm
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31.1
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PHI
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Rule
13a-14(a)/15d-14(a) Certificate of Chief Executive
Officer
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31.2
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PHI
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Rule
13a-14(a)/15d-14(a) Certificate of Chief Financial
Officer
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31.3
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Pepco
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Rule
13a-14(a)/15d-14(a) Certificate of Chief Executive
Officer
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31.4
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Pepco
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Rule
13a-14(a)/15d-14(a) Certificate of Chief Financial
Officer
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31.5
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DPL
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Rule
13a-14(a)/15d-14(a) Certificate of Chief Executive
Officer
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31.6
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DPL
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Rule
13a-14(a)/15d-14(a) Certificate of Chief Financial
Officer
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31.7
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ACE
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Rule
13a-14(a)/15d-14(a) Certificate of Chief Executive
Officer
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31.8
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ACE
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Rule
13a-14(a)/15d-14(a) Certificate of Chief Financial
Officer
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Exhibit No.
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Registrant(s)
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Description of Exhibit
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32.1
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PHI
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Certificate
of Chief Executive Officer and Chief Financial Officer pursuant to 18
U.S.C. Section 1350
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32.2
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Pepco
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Certificate
of Chief Executive Officer and Chief Financial Officer pursuant to 18
U.S.C. Section 1350
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32.3
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DPL
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Certificate
of Chief Executive Officer and Chief Financial Officer pursuant to 18
U.S.C. Section 1350
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32.4
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ACE
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Certificate
of Chief Executive Officer and Chief Financial Officer pursuant to 18
U.S.C. Section 1350
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