.
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:
